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As filed with the Securities and Exchange Commission on June 9, 2011

 Registration No. 333-173191

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Amendment No. 3
to

Form S-1
 
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
American Midstream Partners, LP
(Exact Name of Registrant as Specified in its Charter)

Delaware	 	4922	 	27-0855785	
(State or Other Jurisdiction of
Incorporation or Organization)	 	(Primary Standard Industrial
Classification Code Number)	 	(I.R.S. Employer
Identification Number)	

1614 15th Street
Suite 300
Denver, Colorado 80202
(720) 457-6060
(Address, including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal Executive Offices)
 
Brian F. Bierbach
President and Chief Executive Officer
1614 15th Street
Suite 300
Denver, Colorado 80202
(720) 457-6060
(Name, Address, including Zip Code, and Telephone Number, including Area Code, of Agent for Service)
 
Copies to:

 	 	 	
G. Michael O’Leary
Timothy C. Langenkamp
Andrews Kurth LLP
600 Travis, Suite 4200
Houston, Texas 77002
(713) 220-4200	 	William N. Finnegan IV
Brett E. Braden
Latham & Watkins LLP
717 Texas Avenue, Suite 1600
Houston, Texas 77002
(713) 546-5400	

 
Approximate date of commencement of proposed sale to the public:   As soon as practicable after this Registration Statement becomes effective.
 
If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.   o

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.   o

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.   o
 
If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.   o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  o	 	Accelerated filer  o	 	Non-accelerated filer  þ	 	Smaller reporting company  o	
 	 	 	 	(Do not check if a smaller reporting company)	 	 	

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

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The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.	
 
SUBJECT TO COMPLETION, DATED JUNE 9, 2011

PRELIMINARY PROSPECTUS

 
3,750,000 Common Units

Representing Limited Partner Interests
American Midstream Partners, LP

 
 
This is the initial public offering of our common units representing limited partner interests. We are offering 3,750,000 common units in this offering. We currently expect that the initial public offering price will be between $      and $      per common unit. Prior to this offering, there has been no public market for our common units.

 
We have granted the underwriters an option to purchase up to an additional 562,500 common units to cover over-allotments.

 
We intend to apply to list our common units on the New York Stock Exchange under the symbol “AMID.”

 

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 14.
 
These risks include the following:

			
 	• 	We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution or any distribution to holders of our common units and subordinated units.	

			
 	• 	Because of the natural decline in production from existing wells in our areas of operation, our success depends on our ability to obtain new sources of natural gas, which is dependent on factors beyond our control. Any decrease in the volumes of natural gas that we gather, process or transport could adversely affect our business and operating results.	
 		
 	• 	Natural gas, NGL and other commodity prices are volatile, and a reduction in these prices in absolute terms, or an adverse change in the prices of natural gas and NGLs relative to one another, could adversely affect our gross margin and cash flow and our ability to make distributions to our unitholders.	
 		
 	• 	We are a relatively small enterprise, and our management has limited history with our assets and no experience in managing our business as a publicly traded partnership. As a result, operational, financial and other events in the ordinary course of business could disproportionately affect us, and our ability to grow our business could be significantly limited.	
 		
 	• 	If third-party pipelines or other midstream facilities interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenue and cash available for distribution could be adversely affected.	
 		
 	• 	AIM Midstream Holdings, LLC directly owns and controls American Midstream GP, LLC, our general partner, which has sole responsibility for conducting our business and managing our operations, each of which have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our other unitholders.	
 		
 	• 	There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.	
 		
 	• 	Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.	
 		
 	• 	Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.	
 		
 	• 	You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.	
 
Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 	 	Per Common Unit	 	Total	
 		
Public Offering Price	 	$	     	 	 	$	          	 	
Underwriting Discount(1)	 	$	 	 	 	$	 	 	
Proceeds to American Midstream Partners, LP (before expenses)	 	$	 	 	 	$		 	

			
(1)		Excludes an aggregate structuring fee payable to Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated that is equal to 0.75% of the gross proceeds of this offering. Please see “Underwriting.”	
 
The underwriters expect to deliver the common units to purchasers on or about          , 2011, through the book-entry facilities of The Depository Trust Company.

 
 
Joint Book-Running Managers

Citi	BofA Merrill Lynch	

 
Co-Managers

		
Barclays Capital      	Wells Fargo Securities	

 
          , 2011

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Table of Contents

 	 	 	 	 	
 	 	Page	
 		
Summary	 	 	1	 	
American Midstream Partners, LP	 	 	1	 	
Overview	 	 	1	 	
Business Strategies	 	 	2	 	
Competitive Strengths	 	 	2	 	
Our Sponsor	 	 	3	 	
Risk Factors	 	 	3	 	
Recapitalization Transactions and Partnership Structure	 	 	3	 	
Ownership of American Midstream Partners, LP	 	 	4	 	
Our Management	 	 	5	 	
Principal Executive Offices and Internet Address	 	 	5	 	
Summary of Conflicts of Interest and Fiduciary Duties	 	 	5	 	
General	 	 	5	 	
Partnership Agreement Modifications to Fiduciary Duties	 	 	6	 	
AIM Midstream Holdings May Engage in Competition with Us	 	 	6	 	
The Offering	 	 	7	 	
Summary Historical Financial and Operating Data	 	 	11	 	
Risk Factors	 	 	14	 	
Risks Related to our Business	 	 	14	 	
Risks Inherent in an Investment in Us	 	 	33	 	
Tax Risks to Common Unitholders	 	 	41	 	
Use of Proceeds	 	 	46	 	
Capitalization	 	 	48	 	
Dilution	 	 	49	 	
Our Cash Distribution Policy and Restrictions on Distributions	 	 	50	 	
General	 	 	50	 	
Our Minimum Quarterly Distribution	 	 	51	 	
Unaudited Historical As Adjusted Available Cash for the Year Ended December 31, 2010 and the Twelve Months Ended March 31, 2011	 	 	53	 	
Estimated Adjusted EBITDA for the Twelve Months Ending June 30, 2012	 	 	55	 	
Statement of Estimated Adjusted EBITDA	 	 	57	 	
Assumptions and Considerations	 	 	59	 	
Provisions of our Partnership Agreement Relating to Cash Distributions	 	 	65	 	
Distributions of Available Cash	 	 	65	 	
Operating Surplus and Capital Surplus	 	 	66	 	
Capital Expenditures	 	 	68	 	
Subordination Period	 	 	69	 	
Distributions of Available Cash from Operating Surplus during the Subordination Period	 	 	71	 	
Distributions of Available Cash from Operating Surplus after the Subordination Period	 	 	71	 	
General Partner Interest and Incentive Distribution Rights	 	 	71	 	
Percentage Allocations of Available Cash from Operating Surplus	 	 	72	 	
General Partner’s Right to Reset Incentive Distribution Levels	 	 	72	 	
Distributions from Capital Surplus	 	 	75	 	
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels	 	 	76	 	
Distributions of Cash Upon Liquidation	 	 	76	 	
Selected Historical Financial and Operating Data	 	 	79	 	
Non-GAAP Financial Measures	 	 	81	 	
Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	 	83	 	
Overview	 	 	83	 	
Our Operations	 	 	83	 	
How We Evaluate Our Operations	 	 	85	 	
Items Affecting the Comparability of Our Financial Results	 	 	87	 	

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 	 	Page	
 		
General Trends and Outlook	 	 	88	 	
Results of Operations — Combined Overview	 	 	89	 	
Segment Results	 	 	93	 	
Liquidity and Capital Resources	 	 	98	 	
Quantitative and Qualitative Disclosures about Market Risk	 	 	104	 	
Impact of Seasonality	 	 	105	 	
Critical Accounting Policies and Estimates	 	 	106	 	
Industry Overview	 	 	109	 	
General	 	 	109	 	
Midstream Services	 	 	109	 	
Typical Midstream Contractual Arrangements	 	 	110	 	
U.S. Natural Gas Fundamentals	 	 	111	 	
Business	 	 	113	 	
Overview	 	 	113	 	
Business Strategies	 	 	114	 	
Competitive Strengths	 	 	115	 	
Our Sponsor	 	 	116	 	
Our Assets	 	 	117	 	
Gathering and Processing Segment	 	 	118	 	
Transmission Segment	 	 	125	 	
Competition	 	 	130	 	
Safety and Maintenance	 	 	130	 	
Regulation of Operations	 	 	131	 	
Environmental Matters	 	 	136	 	
Title to Properties and Rights-of-Way	 	 	140	 	
Employees	 	 	141	 	
Legal Proceedings	 	 	141	 	
Management	 	 	142	 	
Compensation Discussion and Analysis	 	 	145	 	
Summary Compensation Table for 2010	 	 	152	 	
Grants of Plan-Based Awards for 2010	 	 	153	 	
Outstanding Equity-Based Awards at December 31, 2010	 	 	155	 	
Units Vested in 2010	 	 	155	 	
Long-Term Incentive Plan	 	 	155	 	
Potential Payments Upon Termination or Change in Control	 	 	156	 	
Compensation of Directors	 	 	159	 	
Director Compensation Table for 2010	 	 	160	 	
Compensation Practices as they Relate to Risk Management	 	 	161	 	
Security Ownership of Certain Beneficial Owners and Management	 	 	162	 	
Certain Relationships and Related Party Transactions	 	 	164	 	
Distributions and Payments to our General Partner and its Affiliates	 	 	164	 	
Ownership Interests of Certain Executive Officers and Directors of Our General Partner	 	 	165	 	
Agreements with Affiliates	 	 	165	 	
Procedures for Review, Approval and Ratification of Related-Person Transactions	 	 	166	 	
Conflicts Of Interest and Fiduciary Duties	 	 	167	 	
Conflicts of Interest	 	 	167	 	
Fiduciary Duties	 	 	172	 	
Description of the Common Units	 	 	175	 	
The Units	 	 	175	 	
Transfer Agent and Registrar	 	 	175	 	
Transfer of Common Units	 	 	175	 	
The Partnership Agreement	 	 	177	 	
Organization and Duration	 	 	177	 	
Purpose	 	 	177	 	

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 	 	Page	
 		
Cash Distributions	 	 	177	 	
Capital Contributions	 	 	177	 	
Voting Rights	 	 	178	 	
Limited Liability	 	 	179	 	
Issuance of Additional Securities	 	 	180	 	
Amendment of Our Partnership Agreement	 	 	180	 	
Merger, Sale or Other Disposition of Assets	 	 	182	 	
Termination and Dissolution	 	 	183	 	
Liquidation and Distribution of Proceeds	 	 	183	 	
Withdrawal or Removal of Our General Partner	 	 	183	 	
Transfer of General Partner Interest	 	 	184	 	
Transfer of Ownership Interests in Our General Partner	 	 	185	 	
Transfer of Incentive Distribution Rights	 	 	185	 	
Change of Management Provisions	 	 	185	 	
Limited Call Right	 	 	186	 	
Meetings; Voting	 	 	186	 	
Status as Limited Partner	 	 	187	 	
Non-Citizen Assignees; Redemption	 	 	187	 	
Non-Taxpaying Assignees; Redemption	 	 	187	 	
Indemnification	 	 	188	 	
Reimbursement of Expenses	 	 	188	 	
Books and Reports	 	 	188	 	
Right to Inspect Our Books and Records	 	 	189	 	
Registration Rights	 	 	189	 	
Units Eligible for Future Sale	 	 	190	 	
Material Federal Income Tax Consequences	 	 	191	 	
Partnership Status	 	 	191	 	
Limited Partner Status	 	 	193	 	
Tax Consequences of Unit Ownership	 	 	193	 	
Tax Treatment of Operations	 	 	199	 	
Disposition of Common Units	 	 	200	 	
Uniformity of Units	 	 	202	 	
Tax-Exempt Organizations and Other Investors	 	 	203	 	
Administrative Matters	 	 	204	 	
Recent Legislative Developments	 	 	206	 	
State, Local, Foreign and Other Tax Considerations	 	 	206	 	
Investment in American Midstream Partners, LP by Employee Benefit Plans	 	 	207	 	
Underwriting	 	 	209	 	
Offering Price Determination	 	 	211	 	
Notice to Prospective Investors in the European Economic Area	 	 	211	 	
Notice to Prospective Investors in the Dubai International Financial Centre	 	 	212	 	
Notice to Prospective Investors in the United Kingdom	 	 	212	 	
Notice to Prospective Investors in Germany	 	 	212	 	
Notice to Prospective Investors in the Netherlands	 	 	213	 	
Notice to Prospective Investors in Switzerland	 	 	213	 	
Validity of the Common Units	 	 	214	 	
Experts	 	 	214	 	
Where You Can Find More Information	 	 	214	 	
Forward-Looking Statements	 	 	214	 	
Index to Financial Statements	 	 	F-1	 	
Appendix A — Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP	 	 	A-1	 	
Appendix B — Glossary of Terms	 	 	B-1	 	
  EX-5.1	
  EX-8.1	
  EX-10.1	
  EX-10.2	
  EX-10.3	
  EX-10.4	
  EX-10.5	
  EX-10.6	
  EX-10.7	
  EX-10.8	
  EX-10.9	
  EX-10.14	
  EX-10.15	
  EX-10.16	
  EX-10.17	
  EX-10.18	
  EX-10.19	
  EX-10.20	
  EX-10.21	
  EX-10.22	
  EX-10.23	
  EX-10.24	
  EX-10.25	
  EX-10.26	
  EX-10.27	
  EX-10.28	
  EX-23.1	
  EX-23.2	

 

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You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. Neither we nor the underwriters have authorized anyone to provide you with additional or different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this prospectus.

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SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical consolidated financial statements and related notes of American Midstream Partners, LP and the historical combined financial statements and related notes of American Midstream Partners Predecessor, which we refer to as our Predecessor. The information presented in this prospectus assumes (1) an initial public offering price of $20.00 per common unit, (2) unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised, and (3) that the reverse unit split referred to in “Recapitalization Transactions and Partnership Structure” has occurred. You should read “Risk Factors” beginning on page 14 for more information about important risks that you should consider carefully before investing in our common units. We include a glossary of some of the terms used in this prospectus as Appendix B.

Unless the context otherwise requires, references in this prospectus to (i) “American Midstream Partners, LP,” “we,” “our,” “us” or like terms for periods from and after the acquisition of our assets on November 1, 2009 refer to American Midstream Partners, LP and its subsidiaries; (ii) “American Midstream Partners, LP,” “we,” “our,” “us” or like terms for periods prior to November 1, 2009 refer to our Predecessor and its subsidiaries; (iii) “American Midstream GP” or our “general partner” refer to American Midstream GP, LLC; (iv)“AIM Midstream Holdings” refers to AIM Midstream Holdings, LLC and its subsidiaries and affiliates, other than American Midstream Partners, LP and its subsidiaries and American Midstream GP, as of the closing date of this offering; and (v) “AIM” refers to American Infrastructure MLP Fund, L.P. and its subsidiaries and affiliates, other than American Midstream Partners, LP, American Midstream GP, AIM Midstream Holdings and their respective subsidiaries.
 
American Midstream Partners, LP
 
Overview
 
We are a growth-oriented Delaware limited partnership that was formed by AIM in August 2009 to own, operate, develop and acquire a diversified portfolio of natural gas midstream energy assets. We are engaged in the business of gathering, treating, processing and transporting natural gas through our ownership and operation of nine gathering systems, three processing facilities, two interstate pipelines and six intrastate pipelines. Our primary assets, which are strategically located in Alabama, Louisiana, Mississippi, Tennessee and Texas, provide critical infrastructure that links producers and suppliers of natural gas to diverse natural gas markets, including various interstate and intrastate pipelines, as well as utility, industrial and other commercial customers. We currently operate approximately 1,400 miles of pipelines that gather and transport over 500 MMcf/d of natural gas. We acquired our existing portfolio of assets from a subsidiary of Enbridge Energy Partners, L.P., or Enbridge, in November 2009.

Our operations are organized into two segments: (i) Gathering and Processing and (ii) Transmission. In our Gathering and Processing segment, we receive fee-based and fixed-margin compensation for gathering, transporting and treating natural gas. Where we provide processing services at the plants that we own, or obtain processing services for our own account in connection with our elective processing arrangements, we typically retain and sell a percentage of the residue natural gas and resulting natural gas liquids, or NGLs, under percent-of-proceeds, or POP, arrangements. We also receive fee-based and fixed-margin compensation in our Transmission segment primarily related to capacity reservation charges under our firm transportation contracts and the transportation of natural gas pursuant to our interruptible transportation and fixed-margin contracts.

For the year ended December 31, 2010 and the quarter ended March 31, 2011, we generated $38.1 million and $12.3 million of gross margin, respectively, of which $24.6 million and $8.2 million, respectively, represented segment gross margin generated in our Gathering and Processing segment and $13.5 million and $4.1 million, respectively, represented segment gross margin generated in our Transmission segment. For the year ended December 31, 2010 and the quarter ended March 31, 2011, $24.9 million, or 65.4%, and $7.3 million, or 59.5%, respectively, of our gross margin was generated from fee-based, fixed-margin and firm and interruptible transportation contracts with respect to which we have little or no direct commodity price exposure. For a definition of gross margin and a reconciliation of gross margin to its most directly comparable financial measure calculated in accordance with GAAP, please read “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures.”

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Business Strategies
 
Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business. We expect to achieve this objective by executing the following strategies:

 	• 	Capitalize on Organic Growth Opportunities Associated with Our Existing Assets.   We continually seek to identify and evaluate economically attractive organic expansion and asset enhancement opportunities that leverage our existing asset footprint and strategic relationships with our customers.	
 		
 	• 	Attract Additional Volumes to Our Systems.   We intend to attract new volumes of natural gas to our systems from existing and new customers by continuing to provide superior customer service and reestablishing relationships with customers that were potentially underserved by the previous owner of our assets.	
 		
 	• 	Pursue Strategic and Accretive Acquisitions.   We plan to pursue accretive acquisitions of energy infrastructure assets that are complementary to our existing asset base or that provide attractive potential returns in new operating regions or business lines.	
 		
 	• 	Manage Exposure to Commodity Price Risk.   We will manage our commodity price exposure by targeting a contract portfolio that is weighted towards fee-based and fixed-margin contracts while mitigating direct commodity price exposure by employing a prudent hedging strategy.	
 		
 	• 	Maintain Financial Flexibility and Conservative Leverage.   We plan to pursue a disciplined financial policy and seek to maintain a conservative capital structure that we believe will allow us to consider attractive growth projects and acquisitions even in periods of challenging market environments.	
 		
 	• 	Continue Our Commitment to Safe and Environmentally Sound Operations.   The safety of our employees and the communities in which we operate is one of our highest priorities. We believe it is critical to handle natural gas and NGLs for our customers safely, while striving to minimize the environmental impact of our operations.	
 
Competitive Strengths
 
We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:

 	• 	Well Positioned to Pursue Opportunities Overlooked by Larger Competitors .  Our size and flexibility, in conjunction with our geographically diverse asset base, position us to pursue economically attractive growth projects and acquisitions that may not be large enough to be attractive to many of our larger competitors.	
 		
 	• 	Diversified Asset Base.   Our assets are diversified geographically and by business line, which contributes to the stability of our cash flows and creates a number of potential growth opportunities for our business.	
 		
 	• 	Strategically Located Assets.   Our assets are located in areas where we believe there will be opportunities to access new natural gas supplies and to capture new customers that are underserved by our competitors. We continue to see drilling activity on and around our systems, and we believe that our assets are strategically positioned to capitalize on such activity.	
 		
 	• 	Focus on Delivering Excellent Customer Service.   We view our strong customer relationships as one of our key assets and believe it is critical to maintain operational excellence and ensure best-in-class customer service and reliability.	
 		
 	• 	Experienced and Incentivized Management and Operating Teams.   Our executive management team has an average of over 25 years of experience in the midstream energy industry. The team possesses a comprehensive skill set to support our business and enhance unitholder value through asset optimization, accretive development projects and acquisitions.	

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Our Sponsor

American Infrastructure MLP Fund, L.P., or AIM, is a private investment firm specializing in investments in energy, natural resources, infrastructure and real property. AIM, along with certain of the funds that AIM advises, currently indirectly owns 84.4% of the ownership interests in AIM Midstream Holdings, which owns 100.0% of our general partner. Robert B. Hellman, Jr., Matthew P. Carbone and Edward O. Diffendal serve on the board of directors of our general partner and are principals of and have ownership interests in AIM. After the closing of this offering, AIM Midstream Holdings will continue to hold 100.0% of the ownership interests in our general partner and will hold 16.0% of our common units and 100.0% of our subordinated units, or an aggregate of 58.0% of our total limited partner interests.

Risk Factors
 
An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. Please read carefully the risks under the caption “Risk Factors” immediately following this Summary, beginning on page 14.
 
Recapitalization Transactions and Partnership Structure
 
We are a growth-oriented Delaware limited partnership that was formed by AIM to own, operate, develop and acquire a diversified portfolio of midstream energy assets.
 
Immediately prior to the closing of this offering, the following transactions, which we refer to as the recapitalization transactions, will occur:

			
 	• 	each general partner unit held by our general partner will automatically reverse split into 0.485 general partner units, resulting in the ownership by our general partner of an aggregate of 108,718 general partner units, representing a 2.0% general partner interest in us;	

 
			
 	• 	each common unit held by participants in our Long-Term Incentive Plan, or LTIP, will automatically reverse split into 0.485 common units, resulting in their ownership of an aggregate of 50,946 common units, representing an aggregate 0.9% limited partner interest in us;	

 
			
 	• 	each outstanding phantom unit granted to participants in our LTIP will automatically reverse split into 0.485 phantom units, resulting in their holding an aggregate of 209,824 phantom units;	

 
			
 	• 	each common unit held by AIM Midstream Holdings will automatically reverse split into 0.485 common units, resulting in the ownership by AIM Midstream Holdings of an aggregate of 5,327,205 common units, representing an aggregate 97.1% limited partner interest in us; and	

 
			
 	• 	the common units held by AIM Midstream Holdings will automatically convert into 801,139 common units and 4,526,066 subordinated units.	

In connection with the closing of this offering and immediately following the recapitalization transactions, the following transactions will occur:

			
 	• 	we will issue 3,750,000 common units to the public in this offering;	

 
			
 	• 	AIM Midstream Holdings will contribute 76,019 common units to our general partner as a capital contribution;	

 
			
 	• 	our general partner will contribute the common units contributed to it by AIM Midstream Holdings to us in exchange for 76,019 general partner units in order to maintain its 2.0% general partner interest in us;	

			
 	• 	we will use the net proceeds from this offering for the purposes set forth in “Use of Proceeds;”	
 		
 	• 	we will enter into a new credit facility; and	
 		
 	• 	we will use the net proceeds from borrowings under our new credit facility for the purposes set forth in “Use of Proceeds.”	

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Ownership of American Midstream Partners, LP
 
The diagram below illustrates our organization and ownership after giving effect to this offering and the related recapitalization transactions and assumes that the underwriters’ option to purchase additional common units is not exercised.

 	 	 	 	 	
Public Common Units	 	 	40.6	%	
AIM Midstream Holdings Units:	 	 	 	 	
Common Units	 	 	7.8	%	
Subordinated Units	 	 	49.0	%	
LTIP Participants Common Units	 	 	0.6	%	
General Partner Interest	 	 	2.0	%	
 	 	 	 	 	
Total	 	 	100.0	%	

 

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Our Management

We are managed and operated by the board of directors and executive officers of our general partner, American Midstream GP. Currently, and upon the closing of this offering, AIM Midstream Holdings will own all of the ownership interests in our general partner. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. AIM holds an aggregate 84.4% indirect interest in AIM Midstream Holdings. Robert B. Hellman, Jr., Matthew P. Carbone and Edward O. Diffendal serve on the board of directors of our general partner and are principals of and have ownership interests in AIM. In addition, the executive officers of our general partner and certain members of our general partner’s board of directors hold an aggregate 1.1% interest in AIM Midstream Holdings. After the closing of this offering, AIM Midstream Holdings will continue to hold 100.0% of the ownership interests in our general partner and will hold 16.0% of our common units and 100.0% of our subordinated units, or an aggregate of 58.0% of our total limited partner interests. For information about the executive officers and directors of our general partner, please read “Management.” Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, our general partner intends to cause us to incur indebtedness or other obligations that are nonrecourse to it.

In order to maintain operational flexibility, our operations will be conducted through, and our operating assets will be owned by, American Midstream, LLC and its subsidiaries. However, we, American Midstream, LLC and its subsidiaries do not have any employees. Although all of the employees that conduct our business are employed by our general partner, we sometimes refer to these individuals in this prospectus as our employees.
 
Following the closing of this offering, our general partner and its affiliates will not receive any management fee or other compensation in connection with our general partner’s management of our business, but will be reimbursed for expenses incurred on our behalf. These expenses include the costs of employee and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate for the conduct of our business and allocable to us. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

Following the closing of this offering, our general partner will own 184,737 general partner units representing a 2.0% general partner interest in us, which will entitle it to receive 2.0% of all the distributions we make. Our general partner also owns all of our incentive distribution rights, which will entitle it to increasing percentages, up to a maximum of 48.0%, of the cash we distribute in excess of $0.47438 per unit per quarter, after the closing of our initial public offering. Please read “Certain Relationships and Related Party Transactions.”

Principal Executive Offices and Internet Address

Our principal executive offices are located at 1614 15th Street, Suite 300, Denver, CO 80202, and our telephone number is (720) 457-6060. Our website is located at www.americanmidstream.com. We expect to make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Fiduciary Duties
 
General
 
Our general partner has a legal duty to manage us in a manner beneficial to the holders of our common and subordinated units. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, the officers and directors of our general partner also have a fiduciary duty to manage the business of our general partner in a manner beneficial to its owner, AIM Midstream Holdings.

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Certain of the officers and directors of our general partner are also officers of AIM Midstream Holdings. As a result of these relationships, conflicts of interest may arise in the future between us and holders of our common units, on the one hand, and AIM Midstream Holdings and our general partner, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common units, which in turn has an effect on whether our general partner receives incentive cash distributions as discussed above.
 
Partnership Agreement Modifications to Fiduciary Duties
 
Our partnership agreement limits the liability of, and reduces the fiduciary duties owed by, our general partner to holders of our common and subordinated units. Our partnership agreement also restricts the remedies available to holders of our common and subordinated units for actions that might otherwise constitute a breach of our general partner’s fiduciary duties. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, each holder of common units consents to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under applicable state law.
 
AIM Midstream Holdings May Engage in Competition with Us
 
Our partnership agreement does not prohibit AIM, AIM Midstream Holdings or their respective affiliates other than our general partner from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, AIM Midstream Holdings may acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to acquire or construct any of those assets.
 
For a more detailed description of the conflicts of interest and the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties.”

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The Offering

			
Common units offered to the public		3,750,000 common units.	

 
			
		4,312,500 common units, if the underwriters exercise in full their option to purchase additional common units.	

 
			
Units outstanding after this offering		4,526,066 common units and 4,526,066 subordinated units, each representing a 49.0% limited partner interest in us. Our general partner will own 184,737 general partner units, representing a 2.0% general partner interest in us.	

 
			
Use of proceeds		We intend to use the net proceeds from this offering of approximately $69.8 million, after deducting underwriting discounts, commissions and structuring fees, but before paying offering expenses, to:	

 
			
		• repay in full the outstanding balance under our existing credit facility of $59.8 million;	

 
			
		• pay offering expenses of approximately $3.3 million;	

 
			
		• terminate, in exchange for a payment of $2.5 million, the advisory services agreement between our subsidiary, American Midstream, LLC, and AIM;	

			
		• establish a cash reserve of $2.2 million related to our non-recurring deferred maintenance capital expenditures for the twelve months ending June 30, 2012; and	

			
		• distribute approximately $2.0 million, on a pro rata basis, to AIM Midstream Holdings, LTIP participants holding common units and our general partner. The portion of the distribution made to AIM Midstream Holdings is a partial reimbursement of capital expenditures that were funded by its initial investment in us.	

 
			
		We will use the proceeds from borrowings of approximately $30.0 million under our new credit facility to (i) distribute approximately $28.0 million, on a pro rata basis, to AIM Midstream Holdings, LTIP participants holding common units and our general partner and (ii) pay fees and expenses relating to our new credit facility of approximately $2.0 million.	

			
		If the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from AIM Midstream Holdings a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit in this offering before expenses but after deducting underwriting discounts, commissions and structuring fees.	
 		
		Please read “Use of Proceeds.”	

			
Cash distributions		We intend to pay a minimum quarterly distribution of $0.4125 per unit ($1.65 per unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available	

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		cash.” Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.” We will adjust the minimum quarterly distribution payable for the period from the closing of this offering through September 30, 2011, based on the length of that period.	
 		
		Our partnership agreement requires that we distribute all of our available cash each quarter in the following manner:	

			
		•  first , 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $0.4125 plus any arrearages from prior quarters;	

 
			
		•  second , 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $0.4125; and	

 
			
		•  third , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $0.47438.	

 
			
		If cash distributions to our unitholders exceed $0.47438 per unit in any quarter, our general partner will receive, in addition to distributions on its 2.0% general partner interest, increasing percentages, up to 48.0%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”	

 
			
		The amount of as adjusted cash available for distribution generated during the year ended December 31, 2010 and the twelve months ended March 31, 2011 would have been insufficient to allow us to pay the full minimum quarterly distribution ($0.4125 per unit per quarter, or $1.65 on an annualized basis) on all of our common and subordinated units, as well as the corresponding distribution on our 2.0% general partner interest, for such period. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”	

 
			
		We believe that, based on the Statement of Estimated Adjusted EBITDA included under the caption “Our Cash Distribution Policy and Restrictions on Distributions,” we will have sufficient cash available for distribution to pay the annualized minimum quarterly distribution of $0.4125 per unit on all common and subordinated units, as well as the corresponding distribution on our 2.0% general partner interest, for the twelve months ending June 30, 2012.	

			
Subordinated units		AIM Midstream Holdings will initially indirectly own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.	

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Conversion of subordinated units		The subordination period will end on the first business day after we have earned and paid at least (i) $1.65 (the minimum quarterly distribution on an annualized basis) on each outstanding common and subordinated unit, as well as the corresponding distribution on our 2.0% general partner interest, for each of three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2014 or (ii) $2.475 (150% of the annualized minimum quarterly distribution) on each outstanding common and subordinated unit, as well as the corresponding distribution on our 2.0% general partner interest, in addition to any distribution made in respect of the incentive distribution rights, for any four consecutive quarter period ending on or after September 30, 2012; provided that we have paid at least the minimum quarterly distribution from operating surplus on each outstanding common unit and subordinated unit, as well as the corresponding distribution on our 2.0% general partner interest, for each quarter in that four-quarter period.	

			
		In addition, the subordination period will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.	
 		
		When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages.	

			
Limited voting rights		Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66 2 / 3 % of the outstanding limited partner units voting together as a single class, including any limited partner units owned by our general partner and its affiliates, including AIM Midstream Holdings. Upon the closing of this offering, AIM Midstream Holdings will own an aggregate of 58.0% of our common and subordinated units. This will give AIM Midstream Holdings the ability to prevent the involuntary removal of our general partner. Please read “The Partnership Agreement — Voting Rights.”	

			
Limited call right		If at any time our general partner and its affiliates own more than 80.0% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price that is not less than the then-current market price of the common units.	
 		
Eligible holders and redemption		If our general partner determines that a holder of our common units is not an eligible holder, it may elect not to make distributions or allocate income or loss to such holder. Eligible holders are:	
 		
		• U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us; or	

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		• U.S. entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are domestic individuals or entities subject to such taxation.	

			
		We have the right, which we may assign to any of our affiliates, but not the obligation, to redeem all of the common units of any holder that is not an eligible holder or that has failed to certify or has falsely certified that such holder is an eligible holder. The purchase price for such redemption would be equal to the lesser of the holder’s purchase price and the then-current market price of the common units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.	
 		
		Please read “The Partnership Agreement — Non-Citizen Assignees; Redemption” and “The Partnership Agreement — Non-Taxpaying Assignees; Redemption.”	

			
Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending          , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.65 per unit, we estimate that your average allocable federal taxable income per year will be no more than $   per unit. Please read “Material Federal Income Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” and “Material Federal Income Tax Consequences — Tax Consequences of Unit Ownership — Limitations on Deductibility of Losses.”	

			
Material federal income tax consequences		For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, or the U.S., please read “Material Federal Income Tax Consequences.”	

			
Exchange listing		We intend to apply to list our common units on the New York Stock Exchange under the symbol ‘‘AMID.”	

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Summary Historical Financial and Operating Data
 
The following table presents our summary historical consolidated financial and operating data, as well as the summary historical combined financial and operating data of our Predecessor, which was comprised of 12 indirectly wholly owned subsidiaries of Enbridge, as of the dates and for the periods indicated.
 
The summary historical combined financial data presented as of and for the year ended December 31, 2008, and as of and for the 10 months ended October 31, 2009 are derived from the audited historical combined financial statements of our Predecessor that are included elsewhere in this prospectus. The summary historical consolidated financial data presented as of December 31, 2009, for the period from August 20, 2009 (date of inception) to December 31, 2009, as of and for the year ended December 31, 2010, as of and for the quarter ended March 31, 2010 and as of and for the quarter ended March 31, 2011 are derived from our audited and unaudited historical consolidated financial statements included elsewhere in this prospectus. We acquired our assets effective November 1, 2009. During the period from our inception on August 20, 2009 to October 31, 2009, we had no operations although we incurred certain fees and expenses associated with our formation and the acquisition of our assets from Enbridge.
 
For a detailed discussion of the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with our historical audited and unaudited consolidated financial statements and related notes and our Predecessor’s audited combined financial statements and related notes included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.
 
The following table presents the non-GAAP financial measures adjusted EBITDA and gross margin that we use in our business and view as important supplemental measures of our performance. These measures are not calculated or presented in accordance with GAAP. We explain these measures under “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures” and reconcile them to net income (loss), their most directly comparable financial measure calculated and presented in accordance with GAAP.

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 	 	 	American Midstream Partners Predecessor	 	 	 	American Midstream Partners, LP and Subsidiaries (Successor)	 	
 	 	 	 	 	 	 	 	 	 	 	Period from	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	10 Months	 	 	 	August 20, 2009	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Year Ended	 	 	 	Ended	 	 	 	(Inception Date)	 	 	 	Year Ended	 	 	Quarter Ended	 	 	Quarter Ended	 	
 	 	 	December 31,	 	 	 	October 31,	 	 	 	to December 31,	 	 	 	December 31,	 	 	March 31,	 	 	March 31,	 	
 	 	 	2008	 	 	 	2009	 	 	 	2009	 	 	 	2010	 	 	2010	 	 	2011	 	
 	 	 	(in thousands, except per unit and operating data)	 	
Statement of Operations Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenue	 	 	$	366,348	 	 	 	$	143,132	 	 	 	$	32,833	 	 	 	$	211,940	 	 	$	54,712	 	 	$	67,265	 	
Unrealized gain (loss) on commodity derivatives	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	—	 	 	 	(3,500	)	
Total revenue	 	 	 	366,348	 	 	 	 	143,132	 	 	 	 	32,833	 	 	 	 	211,940	 	 	 	54,712	 	 	 	63,765	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Purchases of natural gas, NGLs and condensate	 	 	 	323,205	 	 	 	 	113,227	 	 	 	 	26,593	 	 	 	 	173,821	 	 	 	44,964	 	 	 	54,953	 	
Direct operating expenses	 	 	 	13,423	 	 	 	 	10,331	 	 	 	 	1,594	 	 	 	 	12,187	 	 	 	2,692	 	 	 	3,058	 	
Selling, general and administrative expenses(1)	 	 	 	8,618	 	 	 	 	8,577	 	 	 	 	1,346	 	 	 	 	8,854	 	 	 	2,113	 	 	 	2,675	 	
One-time transaction costs	 	 	 	—	 	 	 	 	—	 	 	 	 	6,404	 	 	 	 	303	 	 	 	74	 	 	 	288	 	
Depreciation expense	 	 	 	13,481	 	 	 	 	12,630	 	 	 	 	2,978	 	 	 	 	20,013	 	 	 	4,966	 	 	 	5,037	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total operating expenses	 	 	 	358,727	 	 	 	 	144,765	 	 	 	 	38,915	 	 	 	 	215,178	 	 	 	54,809	 	 	 	66,011	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income (loss)	 	 	 	7,621	 	 	 	 	(1,633	)	 	 	 	(6,082	)	 	 	 	(3,238	)	 	 	(97	)	 	 	(2,246	)	
Other (income) expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expense	 	 	 	5,747	 	 	 	 	3,728	 	 	 	 	910	 	 	 	 	5,406	 	 	 	1,357	 	 	 	1,264	 	
Income tax expense	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	—	 	 	 	—	 	
Other (income) expenses	 	 	 	(854	)	 	 	 	(24	)	 	 	 	—	 	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	 	$	2,728	 	 	 	$	(5,337	)	 	 	$	(6,992	)	 	 	$	(8,644	)	 	$	(1,454	)	 	$	(3,510	)	
General partner’s interest in net income (loss)	 	 	 	 	 	 	 	 	 	 	 	 	 	(140	)	 	 	 	(173	)	 	 	(29	)	 	 	(70	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Limited partners’ interest in net income (loss)	 	 	 	 	 	 	 	 	 	 	 	 	 	(6,852	)	 	 	 	(8,471	)	 	 	(1,425	)	 	 	(3,440	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Limited partners’ net income (loss) per unit	 	 	 	 	 	 	 	 	 	 	 	 	$	(1.52	)	 	 	$	(0.81	)	 	$	(0.14	)	 	$	(0.30	)	
Pro forma earnings per common unit(2)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	(0.61	)	
Pro forma weighted average common units outstanding(2)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	5,668	 	
Statement of Cash Flows Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by (used in):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating activities	 	 	$	18,155	 	 	 	$	14,589	 	 	 	$	(6,531	)	 	 	$	13,791	 	 	$	2,323	 	 	$	5,067	 	
Investing activities	 	 	 	(10,486	)	 	 	 	(853	)	 	 	 	(151,976	)	 	 	 	(10,268	)	 	 	(494	)	 	 	(1,291	)	
Financing activities	 	 	 	(7,929	)	 	 	 	(14,008	)	 	 	 	159,656	 	 	 	 	(4,609	)	 	 	(2,888	)	 	 	(3,686	)	
Other Financial Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDA(3)	 	 	$	21,956	 	 	 	$	11,021	 	 	 	$	3,450	 	 	 	$	18,263	 	 	$	5,197	 	 	$	6,914	 	
Gross margin(4)	 	 	 	43,143	 	 	 	 	29,905	 	 	 	 	6,240	 	 	 	 	38,119	 	 	 	9,748	 	 	 	12,312	 	
Segment gross margin:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gathering and Processing	 	 	 	27,354	 	 	 	 	20,024	 	 	 	 	3,698	 	 	 	 	24,595	 	 	 	6,098	 	 	 	8,167	 	
Transmission	 	 	 	15,789	 	 	 	 	9,881	 	 	 	 	2,542	 	 	 	 	13,524	 	 	 	3,650	 	 	 	4,145	 	
Balance Sheet Data (At Period End):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	 	$	421	 	 	 	$	149	 	 	 	$	1,149	 	 	 	$	63	 	 	$	90	 	 	$	153	 	
Accounts receivable, net and unbilled revenue	 	 	 	9,532	 	 	 	 	8,756	 	 	 	 	19,776	 	 	 	 	22,850	 	 	 	17,446	 	 	 	22,248	 	
Property, plant and equipment, net	 	 	 	216,903	 	 	 	 	205,126	 	 	 	 	149,266	 	 	 	 	146,808	 	 	 	151,167	 	 	 	143,394	 	
Total assets	 	 	 	277,242	 	 	 	 	250,162	 	 	 	 	174,470	 	 	 	 	173,229	 	 	 	173,217	 	 	 	169,693	 	
Total debt (current and long-term)(5)	 	 	 	60,000	 	 	 	 	—	 	 	 	 	61,000	 	 	 	 	56,370	 	 	 	58,380	 	 	 	56,500	 	
Operating Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gathering and Processing segment :	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Throughput (MMcf/d)	 	 	 	179.2	 	 	 	 	211.8	 	 	 	 	169.7	 	 	 	 	175.6	 	 	 	164.3	 	 	 	242.8	 	
Plant inlet volume (MMcf/d)(6)	 	 	 	12.5	 	 	 	 	11.7	 	 	 	 	11.4	 	 	 	 	9.9	 	 	 	11.1	 	 	 	15.2	 	
Gross NGL production (Mgal/d)(6)	 	 	 	40.2	 	 	 	 	39.3	 	 	 	 	38.2	 	 	 	 	34.1	 	 	 	35.2	 	 	 	56.6	 	
Transmission segment :	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Throughput (MMcf/d)	 	 	 	336.2	 	 	 	 	357.6	 	 	 	 	381.3	 	 	 	 	350.2	 	 	 	360.6	 	 	 	446.0	 	
Firm transportation — capacity reservation (MMcf/d)	 	 	 	627.3	 	 	 	 	613.2	 	 	 	 	701.0	 	 	 	 	677.6	 	 	 	702.8	 	 	 	762.1	 	
Interruptible transportation — throughput (MMcf/d)	 	 	 	141.6	 	 	 	 	121.0	 	 	 	 	118.0	 	 	 	 	80.9	 	 	 	80.2	 	 	 	76.5	 	

 

 
			
(1)		Includes LTIP expenses for the period from August 20, 2009 to December 31, 2009, for the year ended December 31, 2010, for the quarter ended March 31, 2010 and for the quarter ended March 31, 2011 of $0.2 million, $1.7 million, $0.3 million and $0.5 million, respectively. Of these amounts, $0.2 million, $1.2 million, $0.3 million and $0.3 million, respectively, represent non-cash expenses.	

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(2)		The pro forma earnings per common unit gives effect to the recapitalization transactions as of March 31, 2011 and the additional number of common units issued in this offering (at an assumed offering price of $20.00 per unit) necessary to pay the portion of the distribution to AIM Midstream Holdings, LTIP Participants holding common units and our general partner described in “Use of Proceeds” that will be funded from the proceeds of this offering that exceeds net income for the three months ended March 31, 2011.	

 
			
(3)		For a definition of adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Selected Historical Financial and Operating Data — How We Evaluate Our Operations,” and for a discussion of how we use adjusted EBITDA to evaluate our operating performance, please read “— How We Evaluate Our Operations.”	

 
			
(4)		For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 12 to our unaudited consolidated financial statements and Note 18 to our audited consolidated financial statements included elsewhere in this prospectus and for a discussion of how we use gross margin to evaluate our operating performance, please read “— How We Evaluate Our Operations.”	

 
			
(5)		Excludes Predecessor Note payable to Enbridge Midcoast Limited Holdings, L.L.C. of $39.3 million as of December 31, 2008.	

 
			
(6)		Excludes volumes and gross production under our elective processing arrangements. For a description of our elective processing arrangements, please read “Business — Gathering and Processing Segment — Gloria System.”	

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RISK FACTORS
 
Limited partner units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.
 
If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.
 
Risks Related to our Business
 
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.

In order to pay the minimum quarterly distribution of $0.4125 per unit, or $1.65 per unit on an annualized basis, we will require available cash of approximately $3.8 million per quarter, or $15.2 million per year, based on the number of common and subordinated units and the 2.0% general partner interest to be outstanding immediately after completion of this offering. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

			
 	• 	the volume of natural gas we gather, process and transport;	
 		
 	• 	the level of production of oil and natural gas and the resultant market prices of oil and natural gas and NGLs;	
 		
 	• 	realized pricing impacts on our revenue and expenses that are directly subject to commodity price exposure;	
 		
 	• 	the market prices of natural gas and NGLs relative to one another, which affects our processing margins;	
 		
 	• 	capacity charges and volumetric fees associated with our transportation services;	
 		
 	• 	the level of competition from other midstream energy companies in our geographic markets;	
 		
 	• 	the level of our operating, maintenance and general and administrative costs; and	
 		
 	• 	regulatory action affecting the supply of, or demand for, natural gas, the transportation rates we can charge on our regulated pipelines, how we contract for services, our existing contracts, our operating costs or our operating flexibility.	
 
In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

 	• 	the level of capital expenditures we make;	
 		
 	• 	the cost of acquisitions, if any;	
 		
 	• 	our debt service requirements and other liabilities;	
 		
 	• 	fluctuations in our working capital needs;	

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 	• 	our ability to borrow funds and access capital markets;	
 		
 	• 	restrictions contained in our debt agreements;	
 		
 	• 	the amount of cash reserves established by our general partner; and	
 		
 	• 	other business risks affecting our cash levels.	
 
For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our Cash Distribution Policy and Restrictions on Distributions.”
 
On a historical as adjusted basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2010 and for the twelve months ended March 31, 2011.

We must generate approximately $15.2 million of available cash to pay the minimum quarterly distribution for four quarters on all of our common and subordinated units that will be outstanding immediately following this offering, as well as the corresponding distribution on our 2.0% general partner interest. The amount of historical as adjusted available cash generated during the year ended December 31, 2010 and for the twelve months ended March 31, 2011 would not have been sufficient to allow us to pay the full minimum quarterly distribution on our common and subordinated units as well as the corresponding distribution on our 2.0% general partner interest, during those periods. Specifically, the amount of historical as adjusted available cash generated during the year ended December 31, 2010 would have been sufficient to pay the minimum quarterly distribution on all of our common units, but only 31.6% of the minimum quarterly distribution on our subordinated units. Likewise, the amount of historical as adjusted available cash generated during the twelve months ended March 31, 2011 would have been sufficient to pay the minimum quarterly distribution on all of our common units, but only 43.1% of the minimum quarterly distribution on our subordinated units. For a calculation of our ability to make cash distributions to our unitholders based on our historical as adjusted results, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The assumptions underlying the forecast of cash available for distribution that we include in “Our Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.
 
The forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, adjusted EBITDA and cash available for distribution for the twelve months ending June 30, 2012. The financial forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks, including risks that expansion projects do not result in an increase in gathered and transported volumes, and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.
 
Because of the natural decline in production from existing wells in our areas of operation, our success depends on our ability to obtain new sources of natural gas, which is dependent on factors beyond our control. Any decrease in the volumes of natural gas that we gather, process or transport could adversely affect our business and operating results.
 
The natural gas volumes that support our business are dependent on the level of production from natural gas and oil wells connected to our systems, the production of which will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas. The primary factors affecting

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our ability to obtain non-dedicated sources of natural gas include (i) the level of successful drilling activity in our areas of operation and (ii) our ability to compete for volumes from successful new wells.
 
We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things:

 	• 	the availability and cost of capital;	
 		
 	• 	prevailing and projected oil and natural gas and NGL prices;	
 		
 	• 	demand for oil, natural gas and NGLs;	
 		
 	• 	levels of reserves;	
 		
 	• 	geological considerations;	
 		
 	• 	environmental or other governmental regulations, including the availability of drilling permits; and	
 		
 	• 	the availability of drilling rigs and other production and development costs.	
 
Fluctuations in energy prices can also greatly affect the development of new oil and natural gas reserves. Further declines in natural gas prices could have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our assets.
 
Because of these and other factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, it could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.
 
Natural gas, NGL and other commodity prices are volatile, and a reduction in these prices in absolute terms, or an adverse change in the prices of natural gas and NGLs relative to one another, could adversely affect our gross margin and cash flow and our ability to make distributions to our unitholders.
 
We are subject to risks due to frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. The NYMEX daily settlement price for natural gas for the forward month contract in 2010 ranged from a high of $6.01 per MMBtu to a low of $3.29 per MMBtu. Natural gas prices reached relatively high levels in 2005 and early 2006 and have exhibited significant volatility since then, including a sustained decline beginning in 2008, with the forward month gas futures contracts closing at a seven-year low of $2.51 per MMBtu in September 2009. NGL prices are generally positively correlated to the price of WTI crude oil, which has also exhibited frequent and substantial fluctuations. The NYMEX daily settlement price for WTI crude oil for the forward month contract in 2010 ranged from a high of $91.51 per Bbl to a low of $66.88 per Bbl. Crude oil prices reached historically high levels in July 2008, hitting a peak of $145.63 per Bbl, and have demonstrated substantial volatility since then, with the forward month crude oil futures contracts ranging from $30.81 per Bbl in December 2008 to above $100.00 per Bbl in March 2011.
 
The markets for and prices of natural gas, NGLs and other hydrocarbon commodities depend on factors that are beyond our control. These factors include the supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:

 	• 	worldwide economic conditions;	
 		
 	• 	worldwide political events, including actions taken by foreign oil and gas producing nations;	
 		
 	• 	worldwide weather events and conditions, including natural disasters and seasonal changes;	
 		
 	• 	the levels of domestic production and consumer demand;	

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 	• 	the availability of imported liquefied natural gas, or LNG;	
 		
 	• 	the availability of transportation systems with adequate capacity;	
 		
 	• 	the volatility and uncertainty of regional pricing differentials;	
 		
 	• 	the price and availability of alternative fuels;	
 		
 	• 	the effect of energy conservation measures;	
 		
 	• 	the nature and extent of governmental regulation and taxation; and	
 		
 	• 	the anticipated future prices of oil, natural gas, NGLs and other commodities.	

In our Gathering and Processing segment, we have exposure to direct commodity price risk under percent-of-proceeds processing contracts as well as under our elective processing arrangements. Under percent-of-proceeds arrangements, we generally purchase natural gas from producers and retain an agreed percentage of the proceeds (in cash or in-kind) from the sale at market prices of pipeline-quality natural gas and NGLs resulting from our processing activities. We also purchase natural gas at various receipt points, process the gas at a third-party owned natural gas processing facility and sell our portion of the residue gas and NGLs. Under percent-of-proceeds arrangements, our revenue and our cash flows increase or decrease as the prices of natural gas and NGLs fluctuate. When we process natural gas that we purchase for our own account, the relationship between natural gas prices and NGL prices also affects our profitability. When natural gas prices are low relative to NGL prices, it is more profitable for us to process the natural gas that we purchase and process for our own account. When natural gas prices are high relative to NGL prices, it is less profitable for us and our customers to process natural gas both because of the higher value of natural gas and because of the increased cost (principally that of natural gas shrink that occurs during processing and use of natural gas as a fuel) of separating the mixed NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices relative to NGL prices reduce our processing margins or reduce the volume of natural gas processed pursuant to our elective processing arrangements. For the year ended December 31, 2010 and for the quarter ended March 31, 2011, percent-of-proceeds arrangements accounted for approximately 34.6% and 40.5%, respectively, of our gross margin, or 53.6% and 61.0%, respectively, of the segment gross margin in our Gathering and Processing segment. For a discussion of these arrangements, please read “Industry Overview — Typical Midstream Contractual Arrangements.”

A decrease in demand for natural gas, NGLs or condensate by the petrochemical, refining or heating industries, could adversely affect the profitability of our midstream business.
 
A decrease in demand for natural gas, NGLs or condensate by the petrochemical, refining or heating industries, could adversely affect the profitability of our midstream business. Various factors impact the demand for natural gas, NGLs and condensate, including general economic conditions, extended periods of ethane rejection, increased competition from petroleum-based products due to pricing differences, adverse weather conditions, availability of natural gas processing and transportation capacity and government regulations affecting prices and production levels of natural gas, NGLs and condensate.
 
Our hedging activities may not be effective in reducing our direct exposure to commodity price risk and the variability of our cash flows and may, in certain circumstances, increase the variability of our cash flows.

We have entered into derivative transactions related to only a portion of the equity volumes of NGLs to which we take title. As a result, we will continue to have direct commodity price risk to the unhedged portion of our NGL equity volumes. We currently have no hedges in place beyond December 2012. Our actual future volumes may be significantly higher or lower than we estimated at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimated, we will have greater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a reduction of our

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liquidity. The derivative instruments we utilize for these hedges are based on posted market prices, which may be lower than the actual NGL prices that we realize in our operations. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the variability of our cash flows, and in certain circumstances may actually increase the variability of our cash flows. To the extent we hedge our commodity price risk, we may forego the benefits we would otherwise experience if commodity prices were to change in our favor. We do not enter into derivative transactions with respect to the volumes of natural gas or condensate that we purchase and sell.
 
We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks.
 
We purchase from producers and other suppliers a substantial amount of the natural gas that flows through our pipelines and processing facilities for sale to third parties, including natural gas marketers and other purchasers. We are exposed to fluctuations in the price of natural gas through volumes sold pursuant to percent-of-proceeds arrangements as well as through volumes sold pursuant to our fixed-margin contracts.
 
In order to mitigate our direct commodity price exposure, we do not enter into natural gas hedge contracts, but rather attempt to balance our natural gas sales with our natural gas purchases on an aggregate basis across all of our systems. We may not be successful in balancing our purchases and sales, and as such may become exposed to fluctuations in the price of natural gas. For example, we are currently net purchasers of natural gas on certain of our systems and net sellers of natural gas on certain of our other systems. Our overall net position with respect to natural gas can change over time and our exposure to fluctuations in natural gas prices could materially increase, which in turn could result in increased volatility in our revenue, gross margin and cash flows.
 
Although we enter into back-to-back purchases and sales of natural gas in our fixed-margin contracts in which we purchase natural gas from producers or suppliers at receipt points on our systems and simultaneously sell an identical volume of natural gas at delivery points on our systems, we may still be exposed to commodity price risks. For example, the volumes or timing of our purchases and sales may not correspond. In addition, a producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to become unbalanced. If our purchases and sales are unbalanced, we will face increased exposure to commodity price risks, which in turn could result in increased volatility in our revenue, gross margin and cash flows.
 
We are a relatively small enterprise, and our management has limited history with our assets and no experience in managing our business as a publicly traded partnership. As a result, operational, financial and other events in the ordinary course of business could disproportionately affect us, and our ability to grow our business could be significantly limited.
 
We will be smaller than many of the other companies in our industry for the foreseeable future, not only in terms of market capitalization but also in terms of managerial, operational and financial resources. Consequently, an operational incident, customer loss or other event that would not significantly impact the business and operations of the larger companies in our industry may have a material adverse impact on our business and results of operations. In addition, our executive management team is relatively small with no experience in managing our business as a publicly traded partnership and has managed our business and assets for less than two years. As a result, we may not be able to anticipate or respond to material changes or other events in our business as effectively as if our executive management team had such experience and had managed our business and assets for many years. Furthermore, acquisitions and other growth projects may place a significant strain on our management resources. As a result, our ability to execute our growth strategy and to integrate acquisitions and expansion projects successfully into our existing operations could be significantly limited.

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We currently have a limited accounting staff, and if we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.
 
Upon the completion of this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Effective internal controls are necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We prepare our consolidated financial statements in accordance with GAAP, but our internal accounting controls may not meet all standards applicable to companies with publicly traded securities. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. We must comply with Section 404 for our fiscal year ending December 31, 2012. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations.
 
Prior to this offering, we have been a private company and have not been required to file reports with the SEC. We currently have limited accounting personnel, and while we have begun the process of evaluating the adequacy of our accounting personnel staffing level and other matters related to our internal controls over financial reporting, we cannot predict the outcome of our review at this time.
 
Given the difficulties inherent in the design and operation of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our, or our independent registered public accounting firm’s, future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Any failure to implement and maintain effective internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.
 
We depend on a relatively small number of customers for a significant portion of our gross margin. The loss of any one or more of these customers could adversely affect our ability to make distributions to you.

A significant percentage of the gross margin in each of our segments is attributable to a relatively small number of customers. Additionally, a number of customers upon which our business depends are small companies that may in the future have limited access to capital or that may, as a result of operational incidents or other events, be disproportionately affected as a compared to larger, better capitalized companies. In our Gathering and Processing segment, Contango Operators Inc. and Venture Oil & Gas Co. accounted for approximately 19% and 13%, respectively, of our segment gross margin for the year ended December 31, 2010 and approximately 15% and 23%, respectively, of our segment gross margin for the quarter ended March 31, 2011. In our Transmission segment, Calpine Corporation accounted for approximately 38% of our segment gross margin for the year ended December 31, 2010 and approximately 30% of our segment gross margin for the quarter ended March 31, 2011. Although we have gathering, processing or transmission contracts with each of these customers of varying duration and commercial terms, if one or more of these customers were to default on their contract or if we were unable to renew our contract with one or more of these customers on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all. In any of these situations, our gross margin and cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our gross margin.

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If third-party pipelines or other midstream facilities interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenue and cash available for distribution could be adversely affected.
 
Our natural gas gathering and processing and transportation systems connect to other pipelines or facilities, the majority of which, such as the Southern Natural Gas Company, or Sonat, pipeline, the Toca plant, oil gathering lines on Quivira and the Burns Point processing plant, as well as the Destin, Tennessee Gas and Transco pipelines, are owned and operated by third parties. For example, our elective processing arrangements are entirely dependent on the Toca plant for processing services and the Sonat pipeline for natural gas takeaway capacity and are substantially dependent on the Tennessee Gas Pipeline, or TGP, for natural gas supply volumes. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from hurricanes or other operational hazards. If any of these pipelines or other midstream facilities becomes unable to receive or transport natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenue and cash available for distribution could be adversely affected.
 
Our reliance on our key customers exposes us to their credit risks, and any material nonpayment or nonperformance by our key customers or purchasers could have a material adverse effect on our revenue, gross margin and cash flows.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers to which we provide services and sell commodities. Our three largest purchasers of natural gas in our Gathering and Processing segment are ConocoPhillips, Enbridge Marketing (U.S.) L.P., or EMUS, and Dow Hydrocarbons and Resources, which accounted for approximately 34%, 29% and 10%, respectively, of our segment revenue for the year ended December 31, 2010 and approximately 59%, 15% and 8%, respectively, of our segment revenue for the quarter ended March 31, 2011. Additionally, ExxonMobil and Calpine Corporation are the two largest purchasers of natural gas and transmission capacity, respectively, in our Transmission segment and accounted for approximately 43% and 10%, respectively, of our segment revenue for the year ended December 31, 2010 and approximately 50% and 7%, respectively, of our segment revenue for the quarter ended March 31, 2011.

Some of our customers may be highly leveraged or under-capitalized and subject to their own operating and regulatory risks, which could increase the risk that they may default on their obligations to us. In addition, some of our customers, such as Calpine Corporation, which emerged from bankruptcy in 2008, may have a history of bankruptcy or other material financial and liquidity issues. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our revenue, gross margin and cash flows and our ability to make cash distributions to our unitholders.
 
Our gathering, processing and transportation contracts subject us to renewal risks.
 
We gather, purchase, process, transport and sell most of the natural gas and NGLs on our systems under contracts with terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. For example, depending on prevailing market conditions at the time of a contract renewal, gathering and processing customers with percent-of-proceeds contracts may choose to switch to fee-based gathering and transportation contracts, or a producer with whom we have a natural gas purchase contract may choose to enter into a transportation contract with us and retain title to its natural gas. To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenue, gross margin and cash flows could decline and our ability to make distributions to our unitholders could be materially and adversely affected.

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The contracts on which our elective processing arrangements are based are month-to-month, and the loss of these contracts would materially and adversely affect our revenue and gross margin in our Gathering and Processing segment.

 
A substantial portion of our revenue and gross margin in our Gathering and Processing segment is generated by processing natural gas under our percent-of-proceeds arrangements with Enterprise Products Partners L.P. at its Toca plant. Our month-to-month contracts with producers on the Gloria and Lafitte systems permit us to determine, on a month-to-month basis, whether it would be more profitable for us to purchase natural gas from those producers for processing for our own account at the Toca plant or transport that natural gas in exchange for a fee. Similarly, we have the ability to purchase natural gas at the Lafitte/TGP interconnect for processing at the Toca plant when it would profitable to do so. We refer to the flexibility built into these contracts as our elective processing arrangements. During the year ended December 31, 2010, 7% and 20% of our revenue and segment gross margin, respectively, in our Gathering and Processing segment were generated under our elective processing arrangements. During the quarter ended March 31, 2011, 9% and 23% of our revenue and segment gross margin, respectively, in our Gathering and Processing segment was generated under our elective processing arrangements. Our processing contracts with Enterprise at its Toca plant are currently renewing on a month-to-month basis. Our revenue, segment gross margin and cash flows could be materially and adversely affected if we were unable to negotiate an extension of such elective processing arrangements or if Enterprise were to demand commercial terms that are less favorable to us.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.
 
We compete with other midstream companies in our areas of operation. In addition, some of our competitors are large companies that have greater financial, managerial and other resources than we do. Our competitors may expand or construct gathering, compression, treating, processing or transportation systems that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own gathering, compression, treating, processing or transportation systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
 
Significant portions of our pipeline systems have been in service for several decades and we have a limited ownership history with respect to all of our assets. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines that could have a material adverse effect on our business and results of operations.
 
We purchased our assets from Enbridge in November 2009. Significant portions of the pipeline systems that we purchased have been in service for many decades. In addition, our executive management team was hired shortly before that purchase and, consequently, has a limited history of operating our assets. There may be historical occurrences or latent issues regarding our pipeline systems that our executive management may be unaware of and that may have a material adverse effect on our business and results of operations. The age and condition of our pipeline systems could also result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our pipeline systems could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.
 
We may incur significant costs and liabilities as a result of pipeline integrity management program testing and related repairs.
 
Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the U.S. Department of Transportation, or DOT, has adopted regulations requiring pipeline operators to develop integrity management programs for

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transmission pipelines located where a leak or rupture could harm “high consequence areas,” including high population areas, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators, including us, to:

			
 	• 	perform ongoing assessments of pipeline integrity;	
 		
 	• 	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;	
 		
 	• 	maintain processes for data collection, integration and analysis;	
 		
 	• 	repair and remediate pipelines as necessary; and	
 		
 	• 	implement preventive and mitigating actions.	
 
Upon reviewing the integrity maintenance plan we inherited, we determined that we have an additional sixteen high consequence areas that we identified after we acquired our assets.
 
In addition, many states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. Although many of our natural gas facilities fall within a class that is not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with our non-exempt pipelines, particularly our AlaTenn and Midla pipelines. We currently estimate that we will incur future costs of approximately $2.1 million during 2012 to complete the testing required by existing DOT regulations. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. Such costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Additionally, should we fail to comply with DOT regulations, we could be subject to penalties and fines.
 
We intend to grow our business in part by seeking strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from third parties, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.
 
Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our distributions to our unitholders.
 
If we are unable to make accretive acquisitions from third parties, whether because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors or for any other reason, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.
 
Any acquisition involves potential risks, including, among other things:

 	• 	mistaken assumptions about volumes, revenue and costs, including synergies;	
 		
 	• 	an inability to secure adequate customer commitments to use the acquired systems or facilities;	
 		
 	• 	an inability to integrate successfully the assets or businesses we acquire, particularly given the relatively small size of our management team and its limited history with our assets;	
 		
 	• 	the assumption of unknown liabilities;	
 		
 	• 	limitations on rights to indemnity from the seller;	

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 	• 	mistaken assumptions about the overall costs of equity or debt;	
 		
 	• 	the diversion of management’s and employees’ attention from other business concerns;	
 		
 	• 	unforeseen difficulties operating in new geographic areas and business lines; and	
 		
 	• 	customer or key employee losses at the acquired businesses.	
 
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
 
Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.
 
One of the ways we intend to grow our business is through organic growth projects. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.
 
For instance, if we expand a pipeline, the construction may occur over an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed into service. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize or only materializes over a period materially longer than expected. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in that area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.
 
In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way. We may be unable to obtain such rights-of-way and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases materially, our cash flows could be adversely affected.
 
We do not intend to obtain independent evaluations of natural gas reserves connected to our gathering and transportation systems on a regular or ongoing basis; therefore, in the future, volumes of natural gas on our systems could be less than we anticipate.
 
We do not intend to obtain independent evaluations of natural gas reserves connected to our systems on a regular or ongoing basis. Accordingly, we may not have independent estimates of total reserves dedicated to some or all of our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering and transportation systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

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Recent incidents and their aftermath could lead to additional governmental regulation of the offshore exploration and production industry, which may result in substantial cost increases or delays in offshore drilling as well as our offshore natural gas gathering activities.
 
In April 2010, a deepwater exploration well located in the Gulf of Mexico, owned and operated by companies unrelated to us, sustained a blowout and subsequent explosion leading to the leaking of hydrocarbons. In response to this event, certain federal agencies and governmental officials ordered additional inspections of deepwater operations in the Gulf of Mexico. On May 28, 2010, a six-month federal moratorium was implemented on all offshore deepwater drilling projects. On October 12, 2010, the Department of the Interior announced it was lifting the deepwater drilling moratorium. Despite the fact that the drilling moratorium was lifted, this spill and its aftermath has led to additional governmental regulation of the offshore exploration and production industry and delays in the issuance of drilling permits, which may result in volume impacts, cost increases or delays in our offshore natural gas gathering activities, which could materially impact our business, financial condition and results of operations. Although none of our offshore gathering systems currently depend on deepwater production, we cannot predict with any certainty what form any additional regulation or limitations would take or what impact they may have on offshore drilling activity in general or the producers to which we provide offshore gathering services.
 
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured, our operations and financial results could be adversely affected.
 
Our operations are subject to all of the risks and hazards inherent in the gathering, compressing, treating, processing and transportation of natural gas, including:

 	• 	damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;	
 		
 	• 	inadvertent damage from construction, vehicles, farm and utility equipment;	
 		
 	• 	leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;	
 		
 	• 	ruptures, fires and explosions; and	
 		
 	• 	other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.	
 
For example, in April 2010, there was a rupture in our Bazor Ridge gathering pipeline which gathers natural gas high in hydrogen sulfide content which resulted in an extended shut-down of a significant portion of that system until the pipeline could be inspected and repaired. The affected portion of the line is the one that gathers the most significant volumes of gas on this system and delivers it to our Bazor Ridge plant, and we were required to curtail a portion of this flow volume until we built a new bypass pipeline, the Winchester Lateral, connecting this production, as well as potential new production, to the Bazor Ridge plant. The affected section of line was fully shut down for approximately 25 days and, until our Winchester Lateral was completed approximately 177 days later, we were able to gather only approximately 70% of pre-rupture flow volume. The Winchester Lateral cost $3.9 million to construct and the repairs to, and testing of, the affected sections of pipe cost approximately $0.5 million.
 
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. For example, we do not have any casualty insurance on our underground pipeline systems that would cover damage to the pipelines. Additionally, we do not have business interruption/loss of income insurance that would provide coverage in the event of damage to any of our underground facilities. In addition, although we are insured for environmental pollution resulting from environmental

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accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities.
 
Our interstate natural gas pipelines are subject to regulation by the FERC, which could adversely affect our ability to make distributions to our unitholders.
 
Our AlaTenn and Midla interstate natural gas transportation systems are subject to regulation by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA. Under the NGA, the rates for and terms of conditions of service on these interstate facilities must be just and reasonable and not unduly discriminatory. The rates and terms and conditions for our interstate pipeline services are set forth in tariffs that must be filed with and approved by the FERC. Pursuant to the FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. Any successful complaint or protest against our rates could have an adverse impact on our revenue associated with providing transportation service.
 
Under the NGA, the FERC has the authority to regulate companies that provide natural gas pipeline transportation services in interstate commerce. The FERC’s authority over such companies includes such matters as:

 	• 	rates and terms and conditions of service;	
 		
 	• 	the types of services interstate pipelines may offer to their customers;	
 		
 	• 	the certification and construction of new facilities;	
 		
 	• 	the acquisition, extension, disposition or abandonment of facilities;	
 		
 	• 	the maintenance of accounts and records;	
 		
 	• 	relationships between affiliated companies involved in certain aspects of the natural gas business;	
 		
 	• 	the initiation and discontinuation of services;	
 		
 	• 	market manipulation in connection with interstate sales, purchases or transportation of natural gas and NGLs; and	
 		
 	• 	participation by interstate pipelines in cash management arrangements.	
 
The Energy Policy Act of 2005 amended the NGA to add an anti-manipulation provision. Pursuant to the amended NGA, the FERC established rules prohibiting energy market manipulation. Also, the FERC’s rules require interstate pipelines and their affiliates to adhere to Standards of Conduct that, among other things, require that transportation employees function independently of marketing employees. The FERC also requires interstate pipelines to adhere to its rules regarding the filing and approval of transportation agreements that include provisions which differ from the transportation agreements included in their FERC gas tariff. We are conducting a review of the transportation agreements entered into by our predecessor to determine whether, and to what extent, any of our transportation agreements include such provisions. We are subject to audit by the FERC of our compliance in general, including adherence to all its rules and regulations. A violation of these rules, or any other rules, regulations or orders issued or administered by the FERC, may subject us to civil penalties, disgorgement of unjust profits, or appropriate non-monetary remedies imposed by the FERC. In addition, the Energy Policy Act of 2005 amended the NGA and the Natural Gas Policy Act of 1978, or NGPA, to increase civil and criminal penalties for any violation of the NGA, NGPA and any rules, regulations or orders of the FERC up to $1.0 million per day per violation.

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Additionally, existing rates may not reflect our current costs of operations, which may have risen since the last time our rates were approved by the FERC. Because proposed rate increases are procedurally complicated, we may have a significant period of time during which our gross margin from such FERC-regulated systems may be materially less than we have historically obtained.
 
The application of certain FERC policy statements could affect the rate of return on our equity we are allowed to recover through rates and the amount of any allowance (if any) our interstate systems can include for income taxes in establishing their rates for service, which would in turn impact our revenue and/or equity earnings.
 
In setting authorized rates of return for interstate natural gas pipelines, the FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. The FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. The FERC allows master limited partnerships, or MLPs, to be included in the proxy group to determine return on equity. However, as to such MLPs, the FERC will generally adjust the long-term growth rate used to calculate the equity cost of capital. The FERC stated that the long-term growth projection for natural gas pipeline MLPs will be equal to fifty percent of gross domestic product, or GDP, as compared to the unadjusted GDP used for corporations. Therefore, to the extent that MLPs are included in a proxy group, the FERC’s policy lowers the return on equity that might otherwise be allowed if there were no adjustment to the MLP growth projection used for the discounted cash flow model. This could lower the return on equity that we would otherwise be able to obtain.
 
The FERC currently allows partnerships, including MLPs, to include in their cost-of-service an income tax allowance if the partnership’s owners have actual or potential income tax liability, a matter that will be reviewed by the FERC on a case-by-case basis. Any changes to the FERC’s treatment of income tax allowances in cost-of-service rates or an adverse determination with respect to the inclusion of an income tax allowance in our interstate pipelines’ rates could result in an adjustment in a future rate case of our interstate pipelines’ respective equity rates of return that underlie their recourse rates and may cause their recourse rates to be set at a level that is different, and in some instances lower, than the level otherwise in effect.
 
A change in the jurisdictional characterization or regulation of our assets by federal, state or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets which could materially and adversely affect our financial condition, results of operations and cash flows.
 
Intrastate transportation facilities that do not provide interstate transmission services are exempt from the jurisdiction of the FERC under the NGA. Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that our intrastate natural gas pipelines and related facilities that are not engaged in providing interstate transmission services are engaged in exempt gathering and intrastate transportation and, therefore, are not subject to FERC jurisdiction. We believe that our natural gas gathering pipelines meet the traditional tests that the FERC has used to determine if a pipeline is a gathering pipeline and is therefore not subject to the FERC’s jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial ongoing litigation and, over time, the FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and intrastate transportation and gathering facilities, on the other, is a fact-based determination made by the FERC on a case by case basis. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil

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penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.
 
Moreover, FERC regulation affects our gathering, transportation and compression business generally. The FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, capacity release and market transparency and market center promotion, directly and indirectly affect our gathering business. In addition, the classification and regulation of our gathering and intrastate transportation facilities also are subject to change based on future determinations by the FERC, the courts or Congress.
 
State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, the FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of these companies transferring gathering facilities to federally unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels.
 
We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
 
Our natural gas gathering, compression, treating and transportation operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. Examples of these laws include:

 	• 	the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;	
 		
 	• 	the federal Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;	
 		
 	• 	the federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;	
 		
 	• 	the federal Oil Pollution Act, also known as OPA, and analogous state laws that establish strict liability for releases of oil into waters of the United States;	
 		
 	• 	the federal Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities;	
 		
 	• 	the Endangered Species Act, also known as the ESA; and	
 		
 	• 	the Toxic Substances Control Act, also known as TSCA, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.	
 
These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which

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may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.
 
There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbon wastes and potential emissions and discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering or transportation systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. In addition, changes in environmental laws occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance. Please read “Business — Environmental Matters” for more information.
 
Our operations may impact the environment or cause environmental contamination, which could result in material liabilities to us.
 
Our operations use hazardous materials, generate limited quantities of hazardous wastes and may affect runoff or drainage water. In the event of environmental contamination or a release of hazardous materials, we could become subject to claims for toxic torts, natural resource damages and other damages and for the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share. These and other impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could have a material adverse effect on us. Please read “Business — Environmental Matters.”
 
Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the natural gas services we provide.
 
In recent years, the U.S. Congress has been considering legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane, that are understood to contribute to global warming. The American Clean Energy and Security Act of 2009, passed by the House of Representatives, would, if enacted by the full Congress, have required greenhouse gas, or GHG, emissions reductions by covered sources of as much as 17% from 2005 levels by 2020 and by as much as 83% by 2050. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that smaller

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sources such as our gas-fired compressors could become subject to GHG-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.
 
Independent of Congress, the EPA is beginning to adopt regulations controlling GHG emissions under its existing Clean Air Act authority. For example, on December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In 2009, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. Our Bazor Ridge facility is currently required to report under this rule beginning in 2011. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities, including natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule, which went into effect on December 30, 2010, requires reporting of greenhouse gas emissions by regulated facilities to EPA by March 2012 for emissions during 2011 and annually thereafter. Three of our onshore compression facilities will likely be required to report under this rule, with the first report due to the EPA on March 31, 2012. In 2010, EPA also issued a final rule, known as the “Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act. Several of EPA’s greenhouse gas rules are being challenged in pending court proceedings and, depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.
 
Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas we gather, treat or otherwise handle in connection with our services. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of greenhouse gases could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas, resulting in a decrease in demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations.
 
Our pipelines may become subject to more stringent safety regulation.

Proposed pipeline safety legislation requiring more stringent spill reporting and disclosure obligations was introduced in the U.S. Congress and passed by the U.S. House of Representatives in 2010, but was not voted on in the U.S. Senate. Similar legislation has been proposed in the current session of Congress, either independently or in conjunction with the reauthorization of the Pipeline Safety Act. The Department of Transportation, or DOT, has also recently proposed legislation providing for more stringent oversight of pipelines and increased penalties for violations of safety rules, which is in addition to the Pipeline and Hazardous Materials Safety Administration’s announced intention to strengthen its rules. The Pipeline and Hazardous Materials Safety Administration, or the PHMSA, which is part of DOT, recently issued a final rule, effective October 1, 2011, applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. We believe that this rule does not apply to any of our pipelines. While we cannot predict the outcome of other proposed legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations particularly by

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extending more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines not previously subject to such requirements. Additionally, legislative and regulatory changes may also result in higher penalties for the violation of federal pipeline safety regulations. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations. We cannot predict with any certainty at this time the terms of any new laws or rules or the costs of compliance associated with such requirements.

The adoption and implementation of new statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.
 
In July 2010 federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, was enacted. The Dodd-Frank Act provides new statutory requirements for swap transactions, including oil and gas hedging transactions. These statutory requirements must be implemented through, regulation primarily through rules to be adopted by the Commodities Futures Trading Commission, or the CFTC. The Dodd-Frank Act provisions are intended to change fundamentally the way swap transactions are entered into, transforming an over-the-counter market in which parties negotiate directly with each other into a regulated market in which most swaps are to be executed on registered exchanges or swap execution facilities and cleared through central counterparties. Many market participants will be newly regulated as swap dealers or major swap participants, with new regulatory capital requirements and other regulations that may impose business conduct rules and mandate how they hold collateral or margin for swap transactions. All market participants will be subject to new reporting and recordkeeping requirements.
 
The impact of the Dodd-Frank Act on our hedging activities is uncertain at this time, and the CFTC has not yet promulgated final regulations implementing the key provisions. Although we do not believe we will need to register as a swap dealer or major swap participant, and do not believe we will be subject to the new requirements to trade on an exchange or swap execution facility or to clear swaps through a central counterparty, we may have new regulatory burdens. Moreover, the changes to the swap market as a result of Dodd-Frank implementation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps.
 
Depending on the rules and definitions adopted by the CFTC, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our willingness or ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
 
We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
 
We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

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Restrictions in our new credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.
 
We expect to enter into a new credit facility concurrently with the closing of the offering. Our new credit facility is likely to limit our ability to, among other things:

 	• 	incur additional debt;	
 		
 	• 	make distributions on or redeem or repurchase units;	
 		
 	• 	make certain investments and acquisitions;	
 		
 	• 	incur certain liens or permit them to exist;	
 		
 	• 	enter into certain types of transactions with affiliates;	
 		
 	• 	merge or consolidate with another company; and	
 		
 	• 	transfer or otherwise dispose of assets.	
 
Our new credit facility also will likely contain covenants requiring us to maintain certain financial ratios.
 
The provisions of our new credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our new credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.
 
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
 
Our future level of debt could have important consequences to us, including the following:

 	• 	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;	
 		
 	• 	our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;	
 		
 	• 	we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and	
 		
 	• 	our flexibility in responding to changing business and economic conditions may be limited.	
 
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
 
As our common units will be yield-oriented securities, increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
 
Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and implied

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distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
 
We currently have a small management team, and our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel.
 
We currently have a small management team, and our ability to operate our business and implement our strategies depends on the continued contributions of certain executive officers and key employees of our general partner. Our general partner has a smaller managerial, operational and financial staff than many of the companies in our industry. Given the small size of our management team, the loss of any one member of our management team could have a material adverse effect on our business. In addition, certain of our field operating managers are approaching retirement age. We believe that our future success will depend on our continued ability to attract and retain highly skilled management personnel with midstream natural gas industry experience and competition for these persons in the midstream natural gas industry is intense. Given our small size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.
 
A shortage of skilled labor in the midstream natural gas industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.
 
The gathering, treating, processing and transporting of natural gas requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our general partner’s employees, our results of operations could be materially and adversely affected.
 
Our work force could become unionized in the future, which could adversely affect the stability of our production and materially reduce our profitability.
 
All of our systems are operated by non-union employees of our general partner. Our employees have the right at any time under the National Labor Relations Act to form or affiliate with a union. If our employees choose to form or affiliate with a union and the terms of a union collective bargaining agreement are significantly different from our current compensation and job assignment arrangements with our employees, these arrangements could adversely affect the stability of our operations and materially reduce our profitability.
 
The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
 
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

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Risks Inherent in an Investment in Us

AIM Midstream Holdings directly owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. AIM Midstream Holdings and our general partner have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders.

Following this offering, AIM Midstream Holdings will own and control our general partner, as well as appoint all of the officers and directors of our general partner, some of whom will also be officers of AIM Midstream Holdings. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owner, AIM Midstream Holdings. Conflicts of interest may arise between AIM Midstream Holdings and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of AIM Midstream Holdings over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

 	• 	Neither our partnership agreement nor any other agreement requires AIM Midstream Holdings to pursue a business strategy that favors us.	
 		
 	• 	Our general partner is allowed to take into account the interests of parties other than us, such as AIM Midstream Holdings, in resolving conflicts of interest.	
 		
 	• 	Our partnership agreement limits the liability of and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.	
 		
 	• 	Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.	
 		
 	• 	Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.	
 		
 	• 	Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.	
 		
 	• 	Our general partner determines which costs incurred by it are reimbursable by us.	
 		
 	• 	Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.	

			
 	• 	Our partnership agreement permits us to classify up to $11.5 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights.	

			
 	• 	Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.	
 		
 	• 	Our general partner intends to limit its liability regarding our contractual and other obligations.	
 		
 	• 	Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.	

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 	• 	Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.	
 		
 	• 	Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.	
 		
 	• 	Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.	
 
Please read “Conflicts of Interest and Fiduciary Duties.”
 
AIM Midstream Holdings is not limited in its ability to compete with us and is not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.
 
AIM Midstream Holdings is not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, in the future, AIM Midstream Holdings may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Moreover, while AIM Midstream Holdings may offer us the opportunity to buy additional assets from it, it is under no contractual obligation to do so and we are unable to predict whether or when such acquisitions might be completed.
 
There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only 3,750,000 publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional common units. In addition, AIM Midstream Holdings will own 725,120 common units and 4,526,066 subordinated units, representing an aggregate of approximately 56.8% limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Furthermore, this offering is smaller than initial public offerings for midstream companies in recent years, which may lead to an even greater lack of liquidity than normal. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

 	• 	our quarterly distributions;	
 		
 	• 	our quarterly or annual earnings or those of other companies in our industry;	
 		
 	• 	the loss of a large customer;	
 		
 	• 	announcements by us or our competitors of significant contracts or acquisitions;	
 		
 	• 	changes in accounting standards, policies, guidance, interpretations or principles;	
 		
 	• 	general economic conditions;	
 		
 	• 	the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;	

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 	• 	future sales of our common units; and	
 		
 	• 	other factors described in these “Risk Factors.”	

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

 
We intend to apply to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management.”

If you are not an eligible holder, you may not receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption.
 
We have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible holders are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are U.S. individuals or entities subject to such taxation. If you are not an eligible holder, our general partner may elect not to make distributions or allocate income or loss on your units, and you run the risk of having your units redeemed by us at the lower of your purchase price cost and the then-current market price. The redemption price may be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “The Partnership Agreement — Non-Citizen Assignees; Redemption.”
 
Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.
 
Our partnership agreement gives our general partner the power to amend the agreement to avoid any adverse effect on the maximum applicable rates chargeable to customers by us under FERC regulations, or in order to reverse an adverse determination that has occurred regarding such maximum rate. If our general partner determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us, then our general partner may adopt such amendments to our partnership agreement as it determines are necessary or advisable to obtain proof of the U.S. federal income tax status of our limited partners (and their owners, to the extent relevant) and permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status. Please read “The Partnership Agreement — Non-Taxpaying Assignees; Redemption.”
 
Our general partner intends to limit its liability regarding our obligations.
 
Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or

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indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
 
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
 
We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
 
In addition, because we distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate there being limitation in our new credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.
 
Our partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units.
 
Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise, free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

 	• 	how to allocate corporate opportunities among us and its affiliates;	
 		
 	• 	whether to exercise its limited call right;	
 		
 	• 	how to exercise its voting rights with respect to the units it owns;	
 		
 	• 	whether to elect to reset target distribution levels; and	
 		
 	• 	whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.	
 
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”
 
Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

 	• 	provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any	

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 		other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;	

 	• 	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in, or not opposed to, the best interest of our partnership;	
 		
 	• 	provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and	
 		
 	• 	provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:	
 
(a) approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;
 
(b) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
 
(c) on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
 
(d) fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
 
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) and (d) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
 
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner’s board or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
 
Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
 
We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such

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situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”
 
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
 
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner will be chosen by AIM Midstream Holdings. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
 
Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

The unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the closing of this offering to be able to prevent its removal. The vote of the holders of at least 66 2 / 3 % of all outstanding limited partner units voting together as a single class is required to remove our general partner. Following the closing of this offering, AIM Midstream Holdings will own 58.0% of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
 
Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

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Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
 
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of AIM Midstream Holdings to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

You will experience immediate and substantial dilution in net tangible book value of $8.13 per common unit.

 
The estimated initial public offering price of $20.00 per common unit exceeds our pro forma net tangible book value of $11.87 per unit. Based on the estimated initial public offering price of $20.00 per common unit, you will incur immediate and substantial dilution of $8.13 per common unit. Please read “Dilution.”

We may issue additional units without your approval, which would dilute your existing ownership interests.
 
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 	• 	our existing unitholders’ proportionate ownership interest in us will decrease;	
 		
 	• 	the amount of cash available for distribution on each unit may decrease;	
 		
 	• 	because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;	
 		
 	• 	the ratio of taxable income to distributions may increase;	
 		
 	• 	the relative voting strength of each previously outstanding unit may be diminished; and	
 		
 	• 	the market price of the common units may decline.	
 
AIM Midstream Holdings may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered by this prospectus, assuming that the underwriters do not exercise their option to purchase additional common units, AIM Midstream Holdings will hold an aggregate of 725,120 common units and 4,526,066 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the closing of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, AIM Midstream Holdings will own approximately 16.0% of our outstanding common units. At the end of the

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subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), AIM Midstream Holdings will own approximately 58.0% of our outstanding common units. For additional information about this right, please read “The Partnership Agreement — Limited Call Right.”

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
 
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

 	• 	we were conducting business in a state but had not complied with that particular state’s partnership statute; or	
 		
 	• 	your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.	
 
For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement — Limited Liability.”
 
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
 
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
 
We will incur increased costs as a result of being a publicly traded partnership.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the New York Stock Exchange, or the NYSE, have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and to possibly result in our general partner having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers. We have included $2.3 million of estimated annual incremental costs associated with being a publicly traded

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partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

 
Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions to you would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to you. If we were taxed as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units. For a discussion of the federal income tax implications that would result from our treatment as a corporation in any taxable year, please read “Material Federal Income Tax Consequences — Partnership Status.”
 
Tax Risks to Common Unitholders
 
In addition to reading the following risk factors, you should read “Material Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.
 
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or IRS, on this or any other tax matter affecting us.
 
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate distributions (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
 
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
 
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.
 
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such a tax on us by Texas, and if applicable by any other state, will reduce the cash available for distribution to you. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly

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distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
 
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
 
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Recently, members of the U.S. Congress have considered substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships, which, if enacted, may or may not be applied retroactively. Although we are unable to predict whether any of these changes or any other proposals will ultimately be enacted, any such changes could negatively impact the value of an investment in our common units.
 
Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.
 
Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
 
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
 
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
 
Tax gain or loss on the disposition of our common units could be more or less than expected.
 
If you sell your common units, you will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material Federal Income Tax Consequences — Disposition of Common Units — Recognition of Gain or Loss” for a further discussion of the foregoing.

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Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
 
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.
 
We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material Federal Income Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we will adopt.
 
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
 
We will prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Andrews Kurth LLP has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read “Material Federal Income Tax Consequences — Disposition of Common Units — Allocations Between Transferors and Transferees.”
 
A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
 
Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common

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units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.
 
We will adopt certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
 
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
 
We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read “Material Federal Income Tax Consequences — Disposition of Common Units — Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

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As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
 
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We will initially own property or conduct business in a number of states, most of which currently impose a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.
 
Compliance with and changes in tax laws could adversely affect our performance.
 
We are subject to extensive tax laws and regulations, including federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $69.8 million (based on an assumed initial offering price of $20.00 per unit), after deducting underwriting discounts, commissions and structuring fees, but before paying offering expenses, from the issuance and sale of common units offered by this prospectus. We will use the net proceeds from this offering to:

			
 	• 	repay in full the outstanding balance under our existing credit facility;	

			
 	• 	pay offering expenses of approximately $3.3 million;	

 
			
 	• 	terminate, in exchange for a payment of $2.5 million, the advisory services agreement between American Midstream, LLC and AIM;	

			
 	• 	establish a cash reserve of $2.2 million related to non-recurring deferred maintenance capital expenditures for the twelve months ending June 30, 2012; and	

			
 	• 	distribute approximately $2.0 million, on a pro rata basis, to AIM Midstream Holdings, LTIP participants holding common units and our general partner. The portion of the distribution made to AIM Midstream Holdings is a partial reimbursement of capital expenditures that were funded by its initial investments in us.	

 
Immediately following the repayment of the outstanding balance under our existing credit facility with the net proceeds of this offering, we will terminate our existing credit facility and enter into a new credit facility and borrow approximately $30.0 million under that credit facility. We will use the proceeds from our borrowings to (i) fund a distribution of approximately $28.0 million, on a pro rata basis, to AIM Midstream Holdings, LTIP participants holding common units and our general partner and (ii) pay fees and expenses of approximately $2.0 million relating to our new credit facility.

The following table illustrates our use of the net proceeds from this offering and our borrowings under our new credit facility.

 	 	 	 	 	 	 	 	 	 	 	
Sources of Cash (in millions)	 	Uses of Cash (in millions)	 	 	 	
 		
Net proceeds from this offering	 	$	69.8	 	 	Repayment of outstanding balance under existing credit facility	 	$	59.8	 	
Borrowings under new credit facility	 	$	30.0	 	 	Termination of advisory services agreement	 	$	2.5	 	
 	 	 	 	 	 	Establishment of cash reserve related to non-recurring deferred maintenance capital expenditures for the twelve months ending June 30, 2012	 	$	2.2	 	
 	 	 	 	 	 	Distribution to AIM Midstream Holdings, the LTIP participants holding common units and our general partner	 	$	30.0	 	
 	 	 	 	 	 	Offering and credit facility expenses payable by us	 	$	5.3	 	
 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	99.8	 	 	Total	 	$	99.8	 	

 
A portion of the amounts to be repaid under our existing credit facility with the net proceeds of this offering were used to finance our acquisition of our assets in November 2009. As of June 6, 2011, we had approximately $59.8 million of indebtedness outstanding under our existing credit facility. This indebtedness had a weighted average interest rate of 7.3% as of June 6, 2011. At March 31, 2011, we had $56.5 million of borrowings outstanding under our existing credit facility. Our existing credit facility matures in November 2012.

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Our estimates assume an initial public offering price of $20.00 per common unit and no exercise of the underwriters’ option to purchase additional common units. An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, to increase or decrease by $3.5 million. Any increase or decrease in the initial public offering price will result in a corresponding adjustment to the distribution to AIM Midstream Holdings, the LTIP participants holding common units and our general partner from the net proceeds of this offering.

If the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from AIM Midstream Holdings a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit in this offering before expenses but after deducting underwriting discounts, commissions and structuring fees.
 
The underwriters may, from time to time, engage in transactions with and perform services for us and our affiliates in the ordinary course of business. Please read “Underwriting.”

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CAPITALIZATION
 
The following table shows:

 	• 	our historical capitalization, as of March 31, 2011; and	
 		
 	• 	our pro forma as adjusted capitalization, as of March 31, 2011, giving effect to:	

			
 	• 	our receipt and use of net proceeds of $69.8 million from the issuance and sale of 3,750,000 common units to the public at an assumed initial offering price of $20.00 per unit in the manner described in “Use of Proceeds,’’ including the repayment of all outstanding indebtedness under our existing credit facility;	

 
			
 	• 	the entry into and borrowings of $30.0 million under the new credit facility; and	

			
 	• 	the other transactions described in “Summary — Recapitalization Transactions and Partnership Structure.”	
 
We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” This table assumes that the underwriters’ option to purchase additional common units is not exercised.

 	 	 	 	 	 	 	 	 	
 	 	As of March 31, 2011	 	
 	 	 	 	 	Pro Forma,	 	
 	 	Historical	 	 	As Adjusted	 	
 	 	(in thousands)	 	
 		
Cash and cash equivalents(1)	 	$	153	 	 	$	2,353	 	
 	 	 	 	 	 	 	 	 	
Long-Term Debt:	 	 	 	 	 	 	 	 	
Existing credit facility(2)	 	$	56,500	 	 	$	—	 	
New credit facility(3)(4)	 	 	—	 	 	 	30,000	 	
 	 	 	 	 	 	 	 	 	
Total long-term debt (including current maturities)	 	$	56,500	 	 	$	30,000	 	
 	 	 	 	 	 	 	 	 	
Partners’ Capital:	 	 	 	 	 	 	 	 	
Limited partners	 	 	 	 	 	 	 	 	
Common unitholders — public	 	$	—	 	 	$	64,000	 	
Common unitholders — AIM Midstream Holdings	 	 	76,911	 	 	 	5,502	 	
Subordinated unitholders — AIM Midstream Holdings	 	 	—	 	 	 	37,248	 	
General partner	 	 	1,998	 	 	 	2,859	 	
 	 	 	 	 	 	 	 	 	
Total partners’ capital(5)	 	$	78,909	 	 	$	109,609	 	
 	 	 	 	 	 	 	 	 	
Total capitalization	 	$	135,409	 	 	$	139,609	 	

 

			
(1)		The pro forma, as adjusted amount includes $2.2 million of cash reserved for our non-recurring deferred maintenance capital expenditures.	

			
(2)		As of June 6, 2011, we had $59.8 million of borrowings outstanding under our existing credit facility (excluding $0.6 million in outstanding letters of credit). As a result, the distribution to AIM Midstream holdings, LTIP participants holding common units and our general partner implied from the table above on a pro forma basis is $3.3 million higher than the distribution described in “Use of Proceeds.”	

			
(3)		Does not include $0.6 million in currently outstanding letters of credit that will be issued under our new credit facility.	

			
(4)		We expect the initial interest rate under our new credit facility to be 3.0%.	

			
(5)		Total partners’ capital does not include $0.1 million of accumulated other comprehensive income.	

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of March 31, 2011, after giving effect to the recapitalization transactions and the offering of common units and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was $109.7 million, or $11.87 per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

 	 	 	 	 	 	 	 	 	
Assumed initial public offering price per common unit	 	 	 	 	 	$	20.00	 	
Net tangible book value per unit before the offering(1)	 	$	14.39	 	 	 	 	 	
Decrease in net tangible book value per unit attributable to purchasers in the offering	 	 	(2.52	)	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Less: Pro forma net tangible book value per unit after the offering(2)	 	 	 	 	 	 	11.87	 	
 	 	 	 	 	 	 	 	 	
Immediate dilution in tangible net book value per common unit to purchasers in the offering(3)	 	 	 	 	 	$	8.13	 	

 

 
			
(1)		Determined by dividing the number of units (852,085 common units, 4,526,066 subordinated units and 108,718 general partner units) held by our general partner and its affiliates, including AIM Midstream Holdings, and LTIP participants holding common units into the net tangible book value of our assets.	

 
			
(2)		Determined by dividing the total number of units to be outstanding after this offering (4,526,066 common units, 4,526,066 subordinated units and 184,737 general partner units) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of this offering.	

 
			
(3)		If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $9.13 and $7.13, respectively. Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the option.	

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering upon the closing of the transactions contemplated by this prospectus:

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Units Acquired	 	 	Total Consideration	 	
 	 	Number	 	 	Percent	 	 	Amount	 	 	Percent	 	
 	 	($ in thousands)	 	
 		
General partner and affiliates(1)(2)	 	 	5,486,869	 	 	 	59.4	%	 	$	78,965	 	 	 	53.1	%	
Purchasers in the offering	 	 	3,750,000	 	 	 	40.6	 	 	 	69,750	 	 	 	46.9	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	9,236,869	 	 	 	100.0	%	 	$	148,715	 	 	 	100.0	%	

 

 
			
(1)		The units acquired by our general partner and its affiliates, including AIM Midstream Holdings, and LTIP participants holding common units consist of 776,066 common units, 4,526,066 subordinated units and 184,737 general partner units.	

			
(2)		Assumes the underwriters’ option to purchase additional common units is not exercised.	

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
 
You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading “— Assumptions and Considerations” below. In addition, please read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business. For additional information regarding our historical operating results, you should refer to our historical consolidated financial statements and related notes and our Predecessor’s historical combined financial statements and related notes included elsewhere in this prospectus.
 
General
 
Rationale for Our Cash Distribution Policy
 
Our partnership agreement requires us to distribute all of our available cash quarterly. Our cash distribution policy reflects our belief that our unitholders will be better served if we distribute rather than retain our available cash. Generally, our available cash is the sum of our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.
 
Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy
 
There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except as provided in our partnership agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:

			
 	• 	Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated cash distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders. Our partnership agreement provides that in order for a determination by our general partner to be considered to have been made in good faith, our general partner must believe that the determination is in our best interests.	

 
			
 	• 	While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders other than in certain limited circumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by AIM Midstream Holdings) after the subordination period has ended. At the closing of this offering, assuming no exercise of the underwriters’ option to purchase additional common units, AIM Midstream Holdings will own our general partner and approximately 16.0% of our outstanding common units and all of our outstanding subordinated units, or 58.0% of our limited partner interests.	

			
 	• 	Even if our cash distribution policy is not modified or revoked, the amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.	
 		
 	• 	Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.	
 		
 	• 	We may lack sufficient cash to pay distributions to our unitholders for a number of reasons, including as a result of increases in our operating or general and administrative expenses, principal and interest	

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 		payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our general partner will not receive a management fee or other compensation for its management of us. However, under our partnership agreement, we are obligated to reimburse our general partner and its affiliates for all expenses incurred on our behalf. Our partnership agreement provides that our general partner will determine the amount of these reimbursed expenses.	
 
Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital
 
Because we will distribute all of our available cash to our unitholders, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we intend to distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate there being limitations in our new credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
 
Our Minimum Quarterly Distribution

Upon the closing of this offering, the board of directors of our general partner intends to adopt an initial distribution rate of $0.4125 per unit per quarter, or $1.65 per unit on an annualized basis, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter ending September 30, 2011. This equates to an aggregate cash distribution of $3.8 million per quarter, or $15.2 million on an annualized basis, based on the number of common and subordinated units anticipated to be outstanding immediately after the closing of this offering, as well as our 2.0% general partner interest. We refer to our initial quarterly distribution rate as our minimum quarterly distribution. We will adjust our first distribution for the period from the closing of this offering through September 30, 2011 based on the length of that period.

To the extent the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from AIM Midstream Holdings a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit before expenses but after deducting underwriting discounts, commissions and structuring fees. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units or subordinated units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read “Use of Proceeds.”
 
Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. In the future, our general partner’s initial 2.0% interest in these distributions may be reduced if we issue additional units and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest.

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The table below sets forth the number of common, subordinated and general partner units that we anticipate will be outstanding immediately following the closing of this offering, assuming the underwriters do not exercise their option to purchase additional common units and the aggregate distribution amounts payable on those units during the year following the closing of this offering at our minimum quarterly distribution rate of $1.65 per unit per quarter ($0.4125 per unit on an annualized basis).

 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Number of	 	 	 	 	
 	 	Units	 	 	Minimum Quarterly Distributions	 	
 	 	 	 	 	One Quarter	 	 	Annualized	 	
 		
Public Common Units	 	 	3,750,000	 	 	$	1,546,875	 	 	$	6,187,500	 	
AIM Midstream Holdings Units:	 	 	 	 	 	 	 	 	 	 	 	 	
Common Units	 	 	725,120	 	 	 	299,112	 	 	 	1,196,449	 	
Subordinated Units	 	 	4,526,066	 	 	 	1,867,002	 	 	 	7,468,009	 	
LTIP Participants Common Units	 	 	50,946	 	 	 	21,015	 	 	 	84,061	 	
General Partner Interest	 	 	184,737	 	 	 	76,204	 	 	 	304,816	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	9,236,869	 	 	$	3,810,208	 	 	$	15,240,834	 	

 
The subordination period generally will end and all of the subordinated units will convert into an equal number of common units if we have earned and paid at least $1.65 on each outstanding common and subordinated unit and the corresponding distribution on our general partner’s 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2014. The subordination period will automatically terminate and all of the subordinated units will convert into an equal number of common units if we have earned and paid at least $2.475 (150% of the annualized minimum quarterly distribution) on each outstanding common and subordinated unit and the corresponding distributions on our general partner’s 2.0% interest and incentive distribution rights for any four consecutive quarter period ending on or after September 30, 2012; provided that we have paid at least the minimum quarterly distribution from operating surplus on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner’s 2.0% interest for each quarter in that four-quarter period. Please read the “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”

If we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future except in some circumstances during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units and the corresponding distributions on our general partner’s 2.0% interest, we will use this excess available cash to pay any distribution arrearages on the common units related to prior quarters before any cash distribution is made to holders of the subordinated units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”
 
Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $1.65 per unit for the twelve months ending June 30, 2012. In those sections, we present two tables, consisting of:

			
 	• 	“Unaudited Historical As Adjusted Available Cash,” in which we present the amount of cash we would have had available for distribution on a historical as adjusted basis for our fiscal year ended December 31, 2010 and for the twelve months ended March 31, 2011, derived from our audited historical consolidated financial statements that are included in this prospectus, as adjusted to give	

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 		effect to the incremental general and administrative expenses associated with being a publicly traded partnership; and	

 	• 	“Statement of Estimated Adjusted EBITDA,” which supports our belief that we will be able to generate the sufficient estimated adjusted EBITDA to pay the minimum quarterly distribution on all units for the twelve months ending June 30, 2012.	
 
Unaudited Historical As Adjusted Available Cash for the Year Ended December 31, 2010 and for the Twelve Months Ended March 31, 2011
 
If we had completed this offering on January 1, 2010, our historical as adjusted available cash generated would have been approximately $10.0 million for the year ended December 31, 2010. This amount would have been insufficient to pay the minimum quarterly distribution on all of our common and subordinated units for such period.
 
If we had completed this offering on April 1, 2010, our historical as adjusted available cash generated would have been approximately $10.9 million for the twelve months ended March 31, 2011. This amount would have been insufficient to pay the minimum quarterly distribution on all of our common and subordinated units for such period.

Our unaudited historical as adjusted available cash for the year ended December 31, 2010 and for the twelve months ended March 31, 2011 includes $2.3 million of incremental general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership. This amount is an estimate, and our general partner will ultimately determine the actual amount of these incremental general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. Incremental general and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees and director and officer insurance expenses. These expenses are not reflected in our or our Predecessor’s historical financial statements.

Our estimate of incremental general and administrative expenses is based upon currently available information. The adjusted amounts below do not purport to present our results of operations had this offering been completed as of the date indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our historical consolidated financial statements have been prepared on an accrual basis. As a result, you should view the amount of historical as adjusted available cash only as a general indication of the amount of cash available to pay distributions that we might have generated had we completed this offering on the dates indicated.

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The following table illustrates, on a historical as adjusted basis, for the year ended December 31, 2010 and for the twelve months ended March 31, 2011, the amount of cash that would have been available for distribution to our unitholders, assuming that this offering had been completed at the beginning of such periods. Each of the adjustments reflected or presented below is explained in the footnotes to such adjustments.
 
Unaudited Historical As Adjusted Available Cash

 	 	 	 	 	 	 	 	 	
 	 	Year Ended	 	 	Twelve Months Ended	 	
 	 	December 31, 2010	 	 	March 31, 2011	 	
 	 	(in thousands, except per unit data)	 	
 		
Net Loss	 	$	(8,644	)	 	$	(10,700	)	
Adjustments to reconcile net loss to adjusted EBITDA:	 	 	 	 	 	 	 	 	
Add:	 	 	 	 	 	 	 	 	
Other non-cash items(1)	 	 	1,488	 	 	 	5,282	 	
Depreciation expense	 	 	20,013	 	 	 	20,084	 	
Interest expense	 	 	5,406	 	 	 	5,313	 	
 	 	 	 	 	 	 	 	 	
Adjusted EBITDA (2)	 	$	18,263	 	 	$	19,979	 	
Adjustments to reconcile adjusted EBITDA to Historical as Adjusted Available Cash:	 	 	 	 	 	 	 	 	
Less:	 	 	 	 	 	 	 	 	
Incremental general and administrative expenses of being a publicly traded partnership(3)	 	 	2,250	 	 	 	2,250	 	
Net cash interest expense	 	 	4,523	 	 	 	4,379	 	
Maintenance capital expenditures(4)	 	 	1,464	 	 	 	2,442	 	
Expansion capital expenditures(4)	 	 	8,804	 	 	 	8,625	 	
Add:	 	 	 	 	 	 	 	 	
Capital contributed to fund expansion capital expenditures(5)	 	 	8,804	 	 	 	8,625	 	
 	 	 	 	 	 	 	 	 	
Historical as Adjusted Available Cash	 	$	10,026	 	 	$	10,908	 	
 	 	 	 	 	 	 	 	 	
Cash Distributions	 	 	 	 	 	 	 	 	
Distributions per unit(6)	 	 	1.65	 	 	 	1.65	 	
Distributions to public common unitholders(6)	 	 	6,188	 	 	 	6,188	 	
Distributions to AIM Midstream Holdings, our general partner and LTIP participants(6)(7)	 	 	9,053	 	 	 	9,053	 	
 	 	 	 	 	 	 	 	 	
Total Distributions	 	$	15,241	 	 	$	15,241	 	
 	 	 	 	 	 	 	 	 	
Excess (Shortfall)	 	$	(5,215	)	 	$	(4,333	)	
 	 	 	 	 	 	 	 	 	
Percent of minimum quarterly distributions payable to common unitholders	 	 	100.0	%	 	 	100.0	%	
Percent of minimum quarterly distributions payable to subordinated unitholders	 	 	31.6	%	 	 	43.1	%	

 

			
(1)		Includes non-cash compensation expense related to our LTIP, an unrealized loss on our commodity derivatives and certain transaction expenses related to our formation, entry into our new credit facility and acquisition of assets.	
 		
(2)		For a definition of adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures.”	

			
(3)		Represents estimated cash expenses associated with being a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees and director and officer insurance expenses.	

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(4)		Our capital expenditures totaled $10.3 million and $11.1 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. For these periods, capital expenditures included maintenance capital expenditures and expansion capital expenditures. For the year ended December 31, 2010, we estimate that 14.3% of our capital expenditures, or $1.5 million, were maintenance capital expenditures and that 85.7% of our capital expenditures, or $8.8 million, were expansion capital expenditures. For the twelve months ended March 31, 2011, we estimate that 22.0% of our capital expenditures, or $2.4 million, were maintenance capital expenditures and that 78.0% of our capital expenditures, or $8.6 million, were expansion capital expenditures. Although we classified our capital expenditures as maintenance capital expenditures and expansion capital expenditures, we believe those classifications approximate, but do not necessarily correspond to, the definitions of estimated maintenance capital expenditures and expansion capital expenditures under our partnership agreement. While we expect that, in the future, expansion capital expenditures will primarily be funded through borrowings or the sale of debt or equity securities, we funded our expansion capital expenditures during the year ended December 31, 2010 and the twelve months ended March 31, 2011 through a capital contribution made to us by AIM Midstream Holdings and our general partner.	
 		
(5)		Consists of an aggregate of $8.8 million in capital contributed to us by AIM Midstream Holdings and our general partner in September and November of 2010 that was used to fund our expansion capital expenditures during these periods.	

			
(6)		The table above is based on the following assumptions: (i) the recapitalization transactions have been consummated and our general partner has maintained its 2.0% general partner interest, (ii) we have issued 3,750,000 common units in this offering, and (iii) the underwriters’ option to purchase additional common units has not been exercised. Please read “Summary — Recapitalization Transactions and Partnership Structure.” The table reflects the number of common and subordinated units that we anticipate will be outstanding immediately following the closing of this offering, as well as our 2.0% general partner interest, and the aggregate distribution amounts payable on those units during the year following the closing of this offering at our minimum quarterly distribution rate of $0.4125 per unit per quarter ($1.65 per unit on an annualized basis), as well as the corresponding distribution on our 2.0% general partner interest.	

 
			
(7)		Does not include common units issuable pursuant to unvested phantom units that have been granted under our LTIP. As of June 9, 2011, on a pro forma basis after giving effect to the recapitalization transactions, we had 209,824 unvested phantom units outstanding under our LTIP, none of which are subject to vesting within 60 days of the date of this prospectus.	

Estimated Adjusted EBITDA for the Twelve Months Ending June 30, 2012
 
Set forth below is a Statement of Estimated Adjusted EBITDA that supports our belief that we will be able to generate sufficient cash available for distribution to pay the annualized minimum quarterly distribution on all of our outstanding units for the twelve months ending June 30, 2012. The financial forecast presents, to the best of our knowledge and belief, the expected results of operations, adjusted EBITDA and cash available for distribution for the forecast period. We define adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation expense, certain non-cash charges such as non-cash equity compensation, unrealized losses on commodity derivative contracts and selected charges that are unusual or non-recurring, less interest income, income tax benefit, unrealized gains on commodity derivative contracts and selected gains that are unusual or non-recurring.
 
For a reconciliation of adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures.”
 
Our Statement of Estimated Adjusted EBITDA reflects our judgment, as of the date of this prospectus, of conditions we expect to exist and the course of action we expect to take in order to be able to pay the annualized minimum quarterly distribution on all of our outstanding units and the corresponding distributions on our general partner’s 2.0% interest for the twelve months ending June 30, 2012. The assumptions discussed below under “— Assumptions and Considerations” are those that we believe are significant to our ability to generate our estimated adjusted EBITDA. We believe our actual results of operations and cash flows will be sufficient to generate the minimum adjusted EBITDA necessary to pay the annualized minimum quarterly distribution on all of our outstanding common and subordinated units, as well as the corresponding distribution

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on our 2.0% general partner interest, for the twelve months ending June 30, 2012; however, we can give you no assurance that we will generate this amount. There will likely be differences between our estimated adjusted EBITDA and our actual results and those differences could be material. If we fail to generate our estimated adjusted EBITDA, we may not be able to pay the annualized minimum quarterly distribution on all of our outstanding limited partner units and the corresponding distribution on our 2.0% general partner interest. In order to fund distributions on all of our outstanding common, subordinated and general partner units at our initial rate of $1.65 per unit on an annualized basis, as well as the corresponding distribution on our 2.0% general partner interest, for the twelve months ending June 30, 2012, our adjusted EBITDA for the twelve months ending June 30, 2012 must be at least $19.5 million.

We do not, as a matter of course, make public projections as to future operations, earnings or other results. However, management has prepared the Statement of Estimated Adjusted EBITDA and related assumptions and considerations set forth below to substantiate our belief that we will have sufficient available cash to pay the annualized minimum quarterly distribution to all our unitholders for the twelve months ending June 30, 2012. This forecast is a forward-looking statement and should be read together with our historical consolidated financial statements and the accompanying notes, and our Predecessor’s historical combined financial statements and the accompanying notes included elsewhere in this prospectus, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, is substantially consistent with those guidelines and was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate the minimum adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay the aggregate annualized minimum quarterly distribution on all of our outstanding common and subordinated units, as well as the corresponding distribution on our 2.0% general partner interest, for the twelve months ending June 30, 2012. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.
 
The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. PricewaterhouseCoopers LLP has not examined, compiled or performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The reports of PricewaterhouseCoopers LLP included in this prospectus relate to our and our Predecessor’s historical financial information. It does not extend to the prospective financial information and should not be read to do so.
 
When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate the minimum adjusted EBITDA necessary to pay the annualized minimum quarterly distribution on all of our outstanding common and subordinated units, as well as the corresponding distribution on our 2.0% general partner interest, for the twelve months ending June 30, 2012.
 
We are providing the Statement of Estimated Adjusted EBITDA to supplement our historical consolidated financial statements and our Predecessor’s historical combined financial statements in support of our belief that we will have sufficient available cash to pay the annualized minimum quarterly distribution on all of our outstanding common and subordinated units, as well as the corresponding distribution on our 2.0% general partner interest, for the twelve months ending June 30, 2012. Please read below under “— Assumptions and Considerations” for further information as to the assumptions we have made for the financial forecast.
 
We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

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Statement of Estimated Adjusted EBITDA

 	 	 	 	 	
 	 	Twelve Months	 	
 	 	Ending	 	
 	 	June 30, 2012	 	
 	 	(in thousands, except	 	
 	 	per unit data)	 	
 		
Total Revenue	 	$	279,915	 	
Purchases of natural gas, NGLs and condensate	 	 	233,776	 	
 	 	 	 	 	
Gross margin(1)	 	$	46,139	 	
Operating expenses:	 	 	 	 	
Direct operating expenses	 	 	14,404	 	
Selling, general and administrative expenses(2)	 	 	10,837	 	
Depreciation expense	 	 	20,181	 	
 	 	 	 	 	
Total operating expenses	 	$	45,422	 	
 	 	 	 	 	
Operating income (loss)	 	 	717	 	
Interest expense	 	 	1,803	 	
 	 	 	 	 	
Net income (loss)	 	$	(1,086	)	
Adjustments to reconcile net income to estimated adjusted EBITDA:	 	 	 	 	
Add:	 	 	 	 	
Interest expense	 	 	1,803	 	
Non-cash compensation expense related to our LTIP	 	 	1,600	 	
Depreciation expense	 	 	20,181	 	
 	 	 	 	 	
Estimated adjusted EBITDA(1)	 	$	22,498	 	
Adjustments to reconcile estimated adjusted EBITDA to estimated cash available for distribution:	 	 	 	 	
Less:	 	 	 	 	
Cash interest expense	 	 	1,214	 	
Estimated maintenance capital expenditures(3)	 	 	3,000	 	
Non-recurring deferred maintenance capital expenditures during forecast period	 	 	2,200	 	
Expansion capital expenditures	 	 	3,755	 	
Add:	 	 	 	 	
Non-cash items(4)	 	 	5	 	
Borrowings to fund expansion capital expenditures	 	 	3,755	 	
Cash from offering proceeds reserved to fund non-recurring deferred maintenance capital expenditures	 	 	2,200	 	
 	 	 	 	 	
Estimated Cash Available for Distribution	 	$	18,289	 	
 	 	 	 	 	
Estimated Annual Cash Distributions	 	 	 	 	
Distributions per unit(5)	 	 	1.65	 	
Distributions on public common units(5)	 	 	6,188	 	
Distributions on common units held by AIM Midstream Holdings(5)	 	 	1,196	 	
Distributions on subordinated units held by AIM Midstream Holdings(5)	 	 	7,468	 	
Distributions to our general partner(5)	 	 	305	 	
Distributions on common units held by LTIP participants(5)(6)	 	 	84	 	
Total Estimated Annual Distributions	 	$	15,241	 	
 	 	 	 	 	
Excess Cash Available for Distributions	 	$	3,048	 	
 	 	 	 	 	
Minimum Estimated Adjusted EBITDA	 	$	19,450	 	
 	 	 	 	 	
Percent of minimum quarterly distributions payable to common unitholders	 	 	100	%	
Percent of minimum quarterly distributions payable to subordinated unitholders	 	 	100	%	

 

			
(1)		For definitions of adjusted EBITDA and gross margin, please read “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures.”	

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(2)		Includes $2.3 million of estimated cash expenses associated with being a publicly traded partnership, such as expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley compliance, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees and director and officer insurance expenses.	

 
			
(3)		The 3.0 million of estimated maintenance capital expenditures for the forecast period does not include $1.5 million of forecasted integrity management expenditures for that period, which amount is included in direct operating expenses as required by GAAP.	

 
			
(4)		Represents estimated non-cash costs associated with our commodity price hedging program and non-cash revenue from our construction, operating and maintenance agreements.	

 
			
(5)		The table above is based on the assumption that the underwriters’ option to purchase additional common units has not been exercised and reflects the number of common and subordinated units that we anticipate will be outstanding immediately following the closing of this offering, as well as our 2.0% general partner interest, and the aggregate distribution amounts payable on those units during the forecast period at our minimum quarterly distribution rate of $1.65 per unit on an annualized basis, as well as the corresponding distribution on our 2.0% general partner interest.	

 
			
(6)		Does not include common units issuable pursuant to unvested phantom units that have been granted under our LTIP. As of June 9, 2011, on a pro forma basis after giving effect to the recapitalization transactions we had 209,824 unvested phantom units outstanding under our LTIP, none of which are subject to vesting within 60 days of the date of this prospectus.	

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Assumptions and Considerations
 
Set forth below are the material assumptions that we have made in order to demonstrate our ability to generate our estimated adjusted EBITDA for the twelve months ending June 30, 2012.
 
General Considerations and Sensitivity Analysis

 	• 	Revenue and operating expenses are net of intercompany transactions.	

			
 	• 	We estimate that the price of natural gas, NGLs and condensate for the twelve months ending June 30, 2012 will average $4.72 per Mcf, $1.51 per gallon and $2.41 per gallon, respectively. These estimates for the price of natural gas, NGLs and condensate were prepared using forward NYMEX natural gas, OPIS NGL and NYMEX crude oil strip prices, respectively, as of May 25, 2011. The prices we expect to realize reflect various discounts or premiums to these NYMEX- and OPIS-based prices due to transportation, quality and regional price adjustments as well as the effect of the hedging program described below.	

 
			
 	• 	Our estimated revenue, gross margin and adjusted EBITDA include the effect of our commodity price hedging program under which we have hedged a portion of the commodity price risk related to our expected NGL sales with swaps and puts, primarily on individual NGL components. Our hedging program for the twelve months ending June 30, 2012 covers approximately 89% of our expected NGL equity volumes for that period. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk.”	

 
			
 	• 	System throughput volumes and realized natural gas and NGL prices are the key factors that will influence whether the amount of cash available for distribution for the twelve months ending June 30, 2012 is above or below our forecast. For example, if all other assumptions are held constant, a 5.0% increase or decrease in volumes across all of our assets above or below forecasted levels would result in a $1.6 million increase or decrease, respectively, in cash available for distribution. A 5.0% increase or decrease in the price of natural gas above or below forecasted levels would result in a $0.2 million decrease or increase, respectively, in cash available for distribution. A 5.0% decrease in the price of NGLs below forecasted levels, including the effect of our existing hedges, would result in a $0.4 million decrease in cash available for distribution. A 5.0% increase in the price of NGLs above forecasted levels, including the effect of our existing hedges, would result in a $0.4 million increase in cash available for distribution. A decrease in forecasted cash flow of greater than $3.0 million would result in our generating less than the minimum cash required to pay distributions during the forecast period.	

Total Revenue

We estimate that we will generate total revenue of $279.9 million for the twelve months ending June 30, 2012, compared to $211.9 million and $221.0 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. This increase primarily relates to higher expected volumes and higher NGL and condensate prices on our systems as described below. Please read “— Gathering and Processing Segment Gross Margin” and “— Transmission Segment Gross Margin.”

Purchases of Natural Gas, NGLs and Condensate

We estimate that total purchases of natural gas, NGLs and condensate for the twelve months ending June 30, 2012 will be $233.8 million, compared to $173.8 million and $183.8 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. The expected increase in purchases of natural gas, NGLs and condensate for the twelve months ending June 30, 2012 compared to each of the year ended December 31, 2010 and the twelve months ended March 31, 2011 is primarily due to expected higher volumes on our systems and higher NGL and condensate prices, as further described below. We purchase natural gas and NGLs at market prices adjusted for transportation, quality and regional price differentials. As further discussed below, $152.0 million of our estimated purchases of natural gas relate to fixed-margin contracts in our two segments.

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Gathering and Processing Segment Gross Margin

We estimate that we will generate segment gross margin for our Gathering and Processing segment of $32.9 million for the twelve months ending June 30, 2012, as compared to $24.6 million and $26.7 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. The table below outlines the composition of our estimated and actual segment gross margin for our Gathering and Processing segment for the twelve months ending June 30, 2012, the year ended December 31, 2010 and the twelve months ended March 31, 2011.

 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Historical	 	 	Projected	 	
 	 	 	 	 	Twelve Months	 	 	Twelve Months	 	
 	 	Year Ended	 	 	Ended	 	 	Ending	 	
 	 	December 31, 2010	 	 	March 31, 2011	 	 	June 30, 2012	 	
 		
Gathering and Processing Segment Gross Margin:	 	 	 	 	 	 	 	 	 	 	 	 	
Fee-based	 	$	6.5	 	 	$	7.1	 	 	$	10.0	 	
Fixed-margin	 	 	4.9	 	 	 	4.8	 	 	 	3.0	 	
Percent-of-proceeds — fee-based	 	 	0.9	 	 	 	1.7	 	 	 	2.9	 	
Percent-of-proceeds — equity	 	 	12.3	 	 	 	13.1	 	 	 	17.0	(1)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	24.6	 	 	$	26.7	 	 	$	32.9	 	

 

			
(1)		Includes a net realized loss of $1.1 million due to our hedging program.	
 
With respect to the fee-based and fixed-margin portions of our estimated segment gross margin, the increase is primarily attributable to higher estimated volumes on our systems, as further described below. The increase in segment gross margin related to the sale of our equity volumes under our percent-of-proceeds arrangements is attributable to increased estimated volumes on our Gloria and Bazor Ridge systems as well as increased estimated NGL prices.

Throughput and Processing Volumes.   We estimate that we will transport an average of 252.6 MMcf/d of natural gas and process an average of 48.6 MMcf/d of natural gas for the twelve months ending June 30, 2012, compared to an average of approximately 175.6 MMcf/d and 36.8 MMcf/d, respectively, for the year ended December 31, 2010 and an average of approximately 195.1 MMcf/d and 42.7 MMcf/d, respectively, for the twelve months ended March 31, 2011. The table below outlines the composition of our estimated and actual volumes for our Gathering and Processing segment for the twelve months ending June 30, 2012, the year ended December 31, 2010 and the twelve months ended March 31, 2011.

 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Historical	 	 	Projected	 	
 	 	 	 	 	Twelve Months	 	 	Twelve Months	 	
 	 	Year Ended	 	 	Ended	 	 	Ending June 30,	 	
 	 	December 31, 2010	 	 	March 31, 2011	 	 	2012	 	
 		
Throughput Volumes (MMcf/d):	 	 	 	 	 	 	 	 	 	 	 	 	
Fee-based	 	 	98.7	 	 	 	113.9	 	 	 	165.8	 	
Fixed-margin	 	 	65.2	 	 	 	63.4	 	 	 	47.0	 	
Percent-of-proceeds — owned plants	 	 	9.9	 	 	 	10.9	 	 	 	15.6	 	
Incremental interconnect volumes(1)	 	 	1.8	 	 	 	6.9	 	 	 	24.2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total throughput volumes	 	 	175.6	 	 	 	195.1	 	 	 	252.6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Processing Plant Inlet Volumes (MMcf/d):	 	 	 	 	 	 	 	 	 	 	 	 	
Owned plants	 	 	9.9	 	 	 	10.9	 	 	 	15.6	 	
Elective processing arrangements(2)	 	 	26.9	 	 	 	31.8	 	 	 	33.0	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total processing inlet volumes	 	 	36.8	 	 	 	42.7	 	 	 	48.6	 	

 

			
(1)		Represents volumes of natural gas that we purchase at market-based prices at the Lafitte/TGP interconnect to be processed under our elective processing arrangements. We do not receive a gathering or treating fee for such volumes.	

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(2)		Volumes processed pursuant to our elective processing arrangements include certain volumes that are also gathered on our systems pursuant to fixed-margin arrangements. The amount of volumes gathered and processed in this manner is estimated to be 8.9 MMcf/d for the twelve months ending June 30, 2012 and was 25.2 MMcf/d and 25.0 MMcf/d for the year ended December 31, 2010 and the twelve months ended March 31, 2011. This decrease was primarily the result of the conversion of two contracts from fixed-margin to fee-based.	

The increased throughput volumes estimated for the twelve months ending June 30, 2012 are primarily due to increased estimated shipments on the Gloria and Bazor Ridge systems as a result of the completion of an interconnect between TGP and our Lafitte system and the Winchester lateral, respectively, as well as new production on the Quivira system resulting from wells that were connected in late 2010. The increased processing volumes estimated for the twelve months ending June 30, 2012 are primarily due to the full-year impact of the Lafitte/TGP interconnect, the full-year impact of the Winchester lateral that relieved pipeline constraints on our Bazor Ridge system, new production connected to our Bazor Ridge system and planned growth projects.

Gathering Fees.   For the twelve months ending June 30, 2012, we estimate that we will realize an average gathering fee of $0.16/Mcf and $0.18/Mcf for our fee-based and fixed-margin gathering activities, respectively, and an average fee of $0.51/Mcf related to the fee-based portion of our percent-of-proceeds arrangements at our owned plants (we do not receive a gathering or treating fee with respect to our incremental interconnect volumes). This compares to $0.18/Mcf, $0.21/Mcf and $0.26/Mcf, respectively, for the year ended December 31, 2010 and $0.17/Mcf, $0.21/Mcf and $0.42/Mcf, respectively, for the twelve months ended March 31, 2011. Our estimated gathering and fixed-margin fees are generally consistent with those realized on a historical basis. Our estimated fees under the fee-based portion of our percent-of-proceeds arrangements are expected to increase primarily due to an additional fee we collect on volumes associated with the Winchester lateral.

Gathering and Processing Product Sales and Purchases.   The table below outlines the amount and composition of our estimated natural gas, NGL and condensate sales volumes, revenue and associated product purchase costs for the twelve months ending June 30, 2012 without giving effect to our hedging program.

 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Sales Volume	 	 	Revenue	 	 	Purchase Cost	 	
 	 	 	 	 	(in millions)	 	
 		
Gathering and Processing Product Sales:	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas fixed-margin (MMcf/d)	 	 	47.0	 	 	$	86.3	 	 	$	83.2	 	
Percent-of-proceeds arrangements at owned plants(1):	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas (MMcf/d)	 	 	7.5	 	 	 	12.9	 	 	 	10.0	 	
NGLs (Mgal/d)	 	 	59.2	 	 	 	29.6	 	 	 	22.7	 	
Condensate (Mgal/d)	 	 	6.8	 	 	 	5.8	 	 	 	4.6	 	
Elective processing arrangements(2):	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas (MMcf/d, net)	 	 	21.0	 	 	 	38.4	 	 	 	44.4	 	
NGLs (Mgal/d, net)	 	 	24.1	 	 	 	12.4	 	 	 	—	 	
Condensate (Mgal/d, net)	 	 	0.7	 	 	 	0.7	 	 	 	—	 	

 

			
(1)		Represents gross sales volumes, for which we are entitled to retain a percentage of the sales proceeds and remit back the remainder to the producer.	
 		
(2)		Represents net equity sales volumes pursuant to our elective processing arrangements.	
 
For the year ended December 31, 2010, we sold an average of 72.9 MMcf/d of natural gas at an average realized price of $4.61/Mcf, an average of 62.2 Mgal/d of NGLs at an average realized price of $1.08/gal and an average of 5.9 Mgal/d of condensate at an average realized price of $1.82/gal. For the twelve months ended March 31, 2011, we sold an average of 76.3 MMcf/d of natural gas at an average realized price of $4.22/Mcf, an average of 70.8 Mgal/d of NGLs at an average realized price of $1.12/gal and an average of 6.8 Mgal/d of condensate at an average realized price of $1.91/gal. Additionally, total purchases of natural gas, NGLs and

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condensate in our Gathering and Processing segment were $133.9 million and $133.6 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively.
 
Transmission Segment Gross Margin

We estimate that we will generate segment gross margin for our Transmission segment of $13.2 million for the twelve months ending June 30, 2012, as compared to $13.5 million and $14.0 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. The table below outlines the composition of our estimated and actual segment gross margin for our Transmission segment for the twelve months ending June 30, 2012, the year ended December 31, 2010 and the twelve months ended March 31, 2011.

 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Historical	 	 	Projected	 	
 	 	 	 	 	Twelve Months	 	 	Twelve Months	 	
 	 	Year Ended	 	 	Ended	 	 	Ending	 	
 	 	December 31, 2010	 	 	March 31, 2011	 	 	June 30, 2012	 	
 	 	(in millions)	 	
 		
Transmission Segment Gross Margin:	 	 	 	 	 	 	 	 	 	 	 	 	
Firm transportation contracts	 	$	10.8	 	 	$	10.8	 	 	$	11.0	 	
Interruptible transportation contracts	 	 	2.0	 	 	 	2.3	 	 	 	1.7	 	
Fixed-margin	 	 	0.7	 	 	 	0.9	 	 	 	0.5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	13.5	 	 	$	14.0	 	 	$	13.2	 	

 
Transportation Volumes.   We estimate that we will transport 328.6 MMcf/d of natural gas for the twelve months ending June 30, 2012, compared to an average of approximately 350.2 MMcf/d and 372.4 MMcf/d for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. Additionally, we estimate that we will have 702.7 MMcf/d of reserved capacity pursuant to firm transportation contracts during the twelve months ending June 30, 2012, compared to approximately 677.6 MMcf/d and 692.4 MMcf/d for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. We estimate that transportation volumes will consist of 251.8 MMcf/d and 38.1 MMcf/d of volumes pursuant to firm and interruptible transportation contracts, respectively, and 38.7 MMcf/d of volumes pursuant to fixed-margin contracts during the twelve months ending June 30, 2012, compared to 269.3 MMcf/d, 53.5 MMcf/d and 27.4 MMcf/d, respectively, for the year ended December 31, 2010 and 292.4 MMcf/d, 46.9 MMcf/d and 33.1 MMcf/d, respectively, for the twelve months ended March 31, 2011.

 
Transportation Fees.   We estimate that we will realize an aggregate average fee of $0.04/Mcf for capacity reservation and variable use fees pursuant to firm transportation contracts, an average fee of $0.12/Mcf for transportation pursuant to interruptible contracts and an average fee of $0.04/Mcf for transportation pursuant fixed-margin activities for the twelve months ending June 30, 2012, compared to an average of $0.04/Mcf, $0.10/Mcf and $0.07/Mcf, respectively, for the year ended December 31, 2010 and an average of $0.04/Mcf, $0.13/Mcf and $0.08/Mcf, respectively, for the twelve months ended March 31, 2011 due primarily to the full-year impact of a new fixed-margin contract with a lower transportation fee that we entered into in June 2010.

 
Transmission Product Sales and Purchases.   We estimate that our fixed-margin activities will generate $69.4 million of revenue related to natural gas sales and $68.8 million of expense related to natural gas product purchases for the forecast period.

Direct Operating Expense
 
We estimate that direct operating expense for the twelve months ending June 30, 2012 will be $14.4 million compared to $12.2 million and $12.6 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. Direct operating expense is comprised primarily of direct labor costs, insurance costs, ad valorem and property taxes, repair and maintenance costs, integrity management costs, utilities, lost and unaccounted for gas and contract services. As such costs are almost entirely of a fixed nature, direct operating expense will not vary significantly with increases or decreases in revenue and gross margin. The

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expected increase is primarily due to $1.5 million in costs associated with our integrity management program during the forecast period that were not required to be incurred during these historical periods pursuant to the program.
 
Selling, General and Administrative Expense
 
We estimate that SG&A expense for the twelve months ending June 30, 2012 will be $10.8 million, compared to $8.9 million and $9.4 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. These amounts include $1.6 million, $1.7 million and $2.0 million of cash and non-cash expenses, respectively, associated with grants pursuant to our LTIP program. This increase is attributable to the estimated $2.3 million of incremental SG&A expense that we expect to incur as a result of being a publicly traded partnership. SG&A expense is comprised primarily of fixed costs and will not vary significantly with increases or decreases in revenue or gross margin.
 
Depreciation Expense
 
We estimate that depreciation expense for the twelve months ending June 30, 2012 will be $20.2 million compared to $20.0 million and $20.1 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. Estimated depreciation expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The increase in depreciation expense is primarily attributable to additional depreciation associated with capital projects that we expect to be placed in service during the forecast period. Depreciation expenses are derived from asset value and useful life, and therefore will not vary with increases or decreases in revenue and gross margin.
 
Capital Expenditures

We estimate that total capital expenditures for the twelve months ending June 30, 2012 will be $8.9 million compared to $10.3 million and $11.1 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. Total capital expenditures for the twelve months ending June 30, 2012 includes $2.2 million of estimated non-recurring deferred maintenance capital expenditures for which we have reserved $2.2 million of net proceeds from this offering. Our estimate is based on the following assumptions:

			
 	• 	We estimate that maintenance capital expenditures for the twelve months ending June 30, 2012 will total $5.2 million. These expenditures include planned maintenance on our systems. This compares to $1.5 million and $2.4 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. The $5.2 million in estimated maintenance capital expenditures includes the $3.0 million in average estimated annual maintenance capital expenditures that we expect to be required to maintain our assets over the long-term. In addition, we have included $2.2 million of estimated maintenance capital expenditures required for deferred maintenance items on certain of our assets that we identified based upon a thorough review and evaluation of our assets following the closing of our November 2009 acquisition from Enbridge. In order to fund the $2.2 million of incremental costs, we intend to establish at the closing of this offering a cash reserve with a portion of the net proceeds from this offering.	

			
 	• 	We estimate that expansion capital expenditures for the twelve months ending June 30, 2012 will be $3.8 million. These expenditures are comprised of three expansion capital projects that we believe we will pursue during the forecast period. We expect that these projects will add over $1.5 million in gross margin, which is reflected in this forecast. Our expansion capital expenditures were $8.8 million and $8.7 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. The capital projects that we expect to undertake in our forecast period include:	

			
 	• 	a cylinder upgrade on the existing Gloria compressor that we expect will increase throughput capacity on the Gloria system by approximately 7 MMcf/d and that we expect to be completed in the third quarter of 2011 at a cost of approximately $0.2 million;	

			
 	• 	the construction of an interconnect and the installation of a skid-mounted treating facility along Midla, which is expected to cost approximately $0.3 million and be completed in the third quarter of 2011; and	

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 	• 	the addition of field compression capacity to the Bazor Ridge gathering system, which would provide us with the opportunity to treat new natural gas production, at an expected cost of approximately $3.4 million that we expect to complete in the first quarter of 2012.	

Financing

We estimate that interest expense will be approximately $1.8 million for the twelve months ending June 30, 2012, compared to approximately $5.4 million and $5.3 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. Our estimate of interest expense for the forecast period is based on the following assumptions:

 
			
 	• 	We will repay in full the outstanding borrowings of $59.8 million under our existing credit facility with a portion of the proceeds from this offering.	

 
			
 	• 	We will have debt outstanding as of the closing of this offering of $30.0 million.	

 
			
 	• 	We will have average outstanding borrowings of $31.8 million, including borrowings to finance our estimated expansion capital expenditures of $3.8 million, with an assumed weighted average interest rate of 3.5% under our new credit facility, which is lower than the weighted average interest rate under our existing credit facility of 7.5% and 7.6% for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively.	

			
 	• 	We will maintain a low cash balance and therefore do not forecast any interest income.	
 
Regulatory, Industry and Economic Factors
 
Our forecast for the twelve months ending June 30, 2012 is based on the following significant assumptions related to regulatory, industry and economic factors:

 	• 	There will not be any new federal, state or local regulation of the midstream energy sector, or any new interpretation of existing regulations, that will be materially adverse to our business.	
 		
 	• 	There will not be any major adverse change in the midstream energy sector, commodity prices, capital or insurance markets or general economic conditions.	

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS
 
Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.
 
Distributions of Available Cash
 
General
 
Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2009, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through September 30, 2011 based on the actual length of the period.
 
Definition of Available Cash

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

			
 	• 	less the amount of cash reserves established by our general partner at the date of determination of available cash for that quarter to:	

 	• 	provide for the proper conduct of our business (including reserves for our future capital expenditures, anticipated future credit needs and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);	

			
 	• 	comply with applicable law, any of our debt instruments or other agreements; or	

			
 	• 	provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for common and subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter and the next four quarters);	

 	• 	plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.	
 
The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners, and with the intent of the borrower to repay such borrowings within 12 months with funds other than from additional working capital borrowings. The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the 12-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.
 
Intent to Distribute the Minimum Quarterly Distribution

We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.4125 per unit, or $1.65 on an annualized basis, to the extent we have sufficient cash

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from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Our Credit Facility” for a discussion of the restrictions to be included in our new credit facility that may restrict our ability to make distributions.
 
Operating Surplus and Capital Surplus
 
General
 
All cash distributed to unitholders will be characterized as either being paid from “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.
 
Operating Surplus
 
We define operating surplus as:

			
 	• 	$11.5 million (as described below); plus	

			
 	• 	all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below); plus	
 		
 	• 	working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus	
 		
 	• 	cash distributions paid on equity issued to finance all or a portion of the construction, acquisition, development or improvement of a capital improvement or replacement of a capital asset (such as equipment or facilities) in respect of the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition, development or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset commences commercial service and the date that it is abandoned or disposed of; plus	
 		
 	• 	cash distributions paid on equity issued to pay the construction-period interest on debt incurred, or to pay construction-period distributions on equity issued, to finance the capital improvements or capital assets referred to above; less	
 		
 	• 	all of our operating expenditures (as defined below) after the closing of this offering; less	
 		
 	• 	the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less	
 		
 	• 	all working capital borrowings not repaid within 12 months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings; less	
 		
 	• 	any cash loss realized on disposition of an investment capital expenditure.	

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $11.5 million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus.

 
We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account or for a deferred purchase price in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities, (iii) sales or other

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dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of normal asset retirements or replacements, (iv) the termination of commodity hedge contracts or interest rate hedge contracts prior to the termination date specified therein (provided that cash receipts from any such termination will be included in operating surplus in equal quarterly installments over the remaining scheduled life of the contract), (v) capital contributions received and (vi) corporate reorganizations or restructurings.

 
We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses of our general partner and its affiliates, interest payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), estimated maintenance capital expenditures (as discussed in further detail below), director and officer compensation, repayment of working capital borrowings and non-pro rata repurchases of our units; provided , however , that operating expenditures will not include:

			
 	• 	repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);	
 		
 	• 	payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;	
 		
 	• 	expansion capital expenditures;	
 		
 	• 	actual maintenance capital expenditures;	
 		
 	• 	investment capital expenditures;	
 		
 	• 	payment of transaction expenses (including, but not limited to, taxes) relating to interim capital transactions;	

			
 	• 	distributions to our partners;	

 
			
 	• 	non-pro rata purchases of any class of our units made with the proceeds of an interim capital transaction; or	

 
			
 	• 	any other payments made in connection with this offering that are described in “Use of Proceeds.”	

Capital Surplus
 
Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

 	• 	borrowings other than working capital borrowings;	
 		
 	• 	sales of our equity and debt securities; and	
 		
 	• 	sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets.	
 
Characterization of Cash Distributions
 
Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

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Capital Expenditures

Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets, for the acquisition of existing, or the construction or development of new, capital assets or for any integrity management program) made to maintain our long-term operating income or operating capacity. We expect that a primary component of maintenance capital expenditures will include expenditures for routine equipment and pipeline maintenance or replacement due to obsolescence. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of the construction or development of a replacement asset that is paid in respect of the period that begins when we enter into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that any such replacement asset commences commercial service and the date that it is abandoned or disposed of.

Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus.
 
Our partnership agreement requires that an estimate of the average quarterly maintenance capital expenditures be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus for those periods will be determined by the board of directors of our general partner at least once a year, subject to approval by the Conflicts Committee. The estimate will be made annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures on a long-term basis. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures and other maintenance capital expenditures for the forecast period ending June 30, 2012, please read “Our Cash Distribution Policy and Restrictions on Distributions.”
 
The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

 	• 	it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for the quarter and subsequent quarters;	
 		
 	• 	it will increase our ability to distribute as operating surplus cash we receive from non-operating sources;	
 		
 	• 	it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights held by our general partner; and	
 		
 	• 	it will reduce the likelihood that a large actual maintenance capital expenditure in a period will prevent our general partner’s affiliates from being able to convert some or all of their subordinated units into common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.	
 
Estimated maintenance capital expenditures reduce operating surplus, but expansion capital expenditures, investment capital expenditures and actual maintenance capital expenditures do not.
 
Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued to finance the construction, acquisition or development of an improvement to our capital assets and paid in respect of the period beginning on the date that we enter into a binding obligation to commence construction, acquisition or development of the capital improvement and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or

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disposed of. Examples of expansion capital expenditures include the acquisition of equipment, or the construction, development or acquisition of additional pipeline or treating capacity or new compression capacity.
 
Capital expenditures that are made in part for expansion capital purposes and in part for other purposes will be allocated between expansion capital expenditures and expenditures for other purposes by our general partner (with the concurrence of the Conflicts Committee).
 
Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of facilities that are in excess of the maintenance of our existing operating capacity or operating income, but that are not expected to expand, for more than the short term, our operating capacity or operating income.
 
Subordination Period
 
General

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4125 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Subordination Period
 
Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day of any quarter beginning after September 30, 2014, that each of the following tests are met:

			
 	• 	distributions of available cash from operating surplus on each of the outstanding common and subordinated units equaled or exceeded $1.65 (the annualized minimum quarterly distribution) and the corresponding distributions on our 2.0% general partner interest and were made, in each case for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;	

 
			
 	• 	the adjusted operating surplus (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded (i) the sum of $1.65 (the annualized minimum quarterly distribution) on all of the outstanding common and subordinated units during those periods on a fully diluted basis and (ii) the corresponding distribution on our 2.0% general partner interest; and	

			
 	• 	there are no arrearages in payment of the minimum quarterly distribution on the common units.	
 
For purposes of determining whether sufficient adjusted operating surplus has been generated under the above conversion test, the Conflicts Committee may adjust operating surplus upwards or downwards if it determines in good faith that the amount of estimated maintenance capital expenditures used in the determination of adjusted operating surplus was materially incorrect, based on the circumstances prevailing at the time of the original estimate, for any one or more of the preceding two four-quarter periods.

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Early Termination of Subordination Period
 
Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day of any quarter beginning after September 30, 2012, that each of the following tests are met:

			
 	• 	distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $2.475 (150.0% of the annualized minimum quarterly distribution), and the corresponding distribution on our general partner’s 2.0% interest and the incentive distribution rights were made, in each case, for the four-quarter period immediately preceding that date;	

 
			
 	• 	the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $2.475 per unit (150.0% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted basis and (ii) the distributions made on our 2.0% general partner interest and the incentive distribution rights;	

 
			
 	• 	distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution of $0.4125, and we made the corresponding distribution on our 2.0% general partner interest, for each quarter during the four-quarter period immediately preceding that date; and	

			
 	• 	there are no arrearages in payment of the minimum quarterly distributions on the common units.	
 
Expiration of the Subordination Period
 
When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and no units held by our general partner and its affiliates are voted in favor of such removal:

 	• 	the subordination period will end and each subordinated unit will immediately and automatically convert into one common unit;	
 		
 	• 	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and	
 		
 	• 	our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.	
 
Adjusted Operating Surplus
 
Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:

 	• 	operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet point under the caption “— Operating Surplus and Capital Surplus — Operating Surplus” above); less	
 		
 	• 	any net increase in working capital borrowings with respect to that period; less	
 		
 	• 	any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus	
 		
 	• 	any net decrease in working capital borrowings with respect to that period; plus	
 		
 	• 	any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods; plus	

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 	• 	any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.	
 
Distributions of Available Cash from Operating Surplus during the Subordination Period
 
We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 	• 	first , 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;	
 		
 	• 	second , 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;	
 		
 	• 	third , 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and	
 		
 	• 	thereafter , in the manner described in “— General Partner Interest and Incentive Distribution Rights” below.	
 
The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.
 
Distributions of Available Cash from Operating Surplus after the Subordination Period
 
We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

 	• 	first , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and	
 		
 	• 	thereafter , in the manner described in “— General Partner Interest and Incentive Distribution Rights” below.	
 
The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.
 
General Partner Interest and Incentive Distribution Rights
 
Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest if we issue additional units. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is entitled from such 2.0% interest, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash. It may instead fund its capital contribution by the contribution to us of common units or other property.
 
Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.
 
The following discussion assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

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If for any quarter:

 	• 	we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and	
 		
 	• 	we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;	
 
then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

			
 	• 	first , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $0.47438 per unit for that quarter (the “first target distribution”);	

 
			
 	• 	second , 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $0.51563 per unit for that quarter (the “second target distribution”);	

 
			
 	• 	third , 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $0.61875 per unit for that quarter (the “third target distribution”); and	

			
 	• 	thereafter , 50.0% to all unitholders, pro rata, and 50.0% to our general partner.	
 
Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	Marginal Percentage Interest	 	
 	 	 	 	 	 	 	 	in Distributions	 	
 	 	Total Quarterly Distribution	 	 	 	 	 	General	 	
 	 	per Unit Target Amount	 	 	Unitholders	 	 	Partner	 	
 		
Minimum Quarterly Distribution	 	 	 	 	 	  $	0.41250	 	 	 	98.0	%	 	 	2.0	%	
First Target Distribution	 	 	 	 	 	up to $	0.47438	 	 	 	98.0	%	 	 	2.0	%	
Second Target Distribution	 	above $	0.47438	 	 	up to $	0.51563	 	 	 	85.0	%	 	 	15.0	%	
Third Target Distribution	 	above $	0.51563	 	 	up to $	0.61875	 	 	 	75.0	%	 	 	25.0	%	
Thereafter	 	 	 	 	 	above $	0.61875	 	 	 	50.0	%	 	 	50.0	%	

 
General Partner’s Right to Reset Incentive Distribution Levels
 
Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the Conflicts Committee, at any time when there are no

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subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the four consecutive fiscal quarters immediately preceding such time. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.
 
In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units and general partner units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us immediately prior to the reset election.
 
The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the amount of cash distributed per common unit during each of these two quarters.
 
Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

 	• 	first , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;	
 		
 	• 	second , 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;	
 		
 	• 	third , 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and	
 		
 	• 	thereafter , 50.0% to all unitholders, pro rata, and 50.0% to our general partner.	

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The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.65.

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	Marginal Percentage	 	 	 	 	
 	 	 	 	 	 	 	 	Interest in Distributions	 	 	 	 	
 	 	 	 	 	 	 	 	2.0%	 	 	 	 	 	Quarterly	 	
 	 	 	 	 	 	 	 	General	 	 	Incentive	 	 	Distributions	 	
 	 	Quarterly Distribution	 	 	 	 	 	Partner	 	 	Distribution	 	 	per Unit Following	 	
 	 	per Unit Prior to Reset	 	 	Unitholders	 	 	Interest	 	 	Rights	 	 	Hypothetical Reset	 	
 		
Minimum Quarterly Distribution	 	 	 	 	 	     $	0.41250	 	 	 	98.0	%	 	 	2.0	%	 	 	—	 	 	$	0.6500	 	
First Target Distribution	 	 	 	 	 	up to $	0.47438	 	 	 	98.0	%	 	 	2.0	%	 	 	—	 	 	 	0.7475	 	
Second Target Distribution	 	above $	0.47438	 	 	up to $	0.51563	 	 	 	85.0	%	 	 	2.0	%	 	 	13.0	%	 	 	0.8125	 	
Third Target Distribution	 	above $	0.51563	 	 	up to $	0.61875	 	 	 	75.0	%	 	 	2.0	%	 	 	23.0	%	 	 	0.9750	 	
Thereafter	 	 	 	 	 	above $	0.61875	 	 	 	50.0	%	 	 	2.0	%	 	 	48.0	%	 	 	0.9750	 	

 

			
(1)		This amount is 115.0% of the hypothetical reset minimum quarterly distribution.	
 		
(2)		This amount is 125.0% of the hypothetical reset minimum quarterly distribution.	
 		
(3)		This amount is 150.0% of the hypothetical reset minimum quarterly distribution.	

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, based on an average of the amounts distributed each quarter for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be 9,052,132 common units outstanding, our general partner has maintained its 2.0% general partner interest and the average distribution to each common unit would be $0.65 for the two quarters prior to the reset.

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	Cash	 	 	Cash Distribution to General Partner Prior to Reset	 	 	 	 	
 	 	 	 	 	Distributions to	 	 	2.0%	 	 	 	 	 	 	 	 	 	 	
 	 	Quarterly	 	 	Common	 	 	General	 	 	Incentive	 	 	 	 	 	 	 	
 	 	Distribution per	 	 	Unitholders	 	 	Partner	 	 	Distribution	 	 	 	 	 	Total	 	
 	 	Unit Prior to Reset	 	 	Prior to Reset	 	 	Interest	 	 	Rights	 	 	Total	 	 	Distributions	 	
 		
Minimum Quarterly Distribution	 	 	 	 	 	     $	0.41250	 	 	$	3,734,004	 	 	$	76,204	 	 	$	—	 	 	$	76,204	 	 	$	3,810,209	 	
First Target Distribution	 	 	 	 	 	up to $	0.47438	 	 	 	560,101	 	 	 	11,431	 	 	 	—	 	 	 	11,431	 	 	 	571,531	 	
Second Target Distribution	 	above $	0.47438	 	 	up to $	0.51563	 	 	 	373,400	 	 	 	8,786	 	 	 	57,108	 	 	 	65,894	 	 	 	439,295	 	
Third Target Distribution	 	above $	0.51563	 	 	up to $	0.61875	 	 	 	933,501	 	 	 	24,893	 	 	 	286,274	 	 	 	311,167	 	 	 	1,244,668	 	
Thereafter	 	 	 	 	 	above $	0.61875	 	 	 	282,879	 	 	 	11,315	 	 	 	271,564	 	 	 	282,879	 	 	 	565,758	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	$	5,883,886	 	 	$	132,629	 	 	$	614,946	 	 	$	747,575	 	 	$	6,631,461	 	

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The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that, as a result of the reset, there would be 9,998,203 common units outstanding, our general partner’s 2.0% interest has been maintained, and the average distribution to each common unit would be $0.65. The number of common units to be issued to our general partner upon the reset was calculated by dividing (i) the average of the amounts received by our general partner in respect of its incentive distribution rights for the two quarters prior to the reset as shown in the table above, or $614,946, by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $0.65.

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	Cash Distribution to General Partner	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	After Reset	 	 	 	 	
 	 	 	 	 	Cash	 	 	Common	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	Distributions to	 	 	Units Issued in	 	 	2.0%	 	 	 	 	 	 	 	 	 	 	
 	 	Quarterly	 	 	Common	 	 	Connection	 	 	General	 	 	Incentive	 	 	 	 	 	 	 	
 	 	Distribution per	 	 	Unitholders	 	 	With	 	 	Partner	 	 	Distribution	 	 	 	 	 	Total	 	
 	 	Unit After Reset	 	 	After Reset	 	 	Reset	 	 	Interest	 	 	Rights	 	 	Total	 	 	Distributions	 	
 		
Minimum Quarterly Distribution	 	 	 	 	 	      $	0.6500	 	 	$	5,883,886	 	 	$	614,946	 	 	$	132,629	 	 	$	—	 	 	$	747,575	 	 	$	6,631,461	 	
First Target Distribution	 	 	 	 	 	up to $	0.7475	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Second Target Distribution	 	above $	0.7475	 	 	up to $	0.8125	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Third Target Distribution	 	above $	0.8125	 	 	up to $	0.9750	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Thereafter	 	 	 	 	 	above $	0.9750	 	 	$	5,883,886	 	 	$	614,946	 	 	$	132,629	 	 	$	—	 	 	$	747,575	 	 	$	6,631,461	 	

 
Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.
 
Distributions from Capital Surplus
 
How Distributions from Capital Surplus Will Be Made
 
We will make distributions of available cash from capital surplus, if any, in the following manner:

 	• 	first , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;	
 		
 	• 	second , 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and	
 		
 	• 	thereafter , as if they were from operating surplus.	
 
The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.
 
Effect of a Distribution from Capital Surplus
 
Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

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Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50.0% being paid to the unitholders, pro rata, and 50.0% to our general partner. The percentage interests shown for our general partner include its 2.0% general partner interest and assume that our general partner has not transferred the incentive distribution rights.
 
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels
 
In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

 	• 	the minimum quarterly distribution;	
 		
 	• 	the number of common units into which a subordinated unit is convertible;	
 		
 	• 	target distribution levels;	
 		
 	• 	the unrecovered initial unit price; and	
 		
 	• 	the number of general partner units comprising the general partner interest.	
 
For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, and each subordinated unit would be convertible into two common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.
 
In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.
 
Distributions of Cash Upon Liquidation
 
General
 
If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
 
The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

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Manner of Adjustments for Gain
 
The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:

 	• 	first , to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;	
 		
 	• 	second , 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;	
 		
 	• 	third , 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;	
 		
 	• 	fourth , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98.0% to the unitholders, pro rata, and 2.0% to our general partner, for each quarter of our existence;	
 		
 	• 	fifth , 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;	
 		
 	• 	sixth , 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence;	
 		
 	• 	thereafter , 50.0% to all unitholders, pro rata, and 50.0% to our general partner.	
 
The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.
 
If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the fourth bullet point above will no longer be applicable.
 
Manner of Adjustments for Losses
 
If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and unitholders in the following manner:

 	• 	first , 98.0% to the holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;	

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 	• 	second , 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and	
 		
 	• 	thereafter , 100.0% to our general partner.	
 
If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.
 
Adjustments to Capital Accounts
 
Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners’ capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA
 
The following table presents our selected historical consolidated financial and operating data, as well as the selected historical combined financial and operating data of our Predecessor, which was comprised of 12 indirectly wholly owned subsidiaries of Enbridge, as of the dates and for the periods indicated.
 
The selected financial data as of and for the year ended December 31, 2006 are derived from the unaudited historical combined financial data of our Predecessor that are not included in this prospectus. The selected historical combined financial data presented as of and for the year ended December 31, 2007 are derived from the audited historical combined financial statements of our Predecessor that are not included in this prospectus. The selected historical combined financial data presented as of and for the year ended December 31, 2008, and as of and for the 10 months ended October 31, 2009 are derived from the audited historical combined financial statements of our Predecessor that are included elsewhere in this prospectus. The selected historical consolidated financial data presented as of December 31, 2009, for the period from August 20, 2009 (date of inception) to December 31, 2009, as of and for the year ended December 31, 2010, as of and for the quarter ended March 31, 2010 and as of and for the quarter ended March 31, 2011 are derived from our audited and unaudited historical consolidated financial statements included elsewhere in this prospectus. We acquired our assets effective November 1, 2009. During the period from our inception, on August 20, 2009, to October 31, 2009, we had no operations although we incurred certain fees and expenses of approximately $6.4 million associated with our formation and the acquisition of our assets from Enbridge, which are reflected in the “One-time transaction costs” line item of our consolidated financial data for the period from August 20, 2009 through December 31, 2009.
 
For a detailed discussion of the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with the historical audited and unaudited consolidated financial statements of American Midstream Partners, LP and related notes and our Predecessor’s audited combined financial statements and related notes included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

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The following table presents the non-GAAP financial measures adjusted EBITDA and gross margin that we use in our business and view as important supplemental measures of our performance. For a definition of these measures and a reconciliation of them to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read “ — Non-GAAP Financial Measures.”

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	American Midstream Partners Predecessor	 	 	 	American Midstream Partners, LP and Subsidiaries (Successor)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Period from	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	August 20,	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Year	 	 	 	Year	 	 	 	Year	 	 	 	10 Months	 	 	 	2009 (Inception	 	 	 	Year	 	 	Quarter	 	 	Quarter	 	
 	 	 	Ended	 	 	 	Ended	 	 	 	Ended	 	 	 	Ended	 	 	 	Date) to	 	 	 	Ended	 	 	Ended	 	 	Ended	 	
 	 	 	December 31,	 	 	 	December 31,	 	 	 	December 31,	 	 	 	October 31,	 	 	 	December 31,	 	 	 	December 31,	 	 	March 31,	 	 	March 31,	 	
 	 	 	2006	 	 	 	2007	 	 	 	2008	 	 	 	2009	 	 	 	2009	 	 	 	2010	 	 	2010	 	 	2011	 	
 	 	 	(in thousands, except per unit and operating data)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Statement of Operations Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenue	 	 	$	314,278	 	 	 	$	290,777	 	 	 	$	366,348	 	 	 	$	143,132	 	 	 	$	32,833	 	 	 	$	211,940	 	 	$	54,712	 	 	$	67,265	 	
Unrealized gain (loss) on commodity derivatives	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	—	 	 	 	(3,500	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenue	 	 	 	314,278	 	 	 	 	290,777	 	 	 	 	366,348	 	 	 	 	143,132	 	 	 	 	32,833	 	 	 	 	211,940	 	 	 	54,712	 	 	 	63,765	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Purchases of natural gas, NGLs and condensate	 	 	 	278,590	 	 	 	 	251,959	 	 	 	 	323,205	 	 	 	 	113,227	 	 	 	 	26,593	 	 	 	 	173,821	 	 	 	44,964	 	 	 	54,953	 	
Direct operating expenses	 	 	 	14,295	 	 	 	 	15,334	 	 	 	 	13,423	 	 	 	 	10,331	 	 	 	 	1,594	 	 	 	 	12,187	 	 	 	2,692	 	 	 	3,058	 	
Selling, general and administrative expenses(1)	 	 	 	7,407	 	 	 	 	10,294	 	 	 	 	8,618	 	 	 	 	8,577	 	 	 	 	1,346	 	 	 	 	8,854	 	 	 	2,113	 	 	 	2,675	 	
One-time transaction costs	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	6,404	 	 	 	 	303	 	 	 	74	 	 	 	288	 	
Depreciation expense	 	 	 	9,917	 	 	 	 	12,500	 	 	 	 	13,481	 	 	 	 	12,630	 	 	 	 	2,978	 	 	 	 	20,013	 	 	 	4,966	 	 	 	5,037	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total operating expenses	 	 	 	310,209	 	 	 	 	290,087	 	 	 	 	358,727	 	 	 	 	144,765	 	 	 	 	38,915	 	 	 	 	215,178	 	 	 	54,809	 	 	 	66,011	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income (loss)	 	 	 	4,069	 	 	 	 	690	 	 	 	 	7,621	 	 	 	 	(1,633	)	 	 	 	(6,082	)	 	 	 	(3,238	)	 	 	(97	)	 	 	(2,246	)	
Other (income) expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expense	 	 	 	8,469	 	 	 	 	8,527	 	 	 	 	5,747	 	 	 	 	3,728	 	 	 	 	910	 	 	 	 	5,406	 	 	 	1,357	 	 	 	1,264	 	
Income tax expense	 	 	 	102	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	—	 	 	 	—	 	
Other (income) expenses	 	 	 	(996	)	 	 	 	1,209	 	 	 	 	(854	)	 	 	 	(24	)	 	 	 	—	 	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	 	$	(3,506	)	 	 	$	(9,046	)	 	 	$	2,728	 	 	 	$	(5,337	)	 	 	$	(6,992	)	 	 	$	(8,644	)	 	$	(1,454	)	 	$	(3,510	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
General partner’s interest in net income (loss)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(140	)	 	 	 	(173	)	 	 	(29	)	 	 	(70	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Limited partners’ interest in net income (loss)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(6,852	)	 	 	 	(8,471	)	 	 	(1,425	)	 	 	(3,440	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Limited partners’ net income (loss) per unit	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	(1.52	)	 	 	$	(0.81	)	 	$	(0.14	)	 	$	(0.30	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pro forma earnings per common unit(2)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	(0.61	)	
Pro forma weighted average common units outstanding(2)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	5,668	 	
Statement of Cash Flows Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by (used in):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating activities	 	 	$	2,486	 	 	 	$	(447	)	 	 	$	18,155	 	 	 	$	14,589	 	 	 	$	(6,531	)	 	 	$	13,791	 	 	$	2,323	 	 	$	5,067	 	
Investing activities	 	 	 	(7,587	)	 	 	 	745	 	 	 	 	(10,486	)	 	 	 	(853	)	 	 	 	(151,976	)	 	 	 	(10,268	)	 	 	(494	)	 	 	(1,291	)	
Financing activities	 	 	 	5,132	 	 	 	 	322	 	 	 	 	(7,929	)	 	 	 	(14,088	)	 	 	 	159,656	 	 	 	 	(4,609	)	 	 	(2,888	)	 	 	(3,686	)	
Other Financial Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDA(3)	 	 	$	14,880	 	 	 	$	11,981	 	 	 	$	21,956	 	 	 	$	11,021	 	 	 	$	3,450	 	 	 	$	18,263	 	 	$	5,197	 	 	$	6,914	 	
Gross margin(4)	 	 	 	35,688	 	 	 	 	38,818	 	 	 	 	43,143	 	 	 	 	29,905	 	 	 	 	6,240	 	 	 	 	38,119	 	 	 	9,748	 	 	 	12,312	 	
Segment gross margin:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gathering and Processing	 	 	 	19,215	 	 	 	 	22,108	 	 	 	 	27,354	 	 	 	 	20,024	 	 	 	 	3,698	 	 	 	 	24,595	 	 	 	6,098	 	 	 	8,167	 	
Transmission	 	 	 	16,476	 	 	 	 	16,710	 	 	 	 	15,789	 	 	 	 	9,881	 	 	 	 	2,542	 	 	 	 	13,524	 	 	 	3,650	 	 	 	4,145	 	
Balance Sheet Data (At Period End):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	 	$	61	 	 	 	$	681	 	 	 	$	421	 	 	 	$	149	 	 	 	$	1,149	 	 	 	$	63	 	 	$	90	 	 	$	153	 	
Accounts receivable, net and unbilled revenue	 	 	 	16,357	 	 	 	 	13,643	 	 	 	 	9,532	 	 	 	 	8,756	 	 	 	 	19,776	 	 	 	 	22,850	 	 	 	17,446	 	 	 	22,248	 	
Property, plant and equipment, net	 	 	 	233,143	 	 	 	 	219,898	 	 	 	 	216,903	 	 	 	 	205,126	 	 	 	 	149,226	 	 	 	 	146,808	 	 	 	151,167	 	 	 	143,394	 	
Total assets	 	 	 	298,161	 	 	 	 	287,290	 	 	 	 	277,242	 	 	 	 	250,162	 	 	 	 	174,470	 	 	 	 	173,229	 	 	 	173,217	 	 	 	169,693	 	
Total debt (current and long-term)(5)	 	 	 	65,000	 	 	 	 	60,000	 	 	 	 	60,000	 	 	 	 	—	 	 	 	 	61,000	 	 	 	 	56,370	 	 	 	58,380	 	 	 	56,500	 	
Operating Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gathering and Processing segment :	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Throughput (MMcf/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	179.2	 	 	 	 	211.8	 	 	 	 	169.7	 	 	 	 	175.6	 	 	 	164.3	 	 	 	242.8	 	
Plant inlet volume (MMcf/d)(6)	 	 	 	 	 	 	 	 	 	 	 	 	 	12.5	 	 	 	 	11.7	 	 	 	 	11.4	 	 	 	 	9.9	 	 	 	11.1	 	 	 	15.2	 	
Gross NGL production (Mgal/d)(6)	 	 	 	 	 	 	 	 	 	 	 	 	 	40.2	 	 	 	 	39.3	 	 	 	 	38.2	 	 	 	 	34.1	 	 	 	35.2	 	 	 	56.6	 	
Transmission segment :	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Throughput (MMcf/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	336.2	 	 	 	 	357.6	 	 	 	 	381.3	 	 	 	 	350.2	 	 	 	360.6	 	 	 	446.0	 	
Firm transportation — capacity reservation (MMcf/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	627.3	 	 	 	 	613.2	 	 	 	 	701.0	 	 	 	 	677.6	 	 	 	702.8	 	 	 	762.1	 	
Interruptible transportation — throughput (MMcf/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	141.6	 	 	 	 	121.0	 	 	 	 	118.0	 	 	 	 	80.9	 	 	 	80.2	 	 	 	76.5	 	

 

			
(1)		Includes LTIP expenses for the period from August 20, 2009 to December 31, 2009, the year ended December 31, 2010, the quarter ended March 31, 2010 and the quarter ended March 31, 2011 of $0.2 million, $1.7 million, $0.3 million and $0.5 million, respectively. Of these amounts, $0.2 million, $1.2 million, $0.3 million and $0.3 million, respectively, represent non-cash expenses.	

 
			
(2)		The pro forma earnings per common unit gives effect to the recapitalization transactions as of March 31, 2011 and the additional number of common units issued in this offering (at an assumed offering price of $20.00) necessary to pay the portion of the distribution to AIM Midstream Holdings, LTIP participants holding common units and our general partner described in “Use of Proceeds” that will be funded from the proceeds of this offering that exceeds net income for the three months ended March 31, 2011.	

 
			
(3)		For a definition of adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Selected Historical Financial	

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		and Operating Data — Non-GAAP Financial Measures,” and for a discussion of how we use adjusted EBITDA to evaluate our operating performance, please read “— How We Evaluate Our Operations.”	

			
(4)		For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 12 to our unaudited consolidated financial statements and Note 18 to our audited consolidated financial statements included elsewhere in this prospectus and for a discussion of how we use gross margin to evaluate our operating performance, please read “— How We Evaluate Our Operations.”	

 
			
(5)		Excludes Predecessor Note payable to Enbridge Midcoast Limited Holdings, L.L.C. of $39.3 million as of December 31, 2008.	

 
			
(6)		Excludes volumes and gross production under our elective processing arrangements. For a description of our elective processing arrangements, please read “Business — Gathering and Processing Segment — Gloria System.”	

Non-GAAP Financial Measures
 
We include in this prospectus the non-GAAP financial measures of adjusted EBITDA and gross margin. We provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures as calculated and presented in accordance with GAAP.
 
Adjusted EBITDA
 
We define adjusted EBITDA as net income:

 	• 	Plus:	

 	• 	Interest expense;	
 		
 	• 	Income tax expense;	
 		
 	• 	Depreciation expense;	
 		
 	• 	Certain non-cash charges such as non-cash equity compensation;	
 		
 	• 	Unrealized losses on commodity derivative contracts; and	
 		
 	• 	Selected charges that are unusual or non-recurring.	

 	• 	Less:	

 	• 	Interest income;	
 		
 	• 	Income tax benefit;	
 		
 	• 	Unrealized gains on commodity derivative contracts; and	
 		
 	• 	Selected gains that are unusual or non-recurring.	
 
Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and lenders, to assess:

 	• 	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;	
 		
 	• 	the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;	
 		
 	• 	our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and	
 		
 	• 	the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.	
 
The economic rationale behind management’s use of adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our investors.
 
The GAAP measure most directly comparable to adjusted EBITDA is net income. Our non-GAAP financial measure of adjusted EBITDA should not be considered as an alternative to net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical

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tool. You should not consider adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of adjusted EBITDA may not be comparable to similarly titled measures of other companies.
 
Management compensates for the limitations of adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.
 
The following table presents a reconciliation of adjusted EBITDA to net income (loss) attributable to our unitholders for each of the periods indicated:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	American Midstream	 	
 	 	 	 	 	 	 	Partners, LP	 	
 	 	 	 	 	 	 	and Subsidiaries	 	
 	 	 	American Midstream Partners Predecessor	 	 	 	(Successor)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Period from	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	August 20,	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	2009	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Year	 	 	 	Year	 	 	 	Year	 	 	 	10 Months	 	 	 	(Inception	 	 	 	Year	 	 	Quarter	 	 	Quarter	 	
 	 	 	Ended	 	 	 	Ended	 	 	 	Ended	 	 	 	Ended	 	 	 	Date) to	 	 	 	Ended	 	 	Ended	 	 	Ended	 	
 	 	 	December 31,	 	 	 	December 31,	 	 	 	December 31,	 	 	 	October 31,	 	 	 	December 31,	 	 	 	December 31,	 	 	March 31,	 	 	March 31,	 	
 	 	 	2006	 	 	 	2007	 	 	 	2008	 	 	 	2009	 	 	 	2009	 	 	 	2010	 	 	2010	 	 	2011	 	
 	 	 	(unaudited)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(unaudited)	 	
 	 	 	(in thousands)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reconciliation of Adjusted EBITDA to Net Income (Loss)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	 	$	(3,506	)	 	 	$	(9,046	)	 	 	$	2,728	 	 	 	$	(5,337	)	 	 	$	(6,992	)	 	 	$	(8,644	)	 	$	(1,454	)	 	$	(3,510	)	
Add:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation expense	 	 	 	9,917	 	 	 	 	12,500	 	 	 	 	13,481	 	 	 	 	12,630	 	 	 	 	2,978	 	 	 	 	20,013	 	 	 	4,966	 	 	 	5,037	 	
Interest expense	 	 	 	8,469	 	 	 	 	8,527	 	 	 	 	5,747	 	 	 	 	3,728	 	 	 	 	910	 	 	 	 	5,406	 	 	 	1,357	 	 	 	1,264	 	
Unrealized (gain) loss on commodity derivatives	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	—	 	 	 	3,500	 	
Non-cash equity compensation expense	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	150	 	 	 	 	1,185	 	 	 	254	 	 	 	335	 	
One-time transaction costs	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	6,404	 	 	 	 	303	 	 	 	74	 	 	 	288	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDA	 	 	$	14,880	 	 	 	$	11,981	 	 	 	$	21,956	 	 	 	$	11,021	 	 	 	$	3,450	 	 	 	$	18,263	 	 	$	5,197	 	 	$	6,914	 	

 
Gross Margin
 
We define gross margin as the sum of segment gross margin in our Gathering and Processing segment and segment gross margin in our Transmission segment. We define segment gross margin in our Gathering and Processing segment as revenue generated from gathering and processing operations less the cost of natural gas, NGLs and condensate purchased. We define segment gross margin in our Transmission segment as revenue generated from firm and interruptible transportation agreements and fixed-margin arrangements, plus other related fees, less the cost of natural gas purchased in connection with fixed-margin arrangements. Gross margin is included as a supplemental disclosure because it is a primary performance measure used by our management as it represents the results of service fee revenue and cost of sales, which are key components of our operations. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. Effective January 1, 2011, we changed our gross margin and segment gross margin measure to exclude unrealized non-cash mark-to-market adjustments related to our commodity derivatives. For the quarter ended March 31, 2011, $3.5 million in unrealized losses were excluded from the Gathering and Processing segment gross margin. For a reconciliation of gross margin to net income, its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 18 to our audited consolidated financial statements and Note 12 to our unaudited consolidated financial statements included elsewhere in this prospectus.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
 
You should read the following discussion of the financial condition and results of operations of American Midstream Partners, LP and its subsidiaries in conjunction with the historical consolidated financial statements and related notes of American Midstream Partners, LP and the historical combined financial statements and related notes of our Predecessor included elsewhere in this prospectus. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information.
 
Overview
 
We are a growth-oriented Delaware limited partnership that was formed by AIM in August 2009 to own, operate, develop and acquire a diversified portfolio of natural gas midstream energy assets. We are engaged in the business of gathering, treating, processing and transporting natural gas through our ownership and operation of nine gathering systems, three processing facilities, two interstate pipelines and six intrastate pipelines. Our primary assets, which are strategically located in Alabama, Louisiana, Mississippi, Tennessee and Texas, provide critical infrastructure that links producers and suppliers of natural gas to diverse natural gas markets, including various interstate and intrastate pipelines, as well as utility, industrial and other commercial customers. We currently operate approximately 1,400 miles of pipelines that gather and transport over 500 MMcf/d of natural gas. We acquired our existing portfolio of assets from a subsidiary of Enbridge Energy Partners, L.P., or Enbridge, in November 2009.

Our operations are organized into two segments: (i) Gathering and Processing and (ii) Transmission. In our Gathering and Processing segment, we receive fee-based and fixed-margin compensation for gathering, transporting and treating natural gas. Where we provide processing services at the plants that we own, or obtain processing services for our own account in connection with our elective processing arrangements, we typically retain and sell a percentage of the residue natural gas and resulting natural gas liquids, or NGLs, under percent-of-proceeds, or POP, arrangements. We own three processing facilities that produced an average of approximately 34.1 Mgal/d and 55.1 Mgal/d of gross NGLs for the year ended December 31, 2010 and the quarter ended March 31, 2011, respectively. In addition, in connection with our elective processing arrangements, we contract for processing capacity at a third-party plant where we have the option to process natural gas that we purchase. Under these arrangements, we sold an average of approximately 28.1 Mgal/d and 35.0 Mgal/d of net equity NGL volumes for the year ended December 31, 2010 and the quarter ended March 31, 2011, respectively. We also receive fee-based and fixed-margin compensation in our Transmission segment primarily related to capacity reservation charges under our firm transportation contracts and the transportation of natural gas pursuant to our interruptible transportation and fixed-margin contracts.

Our Operations
 
We manage our business and analyze and report our results of operations through two business segments:

 	• 	Gathering and Processing.   Our Gathering and Processing segment provides “wellhead to market” services for natural gas to producers of natural gas and oil, which include transporting raw natural gas from various receipt points through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs and selling or delivering pipeline quality natural gas as well as NGLs to various markets and pipeline systems.	
 		
 	• 	Transmission.   Our Transmission segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, which include local distribution companies, or LDCs, utilities and industrial, commercial and power generation customers.	
 
Gathering and Processing Segment
 
Results of operations from our Gathering and Processing segment are determined primarily by the volumes of natural gas we gather and process, the commercial terms in our current contract portfolio and

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natural gas, NGL and condensate prices. We gather and process natural gas primarily pursuant to the following arrangements:

 	• 	Fee-Based Arrangements.   Under these arrangements, we generally are paid a fixed cash fee for gathering and transporting natural gas.	
 		
 	• 	Fixed-Margin Arrangements.   Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. By entering into back-to-back purchases and sales of natural gas, we are able to lock in a fixed-margin on these transactions. We view the segment gross margin earned under our fixed-margin arrangements to be economically equivalent to the fee earned in our fee-based arrangements.	

			
 	• 	Percent-of-Proceeds Arrangements.   Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas and NGLs at market prices. Where we provide processing services at the processing plants that we own or obtain processing services for our own account in connection with our elective processing arrangements, such as our Toca contracts, we generally retain and sell a percentage of the residue natural gas and resulting NGLs. Please read “Business — Gathering and Processing Segment — Gloria System.”	

Gross margin earned under fee-based and fixed-margin arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. However, a sustained decline in commodity prices could result in a decline in volumes and, thus, a decrease in our fee-based and fixed-margin gross margin. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. Under our typical percent-of-proceeds arrangement, our gross margin is directly impacted by the commodity prices we realize on our share of natural gas and NGLs received as compensation for processing raw natural gas. However, our percent-of-proceeds arrangements also often contain a fee-based component, which helps to mitigate the degree of commodity-price volatility we could experience under these arrangements. We further seek to mitigate our exposure to commodity price risk through our hedging program. Please read “ — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”
 
Transmission Segment
 
Results of operations from our Transmission segment are determined primarily by capacity reservation fees from firm transportation contracts and, to a lesser extent, the volumes of natural gas transported on the interstate and intrastate pipelines we own pursuant to interruptible transportation or fixed-margin contracts. Our transportation arrangements are further described below:

 	• 	Firm Transportation Arrangements.   Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not it utilizes the capacity. In most cases, the shipper also pays a variable use charge with respect to quantities actually transported by us.	
 		
 	• 	Interruptible Transportation Arrangements.   Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable use charge for quantities actually shipped.	
 		
 	• 	Fixed-Margin Arrangements.   Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. We view fixed-margin arrangements to be economically equivalent to our interruptible transportation arrangements.	

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The gross margin we earn from our transportation activities is directly related to the capacity reservation on, and actual volume of natural gas that flows through, our systems, neither of which is directly dependent on commodity prices. However, a sustained decline in market demand could result in a decline in volumes and, thus, a decrease in our commodity-based gross margin under firm transportation contracts or gross margin under our interruptible transportation and fixed-margin contracts.
 
Contract Mix
 
Set forth below is a table summarizing our average contract mix for the year ended December 31, 2010 and the quarter ended March 31, 2011:

 	 	Year Ended	 	 	Quarter Ended	 	
 	 	December 31, 2010	 	 	March 31, 2011	 	
 	 	Segment	 	 	Percent of	 	 	Segment	 	 	Percent of	 	
 	 	Gross	 	 	Segment	 	 	Gross	 	 	Segment	 	
 	 	Margin	 	 	Gross Margin	 	 	Margin	 	 	Gross Margin	 	
 	 	(in millions)	 	 	 	 	 	(in millions)	 	 	 	 	
 		
Gathering and Processing	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fee-based	 	$	6.5	 	 	 	26.4	%	 	$	2.0	 	 	 	24.6	%	
Fixed-margin	 	 	4.9	 	 	 	19.9	 	 	 	1.2	 	 	 	14.4	 	
Percent-of-proceeds	 	 	13.2	 	 	 	53.7	 	 	 	5.0	 	 	 	61.0	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	24.6	 	 	 	100	%	 	$	8.2	 	 	 	100	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Transmission	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Firm transportation	 	$	10.8	 	 	 	80.0	%	 	$	3.4	 	 	 	83.0	%	
Interruptible transportation	 	 	2.0	 	 	 	14.8	 	 	 	0.5	 	 	 	12.6	 	
Fixed-margin	 	 	0.7	 	 	 	5.2	 	 	 	0.2	 	 	 	4.4	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	13.5	 	 	 	100	%	 	$	4.1	 	 	 	100	%	

 
How We Evaluate Our Operations
 
Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include throughput volumes, gross margin and direct operating expenses on a segment basis, and adjusted EBITDA and distributable cash flow on a company-wide basis.
 
Throughput Volumes
 
In our Gathering and Processing segment, we must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our systems. Our ability to maintain or increase existing volumes of natural gas and obtain new supplies is impacted by (i) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to or near our gathering systems, (ii) our ability to compete for volumes from successful new wells in the areas in which we operate, (iii) our ability to obtain natural gas that has been released from other commitments and (iv) the volume of natural gas that we purchase from connected systems. We actively monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.
 
In our Transmission segment, the majority of our segment gross margin is generated by firm capacity reservation fees, as opposed to the actual throughput volumes, on our interstate and intrastate pipelines. Substantially all of this segment gross margin is generated under contracts with shippers, including producers, industrial companies, LDCs and marketers, for firm and interruptible natural gas transportation on our pipelines. We routinely monitor natural gas market activities in the areas served by our transmission systems to pursue new shipper opportunities.

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Gross Margin and Segment Gross Margin
 
Gross margin and segment gross margin are the primary metrics that we use to evaluate our performance. See “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures.” We define segment gross margin in our Gathering and Processing segment as revenue generated from gathering and processing operations less the cost of natural gas, NGLs and condensate purchased. Revenue includes revenue generated from fixed fees associated with the gathering and treating of natural gas and from the sale of natural gas, NGLs and condensate resulting from gathering and processing activities under fixed-margin and percent-of-proceeds arrangements. The cost of natural gas, NGLs and condensate includes volumes of natural gas, NGLs and condensate remitted back to producers pursuant to percent-of-proceeds arrangements and the cost of natural gas purchased for our own account, including pursuant to fixed-margin arrangements.
 
We define segment gross margin in our Transmission segment as revenue generated from firm and interruptible transportation agreements and fixed-margin arrangements, plus other related fees, less the cost of natural gas purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.
 
Effective January 1, 2011, we changed our gross margin and segment gross margin measure to exclude unrealized non-cash mark-to-market adjustments related to our commodity derivatives. For the quarter ended March 31, 2011, $3.5 million in unrealized losses were excluded from the Gathering and Processing segment gross margin.
 
Direct Operating Expenses
 
Our management seeks to maximize the profitability of our operations in part by minimizing direct operating expenses. Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities, lost and unaccounted for gas and contract services comprise the most significant portion of our operating expenses. These expenses are relatively stable and largely independent of throughput volumes through our systems, but may fluctuate depending on the activities performed during a specific period.
 
Adjusted EBITDA and Distributable Cash Flow
 
We define adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation expense, certain non-cash charges such as non-cash equity compensation, unrealized losses on commodity derivative contracts and selected charges that are unusual or non-recurring, less interest income, income tax benefit, unrealized gains on commodity derivative contracts and selected gains that are unusual or non-recurring. See “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures.” Although we have not quantified distributable cash flow on a historical basis, after the closing of this offering we intend to use distributable cash flow, which we define as adjusted EBITDA plus interest income, less cash paid for interest expense and maintenance capital expenditures, to analyze our performance. Distributable cash flow will not reflect changes in working capital balances. Adjusted EBITDA and distributable cash flow are used as supplemental measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

 	• 	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;	
 		
 	• 	the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;	
 		
 	• 	our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and	
 		
 	• 	the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.	

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Note About Non-GAAP Financial Measures
 
Gross margin, adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial condition and results of operations. Net income is the GAAP measure most directly comparable to each of gross margin and adjusted EBITDA. The GAAP measure most directly comparable to distributable cash flow is net cash provided by operating activities. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. You should not consider any of gross margin, adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin, adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
 
Items Affecting the Comparability of Our Financial Results
 
Our historical results of operations for the periods presented and those of our Predecessor may not be comparable, either to each other or to our future results of operations, for the reasons described below:

 	• 	Since we acquired our assets from Enbridge effective November 1, 2009, the financial and operational data for 2009 that is discussed below is generally bifurcated between the period that our Predecessor owned those assets and the period from our acquisition through the end of the year. Moreover, there is some overlap between these two periods resulting from the fact that we were formed on August 20, 2009, which was prior to the acquisition on November 1, 2009. As a result, the 2009 period that our Predecessor owned and operated the assets is the ten months ended October 31, 2009, while the successor 2009 period begins with our inception on August 20, 2009 and ends on December 31, 2009. Although we incurred costs associated with our formation and the acquisition of our assets from Enbridge of $6.4 million, we had no material operations until November 1, 2009.	
 		
 	• 	The historical combined financial statements and related notes of our Predecessor:	

 	• 	are presented on a combined rather than a consolidated basis. The principal difference between consolidated and combined financial statements is that consolidated financial statements do not reflect transactions and investments between consolidated subsidiaries or between those subsidiaries and the parent entity, showing instead a view of the parent entity and its consolidated subsidiaries as a whole; and	
 		
 	• 	reflect the operation of our assets with different business strategies and as part of a larger business rather than the stand-alone fashion in which we operate them. Please read “Business — Business Strategies.”	

			
 	• 	SG&A expenses of our Predecessor during periods in which we did not own or operate our assets were allocated expenses from a much larger parent entity and may not represent SG&A expenses required to actually operate our assets as we intend. In addition, we adopted an LTIP in connection with our formation in 2009, and our SG&A expenses for the year ended December 31, 2010 and for the quarter ended March 31, 2011 included $1.7 million and $0.5 million, respectively, of cash and non-cash expenses associated with grants pursuant to our LTIP.	

 
			
 	• 	Initially, we anticipate incurring approximately $2.3 million of annual incremental general and administrative expenses attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly SEC reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs; and director compensation.	

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 	• 	In connection with our formation and the acquisition of our assets from Enbridge, we incurred transaction expenses of approximately $6.4 million. These transaction expenses are included in our historical consolidated financial statements for the period from August 20, 2009 to December 31, 2009.	
 		
 	• 	In connection with the acquisition of our assets from Enbridge, effective November 1, 2009:	

 	• 	we put in place stand-alone insurance policies customary for midstream partnerships, which had the effect of increasing our direct operating expenses;	
 		
 	• 	we initiated a comprehensive review of the integrity management program that we inherited when we acquired our assets. Following this review, we concluded that there were sixteen high consequence areas that required further testing pursuant to DOT regulations;	
 		
 	• 	one of our subsidiaries entered into an advisory services agreement with certain affiliates of AIM Midstream Holdings, which resulted in higher SG&A expenses during the periods after that acquisition. Please read “Certain Relationships and Related Party Transactions — Agreements with Affiliates.” At the closing of this offering, we will pay $2.5 million to those affiliates to terminate this agreement; and	
 		
 	• 	we recorded our assets at fair value, which was less than our Predecessor’s book value of those assets, and their useful lives were also decreased, which had the net effect of increasing the depreciation expense associated with our assets after the acquisition date.	

 	• 	Interest expense of our Predecessor was an allocated expense from our Predecessor’s publicly traded parent entity. In addition, we incurred indebtedness to finance our acquisition of our assets from Enbridge, which increased our interest expense after the acquisition date.	
 		
 	• 	After our acquisition of our assets from Enbridge, we initiated a hedging program comprised of NGL puts and swaps, as well as interest rate caps, that we account for using mark-to-market accounting. These amounts are included in our historical consolidated financial statements and related notes as unrealized/realized gain (loss) from risk management activities.	
 		
 	• 	In December 2010, we completed an interconnect between our Lafitte pipeline and a pipeline on the TGP interstate system. This interconnect enables us to purchase natural gas from producers on the TGP system and deliver it to the Alliance Refinery and the Toca processing plant, which will enable us to process substantially more natural gas under our elective processing arrangements.	
 
General Trends and Outlook
 
We expect our business to continue to be affected by the key trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.
 
Outlook
 
Beginning in the second half of 2008, the United States and other industrialized countries experienced a significant economic downturn that led to a decline in worldwide energy demand. During this same period, North American oil and natural gas supply was increasing as a result of the rise in domestic unconventional production. The combination of lower energy demand due to the economic downturn and higher North American oil and natural gas supply resulted in significant declines in oil, NGL and natural gas prices. While oil and NGL prices began to increase steadily in the second quarter of 2009, natural gas prices remained depressed and volatile throughout 2009 and 2010 in comparison to much of 2007 and 2008 due to a continued increase in natural gas supply despite weaker offsetting demand growth. The outlook for a worldwide economic recovery in 2011 remains uncertain, and the timing of a recovery in worldwide demand for energy is difficult to predict. As a result, we expect natural gas prices to remain relatively low in the near term.
 
Notwithstanding the ongoing volatility in commodity prices, there has been a recent resurgence in the level of acquisition and divestiture activity in the midstream energy industry and we expect that trend to

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continue. In particular, we believe that opportunities to acquire midstream energy assets from third parties that fulfill our strategic objectives will continue to arise in the foreseeable future.
 
Supply and Demand Outlook for Natural Gas and Oil
 
Natural gas and oil continue to be critical components of energy consumption in the United States. According to the U.S. Energy Information Administration, or EIA, annual consumption of natural gas in the U.S. was approximately 24.1 trillion cubic feet, or Tcf, in 2010, compared to approximately 22.8 Tcf in 2009, representing an increase of approximately 5.7%. Domestic production of natural gas grew from approximately 21.6 Tcf in 2009 to approximately 22.6 Tcf in 2010, or a 4.4% increase. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States, representing approximately 58% of the total natural gas consumed in the United States during 2010. In particular, based on a report by the EIA, industrial natural gas demand is expected to grow from 7.3 Tcf in 2009 to 9.4 Tcf in 2020 as a result of an expected recovery in industrial production.
 
According to the EIA, domestic crude oil production was approximately 5.5 million barrels per day, or MMBbl/d, in 2010, compared to approximately 5.4 MMBbl/d in 2009, representing an increase of approximately 2.8%. Domestic crude oil production is expected to continue to increase over time primarily due to improvements in technology that have enabled U.S. onshore producers to economically extract sources of supply, such as secondary and tertiary oil reserves and unconventional oil reserves, that were previously unavailable or uneconomic.
 
We believe that current oil and natural gas prices and the existing demand for oil and natural gas will continue to result in ongoing oil- and natural gas-related drilling in the United States as producers seek to increase their production levels. In particular, we believe that drilling activity targeting natural gas with modest to high NGL content, such as on our Gloria system, and targeting oil with associated natural gas, such as on our Bazor Ridge system, will remain active. Although we anticipate continued exploration and production activity in the areas in which we operate, fluctuations in energy prices can affect natural gas production levels over time as well as the timing and level of investment activity by third parties in the exploration for and development of new oil and natural gas reserves. We have no control over the level of oil and natural gas exploration and development activity in the areas of our operations.
 
Impact of Interest Rates
 
The credit markets recently have experienced near-record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. If this occurs, interest rates on floating rate credit facilities and future offerings in the debt capital markets could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price will be impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, reduce debt or for other purposes.
 
Results of Operations — Combined Overview
 
The following table and discussion presents certain of our historical consolidated financial data and the historical combined financial data of our Predecessor for the periods indicated.
 
We refer to the results of our Predecessor’s operations for the period from January 1, 2009 to October 31, 2009 as the 2009 Predecessor Period and to our operating results for the period from August 20, 2009 to December 31, 2009 as the 2009 Successor Period.
 
We acquired our assets effective November 1, 2009. During the period from our inception, on August 20, 2009, to October 31, 2009, we had no operations, but we incurred certain fees and expenses totaling $6.4 million associated with our formation and acquisition of our assets from Enbridge.

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The financial data for the 2009 Predecessor Period and the year ended December 31, 2008 represent periods of time prior to our acquisition of our assets. During these periods, our Predecessor owned and operated our operating assets. As such, the results of operations for these periods do not necessarily represent the results of operations that would have been achieved during the period had we owned and operated our assets.
 
The results of operations by segment are discussed in further detail following this combined overview.

 	 	 	 	 	 	 	American Midstream	 	
 	 	 	American Midstream Partners	 	 	 	Partners, LP and Subsidiaries	 	
 	 	 	Predecessor	 	 	 	(Successor)	 	
 	 	 	 	 	 	 	 	 	 	 	Period from	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	August 20,	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Year	 	 	 	10 Months	 	 	 	2009	 	 	 	Year	 	 	Quarter	 	 	Quarter	 	
 	 	 	Ended	 	 	 	Ended	 	 	 	(Inception Date) to	 	 	 	Ended	 	 	Ended	 	 	Ended	 	
 	 	 	December 31,	 	 	 	October 31,	 	 	 	December 31,	 	 	 	December 31,	 	 	March 31,	 	 	March 31,	 	
 	 	 	2008	 	 	 	2009	 	 	 	2009	 	 	 	2010	 	 	2010	 	 	2011	 	
 	 	 	 	 	 	 	 	 	 	 	(in thousands)                           	 	
Statement of Operations Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenue	 	 	$	366,348	 	 	 	$	143,132	 	 	 	$	32,833	 	 	 	$	211,940	 	 	$	54,712	 	 	$	67,265	 	
Unrealized gain (losses) on commodity derivatives	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	—	 	 	 	(3,500	)	
Total revenue	 	 	 	366,348	 	 	 	 	143,132	 	 	 	 	32,833	 	 	 	 	211,940	 	 	 	54,712	 	 	 	63,765	 	
Operating expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Purchases of natural gas, NGLs and condensate	 	 	 	323,205	 	 	 	 	113,227	 	 	 	 	26,593	 	 	 	 	173,821	 	 	 	44,964	 	 	 	54,953	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Direct operating expenses	 	 	 	13,423	 	 	 	 	10,331	 	 	 	 	1,594	 	 	 	 	12,187	 	 	 	2,692	 	 	 	3,058	 	
Selling, general and administrative expenses(1)	 	 	 	8,618	 	 	 	 	8,577	 	 	 	 	1,346	 	 	 	 	8,854	 	 	 	2,113	 	 	 	2,675	 	
One-time transaction costs	 	 	 	—	 	 	 	 	—	 	 	 	 	6,404	 	 	 	 	303	 	 	 	74	 	 	 	288	 	
Depreciation expense	 	 	 	13,481	 	 	 	 	12,630	 	 	 	 	2,978	 	 	 	 	20,013	 	 	 	4,966	 	 	 	5,037	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total operating expenses	 	 	 	358,727	 	 	 	 	144,765	 	 	 	 	38,915	 	 	 	 	215,178	 	 	 	54,809	 	 	 	66,011	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income (loss)	 	 	 	7,621	 	 	 	 	(1,633	)	 	 	 	(6,082	)	 	 	 	(3,238	)	 	 	(97	)	 	 	(2,246	)	
Interest expense	 	 	 	5,747	 	 	 	 	3,728	 	 	 	 	910	 	 	 	 	5,406	 	 	 	1,357	 	 	 	1,264	 	
Other (income) expenses	 	 	 	(854	)	 	 	 	(24	)	 	 	 	—	 	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	 	$	2,728	 	 	 	$	(5,337	)	 	 	$	(6,992	)	 	 	$	(8,644	)	 	$	(1,454	)	 	$	(3,510	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Financial Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDA(2)	 	 	$	21,956	 	 	 	$	11,021	 	 	 	$	3,450	 	 	 	$	18,263	 	 	$	5,197	 	 	$	6,914	 	
Gross margin(3)	 	 	$	43,143	 	 	 	$	29,905	 	 	 	$	6,240	 	 	 	$	38,119	 	 	$	9,748	 	 	$	12,312	 	

 
			
(1)		Includes LTIP expenses for the period from August 20, 2009 to December 31, 2009, the year ended December 31, 2010, the quarter ended March 31, 2010 and the quarter ended March 31, 2011 of $0.2 million, $1.7 million, $0.3 million and $0.5 million, respectively. Of these amounts, $0.2 million, $1.2 million, $0.3 million and $0.3 million, respectively, represent non-cash expenses.	

			
(2)		For a definition of adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures,” and for a discussion of how we use adjusted EBITDA to evaluate our operating performance, please read “— How We Evaluate Our Operations.”	
 		
(3)		For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 12 to our unaudited consolidated financial statements and Note 18 to our audited consolidated financial statements included elsewhere in this prospectus and for a discussion of how we use gross margin to evaluate our operating performance, please read “— How We Evaluate Our Operations.”	
 
Quarter Ended March 31, 2011 Compared to Quarter Ended March 31, 2010
 
Revenue.   Our total revenue in the quarter ended March 31, 2011 was $63.8 million compared to $54.7 million in the quarter ended March 31, 2010. This increase of $9.1 million was primarily due to higher realized NGL prices in our Gathering and Processing segment and a new fixed-margin contract in our

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Transmission segment. This increase was partially offset by lower realized natural gas prices in our Gathering and Processing segment.
 
Purchases of Natural Gas, NGLs and Condensate.   Our purchases of natural gas, NGLs and condensate in the quarter ended March 31, 2011 were $55.0 million compared to $45.0 million in the quarter ended March 31, 2010. This increase of $10.0 million was primarily due to higher realized NGL prices in our Gathering and Processing segment and a new fixed-margin contract in our Transmission segment. This increase was partially offset by lower realized natural gas prices in our Gathering and Processing segment.
 
Gross Margin.   Gross margin in the quarter ended March 31, 2011 was $12.3 million compared to $9.7 million in the quarter ended March 31, 2010. This increase of $2.6 million was primarily due to higher realized NGL prices and increased plant inlet volumes in our Gathering and Processing segment.
 
Direct Operating Expenses.   Direct operating expenses in the quarter ended March 31, 2011 were $3.1 million compared to $2.7 million in the quarter ended March 31, 2010. This increase of $0.4 million was primarily due to increased repairs and maintenance as well as lease and rent expenses. This increase was partially offset by a decrease in personnel costs.
 
Selling, General and Administrative Expenses.   SG&A expenses in the quarter ended March 31, 2011 were $2.7 million compared to $2.1 million in the quarter ended March 31, 2010. This increase of $0.6 million was primarily due to increased information technology expenses, increased employment-related expenses and increased costs associated with our LTIP.
 
Depreciation Expense.   Depreciation expense in the quarter ended March 31, 2011 was $5.0 million compared to $5.0 million in the quarter ended March 31, 2010.
 
Year Ended December 31, 2010 Compared to the 2009 Successor Period and the 2009 Predecessor Period
 
Revenue.   Our total revenue in 2010 was $211.9 million compared to $32.8 million and $143.1 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase was primarily due to higher realized NGL prices in our Gathering and Processing segment and a new fixed-margin contract in our Transmission segment. Under our fixed-margin contracts, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical quantity of natural gas at delivery points on our systems at the same undiscounted index price. This increase was partially offset by lower throughput and processing volumes in our Gathering and Processing segment and lower NGL production.
 
Purchases of Natural Gas, NGLs and Condensate.   Our purchases of natural gas, NGLs and condensate for 2010 were $173.8 million compared to $26.6 million and $113.2 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase was primarily the result of a new fixed-margin contract in our Transmission segment and higher realized NGL prices in our Gathering and Processing segment, and was partially offset by lower throughput and processing volumes in our Gathering and Processing segment.
 
Gross Margin.   Gross margin in 2010 was $38.1 million, compared to $6.2 million and $29.9 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase was primarily due to higher realized NGL prices in our Gathering and Processing segment, which positively impacted the segment gross margin associated with our percent-of-proceeds arrangements, and was partially offset by lower throughput and processing volumes in our Gathering and Processing segment. In addition, segment gross margin in our Transmission segment was higher in 2010 due to increased throughput volumes on our regulated pipelines as a result of colder weather. The increases in revenue and purchases of natural gas, NGLs and condensate that were driven by higher realized commodity prices and the new fixed-margin contract in our Transmission segment had minimal impact on gross margin.
 
Direct Operating Expenses.   Direct operating expenses in 2010 were $12.2 million, compared to $1.6 million and $10.3 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase was primarily due to higher fixed costs, such as insurance and higher maintenance expenses that

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we incurred following our acquisition of our assets in our Transmission segment, partially offset by lower outside services costs in our Gathering and Processing segment.
 
Selling, General and Administrative Expenses.   SG&A expenses in 2010 were $8.9 million, compared to $1.3 million and $8.6 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. SG&A expenses include LTIP expenses of $1.7 million and $0.2 million in 2010 and the 2009 Successor Period, respectively. Because we adopted the LTIP in November 2009, there were no LTIP expenses in the 2009 Predecessor Period. The decrease in SG&A expenses was a result of our incurrence of actual SG&A expenses compared to the historical allocation of SG&A expenses by the owner of our Predecessor, but was offset in part by increases in LTIP expenses due to an increase in the number of phantom units granted in 2010.
 
One-Time Transaction Expenses.   We incurred approximately $6.4 million of one-time expenses, including legal, consulting and accounting fees in the 2009 Successor Period in connection with our acquisition of our assets. An additional $0.3 million was recorded in 2010 primarily related to Predecessor audit fees and remaining asset valuation costs.
 
Depreciation Expense.   Depreciation expense was $20.0 million in 2010 compared to $3.0 million and $12.6 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. We recorded our assets at fair value, which was less than our Predecessor’s book value of those assets, and their useful lives were also decreased, which had the net effect of increasing the depreciation expense associated with our assets after the acquisition date. The increase in depreciation expense from 2009 to 2010 is attributable to those adjustments.
 
The 2009 Successor Period and the 2009 Predecessor Period Compared to Year Ended December 31, 2008
 
Revenue.   Our total revenue was $32.8 million and $143.1 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $366.3 million for 2008. This decrease was primarily due to lower realized natural gas, NGL and condensate prices as well as lower plant inlet volumes and NGL production in our Gathering and Processing segment, although this decrease was partially offset by an increase in volumes gathered pursuant to fee-based and fixed-margin arrangements.
 
Purchases of Natural Gas, NGLs and Condensate.   Our total purchases of natural gas, NGLs and condensate were $26.6 million and $113.2 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $323.2 million for 2008. This decrease was primarily due to lower throughput and processing volumes on our Bazor Ridge and Alabama Processing systems, as well as lower realized natural gas, NGL and condensate prices in our Gathering and Processing segment.
 
Gross Margin.   Gross margin was $6.2 million and $29.9 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $43.1 million for 2008. This decrease was primarily due to lower realized natural gas and NGL prices, which negatively impacted the segment gross margin associated with our percent-of-proceeds arrangements in the Gathering and Processing segment, but was partially offset by higher throughput volumes on the Quivira system. In addition, segment gross margin was lower in the Transmission segment primarily as a result of the full-year impact of the change in the terms of a contract on our Midla system to more accurately reflect market rates between our Predecessor and an affiliate of our Predecessor.
 
Direct Operating Expenses.   Direct operating expenses were $1.6 million and $10.3 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $13.4 million for 2008. This decrease was mainly due to the timing of our Predecessor’s 2008 expenditures in connection with a multi-year integrity management program.
 
Selling, General and Administrative Expenses.   SG&A expenses were $1.3 million and $8.6 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $8.6 million for 2008. This increase in SG&A expenses was primarily due to additional costs allocated to our Predecessor during the 2009 Predecessor Period. Moreover, SG&A expenses include $0.2 million of LTIP expenses for the 2009 Successor Period. We adopted the LTIP in November 2009 and, as a result, there were no LTIP expenses for the 2009 Predecessor Period or any period prior to our formation.

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One-Time Transaction Expenses.   We incurred approximately $6.4 million of one-time expenses, including legal, consulting and accounting fees in the 2009 Successor Period, in connection with our formation and acquisition of our assets.
 
Depreciation Expense.   Depreciation expense was $3.0 million and $12.6 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $13.5 million for 2008. We recorded our assets at fair value, which was less than our Predecessor’s book value of those assets, and their useful lives were also decreased, which had the net effect of increasing the depreciation expense associated with our assets after the acquisition date. This increase in depreciation expense was primarily due to those adjustments.
 
Segment Results
 
The table below contains key segment performance indicators related to our discussion of the results of operations of our segments.

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	American Midstream	 	
 	 	 	American Midstream Partners	 	 	 	Partners, LP and Subsidiaries	 	
 	 	 	Predecessor	 	 	 	(Successor)	 	
 	 	 	 	 	 	 	 	 	 	 	Period from	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	August 20,	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Year	 	 	 	10 Months	 	 	 	2009	 	 	 	Year	 	 	Quarter	 	 	Quarter	 	
 	 	 	Ended	 	 	 	Ended	 	 	 	(Inception Date) to	 	 	 	Ended	 	 	Ended	 	 	Ended	 	
 	 	 	December 31,	 	 	 	October 31,	 	 	 	December 31,	 	 	 	December 31,	 	 	March 31,	 	 	March 31,	 	
 	 	 	2008	 	 	 	2009	 	 	 	2009	 	 	 	2010	 	 	2010	 	 	2011	 	
 	 	 	(in thousands, except operating data)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Segment Financial and Operating Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gathering and Processing segment	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Financial data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenue	 	 	$	349,861	 	 	 	$	132,957	 	 	 	$	27,857	 	 	 	$	158,455	 	 	$	46,624	 	 	$	48,084	 	
Unrealized gain (loss) on commodity derivatives	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	 	—	 	 	 	—	 	 	 	(3,500	)	
Total revenue	 	 	 	349,861	 	 	 	 	132,957	 	 	 	 	27,857	 	 	 	 	158,455	 	 	 	46,614	 	 	 	44,584	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Purchases of natural gas, NGLs and condensate	 	 	 	322,507	 	 	 	 	112,933	 	 	 	 	24,159	 	 	 	 	133,860	 	 	 	40,526	 	 	 	39,917	 	
Direct operating expenses	 	 	$	8,186	 	 	 	$	7,134	 	 	 	$	956	 	 	 	$	7,721	 	 	$	1,670	 	 	$	1,949	 	
Other financial data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Segment gross margin	 	 	$	27,354	 	 	 	$	20,024	 	 	 	$	3,698	 	 	 	$	24,595	 	 	$	6,098	 	 	$	8,167	 	
Operating data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average throughput (MMcf/d)	 	 	 	179.2	 	 	 	 	211.8	 	 	 	 	169.7	 	 	 	 	175.6	 	 	 	164.3	 	 	 	242.8	 	
Average plant inlet volume (MMcf/d)(1)	 	 	 	12.5	 	 	 	 	11.7	 	 	 	 	11.4	 	 	 	 	9.9	 	 	 	11.1	 	 	 	15.2	 	
Average gross NGL production (Mgal/d)(1)	 	 	 	40.2	 	 	 	 	39.3	 	 	 	 	38.2	 	 	 	 	34.1	 	 	 	35.2	 	 	 	55.1	 	
Average realized prices:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas ($/MMcf)	 	 	$	9.08	 	 	 	$	3.76	 	 	 	$	4.71	 	 	 	$	4.61	 	 	$	5.04	 	 	$	3.99	 	
NGLs ($/gal)	 	 	$	1.36	 	 	 	$	0.70	 	 	 	$	1.05	 	 	 	$	1.08	 	 	$	1.13	 	 	$	1.18	 	
Condensate ($/gal)	 	 	$	2.63	 	 	 	$	1.16	 	 	 	$	1.68	 	 	 	$	1.82	 	 	$	1.78	 	 	$	2.07	 	
Transmission segment	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Financial data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenue	 	 	$	16,487	 	 	 	$	10,175	 	 	 	$	4,976	 	 	 	$	53,485	 	 	$	8,088	 	 	$	19,181	 	
Purchases of natural gas, NGLs and condensate	 	 	 	698	 	 	 	 	294	 	 	 	 	2,434	 	 	 	 	39,961	 	 	 	4,438	 	 	 	15,036	 	
Direct operating expenses	 	 	$	5,237	 	 	 	$	3,197	 	 	 	$	638	 	 	 	$	4,466	 	 	$	1,022	 	 	$	1,109	 	
Other financial data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Segment gross margin	 	 	$	15,789	 	 	 	$	9,881	 	 	 	$	2,542	 	 	 	$	13,524	 	 	$	3,650	 	 	$	4,145	 	

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 	 	 	 	 	 	 	American Midstream	 	
 	 	 	American Midstream Partners	 	 	 	Partners, LP and Subsidiaries	 	
 	 	 	Predecessor	 	 	 	(Successor)	 	
 	 	 	 	 	 	 	 	 	 	 	Period from	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	August 20,	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Year	 	 	 	10 Months	 	 	 	2009	 	 	 	Year	 	 	Quarter	 	 	Quarter	 	
 	 	 	Ended	 	 	 	Ended	 	 	 	(Inception Date) to	 	 	 	Ended	 	 	Ended	 	 	Ended	 	
 	 	 	December 31,	 	 	 	October 31,	 	 	 	December 31,	 	 	 	December 31,	 	 	March 31,	 	 	March 31,	 	
 	 	 	2008	 	 	 	2009	 	 	 	2009	 	 	 	2010	 	 	2010	 	 	2011	 	
 	 	 	(in thousands, except operating data)	 	
Operating data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average throughput (MMcf/d)	 	 	 	336.2	 	 	 	 	357.6	 	 	 	 	381.3	 	 	 	 	350.2	 	 	 	360.6	 	 	 	446.0	 	
Average firm transportation —
capacity reservation (MMcf/d)	 	 	 	627.3	 	 	 	 	613.2	 	 	 	 	701.0	 	 	 	 	677.6	 	 	 	702.8	 	 	 	762.1	 	
Average interruptible transportation —
throughput (MMcf/d)	 	 	 	141.6	 	 	 	 	121.0	 	 	 	 	118.0	 	 	 	 	80.9	 	 	 	80.2	 	 	 	76.5	 	

 
			
(1)		Excludes volumes and gross production under our elective processing arrangements.	
 
Quarter Ended March 31, 2011 Compared to Quarter Ended March 31, 2010
 
Gathering and Processing Segment
 
Revenue.   Segment revenue in the quarter ended March 31, 2011 was $48.1 million compared to $46.6 million in the quarter ended March 31, 2010. This increase was primarily due to increased throughput on our Gloria and Quivira systems, increased plant inlet volumes primarily at our Bazor Ridge processing plant, higher NGL sales and condensate volumes on our Bazor Ridge and Gloria Systems, and higher realized NGL prices. This increase was almost entirely offset by lower realized natural gas prices. Set forth below is a comparison of the volumetric and pricing data for the quarters ended March 31, 2011 and 2010 as well as a summary of the effect of the hedge transactions that we entered into in January 2011.

 	• 	Total natural gas throughput volumes on our Gathering and Processing segment were 242.8 MMcf/d in the quarter ended March 31, 2011 compared to 164.3 MMcf/d in the quarter ended March 31, 2010. Natural gas inlet volumes at our owned processing plants were 15.2 MMcf/d in the quarter ended March 31, 2011 compared to 11.1 MMcf/d in the quarter ended March 31, 2010. Gross NGL production volumes from our owned processing plants were 55.1 Mgal/d in the quarter ended March 31, 2011 compared to 35.2 Mgal/d in the quarter ended March 31, 2010.	
 		
 	• 	The average realized price of natural gas in the quarter ended March 31, 2011 was $3.99/Mcf, compared to $5.04/Mcf in the quarter ended March 31, 2010. The average realized price of NGLs in the quarter ended March 31, 2011 was $1.26/gal, compared to $1.13/gal in the quarter ended March 31, 2010. The average realized price of condensate in the quarter ended March 31, 2011 was $2.26/Mcf, compared to $1.78/gal in the quarter ended March 31, 2010.	
 		
 	• 	We entered into a series of hedge transactions in January 2011. These hedges had a net effect of ($3.5) million on our revenue related to unrealized losses for the quarter ended March 31, 2011. We had no hedges during the quarter ended March 31, 2010. For a discussion of our hedge positions, please read “— Quantitative and Qualitative Disclosures about Market Risk.”	
 
Purchases of Natural Gas, NGLs and Condensate.   Purchases of natural gas, NGLs and condensate for the quarter ended March 31, 2011 were $40.0 million compared to $40.5 million for the quarter ended March 31, 2010. This decrease of $0.5 million was primarily due to lower realized natural gas prices and partially offset by higher realized NGL prices and higher NGL and condensate volumes.
 
Segment Gross Margin.   Segment gross margin for the quarter ended March 31, 2011 was $8.2 million compared to $6.1 million for the quarter ended March 31, 2010. This increase of $2.1 million was primarily due to increased throughput on our Gloria, Quivira and Bazor Ridge systems, higher realized NGL prices
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which positively affected our Gloria and Bazor Ridge systems, and lower realized natural gas prices which positively impacted processing margins on our Gloria system. Segment gross margin for the Gathering and Processing segment represented 66.3% of our gross margin for the quarter ended March 31, 2011, compared to 62.6% for the quarter ended March 31, 2010.
 
Direct Operating Expenses.   Direct operating expenses for the quarter ended March 31, 2011 were $2.0 million compared to $1.8 million for the quarter ended March 31, 2010. This increase of $0.2 million was primarily due to increased repairs and maintenance as well as lease and rent expenses and partially offset by a decrease in personnel costs.
 
Transmission Segment
 
Revenue.   Segment revenue for the quarter ended March 31, 2011 was $19.2 million compared to $8.1 million for the quarter ended March 31, 2010. Total natural gas throughput on our Transmission systems for the quarter ended March 31, 2011 was 446.0 MMcf/d compared to 360.6 MMcf/d in the quarter ended March 31, 2010. This increase of $11.1 million in revenue was primarily due to the new fixed-margin contract in our Transmission segment under which we purchase and simultaneously sell the natural gas that we transport, as opposed to typical contracts in this segment in which we receive a fixed fee for transporting natural gas. Our hedges had no effect on segment revenue for the quarter ended March 31, 2011 and we had no hedges during the quarter ended March 31, 2010.
 
Purchases of Natural Gas, NGLs and Condensate.   Purchases of natural gas, NGLs and condensate for the quarter ended March 31, 2011 were $15.0 million compared to $4.4 million for the quarter ended March 31, 2010. This increase of $10.6 million was primarily due to the new fixed-margin contract in our Transmission segment.
 
Segment Gross Margin.   Segment gross margin for the quarter ended March 31, 2011 was $4.1 million compared to $3.7 million for the quarter ended March 31, 2010. This increase of $0.4 million was primarily due to increased throughput on the MLGT and Midla systems, a new customer contract on one of our other, smaller systems and the realization of gross margin related to an increase in seasonally adjusted rates and reservation volumes as a result of colder weather on our AlaTenn System. Segment gross margin for the Transmission segment represented 33.7% of our gross margin for the quarter ended March 31, 2011, compared to 37.4% for the quarter ended March 31, 2010.
 
Direct Operating Expenses.   Direct operating expenses for the quarter ended March 31, 2011 were $1.1 million compared to $1.0 million for the quarter ended March 31, 2010. This increase of $0.1 million was primarily due to increases to repairs and maintenance as well as lease and rent expenses.
 
Year Ended December 31, 2010 Compared to the 2009 Successor Period and the 2009 Predecessor Period
 
Gathering and Processing Segment
 
Revenue.   Segment revenue for 2010 was $158.5 million compared to $27.9 million and $133.0 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This decrease was primarily due to decreased throughput and processing volumes on our Bazor Ridge system due to unplanned downtime caused by the pipeline rupture that occurred in April 2010. Please see “Risk Factors — Risks Related to Our Business — Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured, our operations and financial results could be adversely affected” for more information regarding the Bazor Ridge pipeline rupture. This decrease in revenue was partially offset by higher realized NGL prices across this segment. Set forth below is a comparison of the volumetric and pricing data for the year ended December 31, 2010, and the 2009 Successor Period and the 2009 Predecessor Period.

 	• 	Total natural gas throughput volumes on our Gathering and Processing segment were 175.6 MMcf/d in 2010 compared to 169.7 MMcf/d and 211.8 MMcf/d in the 2009 Successor Period and the 2009 Predecessor Period, respectively. Natural gas inlet volumes at our owned processing plants were 9.9 MMcf/d in 2010 compared to 11.4 MMcf/d and 11.7 MMcf/d in the 2009 Successor Period and the	

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 		2009 Predecessor Period, respectively. Gross NGL production volumes from our owned processing plants were 34.1 Mgal/d in 2010 compared to 38.2 Mgal/d and 39.3 Mgal/d in the 2009 Successor Period and the 2009 Predecessor Period, respectively.	

			
 	• 	The average realized price of natural gas in 2010 was $4.61/MMcf, compared to $4.71/MMcf and $3.76/MMcf for the 2009 Successor Period and the 2009 Predecessor Period, respectively. The average realized price of NGLs in 2010 was $1.08/gal, compared to $1.05/gal and $0.70/gal for the 2009 Successor Period and the 2009 Predecessor Period, respectively.	

			
 	• 	Our hedges had no effect on our revenue for the year ended December 31, 2010. We and our Predecessor had no hedges during the 2009 Successor Period and 2009 Predecessor Period, respectively.	
 
Purchases of Natural Gas, NGLs and Condensate.   Purchases of natural gas, NGLs and condensate for 2010 were $133.9 million compared to $24.2 million and $112.9 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This decrease in purchases of natural gas, NGLs and condensate was primarily driven by lower throughput and processing volumes on our Bazor Ridge system and lower fixed-margin volumes on our Lafitte system, partially offset by higher realized NGL prices across the segment.
 
Segment Gross Margin.   Segment gross margin for 2010 was $24.6 million compared to $3.7 million and $20.0 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase was largely due to higher realized NGL prices that had a positive impact on segment gross margin associated with percent-of-proceeds contracts on our Bazor Ridge and Gloria systems. In addition, natural gas prices were lower in 2010, which had a net positive impact on natural gas we processed under our elective processing arrangements. We also received additional segment gross margin associated with the construction of our Atmore processing plant that commenced operation in June 2010. This increase was partially offset by lower throughput volumes across most of our gathering systems due to well declines and reduced drilling activity due to lower natural gas prices as well as lower volumes on our Bazor Ridge system largely resulting from a pipeline rupture. Segment gross margin for the Gathering and Processing segment represented 64.5% of our gross margin for 2010, compared to 59.3% and 67.0%, respectively, for the 2009 Successor Period and the 2009 Predecessor Period.
 
Direct Operating Expenses.   Direct operating expenses for 2010 were $7.7 million compared to $1.0 million and $7.1 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This decrease in direct operating expenses was primarily due to lower outside services costs.
 
Transmission Segment
 
Revenue.   Segment revenue for 2010 was $53.5 million compared to $5.0 million and $10.2 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. Total natural gas throughput on our Transmission systems for 2010 was 350.2 MMcf/d compared to 381.3 MMcf/d and 357.6 MMcf/d in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase in revenue was primarily due to the new fixed-margin contract in our Transmission segment under which we purchase and simultaneously sell the natural gas that we transport, as opposed to typical contracts in this segment in which we receive a fixed fee for transporting natural gas. This increase in revenue was partially offset by a decrease in volumes transported pursuant to fee-based and fixed-margin arrangements. Our hedges had no effect on our revenue for the year ended December 31, 2010. We and our Predecessor had no hedges during the 2009 Successor Period and 2009 Predecessor Period, respectively.
 
Purchases of Natural Gas, NGLs and Condensate.   Purchases of natural gas, NGLs and condensate for 2010 were $40.0 million compared to $2.4 million and $0.3 million in the 2009 Successor Period and 2009 Predecessor Period, respectively. As part of our fixed-margin arrangements, we purchase natural gas, but not NGLs or condensate, in our Transmission segment. This increase was primarily due to the new fixed-margin arrangement on our MLGT system.
 
Segment Gross Margin.   Segment gross margin for 2010 was $13.5 million compared to $2.5 million and $9.9 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase was primarily due to an increase in seasonally-adjusted rates and reservation volumes as a result of colder

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weather in markets served by our AlaTenn and Midla systems. During periods of unseasonably cold weather, some shippers exceeded their maximum contract quantities and had to secure higher priced transport capacity to meet demand, thereby increasing our segment gross margin. Segment gross margin in our Transmission segment represented 35.5% of our gross margin for 2010, compared to 40.7% and 33.0% for the 2009 Successor Period and the 2009 Predecessor Period, respectively.
 
Direct Operating Expenses.   Direct operating expenses for 2010 were $4.5 million compared to $0.6 million and $3.2 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase was primarily due to incremental insurance costs that we had to incur and allocate to our assets.
 
The 2009 Successor Period and the 2009 Predecessor Period Compared to Year Ended December 31, 2008
 
Gathering and Processing Segment
 
Revenue.   Segment revenue was $27.9 million and $133.0 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $349.9 million for 2008. This decrease was primarily due to a significant decrease in commodity prices as well as a decline in plant inlet volumes and NGL production. The decline in inlet volumes and NGL production was primarily due to lower throughput on our Bazor Ridge and Alabama Processing systems resulting from reductions in drilling activity and demand as a result of the low commodity price environment, partially offset by an increase in natural gas throughput volumes on our Quivira system. Set forth below is a comparison of the volumetric and pricing data for the 2009 Successor Period, the 2009 Predecessor Period and the year ended December 31, 2008.

 	• 	Total natural gas throughput volumes on our Gathering and Processing segment were 169.7 MMcf/d and 211.8 MMcf/d in the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to 179.2 MMcf/d in 2008. Natural gas inlet volumes at our owned processing plants were 11.4 MMcf/d and 11.7 MMcf/d in the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to 12.5 MMcf/d in 2008. Gross NGL production volumes at our owned processing plants were 38.2 Mgal/d and 39.3 Mgal/d in the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to 40.2 Mgal/d in 2008.	

			
 	• 	The average realized price of natural gas was $4.71/MMcf and $3.76/MMcf for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $9.08/MMcf in 2008. The average realized price of NGLs was $1.05/gal and $0.70/gal for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $1.36/gal in 2008.	

Purchases of Natural Gas, NGLs and Condensate.   Purchases of natural gas, NGLs and condensate were $24.2 million and $112.9 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $322.5 million for 2008. This decrease in purchases of natural gas, NGLs and condensate was primarily driven by lower processing volumes as well as lower realized natural gas, NGL and condensate prices.
 
Segment Gross Margin.   Segment gross margin was $3.7 million and $20.0 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $27.4 million for 2008. This decrease was mainly due to lower realized NGL and natural gas prices on our Gloria and Bazor Ridge systems, partially offset by increased throughput volumes on the Lafitte and Quivira systems due to an increase in drilling activity during the high commodity price environment in 2008. Segment gross margin for the Gathering and Processing segment represented 59.3% and 67.0% of our gross margin for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to 63.4% for 2008.
 
Transmission Segment
 
Revenue.   Segment revenue was $5.0 million and $10.2 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $16.5 million for 2008. Total natural gas throughput on our Transmission system was 381.3 MMcf/d and 357.6 MMcf/d in the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to 336.2 MMcf/d in 2008. Despite the increase in throughput, our segment revenue declined due to a reduction in firm and interruptible transportation revenue across the

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segment, specifically caused by the full-year impact of the change in the terms of a contract on our Midla system to more accurately reflect market rates between our Predecessor and an affiliate of our Predecessor.
 
Purchases of Natural Gas, NGLs and Condensate.   Purchases of natural gas, NGLs and condensate were $2.4 million and $0.3 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $0.7 million for 2008. As part of our fixed-margin arrangements, we purchase natural gas, but not NGLs or condensate, in our Transmission segment. This increase was primarily driven by a new fixed-margin arrangement.
 
Segment Gross Margin.   Segment gross margin was $2.5 million and $9.9 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $15.8 million for 2008. The decrease was primarily a result of the full-year impact of the change in the terms of a contract on our Midla system to more accurately reflect market rates between our Predecessor and an affiliate of our Predecessor. This decrease was partially offset by an increase in transportation volumes due to weather-related demand in markets served by the AlaTenn and Midla systems. Segment gross margin for the Transmission segment represented 40.7% and 33.0% of our gross margin for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to 36.6% for 2008.
 
Direct Operating Expenses.   Direct operating expenses were $0.6 million and $3.2 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $5.2 million for 2008. This reduction in direct operating expenses was primarily due to the timing of expenditures in connection with a multi-year integrity management program undertaken by our Predecessor.
 
Liquidity and Capital Resources
 
Since the acquisition of our assets in November 2009, our sources of liquidity have included cash generated from operations, equity investments by AIM Midstream Holdings and our general partner and borrowings under our credit facility.
 
Following the closing of this offering, we expect our sources of liquidity to include:

 	• 	cash generated from operations;	
 		
 	• 	borrowings under our new credit facility; and	
 		
 	• 	issuances of debt and equity securities.	
 
We believe that the cash generated from these sources will be sufficient to allow us to distribute (i) the minimum quarterly distribution on all of our outstanding common and subordinated units and (ii) the corresponding distribution on our 2.0% general partner interest and meet our requirements for working capital and capital expenditures for the foreseeable future.
 
Working Capital
 
Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. Our working capital was ($8.4) million at March 31, 2011, compared to ($4.5) million at December 31, 2010, ($2.4) million at December 31, 2009, $28.6 million at October 31, 2009 and ($3.1) million at December 31, 2008.
 
The $3.9 million decrease in working capital from December 31, 2010 to March 31, 2011 was primarily a result of the following factors:

 	• 	an increase in risk management liabilities of $3.1 million during the quarter ended March 31, 2011, offset in part by $0.2 million in risk management assets related to our commodity derivatives; and	
 		
 	• 	an increase of $1.0 million in the current portion of long-term debt associated with the term portion of our credit facility.	

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The $2.1 million decrease in working capital from December 31, 2009 to December 31, 2010 was primarily a result of the following factors:

 	• 	an increase in the current portion of long-term debt associated with an increased amortization payment of $6.0 million due during 2011 compared to $5.0 million due during 2010; and	
 		
 	• 	an increase in accrued expenses and other liabilities of approximately $0.4 million, which was primarily the result of accrued bonus payments and unfavorable contract obligations acquired in connection with our acquisition of our assets.	
 
The $31.7 million net decrease in working capital from December 31, 2008 to October 31, 2009 was primarily the result of the elimination of affiliate obligations in connection with our acquisition of our assets in 2009.
 
Cash Flows
 
The following table reflects cash flows for the applicable periods:

 	 	 	 	 	 	American Midstream Partners, LP and	
 	 	 	American Midstream Partners Predecessor	 	 	Subsidiaries (Successor)	
 	 	 	 	 	 	 	 	 	Period from	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	August 20, 2009	 	 	 	 	Quarter	 	Quarter	
 	 	 	Year Ended	 	 	10 Months Ended	 	 	(Inception Date) to	 	 	Year Ended	 	Ended	 	Ended	
 	 	 	December 31,	 	 	October 31,	 	 	December 31,	 	 	December 31,	 	March 31,	 	March 31,	
 	 	 	2008	 	 	2009	 	 	2009	 	 	2010	 	2010	 	2011	
 	 	 	 	 	 	 	 	 	          (in thousands)	
Net cash provided by (used in):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating activities	 	 	$	18,155	 	 	 	$	14,589	 	 	 	$	(6,531	)	 	 	$	13,791	 	 	$	2,323	 	 	$	5,067	 	
Investing activities	 	 	 	(10,486	)	 	 	 	(853	)	 	 	 	(151,976	)	 	 	 	(10,268	)	 	 	(494	)	 	 	(1,291	)	
Financing activities	 	 	 	(7,929	)	 	 	 	(14,008	)	 	 	 	159,656	 	 	 	 	(4,609	)	 	 	(2,888	)	 	 	(3,686	)	

Quarter Ended March 31, 2011 Compared to Quarter Ended March 31, 2010
 
Operating Activities.   Net cash provided by (used in) operating activities was $5.1 million for the quarter ended March 31, 2011 compared to $2.3 million for the quarter ended March 31, 2010. The change in cash provided by (used in) operating activities was primarily a result of the combined effects of a net loss, net of non-cash changes, in addition to net positive changes in operating assets and liabilities.
 
Investing Activities.   Net cash provided by (used in) investing activities was ($1.3) million for the quarter ended March 31, 2011 compared to ($0.5) million for the quarter ended March 31, 2010. The change in cash provided by (used in) investing activities was primarily a result of an increase in maintenance capital expenditures associated with our Bazor Ridge and certain of our other, smaller systems.
 
Financing Activities.   Net cash provided by (used in) financing activities was ($3.7) million for the quarter ended March 31, 2011 compared to $2.9 million for the quarter ended March 31, 2010. The change in cash provided by (used in) financing activities was primarily a result of unitholder distributions, offset in part by borrowings under our credit facility.
 
Year Ended December 31, 2010 Compared to the 2009 Successor Period and the 2009 Predecessor Period
 
Operating Activities.   Net cash provided by (used in) operating activities was $13.8 million for the year ended December 31, 2010 compared to ($6.5) million and $14.6 million for the 2009 Successor Period and 2009 Predecessor Period, respectively. The change in cash provided by (used in) operating activities was primarily a result of the combined effects of a net loss, net of non-cash charges, in addition to net positive changes in operating assets and liabilities.
 
Investing Activities.   Net cash provided by (used in) investing activities was ($10.3) million for the year ended December 31, 2010 compared to ($152.0) million and ($0.9) million for the 2009 Successor Period and 2009 Predecessor Period, respectively. The change in cash used in investing activities was primarily a result of

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our acquisition of our assets in November 2009 for cash consideration of $150.8 million and the construction of the Winchester lateral in November 2010.
 
Financing Activities.   Net cash provided by (used in) financing activities was ($4.6) million for the year ended December 31, 2010 compared to $159.7 million and ($14.0) million for the 2009 Successor Period and 2009 Predecessor Period, respectively. The change in cash provided by (used in) financing activities was primarily a result of net borrowings under our credit facility of $61.0 million and a capital contribution of $100.0 million by AIM Midstream Holdings in connection with our acquisition of our assets and funding our initial working capital requirements in November 2009. During the year ended December 31, 2010, AIM Midstream Holdings contributed an additional $12.0 million to us, we made approximately $5.0 million of amortization payments under the term loan portion of our existing credit facility and we made distributions of $11.8 million to our unitholders.
 
The 2009 Successor Period and the 2009 Predecessor Period Compared to Year Ended December 31, 2008
 
Operating Activities.   Net cash provided by (used in) operating activities was ($6.5) million and $14.6 million for the 2009 Successor Period and 2009 Predecessor Period, respectively, compared to $18.2 million for the year ended December 31, 2008. The change in cash provided by (used in) operating activities was primarily a result of the combined effects of a net loss, net of non-cash charges, in addition to net negative changes in operating assets and liabilities.
 
Investing Activities.   Net cash provided by (used in) investing activities was ($152.0) million and ($0.9) million for the 2009 Successor Period and 2009 Predecessor Period, respectively, compared to ($10.5) million for the year ended December 31, 2008. The change in cash used in investing activities was primarily a result of our acquisition of our assets in November 2009 for cash consideration of $150.8 million.
 
Financing Activities.   Net cash provided by (used in) financing activities was $159.7 million and ($14.0) million for the 2009 Successor Period and 2009 Predecessor Period, respectively, compared to ($7.9) million for the year ended December 31, 2008. The change in net cash provided by (used in) financing activities was primarily a result of net borrowings under our credit facility of $61.0 million and a capital contribution of $100.0 million by AIM Midstream Holdings in connection with our acquisition of our assets and funding our initial working capital requirements in November 2009.
 
Off-Balance Sheet Arrangements
 
We do not have any off-balance sheet arrangements.
 
Capital Requirements
 
The midstream energy business can be capital intensive, requiring significant investment for the maintenance of existing assets or acquisition or development of new systems and facilities. We categorize our capital expenditures as either:

 	• 	maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or	
 		
 	• 	expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.	
 
Historically, our maintenance capital expenditures have not included all capital expenditures required to maintain volumes on our systems. It is customary in the regions in which we operate for producers to bear the cost of well connections, but we cannot be assured that this will be the case in the future. For the year ended December 31, 2010, our capital expenditures totaled $10.3 million. For this period, capital expenditures included maintenance capital expenditures and expansion capital expenditures. We estimate that 14.3% of our capital expenditures, or $1.5 million, were maintenance capital expenditures and that 85.7% of our capital

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expenditures, or $8.8 million, were expansion capital expenditures. Although we classified our capital expenditures as maintenance capital expenditures and expansion capital expenditures, we believe those classifications approximate, but do not necessarily correspond to, the definitions of estimated maintenance capital expenditures and expansion capital expenditures under our partnership agreement. While we expect that in the future expansion capital expenditures will primarily be funded through borrowings or the sale of debt or equity securities, we funded our expansion capital expenditures during the year ended December 31, 2010 through a capital contribution made to us by AIM Midstream Holdings and our general partner.
 
We have budgeted $3.2 million in capital expenditures for the year ending December 31, 2011, of which $0.2 million represents expansion capital expenditures and $3.0 million represents maintenance capital expenditures. At December 31, 2010, we had no budgeted expansion capital expenditures for 2011. However, in February 2011, our general partner’s board of directors approved a $0.2 million upgrade on our existing Gloria compressor that we expect to increase throughput capacity on the Gloria system and be completed in 2011.
 
Our 2010 expansion capital expenditures were $8.8 million and our maintenance capital expenditures were $1.5 million. Our expansion capital expenditures during 2010 included:

 	• 	the construction of the Winchester lateral on our Bazor Ridge system for $3.9 million, effectively upgrading the system and increasing the effective operating capacity of that system;	
 		
 	• 	the construction of a strategic interconnect between our Lafitte system and TGP for $1.4 million, which allows us to move gas from TGP onto our Lafitte and Gloria systems for processing and delivery to customers downstream;	
 		
 	• 	the movement and recommissioning of the Atmore processing facility to serve a producer customer for $0.8 million; and	
 		
 	• 	$2.7 million of expansion capital expenditures comprised of approximately 25 small capital projects.	
 
In addition to our budgeted capital projects, we intend to use a portion of the net proceeds from this offering to establish a cash reserve of $2.2 million related to non-recurring deferred maintenance capital expenditures for the twelve months ending June 30, 2012.
 
We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by borrowings under our new credit facility and the issuance of debt and equity securities.
 
Integrity Management
 
When we acquired our operating assets from Enbridge, we inherited an ongoing integrity management program required under regulations of the U.S. Department of Transportation, or DOT. These regulations require transportation pipeline operators to implement continuous integrity management programs over a seven-year cycle. Our current program will be completed in 2012. In connection with the acquisition of our assets from Enbridge we initiated a comprehensive review of the program and concluded that there were sixteen high consequence areas, or HCAs, in addition to those identified by our Predecessor that required further testing pursuant to DOT regulations. We expect to incur $2.1 million in integrity management expenses in 2012 associated with these HCAs to complete the current integrity management program.
 
Beginning in 2013 we will begin a new integrity management program during which we expect to incur an average of $1.5 million in integrity management expenses per year over the course of the seven-year cycle.

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Because DOT regulations require integrity management activities for each HCA to be performed within seven years from when they were last performed, we expect to incur the following expenses:

Year	 	Integrity Management Expense	 	
 	 	(in thousands)	 	
 		
2013	 	$	2,000	 	
2014	 	 	5,015	 	
2015	 	 	839	 	
2016	 	 	675	 	
2017	 	 	0	 	
2018	 	 	0	 	
2019	 	 	2,080	 	
 	 	 	 	 	
Total	 	$	10,609	 	

 
In conjunction with the commencement of our next seven-year integrity management program cycle in 2013, we plan to request the DOT’s consent to a modification of the timing of our integrity management expenses so that we spend approximately $1.5 million each year.
 
Distributions

We intend to pay a quarterly distribution at an initial rate of $0.4125 per unit, which equates to an aggregate distribution of $3.8 million per quarter, or $15.2 million on an annualized basis, based on the number of common and subordinated units anticipated to be outstanding immediately after the closing of this offering, as well as our 2.0% general partner interest. We do not have a legal obligation to make distributions except as provided in our partnership agreement.

Our Credit Facility
 
On November 4, 2009, we entered into our current $85.0 million secured credit facility with a syndicate of lending institutions. The credit facility is composed of a $50.0 million term loan facility and a $35.0 million revolving credit facility, which includes a sub-limit of up to $5.0 million for same-day swing line advances and a sub-limit of up to $10.0 million for letters of credit. Borrowings under our revolving or term loan facility bear interest at a variable rate per annum equal to the Base Rate or Eurodollar-based Rate, as the case may be, plus the Applicable Margin. Base Rate, Eurodollar-based Rate, Applicable Margin, Total Debt, and Consolidated EBITDA are each defined in the credit agreement that evidences our current facility. Our obligations under our current credit facility are secured by a lien on and a security interest in all of our personal property and our real property with an aggregate value equal to at least eighty percent (80%) of the total value of all of our real property. The terms of our credit facility contain customary covenants, including those that restrict our ability to make certain payments, distributions, acquisitions, loans, or investments, incur certain indebtednesses or create certain liens on our assets, consolidate or enter into mergers, dispose of certain of our assets, engage in certain types of transactions with our affiliates, enter into certain sale/leaseback transactions and modify certain material agreements. The remaining principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date in November 2012. As of December 31, 2010, we were in compliance with the covenants in our credit facility.
 
The events that constitute default under our current credit facility include, among other things, the failure to pay principal and interest on the indebtedness under our current facility when due, failure to comply with certain covenants or breach representations and warranties made under our current credit facility, certain bankruptcy, dissolution, liquidation or other insolvency events, or a change of control. In addition, our current certain facility includes cross default provisions with respect to indebtedness for borrowed money (other than is borrowed under our current facility) that is in excess of $1.0 million, individually, or in the aggregate.

In connection with our initial public offering, we plan to pay off our existing credit facility and enter into a new $100.0 million revolving credit facility. The new credit facility will mature in 2016, and borrowings

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will bear interest, at a variable rate per annum equal to, at our option, LIBOR or the Base Rate, as the case may be, plus the Applicable Margin (LIBOR, Base Rate and Applicable Margin will each be defined in the credit agreement that evidences our new credit facility). Under our new credit facility, in addition to the uses described in “Use of Proceeds,” we expect that borrowings may be used for (i) the refinancing and repayment of certain existing indebtedness, (ii) working capital and other general partnership purposes and (iii) future capital expenditures. Borrowings under our new credit facility will be secured by a first-priority lien on and security interest in substantially all of our assets. We expect the credit agreement that evidences our new credit facility to contain customary covenants, including restrictions on our ability to incur additional indebtedness, make certain investments, loans or advances, make distributions to our unitholders, make dispositions or enter into sales and leasebacks, or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries. The credit agreement will also require compliance with certain financial covenant ratios, including limiting our total leverage ratio (ratio of consolidated indebtedness to consolidated EBITDA) to no greater than 4.5x (or under certain circumstances, 5.0x) and limiting our interest coverage ratio (ratio of consolidated EBITDA to consolidated interest expense) to no less than 2.5x.

The events that constitute an Event of Default under our new credit agreement are expected to be customary for loans of this size and type.
 
Credit Risk

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers to which we provide services and sell commodities. Our three largest purchasers of natural gas in our Gathering and Processing segment are ConocoPhillips, Enbridge Marketing (U.S.) L.P. and Dow Hydrocarbons and Resources and accounted for approximately 34%, 29% and 10%, respectively, of our segment revenue for the year ended December 31, 2010. Additionally, ExxonMobil and Calpine Corporation are the two largest purchasers of natural gas and transmission capacity, respectively, in our Transmission segment and accounted for approximately 43% and 10%, respectively, of our segment revenue for the year ended December 31, 2010. We examine the creditworthiness of third-party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.

Customer Concentration

A significant percentage of the gross margin in each of our segments is attributable to a relatively small number of customers. In our Gathering and Processing segment, Contango Operators Inc. and Venture Oil & Gas Co. accounted for approximately 19% and 13%, respectively, of our segment gross margin for the year ended December 31, 2010 and 15% and 23%, respectively, for the quarter ended March 31, 2011. In our Transmission segment, Calpine Corporation accounted for approximately 38% and 30% of our segment gross margin for the year ended December 31, 2010 and the quarter ended March 31, 2011, respectively. Although we have gathering, processing or transmission contracts with each of these customers of varying duration, if one or more of these customers were to default on their contract or if we were unable to renew our contract with one or more of these customers on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all. In any of these situations, our gross margin and cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our gross margin.

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Contractual Obligations
 
The table below summarizes our contractual obligations and other commitments as of December 31, 2010:

 	 	 	 	 	Less Than	 	 	1-3	 	 	 	 	 	More Than	 	
Contractual Obligation	 	Total	 	 	1 Year	 	 	Years	 	 	3-5 Years	 	 	5 Years	 	
 	 	 	 	 	 	 	 	(in thousands)	 	 	 	 	 	 	 	
 		
Long-term debt(1)	 	$	56,370	 	 	$	6,000	 	 	$	50,370	 	 	$	—	 	 	$	—	 	
Rights-of-way and operating leases	 	 	2,057	 	 	 	580	 	 	 	747	 	 	 	700	 	 	 	30	 	
Asset retirement obligations	 	 	8,340	 	 	 	914	 	 	 	—	 	 	 	—	 	 	 	7,426	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	66,767	 	 	$	7,494	 	 	$	51,117	 	 	$	700	 	 	$	7,456	 	

 

 
		
(1) 	Upon the closing of this offering, we expect to incur long-term debt under our new credit facility of $100.0 million, which will be used, together with the net proceeds of this offering, to make a distribution to AIM Midstream Holdings, the LTIP participants holding common units and our general partner as described in “Use of Proceeds.” We expect the initial interest rate under our new credit facility to be 3.0%.	

Quantitative and Qualitative Disclosures about Market Risk
 
Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate in our Gathering and Processing segment. Both our profitability and our cash flow are affected by volatility in the prices of these commodities. Natural gas and NGL prices are impacted by changes in the supply and demand for natural gas and NGLs, as well as market uncertainty. For a discussion of the volatility of natural gas and NGL prices, please read “Risk Factors.” Adverse effects on our cash flow from reductions in natural gas and NGL product prices could adversely affect our ability to make distributions to unitholders. We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, optimization of our assets, and the use of derivative contracts. Our overall direct exposure to movements in natural gas prices is minimal as a result of natural hedges inherent in our current contract portfolio. Natural gas prices, however, can also affect our profitability indirectly by influencing the level of drilling activity in our areas of operation. We are a net seller of NGLs, and as such our financial results are exposed to fluctuations in NGLs pricing. In January 2011, we implemented a hedging program by entering into a number of financial hedges to protect our expected NGL production through mid 2012. Through these January 2011 hedge transactions, we executed swap and put contracts settled against the market prices of ethane, propane, iso-butane, normal butane and natural gasoline.

 
We continually and proactively monitor our commodity exposure and compare this exposure to our stated hedging strategy. In June 2011, the Board of Directors of our general partner determined that we would gain operational and strategic flexibility from cancelling our then-existing swap contracts and entering into a new swap contract with an existing counterparty that extends through the end of 2012. We did not modify the put contracts we entered into through our January 2011 hedge transactions.

 
Pursuant to our January 2011 hedge transactions and June 2011 hedge transactions, we have hedged approximately 85% of our expected exposure to NGL prices in 2011, and approximately 89% in 2012.

 
In June 2010, prior to our entry into our January 2011 hedge transactions, we executed a series of put contracts settled against a basket of NGLs. Under these put contracts, we receive a fixed floor price of $1.03 per gallon on 13,212 gal/d of a negotiated NGL and liquids basket, which included ethane, propane, iso-butane, normal butane, natural gasoline and WTI crude oil. The relative weightings of the price of each component of the basket are calculated via an arithmetic formula. Based on the current commodity price environment, these hedges are currently out of the money.

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The table below sets forth certain information regarding our NGL fixed swaps as of December 31, 2010 and June 6, 2011:

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Notional	 	 	Weighted Average Price	 	Fair Market Value	 	
 	 	 	 	Volumes	 	 	($/gal)	 	December 31,	 	 	June 6,	 	
Commodity	 	Period	 	(gal/d)	 	 	We Receive	 	 	We Pay	 	2010	 	 	2011	 	
 		
Ethane	 	Jul 2011-Dec 2012	 	 	7,300	 	 	$	0.57	 	 	OPIS avg	 	 	N/A	 	 	$	(163,154	)	
Propane	 	Jul 2011-Dec 2012	 	 	7,050	 	 	$	1.40	 	 	OPIS avg	 	 	N/A	 	 	$	(88,354	)	
Iso-Butane	 	Jul 2011-Dec 2012	 	 	2,510	 	 	$	1.74	 	 	OPIS avg	 	 	N/A	 	 	$	(45,888	)	
Normal Butane	 	Jul 2011-Dec 2012	 	 	3,000	 	 	$	1.81	 	 	OPIS avg	 	 	N/A	 	 	$	(57,494	)	
Natural Gasoline	 	Jul 2011-Dec 2012	 	 	5,500	 	 	$	2.31	 	 	OPIS avg	 	 	N/A	 	 	$	(111,198	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	 	 	25,360	 	 	$	1.44	 	 	 	 	 	N/A	 	 	$	(466,089	)	

 
The table below sets forth certain information regarding our NGL puts as of December 31, 2010 and June 6, 2011:

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Notional	 	 	Floor Strike	 	 	Fair Market Value	 	
 	 	 	 	Volumes	 	 	Price	 	 	December 31,	 	 	June 6,	 	
Commodity	 	Period	 	(gal/d)	 	 	($/gal)	 	 	2010	 	 	2011	 	
 		
NGL basket(1)	 	Feb 2011-Jul 2012	 	 	9,800	 	 	$	1.29	 	 	 	N/A	 	 	$	152,227	 	
NGL basket(2)	 	Jul 2010-Jun 2011	 	 	13,212	 	 	$	1.03	 	 	$	—	 	 	$	0	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	 	 	23,012	 	 	$	1.14	 	 	$	—	 	 	$	152,227	 	

 

			
(1)		In January 2011, we entered into a put arrangement under which we receive a fixed floor price of $1.29 per gallon on 9,800 gal/d of a negotiated NGL basket, which includes ethane, propane, iso-butane, normal butane and natural gasoline. The relative weightings of the price of each component of the basket are calculated via an arithmetic formula.	
 		
(2)		In June 2010, we entered into a put arrangement under which we receive a fixed floor price of $1.03 per gallon on 13,212 gal/d of a negotiated NGL and liquids basket, which includes ethane, propane, iso-butane, normal butane, natural gasoline and WTI crude oil. The relative weightings of the price of each component of the basket are calculated via an arithmetic formula.	
 
Interest Rate Risk
 
We have exposure to changes in interest rates on our indebtedness associated with our credit facility. In December 2009, we entered into an interest rate cap with participating lenders with a $26.5 million notional amount at December 31, 2010 that effectively caps our Eurodollar-based rate exposure on that portion of our debt at a maximum of 4.0%. We anticipate that, in conjunction with our entry into a new credit facility contemporaneous with the closing of this offering, we would implement similar swap or cap structures to mitigate our exposure to interest rate risk.
 
The credit markets have recently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will continue to tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.
 
A hypothetical increase or decrease in interest rates by 1.0% would have changed our interest expense by $0.6 million for the year ended December 31, 2010.
 
Impact of Seasonality
 
Results of operations in our Transmission segment are directly affected by seasonality due to higher demand for natural gas during the winter months, primarily driven by our LDC customers. On our AlaTenn system, we offer some customers seasonally-adjusted firm transportation rates that require customers to reserve capacity at rates that are higher in the period from October to March compared to other times of the year. On

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our Midla system, we offer customers seasonally-adjusted firm transportation reservation volumes that allow customers to reserve more capacity during the period from October to March compared to other times of the year. The combination of seasonally-adjusted rates and reservation volumes, as well as higher volumes overall, result in higher revenue and segment gross margin in our Transmission segment during the period from October to March compared to other times of the year. We generally do not experience seasonality in our Gathering and Processing segment.
 
Critical Accounting Policies and Estimates
 
The preparation of financial statements in accordance with GAAP requires our and our Predecessor’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. Actual results could differ from these estimates. The policies and estimates discussed below are considered by our and Predecessor’s management to be critical to an understanding of the financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.
 
Use of Estimates.   The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect our reported financial positions and results of operations. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenue and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing tangible and intangible assets for possible impairment, (4) estimating the useful lives of our assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results could differ materially from our estimates.
 
Property, Plant and Equipment.   In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the period it benefits. Our property, plant and equipment is depreciated using the straight-line method over the estimated useful lives of the assets. The costs of renewals and betterments which extend the useful life of property, plant and equipment are also capitalized. The costs of repairs, replacements and maintenance projects are expensed as incurred.
 
Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values which would impact future depreciation expense.
 
Impairment of Long-Lived Assets.   We assess our long-lived assets for impairment on authoritative guidance. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.
 
Examples of long-lived asset impairment indicators include:

 	• 	a significant decrease in the market price of a long-lived asset or asset group;	
 		
 	• 	a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;	

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 	• 	a significant adverse change in legal factors or in the business climate could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;	
 		
 	• 	as accumulation of costs significantly in excess of the amount originally expected for the for the acquisition or construction of the long-lived asset or asset group;	
 		
 	• 	a current-period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and	
 		
 	• 	a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.	
 
We incurred no impairment charges during the year ended December 31, 2010.
 
Environmental Remediation.   Current accounting guidelines require us to recognize a liability and expense associated with environmental remediation if (i) government agencies mandate such activities, (ii) the existence of a liability is probable and (iii) the amount can be reasonably estimated. As of December 31, 2010 we have recorded no liability for remediation expenditures. If governmental regulations change, we could be required to incur remediation costs which may have a material impact on our profitability.
 
Asset Retirement Obligations.   As of December 31, 2010, we have recorded liabilities of $7.2 million for future asset retirement obligations associated with our pipeline assets. Related accretion expense has been recorded in interest expense as discussed in Note 1 in our consolidated financial statements. The recognition of an asset retirement obligation requires that management make numerous estimates, assumptions and judgments regarding such factors as costs of remediation, timing of settlement to changes in the estimate of the costs of remediation. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset or corresponding liability on a prospective basis and an adjustment in our depreciation expense in future periods.

 
Equity-Based Awards.   We account for equity-based awards in accordance with applicable guidance, which establishes standards of accounting for transactions in which an entity exchanges its equity instruments for goods or services. Equity-based compensation expense is recorded based upon the fair value of the award at grant date. Such costs are recognized as expense on a straight-line basis over the corresponding vesting period.

 
During 2010 and 2009, the fair values of the phantom-unit grants that we made were calculated based on several valuation models, including a discounted cash flow, or DCF, model, a comparable company multiple analysis and a comparable transaction multiple analysis. The DCF model included certain market assumptions related to future throughput volumes, projected fees and/or prices, expected costs of sales and direct operating costs and risk adjusted discount rates. Both the comparable company analysis and comparable transaction analysis contain significant assumptions consistent with the DCF model, in addition to assumptions related to comparability, appropriateness of multiples (primarily based on EBITDA and distributable cash flow) and certain assumptions in the calculation of enterprise value. The initial valuation of $10.00 per common unit was prepared in August 2009 in connection with our formation in anticipation of the acquisition of our assets from a subsidiary of Enbridge Energy Partners, L.P. In November 2009, we received indirect third-party investments at that same valuation in connection with the acquisition of our assets from Enbridge. We assessed the adequacy of that valuation on each grant date subsequent to the initial fair value calculation to determine if events or circumstances had occurred that would cause that valuation to become less relevant, noting none. Moreover, we received additional indirect third-party investments at $10.00 per common unit in each of September and November 2010. As a result, we maintained that $10.00 valuation for phantom-unit grants made in November 2009, March 2010 and October 2010.

 
For the phantom-unit grants made during March 2011, the fair values of the grants were calculated by affiliates of our general partner as $13.67 per common unit based on several valuation models as of December 31, 2010, including a DCF model, a comparable company multiple analysis and a comparable

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transaction multiple analysis. The DCF model includes certain market assumptions related to future throughput volumes, projected fees and/or prices, expected costs of sales and direct operating costs and risk adjusted discount rates. Both the comparable company analysis and comparable transaction analysis contain significant assumptions consistent with the DCF model, in addition to assumptions related to comparability, appropriateness of multiples (primarily based on EBITDA and distributable cash flow) and certain assumptions in the calculation of enterprise value. The year-end 2010 valuation was completed in January 2011. We assessed the adequacy of that valuation in connection with the March 2011 grant date to determine if events or circumstances had occurred since December 31, 2010 that would cause that valuation to become less relevant, noting none.

 
As adjusted to reflect the reverse stock split described under the caption “Summary — Recapitalization Transactions and Partnership Structure,” the $13.67 fair value per phantom unit is $28.17 per phantom unit as compared to an assumed offering price of $20.00 per common unit.

Revenue Recognition.   We recognize revenue when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured. We record revenue and cost of product sold on the gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that is purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating or transportation we record those fees separately in revenue. Under keep-whole contracts, we keep the NGLs extracted and return the processed natural gas or value of the natural gas to the producer.
 
Natural Gas Imbalance Accounting.   Quantities of natural gas over-delivered or under-delivered related to operational balancing agreements are recorded monthly as inventory or as a payable using weighted average prices at the time the imbalance was created. Monthly, gas imbalances over-delivered are valued at the lower of cost or market; gas imbalances under-delivered are valued at replacement cost. These imbalances are typically settled in the following month with deliveries of natural gas. Under the contracts, imbalance cash-outs are recorded as a sale or purchase of natural gas, as appropriate.

Price Risk Management Activities.   We have structured our hedging activities in order to minimize our commodity pricing and interest rate risks and to help maintain compliance with certain financial covenants in our credit facility. These hedging activities rely upon forecasts of our expected operations and financial structure through December 2012. If our operations or financial structure are significantly different from these forecasts, we could be subject to adverse financial results as a result of these hedging activities. We mitigate this potential exposure by retaining an operational cushion between our forecasted transactions and the level of hedging activity executed.

 
From the inception of our hedging program in December 2009, we used mark-to-market accounting for our commodity hedges and interest rate caps. We record monthly realized gains and losses on hedge instruments based upon cash settlements information. The settlement amounts vary due to the volatility in the commodity market prices throughout each month. We also record unrealized gains and losses quarterly based upon the future value on mark-to-market hedges through their expiration dates. The expiration dates vary but are currently no later than October 2012 for our interest rate hedge and December 2012 for our commodity hedges. Costs incurred to purchase interest rate and NGL puts are amortized during the contract period through the unrealized risk management instruments in total revenue. We monitor and review hedging positions regularly.

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INDUSTRY OVERVIEW
 
General
 
The midstream natural gas industry provides the link between the exploration and production of raw natural gas and the delivery of that natural gas and its by-products to industrial, commercial and residential end users. The principal components of the business consist of gathering, compressing, treating, dehydrating, processing, fractionating, transporting and marketing natural gas and natural gas liquids, or NGLs. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing and treating plants to natural gas producing wells. Companies within this industry provide services at various stages along the natural gas value chain by gathering natural gas from producers at the wellhead, separating the hydrocarbons into dry gas (primarily methane) and NGLs, and then routing the separated dry gas and NGL streams to the next intermediate stage of the value chain or to transportation pipelines for delivery to end-markets. Transportation consists of moving pipeline-quality natural gas from these gathering systems and plants for delivery to customers.
 
The following diagram illustrates the various components of the natural gas value chain:

 
Midstream Services
 
The range of services provided by midstream natural gas service providers are generally divided into the following six categories:
 
Gathering.   At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems transport natural gas from the wellhead to a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures.
 
Compression.   Gathering systems are operated at design pressures that maximize the total throughput from all connected wells. Through a mechanical process known as compression, volumes of natural gas at a given pressure are compressed to a sufficiently higher pressure, thereby allowing those volumes to be delivered into a higher pressure downstream pipeline to be brought to market. Since wells produce at progressively lower field pressures as they age, it becomes necessary to add additional compression over time near the wellhead to maintain throughput across the gathering system.
 
Treating and Dehydration.   Another process in the midstream value chain is treating and dehydration, a step that involves the removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide that may be present when natural gas is produced at the wellhead. These impurities must be removed for the natural gas to meet the specifications for transportation on long-haul intrastate and interstate pipelines. Moreover, end users will not purchase natural gas with a high level of these impurities. To meet downstream pipeline and end-user natural gas quality standards, the natural gas is

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dehydrated to remove the saturated water and is chemically treated to separate the impurities from the gas stream.
 
Processing.   The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of other NGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, most natural gas is not suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs. This natural gas, referred to as rich or wet natural gas, must be processed to remove these heavier hydrocarbon components, as well as natural gas condensate. NGLs not only interfere with pipeline transportation, but are also valuable commodities once removed from the natural gas stream. The removal and separation of NGLs usually takes place in a processing plant using industrial processes that exploit differences in the weights, boiling points, vapor pressures and other physical characteristics of NGL components.
 
Fractionation.   The mixture of NGLs that results from natural gas processing is generally comprised of the following five components: ethane, propane, normal butane, iso-butane and natural gasoline. This mixture is often referred to as y-grade or raw make NGL. Fractionation is the process by which this mixture is separated into the NGL components prior to their sale to various petrochemical and industrial end users.
 
Transmission.   Once the raw natural gas has been treated and processed, the remaining natural gas, or residue natural gas, and NGL components are transported and marketed to end users. The transmission of natural gas involves the movement of pipeline-quality natural gas from gathering systems and processing facilities to wholesalers and end users, including industrial plants and LDCs. LDCs purchase natural gas from transmission companies and market that natural gas to commercial, industrial and residential end users. Transmission pipelines generally span considerable distances and consist of large-diameter pipelines that operate at higher pressures than gathering pipelines to facilitate the transportation of greater quantities of natural gas. The concentration of natural gas production in a few regions of the U.S. generally requires transmission pipelines to cross state borders to meet national demand. These pipelines are referred to as interstate pipelines and are primarily regulated by federal agencies or commissions, including the FERC. Pipelines that transport natural gas produced and consumed wholly within one state are generally referred to as intrastate pipelines. Intrastate pipelines are primarily regulated by state agencies or commissions.
 
Typical Midstream Contractual Arrangements
 
The midstream services described above, with the exception of transmission, are typically provided under contracts that vary in the amount of commodity price risk they carry. The following four contractual arrangements are the most common in the midstream industry:

 	• 	Fee-Based.   In exchange for its gathering, compression and treating services, the midstream service provider receives a fee per unit of natural gas that is gathered at the wellhead, compressed and treated. Depending on the fee structure, producer customers may pay a single bundled fee for gathering, treating and compressing, or those services may be unbundled. Under fee-based arrangements, the midstream service provider bears no direct commodity price risk, although a sustained decline in natural gas prices may result in a decline in volumes of natural gas for which these services are needed.	
 		
 	• 	Fixed-Margin.   Under these arrangements, the midstream service provider purchases natural gas from producers or suppliers at receipt points on its systems at an index price less a fixed transportation fee and simultaneously sells an identical volume of natural gas at delivery points on its systems at the same, undiscounted index price. By entering into back-to-back purchases and sales of natural gas, the midstream service provider is able to lock in a fixed-margin on these transactions. These contracts are sometimes referred to as wellhead purchase agreements.	
 		
 	• 	Percent-of-Proceeds, or POP.   In exchange for its processing services, the midstream service provider remits to a producer customer a percentage of the proceeds from sales of residue natural gas and/or NGLs that result from its processing, or in some cases, a percentage of the physical residue natural gas	

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 		and/or NGLs at the tailgate of the processing plant, retaining the balance of the proceeds or physical commodity for its own account. These types of arrangements expose the midstream service provider to direct commodity price risk because the revenue from these contracts directly correlates with the fluctuating price of natural gas and/or NGLs. Moreover, the midstream service provider using a percent-of-proceeds arrangement will bear indirect commodity price risk in that a sustained decline in natural gas or NGL prices may result in a decline in volumes of natural gas for which processing services are needed.	

 	• 	Keep-Whole.   Keep-whole arrangements may be used for processing services. Under these arrangements, the midstream service provider keeps 100% of the NGLs produced, and the processed natural gas, or value of the natural gas, is returned to the producer customer. Since some of the natural gas is used and removed during processing, the midstream service provider compensates the producer customer for the amount used and removed in processing by supplying additional natural gas or by paying an agreed-upon value for the natural gas utilized. These arrangements have the highest direct commodity price exposure for the midstream service provider because its costs are dependent on the price of natural gas and its revenue is based on the price of NGLs, each of which fluctuate independently.	
 
There are three primary forms of contracts utilized in the transmission of natural gas, firm transportation contracts and interruptible transportation contracts.

 	• 	Firm Transportation.   Firm transportation contracts require a shipper customer to pay a monthly reservation charge, which is a fixed charge owed regardless of the actual pipeline capacity used by that customer. When a shipper customer uses the capacity it has reserved under these contracts, the midstream service provider also collects a usage charge based on the volume of natural gas actually transported. Usage charges generally enable the midstream service provider to recover the variable costs of operating the transmission system. Usage charges are typically a small percentage of the total revenue received under firm transportation contracts.	
 		
 	• 	Interruptible Transportation.   Interruptible transportation contracts require a shipper customer to pay fees based on its actual use of the transmission system and related services. Shipper customers with interruptible transportation contracts are not assured capacity or service on the transmission pipeline. To the extent that the transmission pipeline has physical capacity resulting from firm transportation contracts that are not being fully utilized, the system uses that capacity for interruptible service.	
 		
 	• 	Fixed-Margin Transportation.   Under these arrangements, the midstream service provider purchases natural gas from producers or suppliers at receipt points on its systems at an index price less a fixed transportation fee and simultaneously sells an identical volume of natural gas at delivery points on its systems at the same, undiscounted index price. These contracts are sometimes referred to as wellhead purchase agreements.	
 
U.S. Natural Gas Fundamentals
 
Natural gas is a critical component of energy consumption in the United States. According to the EIA, annual consumption of natural gas in the United States increased from approximately 22.8 Tcf in 2009 to approximately 24.1 Tcf in 2010, an increase of approximately 5.7%. Total annual domestic natural gas consumption is expected to rise from 24.1 Tcf in 2010 to 26.5 Tcf in 2035.
 
In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset the decline rates of existing production. Over the past several years, a fundamental shift in U.S. natural gas production has emerged with the contribution of natural gas from unconventional resources, defined by the EIA as natural gas produced from shale formations and coalbeds. The primary factors driving this shift are the emergence of unconventional natural gas plays and advances in technology that have allowed producers to cost-effectively extract significant volumes of natural gas from these plays. The development of these unconventional sources

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offsets declines in other U.S. natural gas supply, meeting growing consumption and lowering the need for imported natural gas.
 
According to the EIA:

 	• 	The industrial and electricity generation sectors are the largest users of natural gas in the United States, accounting for approximately 58% of the total natural gas consumed in the United States during 2010;	
 		
 	• 	Annual industrial natural gas demand is expected to grow sharply in the near term, from 7.3 Tcf in 2009 to 9.4 Tcf in 2020 as a result of an expected recovery in industrial production;	
 		
 	• 	In 2010, the end-user commercial and residential sectors accounted for approximately 34% of the total natural gas consumed in the United States; and	
 		
 	• 	During the last five years ending December 31, 2010, the United States has on average consumed approximately 23.0 Tcf per year, with average annual domestic production of approximately 20.0 Tcf during the same period.	
 
The graph below represents projected U.S. natural gas production versus U.S. natural gas consumption through the year 2035.

 
Source: Energy Information Administration.

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BUSINESS
 
Overview
 
We are a growth-oriented Delaware limited partnership that was formed by AIM in August 2009 to own, operate, develop and acquire a diversified portfolio of natural gas midstream energy assets. We are engaged in the business of gathering, treating, processing and transporting natural gas through our ownership and operation of nine gathering systems, three processing facilities, two interstate pipelines and six intrastate pipelines. Our primary assets, which are strategically located in Alabama, Louisiana, Mississippi, Tennessee and Texas, provide critical infrastructure that links producers and suppliers of natural gas to diverse natural gas markets, including various interstate and intrastate pipelines, as well as utility, industrial and other commercial customers. We currently operate approximately 1,400 miles of pipelines that gather and transport over 500 MMcf/d of natural gas. We acquired our existing portfolio of assets from Enbridge in November 2009.

 
Our operations are organized into two segments: (i) Gathering and Processing and (ii) Transmission. In our Gathering and Processing segment, we receive fee-based and fixed-margin compensation for gathering, transporting and treating natural gas. Where we provide processing services at the plants that we own, or obtain processing services for our own account under our elective processing arrangements, we typically retain and sell a percentage of the residue natural gas and resulting NGLs under POP arrangements. We own three processing facilities that produced an average of approximately 34.1 Mgal/d and 56.6 Mgal/d of gross NGLs for the year ended December 31, 2010 and the quarter ended March 31, 2011, respectively. In addition, in connection with our elective processing arrangements, we contract for processing capacity at a third-party plant where we have the option to process natural gas that we purchase. Under these arrangements, we sold an average of approximately 28.1 Mgal/d and 35.0 Mgal/d of net equity NGL volumes for the year ended

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December 31, 2010 and the quarter ended March 31, 2011, respectively. We also receive fee-based and fixed-margin compensation in our Transmission segment primarily related to capacity reservation charges under our firm transportation contracts and the transportation of natural gas pursuant to our interruptible transportation and fixed-margin contracts.
 
For the year ended December 31, 2010 and the quarter ended March 31, 2011, we generated $38.1 million and $12.3 million of gross margin, respectively, of which $24.6 million and $8.2 million, respectively, was segment gross margin generated in our Gathering and Processing segment and $13.5 million and $4.1 million, respectively, was segment gross margin generated in our Transmission segment. For the year ended December 31, 2010 and the quarter ended March 31, 2011, $24.9 million and $7.3 million, or 65.4% and 59.5%, respectively, of our gross margin was generated from fee-based, fixed-margin and firm and interruptible transportation contracts with respect to which we have little or no direct commodity price exposure. For a definition of gross margin and a reconciliation of gross margin to its most directly comparable financial measure calculated in accordance with GAAP, please read “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures.”
 
Business Strategies
 
Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business. We expect to achieve this objective by executing the following strategies:

 	• 	Capitalize on Organic Growth Opportunities Associated with Our Existing Assets.   We continually seek to identify and evaluate economically attractive organic expansion and asset enhancement opportunities that leverage our existing asset footprint and strategic relationships with our customers. We expect to have opportunities to expand our systems into new markets and sources of supply, which we believe will make our services more attractive to our customers. We intend to focus on projects that can be completed at a relatively low cost and have potential for attractive returns. Projects that we expect to undertake in our forecast period include:	

 	• 	a cylinder upgrade on the existing Gloria compressor that we expect will increase throughput capacity on the Gloria system by approximately 7 MMcf/d and that we expect to be completed in the third quarter of 2011 at a cost of approximately $0.2 million;	

			
 	• 	the construction of an interconnect and the installation of a skid-mounted treating facility along Midla, which is expected to cost approximately $0.3 million and be completed in the third quarter of 2011; and	

 
			
 	• 	the addition of field compression capacity to the Bazor Ridge gathering system, which would provide us with the opportunity to treat new natural gas production, at an expected cost of approximately $3.4 million that we expect to complete in the first quarter of 2012.	

			
 	• 	Attract Additional Volumes to Our Systems.   We intend to attract new volumes of natural gas to our systems from existing and new customers by continuing to provide superior customer service and aggressively marketing our services to additional customers in our areas of operation. In addition, we intend to rebuild or reestablish relationships with customers that were potentially underserved by the previous owner of our assets. For example, in 2010 we were able to contract with a customer on our Gloria system for volumes of natural gas that it had decided to have gathered and processed by alternative means prior to our acquisition of the system. We have available capacity on a majority of our systems, and as a result, we can accommodate additional volumes at a minimal incremental cost.	
 		
 	• 	Pursue Strategic and Accretive Acquisitions.   We plan to pursue accretive acquisitions of energy infrastructure assets that are complementary to our existing asset base or that provide attractive returns in new operating regions or business lines. We will pursue acquisitions in our areas of operation that we believe will allow us to realize operational efficiencies by capitalizing on our existing infrastructure, personnel and customer relationships. We will also seek acquisitions in new geographic areas or new	

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 		but related business lines to the extent that we believe we can utilize our operational expertise to enhance our business with these acquisitions.	

			
 	• 	Manage Exposure to Commodity Price Risk.   We will manage our commodity price exposure by targeting a contract portfolio that is weighted towards firm transportation, fee-based and fixed-margin contracts while mitigating direct commodity price exposure by employing a prudent hedging strategy. For the year ended December 31, 2010 and the quarter ended March 31, 2011, approximately 65.4% and 59.5%, respectively, of our gross margin was generated from firm transportation, fee-based and fixed-margin contracts that, together with our percent-of-proceeds contracts and hedging activities, generated relatively stable cash flows. For the years ending December 31, 2011 and 2012, we have hedged 85% and 89%, respectively, of our expected net equity NGL volumes with a combination of swaps and puts for the specific NGL components to which we are exposed. With respect to our exposure to natural gas prices, we are currently long natural gas on certain of our systems and short natural gas on certain of our other systems, which effectively creates a natural hedge against our exposure to fluctuations in the price of natural gas.	

			
 	• 	Maintain Financial Flexibility and Conservative Leverage.   We plan to pursue a disciplined financial policy and seek to maintain a conservative capital structure that we believe will allow us to consider attractive growth projects and acquisitions even in challenging commodity price or capital markets environments. At the closing of this offering, we anticipate entering into a new credit facility with sufficient capacity to fund acquisitions, expansions and working capital for our operations.	
 		
 	• 	Continue our Commitment to Safe and Environmentally Sound Operations.   The safety of our employees and the communities in which we operate is one of our highest priorities. We believe it is critical to handle natural gas and NGLs for our customers safely, while striving to minimize the environmental impact of our operations. To this end, we implemented a safety performance program, including an integrity management program, upon our formation in 2009 and implemented planned maintenance programs to increase the safety, reliability and efficiency of our operations.	
 
Competitive Strengths
 
We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:

 	• 	Well Positioned to Pursue Opportunities Overlooked by Larger Competitors .  Our size and flexibility, in conjunction with our geographically diverse asset base, positions us to pursue economically attractive growth projects and acquisitions that may not be large enough to be attractive to many of our larger competitors. Given the current size of our business, these opportunities may have a larger impact on us than they would have on our competitors and may provide us with material growth opportunities. In addition, as a result of our focus on customer service, we believe that we have unique insights into our customers’ needs and are well situated to take advantage of organic growth opportunities that arise from those needs. For example, in 2010 we identified and executed an opportunity to construct a major interconnection on our Lafitte system with a third-party interstate pipeline offshore Louisiana that provides additional volumes to a customer’s refinery while also substantially increasing the utilization of both our Gloria and Lafitte systems.	
 		
 	• 	Diversified Asset Base.   Our assets are diversified geographically and by business line, which contributes to the stability of our cash flows and creates a number of potential growth avenues for our business. We primarily operate in five states, have access to multiple sources of natural gas supply and service various interstate and intrastate pipelines as well as utility, industrial and other commercial customers. We believe this diversification provides us with a variety of growth opportunities and mitigates our exposure to reduced activity in any one area.	
 		
 	• 	Strategically Located Assets.   Our assets are located in areas where we believe there will be opportunities to access new natural gas supplies and to capture new customers that are underserved by our competitors. We continue to see drilling activity on and around our systems, and we believe that	

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 		our assets are strategically positioned to capitalize on the resurgent drilling activity, increased demand for midstream services and growing commodity consumption in the Gulf Coast and Southeast U.S. regions. This belief is based on:	

 	• 	the proximity of our gathering and transmission systems to newly producing wells and the relatively lower cost to connect to our systems compared to those farther away;	
 		
 	• 	the available capacity of our systems, coupled with an ability to add capacity economically to our systems; and	
 		
 	• 	the fact that many of our systems have multiple downstream interconnects that provide our customers with multiple market delivery options, thus causing our systems to be more attractive versus those of our competitors.	

			
 	• 	Focus on Delivering Excellent Customer Service.   We view our strong customer relationships as one of our key assets and believe it is critical to maintain operational excellence and ensure best-in-class customer service and reliability. Furthermore, we believe our entrepreneurial culture and smaller size relative to our peers enables us to offer more customized and creative solutions for our customers and to be more responsive to their needs. We believe our customer focus will enable us to capture new opportunities and expand into new markets.	
 		
 	• 	Experienced and Incentivized Management and Operating Teams.   Our executive management team has an average of over 25 years of experience in the midstream energy industry. The team possesses a comprehensive skill set to support our business and enhance unitholder value through asset optimization, accretive development projects and acquisitions. In addition, our field supervisory team has operated our assets for an average of over 20 years. We believe that our field employees’ knowledge of the assets will further contribute to our ability to execute our business strategies. Furthermore, the interests of our executive management and operating teams are strongly aligned with those of common unitholders, including through their ownership of common units and our Long-Term Incentive Plan.	
 
Our Sponsor

AIM is a private investment firm specializing in investments in energy, natural resources, infrastructure and real property. AIM, along with certain of the funds that AIM advises, currently indirectly owns 84.4% of the ownership interests in AIM Midstream Holdings, which owns 100.0% of our general partner. Robert B. Hellman, Jr., Matthew P. Carbone and Edward O. Diffendal serve on the board of directors of our general partner and are principals of and have ownership interests in AIM. After the closing of this offering, AIM Midstream Holdings will continue to hold 100.0% of the ownership interests in our general partner and will hold 16.0% of our common units and 100.0% of our subordinated units, or an aggregate of 58.0% of our total limited partner interests.

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Our Assets
 
We own and operate all of our assets, which consist of nine gathering systems, three processing facilities, two interstate pipelines and six intrastate pipelines. Our assets are primarily located in Alabama, Louisiana, Mississippi, Tennessee and Texas. We organize our operations into two business segments: (i) Gathering and Processing; and (ii) Transmission. The following table provides information regarding our segments and assets as of March 31, 2011 and for the year ended December 31, 2010 and the quarter ended March 31, 2011.

 	 	 	 	 	 	 	 	 	 	 	 	 	 	Approximate	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Average	
 	 	 	 	 	 	 	 	Approximate	 	 	 	 	 	Throughput (MMcf/d)	
 	 	 	 	 	 	 	 	Number	 	 	 	Approximate	 	Year	 	Quarter	
 	 	 	 	 	 	 	 	of Connected	 	 	 	Design	 	Ended	 	Ended	
 	 	 	 	Contract	 	 	 	Wells/Receipt	 	Compression	 	Capacity	 	December 31,	 	March 31,	
 	 	System Type	 	Type(1)	 	Miles	 	Points	 	(Horsepower)	 	(MMcf/d)	 	2010	 	2011	

Gathering & Processing	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gloria	 	Gathering,	 	Fee(5), POP	 	 	110	 	 	 	57	 	 	 	1,877	 	 	 	60	 	 	 	36.6	 	 	 	49.0	 	
 	 	Processing(2)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lafitte	 	Gathering	 	Fee(5)	 	 	40	 	 	 	44	 	 	 	—	 	 	 	71	 	 	 	12.0	 	 	 	19.9	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Bazor Ridge	 	Gathering,	 	Fee, POP	 	 	160	 	 	 	40	 	 	 	6,287	 	 	 	22	 	 	 	9.2	 	 	 	13.6	 	
 	 	Processing	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Quivira	 	Gathering	 	Fee	 	 	34	 	 	 	16	 	 	 	—	 	 	 	140	 	 	 	77.4	 	 	 	113.5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Offshore Texas	 	Gathering	 	Fee(5)	 	 	56	 	 	 	22	 	 	 	—	 	 	 	100	 	 	 	15.3	 	 	 	19.2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other(3)	 	Gathering,	 	Fee(5), POP	 	 	189	 	 	 	445	 	 	 	5,156	 	 	 	153	 	 	 	25.1	 	 	 	27.6	 	
 	 	Processing	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

Gathering & Processing total	 	 	 	 	 	 	589	 	 	 	624	 	 	 	13,320	 	 	 	546	 	 	 	175.6	 	 	 	242.8	 	

Transmission	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Bamagas	 	Intrastate	 	FT	 	 	52	 	 	 	2	 	 	 	—	 	 	 	450	 	 	 	151.5	 	 	 	180.9	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
AlaTenn	 	Interstate	 	FT, IT	 	 	295	 	 	 	4	 	 	 	3,665	 	 	 	200	 	 	 	48.0	 	 	 	66.2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Midla	 	Interstate	 	FT, IT	 	 	370	 	 	 	9	 	 	 	3,600	 	 	 	198	 	 	 	87.2	 	 	 	121.6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
MLGT	 	Intrastate	 	FT, IT(5)	 	 	54	 	 	 	7	 	 	 	—	 	 	 	170	 	 	 	50.5	 	 	 	63.8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other(4)	 	Intrastate	 	FT, IT	 	 	82	 	 	 	6	 	 	 	—	 	 	 	336	 	 	 	13.0	 	 	 	13.4	 	

Transmission total	 	 	 	 	 	 	853	 	 	 	28	 	 	 	7,265	 	 	 	1,354	 	 	 	350.2	 	 	 	445.9	 	

 

			
(1)		In this table, fee refers to fee-based contracts, POP refers to percent-of-proceeds contracts, FT refers to firm transportation contracts and IT refers to interruptible transportation contracts. For a general description of these types of contracts, please see “Industry Overview — Typical Midstream Contractual Arrangements.”	

			
(2)		Although the Gloria system is comprised solely of gathering pipelines, we generate a substantial portion of our Gloria revenue by processing natural gas for our own account at the Toca processing plant in connection with our elective processing arrangements. We do not own the Toca processing plant, but we have the contractual ability to process the natural gas for our own account and retain the majority of the proceeds derived from the sale of the residue natural gas and resulting NGLs. Please see “— Gathering and Processing Segment — Gloria System.”	

			
(3)		Includes our Alabama Processing, Fayette, Magnolia, Stringer and Heidelberg systems.	
 		
(4)		Includes our Trigas, Owens Corning and Chalmette systems.	
 		
(5)		Because we view the segment gross margin earned under our fixed-margin arrangements to be economically equivalent to the fee earned in our fee-based arrangements in our Gathering and Processing segment and the fee earned in our interruptible transportation arrangements in our Transmission segment, we have included the fixed-margin arrangements in those categories.	

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Gathering and Processing Segment
 
General
 
Our Gathering and Processing segment is an integrated midstream natural gas system that provides the following services to our customers:

 	• 	gathering;	
 		
 	• 	compression;	
 		
 	• 	treating;	
 		
 	• 	processing;	
 		
 	• 	transportation; and	
 		
 	• 	sales of natural gas, NGLs and condensate.	
 
For a description of these services, please read “Industry Overview — Midstream Services.”
 
We own one processing plant on our Bazor Ridge system, two on our Alabama Processing system and have the right to contract for processing services for our own account at another, the Toca plant, that is connected to our Gloria system. The Toca plant is owned and operated by Enterprise. Our Bazor Ridge processing plant and the Toca plant are both cryogenic processing plants. These types of processing plants represent the latest generation of processing techniques, using extremely low temperatures and high pressures to optimize the extraction of NGLs from the raw natural gas stream.

We generally derive revenue in our Gathering and Processing segment from fee-based, fixed-margin and POP arrangements, whether for our producer and supplier customers or our own account. We have no keep-whole arrangements with our customers. On our Gloria, Lafitte and Offshore Texas systems, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and subsequently transport that natural gas to delivery points on our systems at which we sell the natural gas at the same undiscounted index price thereby earning a fixed margin on each transaction. We regard the segment gross margin we earn with respect to those purchases and sales a “fixed-margin” and as the economic equivalent of a fee for our transportation service, and as such, we include these transactions in the category of fee-based contractual arrangements. In order to minimize commodity price risk we face in these transactions, we match sales with purchases at the index price on the date of settlement. For the year ended December 31, 2010, our fee-based and fixed-margin arrangements and our POP arrangements accounted for approximately 46.3% and 53.6%, respectively, of our segment gross margin for this segment. For the quarter ended March 31, 2011, our fee-based and fixed-margin arrangements and our POP arrangements accounted for approximately 39.0% and 61.0%, respectively, of our segment gross margin for this segment.

We continually seek new sources of raw natural gas supply to maintain and increase the throughput volume on our gathering systems and through our processing plants. As a result, we connected eleven new supply sources in 2010 to systems in our Gathering and Processing segment, including connections of individual wells, as well as central delivery points and interstate and intrastate pipelines that have multiple wells behind them.
 
Our Gathering and Processing assets are located in Alabama, Louisiana and Mississippi and in shallow state and federal waters in the Gulf of Mexico off the coasts of Louisiana and Texas.
 
Gloria System

The Gloria gathering system provides gathering and compression services through our assets, as well as processing services through our elective processing arrangements. The Gloria system is located in Lafourche, Jefferson, Plaquemines, St. Charles and St. Bernard parishes of Louisiana and consists of approximately 110 miles of pipeline with diameters ranging from three to 16 inches and three compressors with a combined capacity of 1,877 horsepower. The Gloria system has a design capacity of approximately 90 MMcf/d, but is currently limited by compression horsepower at the Gloria Compressor Station to approximately 60 MMcf/d.

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Average throughput on the Gloria system for the year ended December 31, 2010 was 36.6 MMcf/d from approximately 57 connected wells and an interconnect with our Lafitte system. Average throughput on the Gloria system increased to approximately 49.0 MMcf/d for the quarter ended March 31, 2011 due to excess volumes from our Lafitte system, primarily resulting from the completion of a new interconnect between the Lafitte system and TGP, an interstate pipeline owned by El Paso Corporation. For more information about the excess natural gas from our Lafitte system, please read “— Lafitte System.”

 
The Gloria system gathers natural gas from onshore oil and natural gas wells producing from the Gulf Coast region of Louisiana. Production is derived from a variety of reservoirs and ranges from dry natural gas to rich associated natural gas. Well decline rates are variable in this area, but it is common practice for producers to mitigate declines in production with workovers and re-completions of existing wells. An average of four wells per year were connected to the Gloria system over the last three years, with four wells connected during the year ended December 31, 2010. Producers generally bear the cost of connecting their wells to our Gloria system.

Toca Plant and Our Elective Processing Arrangements.   The Toca plant is a cryogenic processing plant with a design capacity of approximately 1.1 Bcf/d that is located in St. Bernard Parish in Louisiana and operated by Enterprise. In conjunction with the acquisition of the Gloria system in November 2009, we assumed a POP processing contract with Enterprise that allows us to process raw natural gas through the Toca plant, whether for our customers or our own account. This contract renews on a month-to-month basis and specifies that Enterprise retains a percentage of the NGLs produced by the Toca plant as payment for processing services. In connection with the completion of the Lafitte/TGP interconnect in November 2010, we entered into an additional contract with Enterprise, that renews on a month-to-month basis, for processing natural gas we purchase at the Lafitte/TGP interconnect. Please read “Risk Factors — Risks Related to Our

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Business — The contracts on which our elective processing arrangements are based are month-to-month, and the loss of these contracts would materially and adversely affect our revenue and gross margin in our Gathering and Processing segment.” Natural gas that is processed at the Toca plant is transported to end users via the Sonat pipeline directly and through various interconnects downstream of the Toca plant. Sonat is the primary pipeline into which Toca volumes are delivered.

 
Our month-to-month contracts with producers on the Gloria and Lafitte systems, as well as our ability to purchase natural gas at the Lafitte/TGP interconnect, provide us with the flexibility to decide whether to process natural gas through the Toca plant and capture processing margins for our own account or deliver the natural gas into the interstate pipeline market at the inlet to the Toca plant, and we make this decision based on the relative prices of natural gas and NGLs on a monthly basis. We refer to the flexibility built into these contracts as our elective processing arrangements. Due to currently strong processing margins, we currently process 100% of the natural gas purchased on the Gloria system, as well as any excess natural gas purchased via the Lafitte/TGP interconnect in excess of the needs of ConocoPhillips at the Alliance Refinery. Based on publicly available information, we believe that the Toca plant has sufficient capacity available to accommodate additional volumes from the Gloria system.

Lafitte System
 
The Lafitte gathering system consists of approximately 40 miles of gathering pipeline, with diameters ranging from four to 12 inches and a design capacity of approximately 71 MMcf/d. The Lafitte system originates onshore in southern Louisiana and terminates in Plaquemines Parish, Louisiana at the Alliance Refinery owned by ConocoPhillips Corporation, or ConocoPhillips. Average throughput on the Lafitte system for the year ended December 31, 2010 and the quarter ended March 31, 2011 was 12.0 MMcf/d and 19.9 MMcf/d, respectively, from approximately 44 connected wells and an interconnect with TGP that was completed in December 2010. We are the sole supplier of natural gas to the Alliance Refinery through our Lafitte and Gloria systems. We supply natural gas to the Alliance Refinery pursuant to a long-term contract that expires in 2023. Any natural gas not used by ConocoPhillips at the Alliance Refinery is delivered to our Gloria system.
 
Like our nearby Gloria system, the Lafitte system gathers natural gas from onshore oil and natural gas wells producing from the Gulf Coast region of Louisiana. An average of three wells per year were connected to the Lafitte system over the last three years, with no wells connected during the year ended December 31, 2010. Producers generally bear the cost of connecting their wells to our Lafitte system.
 
TGP Interconnect.   In December 2010, we completed an interconnect between our Lafitte pipeline and a pipeline on the TGP interstate system. This interconnect provides a redundant source of natural gas supply for the ConocoPhillips Alliance Refinery to the extent that the Lafitte native production is insufficient to supply the needs of the refinery and provides us with increased operational flexibility on our Gloria and Lafitte systems. To the extent that there is excess supply that the refinery does not consume, we purchase those volumes to be sold into Sonat pursuant to a fixed-margin arrangement or to be processed at the Toca processing facility pursuant to elective processing arrangements.
 
Bazor Ridge System
 
The Bazor Ridge gathering and processing system consists of approximately 160 miles of pipeline with diameters ranging from three to eight inches and three compressor stations with a combined compression capacity of 1,069 horsepower. Our Bazor Ridge system is located in Jasper, Clarke, Wayne and Greene Counties of Mississippi. The Bazor Ridge system also contains a cryogenic sour natural gas treating and processing plant located in Wayne County, Mississippi with a design capacity of approximately 22 MMcf/d and four inlet and one discharge compressor with approximately 5,218 of combined horsepower. We upgraded the turbo expander at the Bazor Ridge processing plant in June 2010, which resulted in a significant improvement in the plant’s NGL recoveries and provided us with greater operating flexibility during changing commodity price environments. We have POP arrangements with each of our customers on the Bazor Ridge system that generally also include a fee-based element for gathering and treating services. After processing, the residue natural gas is sold and delivered into the Destin Pipeline system, an interstate pipeline operated by

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Destin Pipeline Company, L.L.C., which has connections with a number of other interstate pipeline systems. We sell the NGLs we recover at the truck rack at the tailgate of the Bazor Ridge processing plant to Dufour Petroleum LP, an affiliate of Enbridge, pursuant to a month-to-month contract. The NGLs are sold on a Mt. Belvieu index-based price. Average throughput on the Bazor Ridge plant for the year ended December 31, 2010 was approximately 9.2 MMcf/d from 40 connected wells. Average throughput increased to approximately 13.6 MMcf/d for the quarter ended March 31, 2011 as a result of the completion of the Winchester lateral, which we describe below, in November 2010.

 
Winchester Lateral.   In 2010, we built a new eight-inch diameter pipeline consisting of approximately nine miles of pipe, called the Winchester lateral, to serve the natural gas wells located in Wayne County, Mississippi owned by Venture Oil & Gas, Inc., or Venture, and other producers. The Winchester lateral allowed us to increase the effective throughput capacity of the Bazor Ridge gathering system by approximately 200% to approximately 25 MMcf/d. In conjunction with the construction of the Winchester lateral, we negotiated a five-year acreage dedication from Venture.
 
The natural gas supply for our Bazor Ridge system is derived primarily from rich associated natural gas produced from oil wells targeting the mature Upper Smackover formation. Production from the wells drilled in this area is generally stable with relatively modest decline rates. An average of one well per year was connected to our Bazor Ridge gathering system over the last three years, with no wells connected during the year ended December 31, 2010 and one well connected during the quarter ended March 31, 2011. Despite the low number of new wells connected, the generally stable production and relatively modest decline rates from this formation allow us to maintain steady throughput on our Bazor Ridge system. Given the recent and current commodity price environment for crude oil, we expect increasing drilling activity and resulting production in this area during 2011.

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Quivira System
 
The Quivira gathering system consists of approximately 34 miles of pipeline, with a 12-inch diameter mainline and several laterals ranging in diameter from six to eight inches. The system originates offshore of Iberia and St. Mary Parishes of Louisiana in Eugene Island Block 24 and terminates onshore in St. Mary Parish, Louisiana at a connection with the Burns Point processing plant, a cryogenic processing plant with a design capacity of 160 MMcf/d that is owned and operated by Enterprise. The Quivira system has a design capacity of approximately 140 MMcf/d. This system also includes an onshore condensate handling facility at Bayou Sale, Louisiana that is upstream of the Burns Point processing plant. Residue natural gas is sold into TGP or the Gulf South Pipeline system, an interstate pipeline owned by Boardwalk Pipeline Partners, LP.
 
The Quivira system is fully subscribed under a firm transportation arrangement through 2012, although a substantial proportion of the revenue is derived from volumetric and fee-based charges. Existing production in our gathering area above our current system capacity is transported on other systems that we believe offer producers less attractive economic alternatives to our customers. Average throughput on the Quivira system for the year ended December 31, 2010 was approximately 77.4 MMcf/d from 16 connected wells. Average throughput increased to approximately 113.5 MMcf/d for the quarter ended March 31, 2011 as a result of additional production added to the system from a new interconnect to a gathering system owned and operated by Contango Oil & Gas Company. We expect that the Quivira system will be operating at capacity for the remainder of 2011 and through 2012.

 
The Quivira system provides gathering services for natural gas wells and associated natural gas produced from crude oil wells operated by major and independent producers targeting multiple conventional production zones in the shallow waters of the Gulf of Mexico. Wells in this area have historically exhibited relatively low

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rates of decline throughout the life of the wells. The natural gas produced from these wells is typically natural gas with condensate. An average of three wells per year were connected to the Quivira system over the last three years, with three wells connected during the year ended December 31, 2010. Producers generally bear the cost of connecting their wells to our Quivira system.
 
Offshore Texas System
 
The Offshore Texas system consists of the GIGS and Brazos systems, two parallel gathering systems that share common geography and operating characteristics. The Offshore Texas system provides gathering and dehydration services to natural gas producers in the shallow waters of the Gulf of Mexico region offshore Texas.

 
The Offshore Texas system consists of approximately 56 miles of pipeline with diameters ranging from six to 16 inches and a design capacity of approximately 100 MMcf/d. Additionally, the Offshore Texas system has two onshore separation and dehydration units, each with a capacity of approximately 40 MMcf/d, that remove water and other impurities from the gathered natural gas before delivering it to our customers. The GIGS system originates offshore of Brazoria County, Texas in Galveston Island Block 343 and connects onshore to the Houston Pipeline system, an intrastate pipeline owned by Energy Transfer Partners, L.P. The Brazos system originates offshore of Brazoria County, Texas in Brazos Block 366 and connects onshore to the Dow Pipeline system, an interstate pipeline owned by Dow Chemical Company. Substantially all of the natural gas gathered on the Brazos system is delivered to Dow Chemical for use in its chemical plant located in Freeport, Texas pursuant to a month-to-month contract. Dow consumes significantly more natural gas than is provided by the Brazos system and we believe Dow may purchase additional volumes from the Brazos system.

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Average throughput on the Offshore Texas system for the year ended December 31, 2010 was 15.3 MMcf/d from approximately 22 connected wells. Average throughput increased to approximately 19.2 MMcf/d for the quarter ended March 31, 2011 as a result of recent recompletion activity on wells connected to the system.
 
All of the wells in this area are natural gas wells producing from the Gulf of Mexico shelf offshore Texas. An average of three wells per year were connected to the Offshore Texas system over the last three years, with no new wells connected during the year ended December 31, 2010. Producers generally bear the cost of connecting their wells to our Texas Offshore system.
 
Other Gathering and Processing Assets
 
Alabama Processing.   The Alabama Processing system consists of two small skid-mounted treating and processing plants that we refer to, individually, as Atmore and Wildfork. These treating and processing plants are located in Escambia and Monroe Counties of Alabama, respectively, and have design capacities of 3 MMcf/d and 7 MMcf/d, respectively. The Atmore and Wildfork plants processed an average of 0.4 MMcf/d and 0.3 MMcf/d of natural gas, respectively, during the year ended December 31, 2010 and an average of 1.3 MMcf/d and 0.2 MMcf/d, respectively, during the quarter ended March 31, 2011.
 
Magnolia System.   The Magnolia gathering system is a Section 311 intrastate pipeline that gathers coalbed methane in Tuscaloosa, Greene, Bibb, Chilton and Hale counties of Alabama and delivers this natural gas to an interconnect with the Transco Pipeline system, an interstate pipeline owned by The Williams Companies, Inc. The Magnolia system consists of approximately 116 miles of pipeline with small-diameter gathering lines and trunklines ranging from six to 24 inches in diameter and one compressor station with 3,328 horsepower. The Magnolia system has a design capacity of approximately 120 MMcf/d. Average throughput on the Magnolia system for the year ended December 31, 2010 and the quarter ended March 31, 2011 was approximately 17.4 MMcf/d and 19.9 MMcf/d, respectively. The Magnolia system is also strategically located in the Floyd shale formation, a currently underdeveloped play that may have significant production potential in a higher natural gas price environment.
 
Our other gathering and processing systems include the Fayette and Heidelberg gathering systems, located in Fayette County, Alabama and Jasper County, Mississippi, respectively. The design capacities for these systems are approximately 5 MMcf/d and approximately 18 MMcf/d, respectively. Average throughput for these systems was approximately 0.5 MMcf/d and approximately 6.5 MMcf/d, respectively, during the year ended December 31, 2010, and approximately 0.5 MMcf/d and approximately 5.7 MMcf/d, respectively, during the quarter ended March 31, 2011. We also own a small Joule Thompson processing skid, called Stringer, that we lease to a producer in Wayne County, Mississippi.
 
Growth Opportunities
 
In our Gathering and Processing segment, we continually seek new sources of raw natural gas supply to increase the throughput volume on our gathering systems and through our processing plants. In addition, we seek to identify and evaluate economically attractive organic expansion and asset acquisition opportunities that leverage our existing asset footprint and strategic relationships with our customers. We also plan to opportunistically pursue strategic and accretive acquisitions within the midstream energy industry that are complementary to our existing asset base or that provide attractive potential returns in new operating regions or business lines. In addition to the projects that we expect to undertake in our forecast period, we are evaluating the following growth opportunities:

 	• 	the addition of compression to the Gloria system to accommodate expected new production from existing customers or increase the volumes purchased via the Lafitte/TGP interconnect, which we expect to increase the current capacity of the Gloria system by approximately 50%, to approximately 90 MMcf/d;	
 		
 	• 	the reconnection of our stranded Montegut lateral to the Gloria system to provide access to areas of existing production that we currently do not serve and potential access to a third-party processing plant,	

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 		which would allow us to connect new wells that would increase the volume of natural gas that we gather on the Gloria system;	

 	• 	the addition of pipeline capacity on the Quivira system through the pursuit of near-system acquisitions and the installation of additional pipe or additional compression capacity; and	
 		
 	• 	the addition of compression capacity to the Wildfork plant on the Alabama Processing system in order to increase plant throughput.	
 
Customers

Substantially all of the natural gas produced on our Lafitte system is sold to ConocoPhillips for use at its Alliance Refinery in Plaquemines Parish, Louisiana under a contract that expires in 2023. On our Bazor Ridge system, we have a POP arrangement with Venture Oil & Gas Co. that contains an acreage dedication under a contract that expires in 2015. We have a weighted-average remaining life of approximately two years on our fee-based contracts in this segment. The weighted-average remaining life on our POP contracts in this segment is approximately three years. For the year ended December 31, 2010, our Gathering and Processing segment derived 34%, 29% and 10% of its revenue from ConocoPhillips, EMUS and Dow Hydrocarbons and Resources, respectively, and 19% and 13% of its segment gross margin from arrangements with Contango Operators Inc. and Venture Oil & Gas Co., respectively. For the quarter ended March 31, 2011, our Gathering and Processing segment derived 59%, 15% and 8% of its revenue from ConocoPhillips, EMUS and Dow Hydrocarbons and Resources, respectively, and 15% and 23% of its segment gross margin from arrangements with Contango Operators Inc. and Venture Oil & Gas Co., respectively.

Transmission Segment
 
General
 
Our Transmission segment is comprised of interstate and intrastate pipelines that transport natural gas from interconnection points on other large pipelines to customers such as LDCs, electric utilities or direct-served industrial complexes, or to interconnects on other pipelines. Certain of our pipelines are subject to regulation by FERC and by state regulators. In this segment, we generally enter into firm transportation contracts with our shipper customers to transport natural gas sourced from large interstate or intrastate pipelines. Our Transmission segment assets are located in multiple parishes in Louisiana and multiple counties in Mississippi, Alabama and Tennessee.
 
In our Transmission segment, we contract with customers to provide firm and interruptible transportation services. In addition, we have a fixed-margin arrangement on our MLGT system whereby we purchase and sell the natural gas that we transport under this arrangement. For a description of the types of contracts that we enter into with the customers in our Transmission segment, please read “Industry Overview — Typical Midstream Contractual Arrangements.”
 
For our Midla and AlaTenn systems, which are interstate natural gas pipelines, the maximum and minimum rates for services are governed by each individual system’s FERC-approved tariff. In some cases, we agree to discount services or in certain cases we enter into negotiated rate agreements that, with FERC approval, can have rates or other terms that are different than those provided for in the FERC tariff. For our Bamagas and MLGT systems, which are intrastate pipelines providing interstate services under the Hinshaw exemption of the NGA, we negotiate service rates with each of our shipper customers.

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The table below sets forth certain information regarding the assets, contracts and revenue for each of the major systems comprising our Transmission segment, as of and for the year ended December 31, 2010:

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	Percent of	 	 	
 	 	Tariff Revenue Composition	 	Design Capacity	 	Weighted	
 	 	Firm Transportation Contracts	 	 	 	Subscribed	 	Average	
 	 	Capacity	 	 	 	Interruptible	 	Under Firm	 	Remaining	
 	 	Reservation	 	Variable Use	 	Transportation	 	Transportation	 	Contract Life	
Asset	 	Charges	 	Charges	 	Contracts	 	Contracts	 	(in Years)	
 		
Bamagas	 	 	100	%	 	 	—	%	 	 	—	%	 	 	44	%	 	 	9	 	
AlaTenn	 	 	78	%	 	 	2	%	 	 	20	%	 	 	26	%	 	 	2	 	
Midla	 	 	83	%	 	 	3	%	 	 	14	%	 	 	100	%(1)	 	 	1	 	
MLGT(2)	 	 	—	%	 	 	—	%	 	 	100	%	 	 	15	%	 	 	1	 	

 

			
(1)		Represents volumes subscribed under firm transportation contracts and design capacity on the mainline of our Midla system.	
 		
(2)		Includes fixed-margin arrangements.	
 
Bamagas System
 
Our Bamagas system is a Hinshaw intrastate natural gas pipeline that travels west to east from an interconnection point with TGP in Colbert County, Alabama to two power plants owned by Calpine Corporation, or Calpine, in Morgan County, Alabama. The Bamagas system consists of 52 miles of high pressure, 30-inch pipeline with a design capacity of approximately 450 MMcf/d.
 
Average throughput on the Bamagas system for the year ended December 31, 2010 and the quarter ended March 31, 2011 was approximately 151.5 MMcf/d and 180.9 MMcf/d, respectively. Currently, 100% of the throughput on this system is contracted under long-term firm transportation agreements. Calpine Corporation is the sole customer on the Bamagas system, with two firm transportation contracts providing for a total of 200 MMcf/d of firm transportation capacity. These contracts, which expire in 2020, ensure steady natural gas supply for the Morgan and Decatur Energy Centers in Morgan County, Alabama. These two natural gas-fired power plants were built in 2002 and 2003 and have a combined capacity of 1,502 megawatts. These generating facilities supply the Tennessee Valley Authority, or the TVA, with electricity under long-term contractual arrangements between Calpine Corporation and the TVA.

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AlaTenn System
 
The AlaTenn system is an interstate natural gas pipeline that interconnects with TGP and travels west to east delivering natural gas to industrial customers in northwestern Alabama, as well as the city gates of Decatur and Huntsville, Alabama. Our AlaTenn system has a design capacity of approximately 200 MMcf/d and is comprised of approximately 295 miles of pipeline with diameters ranging from three to 16 inches and includes two compressor stations with combined capacity of 3,665 horsepower. The AlaTenn system is connected to four receipt and 61 delivery points, including the Tetco Pipeline system, an interstate pipeline owned by Duke Energy Corporation, and the Columbia Gulf Pipeline system, an interstate pipeline owned by NiSource Gas Transmission and Storage. Average throughput on the AlaTenn system for the year ended December 31, 2010 and the quarter ended March 31, 2011 was approximately 48.0 MMcf/d and 66.2 MMcf/d, respectively.
 
Midla System
 
Our Midla system is an interstate natural gas pipeline with approximately 370 miles of pipeline linking the Monroe Natural Gas Field in Northern Louisiana and interconnections with the Transco Pipeline system and Gulf South Pipeline system to customers near Baton Rouge, Louisiana. Our Midla system also has interconnects to Centerpoint, TGP and Sonat along a high-pressure lateral at the north end of the system, called the T-32 lateral.
 
Our Midla system is strategically located near the Perryville Hub, which is a major hub for natural gas produced in the Louisiana and broader Gulf Coast region, including natural gas from the Haynesville shale, Barnett shale, Fayetteville shale, Woodford shale and Deep Bossier formations of Northern Louisiana, Central Texas, Northern Arkansas, Eastern Oklahoma and East Texas, respectively. The Midla system is connected to nine receipt and 19 delivery points. Due to the numerous interstate pipeline connections and growing supply
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and demand dynamics in the surrounding regions, we believe that our location near the Perryville Hub provides us a strategic advantage in securing supplies of natural gas.

 
Natural gas generally flows from north to south on the Midla mainline from interconnections with other interstate pipelines to customers and end users. The Midla system consists of the following components:

 	• 	the northern portion of the system, including the T-32 lateral;	
 		
 	• 	the mainline; and	
 		
 	• 	the southern portion of the system, including interconnections with the MLGT system and other associated laterals.	
 
The northern portion of the system, including the T-32 lateral, consists of approximately four miles of high pressure, 12-inch diameter pipeline. Natural gas on the northern end of the Midla system is delivered to two power plants operated by Entergy by way of the T-32 lateral and the CLECO Sterlington plant by way of the Sterlington lateral. These power plants are peak-load generating facilities that consumed an aggregate average of approximately 23.6 MMcf/d and 27.8 MMcf/d of natural gas for the year ended December 31, 2010 and the quarter ended March 31, 2011, respectively. The T-32 lateral is fully subscribed, with approximately 296 MMcf/d of firm transportation capacity under contracts with an average remaining term of 0.5 years that automatically renew on a year-to-year basis.
 
The mainline of the system has a design capacity of approximately 198 MMcf/d and consists of approximately 170 miles of low pressure, 22-inch diameter pipeline with laterals ranging in diameter from two to 16 inches. This section of the Midla system primarily serves small LDCs under firm transportation contracts that automatically renew on a year-to-year basis. Substantially all of these contracts are at maximum rates allowed under Midla’s FERC tariff. Average throughput on the Midla mainline for the year ended December 31, 2010 and the quarter ended March 31, 2011 was approximately 61.6 MMcf/d and 92.2 MMcf/d, respectively.

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The southern portion of the system, including interconnections with the MLGT system and other associated laterals, consists of approximately two miles of high and low pressure, 12-inch diameter pipeline. This section of the system primarily serves industrial and LDC customers in the Baton Rouge market through contracts with several large marketing companies. In addition, this section includes two small offshore gathering lines, the T-33 lateral in Grand Bay and the T-51 lateral in Eugene Island 28, each of which are approximately five miles in length. Natural gas delivered on the southern end of the system is sold under both firm and interruptible transportation contracts with average remaining terms of two years.
 
MLGT System
 
The MLGT system is an intrastate transmission system that sources natural gas from interconnects with the FGT Pipeline system, an interstate pipeline owned by Florida Gas Transmission Company, the Tetco Pipeline system, the Transco Pipeline system and our Midla system to a Baton Rouge, Louisiana refinery owned and operated by ExxonMobil and five other industrial customers. Our MLGT system has a design capacity of approximately 170 MMcf/d and is comprised of approximately 54 miles of pipeline with diameters ranging from three to 14 inches. The MLGT system is connected to seven receipt and 16 delivery points. Average throughput on the MLGT system for the year ended December 31, 2010 and the quarter ended March 31, 2011 was approximately 50.5 MMcf/d and 63.8 MMcf/d, respectively.
 
Other Systems
 
Our other transmission systems include the Chalmette system, located in St. Bernard Parish, Louisiana, and the Trigas system, located in three counties in northwestern Alabama. The approximate design capacities for the Chalmette and Trigas systems are 125 MMcf/d and 60 MMcf/d, respectively. The approximate average throughput for these systems was 6.0 MMcf/d and 5.9 MMcf/d, respectively, for the year ended December 31, 2010 and 0.5 MMcf/d and 11.9 MMcf/d, respectively, for the quarter ended March 31, 2011. We also have an interconnect in Albany County, New York with an Owens Corning Delmar Facility in respect of which we receive a small monthly payment. Finally, we also own a number of miscellaneous interconnects and small laterals that are collectively referred to as the SIGCO assets.
 
Growth Opportunities
 
In our Transmission segment, we continually seek to increase the throughput volume on our pipelines. We also seek to identify and evaluate economically attractive organic expansion and asset opportunities that leverage our existing asset footprint and strategic relationships with our customers. In addition to the projects that we expect to undertake in our forecast period, we are evaluating the following growth opportunities:

 	• 	the addition of delivery points to the AlaTenn system, which we believe will improve overall system flexibility and allow us to capitalize on possible incremental natural gas demand from various electric utilities on our system who are either in the process of, or are evaluating, switching fuel sources from coal to natural gas; and	
 		
 	• 	the addition of LDC and industrial customers on the AlaTenn system who were commercially underserved by our Predecessor.	
 
Customers
 
In our Transmission segment, we contract with LDCs, electric utilities, or direct-served industrial complexes, or to interconnections on other large pipelines, to provide firm and interruptible transportation services. Among all of our customers in this segment, the weighted-average remaining life of our firm and interruptible transportation contracts are approximately five years and less than one year, respectively. ExxonMobil and Calpine Corporation are the two largest purchasers of natural gas and transmission capacity, respectively, in our Transmission segment and accounted for approximately 43% and 10%, respectively, of our segment revenue for the year ended December 31, 2010 and approximately 50% and 7%, respectively, of our segment revenue for the quarter ended March 31, 2011. In addition, our Transmission segment derived 38%

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and 30% of its gross margin from arrangements with Calpine Corporation for the year ended December 31, 2010 and the quarter ended March 31, 2011, respectively.
 
Competition
 
The natural gas gathering, compression, treating and transportation business is very competitive. Our competitors in our Gathering and Processing segment include other midstream companies, producers, intrastate and interstate pipelines. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies. Our major competitors in this segment include TGP and Gulf South.
 
In our Transmission segment, we compete with other pipelines that service regional markets, specifically in our Baton Rouge market. An increase in competition could result from new pipeline installations or expansions by existing pipelines. Competitive factors include the commercial terms, available capacity, fuel efficiencies, the interconnected pipelines and gas quality issues. Our major competitors for this segment are Southern Natural Gas Company, a subsidiary of El Paso Corporation and Louisiana Intrastate Gas, owned by Crosstex Energy, L.P.
 
Safety and Maintenance

We are subject to regulation by the PHMSA pursuant to the Natural Gas Pipeline Safety Act of 1968, or the NGPSA, and the Pipeline Safety Improvement Act of 2002, or the PSIA, which was recently reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in high-consequence areas. The PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas. New pipeline safety legislation requiring more stringent spill reporting and disclosure obligations has been introduced in the U.S. Congress and was passed by the U.S. House of Representatives in 2010, but was not voted on in the U.S. Senate. Similar legislation has been introduced in the current session of Congress, either independently or in conjunction with the reauthorization of the Pipeline Safety Act. In part as a result of the PG&E gas line explosion in California last year, the Department of Transportation has also recently proposed legislation providing for more stringent oversight of pipelines and increased penalties for violations of safety rules, which is in addition to the PHMSA’s announced intention to strengthen its rules. The PHMSA recently issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. We believe that this rule does not apply to any of our pipelines. While we cannot predict the outcome of other proposed legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations, particularly by extending through more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines not previously subject to such requirements. Additionally, legislative and regulatory changes may also result in higher penalties for the violation of federal pipeline safety regulations. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations. We cannot predict with any certainty at this time the terms of any new laws or rules or the costs of compliance associated with such requirements.

We regularly inspect our pipelines and third parties assist us in interpreting the results of the inspections.
 
States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. These state oil and gas standards may include requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant

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difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.
 
In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the Environmental Protection Agency, or EPA, community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.
 
We and the entities in which we own an interest are also subject to:

 	• 	EPA Chemical Accident Prevention Provisions, also known as the Risk Management Plan requirements, which are designed to prevent the accidental release of toxic, reactive, flammable or explosive materials;	
 		
 	• 	OSHA Process Safety Management Regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive materials; and	
 		
 	• 	Department of Homeland Security Chemical Facility Anti-Terrorism Standards, which are designed to regulate the security of high-risk chemical facilities.	
 
Regulation of Operations
 
Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for our products and services.
 
Interstate Natural Gas Pipeline Regulation
 
Our interstate natural gas transportation systems are subject to the jurisdiction of the FERC under the Natural Gas Act of 1938, or the NGA. Under the NGA, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Federal regulation of our interstate pipelines extends to such matters as:

 	• 	rates, services, and terms and conditions of service;	
 		
 	• 	the types of services offered to customers;	
 		
 	• 	the certification and construction of new facilities;	
 		
 	• 	the acquisition, extension, disposition or abandonment of facilities;	
 		
 	• 	the maintenance of accounts and records;	
 		
 	• 	relationships between affiliated companies involved in certain aspects of the natural gas business;	
 		
 	• 	the initiation and discontinuation of services;	

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 	• 	market manipulation in connection with interstate sales, purchases or transportation of natural gas and NGLs; and	
 		
 	• 	participation by interstate pipelines in cash management arrangements.	
 
Under the NGA, the rates for service on these interstate facilities must be just and reasonable and not unduly discriminatory.
 
The rates and terms and conditions for our interstate pipeline services are set forth in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. Any successful complaint or protest against our rates could have an adverse impact on our revenue associated with providing transportation service.
 
In 2008, FERC issued Order No. 717, a final rule that implements standards of conduct that include three primary rules: (1) the “independent functioning rule,” which requires transmission function and marketing function employees to operate independently of each other; (2) the “no-conduit rule,” which prohibits passing transmission function information to marketing function employees; and (3) the “transparency rule,” which imposes posting requirements to help detect any instances of undue preference. The FERC has since issued three rehearing orders which generally reaffirmed the determinations in Order No. 717 and also clarified certain provisions of the Standards of Conduct. A single rehearing request related to elective issues is currently pending before the FERC.
 
In 2005, the FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass through partnership entity to reflect actual or potential income tax liability on public utility income, if the pipeline proves that the ultimate owner of its interests has an actual or potential income tax liability on such income. The policy statement provided that whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. In August 2005, FERC dismissed requests for rehearing of its new policy statement. In December 2005, the FERC issued its first significant case-specific review of the income tax allowance issue in another pipeline partnership’s rate case. The FERC reaffirmed its income tax allowance policy and directed the subject pipeline to provide certain evidence necessary for the pipeline to determine its income tax allowance. The tax allowance policy and the December 2005 order were appealed to the United States Court of Appeals for the District of Columbia Circuit, or D.C. Circuit. The D.C. Circuit denied these appeals in May 2007 in ExxonMobil Oil Corporation v. FERC and fully upheld the FERC’s new tax allowance policy and the application of that policy in the December 2005 order. In 2007, the D.C. Circuit denied rehearing of its ExxonMobil decision. The ExxonMobil decision, its applicability and the issue of the inclusion of an income tax allowance have been the subject of extensive litigation before the FERC. Whether a pipeline’s owners have actual or potential income tax liability continues to be reviewed by FERC on a case-by-case basis. How the FERC applies ExxonMobil and the policy to pipelines owned by publicly traded partnerships could impose limits on a pipeline’s ability to include a full income tax allowance in its cost of service.
 
In April 2008, the FERC issued a Policy Statement regarding the composition of proxy groups for determining the appropriate return on equity for natural gas and oil pipelines using FERC’s Discounted Cash Flow, or “DCF,” model for setting cost-of-service or recourse rates. The FERC denied rehearing and no petitions for review of the Policy Statement were filed. In the policy statement, FERC concluded, among other matters that MLPs should be included in the proxy group used to determine return on equity for both oil and natural gas pipelines, but the long-term growth component of the DCF model should be limited to fifty percent of long-term gross domestic product. The adjustment to the long-term growth component, and all other things being equal, results in lower returns on equity than would be calculated without the adjustment. However, the actual return on equity for our interstate pipelines will depend on the specific companies included in the proxy group and the specific conditions at the time of the future rate case proceeding. FERC’s policy determinations applicable to MLPs are subject to further modification.

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Section 311 Pipelines
 
Intrastate transportation of natural gas is largely regulated by the state in which such transportation takes place. To the extent that our intrastate natural gas transportation systems transport natural gas in interstate commerce without an exemption under the NGA, the rates, terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act, or NGPA, and Part 284 of the FERC’s regulations. Pipelines providing transportation service under Section 311 are required to provide services on an open and nondiscriminatory basis. The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates, terms and conditions of some transportation services provided on our Section 311 pipeline systems are subject to FERC regulation pursuant to Section 311 of the NGPA. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to the FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.
 
Hinshaw Pipelines
 
Intrastate natural gas pipelines are defined as pipelines that operate entirely within a single state, and generally are not subject to FERC’s jurisdiction under the NGA. Hinshaw pipelines, by definition, also operate within a single state, but can receive gas from outside their state without becoming subject to FERC’s NGA jurisdiction. Specifically, Section 1(c) of the NGA exempts from the FERC’s NGA jurisdiction those pipelines which transport gas in interstate commerce if (1) they receive natural gas at or within the boundary of a state, (2) all the gas is consumed within that state and (3) the pipeline is regulated by a state commission. Following the enactment of the NGPA, the FERC issued Order No. 63 authorizing Hinshaw pipelines to apply for authorization to transport natural gas in interstate commerce in the same manner as intrastate pipelines operating pursuant to Section 311 of the NGPA. Hinshaw pipelines frequently operate pursuant to blanket certificates to provide transportation and sales service under the FERC’s regulations.
 
Historically, FERC did not require intrastate and Hinshaw pipelines to meet the same rigorous transactional reporting guidelines as interstate pipelines. However, as discussed below, last year the FERC issued a new rule, Order No. 735, which increases FERC regulation of certain intrastate and Hinshaw pipelines. See “— Market Behavior Rules; Posting and Reporting Requirements.”
 
Gathering Pipeline Regulation
 
Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. However, some of our natural gas gathering activity is subject to Internet posting requirements imposed by FERC as a result of FERC’s market transparency initiatives. We believe that our natural gas pipelines meet the traditional tests that FERC has used to determine that a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and

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services. Our natural gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
 
Our natural gas gathering operations are subject to ratable take and common purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our system due to these regulations.
 
Market Behavior Rules; Posting and Reporting Requirements
 
On August 8, 2005, Congress enacted the Energy Policy Act of 2005, or the EPAct 2005. Among other matters, the EPAct 2005 amended the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC and, furthermore, provides FERC with additional civil penalty authority. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of the EPAct 2005, and subsequently denied rehearing. The rules make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC or the purchase or sale of transportation services subject to the jurisdiction of FERC to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a “nexus” to jurisdictional transactions. The EPAct 2005 also amends the NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes, up to $1,000,000 per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial penalties and fines.
 
The EPAct of 2005 also added a section 23 to the NGA authorizing the FERC to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. In 2007, FERC took steps to enhance its market oversight and monitoring of the natural gas industry by issuing several rulemaking orders designed to promote gas price transparency and to prevent market manipulation. In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Order No. 704 requires buyers and sellers of annual quantities of natural gas of 2,200,000 MMBtu or more, including entities not otherwise subject to FERC jurisdiction, to submit on May 1 of each year an annual report to FERC describing their aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions

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utilize, contribute to or may contribute to the formation of price indices. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. In June 2010, the FERC issued the last of its three orders on rehearing and clarification further clarifying its requirements.
 
In 2008, the FERC issued Order No. 720 which increases the Internet posting obligations of interstate pipelines, and also requires “major non-interstate” pipelines (defined as pipelines that are not natural gas companies under the NGA that deliver more than 50 million MMBtu annually) to post on the Internet the daily volumes scheduled for each receipt and delivery point on their systems with a design capacity of 15,000 MMBtu per day or greater. Numerous parties requested modification or reconsideration of this rule. An order on rehearing, Order No. 720-A, was issued on January 21, 2010. In that order the FERC reaffirmed its holding that it has jurisdiction over major non-interstate pipelines for the purpose of requiring public disclosure of information to enhance market transparency. Order No. 720-A also granted clarification regarding application of the rule. Two parties have filed appeals of Order Nos. 720 and 720-A to the Fifth Circuit. The parties have filed briefs but no decision has been issued.
 
In May 2010, the FERC issued Order No. 735, which requires intrastate pipelines providing transportation services under Section 311 of the NGPA and Hinshaw pipelines operating under Section 1(c) of the NGA to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 further requires that such information must be supplied through a new electronic reporting system and will be posted on FERC’s website, and that such quarterly reports may not contain information redacted as privileged. The FERC promulgated this rule after determining that such transactional information would help shippers make more informed purchasing decisions and would improve the ability of both shippers and the FERC to monitor actual transactions for evidence of market power or undue discrimination. Order No. 735 also extends the Commission’s periodic review of the rates charged by the subject pipelines from three years to five years. Order No. 735 becomes effective on April 1, 2011. In December 2010, the Commission issued Order No. 735-A. In Order No. 735-A, the Commission generally reaffirmed Order No. 735 requiring section 311 and “Hinshaw” pipelines to report on a quarterly basis storage and transportation transactions containing specific information for each transaction, aggregated by contract.
 
In July 2010, for the first time the FERC issued an order finding that the prohibition against buy/sell arrangements applies to interstate open access services provided by Section 311 and Hinshaw pipelines. The FERC denied numerous requests for rehearing and motions for late interventions that were filed in response to the July order. However, in October 2010, the FERC issued a Notice of Inquiry seeking public comment on the issue of whether and how parties that hold firm capacity on some intrastate pipelines can allow others to use their capacity, including to what extent buy/sell transactions should permitted and whether the FERC should consider requiring such pipelines to offer capacity release programs. In the Notice of Inquiry, the FERC granted a blanket waiver regarding such transactions while the FERC is considering these policy issues. The comment period has ended but the FERC has not yet issued an order.
 
Offshore Natural Gas Pipelines
 
Our offshore natural gas gathering pipelines are subject to federal regulation under the Outer Continental Shelf Lands Act, which requires that all pipelines operating on or across the outer continental shelf provide open and nondiscriminatory access to shippers. From 1982 until 2010, the Minerals Management Service, or MMS, of the U.S. Department of the Interior, or DOI, was the federal agency that managed the nation’s oil, natural gas, and other mineral resources on the outer continental shelf, which is all submerged lands lying seaward of state coastal waters which are under U.S. jurisdiction, and collected, accounted for, and disbursed revenues from federal offshore mineral leases. On June 18, 2010, the Minerals Management Service was renamed the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE. The BOEMRE currently regulates offshore operations, including engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the outer continental shelf, and

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removal of facilities. On January 19, 2011, the U.S. Department of the Interior announced the structures and responsibilities of the two remaining agencies, with the reorganization of BOEMRE into these agencies to be completed by October 1, 2011. Once the reorganization is complete, the BOEMRE will cease to exist. At this time, we cannot predict the impact that this reorganization, or future regulations or enforcement actions taken by the new agencies, may have on our operations.
 
Sales of Natural Gas and NGLs
 
Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the NGA, the NGPA, and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.
 
The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission, or the CFTC, and the Federal Trade Commission, or FTC. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
 
Sales of NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could enact price controls in the future.
 
As discussed above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting interstate natural gas pipelines and those initiatives may also affect the intrastate transportation of natural gas both directly and indirectly.
 
Environmental Matters
 
General
 
Our operation of pipelines, plants and other facilities for the gathering, compressing, treating and transporting of natural gas and other products is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

 	• 	requiring the installation of pollution-control equipment or otherwise restricting the way we operate;	
 		
 	• 	limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;	
 		
 	• 	delaying system modification or upgrades during permit reviews;	
 		
 	• 	requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and	
 		
 	• 	enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to such environmental laws and regulations.	
 
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage

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allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
 
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.
 
We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, compress, treat and transport natural gas. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.
 
Hazardous Substances and Waste
 
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
 
We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. We generate little hazardous waste; however, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.
 
We currently own or lease, and our Predecessor has in the past owned or leased, properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

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Oil Pollution Act
 
In January of 1974, the EPA adopted regulations under the OPA. These oil pollution prevention regulations require the preparation of a Spill Prevention Control and Countermeasure Plan or SPCC for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility’s operations comply with the requirements. To be in compliance, the facility’s SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. We believe that our facilities will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.
 
Air Emissions
 
Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations and processing plants, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we are in substantial compliance with these requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.
 
Water Discharges
 
The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the U.S. and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition, results of operations or cash flow.
 
Safe Drinking Water Act
 
The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We own and operate an acid gas disposal

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well in Wayne County, Mississippi as part of our Bazor Ridge gas treating facilities. This well takes a combination of hydrogen sulfide and carbon dioxide recovered from the raw field natural gas feeding the Bazor Ridge Gas plant and injects it into an underground formation permitted for this purpose. The well received an Underground Injection Control (UIC) Class 2 permit through the Mississippi state oil and gas board in 1999. As part of our permit requirements, we perform regular inspection, maintenance and reporting to the state on the condition and operations of this well which is adjacent to our processing plant. We believe that our facilities will not be materially adversely affected by such requirements.
 
Endangered Species
 
The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.
 
National Environmental Policy Act
 
The National Environmental Policy Act, or NEPA, establishes a national environmental policy and goals for the protection, maintenance, and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC approval must undergo NEPA review. Many of our activities are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention to reinvigorate NEPA reviews which may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.
 
Climate Change
 
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to the scientific studies, international negotiations to address climate change have occurred. The United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” became effective on February 16, 2005 as a result of these negotiations, but the United States did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17 percent compared to 2005 levels. We continue to monitor the international efforts to address climate change. Their effect on our operations cannot be determined with any certainty at this time.
 
In the U.S., legislative and regulatory initiatives are underway to limit GHG emissions. The U.S. Congress has considered legislation that would control GHG emissions through a “cap and trade” program and several states have already implemented programs to reduce GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act, or the CAA, definition of an “air pollutant,” and in response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. In 2010, the EPA issued a final rule, known as the “Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act.
 
In addition, on September 2009, the EPA issued a final rule requiring the reporting of GHGs from specified large GHG emission sources in the U.S. beginning in 2011 for emissions in 2010. Our Bazor Ridge facility is currently required to report under this rule beginning in 2011. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting to include onshore and offshore oil and natural gas systems beginning in 2012. Three of our onshore compression facilities will likely be required to report under this rule, with the first report due to the EPA on March 31, 2012.

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Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. In addition to these regulatory developments, recent judicial decisions have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase our litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.
 
Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources such as coal, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. To the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.
 
The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. Due to their location, our operations along the Gulf Coast are vulnerable to operational and structural damages resulting from hurricanes and other severe weather systems and our insurance may not cover all associated losses. We are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.
 
Anti-terrorism Measures
 
The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information. Three of our facilities have more than the threshold quantity of listed chemicals; therefore, a “Top Screen” evaluation was submitted to the DHS. The DHS reviewed this information and made the determination that none of the facilities are considered high-risk chemical facilities.
 
Title to Properties and Rights-of-Way
 
Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. Our Predecessors leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership in such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.

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Employees
 
We do not have any employees. The officers of our general partner will manage our operations and activities. As of December 31, 2010, our general partner employed approximately 76 people who will provide direct, full-time support to our operations. All of the employees required to conduct and support our operations will be employed by our general partner. None of these employees are covered by collective bargaining agreements, and our general partner considers its employee relations to be good.
 
Legal Proceedings
 
We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Please read “— Regulation of Operations — Interstate Transportation Pipeline Regulation” and “— Environmental Matters.”

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MANAGEMENT
 
We are managed by the directors and executive officers of our general partner, American Midstream GP. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. AIM Midstream Holdings owns all of the membership interests in our general partner. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or directly or indirectly participate in our management or operations. AIM, Eagle River Ventures, LLC, Stockwell Fund II, L.P. and certain of our executive officers own all of the membership interests in AIM Midstream Holdings. In addition, Messrs. Hellman, Carbone and Diffendal serve on the board of directors of our general partner and are principals of and have ownership interests in AIM. Our general partner owes certain fiduciary duties to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Our partnership agreement provides for the conflicts committee of the board of directors of our general partner, or the Conflicts Committee, as delegated by the board of directors of our general partner as circumstances warrant, to review conflicts of interest between us and our general partner or between us and affiliates of our general partner. If a matter is submitted to the Conflicts Committee, which will consist solely of independent directors, for their review and approval, the Conflicts Committee will determine if the resolution of a conflict of interest that has been presented to it by the board of directors of our general partner is fair and reasonable to us. The members of the Conflicts Committee may not be executive officers or employees of our general partner or directors, executive officers or employees of its affiliates. In addition, the members of the Conflicts Committee must meet the independence and experience standards established by the NYSE and the Exchange Act for service on an audit committee of a board of directors. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. In addition, the board of directors of our general partner will have an audit committee, or the Audit Committee, that complies with the NYSE requirements, and a compensation committee of the board of directors, or the Compensation Committee.

 
Even though most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of its general partner.

 
L. Kent Moore, Matthew P. Carbone, David L. Page, Edward O. Diffendal and Gerald A. Tywoniuk will serve as the initial members of the Audit Committee. Mr. Tywoniuk serves as the chairman of the Audit Committee. In compliance with the rules of the NYSE, the members of the board of directors will appoint two additional independent members to the board of directors, one within 90 days of this offering and a second within twelve months of this offering. Messrs. Carbone and Page will resign from the Audit Committee upon appointment of the first such additional independent director to the board of directors and the Audit Committee. Mr. Diffendal will resign from the Audit Committee when the final independent director is appointed. Thereafter, our general partner is generally required to have at least three independent directors serving on its board at all times.

 
Robert B. Hellman, Jr. and L. Kent Moore serve as the members of the Compensation Committee. Robert B. Hellman, Jr. serves as the chairman of the Compensation Committee.

 
Robert B. Hellman, Jr. and Matthew P. Carbone serve as the members of the Compliance Committee. Robert B. Hellman, Jr. serves as the chairman of the Compliance Committee.

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Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board. The following table shows information for the directors and executive officers of our general partner.

 	 	 	 	 	 	 	
Name	 	Age	 	Position with American Midstream GP, LLC	
 		
Robert B. Hellman, Jr.	 	 	53	 	 	Chairman of the Board	
Brian F. Bierbach	 	 	53	 	 	Director, President and Chief Executive Officer	
Sandra M. Flower	 	 	51	 	 	Vice President of Finance	
John J. Connor II	 	 	54	 	 	Senior Vice President of Operations and Engineering	
Marty W. Patterson	 	 	52	 	 	Senior Vice President of Commercial Services	
William B. Mathews	 	 	59	 	 	Secretary, General Counsel and Vice President of Legal Affairs	
Matthew P. Carbone	 	 	45	 	 	Director	
Edward O. Diffendal	 	 	41	 	 	Director	
David L. Page	 	 	76	 	 	Director	
L. Kent Moore	 	 	55	 	 	Director	
Gerald A. Tywoniuk	 	 	49	 	 	Director	

 
Robert B. Hellman, Jr. was elected Chairman of the board of directors of our general partner in November 2009. Mr. Hellman has been a Managing Director of AIM since he co-founded AIM in July of 2006. Prior to co-founding AIM, Mr. Hellman was a Managing Director of McCown De Leeuw & Co., a private equity firm based in Foster City, California since 1986. Mr. Hellman is also chairman of the Board of Directors of Stonemor Partners L.P. Mr. Hellman received an MBA from Harvard University, an M.A. in Economics from the London School of Economics and a B.A. in Economics from Stanford University.

Brian F. Bierbach was appointed President and Chief Executive Officer, and elected as a member of the board of directors of our general partner in November 2009. Prior to our formation, Mr. Bierbach served as President and as a member of the board of directors of Foothills Energy Ventures, LLC, a private midstream natural gas asset development and operating company, from 2006 to 2009. Mr. Bierbach has also served as President of Cinergy Canada, Inc. from 2003 to 2005 and President of Bear Paw Energy, LLC, a subsidiary of Northern Border Partners, L.P., from 2000 to 2002. He also held various positions with Enron Corporation, The Williams Companies, Inc., Apache Corporation and ConocoPhillips. He received a B.S. in Civil Engineering from the University of Arizona.
 
Sandra M. Flower has served as Vice President of Finance of our general partner since November 2009. Ms. Flower also served as our Controller from November 2009 until March 2011. Prior to our formation, Ms. Flower served as Group Controller at TransMontaigne, Inc. and as Director of Internal Audit for TransMontaigne Partners, LP from 2005 to 2009. While at TransMontaigne, she was responsible for trading support, credit, accounting and consolidation activities of TransMontaigne Inc., as well as supervising the design and implementation of all internal audit activities including Sarbanes-Oxley compliance procedures. Ms. Flower began her career at Touche Ross & Co. She received a B.S.B.A. from the University of Rhode Island and is a CPA.
 
John J. Connor II has served as Senior Vice President of Operations and Engineering of our general partner since November 2009. Prior to our formation, Mr. Connor served as Vice President of Development at Foothills Energy Ventures, LLC. Prior to Foothills, he was Director of Midstream Operations at Black Hills Midstream, LLC from 2006 to 2007 and held various Director and General Manager positions at El Paso Corporation from 1980 to 2004. Mr. Connor received his B.S. in Civil Engineering from Colorado State University and is a licensed professional engineer.
 
Marty W. Patterson has served as Senior Vice President of Commercial Services of our general partner since November 2009. Prior to our formation, he served as Vice President of Commercial Operations at Foothills Energy Ventures, LLC from 2006 to 2009. Prior to joining Foothills, Mr. Patterson was the Director of Commercial Operations with Cinergy Corp. from 2004 to 2006. Before that, he was the Senior VP Energy Services, IDACORP Energy, L.P. from 1997 to 2003, and held various other positions, focused on operations.

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Mr. Patterson received his degree in Petroleum Technology from Kilgore College and is currently a board member of the North American Energy Standards Board.
 
William B. Mathews has served as Secretary and Vice President of Legal Affairs of our general partner since November 2009 and General Counsel of our general partner since March 2011. Prior to our formation, he served as Vice President, General Counsel and Secretary of Foothills Energy Ventures, LLC from December 2006 to November 2009, as well as a director from August 2009 to November 2009. Prior to Foothills, Mr. Mathews served as Assistant General Counsel for ONEOK Partners, L.P., Northern Border Partners, L.P. and Bear Paw Energy, LLC from July 2001 to December 2006 and, previous to that, as Vice President and General Counsel of Duke Energy Field Services (now DCP Midstream, LLC) until 2000, having joined a predecessor company in 1985. He received a J.D. from the University of Denver and a B.S. in Civil Engineering from the University of Colorado.
 
Matthew P. Carbone was elected as a member of the board of directors of our general partner in November 2009. Mr. Carbone has been a Managing Director of AIM since he co-founded AIM in July 2006. Prior to co-founding AIM, from January 2005 until July 2006, Mr. Carbone was a Managing Director of McCown De Leeuw & Co., or MDC. Mr. Carbone has spent nearly 20 years in private equity and investment banking. Prior to MDC he led Wit Capital Group’s West Coast operations and worked in the investment banking divisions of Morgan Stanley, First Boston Corporation and Smith Barney. Mr. Carbone is also a member of the board of directors of the general partner of Oxford Resource Partners L.P. He received an MBA from Harvard Business School and a B.A. in Neuroscience from Amherst College.
 
Edward O. Diffendal was elected as a member of the board of directors of our general partner in November 2009. Mr. Diffendal has been a Principal with AIM since September 2007. Prior to joining AIM he served as a management consultant from 2005 to 2007, held various operating positions at Veritas Software Corp. from 2003 to 2005, was a Vice President at Broadview Capital Partners, L.P. from 2000 to 2003 and was a consultant at Monitor Company from 1991 to 1998. Mr. Diffendal received an MBA from Dartmouth College and M.A. and B.A. degrees in Economics from Stanford University.
 
David L. Page was elected as a member of the board of directors of our general partner in February 2010. Mr. Page also serves as Chairman of the Executive Committee and a member of the Audit Committee of our General Partner. Mr. Page has served as a management consultant since February 2002. Prior to working as a management consultant, Mr. Page served as Chairman and Chief Executive Officer of Distribution Dynamics, Inc. from January 2000 until February 2002. His earlier career included a variety of management roles at McCown De Leeuw & Co. from 1994 through 2000. Prior to joining McCown De Leeuw & Co., Mr. Page was President and Chief Executive Officer of Page Packaging Corporation from 1987 through 1993, and Vice President and General Manager of Boise Cascade Corporation from 1959 through 1987. Mr. Page received a B.A. in Business Administration and Economics from Whitman College and completed the Executive Program at Stanford University.

L. Kent Moore was elected as a member of the board of directors of our general partner in November 2009. Mr. Moore owns Eagle River Ventures, LLC, which holds mostly oil and gas investments and a 0.5% interest in AIM Midstream Holdings. From 2006 through 2011, Mr. Moore served as chairman of the board of directors of Foothills Energy Ventures, LLC. He also serves as chairman of the board of trustees for the Old Mutual Funds I and II, and also a trustee of the TS&W/Claymore Long Short Fund. He has also served as a portfolio manager and vice-president at Janus Capital, and as analyst/portfolio manager for Marsico Capital Management, focusing on technology and energy stocks. Before working in the mutual fund industry, Mr. Moore was a vice-president with Exeter Drilling Company and also co-founded and was President of Caza Drilling Company. Mr. Moore received a B.S. in Industrial Management from Purdue University.

 
Gerald A. Tywoniuk was elected as a member of the board of directors of our general partner in May 2011. Mr. Tywoniuk also serves as Chairman of the Audit Committee of our general partner. With respect to the Audit Committee, he also qualifies as an “audit committee financial expert.” Mr. Tywoniuk has nearly 30 years of management, finance and accounting experience and has held various positions in public energy master limited partnerships. Mr. Tywoniuk serves as a director of the general partner of Oxford Resource

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Partners, LP. Mr. Tywoniuk has served as interim Senior Vice President, Finance of CIBER, Inc., a global information technology services company, since May 2010. Prior to CIBER, he held various management and finance roles, including acting Chief Executive Officer and Chief Financial Officer, of Pacific Energy Resources Ltd. from 2008 to 2010, was Senior Vice President and Chief Financial Officer of Pacific Energy Partners, LP., where he assisted with the integration of the company after it was acquired by Plains All American Pipeline, L.P., from 2002 to 2006 and was Senior Vice President, Chief Financial Officer and a member of the board of directors of the general partner of MarkWest Energy Partners, L.P. and MarkWest Hydrocarbon, Inc. from 1997 to 2002. Mr. Tywoniuk received a B.Comm from the University of Alberta and is a Canadian chartered accountant.

Compensation Discussion and Analysis
 
Our general partner, under the direction of its board of directors, or the Board, is responsible for managing our operations and employs all of the employees that operate our business. The compensation payable to the officers of our general partner is paid by our general partner and such payments are reimbursed by us on a dollar-for-dollar basis. See “The Partnership Agreement — Reimbursement of Expenses.”
 
The following is a discussion of the compensation policies and decisions of the Compensation Committee of the Board, with respect to the following individuals, who are executive officers of our general partner and referred to as the “named executive officers” for the fiscal year ended December 31, 2010:

 	• 	Brian F. Bierbach, President and Chief Executive Officer;	
 		
 	• 	Sandra M. Flower, Vice President of Finance;	

			
 	• 	John J. Connor II, Senior Vice President of Operations and Engineering;	

			
 	• 	Marty W. Patterson, Senior Vice President of Commercial Services; and	
 		
 	• 	William B. Mathews, Secretary, General Counsel and Vice President of Legal Affairs.	
 
Our compensation program is designed to recruit and retain as executive officers individuals with the highest capacity to develop, grow and manage our business, and to align their compensation with our short-term and long-term goals. To do this, our compensation program for executive officers is made up of the following main components: (i) base salary, designed to compensate our executive officers for work performed during the fiscal year; (ii) short-term incentive programs, designed to reward our executive officers for our yearly performance and for their individual performances during the fiscal year; and (iii) equity-based awards, meant to align our executive officers’ interests with our long-term performance. Going forward, we expect that the Compensation Committee will continue to focus on these same components, although the Compensation Committee may consider whether changes to the types of compensation provided may be appropriate in order to more accurately reflect a compensation program appropriate for a publicly-traded entity.
 
This section should be read together with the compensation tables that follow, which disclose the compensation awarded to, earned by or paid to the named executive officers with respect to the year ended December 31, 2010.
 
Role of the Board, the Compensation Committee and Management
 
The Board has appointed the Compensation Committee to assist the Board in discharging its responsibilities relating to compensation matters, including matters relating to compensation programs for directors and executive officers of the general partner. The Compensation Committee has overall responsibility for evaluating and approving our compensation plans, policies and programs, setting the compensation and benefits of executive officers, and granting awards under and administering our equity compensation plans. The Compensation Committee is charged with, among other things, establishing compensation practices and programs that are (i) designed to attract, retain and motivate exceptional leaders, (ii) structured to align compensation with our overall performance and growth in distributions to unitholders, (iii) implemented to promote achievement of short-term and long-term business objectives consistent with our strategic plans, and (iv) applied to reward performance.

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As described in further detail below under “— Elements of the Compensation Programs,” the compensation programs for our executive officers consist of base salaries, annual incentive bonuses and awards under the American Midstream GP, LLC Long-Term Incentive Plan, which we refer to as our LTIP, currently in the form of equity-based phantom units, as well as other customary employment benefits such as a 401(k) plan and health and welfare benefits. We expect that, following the completion of this offering, total compensation of our executive officers and the components and allocation among components of their annual compensation will be reviewed on at least an annual basis by the Compensation Committee.
 
During 2010 and 2011, the Compensation Committee discussed executive compensation issues at several meetings, and the Compensation Committee expects to hold additional executive compensation-related meetings in 2011 and in future years. Topics discussed and to be discussed at these meetings included and will include, among other things, (i) assessing the performance of the Chief Executive Officer, or the CEO, and other executive officers with respect to our results for the prior year, (ii) reviewing and assessing the personal performance of the executive officers for the preceding year and (iii) determining the amount of the bonus pool to be paid to our executive officers for a given year after taking into account the target bonus amounts established for those executive officers at the outset of the year. In addition, at these meetings, and after taking into account the recommendations of our CEO only with respect to executive officers other than our CEO, base salary levels and target bonus amounts (representing the bonus that may be awarded expressed as a dollar amount or as a percentage of base salary for the year) for all of our executive officers will be established by the Compensation Committee. In addition, the Compensation Committee will make its decisions with respect to any awards under the LTIP. We expect that our CEO will provide periodic recommendations to the Compensation Committee regarding the performance and compensation of the other named executive officers.
 
Compensation Objectives and Methodology
 
The principal objective of our executive compensation program is to attract and retain individuals of demonstrated competence, experience and leadership who share our business aspirations, values, ethics and culture. A further objective is to provide incentives to and reward our executive officers and other key employees for positive contributions to our business and operations, and to align their interests with our unitholders’ interests.
 
In setting our compensation programs, we consider the following objectives:

 	• 	to create unitholder value through sustainable earnings and cash available for distribution;	
 		
 	• 	to provide a significant percentage of total compensation that is “at-risk” or variable;	
 		
 	• 	to encourage significant equity holdings to align the interests of executive officers and other key employees with those of unitholders;	
 		
 	• 	to provide competitive, performance-based compensation programs that allow us to attract and retain superior talent; and	
 		
 	• 	to develop a strong linkage between business performance, safety, environmental stewardship, cooperation and executive compensation.	
 
Taking account of the foregoing objectives, we structure total compensation for our executives to provide a guaranteed amount of cash compensation in the form of competitive base salaries, while also providing a meaningful amount of annual cash compensation that is at risk and dependent on our performance and individual performances of the executives, in the form of discretionary annual bonuses. We also seek to provide a portion of total compensation in the form of equity-based awards under our LTIP, in order to align the interests of executives and other key employees with those of our unitholders and for retention purposes. Historically, we have not made regular annual grants of awards under our LTIP. To date, the only awards under our LTIP were made in connection with our formation, although certain of these grants were made in 2010. Going forward, we expect that equity-based awards will be made more regularly and that equity-based awards will become more prominent in our annual compensation decision-making process.

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Compensation decisions for individual executive officers are the result of the subjective analysis of a number of factors, including the individual executive officer’s experience, skills or tenure with us and changes to the individual executive officer’s position. In evaluating the contributions of executive officers and our performance, although no pre-determined numerical goals were established, a variety of financial measures have been generally considered, including non-GAAP financial measures used by management to assess our financial performance, such as adjusted EBITDA and cash available for distribution. For a definition of adjusted EBITDA, please read “Selected Historical Consolidated Financial and Operating Data.” For a discussion of the general concept of “cash available for distribution,” please read “Our Cash Distribution Policy and Restrictions on Distributions.” In addition, a variety of factors related to the individual performance of the executive officer were taken into consideration.
 
In making individual compensation decisions, the Compensation Committee historically has not relied on pre-determined performance goals or targets. Instead, determinations regarding compensation have been the result of the exercise of judgment based on all reasonably available information and, to that extent, were discretionary. Each executive officer’s current and prior compensation is considered in setting future compensation. The amount of each executive officer’s current compensation will be considered as a base against which determinations are made as to whether increases are appropriate to retain the executive officer in light of competition or in order to provide continuing performance incentives. Subject to the provisions contained in the executive officer’s employment agreement, if any, the Compensation Committee has discretion to adjust any of the components of compensation to achieve our goal of recruiting, promoting and retaining as executive officers, individuals with the skills necessary to execute our business strategy and develop, grow and manage our business.
 
To date, we have not reviewed executive compensation against a specific group of comparable companies or publicly traded partnerships. Rather, the Compensation Committee has historically relied upon the judgment and industry experience of its members in making decisions with respect to total compensation and with respect to the allocation of total compensation among our three main components of compensation. Going forward, we expect that the Compensation Committee will make compensation decisions taking into account trends occurring within our industry, including from a peer group of companies, which we expect will include the following similar publicly traded partnerships: Boardwalk Pipeline Partners, LP, Regency Energy Partners LP, Targa Resources Partners LP, MarkWest Energy Partners LP, Copano Energy LLC, Crosstex Energy LP, and Atlas Pipeline Partners LP. Additionally, we expect that the Compensation Committee will take into account trends occurring within a group of publicly traded energy companies with market capitalizations in the same range as our own, including from a peer group of companies, which we expect will include the following similar publicly-traded energy companies: Contango Oil & Gas Co., Goodrich Petroleum Corp., Kodiak Oil & Gas Corp., Magnum Hunter Resources Corp., Penn Virginia Corp., Resolute Energy Corporation, Approach Resources, Inc., PetroQuest Energy Inc. and Rex Energy Corporation. To date, the Compensation Committee has not retained the services of any compensation consultants.
 
Elements of the Compensation Programs
 
Overall, the executive officer compensation programs are designed to be consistent with the philosophy and objectives set forth above. The principal elements of our executive officer compensation programs are summarized in the table below, followed by a more detailed discussion of each compensation element.

Element	 	Characteristics	 	Purpose	
 		
Base Salaries	 	Fixed annual cash compensation. Executive officers are eligible for periodic increases in base salaries. Increases may be based on performance or such other factors as the Compensation Committee may determine.	 	Keep our annual compensation competitive with the defined market for skills and experience necessary to execute our business strategy.	

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Element	 	Characteristics	 	Purpose	
 		
Annual Incentive Bonuses	 	Performance-related annual cash incentives earned based on our objectives and individual performance of the executive officers. We expect that trends for our peer group will be taken into account in setting future annual cash incentive awards for our executive officers.	 	Align performance to our objectives that drive our business and reward executive officers for our yearly performance and for their individual performances during the fiscal year.	
Equity-Based Awards (Phantom-units and Distribution Equivalent Rights)	 	Performance-related, equity-based awards granted at the discretion of the Compensation Committee. Awards are based on our performance and we expect that, going forward, will take into account competitive practices at peer companies. Grants typically consist of phantom units that vest ratably over four years and may be settled upon vesting with either a net cash payment or an issuance of common units, at the discretion of the Board. Historically, the Board has issued common units upon vesting of phantom units. Distribution Equivalent Rights, or DERs, which have been granted in conjunction with such phantom unit awards, entitle the grantee to receive cash distributions on unvested LTIP awards to the same extent generally as unitholders receive cash distributions on our common units.	 	Align interests of executive officers with unitholders and motivate and reward executive officers to increase unitholder value over the long term. Ratable vesting over a four-year period is designed to facilitate retention of executive officers. Issuance of common units upon vesting encourages equity ownership in order to align interests of executive officers with those of unitholders. DERs provide a clear, objective link between growing distributions to unitholders and executive compensation. (1)	
Retirement Plan	 	Qualified retirement plan benefits are available for our executive officers and all other regular full-time employees. At our formation, we adopted and are maintaining a tax-deferred or after-tax 401(k) plan in which all eligible employees can elect to defer compensation for retirement up to IRS imposed limits. The 401(k) plan permits us to make annual discretionary matching contributions to the plan. For 2010, we matched employee contributions to 401(k) plan accounts up to a maximum employer contribution of 6% of the employee’s eligible compensation.	 	Provide our executive officers and other employees with the opportunity to save for their future retirement.	
Health and Welfare Benefits	 	Health and welfare benefits (medical, dental, vision, disability insurance and life insurance) are available for our executive officers and all other regular full-time employees.	 	Provide benefits to meet the health and wellness needs of our executive officers and other employees and their families.	

 
			
(1)		While we have made grants of DERs in the past, we expect to modify those grants to remove, prior to the closing of this offering, the DERs previously granted for an aggregate payment of approximately $2.0 million, based on an assumed price of $20.00 per common unit in this offering. In addition, we do not expect to use grants of DERs as an element of our compensation programs in the future.	

Base Salaries
 
Base salaries for our executive officers will be determined annually by an assessment of our overall financial and operating performance, each executive officer’s performance evaluation and changes in executive officer responsibilities. While many aspects of performance can be measured in financial terms, senior management will also be evaluated in areas of performance that are more subjective. These areas include the
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development and execution of strategic plans, the exercise of leadership in the development of management and other employees, innovation and improvement in our business activities and each executive officer’s involvement in industry groups and in the communities that we serve. We seek to compensate executive officers for their performance throughout the year with annual base salaries that are fair and competitive within our marketplace. We believe that executive officer base salaries should be competitive with salaries for executive officers in similar positions and with similar responsibilities in our marketplace and adjusted for financial and operating performance and each executive officer’s performance evaluation, length of service with us and previous work experience. Individual salaries have historically been established by the Compensation Committee based on the general industry knowledge and experience of its members, in alignment with these considerations, to ensure the attraction, development and retention of superior talent. Going forward, we expect that determinations will continue to focus on the above considerations and will also take into account relevant market data, including data from our peer group.
 
We expect that base salaries will be reviewed annually to ensure continuing consistency with market levels and our level of financial performance during the previous year. Future adjustments to base salaries and salary ranges will reflect movement in the competitive market as well as individual performance. Annual base salary adjustments, if any, for the CEO will be determined by the Compensation Committee. Annual base salary adjustments, if any, for the other executive officers will be determined by the Compensation Committee, taking into account input from the CEO.

On June 9, 2011, we entered into new employment agreements with each of our named executive officers, which agreements will be effective upon the completion of our initial public offering. In connection with approving the new employment agreements, the Compensation Committee approved base salary increases for 2011 for the named executive officers as provided in the table below. The new employment agreements are filed as exhibits to the registration statement of which this prospectus is a part.

 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	New Base Salary	 	
 	 	Base Salary at the	 	 	 	 	 	After Completion of	 	
Name	 	Beginning of 2011	 	 	Base Salary Increase	 	 	the Offering	 	
 		
Brian F. Bierbach	 	$	235,000	 	 	$	40,000	 	 	$	275,000	 	
Sandra M. Flower	 	$	140,000	 	 	$	35,000	 	 	$	175,000	 	
Marty W. Patterson	 	$	190,000	 	 	$	30,000	 	 	$	220,000	 	
John J. Connor II	 	$	185,000	 	 	$	35,000	 	 	$	220,000	 	
William B. Mathews	 	$	185,000	 	 	$	30,000	 	 	$	215,000	 	

 
Annual Incentive Bonuses
 
As one way of accomplishing compensation objectives, executive officers are rewarded for their contribution to our financial and operational success through the award of discretionary annual cash incentive bonuses. Annual cash incentive awards, if any, for the CEO are determined by the Compensation Committee. Annual cash incentive awards, if any, for the other executive officers are determined by the Compensation Committee taking into account input from the CEO.
 
We expect to review annual cash bonus awards for the named executive officers annually to determine award payments for the prior fiscal year, as well as to establish target bonus amounts for the current fiscal year. At the beginning of each year, the Compensation Committee meets with the CEO to discuss partnership and individual goals for the year and what each executive is expected to contribute in order to help the partnership achieve those goals. However, the amounts of the annual bonuses have been determined in the discretion of the Compensation Committee.

While target bonuses for our executive officers who have entered into employment agreements have been initially set at dollar amounts that are 25% to 100% of their base salaries, the Compensation Committee has had broad discretion to retain, reduce or increase the award amounts when making its final bonus determinations. Target bonus amounts for 2010 for Messrs. Bierbach, Patterson and Connor, which are specified in their existing employment agreements, are set forth in the table below. Please refer to “— Existing Employment Agreements with Named Executive Officers” below for a description of these existing

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employment agreements. Ms. Flower and Mr. Mathews did not have specific target bonus amounts established for 2010. Further, bonuses (similar to other elements of the compensation provided to executive officers) historically have not been solely based on a prescribed formula or pre-determined goals or specified performance targets but rather have been determined on a discretionary basis and generally have been based on a subjective evaluation of individual, company-wide and industry performances. Target bonus amounts for 2011 for all of the executive officers, which are specified in their new employment agreements, are set forth in the table below. Please refer to “— New Employment Agreements with Named Executive Officers” below for a description of the new employment agreements.

The Board and the Compensation Committee believed that this approach to assessing performance resulted in a more comprehensive evaluation for compensation decisions. In 2010, the Compensation Committee recognized the following factors in making discretionary annual bonus recommendations and determinations:

 	• 	a subjective performance evaluation based on company-wide financial and individual qualitative performance, as determined in the Compensation Committee’s discretion; and	
 		
 	• 	the scope, level of expertise and experience required for the executive officer’s position.	
 
These factors were selected as the most appropriate measures upon which to base the annual incentive cash bonus decisions because our Compensation Committee believed that they help to align individual compensation with performance and contribution. With respect to its evaluation of company-wide financial performance, although no pre-determined numerical goals are established, the Compensation Committee generally reviewed our results with respect to adjusted EBITDA and cash available for distribution in making annual bonus determinations.
 
Following its performance assessment, and based on our financial performance with respect to these criteria and the Compensation Committee’s qualitative assessment of individual performance, the Compensation Committee determined to award the incentive bonus amounts set forth in the table below to our named executive officers for performance in 2010.

 	 	2010 Target	 	 	2010 Bonus	 	
Name	 	Bonus	 	 	Awarded	 	
 		
Brian F. Bierbach	 	 	$       65,000	 	 	$	65,000	 	
Sandra M. Flower	 	 	N/A	 	 	$	35,000	 	
Marty W. Patterson	 	 	$       35,000	 	 	$	35,000	 	
John J. Connor	 	 	$       40,000	 	 	$	50,000	 	
William B. Mathews	 	 	N/A	 	 	$	35,000	 	

Bonus amounts were awarded based on our financial performance with respect to these criteria and the Compensation Committee’s qualitative assessment of individual performance. Mr. Connor was awarded in excess of his target bonus in recognition of exceptional performance in the areas of control of operational costs and execution of capital projects.
 
Beginning in 2011, the Compensation Committee expects that it will base annual incentive compensation award recommendations on additional company-wide criteria as well as industry criteria, recognizing the following factors as part of its determination of annual incentive bonuses (without assigning any particular weighting to any factor):

 	• 	financial performance for the prior fiscal year, including adjusted EBITDA and cash available for distribution;	
 		
 	• 	distribution performance for the prior fiscal year compared to the peer group;	
 		
 	• 	unitholder total return for the prior fiscal year compared to the peer group; and	
 		
 	• 	competitive compensation data of executive officers in the peer group.	

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These factors were selected as the most appropriate measures upon which to base the annual cash incentive bonus decisions going forward because the Compensation Committee believes that they will most directly correlate to increases in long-term value for our unitholders.

In June 2011, the Compensation Committee established the 2011 target bonus amounts for the named executive officers as provided in the table below.

 	 	 	 	 	 	 	 	 	 	 	 	 	
Name	 	2010 Target Bonus	 	 	Target Bonus Increase	 	 	2011 Target Bonus	 	
 		
Brian F. Bierbach	 	$	65,000	 	 	$	210,000	 	 	$	275,000	 	
Sandra M. Flower	 	 	N/A	 	 	 	N/A	 	 	$	100,000	 	
Marty W. Patterson	 	$	35,000	 	 	$	95,000	 	 	$	130,000	 	
John J. Connor II	 	$	40,000	 	 	$	90,000	 	 	$	130,000	 	
William B. Mathews	 	 	N/A	 	 	 	N/A	 	 	$	100,000	 	

 
Equity-Based Awards
 
Design.   The LTIP was adopted in 2009 in connection with our formation. In adopting the LTIP, the Board recognized that it needed a source of equity to attract new members to and retain members of the management team, as well as to provide an equity incentive to other key employees and non-employee directors. We believe the LTIP promotes a long-term focus on results and aligns executive and unitholder interests. Historically, we have granted phantom units with associated DERs to provide long-term incentives to our named executive officers. DERs enable the recipients of phantom unit awards to receive cash distributions on our phantom units to the same extent generally as unitholders receive cash distributions on our common units.
 
The LTIP is designed to encourage responsible and profitable growth while taking into account non-routine factors that may be integral to our success. Long-term incentive compensation in the form of equity grants are used to provide incentives for performance that leads to enhanced unitholder value, encourage retention and closely align the executive officers’ interests with unitholders’ interests. Equity grants provide a vital link between the long-term results achieved for our unitholders and the rewards provided to executive officers and other key employees.
 
Phantom Units.   The only awards made under the LTIP since its adoption have been phantom units. A phantom unit is a notional unit granted under the LTIP that entitles the holder to receive an amount of cash equal to the fair market value of one common unit upon vesting of the phantom unit, unless the Board elects to pay such vested phantom unit with a common unit in lieu of cash. Historically, our Board has always issued common units instead of cash. Unless an individual award agreement provides otherwise, the LTIP provides that unvested phantom units are forfeited at the time the holder terminates employment or board membership, as applicable. The terms of the award agreements of our named executive officers provide that a termination due to death or disability results in full acceleration of vesting. In general, phantom units awarded under our LTIP vest as to 25% of the award on each of the first four anniversaries of the date of grant. A grant of phantom units may include accompanying DERs, which entitle the grantee to receive a cash payment with respect to each phantom unit equal to the cash distribution made by the partnership on each common unit. Under the terms of the award agreements, the phantom units granted to the named executive officers include DERs that are paid to the executive within 10 business days after the date of the associated cash distribution made by the partnership with respect to its common units.
 
Equity-Based Award Policies.   Prior to 2011, equity-based awards were granted by the Compensation Committee in connection with our formation. Going forward, we expect that equity-based awards will be awarded by the Compensation Committee on an annual basis as part of the ongoing total annual compensation package for executive officers. On March 2, 2010, Ms. Flower and Mr. Mathews received awards of 51,579 phantom units and 25,789 phantom units, respectively, including accompanying DERs, in connection with our formation. No other named executive officers received any awards under the LTIP in 2010.

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Deferred Compensation
 
Tax-qualified retirement plans are a common way that companies assist employees in preparing for retirement. We provide our eligible executive officers and other employees with an opportunity to save for their retirement by participating in our 401(k) savings plan. The 401(k) plan allows executive officers and other employees to defer compensation (up to IRS imposed limits) for retirement and permits us to make annual discretionary matching contributions to the plan. For 2010, we matched employee contributions to 401(k) plan accounts up to a maximum employer contribution of 6% of the employee’s eligible compensation. Decisions regarding this element of compensation do not impact any other element of compensation.
 
Other Benefits
 
Each of the named executive officers is eligible to participate in our employee benefit plans which provide for medical, dental, vision, disability insurance and life insurance benefits, which are provided on the same terms as available generally to all salaried employees. In 2010, no perquisites were provided to the named executive officers.
 
Recoupment Policy
 
We currently do not have a recoupment policy applicable to annual incentive bonuses or equity awards. The Compensation Committee expects to continue to evaluate the need to adopt such a policy, in light of current legislative policies as well as economic and market conditions.
 
Employment and Severance Arrangements

The Board and the Compensation Committee consider the maintenance of a sound management team to be essential to protecting and enhancing our best interests. To that end, we recognize that the uncertainty that may exist among management with respect to their “at-will” employment with our general partner may result in the departure or distraction of management personnel to our detriment. Accordingly, our general partner previously entered into employment agreements with each of Messrs. Bierbach, Patterson and Connor, which existing employment agreements contain severance arrangements that we believed were appropriate to encourage the continued attention and dedication of members of our management. These employment agreements are described more fully below under “— Existing Employment Agreements with Named Executive Officers.” In connection with the initial public offering, on June 9, 2011, our general partner entered into new employment agreements with each of our named executive officers to be effective upon the closing of the offering. These new employment agreements are described more fully under “— New Employment Agreements with Named Executive Officers” below.

Summary Compensation Table for 2010
 
The following table sets forth certain information with respect to the compensation paid to the named executive officers for the year ended December 31, 2010.

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	All Other	 	 	
Name and Principal Position	 	Salary	 	Bonus	 	Unit Awards(1)	 	Compensation(2)	 	Total	
 		
Brian F. Bierbach	 	$	235,000	 	 	$	65,000	 	 	 	—	 	 	$	183,016	 	 	$	483,016	 	
President and Chief Executive Officer	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Sandra M. Flower	 	$	140,000	 	 	$	35,000	 	 	$	643,691	 	 	$	7,437	 	 	$	826,128	 	
Vice President of Finance	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Marty W. Patterson	 	$	190,000	 	 	$	35,000	 	 	$	—	 	 	$	91,733	 	 	$	316,733	 	
Senior Vice President of Commercial Services	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
John J. Connor II	 	$	185,000	 	 	$	50,000	 	 	$	—	 	 	$	91,717	 	 	$	326,717	 	
Senior Vice President of Operations and Engineering	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
William B. Mathews	 	$	185,000	 	 	$	35,000	 	 	$	321,839	 	 	$	9,872	 	 	$	581,711	 	
Vice President Legal Affairs, General Counsel and Secretary	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

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(1)		Amounts shown in this column do not reflect dollar amounts actually received by our named executive officers. Instead, these amounts reflect the aggregate grant date fair value of each phantom unit award granted in the year ended December 31, 2010 computed in accordance with the provisions of Financial Accounting Standards Board Accounting Standards Codification Topic 718, Compensation — Stock Compensation (“FASB ASC Topic 718”). Assumptions used in the calculation of these amounts are included in Note 14 to our audited consolidated financial statements included in this prospectus.	
 		
(2)		Amounts shown in this column include employer contributions to the named executive officers’ 401(k) plan accounts and life insurance premiums paid by the employer. In addition, the amounts shown for Messrs. Bierbach, Patterson and Connor include the dollar value of any distributions paid on their phantom unit awards pursuant to the DERs in 2010 in the amounts of $182,283, $91,140 and $91,140, respectively. The amounts of such distributions pursuant to DERs are not included in the amounts shown for Ms. Flower and Mr. Mathews because the grant date fair value of their awards reported in the “Unit Awards” column factors in the value of such distributions pursuant to the DERs.	
 
Grants of Plan-Based Awards for 2010
 
The following table provides information regarding grants of plan-based awards received by Sandra Flower and William Mathews in 2010. Such awards consisted of phantom units and accompanying DERs granted under the LTIP. No other named executive officers received grants of plan-based awards during the year ended December 31, 2010.

 	 	 	 	All Other Unit	 	Grant Date Fair	
 	 	 	 	Awards: Number of	 	Value of Phantom	
Name	 	Grant Date	 	Phantom Units(1)	 	Unit Awards(2)	
 		
Sandra M. Flower	 	March 2, 2010	 	 	51,579	(3)	 	$	643,691	 	
William B. Mathews	 	March 2, 2010	 	 	25,789	(3)	 	$	321,839	 	

 
			
(1)		Each phantom unit award was accompanied by a DER.	
 		
(2)		The grant date fair value of each phantom unit award is computed in accordance with FASB ASC Topic 718, and factors in the value of the DERs accompanying such awards. Assumptions used in the calculation of these amounts are included in Note 14 to our audited consolidated financial statements included in this prospectus.	
 		
(3)		Vests as to 25% of the award on each of first four anniversaries of the date of grant.	

Existing Employment Agreements with Named Executive Officers

 
Our general partner has entered into employment agreements dated November 2, 2009 and effective as of November 4, 2009, with each of Brian F. Bierbach, Marty W. Patterson and John J. Connor. In addition, our general partner has entered into new employment agreements to be effective upon the closing of this initial public offering, with each of the named executive officers, which will replace the existing agreements. Please refer to “— New Employment Agreements with Named Executive Officers” below for a description of the new employment agreements. Each of the existing employment agreements has an initial term of two years. These employment agreements are each automatically extended for successive one-year periods unless and until either party elects to terminate the agreement by giving at least 90 days written notice prior to the commencement of the next succeeding one-year period. These employment agreements will terminate if either party gives such required notice, in which case employment may continue on an “at-will” basis, but the non-compete, non-solicitation and certain other provisions of the agreements would terminate. The base salary and target bonus amounts set forth in such employment agreements are shown in the table below. The employment agreements provide that the base salary may be increased but not decreased (except for a decrease that is consistent with reductions taken generally by other executives of the general partner) and that the executive is eligible to receive an annual cash bonus as approved from time to time by the Compensation Committee based on criteria established by the Compensation Committee. The employment agreements also provide that the executive is eligible to receive awards under the LTIP as determined by the Compensation Committee.

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 	 	2010 Base	 	 	2010 Target	 	
Name	 	Salary	 	 	Bonus	 	
 		
Brian F. Bierbach	 	$	235,000	 	 	$	65,000	 	
Marty W. Patterson	 	$	190,000	 	 	$	35,000	 	
John J. Connor II	 	$	185,000	 	 	$	40,000	 	

 
Each employment agreement also contains certain confidentiality covenants prohibiting each executive officer from, among other things, disclosing confidential information relating to our general partner or any of its affiliates including us. The employment agreements also contain non-competition and non-solicitation restrictions, which apply during the term of the executive’s employment with our general partner and continue for a period of 12 months following termination of employment for any reason if such termination occurs during the term of the employment agreement and not in connection with the expiration of the employment agreement.
 
These employment agreements also provide for, among other things, the payment of severance benefits under certain circumstances. Please refer to “— Potential Payment Upon Termination or Change in Control — Employment Agreements with Named Executive Officers” below for a description of these benefits under the employment agreements.

New Employment Agreements with Named Executive Officers

 
In June 2011, our general partner entered into new employment agreements with each of our named executive officers, which will be effective as of the closing of this offering. Each of the new employment agreements has an initial term of two years, which will be automatically extended for successive one year terms until either party elects to terminate the agreement by giving written notice at least 90 days prior to the end of the expiration of the initial or extended term, as applicable. The base salary and target bonus amounts set forth in such employment agreements are shown in the table below. The employment agreements provide that the base salary may be increased but not decreased (except for a decrease that is consistent with reductions taken generally by other executives of the general partner). The agreements provide that the executive will be provided with the opportunity to earn an annual cash bonus, 20 percent of which will be conditioned and determined on the attainment of personal performance goals and 80 percent of which will be conditioned and determined on the attainment of organizational performance goals, in each case as set by, and based on performance criteria established by, the Compensation Committee. The employment agreements also provide that the executive is eligible to receive awards under the LTIP as determined by the Compensation Committee.

 	 	 	 	 	 	 	 	 	
 	 	Base Salary	 	 	
Name	 	following completion of the offering	 	2011 Target Bonus	
 		
Brian F. Bierbach	 	$	275,000	 	 	$	275,000	 	
Sandra M. Flower	 	$	175,000	 	 	$	100,000	 	
Marty W. Patterson	 	$	220,000	 	 	$	130,000	 	
John J. Connor II	 	$	220,000	 	 	$	130,000	 	
William B. Mathews	 	$	215,000	 	 	$	100,000	 	

 
Each employment agreement also contains certain confidentiality covenants prohibiting each executive officer from, among other things, disclosing confidential information relating to our general partner or any of its affiliates, including us. The employment agreements also contain non-competition and non-solicitation restrictions, which apply during the term of the executive’s employment with our general partner and, with certain exceptions, continue for a period of 12 months following termination for any reason.

 
The new employment agreements also provide for, among other things, the payment of severance benefits under certain circumstances. Please refer to “— Potential Payment Upon Termination or Change in Control — New Employment Agreements with Named Executive Officers” below for a description of these benefits under the new employment agreements.

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Outstanding Equity-Based Awards at December 31, 2010
 
The following table provides information regarding outstanding equity-based awards held by the named executive officers as of December 31, 2010. All such equity-based awards consist of phantom units and accompanying DERs granted under the LTIP.

 	 	 	 	 	 	 	 	 	
 	 	Units Awards	
 	 	Number of Phantom	 	Market Value of	
 	 	Units That Have Not	 	Phantom Units That	
Name	 	Vested(1)	 	Have Not Vested(2)	
 		
Brian F. Bierbach	 	 	116,053	 	 	$	1,586,441	 	
Sandra M. Flower	 	 	51,579	 	 	$	705,085	 	
Marty W. Patterson	 	 	58,026	 	 	$	793,215	 	
John J. Connor II	 	 	58,026	 	 	$	793,215	 	
William B. Mathews	 	 	25,789	 	 	$	352,536	 	

 

			
(1)		The awards to Messrs. Bierbach, Patterson and Connor were granted on November 2, 2009. The awards to Ms. Flower and Mr. Mathews were awarded on March 2, 2010. Each of the awards vests as to 25% of the award on each of the first four anniversaries of the date of grant.	

			
(2)		The market value of phantom units that had not vested as of December 31, 2010 is calculated based on the fair market value of our common units as of December 31, 2010, which was $13.67 multiplied by the number of unvested phantom units. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Equity-Based Awards.”	

Units Vested in 2010
 
The following table shows the phantom unit awards that vested during 2010.

 	 	 	 	 	 	 	 	 	
 	 	Number of Units	 	 	Value Realized on	 	
Name	 	Acquired on Vesting	 	 	Vesting(1)	 	
 		
Brian F. Bierbach	 	 	38,684	 	 	$	386,840	 	
Marty W. Patterson	 	 	19,342	 	 	$	193,420	 	
John J. Connor II	 	 	19,342	 	 	$	193,420	 	

 

 
			
(1)		The value realized upon vesting of phantom units is calculated based on the fair market value of our common units as of the applicable vesting date, which was $10.00, multiplied by the number of phantom units that vested.	

Long-Term Incentive Plan
 
The Board has adopted our LTIP for employees, consultants and directors of our general partner and affiliates who perform services for us. The plan provides for the issuance of options, unit appreciation rights, restricted units, phantom units, other unit-based awards, unit awards or replacement awards, as well as tandem DERs granted with respect to an award. To date, only phantom units and related DERs have been issued under the LTIP.

As of June 9, 2011, on a pro forma basis after giving effect to the recapitalization transactions, 209,824 unvested phantom units are outstanding under our LTIP. A phantom unit is a notional unit granted under the LTIP that entitles the holder to receive an amount of cash equal to the fair market value of one common unit upon vesting of the phantom unit, unless the Board elects to pay such vested phantom unit with a common unit in lieu of cash. Historically, our Board has always issued common units in lieu of cash upon vesting of a phantom unit. DERs may be granted in tandem with phantom units. Except as otherwise provided in an award agreement, DERs that are not subject to a restricted period are currently paid to the participant at the time a distribution is made to the unitholders, and DERs that are subject to a restricted period are paid to the

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participant in a single lump sum no later than the 15th day of the third calendar month following the date on which the restricted period ends.
 
The number of units that may be delivered with respect to awards under the LTIP may not exceed 625,532 units, subject to specified anti-dilution adjustments. However, if any award is terminated, cancelled, forfeited or expires for any reason without the actual delivery of units covered by such award or units are withheld from an award to satisfy the exercise price or the employer’s tax withholding obligation with respect to such award, such units will again be available for issuance pursuant to other awards granted under the LTIP. In addition, any units allocated to an award will, to the extent such award is paid in cash, be again available for delivery under the LTIP with respect to other awards. There is no limitation on the number of awards that may be granted under the LTIP and paid in cash. The LTIP provides that it is to be administered by the Board, provided that the Board may delegate authority to administer the LTIP to a committee of non-employee directors.
 
The LTIP may be terminated or amended at any time, including increasing the number of units that may be granted, subject to unitholder approval as required by the securities exchange on which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the benefits of the participant without the consent of the participant. The plan will terminate on the earliest of (i) its termination by the Board or the Compensation Committee, (ii) the tenth anniversary of the date the LTIP was adopted or (iii) when units are no longer available for delivery pursuant to awards under the LTIP. Unless expressly provided for in the plan or an applicable award agreement, any award granted prior to the termination of the plan, and the authority of the Board or the Compensation Committee to amend, adjust or terminate such award or to waive any conditions or rights under such award, will extend beyond the termination date.
 
Potential Payments Upon Termination or Change in Control
 
Employment Agreements with Named Executive Officers
 
The employment agreements with Messrs. Bierbach, Patterson and Connor provide for, among other things, the payment of severance benefits following certain terminations of employment by our general partner or the termination of employment for “Good Reason” (as defined in each of the employment agreements) by the executive officer. Under these agreements, if the executive’s employment is terminated by the general partner other than for “Cause” (as defined in the employment agreements) or other than upon the executive’s death or disability, or if the executive resigns for Good Reason, in each case, during the term of the agreement, the executive will have the right to a lump sum cash payment by our general partner equal to the executive’s annual base salary at the rate in effect on the date of such termination, which will be subject to reimbursement by us to our general partner. The foregoing severance benefit is conditioned on the executive executing a release of claims in favor of our general partner and its affiliates, including us.
 
“Cause” is defined in each employment agreement as the executive having (i) engaged in gross negligence, gross incompetence or willful misconduct in the performance of the duties required of him under the employment agreement, (ii) refused without proper reason to perform the duties and responsibilities required of him under the employment agreement, (iii) willfully engaged in conduct that is materially injurious to our general partner or its affiliates including us (monetarily or otherwise), (iv) committed an act of fraud, embezzlement or willful breach of fiduciary duty to our general partner or an affiliate including us (including the unauthorized disclosure of confidential or proprietary material information of our general partner or an affiliate including us) or (v) been convicted of (or pleaded no contest to) a crime involving fraud, dishonesty or moral turpitude or any felony. “Good Reason” is defined in each employment agreement as a termination by the executive in connection with or based upon (i) a material diminution in the executive’s responsibilities, duties or authority, (ii) a material diminution in the executive’s base compensation, (iii) assignment of the executive to a principal office located beyond a 50-mile radius of the executive’s then current work place, or (iv) a material breach by us of any material provision of the employment agreement.
 
Each employment agreement also contains certain confidentiality covenants prohibiting each executive officer from, among other things, disclosing confidential information relating to our general partner or any of

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its affiliates including us. The employment agreements also contain non-competition and non-solicitation restrictions, which apply during the term of the executive’s employment with our general partner and continue for a period of 12 months following termination of employment for any reason if such termination occurs during the term of the employment agreement and not in connection with the expiration of the employment agreement.
 
Phantom Unit Award Agreements
 
Each of our named executive officers has received an award of phantom units under the LTIP. The terms of the phantom unit award agreements of our named executive officers provide that a termination due to death or disability results in full acceleration of vesting of any outstanding phantom units.

The following table shows the value of the severance benefits and other benefits (1) under the existing employment agreements for the named executive officers who have existing employment agreements and (2) under the phantom unit award agreements, assuming in each case that such named executive officer had terminated employment on December 31, 2010. The named executive officers are not entitled to receive any severance or other benefits upon a change of control under such agreements.

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Death or	 	 	Termination	 	 	Resignation for	 	
Name	 	Benefit Type	 	Disability(1)	 	 	Without Cause	 	 	Good Reason	 	
 		
Brian F. Bierbach	 	Lump sum payment per employment agreement	 	 	None	 	 	$	235,000	 	 	$	235,000	 	
 	 	Accelerated vesting of phantom units per award agreement	 	$	1,586,441	 	 	 	None	 	 	 	None	 	
Sandra M. Flower	 	Accelerated vesting of phantom units per award agreement	 	$	528,814	 	 	 	None	 	 	 	None	 	
Marty W. Patterson	 	Lump sum payment per employment agreement	 	 	None	 	 	$	190,000	 	 	$	190,000	 	
 	 	Accelerated vesting of phantom units per award agreement	 	$	793,215	 	 	 	None	 	 	 	None	 	
John J. Connor II	 	Lump sum payment per employment agreement	 	 	None	 	 	$	185,000	 	 	$	185,000	 	
 	 	Accelerated vesting of phantom units per award agreement	 	$	793,215	 	 	 	None	 	 	 	None	 	
William B. Mathews	 	Accelerated vesting of phantom units per award agreement	 	$	264,402	 	 	 	None	 	 	 	None	 	

 

 
			
(1)		The amounts shown in this column are calculated based on the fair market value of our common units as of December 31, 2010, which we have assumed was $13.67 multiplied by the number of phantom units that would have vested.	

 
The new employment agreements that will be effective upon the completion of this offering also provide for, among other things, the payment of severance benefits following certain terminations of employment by our general partner, the termination of employment for “Good Reason” (as defined under “— Existing Employment Agreements with Named Executive Officers” above) by the executive officer, or, under certain circumstances, upon expiration of the term of the agreement. Under the new employment agreements, if the executive’s employment is terminated upon expiration of the initial or extended term of the agreement by either party upon 90 days’ written notice (with certain exceptions, as described below), if the executive’s employment is terminated by the general partner other than for “Cause” (as defined under “— Existing Employment Agreements with Named Executive Officers” above) or other than upon the executive’s death or

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disability, or if the executive resigns for Good Reason, the executive will have the right to severance in an amount equal to the sum of the executive’s annual base salary at the rate in effect on the date of termination plus the amount, if any, paid to the executive as an annual cash bonus for the calendar year ending immediately prior to the date of such termination. Such severance amount will be paid in installments (on regular pay days scheduled in accordance with our regular payroll practices) beginning on the 60th day following the termination date and ending on the one year anniversary of the termination date, and will be subject to reimbursement by us to our general partner. The foregoing severance benefit is conditioned on the executive executing a release of claims in favor of our general partner and its affiliates, including us.

 
Each employment agreement also contains certain confidentiality covenants prohibiting each executive officer from, among other things, disclosing confidential information relating to our general partner or any of its affiliates, including us. The employment agreements also contain non-competition and non-solicitation restrictions, which apply during the term of the executive’s employment with our general partner and continue for a period of 12 months following termination for any reason. If the executive’s employment is terminated upon expiration of the initial or extended term of the agreement by either party upon 90 days’ written notice, the board of directors may, in its discretion, release the executive from being subject to the noncompetition covenant following termination of employment; however, in that case, the executive would not be entitled to receive any severance payment in connection with such termination.

 
Amended Phantom Unit Grant Agreements

 
As discussed above, we do not expect to use DERs as an element of our compensation programs in the future and, on June 9, 2011, we amended each of outstanding phantom unit grant agreements with our named executive officers to eliminate the DERs previously granted with our phantom units. The form of the amendment to the phantom unit award agreement is filed as an exhibit to the registration statement of which this prospectus forms a part. In addition to eliminating the DERs, the amendments will also provide for acceleration of vesting of phantom units in certain cases in the event of a change of control. More specifically, all unvested phantom units held by a named executive officer will vest:

 
			
 	• 	on the closing date of a Change of Control transaction in which the surviving or acquiring entity does not assume and continue the unvested phantom units on the terms and conditions not less favorable than those provided under the LTIP and the award agreement immediately prior to such Change in Control;	

 
			
 	• 	on the closing date of a Change of Control transaction in which the unitholders of the Partnership sell or exchange their interests in the Partnership for consideration comprised entirely of cash or a combination of cash and equity interests in the surviving or acquiring entity, but only with respect to the portion of the then-unvested phantom units equal to the percentage of all the consideration to such unitholders represented by cash;	

 
			
 	• 	on the closing date of a Change of Control transaction in which the named executive officer is not offered or does not accept employment with the surviving or acquiring entity; or	

 
			
 	• 	on the date of the named executive officer’s termination of employment other than for Cause within one year after the closing date of a Change of Control transaction.	

 
If the named executive officers terminate employment following the closing of the offering, their terminations would be subject to the terms of their new employment agreements and the amended phantom unit award agreements. The following table shows the value of the severance benefits and other benefits for the named executive officers under the new employment agreements and amended phantom unit grant

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agreements, assuming the named executive officer terminates employment immediately following the closing of this offering.

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	Termination	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	Without	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	Cause or	 	 	Resignation	 	 	Certain	 	
 	 	 	 	Death or	 	 	Upon	 	 	For Good	 	 	Changes of	 	
Name	 	Benefit Type	 	Disability(1)	 	 	Expiration(2)	 	 	Reason	 	 	Control(1)(3)	 	
 		
Brian F. Bierbach	 	Severance payment per employment agreement	 	 	None	 	 	$	340,000	 	 	$	340,000	 	 	 	None	 	
 	 	Accelerated vesting of phantom unit awards per award agreement	 	$	1,126,525	 	 	 	None	 	 	 	None	 	 	$	1,126,525	 	
Sandra M. Flower	 	Severance payment per employment agreement	 	 	None	 	 	$	210,000	 	 	$	210,000	 	 	 	None	 	
 	 	Accelerated vesting of phantom unit awards per award agreement	 	$	375,508	 	 	 	None	 	 	 	None	 	 	$	375,508	 	
Marty W. Patterson	 	Severance payment per employment agreement	 	 	None	 	 	$	255,000	 	 	$	255,000	 	 	 	None	 	
 	 	Accelerated vesting of phantom unit awards per award agreement	 	$	563,259	 	 	 	None	 	 	 	None	 	 	$	563,259	 	
John J. Connor II	 	Severance payment per employment agreement	 	 	None	 	 	$	270,000	 	 	$	270,000	 	 	 	None	 	
 	 	Accelerated vesting of phantom unit awards per award agreement	 	$	563,259	 	 	 	None	 	 	 	None	 	 	$	563,259	 	
William B. Mathews	 	Severance payment per employment agreement	 	 	None	 	 	$	270,000	 	 	$	270,000	 	 	 	None	 	
 	 	Accelerated vesting of phantom unit awards per award agreement	 	$	187,750	 	 	 	None	 	 	 	None	 	 	$	187,750	 	

 

 
			
(1)		The amounts shown in this column are calculated based on the fair market value of our common units immediately following the completion of our offering, which we have assumed for this purpose will be $20.00, multiplied by the number of split-adjusted phantom units that would vest.	

 
			
(2)		In connection with a termination of the executive’s employment upon expiration of the initial or extended term of the agreement by either party pursuant to the terms of the employment agreement, the board of directors may, in its discretion, release the executive from being subject to the noncompetition covenant following termination of employment; however, in such case, the executive would not be entitled to receive the severance payment.	

 
			
(3)		Pursuant to the amended phantom unit award agreements, accelerated vesting of phantom units would only occur under certain types of change of control transactions, as described under “— Amended Phantom Unit Grant Agreements” above.	

Compensation of Directors
 
In 2010, one of our directors, Kent Moore, received a retainer paid quarterly in cash for his service on the Board. None of our other directors received any fees paid in cash for service on the Board. Following the closing of our initial public offering, we anticipate that each director who is not an officer or employee of our general partner will receive compensation for attending meetings of the Board, as well as committee meetings, as follows:

 	• 	a $50,000 cash retainer;	

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 	• 	a $50,000 annual phantom unit grant; and	
 		
 	• 	where applicable, a committee chair retainer of $10,000 for each committee chaired.	
 
In addition, each non-employee director will receive per meeting fees of:

 	• 	$1,000 for Board meetings attended in person;	
 		
 	• 	where applicable, $500 for Board committee meetings attended in person; and	
 		
 	• 	$500 for telephonic Board meetings and committee meetings greater than one hour in length.	

We do not anticipate that Messrs. Moore or Page will participate in the annual phantom unit grant for the foreseeable future because each received a substantial phantom unit grant prior to our initial public offering. We expect Messrs. Moore and Page to receive the other elements of compensation outlined above.

Each non-employee director listed in the table below has received grants of phantom units and accompanying DERs under our LTIP. Each non-employee director is also reimbursed for out-of-pocket expenses in connection with attending meetings of the Board or its committees. Each director will be fully indemnified by us for actions associated with being a director of our general partner to the extent permitted under Delaware law.

In connection with eliminating the use of DERs as an element of our compensation programs in the future, we will amend the outstanding phantom unit award agreements with Messrs. Moore and Page prior to the completion of the offering to eliminate the DERs previously granted with the phantom units. The form of the amendment to the phantom unit award agreement is filed as an exhibit to the registration statement of which this prospectus forms a part. In addition to eliminating the DERs, the amendments will also provide for acceleration of vesting of phantom units in certain cases in the event of a change of control. More specifically, all unvested phantom units held by such directors will vest:

 
			
 	• 	on the closing date of a Change of Control transaction in which the surviving or acquiring entity does not assume and continue the unvested phantom units on the terms and conditions not less favorable than those provided under the LTIP and the award agreement immediately prior to such Change in Control;	

 
			
 	• 	on the closing date of a Change of Control transaction in which the unitholders of the Partnership sell or exchange their interests in the Partnership for consideration comprised entirely of cash or a combination of cash and equity interests in the surviving or acquiring entity, but only with respect to the portion of the then-unvested phantom units equal to the percentage of all the consideration to such unitholders represented by cash; or	

 
			
 	• 	on the date of the director’s termination of employment, if any, other than for Cause within one year after the closing date of a Change of Control transaction.	

Director Compensation Table for 2010
 
The following table sets forth the compensation paid to our non-employee directors for the year ended December 31, 2010, as described above. The compensation paid in 2010 to Mr. Bierbach as an executive officer is set forth in the Summary Compensation Table above. Mr. Bierbach did not receive any additional compensation related to his service as a director.

 	 	Fees Earned or	 	 	 	All Other	 	 	
Name and Principal Position	 	Paid in Cash	 	Unit Awards(1)	 	Compensation(2)	 	Total	
 		
L. Kent Moore	 	$	25,000	 	 	 	—	 	 	$	60,760	 	 	$	85,760	 	
David L. Page	 	 	—	 	 	$	623,991	(3)	 	 	—	 	 	$	623,991	 	

 
			
(1)		The amount reported in this column represents the aggregate grant date fair value of the phantom unit award granted to Mr. Page as computed in accordance with FASB ASC Topic 718, which factors in the value of the accompanying DERs. Assumptions used in the calculation of these amounts are included in Note 14 to our audited consolidated financial statements included in this prospectus.	

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(2)		The amount reported in this column represents the dollar value of distributions paid in 2010 pursuant to DERs granted in connection with outstanding phantom unit awards held by Mr. Moore. No such amounts are reported with respect to Mr. Page due to the fact that the aggregate grant date fair value of his unit award reported in the above table factors in the value of the accompanying DERs.	
 		
(3)		On March 2, 2010, Mr. Page received a grant of 50,000 phantom units, with 25% of such units vesting on each of the first through fourth anniversaries of the grant date. As of December 31, 2010, Mr. Page held an aggregate of 50,000 unvested phantom units.	
 
On November 2, 2009, Mr. Moore received a grant of 51,579 phantom units, with 25% of such units vesting on each of the first through fourth anniversaries of the grant date. As of December 31, 2010, Mr. Moore held an aggregate of 38,684 unvested phantom units. Such phantom units will vest in full upon a change of control.
 
Compensation Practices as They Relate to Risk Management
 
We do not believe that our compensation policies and practices create risks that are reasonably likely to have a material adverse effect on the partnership. We believe our compensation programs do not encourage excessive and unnecessary risk taking by executive officers (or other employees). Short-term annual incentives are generally paid pursuant to discretionary bonuses enabling the Compensation Committee to assess the actual behavior of our employees as it relates to risk taking in awarding a bonus. Our use of equity based long-term compensation serves our compensation program’s goal of aligning the interests of executives and unitholders, thereby reducing the incentives to unnecessary risk taking.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
The following table sets forth certain information regarding the beneficial ownership of units following the closing of this offering and the related transactions by:

 	• 	each person who is known to us to beneficially own 5% or more of such units to be outstanding;	
 		
 	• 	our general partner;	
 		
 	• 	each of the directors and named executive officers of our general partner; and	
 		
 	• 	all of the directors and executive officers of our general partner as a group.	
 
All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be.

Our general partner is owned 100.0% by AIM Midstream Holdings. AIM holds an aggregate 84.4% indirect interest in AIM Midstream Holdings. Robert B. Hellman, Jr., Matthew P. Carbone and Edward O. Diffendal serve on the board of directors of our general partner and are principals of and have ownership interests in AIM. In addition, Brian F. Bierbach, the President and Chief Executive Officer of our general partner and a member of the board of directors of our general partner, Marty W. Patterson, the Vice President of Commercial Affairs of our general partner, John J. Connor II, the Vice President of Operations of our general partner, Sandra M. Flower, the Vice President of Finance of our general partner, and William B. Mathews, the Secretary, General Counsel and Vice President of Legal Affairs of our general partner, have an aggregate 1.1% interest in AIM Midstream Holdings.

 
The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of June 9, 2011, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

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The percentage of units beneficially owned is based on a total of 9,052,132 common units and subordinated units outstanding immediately following this offering.

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Percentage of	
 	 	 	 	 	 	 	 	 	 	Total	
 	 	 	 	Percentage of	 	 	 	Percentage of	 	Common and	
 	 	Common Units	 	Common Units	 	Subordinated	 	Subordinated Units	 	Subordinated	
 	 	to be	 	to be	 	Units to be	 	to be	 	Units to be	
 	 	Beneficially	 	Beneficially	 	Beneficially	 	Beneficially	 	Beneficially	
Name of Beneficial Owner	 	Owned	 	Owned	 	Owned	 	Owned	 	Owned	
 		
AIM Universal Holdings, LLC(1)(2)	 	 	725,120	 	 	 	16.0	%	 	 	4,526,066	 	 	 	100.0	%	 	 	58.0	%	
AIM Midstream Holdings, LLC(2)	 	 	725,120	 	 	 	16.0	%	 	 	4,526,066	 	 	 	100.0	%	 	 	58.0	%	
Robert B. Hellman, Jr.(2)	 	 	—	 	 	 	—	%	 	 	—	 	 	 	—	%	 	 	—	%	
Brian F. Bierbach(3)	 	 	*	 	 	 	*	%	 	 	—	 	 	 	—	%	 	 	*	%	
Matthew P. Carbone(2)	 	 	—	 	 	 	—	%	 	 	—	 	 	 	—	%	 	 	—	%	
Edward O. Diffendal(2)	 	 	—	 	 	 	—	%	 	 	—	 	 	 	—	%	 	 	—	%	
David L. Page(2)	 	 	*	 	 	 	*	%	 	 	—	 	 	 	—	%	 	 	*	%	
L. Kent Moore(3)	 	 	*	 	 	 	*	%	 	 	—	 	 	 	—	%	 	 	*	%	
Gerald A. Tywoniuk(2)	 	 	—	 	 	 	—	%	 	 	—	 	 	 	—	%	 	 	—	%	
Sandra M. Flower(3)	 	 	*	 	 	 	*	%	 	 	—	 	 	 	—	%	 	 	*	%	
John J. Connor II(3)	 	 	*	 	 	 	*	%	 	 	—	 	 	 	—	%	 	 	*	%	
Marty W. Patterson(3)	 	 	*	 	 	 	*	%	 	 	—	 	 	 	—	%	 	 	*	%	
William B. Mathews(3)	 	 	*	 	 	 	*	%	 	 	—	 	 	 	—	%	 	 	*	%	
All directors and executive officers as a group (consisting of 10 persons)	 	 	59,264	 	 	 	1.3	%	 	 	—	 	 	 	—	%	 	 	0.7	%	

 

			
* 		An asterisk indicates that the person or entity owns less than one percent.	

			
(1)		AIM Universal Holdings, LLC, a Delaware limited liability company, is the sole manager of AIM Midstream Holdings and may therefore be deemed to beneficially own the 725,120 common units and 4,526,066 subordinated units held by AIM Midstream Holdings. AIM Universal Holdings, LLC’s members consist of Robert B. Hellman, Jr. and Matthew P. Carbone, both directors of our general partner, and George E. McCown.	

			
(2)		The address for this person or entity is 950 Tower Lane, Suite 800, Foster City, California 94404.	
 		
(3)		The address for this person or entity is 1614 15th Street, Suite 300, Denver, Colorado 80202.	

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Immediately following the closing of this offering, AIM Midstream Holdings will own 725,120 common units and 4,526,066 subordinated units, representing a combined 56.9% limited partner interest in us (or 162,620 common units and 4,526,066 subordinated units, representing a combined 50.8% limited partner interest in us, if the underwriters exercise their option to purchase additional common units in full). In addition, AIM Midstream Holdings will own and control our general partner, which will own a 2.0% general partner interest in us and all of our incentive distribution rights.

Distributions and Payments to our General Partner and its Affiliates
 
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and any liquidation of American Midstream Partners, LP. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
 
Pre-IPO Stage

The consideration received by our general partner and its affiliates prior to or in connection with this offering	 	     •   common units;

     •   subordinated units;

     •   all of our incentive distribution rights; and

     •   2.0% general partner interest.	

Post-IPO Stage

			
Distributions of available cash to our general partner and its affiliates		We will initially make cash distributions 98.0% to our unitholders pro rata, including AIM Midstream Holdings, as the holder of an aggregate of 725,120 common units and 4,526,066 subordinated units, and 2.0% to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our general partner will entitle our general partner to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target distribution level.	

 
			
		Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $0.3 million on its 2.0% general partner interest and AIM Midstream Holdings would receive an annual distribution of approximately $8.7 million on its common units and subordinated units.	

			
Payments to our general partner and its affiliates		Our general partner will not receive a management fee or other compensation for its management of us. However, we will reimburse our general partner and its affiliates for all expenses incurred on our behalf. Our partnership agreement provides that our general partner will determine the amount of these reimbursed expenses.	
 		
Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units,	

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		in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement — Withdrawal or Removal of Our General Partner.”	
 
Liquidation Stage

Liquidation		Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.	
 
Ownership Interests of Certain Executive Officers and Directors of Our General Partner

Upon the closing of this offering, AIM Midstream Holdings will continue to own 100.0% of our general partner. AIM, Eagle River Ventures, LLC, Stockwell Fund II, L.P. and certain of our executive officers own all of the equity interests in AIM Midstream Holdings. In addition, Robert B. Hellman, Jr., Matthew P. Carbone and Edward O. Diffendal serve on the board of directors of our general partner and are principals of AIM.

 
In addition to the 2.0% general partner interest in us, our general partner owns the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 48.0%, of the cash we distribute in excess of $0.47438 per unit per quarter, after the closing of our initial public offering. Upon the closing of this offering, AIM Midstream Holdings will own 725,120 common units and 4,526,066 subordinated units.

Agreements with Affiliates
 
We and other parties have or will enter into the various documents and agreements with certain of our affiliates, as described in more detail below. These agreements will affect the offering transactions, including the vesting of assets in, and the assumptions of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations.
 
Advisory Services Agreement
 
In October 2009, our subsidiary, American Midstream, LLC entered into an advisory services agreement with American Infrastructure MLP Management, L.L.C., American Infrastructure MLP PE Management, L.L.C., and American Infrastructure MLP Associates Management, L.L.C., as the advisors. Under this agreement, the advisors perform certain financial and advisory services for American Midstream, LLC. No fees or reimbursements were paid to the advisors during 2009 in respect of this agreement. During 2010, American Midstream, LLC paid the advisors $250,000 for such services and reimbursed the advisors $77,606 for the advisors’ actual and direct out-of-pocket expenses incurred in the performance of their services. For the calendar year 2011 and each calendar year thereafter, the advisors are entitled to annual compensation in the amount of $250,000, plus a fee determined by a formula that takes into account the increase in gross revenue of American Midstream, LLC over the prior year. American Midstream, LLC is also obligated to reimburse the advisors for their actual and direct out-of-pocket expenses. In connection with the closing of this offering, the advisory services agreement will be terminated in exchange for an aggregate payment of $2.5 million from us to the advisors.
 
Contribution Agreements
 
In October 2009, a contribution and sale agreement was entered into by AIM Midstream Holdings and AIM Midstream, LLC, American Infrastructure MLP Fund, L.P., American Infrastructure MLP Private Equity Fund, L.P., American Infrastructure MLP Associates Fund, L.P., Brian F. Bierbach, Marty W. Patterson, John J. Connor II, Eagle River Ventures, LLC, and Stockwell Fund II, L.P., as investors, and AIM Universal Holdings, LLC. Pursuant to this agreement, the investors contributed an aggregate of $100 million to AIM Midstream Holdings in exchange for membership interests in AIM Midstream Holdings.

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In November 2009, we entered into a contribution, conveyance and assumption agreement with AIM Midstream Holdings, American Midstream GP, American Midstream, LLC, and American Midstream Marketing, LLC. Pursuant to this Agreement, AIM Midstream Holdings contributed $2 million to American Midstream GP in exchange for all of the outstanding membership interests in American Midstream GP. American Midstream GP, in turn, contributed such $2 million to us in exchange for 200,000 general partner units representing a 2% general partner interest in us, and all of our incentive distribution rights. AIM Midstream Holdings also contributed $98 million to us in exchange for 9,800,000 common units representing a 98% limited partner interest in us. We then contributed the $100 million that we received from American Midstream GP and AIM Midstream Holdings to American Midstream, LLC in exchange for the continuation of our 100% member interest in American Midstream, LLC.
 
In September 2010, a contribution and sale agreement was entered into by AIM Midstream Holdings and AIM Midstream, LLC, American Infrastructure MLP Fund, L.P., American Midstream MLP Associates Fund, L.P., American Infrastructure MLP Private Equity Fund, L.P., Eagle River Ventures, LLC, Stockwell Fund II, L.P., John J. Connor II, William B. Mathews, and Sandra M. Flower, as investors. Pursuant to this agreement, the investors contributed an aggregate of $12 million to AIM Midstream Holdings in exchange for membership interests in AIM Midstream Holdings.
 
In September 2010, we entered into a contribution agreement with AIM Midstream Holdings, our general partner, and American Midstream, LLC. Pursuant to this Agreement, AIM Midstream Holdings contributed $240,000, or 2% of the $12 million contributed by the investors to AIM Midstream Holdings pursuant to the contribution and sale agreement described in the preceding paragraph, to our general partner. Our general partner, in turn, contributed such $240,000 to us in exchange for 24,000 general partner units. AIM Midstream Holdings also contributed $11,760,000, or 98% of the $12 million contributed by the investors to AIM Midstream Holdings pursuant to the contribution and sale agreement described in the preceding paragraph, to us in exchange for 1,176,000 common units. We then contributed the $12 million that we received from American Midstream GP and AIM Midstream Holdings to American Midstream, LLC in furtherance of our existing limited liability company interest American Midstream, LLC.

 
Procedures for Review, Approval and Ratification of Related-Person Transactions
 
The board of directors of our general partner will adopt a code of business conduct and ethics in connection with the closing of this offering that will provide that the board of directors of our general partner or its authorized committee will periodically review all related-person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related-person transaction and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.
 
The code of business conduct and ethics will provide that, in determining whether to recommend the initial approval or ratification of a related-person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on director independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.
 
The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES
 
Conflicts of Interest
 
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including AIM Midstream Holdings), on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and executive officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders.
 
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of its fiduciary duty.
 
Our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if the resolution of the conflict is:

 	• 	approved by the Conflicts Committee, although our general partner is not obligated to seek such approval;	
 		
 	• 	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;	
 		
 	• 	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or	
 		
 	• 	fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.	
 
Our general partner may, but is not required to, seek the approval of such resolution from the Conflicts Committee. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the Conflicts Committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the Conflicts Committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to have an honest belief that he is acting in, or not opposed to, the best interests of the partnership.
 
Conflicts of interest could arise in the situations described below, among others.
 
AIM Midstream Holdings and other affiliates of our general partner may compete with us.
 
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner (or as general partner of another company of which we are a partner or member) or those activities incidental to its ownership of interests in us. However, certain affiliates of our general partner, including AIM Midstream Holdings, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Additionally, AIM, through its investment funds and managed accounts, makes investments and purchases entities in various areas of the energy sector, including the midstream natural gas industry. These investments and acquisitions may include entities or assets that we would have been interested in acquiring.

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Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including its executive officers, directors and AIM Midstream Holdings. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, AIM Midstream Holdings may compete with us for investment opportunities and may own an interest in entities that compete with us.
 
Our general partner is allowed to take into account the interests of parties other than us, such as AIM Midstream Holdings, in resolving conflicts.
 
Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of our general partner’s limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.
 
Our partnership agreement limits the liability and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without those limitations, might constitute breaches of its fiduciary duty.
 
In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duty. For example, our partnership agreement:

 	• 	provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as such decisions are made in good faith, which means the honest belief that the decision is in our best interest;	
 		
 	• 	provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee and not involving a vote of unitholders must either be (1) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (2) “fair and reasonable” to us, as determined by our general partner in good faith, provided that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and	
 		
 	• 	provides that our general partner and its executive officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its executive officers or directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that their conduct was criminal.	
 
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
 
Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought

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Conflicts Committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

 	• 	the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;	
 		
 	• 	the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;	
 		
 	• 	the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;	
 		
 	• 	the negotiation, execution and performance of any contracts, conveyances or other instruments;	
 		
 	• 	the distribution of our cash;	
 		
 	• 	the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;	
 		
 	• 	the maintenance of insurance for our benefit and the benefit of our partners;	
 		
 	• 	the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;	
 		
 	• 	the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;	
 		
 	• 	the indemnification of any person against liabilities and contingencies to the extent permitted by law;	
 		
 	• 	the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and	
 		
 	• 	the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.	
 
Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination to be made in “good faith,” our general partner must have an honest belief that the determination is in our best interests. Please read “The Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.
 
Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.
 
The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

 	• 	the amount and timing of asset purchases and sales;	
 		
 	• 	cash expenditures and the amount of estimated reserve replacement expenditures;	
 		
 	• 	borrowings;	
 		
 	• 	the issuance of additional units; and	
 		
 	• 	the creation, reduction or increase of reserves in any quarter.	
 
Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the

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amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.

In addition, our general partner may use an amount, initially equal to $11.5 million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

 	• 	enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or	
 		
 	• 	hastening the expiration of the subordination period.	
 
For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”
 
Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, or our operating company and its operating subsidiaries.
 
We will reimburse our general partner and its affiliates for expenses.
 
We will reimburse our general partner and its affiliates for costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith, and it will charge on a fully allocated cost basis for services provided to us. The fully allocated basis charged by our general partner does not include a profit component. Please read “Certain Relationships and Related Party Transactions.”
 
Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations.
 
Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the Conflicts Committee may make a determination on our behalf with respect to such arrangements.
 
Our general partner will determine, in good faith, the terms of any of these transactions entered into after the close of this offering.
 
Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.
 
Our general partner intends to limit its liability regarding our obligations.
 
Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any

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affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained terms that are more favorable without the limitation on liability.
 
Common units are subject to our general partner’s limited call right.
 
Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have to sell his common units at an undesirable time or price. Please read “The Partnership Agreement — Limited Call Right.”
 
Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.
 
Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
 
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
 
The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the Conflicts Committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.
 
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the Conflicts Committee or our unitholders. This election may result in lower distributions to our public common unitholders in certain situations.
 
Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
 
We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our

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general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Available Cash — General Partner Interest and Incentive Distribution Rights.”
 
Fiduciary Duties
 
Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, modify or eliminate, except for the contractual covenant of good faith and fair dealing, the fiduciary duties owed by the general partner to limited partners and the partnership.
 
Our partnership agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. Without such modifications, such transactions could result in violations of our general partner’s state-law fiduciary duty standards. We believe this is appropriate and necessary because the board of directors of our general partner has fiduciary duties to manage our general partner in a manner beneficial both to its owners, as well as to our unitholders. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable our general partner to take into consideration the interests of all parties involved, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications disadvantage the common unitholders because they restrict the rights and remedies that would otherwise be available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

State law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.	
 		
Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or our limited partners whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.	

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		Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders or that are not approved by the Conflicts Committee must be:	
 		
		• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or	
 		
		• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).	
 		
		If our general partner does not seek approval from the Conflicts Committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.	
 		
		In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful.	
 		
Rights and remedies of unitholders		The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.	
 
By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

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Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. We also must provide this indemnification for criminal proceedings when our general partner or these other persons acted with no knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, or the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read “The Partnership Agreement — Indemnification.”

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DESCRIPTION OF THE COMMON UNITS
 
The Units
 
The common units represent limited partner interests in us. The holders of common units, along with the holders of subordinated units, are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “Our Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”
 
Transfer Agent and Registrar
 
Duties

Computershare Trust Company, N.A. will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by our unitholders:

			
 	• 	surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in connection therewith;	
 		
 	• 	special charges for services requested by a holder of a common unit; and	
 		
 	• 	other similar fees or charges.	
 
There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.
 
Resignation or Removal
 
The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.
 
Transfer of Common Units
 
By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

 	• 	automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement;	
 		
 	• 	represents and warrants that the transferee has the right, power, authority and capacity to enter into our partnership agreement; and	
 		
 	• 	gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with this offering.	

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Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.
 
We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.
 
Common units are securities and are transferable according to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.
 
Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT
 
The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.
 
We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 	• 	with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions;”	
 		
 	• 	with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties;”	
 		
 	• 	with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units;” and	
 		
 	• 	with regard to allocations of taxable income and taxable loss, please read “Material Federal Income Tax Consequences.”	
 
Organization and Duration
 
We were organized in August 2009 and have a perpetual existence.
 
Purpose
 
Our purpose under our partnership agreement is limited to any business activities that are approved by our general partner and in any event that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner may not cause us to engage, directly or indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.
 
Although our general partner has the power to cause us, our operating company and its subsidiaries to engage in activities other than the business of gathering, compressing, treating and transporting natural gas, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.
 
Cash Distributions
 
Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”
 
Capital Contributions
 
Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”
 
For a discussion of our general partner’s right to contribute capital to maintain its 2.0% general partner interest if we issue additional units, please read “— Issuance of Additional Securities.”

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Voting Rights
 
The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that require the approval of a “unit majority” require:

 	• 	during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and	
 		
 	• 	after the subordination period, the approval of a majority of the outstanding common units.	
 
By virtue of the exclusion of those common units held by our general partner and its affiliates from the required vote, and by their ownership of all of the subordinated units, during the subordination period our general partner and its affiliates do not have the ability to ensure passage of, but do have the ability to ensure defeat of, any amendment that requires a unit majority.
 
In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us and our limited partners.

 	 	 	
 	 	 	
Issuance of additional units	 	No approval right.	
 	 	 	
Amendment of our partnership agreement	 	Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of Our Partnership Agreement.”	
 	 	 	
Merger of our partnership or the sale of all or substantially all of our assets	 	Unit majority in certain circumstances. Please read “— Merger, Sale or Other Disposition of Assets.”	
 	 	 	
Dissolution of our partnership	 	Unit majority. Please read “— Termination and Dissolution.”	
 	 	 	
Continuation of our business upon dissolution	 	Unit majority. Please read “— Termination and Dissolution.”	
 	 	 	
Withdrawal of our general partner	 	Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to June 30, 2021 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of Our General Partner.”	
 	 	 	
Removal of our general partner	 	Not less than 66 2 / 3 % of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of Our General Partner.”	
 	 	 	
Transfer of our general partner interest	 	Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to June 30, 2020. Please read “— Transfer of General Partner Interest.”	

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Transfer of incentive distribution rights	 	No approval right. Please read “— Transfer of Subordinated Units Incentive Distribution Rights.”	
 	 	 	
Transfer of ownership interests in our general partner	 	No approval required at any time. Please read “— Transfer of Ownership Interests in Our General Partner.”	

 
Limited Liability
 
Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right of, or exercise of the right by, the limited partners as a group:

 	• 	to remove or replace our general partner;	
 		
 	• 	to approve some amendments to our partnership agreement; or	
 		
 	• 	to take other action under our partnership agreement;	
 
constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for such a claim in Delaware case law.
 
Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to it at the time it became a limited partner and that could not be ascertained from the partnership agreement.
 
Our subsidiaries conduct business primarily in five states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of our operating company may require compliance with legal requirements in the jurisdictions in which our operating company conducts business, including qualifying our subsidiaries to do business there.
 
Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a
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manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.
 
Issuance of Additional Securities
 
Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of our limited partners.
 
It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.
 
In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity securities, which may effectively rank senior to the common units.
 
Upon issuance of additional partnership securities, our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in us. Our general partner’s 2.0% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership securities.
 
Amendment of Our Partnership Agreement
 
General
 
Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.
 
Prohibited Amendments
 
No amendment may be made that would:

 	• 	enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or	
 		
 	• 	enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.	

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The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon the closing of this offering, affiliates of our general partner will own approximately 58.0% of the outstanding common and subordinated units.

No Unitholder Approval
 
Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

 	• 	a change in our name, the location of our principal place of business, our registered agent or our registered office;	
 		
 	• 	the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;	
 		
 	• 	a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we, our operating company, nor its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;	

			
 	• 	a change in our fiscal year or taxable period and related changes;	

			
 	• 	an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;	

			
 	• 	any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;	

			
 	• 	an amendment effected, necessitated, or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;	
 		
 	• 	any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, as otherwise permitted by our partnership agreement;	
 		
 	• 	mergers with, conveyances to or conversions into another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger, conveyance or conversion other than those it receives by way of the merger, conveyance or conversion; or	
 		
 	• 	any other amendments substantially similar to any of the matters described above.	
 
In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

 	• 	do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;	
 		
 	• 	are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;	

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 	• 	are necessary or appropriate to facilitate the trading of units or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the units are or will be listed for trading;	
 		
 	• 	are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or	
 		
 	• 	are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.	
 
Opinion of Counsel and Limited Partner Approval
 
Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described above under “— No Unitholder Approval.” No other amendments to our partnership agreement will become effective without the approval of holders of at least 90.0% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.
 
In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.
 
Merger, Sale or Other Disposition of Assets
 
A merger or consolidation of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or our limited partners.
 
In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our and our subsidiaries’ assets in a single transaction or a series of related transactions, including by way of merger, consolidation, other combination or sale of ownership interests of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our and our subsidiaries’ assets without that approval. Our general partner may also sell all or substantially all of our and our subsidiaries’ assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of the limited partners), each of our units will be an identical unit of our partnership following the transaction and the partnership securities to be issued do not exceed 20.0% of our outstanding partnership securities immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed limited liability entity, if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

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Termination and Dissolution
 
We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

 	• 	the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following the approval and admission of a successor general partner;	
 		
 	• 	the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;	
 		
 	• 	the entry of a decree of judicial dissolution of our partnership; or	
 		
 	• 	there being no limited partners, unless we are continued without dissolution in accordance with the Delaware Act.	
 
Upon a dissolution under the first clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement and appoint as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

 	• 	the action would not result in the loss of limited liability of any limited partner; and	
 		
 	• 	neither we nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).	
 
Liquidation and Distribution of Proceeds
 
Upon our dissolution, unless we are continued as a limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time if it determines that an immediate sale or distribution would be impractical or would cause undue loss to our partners. The liquidator may distribute our assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the partners.
 
Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to November 4, 2019 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2021, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving at least 90 days’ advance notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50.0% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest and incentive distribution rights in us without the approval of the unitholders. Please read “— Transfer of General Partner Interest” and “— Transfer of Incentive Distribution Rights.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an

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opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “— Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2 / 3 % of all outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, and a majority of the outstanding subordinated units, voting as a single class. The ownership of more than 33 2 / 3 % of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner’s removal. At the closing of this offering, affiliates of our general partner will own 58.0% of the outstanding common and subordinated units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

 	• 	the subordination period will end and all outstanding subordinated units will immediately and automatically convert into common units on a one-for-one basis;	
 		
 	• 	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and	
 		
 	• 	our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of the interests at the time.	
 
In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for their fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.
 
If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.
 
In addition, we will be required to reimburse the departing general partner for all amounts due to it, including, without limitation, all employee-related liabilities, including severance liabilities, incurred in connection with the termination of any employees employed by the departing general partner or its affiliates for our benefit.
 
Transfer of General Partner Interest
 
Except for transfer by our general partner of all, but not less than all, of its general partner interest to:

 	• 	an affiliate of our general partner (other than an individual); or	

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 	• 	another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity.	

 
Our general partner may not transfer all or any of its general partner interest to another person prior to June 30, 2021 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may, at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.
 
Transfer of Ownership Interests in Our General Partner
 
At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Transfer of Subordinated Units and Incentive Distribution Rights

 
By transfer of subordinated units or incentive distribution rights in accordance with our partnership agreement, each transferee of subordinated units or incentive distribution rights will be admitted as a limited partner with respect to the subordinated units or incentive distribution rights transferred when such transfer and admission is reflected in our books and records. Each transferee:

 
			
 	• 	represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;	

 
			
 	• 	automatically becomes bound by the terms and conditions of our partnership agreement; and	

 
			
 	• 	gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering.	

 
We may, at our discretion, treat the nominee holder of subordinated units or incentive distribution rights as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

 
Subordinated units or incentive distribution rights are securities and any transfers are subject to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner for the transferred subordinated units or incentive distribution rights.

 
Until a subordinated unit or incentive distribution right has been transferred on our books, we and the transfer agent may treat the record holder of the unit or right as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Change of Management Provisions
 
Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change our management. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20.0% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units directly from our general partner or its affiliates or any transferee of that person or group that is approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

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Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

 	• 	the subordination period will end and all outstanding subordinated units will immediately and automatically convert into common units on a one-for-one basis;	
 		
 	• 	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and	
 		
 	• 	our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of the interests at the time.	
 
Limited Call Right
 
If at any time our general partner and its affiliates own more than 80.0% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10, but not more than 60, days notice. The purchase price in the event of this purchase is the greater of:

 	• 	the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and	
 		
 	• 	the average of the daily closing prices of the partnership securities of such class for the 20 consecutive trading days preceding the date three days before the date the notice is mailed.	
 
As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Federal Income Tax Consequences — Disposition of Common Units.”
 
Meetings; Voting
 
Except as described below regarding a person or group owning 20.0% or more of any class of units then outstanding, unitholders who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.
 
Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20.0% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. The units representing the general partner interest are units for distribution and allocation purposes, but do not entitle our general partner to any vote other than its rights as general partner under our partnership agreement, will not be entitled to vote on any action required or permitted to be taken by the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.

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Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20.0% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.
 
Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.
 
Status as Limited Partner
 
By transfer of common units in accordance with our partnership agreement, each transferee of common units will be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described above under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.
 
Non-Citizen Assignees; Redemption

To avoid any adverse effect on the maximum applicable rates chargeable to customers by us under Federal Energy Regulatory Commission regulations, or in order to reverse an adverse determination that has occurred regarding such maximum applicable rate, our partnership agreement provides our general partner the power to amend the agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 
			
 	• 	obtain proof of the U.S. federal income tax status of our member (and their owners, to the extent relevant); and	

 
			
 	• 	permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.	

 
A non-taxpaying assignee will not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

Non-Taxpaying Assignees; Redemption
 
In the event any rates that we charge our customers become regulated by the Federal Energy Regulatory Commission, to avoid any adverse effect on the maximum applicable rates chargeable to customers by us, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend the agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the

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maximum applicable rates chargeable to customers by us, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 	• 	obtain proof of the U.S. federal income tax status of our member (and their owners, to the extent relevant); and	
 		
 	• 	permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.	
 
Indemnification
 
Under our partnership agreement, we will indemnify the following persons, in most circumstances, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

 	• 	our general partner;	
 		
 	• 	any departing general partner;	
 		
 	• 	any person who is or was an affiliate of our general partner or any departing general partner;	
 		
 	• 	any person who is or was a member, manager, partner, director, officer, fiduciary or trustee of our partnership, our subsidiaries, our general partner, any departing general partner or any of their affiliates;	
 		
 	• 	any person who is or was serving at the request of the general partner or any departing general partner as an officer, director, member, manager, partner, fiduciary or trustee of another person; and	
 		
 	• 	any person designated by our general partner.	
 
Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.
 
Reimbursement of Expenses
 
Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.
 
Books and Reports
 
Our general partner is required to keep or cause to be kept appropriate books and records of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For fiscal and tax reporting purposes, we use the calendar year.
 
We will furnish or make available (by posting on our website or other reasonable means) to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants, including a balance sheet and statements of operations, and our equity and cash flows. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

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As soon as practicable, but in no event later than 90 days after the close of each quarter except the last quarter of each fiscal year, our general partner will mail or make available to each record holder of a unit a report containing our unaudited financial statements and such other information as may be required by applicable law, regulation or rule. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether he supplies us with information.
 
Right to Inspect Our Books and Records
 
Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable demand and at its own expense, have furnished to him:

			
 	• 	a current list of the name and last known business, residence or mailing address of each record holder;	

 
			
 	• 	copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments, and powers of attorney under which they have been executed;	

			
 	• 	information regarding the status of our business and financial condition; and	
 		
 	• 	any other information regarding our affairs as is just and reasonable.	
 
Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.
 
Registration Rights
 
Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units, or other partnership securities proposed to be sold by our general partner or any of its affiliates, other than individuals, or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years and for so long thereafter as is required for the holder to sell its partnership securities following any withdrawal or removal of American Midstream GP as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus, AIM Midstream Holdings will hold an aggregate of 725,120 common units and 4,526,066 subordinated units (or 162,620 common units and 4,526,066 subordinated units if the underwriters exercise their option to purchase additional units in full). All of the subordinated units will convert into common units at the end of the subordination period. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 	• 	1.0% of the total number of the securities outstanding; or	
 		
 	• 	the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.	
 
Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell common units under Rule 144 without regard to the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.
 
Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement — Issuance of Additional Securities.”
 
Under our partnership agreement, our general partner and its affiliates, excluding any individual who is an affiliate of our general partner, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units to require registration of any of these common units and to include any of these common units in a registration by us of other common units, including common units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their common units in private transactions at any time, subject to compliance with applicable laws.
 
AIM Midstream Holdings, our general partner and the executive officers and directors of our general partner have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions.

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MATERIAL FEDERAL INCOME TAX CONSEQUENCES
 
This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Andrews Kurth LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to American Midstream Partners, LP and our operating subsidiaries.
 
The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, IRAs, real estate investment trusts (REITs) or mutual funds. In addition, the discussion only comments, to a limited extent, on state, local, and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.
 
No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Andrews Kurth LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.
 
All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Andrews Kurth LLP and are based on the accuracy of the representations made by us.
 
For the reasons described below, Andrews Kurth LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and (iii) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Uniformity of Units”).
 
Partnership Status
 
A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.

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Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of crude oil, natural gas and other products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than     % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Andrews Kurth LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.
 
No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Andrews Kurth LLP on such matters. It is the opinion of Andrews Kurth LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:

 	• 	We will be classified as a partnership for federal income tax purposes; and	
 		
 	• 	Each of our operating subsidiaries will be disregarded as an entity separate from us or will be treated as a partnership for federal income tax purposes.	
 
In rendering its opinion, Andrews Kurth LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Andrews Kurth LLP has relied are:

 	• 	Neither we nor the operating subsidiaries has elected or will elect to be treated as a corporation; and	
 		
 	• 	For each taxable year, more than 90% of our gross income has been and will be income of the type that Andrews Kurth LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.	
 
We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.
 
If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.
 
If we were taxed as a corporation for federal income tax purposes in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction

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in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.
 
The discussion below is based on Andrews Kurth LLP’s opinion that we will be classified as a partnership for federal income tax purposes.
 
Limited Partner Status
 
Unitholders who are admitted as limited partners of American Midstream Partners, LP will be treated as partners of American Midstream Partners, LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of American Midstream Partners, LP for federal income tax purposes.
 
A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”
 
Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in American Midstream Partners, LP. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in American Midstream Partners, LP for federal income tax purposes.
 
Tax Consequences of Unit Ownership
 
Flow-Through of Taxable Income
 
Subject to the discussion below under “— Entity-Level Collections,” we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.
 
Treatment of Distributions
 
Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”
 
A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, depletion recapture and/or substantially appreciated “inventory items,” each as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having

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exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.
 
Ratio of Taxable Income to Distributions
 
We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending           , 20  , will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:

 	• 	gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or	
 		
 	• 	we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.	
 
Basis of Common Units   
 
A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner’s “net value,” as defined in Treasury Regulations under Section 752 of the Internal Revenue Code, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”
 
Limitations on Deductibility of Losses   
 
The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder’s tax basis in his common units. Upon

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the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.
 
In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.
 
In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.
 
A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.
 
Limitations on Interest Deductions
 
The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 	• 	interest on indebtedness properly allocable to property held for investment;	
 		
 	• 	our interest expense attributed to portfolio income; and	
 		
 	• 	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.	
 
The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.
 
Entity-Level Collections
 
If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be

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determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.
 
Allocation of Income, Gain, Loss and Deduction
 
In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.
 
Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of an offering and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates that exists at the time of such contribution, together, referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to the general partner and all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.
 
An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

 	• 	his relative contributions to us;	
 		
 	• 	the interests of all the partners in profits and losses;	
 		
 	• 	the interest of all the partners in cash flow; and	
 		
 	• 	the rights of all the partners to distributions of capital upon liquidation.	
 
Andrews Kurth LLP is of the opinion that, with the exception of the issues described in “— Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

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Treatment of Short Sales
 
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

 	• 	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;	
 		
 	• 	any cash distributions received by the unitholder as to those units would be fully taxable; and	
 		
 	• 	all of these distributions would appear to be ordinary income.	
 
Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Andrews Kurth LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”
 
Alternative Minimum Tax
 
Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.
 
Tax Rates
 
Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.
 
Recently enacted legislation will impose a 3.8% Medicare tax on certain net investment income earned by individuals, estates and trusts for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.
 
Section 754 Election
 
We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read “— Disposition of Common Units — Constructive Termination.” The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets, or inside basis, under Section 743(b) of the Internal

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Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets, or common basis, and (ii) his Section 743(b) adjustment to that basis.
 
We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “— Uniformity of Units.”
 
We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” Andrews Kurth LLP is unable to opine as to whether our method for depreciating Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.
 
A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

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The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.
 
Tax Treatment of Operations
 
Accounting Method and Taxable Year
 
We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”
 
Initial Tax Basis, Depreciation and Amortization
 
The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates, and (ii) any other offering will be borne by our general partner and all of our unitholders as of that time. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”
 
To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “— Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.
 
If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”
 
The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

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Valuation and Tax Basis of Our Properties
 
The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
 
Disposition of Common Units
 
Recognition of Gain or Loss
 
Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.
 
Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.
 
Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15% through December 31, 2012 and 20% thereafter (absent new legislation extending or adjusting the current rate). However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income each year, in the case of individuals, and may only be used to offset capital gains in the case of corporations.
 
The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common

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units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.
 
Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

 	• 	a short sale;	
 		
 	• 	an offsetting notional principal contract; or	
 		
 	• 	a futures or forward contract;	
 
in each case, with respect to the partnership interest or substantially identical property.
 
Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.
 
Allocations Between Transferors and Transferees
 
In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.
 
Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Andrews Kurth LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.
 
A unitholder who disposes of units prior to the record date set for a cash distribution for any quarter will be allocated items of our income, gain, loss and deductions attributable to the month of sale but will not be entitled to receive that cash distribution.
 
Notification Requirements
 
A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase

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within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.
 
Constructive Termination
 
We will be considered to have terminated our tax partnership for federal income tax purposes upon the sale or exchange of our interests that, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
 
Uniformity of Units
 
Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”
 
We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method

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to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under “— Tax Consequences of Unit Ownership — Section 754 Election,” Andrews Kurth LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”
 
Tax-Exempt Organizations and Other Investors
 
Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.
 
Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.
 
Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.
 
In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.
 
A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

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Administrative Matters
 
Information Returns and Audit Procedures
 
We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Andrews Kurth LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.
 
The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.
 
Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names American Midstream GP as our Tax Matters Partner.
 
The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.
 
A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.
 
Nominee Reporting
 
Persons who hold an interest in us as a nominee for another person are required to furnish to us:

 	• 	the name, address and taxpayer identification number of the beneficial owner and the nominee;	
 		
 	• 	whether the beneficial owner is:	

 	• 	a person that is not a U.S. person;	
 		
 	• 	a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or	
 		
 	• 	a tax-exempt entity;	

 	• 	the amount and description of units held, acquired or transferred for the beneficial owner; and	
 		
 	• 	specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.	

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Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.
 
Accuracy-Related Penalties
 
An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.
 
For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

 	• 	for which there is, or was, “substantial authority”; or	
 		
 	• 	as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.	
 
If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.
 
A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts.
 
No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.
 
In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.
 
Reportable Transactions
 
If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of 6 successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures.”

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Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:

 	• 	accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-Related Penalties”;	
 		
 	• 	for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and	
 		
 	• 	in the case of a listed transaction, an extended statute of limitations.	
 
We do not expect to engage in any “reportable transactions.”
 
Recent Legislative Developments
 
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, in the last session of Congress, the U.S. House of Representatives passed legislation that would provide for substantive changes to the definition of qualifying income and the treatment of certain types of income earned from profits interests in partnerships. It is possible that these legislative efforts could result in changes to the existing federal income tax laws that affect publicly traded partnerships. As previously proposed, we do not believe any such legislation would affect our tax treatment as a partnership. However, the proposed legislation could be modified in a way that could affect us. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.
 
State, Local, Foreign and Other Tax Considerations
 
In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business or own property in several states, most of which impose personal income taxes on individuals. Most of these states also impose an income tax on corporations and other entities. Moreover, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. A unitholder may be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.
 
It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Andrews Kurth LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN AMERICAN MIDSTREAM PARTNERS, LP BY EMPLOYEE BENEFIT PLANS
 
An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA, collectively, “Similar Laws.” For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements, collectively, “Employee Benefit Plans.” Among other things, consideration should be given to:

 	• 	whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;	
 		
 	• 	whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;	
 		
 	• 	whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Federal Income Tax Consequences — Tax-Exempt Organizations and Other Investors;” and	
 		
 	• 	whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.	
 
The person with investment discretion with respect to the assets of an Employee Benefit Plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.
 
Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit Employee Benefit Plans from engaging, either directly or indirectly, in specified transactions involving “plan assets” with parties that, with respect to the Employee Benefit Plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.
 
In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the Employee Benefit Plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such Employee Benefit Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.
 
The Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which Employee Benefit Plans acquire equity interests would be deemed “plan assets.” Under these rules, an entity’s assets would not be considered to be “plan assets” if, among other things:
 
(a) the equity interests acquired by the Employee Benefit Plan are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

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(b) the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or
 
(c) there is no significant investment by “benefit plan investors,” which is defined to mean that less than 25% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and some other persons, is held generally by Employee Benefit Plans.
 
Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above.
 
In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

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UNDERWRITING
 
Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are acting as joint book-running managers of the offering and as representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter’s name.

 	 	 	 	 	 	
 	 	Number of	
 	 	Common	
Underwriter	 	Units	
 		
Citigroup Global Markets Inc. 	 	 	 	 	 	
Merrill Lynch, Pierce, Fenner & Smith
Incorporated	 	 	          	 	 	
Barclays Capital Inc. 	 	 	 	 	 	
Wells Fargo Securities, LLC	 	 	 	 	 	
 	 	 	 	 		
Total	 	 	3,750,000	 	 	

 
The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by the over-allotment option described below) if they purchase any of the common units.
 
Common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $      per common unit. If all the common units are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms. The representatives have advised us that the underwriters do not intend to make sales to discretionary accounts.

If the underwriters sell more common units than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to 562,500 additional common units at the public offering price less underwriting discounts and commissions, and the structuring fee. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter’s initial purchase commitment. Any common units issued or sold under the option will be issued and sold on the same terms and conditions as the other common units that are the subject of this offering.

We, our officers and directors, and our other unitholders, including our general partner and AIM Midstream Holdings and its affiliates, have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, dispose of or hedge any common units or any securities convertible into or exchangeable for our common stock. Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated in their sole discretion may release any of the securities subject to these lock-up agreements at any time without notice. Notwithstanding the foregoing, if (i) during the last 17 days of the 180-day restricted period, we issue an earnings release or material news or a material event relating to our partnership occurs; or (ii) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day restricted period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

We intend to apply to have our common units listed on the New York Stock Exchange under the symbol ‘‘AMID.”

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The following table shows the underwriting discounts, commissions and the structuring fee that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ over-allotment option.

 	 	 	 	 	 	 	 	 	
 	 	Paid by American Midstream Partners, LP(1)	
 	 	No Exercise	 	Full Exercise	
 		
Per common unit	 	$	     	 	 	$	     	 	
Total	 	$	 	 	 	$		 	

 

			
(1)		Excludes a structuring fee of $      million, or $      million if the underwriters exercise their over-allotment option in full, payable by us to Citigroup Global Markets, Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated.	

We will pay a structuring fee equal to 0.75% of the gross proceeds of this offering, including the gross proceeds from any exercise of the underwriters’ over-allotment option, to Citigroup Global Markets Inc. and Merrill, Lynch, Pierce, Fenner & Smith Incorporated. This structuring fee will compensate Citigroup Global Markets Inc. and Merrill, Lynch, Pierce, Fenner & Smith Incorporated for providing advice regarding the capital structure of our partnership, the terms of the offering, the terms of our partnership agreement and the terms of certain other agreements between us and our affiliates.

 
We estimate that our total expenses for this offering will be approximately $3.3 million.

In connection with the offering, the underwriters may purchase and sell common units in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the over-allotment option, and stabilizing purchases.

 	• 	Short sales involve secondary market sales by the underwriters of a greater number of common units than they are required to purchase in the offering.	

 	• 	“Covered” short sales are sales of common units in an amount up to the number of common units represented by the underwriters’ over-allotment option.	
 		
 	• 	“Naked” short sales are sales of common units in an amount in excess of the number of common units represented by the underwriters’ over-allotment option.	

 	• 	Covering transactions involve purchases of common units either pursuant to the over-allotment option or in the open market after the distribution has been completed in order to cover short positions.	

 	• 	To close a naked short position, the underwriters must purchase common units in the open market after the distribution has been completed. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.	
 		
 	• 	To close a covered short position, the underwriters must purchase common units in the open market after the distribution has been completed or must exercise the over-allotment option. In determining the source of common units to close the covered short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the over-allotment option.	

 	• 	Stabilizing transactions involve bids to purchase common units so long as the stabilizing bids do not exceed a specified maximum.	

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the New York Stock Exchange, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

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The underwriters have performed commercial banking, investment banking and advisory services for us from time to time for which they have received customary fees and reimbursement of expenses. The underwriters may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. Additionally, affiliates of certain of the underwriters will serve as lenders under our new credit facility.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

Because the Financial Industry Regulatory Authority views our common units as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA rules. Investor suitability with respect to the common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Offering Price Determination
 
Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the common units was determined by negotiations among us and the representatives. Among the factors considered in determining the initial public offering price were our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our partnership. We cannot assure you, however, that the price at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.
 
Notice to Prospective Investors in the European Economic Area
 
In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

 	• 	to any legal entity that is a qualified investor as defined in the Prospectus Directive;	
 		
 	• 	to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the Representatives; or	
 		
 	• 	in any other circumstances falling within Article 3(2) of the Prospectus Directive,	
 
provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.
 
For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the Directive 2010/73/EU, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state, and the expression “2010 PD Amending Directive” means Directive 2010/73/EU.
 
We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of

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the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.
 
Notice to Prospective Investors in the Dubai International Financial Centre
 
This prospectus relates to an Exempt Offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority (“DFSA”). This prospectus is intended for distribution only to persons of a type specified in the Offered Securities Rules of the DFSA. It must not be delivered to, or relied on by, any other person. The DFSA has no responsibility for reviewing or verifying any documents in connection with Exempt Offers. The DFSA has not approved this prospectus nor taken steps to verify the information set forth herein and has no responsibility for the prospectus. The shares to which this prospectus relates may be illiquid and/or subject to restrictions on their resale. Prospective purchasers of the shares offered should conduct their own due diligence on the shares. If you do not understand the contents of this prospectus you should consult an authorized financial advisor.
 
Notice to Prospective Investors in the United Kingdom
 
Our partnership may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000, or FSMA, that is not a “recognised collective investment scheme” for the purposes of FSMA, or CIS, and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and are only directed at:
 
(i) if our partnership is a CIS and is marketed by a person who is an authorised person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) Order 2001, as amended (the “CIS Promotion Order”) or (b) high net worth companies and other persons falling with Article 22(2)(a) to (d) of the CIS Promotion Order; or
 
(ii) otherwise, if marketed by a person who is not an authorised person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Financial Promotion Order”) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and
 
(iii) in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as “relevant persons”). Our partnership’s common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.
 
An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to our partnership.
 
Notice to Prospective Investors in Germany
 
This prospectus has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act ( Wertpapierprospektgesetz ), the German Sales Prospectus Act ( Verkaufsprospektgesetz ), or the German Investment Act ( Investmentgesetz ). Neither the German Federal Financial Services Supervisory Authority ( Bundesanstalt für Finanzdienstleistungsaufsicht-BaFin ) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this prospectus and any other document relating to this offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of the common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified

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investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This prospectus is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.
 
This offering of our common units does not constitute an offer to buy or the solicitation or an offer to sell our common units in any circumstances in which such offer or solicitation is unlawful.
 
Notice to Prospective Investors in the Netherlands
 
Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors ( gekwalificeerde beleggers ) within the meaning of Article 1:1 of the Dutch Financial Supervision Act ( Wet op het financieel toezicht ).
 
Notice to Prospective Investors in Switzerland
 
This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. Our common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be distributed in connection with any such public offering.
 
We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006, or CISA. Accordingly, our common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be made available through a public offering in or from Switzerland. Our common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

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VALIDITY OF THE COMMON UNITS
 
The validity of the common units offered hereby will be passed upon for us by Andrews Kurth LLP, Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.
 
EXPERTS
 
The consolidated financial statements of American Midstream Partners, LP and subsidiaries as of and for the year ended December 31, 2010 and as of December 31, 2009 and for the period from August 20, 2009 to December 31, 2009 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in accounting and auditing.
 
The combined financial statements of American Midstream Partners Predecessor as of October 31, 2009 and for the ten-month period ended October 31, 2009 and as of and for the year ended December 31, 2008 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in accounting and auditing.
 
WHERE YOU CAN FIND MORE INFORMATION
 
We have filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered in this prospectus, you may desire to review the full registration statement, including the exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549 at prescribed rates or from the SEC’s web site on the Internet at http://www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on public reference rooms.

As a result of the offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website is located at http://www.americanmidstream.com, and we expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. Our annual report will contain a detailed statement of any transactions with our general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed. We also intend to furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.
 
FORWARD-LOOKING STATEMENTS
 
Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “will,” “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of financial condition or of results of operations, or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

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INDEX TO FINANCIAL STATEMENTS

 	 	 	 	 	
 	 	Page	
 		
American Midstream Partners, LP	 	 	 	 	
Historical Unaudited Consolidated Financial Statements as of and for the Three Months Ended March 31, 2010 and March 31, 2011	 	 	 	 	
Unaudited Consolidated Balance Sheets	 	 	F-2	 	
Unaudited Consolidated Statements of Operations	 	 	F-3	 	
Unaudited Consolidated Statements of Changes in Partners’ Capital	 	 	F-4	 	
Unaudited Consolidated Statements of Cash Flows	 	 	F-5	 	
Notes to Unaudited Consolidated Financial Statements	 	 	F-6	 	
Historical Consolidated Financial Statements as of December 31, 2009 and 2010 and for the Period From August 20, 2009 (Inception Date) to December 31, 2009 and the Year Ended December 31, 2010	 	 	 	 	
Report of Independent Registered Public Accounting Firm	 	 	F-20	 	
Consolidated Balance Sheets	 	 	F-21	 	
Consolidated Statements of Operations	 	 	F-22	 	
Consolidated Statements of Changes in Partners’ Capital	 	 	F-23	 	
Consolidated Statements of Cash Flows	 	 	F-24	 	
Notes to Consolidated Financial Statements	 	 	F-25	 	
American Midstream Partners Predecessor	 	 	 	 	
Historical Combined Financial Statements as of December 31, 2008 and October 31, 2009 and for the Year Ended December 31, 2008 and the Ten Months Ended October 31, 2009	 	 	 	 	
Report of Independent Registered Public Accounting Firm	 	 	F-50	 	
Combined Balance Sheets	 	 	F-51	 	
Combined Statements of Operations	 	 	F-52	 	
Combined Statements of Group Equity	 	 	F-53	 	
Combined Statements of Cash Flows	 	 	F-54	 	
Notes to Combined Financial Statements	 	 	F-55	 	

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American Midstream Partners, LP and Subsidiaries
 
 Unaudited Consolidated Balance Sheets
 December 31, 2010 and March 31, 2011

 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	Pro Forma	 	
 	 	 	 	 	 	 	 	March 31,	 	
 	 	December 31,	 	 	March 31,	 	 	2011	 	
 	 	2010	 	 	2011	 	 	(note 1)	 	
 	 	(in thousands)	 	
 		
Assets	 	 	 	 	 	 	 	 	 	 	 	 	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	63	 	 	$	153	 	 	$	153	 	
Accounts receivable, net	 	 	656	 	 	 	1,490	 	 	 	1,490	 	
Unbilled revenue	 	 	22,194	 	 	 	20,758	 	 	 	20,758	 	
Risk management assets	 	 	—	 	 	 	174	 	 	 	174	 	
Other current assets	 	 	1,523	 	 	 	1,948	 	 	 	1,948	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total current assets	 	 	24,436	 	 	 	24,523	 	 	 	24,523	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, plant and equipment, net	 	 	146,808	 	 	 	143,394	 	 	 	143,394	 	
Other assets	 	 	1,985	 	 	 	1,776	 	 	 	1,776	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total assets	 	$	173,229	 	 	$	169,693	 	 	$	169,693	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Liabilities and Partners’ Capital	 	 	 	 	 	 	 	 	 	 	 	 	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
Accounts payable	 	$	980	 	 	$	1,105	 	 	$	1,105	 	
Accrued gas purchases	 	 	18,706	 	 	 	17,599	 	 	 	17,599	 	
Dividend payable	 	 	—	 	 	 	—	 	 	 	30,000	 	
Current portion of long-term debt	 	 	6,000	 	 	 	7,000	 	 	 	7,000	 	
Other loans	 	 	615	 	 	 	463	 	 	 	463	 	
Risk management liabilities	 	 	—	 	 	 	3,079	 	 	 	3,079	 	
Accrued expenses and other current liabilities	 	 	2,676	 	 	 	3,644	 	 	 	3,644	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total current liabilities	 	 	28,977	 	 	 	32,890	 	 	 	62,890	 	
Other liabilities	 	 	8,078	 	 	 	8,338	 	 	 	8,338	 	
Long-term debt	 	 	50,370	 	 	 	49,500	 	 	 	49,500	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total liabilities	 	 	87,425	 	 	 	90,728	 	 	 	120,728	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Commitments and contingencies (see Note 10)	 	 	 	 	 	 	 	 	 	 	 	 	
Partners’ capital	 	 	 	 	 	 	 	 	 	 	 	 	
General partner interest (0.2 million units outstanding as of December 31, 2010 and March 31, 2011 and 0.1 million on a pro forma basis as of March 31, 2011)	 	 	2,124	 	 	 	1,998	 	 	 	1,404	 	
Limited partner interest (11.0 million and 11.1 million units outstanding as of December 31, 2010 and March 31, 2011, respectively and 0.9 million on a pro forma basis as of March 31, 2011)	 	 	83,624	 	 	 	76,911	 	 	 	7,535	 	
Subordinated units (4.5 million outstanding on a pro forma basis as of March 31, 2011)	 	 	—	 	 	 	—	 	 	 	39,970	 	
Accumulated other comprehensive income	 	 	56	 	 	 	56	 	 	 	56	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total partners’ capital	 	 	85,804	 	 	 	78,965	 	 	 	48,965	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total liabilities and partners’ capital	 	$	173,229	 	 	$	169,693	 	 	$	169,693	 	

 
The accompanying notes are an integral part of these consolidated financial statements.

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American Midstream Partners, LP and Subsidiaries
 
Unaudited Consolidated Statements of Operations
 For the Three Months Ended March 31, 2010 and 2011

 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended March 31,	 	
 	 	2010	 	 	2011	 	
 	 	(in thousands)	 	
 		
Revenue	 	$	54,712	 	 	$	67,265	 	
Unrealized gain (loss) on commodity derivatives	 	 	—	 	 	 	(3,500	)	
Total revenue	 	 	54,712	 	 	 	63,765	 	
 	 	 	 	 	 	 	 	 	
Operating expenses:	 	 	 	 	 	 	 	 	
Purchases of natural gas, NGLs and condensate	 	 	44,964	 	 	 	54,953	 	
Direct operating expenses	 	 	2,692	 	 	 	3,058	 	
Selling, general and administrative expenses	 	 	2,113	 	 	 	2,675	 	
One-time transaction costs	 	 	74	 	 	 	288	 	
Depreciation expense	 	 	4,966	 	 	 	5,037	 	
 	 	 	 	 	 	 	 	 	
Total operating expenses	 	 	54,809	 	 	 	66,011	 	
 	 	 	 	 	 	 	 	 	
Operating income (loss)	 	 	(97	)	 	 	(2,246	)	
Other expenses (income):	 	 	 	 	 	 	 	 	
Interest expense	 	 	1,357	 	 	 	1,264	 	
 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	(1,454	)	 	$	(3,510	)	
 	 	 	 	 	 	 	 	 	
General partner’s interest in net income (loss)	 	 	(29	)	 	 	(70	)	
 	 	 	 	 	 	 	 	 	
Limited partners’ interest in net income (loss)	 	$	(1,425	)	 	$	(3,440	)	
 	 	 	 	 	 	 	 	 	
Limited partners’ net income (loss) per common unit (See Note 13)	 	$	(0.14	)	 	$	(0.30	)	
 	 	 	 	 	 	 	 	 	
Weighted average number of common units used in computation of limited partners’ net income (loss) per common unit	 	 	10,202	 	 	 	11,473	 	
 	 	 	 	 	 	 	 	 	
Pro forma earnings per common and subordinated units (See Note 1)	 	 	 	 	 	$	(0.61	)	
Pro forma weighted average common and subordinated units outstanding (See Note 1)	 	 	 	 	 	 	5,668	 	

 
The accompanying notes are an integral part of these consolidated financial statements.

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American Midstream Partners, LP and Subsidiaries

Unaudited Consolidated Statements of Changes in Partners’ Capital for the
 Three Months Ended March 31, 2010 and March 31, 2011

 	 	 	 	 	 	 	 	 	 	 	 	 	 	Accumulated	 	 	 	 	
 	 	Limited	 	 	Limited	 	 	General	 	 	General	 	 	Other	 	 	 	 	
 	 	Partner	 	 	Partner	 	 	Partner	 	 	Partner	 	 	Comprehensive	 	 	 	 	
 	 	Units	 	 	Interest	 	 	Units	 	 	Interest	 	 	Income	 	 	Total	 	
 	 	 	 	 	 	 	 	(in thousands)	 	 	 	 	 	 	 	
 		
Balances at December 31, 2009	 	 	9,800	 	 	$	91,148	 	 	 	200	 	 	$	2,010	 	 	$	46	 	 	$	93,204	 	
Net income (loss)	 	 	—	 	 	 	(1,425	)	 	 	—	 	 	 	(29	)	 	 	—	 	 	 	(1,454	)	
Unit based compensation	 	 	—	 	 	 	—	 	 	 	—	 	 	 	254	 	 	 	—	 	 	 	254	 	
Adjustments to other post retirement plan assets and liabilities	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balances at March 31, 2010	 	 	9,800	 	 	$	89,723	 	 	 	200	 	 	$	2,235	 	 	$	46	 	 	$	92,004	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balances at December 31, 2010	 	 	11,049	 	 	$	83,624	 	 	 	224	 	 	$	2,124	 	 	$	56	 	 	$	85,804	 	
Net income (loss)	 	 	—	 	 	 	(3,440	)	 	 	—	 	 	 	(70	)	 	 	—	 	 	 	(3,510	)	
Unitholder distributions	 	 	—	 	 	 	(3,591	)	 	 	—	 	 	 	(73	)	 	 	—	 	 	 	(3,664	)	
LTIP vesting	 	 	32	 	 	 	318	 	 	 	—	 	 	 	(318	)	 	 	—	 	 	 	—	 	
Unit based compensation	 	 	—	 	 	 	—	 	 	 	—	 	 	 	335	 	 	 	—	 	 	 	335	 	
Adjustments to other post retirement benefit plan assets and liabilities	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balances at March 31, 2011	 	 	11,081	 	 	$	76,911	 	 	 	224	 	 	$	1,998	 	 	$	56	 	 	$	78,965	 	

 
The accompanying notes are an integral part of these consolidated financial statements.

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American Midstream Partners, LP and Subsidiaries
 
Unaudited Consolidated Statements of Cash Flows
 Three Months Ended March 31, 2010 and 2011

 	 	Three Months Ended March 31,	 	
 	 	2010	 	 	2011	 	
 	 	(in thousands)	 	
 		
Cash flows from operating activities	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	(1,454	)	 	$	(3,510	)	
Adjustments to reconcile change in net assets to net cash used in operating activities:	 	 	 	 	 	 	 	 	
Depreciation expense	 	 	4,966	 	 	 	5,037	 	
Amortization of deferred financing costs	 	 	198	 	 	 	197	 	
Mark to market on derivatives	 	 	20	 	 	 	3,500	 	
Unit based compensation	 	 	254	 	 	 	335	 	
Changes in operating assets and liabilities:	 	 	 	 	 	 	 	 	
Accounts receivable	 	 	(219	)	 	 	(834	)	
Unbilled revenue	 	 	2,549	 	 	 	1,436	 	
Risk management assets	 	 	—	 	 	 	(670	)	
Other current assets	 	 	(304	)	 	 	(425	)	
Other assets	 	 	(160	)	 	 	12	 	
Accounts payable	 	 	(1,620	)	 	 	125	 	
Accrued gas purchase	 	 	(2,482	)	 	 	(1,107	)	
Accrued expenses and other current liabilities	 	 	512	 	 	 	968	 	
Risk management liabilities	 	 	—	 	 	 	75	 	
Other liabilities	 	 	63	 	 	 	(72	)	
 	 	 	 	 	 	 	 	 	
Net cash provided (used) in operating activities	 	 	2,323	 	 	 	5,067	 	
 	 	 	 	 	 	 	 	 	
Cash flows from investing activities	 	 	 	 	 	 	 	 	
Additions to property, plant and equipment	 	 	(494	)	 	 	(1,291	)	
 	 	 	 	 	 	 	 	 	
Net cash used in investing activities	 	 	(494	)	 	 	(1,291	)	
 	 	 	 	 	 	 	 	 	
Cash flows from financing activities	 	 	 	 	 	 	 	 	
Unit holder distributions	 	 	—	 	 	 	(3,664	)	
Payments on other loan	 	 	(268	)	 	 	(152	)	
Borrowings on long-term debt	 	 	2,500	 	 	 	21,300	 	
Payments on long-term debt	 	 	(5,120	)	 	 	(21,170	)	
 	 	 	 	 	 	 	 	 	
Net cash provided (used) by financing activities	 	 	(2,888	)	 	 	(3,686	)	
 	 	 	 	 	 	 	 	 	
Net increase (decrease) in cash and cash equivalents	 	 	(1,059	)	 	 	90	 	
Cash and cash equivalents	 	 	 	 	 	 	 	 	
Beginning of period	 	 	1,149	 	 	 	63	 	
 	 	 	 	 	 	 	 	 	
End of period	 	$	90	 	 	$	153	 	
 	 	 	 	 	 	 	 	 	
Supplemental cash flow information	 	 	 	 	 	 	 	 	
Interest payments	 	$	1,198	 	 	$	1,054	 	

The accompanying notes are an integral part of these consolidated financial statements.

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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
Notes to Unaudited Consolidated Financial Statements
December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011

1.  	Summary of Significant Accounting Policies	
 
Nature of Business
 
American Midstream Partners, LP (the “Partnership”) was formed on August 20, 2009 (“date of inception”) as a Delaware limited partnership for the purpose of acquiring and operating certain natural gas pipeline and processing businesses. We provide natural gas gathering, treating, processing, marketing and transportation services in the Gulf Coast and Southeast regions of the United States. We hold our assets in a series of wholly owned limited liability companies as well as a limited partnership. Our capital accounts consist of general partner interests and limited partner interests.
 
We are controlled by our general partner, American Midstream GP, LLC, which is a wholly owned subsidiary of AIM Midstream Holdings, LLC.
 
Our interstate natural gas pipeline assets transport natural gas through Federal Energy Regulatory Commission (the “FERC”) regulated interstate natural gas pipelines in Louisiana, Mississippi, Alabama and Tennessee. Our interstate pipelines include:

 	• 	American Midstream (Midla), LLC, which owns and operates approximately 370 miles of interstate pipeline that runs from the Monroe gas field in northern Louisiana south through Mississippi to Baton Rouge, Louisiana.	
 		
 	• 	American Midstream (AlaTenn), LLC, which owns and operates more than approximately 295 miles of interstate pipeline that runs through the Tennessee River Valley from Selmer, Tennessee to Huntsville, Alabama and serves an eight county area in Alabama, Mississippi and Tennessee.	
 
Basis of Presentation
 
These unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include disclosures required by GAAP for annual periods. The unaudited consolidated financial statements for the three months ended March 31, 2010 and 2011 include all adjustments and disclosures that we believe are necessary for a fair statement of the results for the interim periods.
 
Our financial results for the three months ended March 31, 2010 and 2011 are not necessarily indicative of the results that may be expected for the full years ending December 31, 2010 and 2011. These unaudited consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this registration statement.

 
The unaudited pro forma consolidated balance sheet as of March 31, 2001 gives effect to:

 
			
 	• 	the accrual of distributions payable to unitholders of record as of May 27, 2011 and our general partner, in each case in connection with our proposed initial public offering (see Note 14) and as if such distributions had been declared effective as of March 31, 2011; and	

 
			
 	• 	the following recapitalization transactions (the “Recapitalization Transactions”) as if they had occurred as of March 31, 2011:	

 
			
 	• 	each general partner unit held by our general partner is reverse split into 0.485 general partner units, resulting in the ownership by our general partner of an aggregate of 108,718 general partner units, representing a 2.0% general partner interest in us;	

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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
Notes to Unaudited Consolidated Financial Statements
December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

 
			
 	• 	each common unit held by participants in our Long-Term Incentive Plan, or LTIP, is reverse split into 0.485 common units, resulting in their ownership of an aggregate of 50,946 common units, representing an aggregate 0.9% limited partner interest in us;	

 
			
 	• 	each outstanding phantom unit granted to participants in our LTIP is reverse split into 0.485 phantom units, resulting in their holding an aggregate of 209,824 phantom units;	

 
			
 	• 	each common unit held by AIM Midstream Holdings is reverse split into 0.485 common units, resulting in the ownership by AIM Midstream Holdings of an aggregate of 5,327,205 common units, representing an aggregate 97.1% limited partner interest in us; and	

 
			
 	• 	the common units held by AIM Midstream Holdings are converted into 801,139 common units and 4,526,066 subordinated units.	

Revenue Recognition and the Estimation of Revenues and Cost of Natural Gas
 
We recognize revenue when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured. We record revenue and cost of product sold on a gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that are purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating or transportation, we record those fees separately in revenues. For the three months ended March 31, 2010 and 2011, respectively, the Partnership had the following revenues by category:

 	 	Three Months Ended March 31,	 	
 	 	2010	 	 	2011	 	
 	 	(in thousands)	 	
 		
Revenue	 	 	 	 	 	 	 	 	
Transportation — firm	 	$	3,376	 	 	$	3,318	 	
Transportation — interruptible	 	 	666	 	 	 	965	 	
Sales of natural gas, NGLs and condensate	 	 	50,660	 	 	 	62,822	 	
Other	 	 	10	 	 	 	160	 	
Unrealized losses on commodity derivatives	 	 	—	 	 	 	(3,500	)	
 	 	 	 	 	 	 	 	 	
Total revenue	 	$	54,712	 	 	$	63,765	 	

 
Limited Partners’ Net Income Per Unit
 
We compute Limited Partners’ Net Income per Unit by dividing our limited partners’ interest in net income by the weighted average number of units outstanding during the period. The overall computation, presentation and disclosure requirements for our Limited Partners’ Net Income per Unit are made in accordance with the “Earnings per Share” Topic of the Codification.

Earnings Per Common Unit

 
The pro forma earnings per common unit provides supplemental information in connection with our proposed initial public offering (see Note 14). The pro forma earnings per common unit gives effect to the Recapitalization Transactions as of March 31, 2011 and the additional number of common units issued in this offering (at an assumed offering price of $20.00) necessary to pay the portion of the dividend that will be funded from the proceeds of this offering that exceeds net income for the three months ended March 31, 2011.

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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
Notes to Unaudited Consolidated Financial Statements
December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

2.  	Acquisition	
 
On October 2, 2009, American Midstream, LLC, a wholly owned subsidiary, entered into a purchase and sale agreement to acquire certain pipeline businesses from Enbridge Midcoast Energy, L.P., for an aggregate purchase price of approximately $150.8 million. The acquisition was effective as of November 1, 2009. Prior to the acquisition, we had no operating tangible assets.
 
The acquired businesses were renamed as follows:
 
American Midstream (Alabama Intrastate), LLC
American Midstream (Bamagas Intrastate), LLC
American Midstream (Tennessee River), LLC
American Midstream (Mississippi), LLC
American Midstream (Midla), LLC
American Midstream (Alabama Gathering), LLC
American Midstream (AlaTenn), LLC
American Midstream Onshore Pipelines, LLC
Mid Louisiana Gas Transmission, LLC
American Midstream Offshore (Seacrest), LP
American Midstream (SIGCO Intrastate), LLC
American Midstream (Louisiana Intrastate), LLC
 
The acquisition qualifies as a business combination and, as such, the Partnership estimated the fair value of each property as of the acquisition date (the date on which the Partnership obtained control of the properties). The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements also utilize assumptions of market participants. The Partnership used a discounted cash flow model and made market assumptions as to future commodity prices, expectations for timing and amount of future development and operating costs, projections of future rates of production and risk adjusted discount rates. These assumptions represent Level 3 inputs.
 
The following table summarizes the consideration paid to the seller and the amounts of the assets acquired and liabilities assumed in the acquisition.

 	 	(in thousands)	 	
 		
Consideration paid to seller	 	 	 	 	
Cash consideration	 	$	150,818	 	
 	 	 	 	 	
Recognized amounts of identifiable assets acquired and liabilities assumed	 	 	 	 	
Property, plant and equipment	 	 	151,085	 	
Other post-retirement benefit plan assets, net	 	 	394	 	
Other liabilities assumed	 	 	(661	)	
 	 	 	 	 	
Total identifiable net assets	 	$	150,818	 	

 
Acquisition costs of $0.07 million and $0.29 million have been recorded in the statements of operations under the caption Transaction costs on acquisitions for the three months ended March 31, 2010 and 2011, respectively.

3.  	Concentration of Credit Risk and Trade Accounts Receivable	
 
Our primary market areas are located in the United States along the Gulf Coast and in the Southeast. We have a concentration of trade receivable balances due from companies engaged in the production, trading,

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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
Notes to Unaudited Consolidated Financial Statements
December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)
 
distribution and marketing of natural gas and NGL products. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. Our customers’ historical financial and operating information is analyzed prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. We maintain allowances for potentially uncollectible accounts receivable. For the period and year ended December 31, 2009 and 2010, no allowances on accounts receivable were recorded.
 
Enbridge Marketing (US) L.P., ConocoPhillips Corporation, ExxonMobil Corporation and Dow Hydrocarbons and Resources were significant customers, representing at least 10% of our consolidated revenue, accounting for $29.5 million, $7.1 million, $0.1 million and $5.7 million, respectively, of our consolidated revenue in the consolidated statement of operations in the three months ended March 31, 2010 and $12.0 million, $28.5 million, $9.6 million and $3.9 million, respectively, for the three months ended March 31, 2011.

4.  	Derivatives	
 
Commodity Derivatives
 
To minimize the effect of a downturn in commodity prices and protect the Partnership’s profitability and the economics of its development plans, the Partnership enters into commodity economic hedge contracts from time to time. The terms of contracts depend on various factors, including management’s view of future commodity prices, acquisition economics on purchased assets and future financial commitments. This hedging program is designed to moderate the effects of a severe commodity price downturn while allowing us to participate in some commodity price increases. Management regularly monitors the commodity markets and financial commitments to determine if, when, and at what level some form of commodity hedging is appropriate in accordance with policies which are established by the board of directors of our general partner. Currently, the commodity hedges are in the form of swaps and puts.
 
The Partnership is required to post collateral with one counterparty in connection with its derivative positions. As of March 31, 2011, the Partnership had posted $0.68 million in collateral. The counterparties are not required to post collateral with us in connection with their derivative positions. Netting agreements are in place with each of the Partnership’s counterparties allowing the Partnership to offset its commodity derivative asset and liability positions.
 
As of March 31, 2011, the notional volumes of our commodity hedges for 2011 were 10.9 million gallons and 7.5 million gallons for 2012.
 
Interest Rate Derivatives
 
The Partnership also utilizes interest rate caps to protect against changes in interest rates on its floating rate debt.
 
At March 31, 2011, the Partnership had $56.5 million outstanding under its credit facility, with interest accruing at a rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates, the Partnership has entered into interest rate caps that mitigate the risk of increases in interest rates. As of March 31, 2011, we had interest rate caps with a notional amount of $25.0 million that effectively fix the base rate on that portion of our debt, with a fixed maximum rate of 4%.
 
For accounting purposes, no derivative instruments were designated as hedging instruments and were instead accounted for under the mark-to-market method of accounting, with any changes in the mark-to-market value of the derivatives recorded in the balance sheets and through earnings, rather than being

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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
Notes to Unaudited Consolidated Financial Statements
December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)
 
deferred until the anticipated transactions affect earnings. The use of mark-to-market accounting for financial instruments can cause noncash earnings volatility due to changes in the underlying commodity prices indices or interest rates.
 
As of December 31, 2010 and March 31, 2011, the fair value associated with the Partnership’s derivative instruments were recorded in our financial statements, under the caption Risk management assets and Risk management liabilities, as follows:

 	 	December 31,	 	 	March 31,	 	
 	 	2010	 	 	2011	 	
 	 	(in thousands)	 	
 		
Risk management assets:	 	 	 	 	 	 	 	 	
Commodity derivatives	 	$	—	 	 	$	174	 	
Interest rate derivatives	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	
 	 	$	—	 	 	$	174	 	
 	 	 	 	 	 	 	 	 	
Risk management liabilities:	 	 	 	 	 	 	 	 	
Commodity derivatives	 	$	—	 	 	$	3,079	 	
Interest rate derivatives	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	
 	 	$	—	 	 	$	3,079	 	

 
We recorded the following mark-to-market losses:

 	 	Three Months Ended March 31,	 	
 	 	2010	 	 	2011	 	
 	 	(in thousands)	 	
 		
Commodity derivatives	 	$	—	 	 	$	(3,500	)	
Interest rate derivatives	 	 	(20	)	 	 	—	 	
 	 	 	 	 	 	 	 	 	
 	 	$	(20	)	 	$	(3,500	)	

 
Fair Value Measurements
 
The Partnership’s interest rate caps and commodity derivatives discussed above were classified as Level 3 derivatives for all periods presented.
 
The table below includes a roll forward of the balance sheet amounts (including the change in fair value) for financial instruments classified by us within Level 3 of the valuation hierarchy. When a determination is made to classify a financial instrument within Level 3 of the valuation hierarchy, the determination is based upon the significance of the unobservable factors to the overall fair value measurement. Level 3 financial instruments typically include, in addition to the unobservable or Level 3 components, observable components (that is, components that are actively quoted and can be validated to external sources).

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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
Notes to Unaudited Consolidated Financial Statements
December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

 	 	Three Months Ended March 31	 	
 	 	2010	 	 	2011	 	
 	 	(in thousands)	 	
 		
Fair value asset (liability), beginning of period	 	$	77	 	 	$	—	 	
Total realized and unrealized (losses) gains included in revenue	 	 	(20	)	 	 	(3,920	)	
Purchases	 	 	—	 	 	 	670	 	
Settlements	 	 	—	 	 	 	345	 	
 	 	 	 	 	 	 	 	 	
Fair value (liability) asset, end of period	 	$	57	 	 	$	(2,905	)	

 
		
5.  	Property, Plant and Equipment, Net	
 
Property, plant and equipment, net, as of December 31, 2010 and March 31, 2011 were as follows:

 	 	 	 	 	December 31,	 	 	March 31,	 	
 	 	Useful Life	 	 	2010	 	 	2011	 	
 	 	 	 	 	(in thousands)	 	
 		
Land	 	 	 	 	 	$	41	 	 	$	41	 	
Buildings and improvements	 	 	4 to 40	 	 	 	2,523	 	 	 	2,527	 	
Processing and treating plants	 	 	8 to 40	 	 	 	11,954	 	 	 	11,955	 	
Pipelines	 	 	5 to 40	 	 	 	143,805	 	 	 	144,784	 	
Compressors	 	 	4 to 20	 	 	 	7,163	 	 	 	7,211	 	
Equipment	 	 	8 to 20	 	 	 	1,711	 	 	 	1,966	 	
Computer software	 	 	5	 	 	 	1,390	 	 	 	1,393	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total property, plant and equipment	 	 	 	 	 	 	168,587	 	 	 	169,877	 	
Accumulated depreciation	 	 	 	 	 	 	(21,779	)	 	 	(26,483	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, plant and equipment, net	 	 	 	 	 	$	146,808	 	 	$	143,394	 	

 
Of the gross property, plant and equipment balances at December 31, 2010 and March 31, 2011, $24.3 million relate to regulated assets.

6.  	Asset Retirement Obligations	
 
We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis, in the period in which the liability is incurred. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO. Typically, we record an ARO at the time the assets are installed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an ARO, we capitalize the costs as part of the carrying value of the related assets. We recognize an ongoing expense for the interest component of the liability as part of depreciation expense resulting from changes in the value of the ARO due to the passage of time. We depreciate the initial capitalized costs over the useful lives of the related assets. We extinguish the liabilities for an ARO when assets are taken out of service or otherwise abandoned.
 
During the year ended December 31, 2010, we recognized $6.1 million of AROs for specific assets that we intend to retire for operational purposes. We recorded accretion expense of $0.28 million and $0.33 million in our consolidated statements of operations for the three months ended March 31, 2010 and 2011, respectively, related to these AROs.
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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
Notes to Unaudited Consolidated Financial Statements
December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)
 
No assets are legally restricted for purposes of settling our ARO during the three months ended March 31, 2010 and 2011. Following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for the three months ended March 31, 2010 and 2011, respectively.

 	 	Three Months Ended	 	
 	 	March 31	 	
 	 	2010	 	 	2011	 	
 	 	(in thousands)	 	
 		
Balance at beginning of period	 	$	—	 	 	$	7,249	 	
Additions	 	 	6,058	 	 	 	—	 	
Expenditures	 	 	—	 	 	 	(7	)	
Accretion expense	 	 	278	 	 	 	332	 	
 	 	 	 	 	 	 	 	 	
Balance at end of period	 	$	6,336	 	 	$	7,574	 	

 
The Partnership did not recognize AROs as of December 31, 2009 given that, at that time, it did not intend to retire any of its existing assets, nor were retirement costs estimable. However, after the Partnership had obtained sufficient operating experience with assets during 2010, it determined certain assets would be retired from an operational perspective.

7.  	Long-Term Debt	
 
On November 4, 2009, we entered into an $85 million secured credit facility (“credit facility”) with a consortium of lending institutions. The credit facility is composed of a $50 million term loan facility and a $35 million revolving credit facility.
 
Our outstanding borrowings under the credit facility at December 31, 2010 and March 31, 2011, respectively, were:

 	 	December 31,	 	 	March 31,	 	
 	 	2010	 	 	2011	 	
 	 	(in thousands)	 	
 		
Term loan facility	 	$	45,000	 	 	$	43,500	 	
Revolving loan facility	 	 	11,370	 	 	 	13,000	 	
 	 	 	 	 	 	 	 	 	
 	 	 	56,370	 	 	 	56,500	 	
Less: Current portion	 	 	6,000	 	 	 	7,000	 	
 	 	 	 	 	 	 	 	 	
 	 	$	50,370	 	 	$	49,500	 	

 
At December 31, 2010 and March 31, 2011, letters of credit outstanding under the credit facility were $0.6 million.
 
The credit facility provides for a maximum borrowing equal to the lesser of (i) $85 million less the required amortization of term loan payments and (ii) 3.50 times adjusted consolidated EBITDA (as defined: $18.8 million at December 31, 2010 and $20.6 million at March 31, 2011). We may elect to have loans under the credit facility bear interest either (i) at a Eurodollar-based rate with a minimum of 2.0% plus a margin ranging from 3.25% to 4.0% depending on our total leverage ratio then in effect, or (ii) at a base rate (the greater of (i) the daily adjusting LIBOR rate and (ii) a Prime-based rate which is equal to the greater of (A) the Prime Rate and (B) an interest rate per annum equal to the Federal Funds Effective Rate in effect that day, plus one percent) plus a margin ranging from 2.25% to 3.00% depending on the total leverage ratio then in effect. We also pay a facility fee of 1.0% per annum. In December 2009, we entered into an interest rate cap with participating lenders with a $25.0 million notional amount at March 31, 2011 that effectively caps

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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
Notes to Unaudited Consolidated Financial Statements
December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)
 
our Eurodollar-based rate exposure on that portion of our debt at a maximum of 4.0%. For the three months ended March 31, 2010 and 2011, the weighted average interest rate on borrowings under our credit facility was approximately 7.82% and 7.80%, respectively.
 
Our obligations under the credit facility are secured by a first mortgage in favor of the lenders in our real property. The terms of the credit facility include covenants that restrict our ability to make cash distributions and acquisitions in some circumstances. The remaining principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date, November 3, 2012.
 
The term loan facility also provides for quarterly principal installment payments as described below:

Year	 	Amount	 	
 	 	(in thousands)	 	
 		
2011	 	$	6,000	 	
2012	 	 	39,000	 	
 	 	 	 	 	
 	 	$	45,000	 	

 
The credit facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the credit facility are (i) a total leverage ratio test (not to exceed 3.50 times) and a minimum interest coverage ratio test (not less than 2.50 times). We were in compliance with all of the covenants under our credit facility as of December 31, 2010 and March 31, 2011.
 
Fair Market Value of Financial Instruments
 
The Partnership used various assumptions and methods in estimating the fair values of its financial instruments. The carrying amounts of cash and cash equivalents and accounts receivable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of the Partnership’s credit facility approximates fair value, because the interest rate on the facility is variable.

8.  	Partners’ Capital	
 
Our capital accounts are comprised of a 2% general partner interest and 98% limited partner interests. Our limited partners have limited rights of ownership as provided for under our partnership agreement and, as discussed below, the right to participate in our distributions. Our general partner manages our operations, and participates in our distributions, including certain incentive distributions pursuant to the incentive distribution rights that are nonvoting limited partner interests held by our general partner.
 
The number of units outstanding were as follows:

 	 	December 31,	 	 	March 31,	 	
 	 	2010	 	 	2010	 	
 	 	(in thousands)	 	
 		
Common units	 	 	11,049	 	 	 	11,081	 	
General partner units	 	 	224	 	 	 	224	 	

Distributions
 
The Partnership made distributions of $0 million and $3.7 million for the three months ended March 31, 2010 and 2011, respectively. The Partnership made no distributions in respect of our general partner’s incentive distribution rights.

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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
Notes to Unaudited Consolidated Financial Statements
December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

9.  	Long-Term Incentive Plan	
 
Our general partner manages our operations and activities and employs the personnel who provide support to our operations. On November 2, 2009, the board of directors of our general partner adopted a long-term incentive plan for its employees and consultants and directors who perform services for it or its affiliates. On May 25, 2010, the board of directors of our general partner adopted an amended and restated long-term incentive plan (as amended, the “LTIP”). The LTIP currently permits the grant of awards in the form of Partnership units, which may include distribution equivalent rights (“DER“s), covering an aggregate of 625,532 of our units. A DER entitles the grantee to a cash payment equal to the cash distribution made by the Partnership with respect to a unit during the period such DER is outstanding. At December 31, 2010 and March 31, 2011, 111,112 and 71,112 units, respectively, were available for future grant under the LTIP.
 
Ownership in the awards is subject to forfeiture until the vesting date. The LTIP is administered by the board of directors of our general partner. The board of directors of our general partner, at its discretion, may elect to settle such vested phantom units with a number of units equivalent to the fair market value at the date of vesting in lieu of cash. Although, our general partner has the option to settle in cash upon the vesting of phantom unit our general partner does not intend to settle these awards in cash.
 
Although other types of awards are contemplated under the LTIP, currently outstanding awards are phantom units with DERs (392,315 at March 31, 2011) and phantom units without DERs (40,000 at March 31, 2011).
 
Grants issued under the LTIP have historically vested in increments of 25% on each of the first four anniversary dates of the date of the grant and do not contain any other restrictive conditions related to vesting other than continued employment.
 
During 2011, the fair value of the grants issued was calculated by the general partner based on several valuation models, including: a DCF model, a comparable company multiple analysis and a comparable recent transaction multiple analysis. As it relates to the DCF model, the model includes certain market assumptions related to future throughput volumes, projected fees and/or prices, expected costs of sales and direct operating costs and risk adjusted discount rates. Both the comparable company analysis and recent transaction analysis contain significant assumptions consistent with the DCF model, in addition to assumptions related to comparability, appropriateness of multiples (primarily based on EBITDA and DCF) and certain assumptions in the calculation of enterprise value.
 
The following table summarizes our unit-based awards for each of the periods indicated, in units:

 	 	Three Months Ended March 31,	 	
 	 	2010	 	 	2011	 	
 		
Outstanding at beginning of period	 	 	361,052	 	 	 	424,157	 	
Granted	 	 	127,368	 	 	 	40,000	 	
Converted	 	 	—	 	 	 	(31,842	)	
 	 	 	 	 	 	 	 	 	
Outstanding at end of period	 	 	488,420	 	 	 	432,315	 	
 	 	 	 	 	 	 	 	 	
Grant date fair value per share	 	$	10.0	 	 	$	10.0 to $13.67	 	

The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our units at each balance sheet date. Compensation costs related to these awards for the three months ended March 31, 2010 and 2011 was $0.25 million and $0.35 million, respectively, which is classified in selling, general and administrative expenses in the consolidated statement of operations and partners’ capital on the consolidated balance sheet.

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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
Notes to Unaudited Consolidated Financial Statements
December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)
 
The total compensation cost related to nonvested awards not yet recognized on December 31, 2010 and March 31, 2011 was $3.9 million and $4.1 million, respectively, and the weighted average period over which this cost is expected to be recognized is approximately 3 years.

10.  	Commitments and Contingencies	
 
We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to natural gas pipeline operations and we could, at times, be subject to environmental cleanup and enforcement actions. We attempt to manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment.
 
Future noncancelable commitments related to certain contractual obligations are presented below:

 	 	Payments Due by Period (in thousands)	 	
 	 	Total	 	 	2011	 	 	2012	 	 	2013	 	 	2014	 	 	2015	 	 	Thereafter	 	
 		
Operating leases and service contract	 	$	2,057	 	 	$	580	 	 	$	405	 	 	$	342	 	 	$	351	 	 	$	349	 	 	$	30	 	
ARO	 	 	8,340	 	 	 	914	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	7,426	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	10,397	 	 	$	1,494	 	 	$	405	 	 	$	342	 	 	$	351	 	 	$	349	 	 	$	7,456	 	

 
Total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements were:

 	 	Three Months Ended March 31,	 	
 	 	2010	 	 	2011	 	
 	 	(in thousands)	 	
 		
Operating leases	 	$	106	 	 	$	250	 	
ARO	 	 	—	 	 	 	7	 	
 	 	 	 	 	 	 	 	 	
 	 	$	106	 	 	$	257	 	

 
		
11.  	Related-Party Transactions	
 
Employees of our general partner are assigned to work for us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by our general partner to American Midstream, LLC which, in turn, charges the appropriate subsidiary. Our general partner does not record any profit or margin for the administrative and operational services charged to us. During the three months ended March 31, 2010 and 2011, administrative and operational services expenses of $0.03 million and $0.02 million, respectively, were allocated to us by our general partner.
 
We have entered into an advisory services agreement with American Infrastructure MLP Management, L.L.C., American Infrastructure MLP PE Management, L.L.C., and American Infrastructure MLP Associates Management, L.L.C., as the advisors. The agreement provides for the payment of $0.3 million in 2010 and annual fees of $0.3 million plus annual increases in proportion to the increase in budgeted gross revenues thereafter. In exchange, the advisors have agreed to provide us services in obtaining equity, debt, lease and acquisition financing, as well as providing other financial, advisory and consulting services. For the three months ended March 31, 2010 and 2011, less than $0.1 million and $0.1 million, respectively, had been recorded to selling, general and administrative expenses under this agreement.

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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
Notes to Unaudited Consolidated Financial Statements
December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

12.  	Reporting Segments	
 
Our operations are located in the United States and are organized into two reporting segments: (1) Gathering and Processing; and (2) Transmission.
 
Gathering and Processing
 
Our Gathering and Processing segment provides “wellhead to market” services to producers of natural gas and oil, which include transporting raw natural gas from the wellhead through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs and selling or delivering pipeline quality natural gas and NGLs to various markets and pipeline systems.
 
Transmission
 
Our Transmission segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, including local distribution companies, or LDCs, utilities and industrial, commercial and power generation customers.
 
These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the business of each segment.
 
The following tables set forth our segment information:

 	 	 	 	 	Gathering	 	 	 	 	
 	 	 	 	 	and	 	 	 	 	
 	 	Transmission	 	 	Processing	 	 	Total	 	
 	 	 	 	 	(in thousands)	 	 	 	 	
 		
Three months ended March 31, 2010	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenue	 	$	8,088	 	 	$	46,624	 	 	$	54,712	 	
Segment gross margin(a)	 	$	3,650	 	 	$	6,098	 	 	$	9,748	 	
Direct operating expenses	 	 	 	 	 	 	 	 	 	 	2,692	 	
Selling, general and administrative expenses	 	 	 	 	 	 	 	 	 	 	2,113	 	
One-time transaction costs	 	 	 	 	 	 	 	 	 	 	74	 	
Depreciation expense	 	 	 	 	 	 	 	 	 	 	4,966	 	
Interest expense	 	 	 	 	 	 	 	 	 	 	1,357	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	 	 	 	 	 	 	 	 	$	(1,454	)	

 

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American Midstream Partners, LP and Subsidiaries
 
Notes to Unaudited Consolidated Financial Statements
December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

 	 	 	 	 	Gathering	 	 	 	 	
 	 	 	 	 	and	 	 	 	 	
 	 	Transmission	 	 	Processing	 	 	Total	 	
 	 	 	 	 	(in thousands)	 	 	 	 	
 		
Three months ended March 31, 2011	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenue	 	$	19,181	 	 	$	48,084	 	 	$	63,765	 	
Segment gross margin(a)(b)	 	$	4,145	 	 	$	8,167	 	 	$	12,312	 	
Unrealized losses included in revenue	 	 	—	 	 	 	(3,500	)	 	 	(3,500	)	
Direct operating expenses	 	 	 	 	 	 	 	 	 	 	3,058	 	
Selling, general and administrative expenses	 	 	 	 	 	 	 	 	 	 	2,675	 	
One-time transaction costs	 	 	 	 	 	 	 	 	 	 	288	 	
Depreciation expense	 	 	 	 	 	 	 	 	 	 	5,037	 	
Interest expense	 	 	 	 	 	 	 	 	 	 	1,264	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	 	 	 	 	 	 	 	 	$	(3,510	)	

 

			
(a)		Segment gross margin for our Gathering and Processing segment consists of total revenue less purchases of natural gas, NGLs and condensate. Segment gross margin for our Transmission segment consists of total revenue, less purchases of natural gas. Gross margin consists of the sum of the segment gross margin amounts for each of these segments. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow from operations as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.	
 		
(b)		Unrealized gains (losses) from derivative mark-to-market adjustments is included in total revenue and segment gross margin in our Gathering and Processing segment for the three months ended March 31, 2010. Effective January 1, 2011, we changed our gross margin and segment gross margin measure to exclude unrealized non cash mark-to-market adjustments related to our commodity derivatives. There were no such adjustments for the three months ended March 31, 2010 and $3.5 in unrealized losses were excluded from segment gross margin for the three months ended March 31, 2011.	
 
Asset information including capital expenditures, by segment is not included in reports used by our management in its monitoring of performance and therefore, is not disclosed.
 
For the purposes of our Transmission segment, for the three months ended March 31, 2010 and 2011, Enbridge Marketing (US) L.P., ExxonMobil Corporation and Calpine Corporation represented significant customers, each representing more than 10% of our segment revenue in this segment. Our segment revenue derived from Enbridge Marketing (US) L.P., ExxonMobil Corporation and Calpine Corporation represented $5.4 million, $0.1 million and $0.8 million of segment revenue for the three months ended March 31, 2010 and $4.4 million, $9.6 million and $0.8 million for the three months ended March 31, 2011, respectively.
 
For the purposes of our Gathering and Processing segment, for the three months ended March 31, 2010 and 2011, Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented significant customers, each representing more than 10% of our segment revenue in this segment. Our segment revenue derived from Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented $24.1 million, $7.1 million and $5.7 million of segment revenue for the three months ended March 31, 2010 and $7.6 million, $28.5 million and $3.9 million for the three months ended March 31, 2011, respectively.
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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
Notes to Unaudited Consolidated Financial Statements
December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

13.  	Net Income (Loss) per Limited and General Partner Unit	
 
Net Income per Limited Partner Unit.   Net income is allocated to the general partner and the limited partners (common unitholders) in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income by the weighted average number of outstanding limited partner units during the period.
 
Unvested share-based payment awards that contain non-forfeitable rights to distributions (whether paid or unpaid) are classified as participating securities and are included in our computation of basic and diluted net income per limited partner unit.
 
We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.
 
The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit. We have no dilutive securities, therefore basic and diluted net income per unit are the same.
 
We determined basic and diluted net income per general partner unit and limited partner unit as follows:

 	 	 	 	 	 	 	 	 	
 	 	For the Three Months Ended March 31,	 	
 	 	2010	 	 	2011	 	
 	 	(in thousands, except per unit amounts)	 	
 		
Net loss attributable to general partner and limited partners	 	$	(1,454	)	 	$	(3,510	)	
Weighted average general partner and limited partner units outstanding(a)	 	 	10,402	 	 	 	11,697	 	
Earnings per general partner and limited partner unit (basic and diluted)	 	$	(0.14	)	 	$	(0.30	)	
Net loss attributable to limited partners	 	$	(1,425	)	 	$	(3,440	)	
Weighted average limited partner units outstanding(a)	 	 	10,202	 	 	 	11,473	 	
Earnings per limited partner unit (basic and diluted)	 	$	(0.14	)	 	$	(0.30	)	
Net loss attributable to general partner	 	$	(29	)	 	$	(70	)	
Weighted average general partner units outstanding	 	 	200	 	 	 	224	 	
Earnings per general partner unit (basic and diluted)	 	$	(0.15	)	 	$	(0.31	)	

 

 
			
(a)		Includes unvested phantom units, which are considered participating securities, of 424,157 and 392,315 as of December 31, 2010 and March 31, 2011, respectively.	

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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
Notes to Unaudited Consolidated Financial Statements
December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

14.  	Subsequent Events	

The Partnership has evaluated subsequent events through June 9, 2011:

 
On March 31, 2011, we filed a registration statement with the Securities and Exchange Commission relating to a proposed public offering of shares of our common units (the “IPO”), and have from time to time thereafter amended such registration statement. The registration statement, as amended, reflects our intentions to use a portion of the net proceeds of the offering and borrowings under our new credit facility to make a special distribution to pre-offering unitholders of record and our general partner. At an assumed offering price of $20.00 per common unit, the aggregate distribution to those unitholders and our general partner would be approximately $30.1 million.

 
On May 4, 2011, the Board of Directors of our general partner approved a distribution in the amount of $3.7 million, consisting of $3.6 million to the limited partners and $0.1 million to the general partner, as well as a payment of $0.1 million in respect of DERs outstanding and $0.1 million in DER payments.

 
On June 2, 2011, our Board of Directors determined that we would gain operational and strategic flexibility from cancelling our then-existing swap contracts that we entered into in January 2011. In conjunction with un-winding and cancelling these contracts, we entered into new swap contracts that extend through the end of 2012. We did not modify the put contracts we entered into through our January 2011 hedge transactions.

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Table of Contents

Report of Independent Registered Public Accounting Firm
 
To the Board of Directors of the General Partner of
American Midstream Partners, LP
 
We have audited the accompanying consolidated balance sheets of American Midstream Partners, LP and its subsidiaries as of December 31, 2009 and 2010, and the related consolidated statements of operations, of changes in partners’ capital and of cash flows for the period from August 20, 2009 (inception date) to December 31, 2009 and year ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Midstream Partners, LP and its subsidiaries at December 31, 2009 and 2010, and the results of their operations and their cash flows for the period from August 20, 2009 (inception date) to December 31, 2009 and year ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.
 
/s/ PricewaterhouseCoopers LLP
 
Denver, Colorado
March 30, 2011

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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
 Consolidated Balance Sheets
 December 31, 2009 and 2010

 	 	December 31,	 	
 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Assets	 	 	 	 	 	 	 	 	
Current assets	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	1,149	 	 	$	63	 	
Accounts receivable, net	 	 	1,447	 	 	 	656	 	
Unbilled revenue	 	 	18,329	 	 	 	22,194	 	
Other current assets	 	 	1,523	 	 	 	1,523	 	
 	 	 	 	 	 	 	 	 	
Total current assets	 	 	22,448	 	 	 	24,436	 	
 	 	 	 	 	 	 	 	 	
Property, plant and equipment, net	 	 	149,266	 	 	 	146,808	 	
Other assets	 	 	2,679	 	 	 	1,985	 	
Risk management assets	 	 	77	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	
Total assets	 	$	174,470	 	 	$	173,229	 	
 	 	 	 	 	 	 	 	 	
Liabilities and Partners’ Capital	 	 	 	 	 	 	 	 	
Current liabilities	 	 	 	 	 	 	 	 	
Accounts payable	 	$	1,934	 	 	$	980	 	
Accrued gas purchases	 	 	14,881	 	 	 	18,706	 	
Current portion of long-term debt	 	 	5,000	 	 	 	6,000	 	
Other loans	 	 	815	 	 	 	615	 	
Accrued expenses and other current liabilities	 	 	2,237	 	 	 	2,676	 	
 	 	 	 	 	 	 	 	 	
Total current liabilities	 	 	24,867	 	 	 	28,977	 	
Other liabilities	 	 	399	 	 	 	8,078	 	
Long-term debt	 	 	56,000	 	 	 	50,370	 	
 	 	 	 	 	 	 	 	 	
Total liabilities	 	 	81,266	 	 	 	87,425	 	
 	 	 	 	 	 	 	 	 	
Commitments and contingencies (see Note 16)	 	 	 	 	 	 	 	 	
Partners’ capital	 	 	 	 	 	 	 	 	
General partner interest (0.2 million units outstanding as of December 31, 2010 and 2009)	 	 	2,010	 	 	 	2,124	 	
Limited partner interest (9.8 million and 11.0 million units outstanding as of December 31, 2010 and 2009, respectively)	 	 	91,148	 	 	 	83,624	 	
Accumulated other comprehensive income	 	 	46	 	 	 	56	 	
 	 	 	 	 	 	 	 	 	
Total partners’ capital	 	 	93,204	 	 	 	85,804	 	
 	 	 	 	 	 	 	 	 	
Total liabilities and partners’ equity	 	$	174,470	 	 	$	173,229	 	

 
The accompanying notes are an integral part of these consolidated financial statements.

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Table of Contents

American Midstream Partners, LP and Subsidiaries
 
 Consolidated Statements of Operations
 Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010

 	 	 	 	 	 	 	 	 	
 	 	Period from	 	 	 	 	
 	 	August 20,	 	 	 	 	
 	 	2009	 	 	 	 	
 	 	(Inception Date)	 	 	 	 	
 	 	to	 	 	Year Ended	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Total revenue	 	$	32,833	 	 	$	211,940	 	
Operating expenses:	 	 	 	 	 	 	 	 	
Purchases of natural gas, NGLs and condensate	 	 	26,593	 	 	 	173,821	 	
Direct operating expenses	 	 	1,594	 	 	 	12,187	 	
Selling, general and administrative expenses	 	 	1,346	 	 	 	8,854	 	
One-time transaction costs	 	 	6,404	 	 	 	303	 	
Depreciation expense	 	 	2,978	 	 	 	20,013	 	
 	 	 	 	 	 	 	 	 	
Total operating expenses	 	 	38,915	 	 	 	215,178	 	
 	 	 	 	 	 	 	 	 	
Operating income (loss)	 	 	(6,082	)	 	 	(3,238	)	
Other expenses (income):	 	 	 	 	 	 	 	 	
Interest expense	 	 	910	 	 	 	5,406	 	
 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	(6,992	)	 	$	(8,644	)	
 	 	 	 	 	 	 	 	 	
General partner’s interest in net income (loss)	 	 	(140	)	 	 	(173	)	
 	 	 	 	 	 	 	 	 	
Limited partners’ interest in net income (loss)	 	$	(6,852	)	 	$	(8,471	)	
 	 	 	 	 	 	 	 	 	
Limited partners’ net income (loss) per common unit (Note 19)	 	$	(1.52	)	 	$	(.81	)	
 	 	 	 	 	 	 	 	 	
Weighted average number of common units used in computation of limited partners’ net income (loss) per common unit	 	 	4,507	 	 	 	10,506	 	

 
The accompanying notes are an integral part of these consolidated financial statements.

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Table of Contents

American Midstream Partners, LP and Subsidiaries

 Consolidated Statements of Changes in Partners’ Capital
 Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010

 	 	 	 	 	 	 	 	 	 	 	 	 	 	Accumulated	 	 	 	 	
 	 	Limited	 	 	Limited	 	 	General	 	 	General	 	 	Other	 	 	 	 	
 	 	Partner	 	 	Partner	 	 	Partner	 	 	Partner	 	 	Comprehensive	 	 	 	 	
 	 	Units	 	 	Interest	 	 	Units	 	 	Interest	 	 	Income	 	 	Total	 	
 	 	(in thousands)	 	
 		
Balances at August 20, 2009 (Inception Date)	 	 	9,800	 	 	$	—	 	 	 	200	 	 	$	—	 	 	$	—	 	 	$	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Contributions by partners	 	 	—	 	 	 	98,000	 	 	 	—	 	 	 	2,000	 	 	 	—	 	 	 	100,000	 	
Net loss	 	 	—	 	 	 	(6,852	)	 	 	—	 	 	 	(140	)	 	 	—	 	 	 	(6,992	)	
Unit based compensation	 	 	—	 	 	 	—	 	 	 	—	 	 	 	150	 	 	 	—	 	 	 	150	 	
Adjustments to other post retirement benefit plan assets and liabilities	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	46	 	 	 	46	 	

Balances at December 31, 2009	 	 	9,800	 	 	$	91,148	 	 	 	200	 	 	$	2,010	 	 	$	46	 	 	$	93,204	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Contributions by partners	 	 	1,176	 	 	 	11,760	 	 	 	24	 	 	 	240	 	 	 	—	 	 	 	12,000	 	
Net loss	 	 	—	 	 	 	(8,471	)	 	 	—	 	 	 	(173	)	 	 	—	 	 	 	(8,644	)	
Unitholder distributions	 	 	—	 	 	 	(11,545	)	 	 	—	 	 	 	(234	)	 	 	—	 	 	 	(11,779	)	
LTIP vesting	 	 	90	 	 	 	903	 	 	 	—	 	 	 	(903	)	 	 	—	 	 	 	—	 	
Tax netting repurchase	 	 	(17	)	 	 	(171	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(171	)	
Unit based compensation	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,184	 	 	 	—	 	 	 	1,184	 	
Adjustments to other post retirement benefit plan assets and liabilities	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	10	 	 	 	10	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balances at December 31, 2010	 	 	11,049	 	 	$	83,624	 	 	 	224	 	 	$	2,124	 	 	$	56	 	 	$	85,804	 	

 
The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statements of Cash Flows
 Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010

 	 	Period from	 	 	 	 	
 	 	August 20,	 	 	 	 	
 	 	2009	 	 	 	 	
 	 	(Inception Date)	 	 	 	 	
 	 	to	 	 	Year Ended	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Cash flows from operating activities	 	 	 	 	 	 	 	 	
Net loss	 	$	(6,992	)	 	$	(8,644	)	
Adjustments to reconcile change in net assets to net cash used in operating activities:	 	 	 	 	 	 	 	 	
Depreciation expense	 	 	2,978	 	 	 	20,013	 	
Amortization of deferred financing costs	 	 	118	 	 	 	807	 	
Mark to market on derivatives	 	 	5	 	 	 	385	 	
Unit based compensation	 	 	150	 	 	 	1,185	 	
Changes in operating assets and liabilities:	 	 	 	 	 	 	 	 	
Accounts receivable	 	 	(1,447	)	 	 	791	 	
Unbilled revenue	 	 	(18,329	)	 	 	(3,865	)	
Risk management assets	 	 	(82	)	 	 	(308	)	
Other current assets	 	 	(1,523	)	 	 	—	 	
Other assets	 	 	(199	)	 	 	(104	)	
Accounts payable	 	 	1,934	 	 	 	(954	)	
Accrued gas purchase	 	 	14,881	 	 	 	3,825	 	
Accrued expenses and other current liabilities	 	 	1,997	 	 	 	268	 	
Other liabilities	 	 	(22	)	 	 	392	 	
 	 	 	 	 	 	 	 	 	
Net cash provided (used) in operating activities	 	 	(6,531	)	 	 	13,791	 	
 	 	 	 	 	 	 	 	 	
Cash flows from investing activities	 	 	 	 	 	 	 	 	
Acquisition of operating assets from Enbridge Midcoast Energy, LP	 	 	(150,818	)	 	 	—	 	
Additions to property, plant and equipment	 	 	(1,158	)	 	 	(10,268	)	
 	 	 	 	 	 	 	 	 	
Net cash used in investing activities	 	 	(151,976	)	 	 	(10,268	)	
 	 	 	 	 	 	 	 	 	
Cash flows from financing activities	 	 	 	 	 	 	 	 	
Capital contributions	 	 	100,000	 	 	 	12,000	 	
Unit holder distributions	 	 	—	 	 	 	(11,779	)	
Payment of deferred financing costs	 	 	(2,158	)	 	 	—	 	
Borrowings on other loans	 	 	903	 	 	 	800	 	
Payments on other loan	 	 	(89	)	 	 	(1,000	)	
Borrowings on long-term debt	 	 	63,000	 	 	 	26,500	 	
Payments on long-term debt	 	 	(2,000	)	 	 	(31,130	)	
 	 	 	 	 	 	 	 	 	
Net cash provided (used) by financing activities	 	 	159,656	 	 	 	(4,609	)	
 	 	 	 	 	 	 	 	 	
Net increase (decrease) in cash and cash equivalents	 	 	1,149	 	 	 	(1,086	)	
Cash and cash equivalents	 	 	 	 	 	 	 	 	
Beginning of period	 	 	—	 	 	 	1,149	 	
 	 	 	 	 	 	 	 	 	
End of period	 	$	1,149	 	 	$	63	 	
 	 	 	 	 	 	 	 	 	
Supplemental cash flow information	 	 	 	 	 	 	 	 	
Interest payments	 	$	337	 	 	$	4,523	 	

The accompanying notes are an integral part of these consolidated financial statements.

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 Notes to Consolidated Financial Statements
 December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010

1.  	Summary of Significant Accounting Policies	
 
Nature of Business
 
American Midstream Partners, LP (the “Partnership”) was formed on August 20, 2009 (“date of inception”) as a Delaware limited partnership for the purpose of acquiring and operating certain natural gas pipeline and processing businesses. We provide natural gas gathering, treating, processing, marketing and transportation services in the Gulf Coast and Southeast regions of the United States. We hold our assets in a series of wholly owned limited liability companies as well as a limited partnership. Our capital accounts consist of general partner interests and limited partner interests.
 
We are controlled by our general partner, American Midstream GP, LLC, which is a wholly owned subsidiary of AIM Midstream Holdings, LLC.
 
Our interstate natural gas pipeline assets transport natural gas through Federal Energy Regulatory Commission (the “FERC”) regulated interstate natural gas pipelines in Louisiana, Mississippi, Alabama and Tennessee. Our interstate pipelines include:

 	• 	American Midstream (Midla), LLC, which owns and operates approximately 370 miles of interstate pipeline that runs from the Monroe gas field in northern Louisiana south through Mississippi to Baton Rouge, Louisiana.	
 		
 	• 	American Midstream (AlaTenn), LLC, which owns and operates more than approximately 295 miles of interstate pipeline that runs through the Tennessee River Valley from Selmer, Tennessee to Huntsville, Alabama and serves an eight county area in Alabama, Mississippi and Tennessee.	
 
Basis of Presentation
 
We have prepared the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The accompanying consolidated financial statements include the accounts of American Midstream Partners, LP and its controlled subsidiaries. All significant inter-company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements.
 
The financial position at December 31, 2009 and results of operations and changes in cash flows for the period then ended reflect operations from August 20, 2009, the date of inception. Between the date of inception and the date of the acquisition of the assets discussed in Note 2 on November 2, 2009, no operating activity occurred in the Partnership.
 
Use of Estimates
 
When preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
(5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.
 
Accounting for Regulated Operations
 
Certain of our natural gas pipelines are subject to regulation by the FERC. The FERC exercises statutory authority over matters such as construction, transportation rates we charge and our underlying accounting practices, and ratemaking agreements with customers. Accordingly, we record costs that are allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a non-regulated entity. Also, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for our regulated entities. As of December 31, 2009 and 2010, the Partnership had no such significant regulatory assets or liabilities.
 
Revenue Recognition and the Estimation of Revenues and Cost of Natural Gas
 
We recognize revenue when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectibility is reasonably assured. We record revenue and cost of product sold on a gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that are purchased for resale. We do not have multiple elements in our revenue contracts with our customers. When our customers pay us a fee for providing a service such as gathering, treating or transportation, we record those fees separately in revenues. For the period and year ended December 31, 2009 and 2010, respectively, the Partnership had the following revenues by category:

 	 	Period from	 	 	 	 	
 	 	August 20	 	 	 	 	
 	 	2009	 	 	 	 	
 	 	(Inception Date)	 	 	 	 	
 	 	to	 	 	Year Ended	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Revenue	 	 	 	 	 	 	 	 	
Transportation — firm	 	$	2,274	 	 	$	10,610	 	
Transportation — interruptible	 	 	444	 	 	 	3,313	 	
Sales of natural gas, NGLs and condensate	 	 	30,078	 	 	 	197,398	 	
Other	 	 	37	 	 	 	619	 	
 	 	 	 	 	 	 	 	 	
Total revenue	 	$	32,833	 	 	$	211,940	 	

 
We derive revenue in our business from the following types of arrangements:
 
Fee-Based

Under these arrangements, we generally are paid a fixed cash fee for gathering and transporting natural gas. Fee-based revenues, which are included in sales of natural gas, NGLs and condensate above, are recorded when services have been provided, and collectability of the revenue is reasonably assured.

Percent-of-Proceeds, or POP
 
Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas and NGLs

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)

at market prices. Where we provide processing services at the processing plants that we own, or obtain processing services for our own account under our elective processing arrangements we typically retain and sell a percentage of the residue natural gas and resulting NGLs. We recognize percent-of-proceeds contract revenue, which is included in sales of natural gas, NGLs and condensate above, when the natural gas, NGL’s or condensate is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.

Fixed-Margin

Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. We recognize revenue from fixed-margin contracts, which is included in sales of natural gas, NGLs and condensate above, when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.

Firm Transportation

Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not it utilizes the capacity. In most cases, the shipper also pays a variable use charge with respect to quantities actually transported by us. Firm transportation revenue is recorded when products are delivered, services have been provided and collectability of the revenue is reasonably assured.

Interruptible Transportation

Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable use charge for quantities actually shipped. Interruptible transportation revenue is recorded when products are delivered, services have been provided, and collectability of the revenue is reasonably assured.

Cash and Cash Equivalents
 
We consider all highly liquid investments with an original maturity of three months or less at the date of purchase to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.
 
Allowance for Doubtful Accounts
 
We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. For each of the period and year ended December 31, 2009 and 2010, the Partnership recorded no allowances for losses on accounts receivable.
 
Our predecessor financial statements included certain allowance for doubtful accounts in relation with the recoverability of certain customers accounts. In connection with our acquisition of the Enbridge assets, we did not acquire any working capital accounts (which includes accounts receivable) as of November 1, 2009.

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
Inventory
 
Inventory includes primarily product inventory. The Partnership records all product inventories at the lower of cost or market (“LCM”), which is determined on a weighted average basis.
 
Operational Balancing Agreements and Natural Gas Imbalances
 
To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through future receipt or delivery of natural gas. Natural gas imbalances are recorded as gas imbalances and classified within other current assets or other current liabilities on our consolidated balance sheets based on the market value. Natural gas imbalances are recorded as gas imbalances within “Accrued gas purchases” on the consolidated balance sheets.
 
Property, Plant and Equipment
 
We capitalize expenditures related to property, plant and equipment that have a useful life greater than one year for (1) assets purchased or constructed; (2) existing assets that are replaced, improved, or the useful lives of which have been extended; and (3) all land, regardless of cost. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.
 
We record property, plant and equipment at its original cost, which we depreciate on a straight-line basis over its estimated useful life. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We record depreciation using the group method of depreciation, which is commonly used by pipelines, utilities and similar entities.
 
The Company engaged an independent third party to perform the valuation associated with its acquisition. This valuation was performed primarily using a discounted cash flow model, which included certain market assumptions related to future throughput volumes, projected fees and/or prices, expected costs of sales and direct operating costs and risk adjusted discount rates.
 
Impairment of Long Lived Assets
 
We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our businesses, the market and business environment to identify indicators that could suggest an asset may not be recoverable. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
impairment loss in our consolidated statements of income. No impairment losses were recognized during the period ended and year ended December 31, 2009 and 2010.
 
We assess our long-lived assets for impairment using authoritative guidance. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. Fair values, for the purposes of the impairment test, are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.
 
Examples of long-lived asset impairment indicators include:

 	• 	A significant decrease in the market price of a long-lived asset or group;	
 		
 	• 	A significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;	
 		
 	• 	A significant adverse change in legal factors or in the business climate could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;	
 		
 	• 	An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group; and	
 		
 	• 	A current-period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long lived asset or asset group;	
 		
 	• 	A current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.	
 
Income Taxes
 
We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of state income tax laws by the State of Texas that apply to entities organized as partnerships. The Texas margin tax is computed on our modified gross margin and was not significant for each of the period or year ended December 31, 2009 and 2010.
 
Net income for financial statement purposes may differ significantly from taxable income allocable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available.
 
Commitments, Contingencies and Environmental Liabilities
 
We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense amounts we incur for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also take into account our prior experience in remediating contaminated sites, other companies’ clean-up experience and

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new information. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in our consolidated financial statements.
 
We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.
 
We have legal obligations requiring us to decommission our offshore pipeline systems at retirement. In certain rate jurisdictions, we are permitted to include annual charges for removal costs in the regulated cost of service rates we charge our customers. Additionally, legal obligations exist for a minority of our onshore right-of-way agreements due to requirements or landowner options to compel us to remove the pipe at final abandonment. Sufficient data exists with certain onshore pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management’s experience, or the asset’s estimated economic life. The useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to reasonably estimate potential settlement dates and methods.
 
Asset Retirement Obligations (“AROs”)
 
AROs are legal obligations associated with the retirement of tangible long-lived assets that result from the asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. We depreciate the capitalized ARO using the straight-line method over the period during which the related long-lived asset is expected to provide benefits. After the initial period of ARO recognition, we revise the ARO to reflect the passage of time or revisions to the amounts of estimated cash flows or their timing.
 
Derivative Financial Instruments
 
Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt, commodity prices and fractionation margins (the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas purchases). In an effort to manage the risks to unitholders, we use a variety of derivative financial instruments including swaps, put options and interest rate caps to create offsetting positions to specific commodity or interest rate exposures. In accordance with the authoritative accounting guidance, we record all derivative financial instruments in our consolidated balance sheets at fair market value. We record the fair market value of our derivative financial instruments in the consolidated balance sheets as current and long-term assets or liabilities on a net basis by counterparty. We

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
record changes in the fair value of our derivative financial instruments in our consolidated statements of operations as follows:

 	• 	Commodity-based derivatives: “Total revenue”	
 		
 	• 	Corporate interest rate derivatives: “Interest expense”	
 
Our formal hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to the approval and monitoring by the board of directors of our general partner. We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction, and we do not use derivative financial instruments for speculative purposes.
 
The price assumptions we use to value our derivative financial instruments can affect net income for each period. We use published market price information where available, or quotations from over-the-counter, or OTC, market makers to find executable bids and offers. The valuations also reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
 
Our earnings are affected by use of the mark-to-market method of accounting as required under GAAP for derivative financial instruments. The use of mark-to-market accounting for derivative financial instruments can cause noncash earnings volatility resulting from changes in the underlying indices, primarily commodity prices.
 
The Partnership’s other comprehensive income is comprised of changes in the net pension asset or liability associated with the OPEB plan (Note 15). Comprehensive income for the period and year ended December 31, 2009 and 2010 was as follows:

 	 	Period Ended	 	 	Year Ended	 	
 	 	December 31, 2009	 	 	December 31, 2010	 	
 		
Net income (loss)	 	$	(6,992	)	 	$	(8,644	)	
Unrealized gains (losses) on post retirement benefit plan assets and liabilities	 	 	46	 	 	 	10	 	
 	 	 	 	 	 	 	 	 	
Comprehensive income (loss)	 	$	(6,946	)	 	$	(8,634	)	

 
Unit-Based Employee Compensation
 
We award unit-based compensation to management, nonmanagement employees and directors in the form of phantom units, which are deemed to be equity awards. Compensation expense on phantom units is measured by the fair value of the award at the date of grant as determined by management. Compensation expense is recognized in general and administrative expense over the requisite service period of each award. See Note 14.
 
Fair Value Measurements
 
We apply the authoritative accounting provisions for measuring fair value of our derivative instruments and disclosures associated with our outstanding indebtedness. We define fair value as an exit price representing the expected amount we would receive when selling an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.

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American Midstream Partners, LP and Subsidiaries

Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:

 	• 	Level 1 — We include in this category the fair value of assets and liabilities that we measure based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. We have no assets and liabilities included in this category.	
 		
 	• 	Level 2 — We categorize the fair value of assets and liabilities that we measure with either directly or indirectly observable inputs as of the measurement date, where pricing inputs are other than quoted prices in active markets for the identical instrument, as Level 2. Assets and liabilities that we value using either models or other valuation methodologies are derived from observable market data. These models are primarily industry-standard models that consider various inputs including: (a) quoted prices for assets and liabilities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the assets and liabilities, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. We have no fair value of assets or liabilities included in this category.	
 		
 	• 	Level 3 — We include in this category the fair value of assets and liabilities that we measure based on prices or valuation techniques that require inputs which are both significant to the fair value measurement and less observable from objective sources (i.e., values supported by lesser volumes of market activity). We may also use these inputs with internally developed methodologies that result in our best estimate of the fair value. Level 3 assets and liabilities primarily include debt and derivative instruments for which we do not have sufficient corroborating market evidence support classifying the asset or liability as Level 2. Additionally, Level 3 valuations may utilize modeled pricing inputs to derive forward valuations, which may include some or all of the following inputs: nonbinding broker quotes, time value, volatility, correlation and extrapolation methods.	
 
We utilize a mid-market pricing convention, or the “market approach,” for valuation for assigning fair value to our derivative assets and liabilities. Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.
 
Debt Issuance Costs
 
Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchase and debt extinguishments include any associated unamortized debt issue costs.
 
Limited Partners’ Net Income Per Unit
 
We compute Limited Partners’ Net Income per Unit by dividing our limited partners’ interest in net income by the weighted average number of units outstanding during the period. The overall computation,

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
presentation, and disclosure requirements for our Limited Partners’ Net Income per Unit are made in accordance with the “Earnings per Share” Topic of the Codification.
 
Accounting Pronouncements Recently Adopted
 
In December 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2009-16, “Accounting for Transfers of Financial Assets” and Accounting Standards Update No. 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities.” ASU No. 2009-16 amended the Codification’s “Transfers and Servicing” Topic to include the provisions included within the FASB’s previous Statement of Financial Accounting Standards (SFAS) No. 166, “Accounting for Transfers of Financial Assets — an amendment of FASB Statement No. 140,” issued June 12, 2009. ASU No. 2009-17 amended the Codification’s “Consolidations” Topic to include the provisions included within the FASB’s previous SFAS No. 167, “Amendments to FASB Interpretation No. 46(R),” also issued June 12, 2009. These two Updates changed the way entities must account for securitizations and special-purpose entities. ASU No. 2009-16 requires more information about transfers of financial assets, including securitization transactions, and where companies have continuing exposure to the risks related to transfer financial assets. ASU No. 2009-17 changes how a company determines whether an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. For us, both Updates were effective January 1, 2010; however, the adoption of these Updates did not have any impact on our consolidated financial statements.
 
In January 2010, the FASB issued Accounting Standards Update No. 2010-06, “Improving Disclosures about Fair Value Measurements.” This ASU requires both the gross presentation of activity within the Level 3 fair value measurement roll forward and the details of transfers in and out of Levels 1 and 2 fair value measurements. It also clarifies certain disclosure requirements on the level of disaggregation of fair value measurements and disclosures on inputs and valuation techniques. For us, this ASU was effective January 1, 2010 (except for the Level 3 roll forward which was effective for us January 1, 2011); however, the adoption of this ASU did not have a material impact on our consolidated financial statements. Furthermore, during each of the period and year ended December 31, 2010 and 2009, we made no transfers in and out of Level 1, Level 2, or Level 3 of the fair value hierarchy.
 
In July 2010, the FASB issued Accounting Standards Update No. 2010-20, “Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses.” ASU No. 2010-20 requires companies that hold financing receivables, which include loans, lease receivables, and the other long-term receivables to provide more information in their disclosures about the credit quality of their financing receivables and the credit reserves held against them. On December 31, 2010, we adopted all amendments that require disclosures as of the end of a reporting period, and on January 1, 2011, we adopted all amendments that require disclosures about activity that occurs during a reporting period (the remainder of this ASU). The adoption of this ASU did not have a material impact on our consolidated financial statements.

2.  	Acquisition	
 
On October 2, 2009, American Midstream, LLC, a wholly owned subsidiary, entered into a purchase and sale agreement to acquire certain pipeline businesses from Enbridge Midcoast Energy, L.P., for an aggregate purchase price of approximately $150.8 million. The acquisition was effective as of November 1, 2009. Prior to the acquisition, we had no operating tangible assets.
 
The acquired businesses were renamed as follows:
 
American Midstream (Alabama Intrastate), LLC

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
American Midstream (Bamagas Intrastate), LLC
American Midstream (Tennessee River), LLC
American Midstream (Mississippi), LLC
American Midstream (Midla), LLC
American Midstream (Alabama Gathering), LLC
American Midstream (AlaTenn), LLC
American Midstream Onshore Pipelines, LLC
Mid Louisiana Gas Transmission, LLC
American Midstream Offshore (Seacrest), LP
American Midstream (SIGCO Intrastate), LLC
American Midstream (Louisiana Intrastate), LLC
 
The acquisition qualifies as a business combination and, as such, the Partnership estimated the fair value of each property as of the acquisition date (the date on which the Partnership obtained control of the properties). The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements also utilize assumptions of market participants. The Partnership used a discounted cash flow model and made market assumptions as to future commodity prices, expectations for timing and amount of future development and operating costs, projections of future rates of production, and risk adjusted discount rates. These assumptions represent Level 3 inputs.
 
The following table summarizes the consideration paid to the seller and the amounts of the assets acquired and liabilities assumed in the acquisition.

 	 	(in thousands)	 	
 		
Consideration paid to seller	 	 	 	 	
Cash consideration	 	$	150,818	 	
 	 	 	 	 	
Recognized amounts of identifiable assets acquired and liabilities assumed	 	 	 	 	
Property, plant and equipment	 	 	151,085	 	
Other post-retirement benefit plan assets, net	 	 	394	 	
Other liabilities assumed	 	 	(661	)	
 	 	 	 	 	
Total identifiable net assets	 	$	150,818	 	

 
Acquisition costs of $6.4 million and $0.3 million have been recorded in the statements of operations under the caption Transaction costs on acquisitions for the period and year ended December 31, 2009 and 2010.

3.  	Concentration of Credit Risk and Trade Accounts Receivable	
 
Our primary market areas are located in the United States along the Gulf Coast and in the Southeast. We have a concentration of trade receivable balances due from companies engaged in the production, trading, distribution and marketing of natural gas and NGL products. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. Our customers’ historical financial and operating information is analyzed prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. We maintain allowances for potentially uncollectible accounts receivable. For the period and year ended December 31, 2009 and 2010, no allowances on accounts receivable were recorded.

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
Enbridge Marketing (US) L.P., ConocoPhillips Corporation and ExxonMobil Corporation were significant customers, representing at least 10% of our consolidated revenue, accounting for $17.8 million, $5.0 million and $0.1 million, respectively, of our consolidated revenue in the consolidated statement of operations in the period ended December 31, 2009 and $63.9 million, $53.4 million and $22.9 million for the year ended December 31, 2010.

4.  	Other Current Assets	
 
Other current assets as of December 31 were as follows:

 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Prepaid insurance — current portion	 	$	815	 	 	$	767	 	
NGL inventory	 	 	121	 	 	 	101	 	
Other receivables	 	 	431	 	 	 	30	 	
Other prepaid amounts	 	 	156	 	 	 	625	 	
 	 	 	 	 	 	 	 	 	
 	 	$	1,523	 	 	$	1,523	 	

 
For each of the period and year ended December 31, 2009 and 2010, the Partnership recorded no LCM write-downs.

5.  	Derivatives	
 
Commodity Derivatives
 
To minimize the effect of a downturn in commodity prices and protect the Partnership’s profitability and the economics of its development plans, the Partnership enters into commodity economic hedge contracts from time to time. The terms of contracts depend on various factors, including management’s view of future commodity prices, acquisition economics on purchased assets and future financial commitments. This hedging program is designed to moderate the effects of a severe commodity price downturn while allowing us to participate in some commodity price increases. Management regularly monitors the commodity markets and financial commitments to determine if, when, and at what level some form of commodity hedging is appropriate in accordance with policies which are established by the board of directors of our general partner. Currently, the commodity hedges are in the form of swaps and puts.
 
Neither the Partnership nor its counterparties are required to post collateral in connection with its derivative positions and netting agreements are in place with each of the Partnership’s counterparties allowing the Partnership to offset its commodity derivative asset and liability positions.
 
As of December 31, 2010, the notional volumes of our commodity hedges for 2011 were 2,404,584 gallons, with no amounts hedged in 2012 or after.
 
Interest Rate Derivatives
 
The Partnership also utilizes interest rate caps to protect against changes in interest rates on its floating rate debt.
 
At December 31, 2010, the Partnership had $56.4 million outstanding under its credit facility, with interest accruing at a rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates, the Partnership has entered into interest rate caps that mitigate

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
the risk of increases in interest rates. As of December 31, 2010, we had interest rate caps with a notional amount of $26.5 million that effectively fix the base rate on that portion of our debt, with a fixed maximum rate of 4%.
 
For accounting purposes, no derivative instruments were designated as hedging instruments and were instead accounted for under the mark-to-market method of accounting, with any changes in the mark-to-market value of the derivatives recorded in the balance sheets and through earnings, rather than being deferred until the anticipated transactions affect earnings. The use of mark-to-market accounting for financial instruments can cause noncash earnings volatility due to changes in the underlying commodity prices indices or interest rates.
 
As of December 31, 2009 and 2010, the fair value associated with the Partnership’s derivative instruments were recorded in our financial statements, under the caption Risk management assets, as follows:

 	 	December 31,	 	 	December 31,	 	
 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Commodity derivatives	 	$	—	 	 	$	—	 	
Interest rate derivatives	 	 	77	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	
 	 	$	77	 	 	$	—	 	

 
During 2009 and 2010, we recorded the following mark-to-market losses:

 	 	December 31,	 	 	December 31,	 	
 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Commodity derivatives	 	$	—	 	 	$	(308	)	
Interest rate derivatives	 	 	(5	)	 	 	(77	)	
 	 	 	 	 	 	 	 	 	
 	 	$	(5	)	 	$	(385	)	

 
Fair Value Measurements
 
The Partnership’s interest rate caps and commodity derivatives discussed above were classified as Level 3 derivatives for all periods presented.
 
The table below includes a roll forward of the balance sheet amounts (including the change in fair value) for financial instruments classified by us within Level 3 of the valuation hierarchy. When a determination is made to classify a financial instrument within Level 3 of the valuation hierarchy, the determination is based upon the significance of the unobservable factors to the overall fair value measurement. Level 3 financial instruments typically include, in addition to the unobservable or Level 3 components, observable components (that is, components that are actively quoted and can be validated to external sources).

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)

 	 	Period from	 	 	 	 	
 	 	August 20, 2009	 	 	 	 	
 	 	(Inception Date)	 	 	 	 	
 	 	to	 	 	Year Ended	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Fair value asset (liability), beginning of period	 	$	—	 	 	$	77	 	
Total realized and unrealized (losses) gains included in revenue	 	 	(5	)	 	 	(385	)	
Purchases, sales and settlements, net	 	 	82	 	 	 	308	 	
 	 	 	 	 	 	 	 	 	
Fair value (liability) asset, end of period	 	$	77	 	 	$	—	 	

 
		
6.  	Property, Plant and Equipment, Net	
 
Property, plant and equipment, net, as of December 31 were as follows:

 	 	Useful Life	 	 	2009	 	 	2010	 	
 	 	 	 	 	(in thousands)	 	
 		
Land	 	 	 	 	 	$	41	 	 	$	41	 	
Buildings and improvements	 	 	4 to 40	 	 	 	1,427	 	 	 	2,523	 	
Processing and treating plants	 	 	8 to 40	 	 	 	10,255	 	 	 	11,954	 	
Pipelines	 	 	5 to 40	 	 	 	131,845	 	 	 	143,805	 	
Compressors	 	 	4 to 20	 	 	 	7,164	 	 	 	7,163	 	
Equipment	 	 	8 to 20	 	 	 	825	 	 	 	1,711	 	
Computer software	 	 	5	 	 	 	687	 	 	 	1,390	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total property, plant and equipment	 	 	 	 	 	 	152,244	 	 	 	168,587	 	
Accumulated depreciation	 	 	 	 	 	 	(2,978	)	 	 	(21,779	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, plant and equipment, net	 	 	 	 	 	$	149,266	 	 	$	146,808	 	

 
Of the gross property, plant and equipment balances at December 31, 2009 and 2010, $20.3 million and $24.3 million, respectively, relate to regulated assets.

7.  	Asset Retirement Obligations	
 
We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis, in the period in which the liability is incurred. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO. Typically we record an ARO at the time the assets are installed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an ARO, we capitalize the costs as part of the carrying value of the related assets. We recognize an ongoing expense for the interest component of the liability as part of depreciation expense resulting from changes in the value of the ARO due to the passage of time. We depreciate the initial capitalized costs over the useful lives of the related assets. We extinguish the liabilities for an ARO when assets are taken out of service or otherwise abandoned.
 
During the year ended December 31, 2010, we recognized $6.1 million of AROs for specific assets that we intend to retire for operational purposes. We recorded accretion expense of $1.2 million, in our consolidated statements of operations for the year ended December 31, 2010 related to these AROs.
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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
No assets are legally restricted for purposes of settling our ARO for each of the period and year ended December 31, 2009 and 2010. Following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for each of the period and year ended December 31, 2009 and 2010, respectively.

 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Balance at beginning of period	 	$	—	 	 	$	—	 	
Additions	 	$	—	 	 	 	6,058	 	
Accretion expense	 	$	—	 	 	 	1,191	 	
 	 	 	 	 	 	 	 	 	
Balance at end of period	 	$	—	 	 	$	7,249	 	

 
The Partnership did not recognize AROs as of December 31, 2009 given that, at that time, it did not intend to retire any of its existing assets, nor were retirement costs estimable. However, after the Partnership had obtained sufficient operating experience with assets during 2010, it determined certain assets would be retired from an operational perspective.

8.  	Other Assets, Net	
 
Other assets, net, as of December 31 were as follows:

 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Deferred financing costs	 	$	2,040	 	 	$	1,338	 	
Other post-retirement benefit plan assets, net	 	 	440	 	 	 	450	 	
Prepaid insurance — long term portion	 	 	189	 	 	 	140	 	
Security deposits	 	 	10	 	 	 	57	 	
 	 	 	 	 	 	 	 	 	
 	 	$	2,679	 	 	$	1,985	 	

 
Deferred Financing Costs
 
Deferred financing costs related to the term loan portion of our credit facility are amortized using the effective interest method over the term of the term credit facility. See Note 12 for more information about our credit facility. Deferred financing costs related to the revolver portion of our credit facility are amortized on a straight line basis over the term of the credit facility. During the year ended December 31, 2010, we incurred deferred financing costs of $2.2 million related to our November 2009 $85 million credit facility.

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)

9.  	Accrued Expenses and Other Current Liabilities	
 
Other current liabilities as of December 31 were as follows:

 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Accrued interest payable	 	$	508	 	 	$	407	 	
Accrued expenses	 	 	651	 	 	 	839	 	
Accrued salaries	 	 	267	 	 	 	957	 	
Accrued property taxes	 	 	217	 	 	 	3	 	
Contract obligations — short term	 	 	240	 	 	 	240	 	
Deferred revenue	 	 	—	 	 	 	210	 	
Other	 	 	354	 	 	 	20	 	
 	 	 	 	 	 	 	 	 	
 	 	$	2,237	 	 	$	2,676	 	

 
		
10.  	Other Liabilities	
 
Other long term liabilities as of December 31 were as follows:

 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Deferred revenue	 	$	—	 	 	$	528	 	
ARO	 	 	—	 	 	 	7,249	 	
Contract obligations — long term	 	 	399	 	 	 	208	 	
Other deferred expenses	 	 	—	 	 	 	93	 	
 	 	 	 	 	 	 	 	 	
 	 	$	399	 	 	$	8,078	 	

 
		
11.  	Other Loan	
 
Other loan represents insurance premium financing in the original amounts of $0.8 million bearing interest at 4.25% per annum, that is repayable in equal monthly installments of less than $0.1 million through October 1, 2011.

12.  	Long-Term Debt	
 
On November 4, 2009, we entered into an $85 million secured credit facility (“credit facility”) with a consortium of lending institutions. The credit facility is composed of a $50 million term loan facility and a $35 million revolving credit facility.

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
Our outstanding borrowings under the credit facility at December 31 were:

 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Term loan facility	 	$	50,000	 	 	$	45,000	 	
Revolving loan facility	 	 	11,000	 	 	 	11,370	 	
 	 	 	 	 	 	 	 	 	
 	 	 	61,000	 	 	 	56,370	 	
Less: Current portion	 	 	5,000	 	 	 	6,000	 	
 	 	 	 	 	 	 	 	 	
 	 	$	56,000	 	 	$	50,370	 	

 
At December 31, 2009 and 2010, letters of credit outstanding under the credit facility were $2.0 million and $0.6 million, respectively.
 
The credit facility provides for a maximum borrowing equal to the lesser of (i) $85 million less the required amortization of term loan payments and (ii) 3.50 times adjusted consolidated EBITDA (as defined: $20.9 and $18.8 million at December 31, 2009 and 2010, respectively). We may elect to have loans under the credit facility bear interest either (i) at a Eurodollar-based rate with a minimum of 2.0% plus a margin ranging from 3.25% to 4.0% depending on our total leverage ratio then in effect, or (ii) at a base rate (the greater of (i) the daily adjusting LIBOR rate and (ii) a Prime-based rate which is equal to the greater of (A) the Prime Rate and (B) an interest rate per annum equal to the Federal Funds Effective Rate in effect that day, plus one percent) plus a margin ranging from 2.25% to 3.00% depending on the total leverage ratio then in effect. We also pay a facility fee of 1.0% per annum. In December 2009, we entered into an interest rate cap with participating lenders with a $26.5 million notional amount at December 31, 2010 that effectively caps our Eurodollar-based rate exposure on that portion of our debt at a maximum of 4.0%. For the period and year ended December 31, 2009 and 2010, the weighted average interest rate on borrowings under our credit facility was approximately 5.79% and 7.48%, respectively.
 
Our obligations under the credit facility are secured by first mortgage in favor of the lenders in our real property. The terms of the credit facility include covenants that restrict our ability to make cash distributions and acquisitions in some circumstances. The remaining principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date, November 3, 2012.
 
The term loan facility also provides for quarterly principal installment payments as described below:

Year	 	Amount	 	
 	 	(in thousands)	 	
 		
2011	 	$	6,000	 	
2012	 	 	39,000	 	
 	 	 	 	 	
 	 	$	45,000	 	

 
The credit facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the credit facility are (i) a total leverage ratio test (not to exceed 3.50 times) and a minimum interest coverage ratio test (not less than 2.50 times). We were in compliance with all of the covenants under our credit facility as of December 31, 2009 and 2010.

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
Fair Market Value of Financial Instruments
 
The Partnership used various assumptions and methods in estimating the fair values of its financial instruments. The carrying amounts of cash and cash equivalents and accounts receivable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of the Partnership’s credit facility approximates fair value, because the interest rate on the facility is variable.

13.  	Partners’ Capital	
 
Our capital accounts are comprised of a 2% general partner interest and 98% limited partner interests. Our limited partners have limited rights of ownership as provided for under our partnership agreement and, as discussed below, the right to participate in our distributions. Our general partner manages our operations, and participates in our distributions, including certain incentive distributions pursuant to the incentive distribution rights that are nonvoting limited partner interests held by our general partner. Incentive distribution rights confer upon the holder thereof only the rights and obligations specifically provided in our partnership agreement. Under that agreement, our incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Incentive distribution rights are not unitized and have no associated capital account. Our general partner may transfer these incentive distribution rights separately from its general partner interest, subject to restrictions in our partnership agreement.
 
The number of units outstanding as of December 31, were as follows:

 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Common units	 	 	9,800	 	 	 	11,049	 	
General partner units	 	 	200	 	 	 	224	 	

Distributions
 
The Partnership made distributions of $0 million and $11.8 million for the period and year ended December 31, 2009 and 2010, respectively. We issued our incentive distribution rights to our general partner in November 2009. However, as no such distributions are owed under our partnership agreement prior to the consummation our initial public offering, no distributions have been made to date on our incentive distribution rights. We have neither adopted a policy of nor were required to make minimum distributions during the periods presented in these financial statements.

14.  	Long-Term Incentive Plan	
 
Our general partner manages our operations and activities and employs the personnel who provide support to our operations. On November 2, 2009, the board of directors of our general partner adopted a long-term incentive plan for its employees and consultants and directors who perform services for it or its affiliates. On May 25, 2010, the board of directors of our general partner adopted an amended and restated long-term incentive plan (as amended, the “LTIP”). The LTIP currently permits the grant of awards in the form of Partnership units, which may include distribution equivalent rights (“DER”s), covering an aggregate of 625,532 of our units. A DER entitles the grantee to a cash payment equal to the cash distribution made by the Partnership with respect to a unit during the period such DER is outstanding. At December 31, 2009 and 2010, 154,737 and 111,112 units, respectively, were available for future grant under the LTIP.

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
Ownership in the awards is subject to forfeiture until the vesting date. The LTIP is administered by the board of directors of our general partner.
 
Although other types of awards are contemplated under the LTIP, currently outstanding awards are limited to phantom units with DERs issued on November 2, 2009. The board of directors of our general partner, at its discretion, may elect to settle such vested phantom units with a number of units equivalent to the fair market value at the date of vesting in lieu of cash. Although, our general partner has the option to settle in cash upon the vesting of phantom unit our general partner does not intend to settle these awards in cash.
 
Grants issued under the LTIP have historically vested in increments of 25% on each of the first four anniversary dates of the date of the grant and do not contain any other restrictive conditions related to vesting other than continued employment.
 
During 2009 and 2010, the fair value of the grants issued were calculated based on a discounted cash flow (“DCF”) model, prepared by an independent third party in October 2009, using a DCF analysis. This model included certain market assumptions related to future throughput volumes, projected fees and/or prices, expected costs of sales and direct operating costs and risk adjusted discount rates. The initial valuation was prepared in October of 2009 and the Company assessed the adequacy of that valuation on each grant date subsequent to the initial fair value calculation to determine if events or circumstances had occurred that would cause that valuation to become less relevant, noting none. Therefore, the Company maintained the $10 valuation throughout 2009 and 2010.
 
The following table summarizes our unit-based awards for each of the periods indicated, in units:

 	 	Period Ended	 	 	Year Ended	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2009	 	 	2010	 	
 		
Outstanding at beginning of period	 	 	—	 	 	 	361,052	 	
Granted	 	 	361,052	 	 	 	153,368	 	
Converted	 	 	—	 	 	 	(90,263	)	
 	 	 	 	 	 	 	 	 	
Outstanding at end of period	 	 	361,052	 	 	 	424,157	 	
 	 	 	 	 	 	 	 	 	
Grant date fair value per share	 	$	10.0	 	 	$	10.0	 	

The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our units at each balance sheet date. Compensation costs related to these awards during 2009 and 2010 was $0.2 million and $1.2 million, respectively, which is classified in selling, general and administrative expenses in the consolidated statement of operations and partners’ capital on the consolidated balance sheet.
 
The total compensation cost related to nonvested awards not yet recognized on December 31, 2009 and 2010 was $3.5 million and $3.9 million, respectively, and the weighted average period over which this cost is expected to be recognized is approximately 2 years.

15.  	Post-Employment Benefits	
 
Post-Employment Benefits other than Pensions
 
As a result of our acquisition from Enbridge, the sponsorship of the AlaTenn VEBA plans were transferred from Enbridge to us effective November 1, 2009. Accordingly, we sponsor a contributory postretirement plan that provides medical, dental and life insurance benefits for qualifying U.S. retired employees (referred to as the “OPEB Plan”).

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American Midstream Partners, LP and Subsidiaries

Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
The tables below detail the changes in the benefit obligation, the fair value of plan assets and the recorded asset or liability of the OPEB Plan using the accrual method.

 	 	OPEB Plan	 	
 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Change In Benefit Obligation	 	 	 	 	 	 	 	 	
Obligation assumed from the acquisition from Enbridge	 	$	771	 	 	$	734	 	
Service cost	 	 	2	 	 	 	10	 	
Interest cost	 	 	7	 	 	 	43	 	
Actuarial (gain) loss	 	 	(44	)	 	 	112	 	
Benefits paid	 	 	(2	)	 	 	(30	)	
 	 	 	 	 	 	 	 	 	
Benefit obligation, December 31	 	$	734	 	 	$	869	 	
 	 	 	 	 	 	 	 	 	
Change In Plan Assets	 	 	 	 	 	 	 	 	
Plan assets acquired from Enbridge	 	$	1,165	 	 	$	1,174	 	
Actual return on plan assets	 	 	11	 	 	 	61	 	
Employer’s contributions	 	 	—	 	 	 	113	 	
Benefits paid	 	 	(2	)	 	 	(29	)	
 	 	 	 	 	 	 	 	 	
Fair value of plan assets, December 31	 	$	1,174	 	 	$	1,319	 	
 	 	 	 	 	 	 	 	 	
Funded Status	 	 	 	 	 	 	 	 	
Funded status	 	$	394	 	 	$	440	 	
Unrecognized actuarial gain	 	 	46	 	 	 	10	 	
 	 	 	 	 	 	 	 	 	
Prepaid (accrued) benefit cost, December 31	 	$	440	 	 	$	450	 	

 
The amounts of plan net assets recognized in our consolidated balance sheets at December 31, 2009 and December 31, 2010 were as follows:

 	 	OPEB Plan	 	
 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Other assets, net	 	$	440	 	 	$	450	 	
 	 	 	 	 	 	 	 	 	
 	 	$	440	 	 	$	450	 	

 
The amounts included in accumulated other comprehensive income that have not yet been recognized as components of net periodic benefit expense are $46,000 and $56,000 as of December 31, 2009 and 2010, respectively.
 
The accumulated benefit obligation for the OPEB Plan at December 31, 2009 and December 31, 2010 was $0.7 million and $0.9 million, respectively.

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Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
Economic Assumptions
 
The assumptions made in measurement of the projected benefit obligations or assets of the OPEB Plan were as follows:

 	 	OPEB Plan	 	
 	 	2009	 	 	2010	 	
 		
Discount rate	 	 	6.00	%	 	 	5.50	%	
Expected return on plan assets	 	 	4.50	%	 	 	4.50	%	

A one percent increase in the assumed medical and dental care trend rate would result in an increase of $0.1 million in the accumulated post-employment benefit obligations. A one percent decrease in the assumed medical and dental care trend rate would result in a decrease of $0.1 million in the accumulated post-employment benefit obligations.
 
The above table reflects the expected long-term rates of return on assets of the OPEB Plan on a weighted-average basis. The overall expected rates of return are based on the asset allocation targets with estimates for returns on equity and debt securities based on long term expectations. We believe this rate approximates the return we will achieve over the long-term on the assets of our plans. Historically, we have used a discount rate that corresponds to one or more high quality corporate bond indices as an estimate of our expected long-term rate of return on plan assets for our OPEB Plan assets. For 2009 and 2010 we selected the discount rate using the Citigroup Pension Discount Curve, or CPDC. The CPDC spot rates represent the equivalent yield on high-quality, zero-coupon bonds for specific maturities. These rates are used to develop a single, equivalent discount rate based on the OPEB Plan’s expected future cash flows.
 
Expected Future Benefit Payments
 
The following table presents the benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five years thereafter by the OPEB Plan:

 	 	Gross Benefit	 	
 	 	Payments	 	
For the year ending	 	OPEB Plan	 	
 	 	(in thousands)	 	
 		
2011	 	$	56	 	
2012	 	 	56	 	
2013	 	 	55	 	
2014	 	 	55	 	
2015	 	 	55	 	
Five years thereafter	 	 	235	 	

The expected future benefit payments are based upon the same assumptions used to measure the projected benefit obligations of the OPEB Plan including benefits associated with future employee service.
 
Expected Contributions to the Plans
 
We expect to make contributions to the OPEB Plan for the year ending December 31, 2011 of $0.1 million.

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American Midstream Partners, LP and Subsidiaries

Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
Plan Assets
 
The weighted average asset allocation of our OPEB Plan at the measurement date by asset category, are as follows:

 	 	 	 	 	 	 	 	 	
 	 	OPEB Plan	 	
 	 	2009	 	 	2010	 	
 		
Fixed income(a)	 	 	76.7	%	 	 	70.7	%	
Cash and short-term assets(b)	 	 	23.3	%	 	 	29.3	%	
 	 	 	 	 	 	 	 	 	
Total	 	 	100.0	%	 	 	100.0	%	

 

 
			
(a)		United States government securities, municipal corporate bonds and notes and as set backed securities.	

 
			
(b)		Cash and securities with maturities of one year or less.	

		
16.  	Commitments and Contingencies	
 
We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to natural gas pipeline operations and we could, at times, be subject to environmental cleanup and enforcement actions. We attempt to manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment.
 
Future noncancelable commitments related to certain contractual obligations are presented below:

 	 	Payments Due by Period (in thousands)	 	
 	 	Total	 	 	2011	 	 	2012	 	 	2013	 	 	2014	 	 	2015	 	 	Thereafter	 	
 		
Operating leases and service contract	 	$	2,057	 	 	$	580	 	 	$	405	 	 	$	342	 	 	$	351	 	 	$	349	 	 	$	30	 	
ARO	 	 	8,340	 	 	 	914	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	7,426	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	10,397	 	 	$	1,494	 	 	$	405	 	 	$	342	 	 	$	351	 	 	$	349	 	 	$	7,456	 	

 
Total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements were:

 	 	Period from	 	 	 	 	
 	 	August 20, 2009	 	 	 	 	
 	 	(Inception Date)	 	 	 	 	
 	 	to	 	 	Year Ended	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2009	 	 	2010	 	
 	 	(in thousands)	 	
 		
Operating leases	 	$	60	 	 	$	757	 	
ARO	 	 	—	 	 	 	25	 	
 	 	 	 	 	 	 	 	 	
 	 	$	60	 	 	$	782	 	

 
		
17.  	Related-Party Transactions	
 
Employees of our general partner are assigned to work for us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by our general partner to American Midstream, LLC which, in turn, charges the appropriate subsidiary. Our general

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American Midstream Partners, LP and Subsidiaries

Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
partner does not record any profit or margin for the administrative and operational services charged to us. During the period and year ended December 31, 2009 and 2010, administrative and operational services expenses of $0.9 million and $0.9 million were allocated to us by our general partner.
 
We have entered into an advisory services agreement with American Infrastructure MLP Management, L.L.C., American Infrastructure MLP PE Management, L.L.C., and American Infrastructure MLP Associates Management, L.L.C., as the advisors. The agreement provides that we pay $0.3 million in 2010 and annual fees of $0.3 million plus annual increases in proportion to the increase in budgeted gross revenues thereafter. In exchange, the advisors have agreed to provide us services in obtaining equity, debt, lease and acquisition financing, as well as providing other financial, advisory and consulting services. For the period and year ended December 31, 2009 and 2010, less than $0.1 million and $0.3 million, respectively, had been recorded to selling, general and administrative expenses under this agreement.

18.  	Reporting Segments	
 
Our operations are located in the United States and are organized into two reporting segments: (1) Gathering and Processing; and (2) Transmission
 
Gathering and Processing
 
Our Gathering and Processing segment provides “wellhead to market” services to producers of natural gas and oil, which include transporting raw natural gas from the wellhead through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs and selling or delivering pipeline quality natural gas and NGLs to various markets and pipeline systems.
 
Transmission
 
Our Transmission segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, including local distribution companies, or LDCs, utilities and industrial, commercial and power generation customers.
 
These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the business of each segment.

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American Midstream Partners, LP and Subsidiaries

Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
The following tables set forth our segment information:

 	 	 	 	 	Gathering	 	 	 	 	
 	 	 	 	 	and	 	 	 	 	
 	 	Transmission	 	 	Processing	 	 	Total	 	
 	 	(in thousands)	 	
 		
Period from August 20, 2009 (Inception date) to December 31, 2009	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenue	 	$	4,976	 	 	$	27,857	 	 	$	32,833	 	
Segment gross margin(a)	 	$	2,542	 	 	$	3,698	 	 	$	6,240	 	
Direct operating expenses	 	 	 	 	 	 	 	 	 	 	1,594	 	
Selling, general and administrative expenses	 	 	 	 	 	 	 	 	 	 	1,346	 	
One-time transaction costs	 	 	 	 	 	 	 	 	 	 	6,404	 	
Depreciation expense	 	 	 	 	 	 	 	 	 	 	2,978	 	
Interest expense	 	 	 	 	 	 	 	 	 	 	910	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	 	 	 	 	 	 	 	 	$	(6,992	)	

 
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	Gathering	 	 	 	 	
 	 	 	 	 	and	 	 	 	 	
 	 	Transmission	 	 	Processing	 	 	Total	 	
 	 	(in thousands)	 	
 		
Year ended December 31, 2010	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenue(b)	 	$	53,485	 	 	$	158,455	 	 	$	211,940	 	
Segment gross margin(a)(b)	 	$	13,524	 	 	$	24,595	 	 	$	38,119	 	
Direct operating expenses	 	 	 	 	 	 	 	 	 	 	12,187	 	
Selling, general and administrative expenses	 	 	 	 	 	 	 	 	 	 	8,854	 	
One-time transaction costs	 	 	 	 	 	 	 	 	 	 	303	 	
Depreciation expense	 	 	 	 	 	 	 	 	 	 	20,013	 	
Interest expense	 	 	 	 	 	 	 	 	 	 	5,406	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	 	 	 	 	 	 	 	 	$	(8,644	)	

 

			
(a)		Segment gross margin for our Gathering and Processing segment consists of total revenue, including commodity derivative activity, less purchases of natural gas, NGLs and condensate. Segment gross margin for our Transmission segment consists of total revenue, less purchases of natural gas. Gross margin consists of the sum of the segment gross margin amounts for each of these segments. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow from operations as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.	
 		
(b)		Noncash derivative mark-to-market is included in total revenue and segment gross margin in our Gathering and Processing segment.	
 
Asset information including capital expenditures, by segment is not included in reports used by our management in its monitoring of performance and therefore, is not disclosed.

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American Midstream Partners, LP and Subsidiaries

Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
For the purposes of our Transmission segment, for the period ended December 31, 2009 and the year ended December 31, 2010, Enbridge Marketing (US) L.P., ExxonMobil Corporation and Calpine Corporation represented significant customers, each representing more than 10% of our segment revenue in this segment. Our segment revenue derived from Enbridge Marketing (US) L.P., ExxonMobil Corporation and Calpine Corporation represented $3.0 million, $0.1 million and $0.9 million of segment revenue for the period ended 2009 and $16.6 million, $22.9 million and $5.1 million for the year ended 2010, respectively.
 
For the purposes of our Gathering and Processing segment, for the period ended December 31, 2009 and the year ended December 31, 2010, Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented significant customers, each representing more than 10% of our segment revenue in this segment. Our segment revenue derived from Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented $14.7 million, $5.0 million and $3.1 million of segment revenue for the period ended 2009 and $47.3 million, $53.4 million and $16.4 million for the year ended 2010, respectively.

19.  	Net Income (Loss) per Limited and General Partner Unit	
 
Net Income per Limited Partner Unit.   Net income is allocated to the general partner and the limited partners (common unitholders) in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income by the weighted average number of outstanding limited partner units during the period.
 
Unvested share-based payment awards that contain non-forfeitable rights to distributions (whether paid or unpaid) are classified as participating securities and are included in our computation of basic and diluted net income per limited partner unit.
 
We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.
 
The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit. We have no dilutive securities, therefore basic and diluted net income per unit are the same.

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American Midstream Partners, LP and Subsidiaries

Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010 – (continued)
 
We determined basic and diluted net income per general partner unit and limited partner unit as follows:

 	 	 	 	 	 	 	 	 	
 	 	For the	 	 	 	 	
 	 	Period from	 	 	 	 	
 	 	August 20, 2009	 	 	 	 	
 	 	(Inception Date)	 	 	For The	 	
 	 	to	 	 	Year Ended	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2009	 	 	2010	 	
 	 	(in thousands, except per unit amounts)	 	
 		
Net loss attributable to general partner and limited partners	 	$	(6,992	)	 	$	(8,644	)	
Weighted average general partner and limited partner units outstanding(a)	 	 	4,596	 	 	 	10,711	 	
Earnings per general partner and limited partner unit (basic and diluted)	 	$	(1.52	)	 	$	(.81	)	
Net loss attributable to limited partners	 	$	(6,852	)	 	$	(8,471	)	
Weighted average limited partner units outstanding(a)	 	 	4,507	 	 	 	10,506	 	
Earnings per limited partner unit (basic and diluted)	 	$	(1.52	)	 	$	(.81	)	
Net loss attributable to general partner	 	$	(140	)	 	$	(173	)	
Weighted average general partner units outstanding	 	 	89	 	 	 	205	 	
Earnings per general partner unit (basic and diluted)	 	$	(1.58	)	 	$	(.84	)	

 

 
			
(a)		Includes unvested phantom units, which are considered participating securities, of 361,052 and 424,157 as of December 31, 2009 and 2010, respectively.	

		
20.  	Subsequent Events	
 
The Partnership has evaluated subsequent events through March 30, 2011.
 
On February 11, 2011, the Board of Directors of our general partner approved a distribution in the amount of $3.8 million, consisting of payments of $3.6 million to the limited partners, $0.1 million to the general partner and $0.1 million in DER payments.
 
On March 1, 2011, the Compensation Committee of the Board of Directors of our general partner approved the award of a total of 40,000 phantom units to certain employees under the Partnership LTIP program. The units vest over four years and do not contain distribution equivalent rights.

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Report of Independent Registered Public Accounting Firm
 
To the Board of Directors of the General Partner of
American Midstream Partners, LP
 
We have audited the accompanying combined balance sheets of American Midstream Partners Predecessor (the Predecessor) as of December 31, 2008 and October 31, 2009, and the related combined statements of operations, of changes in group equity and of cash flows for the year ended December 31, 2008 and the ten-month period ended October 31, 2009. These financial statements are the responsibility of the management of American Midstream Partners, LP. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of the Predecessor at December 31, 2008 and October 31, 2009, and the results of their operations and their cash flows for the year ended December 31, 2008 and the ten-month period ended October 31, 2009 in conformity with accounting principles generally accepted in the United States of America.
 
As discussed in Note 11 to the financial statements, the financial results contain significant transactions with related parties.
 
/s/ PricewaterhouseCoopers LLP
 
Houston, Texas
March 30, 2011

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American Midstream Partners Predecessor
 
 Combined Balance Sheets
 December 31, 2008 and October 31, 2009

 	 	December 31,	 	 	October 31,	 	
 	 	2008	 	 	2009	 	
 	 	(in thousands)	 	
 		
Assets	 	 	 	 	 	 	 	 	
Current assets	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	421	 	 	$	149	 	
Trade accounts receivable, net	 	 	1,411	 	 	 	248	 	
Unbilled revenue	 	 	8,121	 	 	 	8,508	 	
Due from affiliates	 	 	20,635	 	 	 	33,779	 	
Notes receivable — affiliates	 	 	26,872	 	 	 	—	 	
Other current assets	 	 	2,314	 	 	 	1,668	 	
 	 	 	 	 	 	 	 	 	
Total current assets	 	 	59,774	 	 	 	44,352	 	
Property, plant and equipment, net	 	 	216,903	 	 	 	205,126	 	
Other assets	 	 	565	 	 	 	684	 	
 	 	 	 	 	 	 	 	 	
Total assets	 	$	277,242	 	 	$	250,162	 	
 	 	 	 	 	 	 	 	 	
Liabilities and Group Equity	 	 	 	 	 	 	 	 	
Current liabilities	 	 	 	 	 	 	 	 	
Accounts payable	 	$	273	 	 	$	1,515	 	
Accrued gas purchases	 	 	19,688	 	 	 	11,575	 	
Notes payable — affiliate	 	 	39,339	 	 	 	—	 	
Accrued expenses and other current liabilities	 	 	3,538	 	 	 	2,616	 	
 	 	 	 	 	 	 	 	 	
Total current liabilities	 	 	62,838	 	 	 	15,706	 	
Other liabilities	 	 	2,605	 	 	 	2,864	 	
Long-term debt	 	 	60,000	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	
Total liabilities	 	 	125,443	 	 	 	18,570	 	
Commitments and contingencies (see Note 10)	 	 	 	 	 	 	 	 	
Group equity	 	 	151,799	 	 	 	231,592	 	
 	 	 	 	 	 	 	 	 	
Total liabilities and group equity	 	$	277,242	 	 	$	250,162	 	

 
The accompanying notes are an integral part of these combined financial statements.

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American Midstream Partners Predecessor
 
 Combined Statements of Operations
 Year Ended December 31, 2008 and Period Ended October 31, 2009

 	 	 	 	 	 	 	 	 	
 	 	Year Ended	 	 	Period Ended	 	
 	 	December 31,	 	 	October 31,	 	
 	 	2008	 	 	2009	 	
 	 	(in thousands)	 	
 		
Total revenue	 	$	366,348	 	 	$	143,132	 	
Operating expenses:	 	 	 	 	 	 	 	 	
Purchases of natural gas, NGLs and condensate	 	 	323,205	 	 	 	113,227	 	
Direct operating expenses	 	 	13,423	 	 	 	10,331	 	
Selling, general and administrative expenses	 	 	8,618	 	 	 	8,577	 	
Depreciation expense	 	 	13,481	 	 	 	12,630	 	
 	 	 	 	 	 	 	 	 	
Total operating expenses	 	 	358,727	 	 	 	144,765	 	
 	 	 	 	 	 	 	 	 	
Operating income (loss)	 	 	7,621	 	 	 	(1,633	)	
Other (income) expenses:	 	 	 	 	 	 	 	 	
Interest expense	 	 	5,747	 	 	 	3,728	 	
Other (income) expense	 	 	(854	)	 	 	(24	)	
 	 	 	 	 	 	 	 	 	
Total other (income) expenses	 	 	4,893	 	 	 	3,704	 	
 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	2,728	 	 	$	(5,337	)	

 
The accompanying notes are an integral part of these combined financial statements.

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American Midstream Partners Predecessor
 
 Combined Statements of Group Equity
 Year Ended December 31, 2008 and Period Ended October 31, 2009

 	 	(in thousands)	 	
 		
Group equity at December 31, 2007	 	$	145,833	 	
Contributions by parent	 	 	10,500	 	
Distributions to parent	 	 	(7,245	)	
Other comprehensive loss	 	 	(17	)	
Net income	 	 	2,728	 	
 	 	 	 	 	
Group equity at December 31, 2008	 	$	151,799	 	
Contributions by parent	 	 	111,103	 	
Distributions to parent	 	 	(25,772	)	
Other comprehensive loss	 	 	(201	)	
Net loss	 	 	(5,337	)	
 	 	 	 	 	
Group equity at October 31, 2009	 	$	231,592	 	

 
The accompanying notes are an integral part of these combined financial statements.

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American Midstream Partners Predecessor

 Combined Statements of Cash Flows
  December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

 	 	Year Ended	 	 	Period Ended	 	
 	 	December 31,	 	 	October 31,	 	
 	 	2008	 	 	2009	 	
 	 	(in thousands)	 	
 		
Cash flows from operating activities	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	2,728	 	 	$	(5,337	)	
Adjustments to reconcile change in net assets to net cash provided by operating activities	 	 	 	 	 	 	 	 	
Depreciation expense	 	 	13,481	 	 	 	12,630	 	
Changes in operating assets and liabilities	 	 	 	 	 	 	 	 	
Accounts receivable	 	 	1,102	 	 	 	1,163	 	
Unbilled revenue	 	 	3,009	 	 	 	(387	)	
Due from affiliates	 	 	8,262	 	 	 	(13,144	)	
Notes receivable from affiliates	 	 	(4,400	)	 	 	26,872	 	
Other current assets	 	 	(1,755	)	 	 	646	 	
Other assets	 	 	(156	)	 	 	(320	)	
Accounts payable	 	 	(807	)	 	 	1,242	 	
Accrued gas purchase	 	 	(1,662	)	 	 	(8,113	)	
Accrued expenses and other current liabilities	 	 	(1,761	)	 	 	(922	)	
Other liabilities	 	 	114	 	 	 	259	 	
 	 	 	 	 	 	 	 	 	
Net cash provided by operating activities	 	 	18,155	 	 	 	14,589	 	
 	 	 	 	 	 	 	 	 	
Cash flows from investing activities	 	 	 	 	 	 	 	 	
Additions to property, plant and equipment	 	 	(10,486	)	 	 	(853	)	
 	 	 	 	 	 	 	 	 	
Net cash (used in) investing activities	 	 	(10,486	)	 	 	(853	)	
 	 	 	 	 	 	 	 	 	
Cash flows from financing activities	 	 	 	 	 	 	 	 	
Contributions from parent	 	 	10,500	 	 	 	111,103	 	
Distributions to parent	 	 	(7,245	)	 	 	(25,772	)	
Repayments of notes to affiliates	 	 	(11,184	)	 	 	(39,339	)	
Repayments of long term debt	 	 	—	 	 	 	(60,000	)	
 	 	 	 	 	 	 	 	 	
Net cash (used in) financing activities	 	 	(7,929	)	 	 	(14,008	)	
 	 	 	 	 	 	 	 	 	
Net (decrease) increase in cash and cash equivalents	 	 	(260	)	 	 	(272	)	
Cash and cash equivalents	 	 	 	 	 	 	 	 	
Beginning of period	 	 	681	 	 	 	421	 	
 	 	 	 	 	 	 	 	 	
End of period	 	$	421	 	 	$	149	 	
 	 	 	 	 	 	 	 	 	
Supplemental cash flow information	 	 	 	 	 	 	 	 	
Interest payments	 	$	325	 	 	$	132	 	

The accompanying notes are an integral part of these combined financial statements.

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American Midstream Partners Predecessor

Notes to Combined Financial Statements
 December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

1.  	Summary of Significant Accounting Policies	
 
Nature of Business
 
These financial statements of American Midstream Partners Predecessor (the “Predecessor”) have been prepared in connection with the proposed initial public offering (the “Offering”) of limited partner units in America Midstream Partners, LP (the “Partnership”), which was formed in Delaware on August 20, 2009. The Partnership acquired certain natural gas pipeline and processing businesses from Enbridge Energy Partners, LP (“Enbridge”) in November 2009, as described below.
 
On October 2, 2009, Enbridge Midcoast Energy, L.P. (the “Parent”), a wholly-owned subsidiary of Enbridge entered into a purchase and sale agreement with American Midstream, LLC, a wholly owned subsidiary of the Partnership, for the sale of certain pipeline entities (collectively the “Entities”). The sale was effective as of November 1, 2009. In conjunction with the close of the transaction, the Parent received cash consideration of $150,817,898, excluding the subsequent settlement for working capital as provided in the purchase and sale agreement.
 
The Entities were as follows:
 
Enbridge Pipelines — Alabama Intrastate L.L.C.
Enbridge Pipelines — Bamagas Intrastate L.L.C.
Enbridge Pipelines — Tennessee River L.L.C.
Enbridge Pipelines — Mississippi L.L.C.
Enbridge Pipelines — Midla L.L.C.
Enbridge Pipelines — Alabama Gathering L.L.C.
Enbridge Pipelines — AlaTenn L.L.C.
Midcoast Holdings No. One L.L.C.
Mid Louisiana Gas Transmission L.L.C.
Enbridge Offshore Pipelines — Seacrest, LP
Enbridge Pipelines — SIGCO Intrastate L.L.C.
Enbridge Pipelines — Louisiana Intrastate, L.L.C.
 
These combined financial statements represent the financial position, results of operations, changes in group equity and cash flows of the Predecessor, have been prepared from the separate records maintained by Enbridge and include allocations of certain Enbridge corporate expenses. Management of the Partnership believes that the assumptions and estimates used in preparation of the combined financial statements are reasonable. However, the combined financial statements may not necessarily reflect what the Predecessor’s financial position, results of operations or cash flows would have been had it been a stand-alone entity during the periods presented. Because of the nature of these combined financial statements, the Parent’s net investment in the Entities, including amounts due to the Parent are shown as “group equity”.
 
The Predecessor’s interstate natural gas pipeline assets transport natural gas through Federal Energy Regulatory Commission (the “FERC”) regulated interstate natural gas pipelines in Louisiana, Mississippi, Alabama and Tennessee. The interstate pipelines include:

 	• 	Enbridge Pipelines — Midla L.L.C., which owns and operates approximately 370 miles of interstate pipeline that runs from the Monroe gas field in northern Louisiana south through Mississippi to Baton Rouge, Louisiana.	
 		
 	• 	Enbridge Pipelines — AlaTenn L.L.C., which owns and operates approximately 295 miles of interstate pipeline that runs through the Tennessee River Valley from Selmer, Tennessee to Huntsville, Alabama and serves an eight county area in Alabama, Mississippi, and Tennessee.	

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American Midstream Partners Predecessor

Notes to Combined Financial Statements  (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

Events and transactions subsequent to the balance sheet date have been evaluated through March 30, 2011, the date these combined financial statements were issued.
 
Basis of Presentation and Use of Estimates
 
The combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) on the basis of the Parent’s historical ownership of the Predecessor. All significant inter-company accounts and transactions have been eliminated in the preparation of the accompanying combined financial statements.
 
Use of Estimates
 
When preparing financial statements in conformity with accounting principles generally accepted in the United States of America, the Predecessor must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.
 
Accounting for Regulated Operations
 
Certain of the Predecessor’s natural gas pipelines are subject to regulation by the FERC. The FERC exercises statutory authority over matters such as construction, transportation rates the Predecessor charges and the Predecessor’s underlying accounting practices, and ratemaking agreements with customers. Accordingly, the Predecessor records costs that are allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a nonregulated entity. Also, the Predecessor records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for the Predecessor’s regulated entities. As of December 31, 2008 and October 31, 2009, the Predecessor had no significant regulatory assets or liabilities.
 
Revenue Recognition and the Estimation of Revenues and Cost of Natural Gas
 
The Predecessor recognizes revenue when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectibility is reasonably assured. The Predecessor records revenue and cost of product sold on the gross basis for those transactions where the Predecessor acted as the principal and takes title to natural gas, natural gas liquids (“NGLs”) or condensate that are purchased for resale. When the Predecessors’ customers pay it a fee for providing a service such as gathering, treating or transportation the

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American Midstream Partners Predecessor

Notes to Combined Financial Statements  (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009
 
Predecessor records those fees separately in revenues. For the year and period ended December 31, 2008 and October 31 2009, respectively, the Predecessor had the following revenues by category:

 	 	Year Ended	 	 	Period Ended	 	
 	 	December 31,	 	 	October 31,	 	
 	 	2008	 	 	2009	 	
 	 	(in thousands)	 	
 		
Revenue	 	 	 	 	 	 	 	 	
Transportation — firm	 	$	15,780	 	 	$	10,616	 	
Transportation — interruptible	 	 	2,331	 	 	 	1,662	 	
Sales of natural gas, NGLs and condensate	 	 	348,034	 	 	 	129,673	 	
Other	 	 	203	 	 	 	1,181	 	
 	 	 	 	 	 	 	 	 	
 	 	$	366,348	 	 	$	143,132	 	

 
The Predecessor derives revenue in its business from the following types of arrangements:

 	• 	Fee-Based.   Under these arrangements, the Predecessor generally is paid a fixed cash fee for gathering and transporting natural gas.	
 		
 	• 	Percent-of-Proceeds, or POP.   Under these arrangements, the Predecessor generally gathers raw natural gas from producers at the wellhead or other supply points, transports it through the Predecessor’s gathering system, processes it and sells the residue natural gas and NGLs at market prices. Where the Predecessor provides processing services at the processing plants that it owns, or obtains processing services for its own account under its elective processing arrangements, the Predecessor typically retains and sells a percentage of the residue natural gas and resulting NGLs.	
 		
 	• 	Fixed-Margin.   Under these arrangements, the Predecessor purchases natural gas from producers or suppliers at receipt points on the Predecessor’s systems at an index price less a fixed transportation fee and simultaneously sells an identical volume of natural gas at delivery points on the Predecessor’s systems at the same, undiscounted index price.	
 		
 	• 	Firm Transportation.   The Predecessor’s obligation to provide firm transportation service means that the Predecessor is obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on the Predecessor’s part, the shipper pays a specified reservation charge, whether or not it utilizes the capacity. In most cases, the shipper also pays a variable use charge with respect to quantities actually transported by the Predecessor.	
 		
 	• 	Interruptible Transportation.   The Predecessor’s obligation to provide interruptible transportation service means that the Predecessor is only obligated to transport natural gas nominated by the shipper to the extent that the Predecessor was available capacity. For this service the shipper pays no reservation charge but pays a variable use charge for quantities actually shipped.	
 
Estimates of Revenue and Cost of Natural Gas
 
The Predecessor must estimate its current month revenue and cost of gas to permit the timely preparation of the combined financial statements. The Predecessor generally cannot compile actual billing information nor obtain actual vendor invoices within a timeframe that would permit the recording of this actual data prior to the preparation of the combined financial statements. As a result, the Predecessor records an estimate each month for its operating revenues and cost of natural gas based on the best available volume and price data for natural gas delivered and received, along with a true-up of the prior month’s estimate to equal the prior month’s actual data. As a result there is one month of estimated data reported in the Predecessor’s operating

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American Midstream Partners Predecessor

Notes to Combined Financial Statements  (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009
 
revenues and cost of natural gas for each of the year ended December 31, 2008. The operating revenues and cost of natural gas for the ten months ended October 31, 2009 reflects actual invoiced amounts.
 
Cash and Cash Equivalents
 
The Predecessor considers all highly liquid investments with an original maturity of three months or less at the date of purchase to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.
 
Allowance for Doubtful Accounts
 
The Predecessor establishes provisions for losses on accounts receivable when it determines that it will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of December 31, 2008 and October 31, 2009 the Predecessor has recorded, $170,393 and $985,956, respectively, in allowances for doubtful accounts.
 
Inventory
 
Inventory includes product inventory and material and supplies inventory. The Entities records all product inventories at the lower of its cost, as determined on a weighted average basis, or market value. The product inventory consists of liquid hydrocarbons and natural gas. Upon disposition, product inventory is recorded to “Purchases of natural gas, NGL’s and Condensate” at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value.
 
Operational Balancing Agreements and Natural Gas Imbalances
 
To facilitate deliveries of natural gas and provide for operational flexibility, the Predecessor has operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through receipt or delivery of natural gas. Natural gas imbalances are recorded as gas imbalances and classified within “Other currents assets” on the Predecessor’s combined balance sheets using the posted index prices, which approximate market rates, or the Predecessor’s weighted average cost of natural gas.
 
Property, Plant and Equipment
 
The Predecessor capitalizes expenditures related to property, plant and equipment that have a useful life greater than one year for 1) assets purchased or constructed; 2) existing assets that are replaced, improved, or the useful lives of which have been extended; and 3) all land, regardless of cost. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.
 
The Predecessor records property, plant and equipment at its original cost, which the Predecessor depreciates on a straight-line basis over the lesser of its estimated useful life or the estimated remaining lives. The Predecessor’s determination of the useful lives of property, plant and equipment requires the Predecessor to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by the Predecessor’s assets, normal wear and tear of the facilities, and the extent and frequency of maintenance

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American Midstream Partners Predecessor

Notes to Combined Financial Statements  (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009
 
programs. The Predecessor records depreciation using the group method of depreciation which is commonly used by pipelines, utilities and similar entities.
 
Impairment of Long Lived Assets
 
The Predecessor evaluates the recoverability of its property, plant and equipment when events or circumstances such as economic obsolescence, business climate, legal and other factors indicate the Predecessor may not recover the carrying amount of the assets. The Predecessor continually monitors its businesses, the market and business environment to identify indicators that could suggest an asset may not be recoverable. The Predecessor evaluates the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. These cash flow estimates require the Predecessor to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. The Predecessor recognizes an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires the Predecessor to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes the Predecessor makes to these projections and assumptions could result in significant revisions to the Predecessor’s evaluation of the recoverability of its property, plant and equipment and the recognition of an impairment loss in its consolidated statements of income. No impairment losses were recognized during the year ended and period ended December 31, 2008 and October 31, 2009, respectively.
 
The Predecessor assess its long-lived assets for impairment using authoritative guidance. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. Fair values, for the purposes of the impairment test, are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.
 
Examples of long-lived asset impairment indicators include:

 	• 	A significant decrease in the market price of a long-lived asset or group;	
 		
 	• 	A significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;	
 		
 	• 	A significant adverse change in legal factors or in the business climate could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;	
 		
 	• 	An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group;	
 		
 	• 	A current-period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long lived asset or asset group; and	
 		
 	• 	A current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.	
 
Income Taxes
 
All of the entities of the Entities are disregarded for U.S. federal income tax purposes or for the majority of states that impose an income tax. The Entities’ income tax expense results from the enactment of state

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American Midstream Partners Predecessor

Notes to Combined Financial Statements  (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009
 
income tax laws by the State of Texas that apply to entities organized as partnerships. The Texas margin tax is computed on our modified gross margin and was not significant for each of the year ended December 31, 2008 and the period ended October 31, 2009. The Predecessor has determined these taxes to be income taxes as set forth in the authoritative accounting guidance.
 
Commitments, Contingencies and Environmental Liabilities
 
The Predecessor expenses or capitalizes, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. The Predecessor expenses amounts it incurs for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. It records liabilities for environmental matters when assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of inflation and other factors. These amounts also consider the Predecessor’s prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Its estimates are subject to revision in future periods based on actual costs or new information. The Predecessor evaluates recoveries from insurance coverage separately from the liability and, when recovery is probable, it records and reports an asset separately from the associated liability in its combined financial statements.
 
The Predecessor recognizes liabilities for other commitments and contingencies when, after fully analyzing the available information, determines it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, it accrues the most likely amount, or if no amount is more likely than another, it accrues the minimum of the range of probable loss. The Predecessor expenses legal costs associated with loss contingencies as such costs are incurred.
 
Asset Retirement Obligations (“AROs”)
 
AROs are legal obligations associated with the retirement of tangible long-lived assets that result from the asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, the Predecessor records an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. The Predecessor depreciates the capitalized ARO using the straight-line method over the period during which the related long-lived asset is expected to provide benefits. After the initial period of ARO recognition, the Predecessor revises the ARO to reflect the passage of time or revisions to the amounts of estimated cash flows or their timing.
 
Group Equity
 
The group equity balance represents a net balance reflecting the Parent’s initial investment in Entities and subsequent adjustments resulting from the operations of the Entities and various transactions between the Parent and the Entities. Other transactions affecting the group equity include general, administrative and overhead costs incurred by the Parent that are allocated to the Entities. There are no terms of settlement or interest charges associated with the group equity balance.

2.  	Concentration of Credit Risk and Trade Accounts Receivable	
 
The Predecessor’s primary market areas are located in the United States along the Gulf Coast and in the Southeast. The Predecessor has a concentration of trade receivable balances due from companies engaged in the production, trading, distribution and marketing of natural gas and NGL products. These concentrations of

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American Midstream Partners Predecessor

Notes to Combined Financial Statements  (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009
 
customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. The Predecessor’s customers’ historical financial and operating information is analyzed prior to extending credit. The Predecessor manages its exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions, the Predecessor may request letters of credit, prepayments or guarantees. The Predecessor maintains allowances for potentially uncollectible accounts receivable.
 
As of December 31, 2008, ConocoPhillips Corporation and Dow Hydrocarbons and Resources were significant customers, representing at least 10% of the Predecessor’s combined revenue, accounting for $40.5 million and $44.2 million, respectively, of the Predecessor’s combined revenue in the combined statement of operations for the year then ended. As of October 31, 2009, ConocoPhillips Corporation and Enbridge Marketing were significant customers, representing at least 10% of the Predecessor’s combined revenue, accounting for $18.5 million and $40.4 million, respectively, of the Predecessor’s combined revenue in the consolidated statement of operations for the period then ended.

3.  	Other Current Assets	
 
Other current assets as of December 31, 2008 and October 31, 2009 were as follows:

 	 	2008	 	 	2009	 	
 	 	(in thousands)	 	
 		
Gas imbalance	 	$	76	 	 	$	530	 	
Inventory	 	 	2,045	 	 	 	180	 	
Other receivables	 	 	42	 	 	 	773	 	
Regulatory deferrals	 	 	74	 	 	 	88	 	
Other prepaid amounts	 	 	77	 	 	 	97	 	
 	 	 	 	 	 	 	 	 	
 	 	$	2,314	 	 	$	1,668	 	

 
		
4.  	Property, Plant and Equipment, Net	
 
Property, plant and equipment, net, as of December 31, 2008 and October 31, 2009 were as follows:

 	 	Useful Life	 	 	2008	 	 	2009	 	
 	 	 	 	 	(in thousands)	 	
 		
Land	 	 	—	 	 	$	433	 	 	$	433	 	
Rights-of-way	 	 	40	 	 	 	26,628	 	 	 	26,633	 	
Pipelines	 	 	40	 	 	 	180,470	 	 	 	181,096	 	
Compressors, meters and other operating equipment	 	 	20	 	 	 	25,821	 	 	 	28,182	 	
Vehicles, office furniture and equipment	 	 	5	 	 	 	6,847	 	 	 	6,937	 	
Processing and treating plants	 	 	40	 	 	 	30,009	 	 	 	32,306	 	
Construction in progress	 	 	—	 	 	 	7,222	 	 	 	1,110	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total property, plant and equipment	 	 	 	 	 	 	277,430	 	 	 	276,697	 	
Accumulated depreciation	 	 	 	 	 	 	(60,527	)	 	 	(71,571	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, plant and equipment, net	 	 	 	 	 	$	216,903	 	 	$	205,126	 	

 
For regulatory purposes, the Predecessor’s uses FERC-approved depreciation rates to depreciate the regulated pipeline assets of Enbridge Pipelines — Midla L.L.C. and Enbridge Pipelines — AlaTenn L.L.C. Of

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American Midstream Partners Predecessor

Notes to Combined Financial Statements  (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009
 
the gross property, plant and equipment balances at December 31, 2008 and October 31, 2009 $102.4 million and $101.8 million, respectively, related to regulated assets.

5.  	Asset Retirement Obligations (“AROs”)	
 
No assets are legally restricted for purposes of settling the Predecessor’s AROs for the year ended December 31, 2008 and the period ended October 31, 2009. Following is a reconciliation of the beginning and ending aggregate carrying amount of the Predecessor’s ARO liabilities for the year ended December 31, 2008 and the period ended October 31, 2009:

 	 	2008	 	 	2009	 	
 	 	(in thousands)	 	
 		
Balance at beginning of period	 	$	1,926	 	 	$	2,006	 	
Accretion expense	 	 	80	 	 	 	108	 	
 	 	 	 	 	 	 	 	 	
Balance at end of period	 	$	2,006	 	 	$	2,114	 	

 
		
6.  	Other Assets, net	
 
Other assets, net, as of December 31, 2008 and October 31, 2009 were as follows:

 	 	2008	 	 	2009	 	
 	 	(in thousands)	 	
 		
Other post-retirement benefit plan assets, net	 	$	258	 	 	$	395	 	
Deferred charges, net	 	 	128	 	 	 	123	 	
Other	 	 	179	 	 	 	166	 	
 	 	 	 	 	 	 	 	 	
 	 	$	565	 	 	$	684	 	

 
		
7.  	Accrued Expenses and Other Current Liabilities	
 
Other current liabilities as of December 31, 2008 and October 31, 2009 were as follows:

 	 	2008	 	 	2009	 	
 	 	(in thousands)	 	
 		
Accrued expenses	 	$	2,972	 	 	$	1,109	 	
Property taxes payable	 	 	500	 	 	 	1,103	 	
Environmental reserves	 	 	45	 	 	 	380	 	
Deferred revenue	 	 	21	 	 	 	24	 	
 	 	 	 	 	 	 	 	 	
 	 	$	3,538	 	 	$	2,616	 	

 
		
8.  	Notes Payable — Affiliate	
 
Short-term Borrowings
 
Throughout 2008 and 2009, the Entities periodically entered into certain short-term demand promissory notes with Enbridge Midcoast Limited Holdings, L.L.C. (“EMLH”), a wholly owned subsidiary of the Parent. At December 31, 2008 and October 31, 2009, the outstanding balances of short-term borrowings were $39.3 and $0 million, respectively. Prior to March 2008, interest on these borrowings is charged at 130% of the applicable federal rate as published by the U.S Treasury (“AFR”). Subsequent to March 2008, interest on these borrowings is charged at the greater of i) the London Interbank Offering Rate (“LIBOR”), plus 100 basis

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American Midstream Partners Predecessor

Notes to Combined Financial Statements  (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009
 
points or ii) 130% of the published AFR. The weighted average interest rate on outstanding borrowings at October 31, 2009 and December 31, 2008 was 1.36% and 3.59%, respectively.
 
Long-term Borrowings
 
During 2004, the Entities entered into a series of promissory notes with EMLH, totaling $65 million, with repayment of the principal balance of these notes due on November 26, 2014 (“the Notes”). Interest on the Notes was paid semiannually in May and November of each year. The capitalized deferred costs of approximately $0.1 million and $0.1 million as of December 31, 2008 and October 31, 2009 associated with the issuance of this debt are amortized over the ten year life of the Notes.
 
Debt Extinguishment
 
On October 29, 2009, the Parent made a capital contribution of $111.1 million to the Entities. A portion of the proceeds of this contribution were used by the Entities to repay in full the short-term borrowings and the Notes outstanding with EMLH.
 
Financial Covenants
 
There were no restrictive covenants associated with either the short-term borrowings or the Notes.

9.  	Post-Employment Benefits	
 
Post-Employment Benefits Other Than Pensions
 
We sponsor a contributory postretirement plan that provides medical, dental and life insurance benefits for qualifying U.S. retired employees (referred to as the “OPEB Plan”).
 
The tables below detail the changes in the benefit obligation, the fair value of plan assets and the recorded asset or liability of the OPEB Plan using the accrual method.

 	 	OPEB Plan	 	
 	 	2008	 	 	2009	 	
 	 	(in thousands)	 	
 		
Change in benefit obligation	 	 	 	 	 	 	 	 	
Benefit obligation, January 1	 	$	642	 	 	$	741	 	
Service cost	 	 	11	 	 	 	8	 	
Interest cost	 	 	46	 	 	 	36	 	
Actuarial (gain) loss	 	 	71	 	 	 	10	 	
Benefits paid	 	 	(29	)	 	 	(24	)	
 	 	 	 	 	 	 	 	 	
Benefit obligation, December 31, and October 31	 	$	741	 	 	$	771	 	

 

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American Midstream Partners Predecessor

Notes to Combined Financial Statements  (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

 	 	OPEB Plan	 	
 	 	2008	 	 	2009	 	
 	 	(in thousands)	 	
 		
Change in plan assets	 	 	 	 	 	 	 	 	
Fair value of plan assets, January 1	 	$	987	 	 	$	999	 	
Actual return on plan assets	 	 	(72	)	 	 	123	 	
Employer’s contributions	 	 	113	 	 	 	68	 	
Participant contributions	 	 	—	 	 	 	—	 	
Benefits paid	 	 	(29	)	 	 	(24	)	
 	 	 	 	 	 	 	 	 	
Fair value of plan assets, December 31 and October 31	 	$	999	 	 	$	1,166	 	

 
 	 	 	 	 	 	 	 	 	
 	 	OPEB Plan	 	
 	 	2008	 	 	2009	 	
 	 	(in thousands)	 	
 		
Funded status	 	 	 	 	 	 	 	 	
Funded status	 	$	258	 	 	$	395	 	
Unrecognized actuarial gain	 	 	(339	)	 	 	(138	)	
 	 	 	 	 	 	 	 	 	
Prepaid (accrued) benefit cost, December 31 and October 31	 	$	(81	)	 	$	257	 	

 
The amounts of plan assets and liabilities recognized in our statements of financial position at December 31, 2008 and October 31, 2009 are as follows:

 	 	OPEB Plan	 	
 	 	2008	 	 	2009	 	
 	 	(in thousands)	 	
 		
Long term other assets	 	$	258	 	 	$	395	 	
 	 	 	 	 	 	 	 	 	
 	 	$	258	 	 	$	395	 	

 
The amounts included in accumulated other comprehensive income that have not yet been recognized as components of net periodic benefit expense are $339,000 and $138,000 as of December 31, 2008 and October 31, 2009, respectively.
 
Economic Assumptions
 
The assumptions made in measurement of the projected benefit obligations or assets of the OPEB Plan were as follows:

 	 	OPEB Plan	 	
 	 	2008	 	 	2009	 	
 		
Discount rate	 	 	6.00%	 	 	 	5.70%	 	
Expected return on plan assets	 	 	4.50%	 	 	 	6.00%	 	
Rate of compensation increase	 	 	5%	 	 	 	0%	 	
Health care trend	 	 	Grade 9% to
5% over 5 years	 	 	 	Grade 9% to
5% over 5 years	 	

 
A one percent increase in the assumed medical and dental care trend rate would result in an increase of $0.1 million in the accumulated post-employment benefit obligations. A one percent decrease in the assumed
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American Midstream Partners Predecessor

Notes to Combined Financial Statements  (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009
 
medical and dental care trend rate would result in a decrease of $0.1 million in the accumulated post-employment benefit obligations.
 
The above table reflects the expected long-term rates of return on assets of the OPEB Plan on a weighted-average basis. The overall expected rates of return are based on the asset allocation targets with estimates for returns on equity and debt securities based on long term expectations. We believe this rate approximates the return we will achieve over the long-term on the assets of our plans. Historically, we have used a discount rate that corresponds to one or more high quality corporate bond indices as an estimate of our expected long-term rate of return on plan assets for our OPEB Plan assets. For 2008 and 2009 we selected the discount rate using the Citigroup Pension Discount Curve, or CPDC. The CPDC spot rates represent the equivalent yield on high-quality, zero-coupon bonds for specific maturities. These rates are used to develop a single, equivalent discount rate based on the OPEB Plan’s expected future cash flows.
 
Expected Future Benefit Payments
 
The following table presents the benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five years thereafter by the OPEB Plan:

 	 	Gross Benefit	 	
 	 	Payments	 	
For the year ending	 	OPEB Plan	 	
 	 	(in thousands)	 	
 		
2011	 	$	56	 	
2012	 	 	56	 	
2013	 	 	55	 	
2014	 	 	55	 	
2015	 	 	55	 	
Five years thereafter	 	 	235	 	

The expected future benefit payments are based upon the same assumptions used to measure the projected benefit obligations of the OPEB Plan including benefits associated with future employee service.
 
Expected Contributions to the Plans
 
We expect to make contributions to the OPEB Plan for the year ending December 31, 2010 of $0.1 million.
 
Plan Assets
 
The weighted average asset allocation of our OPEB Plan at the measurement date by asset category, are as follows:

 	 	 	 	 	 	 	 	 	
 	 	OPEB Plan	 	
 	 	2008	 	 	2009	 	
 		
Fixed income(a)	 	 	77.0%	 	 	 	77.0%	 	
Cash and short-term assets(b)	 	 	23.0%	 	 	 	23.0%	 	
 	 	 	 	 	 	 	 	 	
 	 	 	100.0%	 	 	 	100.0%	 	

 

 
			
(a)		United States government securities, corporate bonds and notes and asset-backed securities.	

 
			
(b)		Cash and securities with maturities of one year or less.	

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American Midstream Partners Predecessor

Notes to Combined Financial Statements  (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

10.  	Commitments and Contingencies	
 
The Predecessor is subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to natural gas pipeline operations, and the Predecessor could, at times, be subject to environmental cleanup and enforcement actions. The Predecessor attempts to manage this environmental risk through appropriate environmental policies and practices to minimize any impact the Predecessor’s operations may have on the environment.

11.  	Related Party Transactions	
 
The Predecessor was wholly owned by the Parent and its subsidiaries. The Parent has allocated certain overhead costs associated with general and administrative services, including executive management, accounting, information services, engineering, and human resources support to the Predecessor. These overhead costs were allocated based primarily on a percentage of revenue, which management of the Partnership believes is reasonable.
 
Revenues, Purchases and Cost Allocations
 
The Predecessor recorded operating revenues to Enbridge affiliates for natural gas gathering, treating, processing, marketing and transportation services. Included in the Predecessor’s results for the year ended December 31, 2008 and period ended October 31, 2009, are operating revenues $202.9 of million and $73.9 million, respectively, related to these transactions.
 
The Predecessor also purchased natural gas from Enbridge affiliates for sale to third-parties at market prices on the date of purchase. Included in the Predecessor’s results for the year ended December 31, 2008 and period ended October 31, 2009, are costs for natural gas purchases of $0.1 million and $0.9 million, respectively, related to these purchases.
 
The Predecessor incurred expenses related to managerial, administrative, operational and director services provided by the Parent and its affiliates and the ultimate parent, Enbridge pursuant to service agreements (referred to as “Enbridge cost allocations”).
 
The Enbridge cost allocations were charged based on a combination of fixed monthly fees for operations and allocations for overhead costs, which were based primarily on the direct salaries of the employees by department and by entity. The allocation method has been consistently applied in the statements of operations.
 
The total amount charged to the Predecessor for Enbridge cost allocations for the year ended December 31, 2008 and period ended October 31, 2009 was $7.9 million and $6.7 million, respectively.
 
At December 31, 2008 and October 31, 2009, the Predecessor had affiliate receivables of $21.0 million and $34.4 million, respectively related to these transactions.
 
Financing Transactions with Affiliates
 
Demand Notes Receivable and Notes Payable
 
At December 31, 2008 and October 31, 2009, the Predecessor had affiliate notes receivable of $26.9 and $0 million, respectively, and affiliate notes payable of $39.3 million and $0 million, respectively. For the twelve months ended December 31, 2008 and ten months ended October 31, 2009, the Predecessor had interest income of $0.8 million and $0.4 million, respectively. Interest expense for the twelve months ended December 31, 2008 and ten months ended October 31, 2009 was $6.7 million and $4.1 million, respectively.

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American Midstream Partners Predecessor

Notes to Combined Financial Statements  (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009
 
Equity Transactions
 
For the twelve months ended December 31, 2008 and the ten months ended October 31, 2009, the Predecessor received contributions by the Parent of $10.5 million and $111.1 million, respectively, and paid distributions to the Parent of $7.3 million and $25.8 million, respectively.

12.  	Reportable Segments	
 
The Predecessor’s operations are located in the United States and are organized into two reporting segments: (1) Gathering and Processing; and (2) Transmission.
 
Gathering and Processing
 
The Predecessor’s Gathering and Processing segment provides “wellhead to market” services to producers of natural gas and oil, which include transporting raw natural gas from the wellhead through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs and selling or delivering pipeline quality natural gas and NGLs to various markets and pipeline systems.
 
Transmission
 
The Predecessor’s Transmission segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, including local distribution companies, or LDCs, utilities and industrial, commercial and power generation customers.
 
These segments are monitored separately by American Midstream Partners, LP for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by the Predecessor to monitor the business of each segment.
 
The following tables set forth the Predecessor’s segment information:

 	 	 	 	 	Gathering	 	 	 	 	
 	 	 	 	 	and	 	 	 	 	
 	 	Transmission	 	 	Processing	 	 	Total	 	
 	 	(in thousands)	 	
 		
Year ended December 31, 2008	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenue	 	$	16,487	 	 	$	349,861	 	 	$	366,348	 	
Segment gross margin(a)	 	$	15,789	 	 	$	27,354	 	 	$	43,143	 	
Direct operating expenses	 	 	 	 	 	 	 	 	 	 	13,423	 	
Selling, general and administrative expenses	 	 	 	 	 	 	 	 	 	 	8,618	 	
Depreciation expense	 	 	 	 	 	 	 	 	 	 	13,481	 	
Interest expense	 	 	 	 	 	 	 	 	 	 	5,747	 	
Other (income) expense	 	 	 	 	 	 	 	 	 	 	(854	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	 	 	 	 	 	 	 	 	$	2,728	 	

 

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American Midstream Partners Predecessor

Notes to Combined Financial Statements  (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

 	 	 	 	 	Gathering	 	 	 	 	
 	 	 	 	 	and	 	 	 	 	
 	 	Transmission	 	 	Processing	 	 	Total	 	
 	 	(in thousands)	 	
 		
Period ended October 31, 2009	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenue	 	$	10,175	 	 	$	132,957	 	 	$	143,132	 	
Segment gross margin(a)	 	$	9,881	 	 	$	20,024	 	 	$	29,905	 	
Direct operating expenses	 	 	 	 	 	 	 	 	 	 	10,331	 	
Depreciation expense	 	 	 	 	 	 	 	 	 	 	8,577	 	
Selling, general and administrative expense	 	 	 	 	 	 	 	 	 	 	12,630	 	
Interest expense	 	 	 	 	 	 	 	 	 	 	3,728	 	
Other (income) expense	 	 	 	 	 	 	 	 	 	 	(24	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	 	 	 	 	 	 	 	 	$	(5,337	)	

 

			
(a)		Segment gross margin for our Gathering and Processing segment consists of total revenue, less purchases of natural gas, propane and NGLs. Segment gross margin for our Transmission segment consists of total revenue, less purchases of natural gas. Gross margin consists of the sum of the segment gross margin amounts for each of these segments. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.	
 
Asset information by segment, including capital expenditures, is not included in reports used by management of American Midstream Partners, LP in its monitoring of performance and therefore, is not disclosed.
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APPENDIX A

Second Amended and Restated Agreement
of Limited Partnership of American Midstream Partners, LP

Table of Contents

 
SECOND AMENDED AND RESTATED
AGREEMENT OF LIMITED PARTNERSHIP

OF

AMERICAN MIDSTREAM PARTNERS, LP

Table of Contents

TABLE OF CONTENTS

 	 	 	 	 	 	 	
ARTICLE I DEFINITIONS	 	 	A-1	 	
Section 1.1	 	Definitions	 	 	A-1	 	
Section 1.2	 	Construction	 	 	A-20	 	
ARTICLE II ORGANIZATION	 	 	A-20	 	
Section 2.1	 	Formation	 	 	A-20	 	
Section 2.2	 	Name	 	 	A-20	 	
Section 2.3	 	Registered Office; Registered Agent; Principal Office; Other Offices	 	 	A-20	 	
Section 2.4	 	Purpose and Business	 	 	A-21	 	
Section 2.5	 	Powers	 	 	A-21	 	
Section 2.6	 	Term	 	 	A-21	 	
Section 2.7	 	Title to Partnership Assets	 	 	A-21	 	
ARTICLE III RIGHTS OF LIMITED PARTNERS	 	 	A-22	 	
Section 3.1	 	Limitation of Liability	 	 	A-22	 	
Section 3.2	 	Management of Business	 	 	A-22	 	
Section 3.3	 	Outside Activities of the Limited Partners	 	 	A-22	 	
Section 3.4	 	Rights of Limited Partners	 	 	A-22	 	
ARTICLE IV CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS	 	 	A-23	 	
Section 4.1	 	Certificates	 	 	A-23	 	
Section 4.2	 	Mutilated, Destroyed, Lost or Stolen Certificates	 	 	A-23	 	
Section 4.3	 	Record Holders	 	 	A-24	 	
Section 4.4	 	Transfer Generally	 	 	A-24	 	
Section 4.5	 	Registration and Transfer of Limited Partner Interests	 	 	A-24	 	
Section 4.6	 	Transfer of the General Partner’s General Partner Interest	 	 	A-25	 	
Section 4.7	 	Transfer of Incentive Distribution Rights	 	 	A-26	 	
Section 4.8	 	Restrictions on Transfers	 	 	A-26	 	
Section 4.9	 	Eligibility Certifications; Ineligible Holders	 	 	A-26	 	
Section 4.10	 	Redemption of Partnership Interests of Ineligible Holders	 	 	A-27	 	
ARTICLE V CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS	 	 	A-28	 	
Section 5.1	 	Intentionally Omitted	 	 	A-28	 	
Section 5.2	 	Contributions by the General Partner and the Initial Limited Partners	 	 	A-28	 	
Section 5.3	 	Contributions by Limited Partners	 	 	A-28	 	
Section 5.4	 	Interest and Withdrawal of Capital Contributions	 	 	A-29	 	
Section 5.5	 	Capital Accounts	 	 	A-29	 	
Section 5.6	 	Issuances of Additional Partnership Interests	 	 	A-31	 	
Section 5.7	 	Conversion of Subordinated Units	 	 	A-32	 	
Section 5.8	 	Limited Preemptive Right	 	 	A-32	 	
Section 5.9	 	Splits and Combinations	 	 	A-32	 	
Section 5.10	 	Fully Paid and Non-Assessable Nature of Limited Partner Interests	 	 	A-33	 	
Section 5.11	 	Issuance of Common Units in Connection with Reset of Incentive Distribution Rights	 	 	A-33	 	
ARTICLE VI ALLOCATIONS AND DISTRIBUTIONS	 	 	A-34	 	
Section 6.1	 	Allocations for Capital Account Purposes	 	 	A-34	 	

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Table of Contents

 	 	 	 	 	 	 	
Section 6.2	 	Allocations for Tax Purposes	 	 	A-41	 	
Section 6.3	 	Requirement and Characterization of Distributions; Distributions to Record Holders	 	 	A-42	 	
Section 6.4	 	Distributions of Available Cash from Operating Surplus	 	 	A-43	 	
Section 6.5	 	Distributions of Available Cash from Capital Surplus	 	 	A-44	 	
Section 6.6	 	Adjustment of Minimum Quarterly Distribution and Target Distribution Levels	 	 	A-45	 	
Section 6.7	 	Special Provisions Relating to the Holders of Subordinated Units	 	 	A-45	 	
Section 6.8	 	Special Provisions Relating to the Holders of Incentive Distribution Rights	 	 	A-46	 	
Section 6.9	 	Entity-Level Taxation	 	 	A-46	 	
ARTICLE VII MANAGEMENT AND OPERATION OF BUSINESS	 	 	A-46	 	
Section 7.1	 	Management	 	 	A-46	 	
Section 7.2	 	Certificate of Limited Partnership	 	 	A-48	 	
Section 7.3	 	Restrictions on the General Partner’s Authority	 	 	A-48	 	
Section 7.4	 	Reimbursement of the General Partner	 	 	A-49	 	
Section 7.5	 	Outside Activities	 	 	A-49	 	
Section 7.6	 	Loans from the General Partner; Loans or Contributions from the Partnership or Group Members	 	 	A-50	 	
Section 7.7	 	Indemnification	 	 	A-51	 	
Section 7.8	 	Liability of Indemnitees	 	 	A-52	 	
Section 7.9	 	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties	 	 	A-53	 	
Section 7.10	 	Other Matters Concerning the General Partner	 	 	A-54	 	
Section 7.11	 	Purchase or Sale of Partnership Interests	 	 	A-54	 	
Section 7.12	 	Registration Rights of the General Partner and its Affiliates	 	 	A-55	 	
Section 7.13	 	Reliance by Third Parties	 	 	A-56	 	
ARTICLE VIII BOOKS, RECORDS, ACCOUNTING AND REPORTS	 	 	A-57	 	
Section 8.1	 	Records and Accounting	 	 	A-57	 	
Section 8.2	 	Fiscal Year	 	 	A-57	 	
Section 8.3	 	Reports	 	 	A-57	 	
ARTICLE IX TAX MATTERS	 	 	A-58	 	
Section 9.1	 	Tax Returns and Information	 	 	A-58	 	
Section 9.2	 	Tax Elections	 	 	A-58	 	
Section 9.3	 	Tax Controversies	 	 	A-58	 	
Section 9.4	 	Withholding	 	 	A-58	 	
ARTICLE X ADMISSION OF PARTNERS	 	 	A-59	 	
Section 10.1	 	Admission of Limited Partners	 	 	A-59	 	
Section 10.2	 	Admission of Successor General Partner	 	 	A-59	 	
Section 10.3	 	Amendment of Agreement and Certificate of Limited Partnership	 	 	A-59	 	
ARTICLE XI WITHDRAWAL OR REMOVAL OF PARTNERS	 	 	A-60	 	
Section 11.1	 	Withdrawal of the General Partner	 	 	A-60	 	
Section 11.2	 	Removal of the General Partner	 	 	A-61	 	
Section 11.3	 	Interest of Departing General Partner and Successor General Partner	 	 	A-61	 	
Section 11.4	 	Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages	 	 	A-63	 	
 	 	 	 		 	 	
Section 11.5	 	Withdrawal of Limited Partners	 	 	A-63	 	

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ARTICLE XII DISSOLUTION AND LIQUIDATION	 	 	A-63	 	
Section 12.1	 	Dissolution	 	 	A-63	 	
Section 12.2	 	Continuation of the Business of the Partnership After Dissolution	 	 	A-63	 	
Section 12.3	 	Liquidator	 	 	A-64	 	
Section 12.4	 	Liquidation	 	 	A-64	 	
Section 12.5	 	Cancellation of Certificate of Limited Partnership	 	 	A-65	 	
Section 12.6	 	Return of Contributions	 	 	A-65	 	
Section 12.7	 	Waiver of Partition	 	 	A-65	 	
Section 12.8	 	Capital Account Restoration	 	 	A-65	 	
ARTICLE XIII AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE	 	 	A-65	 	
Section 13.1	 	Amendments to be Adopted Solely by the General Partner	 	 	A-65	 	
Section 13.2	 	Amendment Procedures	 	 	A-67	 	
Section 13.3	 	Amendment Requirements	 	 	A-67	 	
Section 13.4	 	Special Meetings	 	 	A-68	 	
Section 13.5	 	Notice of a Meeting	 	 	A-68	 	
Section 13.6	 	Record Date	 	 	A-68	 	
Section 13.7	 	Adjournment	 	 	A-68	 	
Section 13.8	 	Waiver of Notice; Approval of Meeting; Approval of Minutes	 	 	A-69	 	
Section 13.9	 	Quorum and Voting	 	 	A-69	 	
Section 13.10	 	Conduct of a Meeting	 	 	A-69	 	
Section 13.11	 	Action Without a Meeting	 	 	A-70	 	
Section 13.12	 	Right to Vote and Related Matters	 	 	A-70	 	
ARTICLE XIV MERGER, CONSOLIDATION OR CONVERSION	 	 	A-70	 	
Section 14.1	 	Authority	 	 	A-70	 	
Section 14.2	 	Procedure for Merger, Consolidation or Conversion	 	 	A-71	 	
Section 14.3	 	Approval by Limited Partners	 	 	A-71	 	
Section 14.4	 	Amendment of Partnership Agreement	 	 	A-72	 	
Section 14.5	 	Certificate of Merger	 	 	A-73	 	
Section 14.6	 	Effect of Merger or Consolidation	 	 	A-73	 	
ARTICLE XV RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS	 	 	A-73	 	
Section 15.1	 	Right to Acquire Limited Partner Interests	 	 	A-73	 	
ARTICLE XVI GENERAL PROVISIONS	 	 	A-74	 	
Section 16.1	 	Addresses and Notices; Written Communications	 	 	A-74	 	
Section 16.2	 	Further Action	 	 	A-75	 	
Section 16.3	 	Binding Effect	 	 	A-75	 	
Section 16.4	 	Integration	 	 	A-75	 	
Section 16.5	 	Creditors	 	 	A-75	 	
Section 16.6	 	Waiver	 	 	A-75	 	
Section 16.7	 	Third-Party Beneficiaries	 	 	A-75	 	
Section 16.8	 	Counterparts	 	 	A-75	 	
Section 16.9	 	Applicable Law; Forum; Venue and Jurisdiction	 	 	A-75	 	
Section 16.10	 	Invalidity of Provisions	 	 	A-76	 	
Section 16.11	 	Consent of Partners	 	 	A-76	 	
Section 16.12	 	Facsimile Signatures	 	 	A-76	 	

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Section 16.13	 	Provisions Regarding Effective Time	 	 	A-77	 	
ARTICLE XVII CERTAIN TRANSACTIONS IN CONNECTION WITH THE INITIAL PUBLIC OFFERING	 	 	A-77	 	
Section 17.1	 	Non-Pro Rata Redemption of Common Units	 	 	A-77	 	
EXHIBIT A  Certificate Evidencing Common Units Representing Limited Partner Interests in American Midstream Partners, LP	 	 	A-A-1	 	

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SECOND AMENDED AND RESTATED
AGREEMENT OF LIMITED PARTNERSHIP OF
AMERICAN MIDSTREAM PARTNERS, LP

THIS SECOND AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF AMERICAN MIDSTREAM PARTNERS, LP dated as of          , 2011, is entered into by and between American Midstream GP, LLC, a Delaware limited liability company, as the General Partner, and AIM Midstream Holdings, LLC, a Delaware limited liability company ( “AIM Midstream” ), together with any other Persons who are now or become Partners in the Partnership or parties hereto as provided herein.

WHEREAS, the General Partner and the Limited Partners entered into that certain First Amended and Restated Agreement of Limited Partnership dated as of November 4, 2009 (the “First A/R Partnership Agreement” );
 
WHEREAS, in connection with the Initial Public Offering of Common Units (as such terms are hereinafter defined) by the Partnership, the Board of Directors of the General Partner deems it necessary and appropriate to amend and restate the First A/R Partnership Agreement to provide for certain amendments in connection with the Initial Public Offering; and
 
WHEREAS, pursuant to Article XIII of the First A/R Partnership Agreement, the First A/R Partnership Agreement may be amended upon approval by the General Partner, the holders of at least 90% of the Outstanding Units (as defined in the First A/R Partnership Agreement) voting as a single class, such approval having been duly obtained in accordance with the procedures set forth in the First A/R Partnership Agreement;
 
NOW, THEREFORE, the General Partner does hereby amend and restate the Second A/R Partnership Agreement to provide in its entirety as follows:

ARTICLE I
 
DEFINITIONS

Section 1.1   Definitions.
 
The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“Acquisition” means any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing the long-term operating capacity or operating income of the Partnership Group from the operating capacity or operating income of the Partnership Group existing immediately prior to such transaction.

“Additional Book Basis” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:
 
(a) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.
 
(b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided , that the amount treated as Additional Book Basis pursuant hereto as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the

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Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).
 
“Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis” ), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period.
 
“Additional Limited Partner” means a Person admitted to the Partnership as a Limited Partner pursuant to Section 10.1(b) and who is shown as such on the books and records of the Partnership.
 
“Adjusted Capital Account” means the Capital Account maintained for each Partner as of the end of each taxable period of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all losses and deductions that, as of the end of such taxable period, are reasonably expected to be allocated to such Partner in subsequent taxable periods under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (ii) the amount of all distributions that, as of the end of such taxable period, are reasonably expected to be made to such Partner in subsequent taxable periods in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to) the taxable period in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii) ). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of a Partnership Interest shall be the amount that such Adjusted Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.
 
“Adjusted Operating Surplus” means, with respect to any period, (a) Operating Surplus generated with respect to such period, less (b) (i) any net increase in Working Capital Borrowings with respect to that period and (ii) any net decrease in cash reserves for Operating Expenditures with respect to such period not relating to an Operating Expenditure made with respect to such period, and plus (c) (i) any net decrease in Working Capital Borrowings with respect to that period, (ii) any net decrease made in subsequent periods in cash reserves for Operating Expenditures initially established with respect to such period to the extent such decrease results in a reduction in Adjusted Operating Surplus in subsequent periods pursuant to clause (b)(ii) above and (iii) any net increase in cash reserves for Operating Expenditures with respect to such period required by any debt instrument for the repayment of principal, interest or premium. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clause (a)(i) of the definition of Operating Surplus.
 
“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.5(d).
 
“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.
 
“Aggregate Quantity of IDR Reset Common Units” has the meaning assigned to such term in Section 5.11(a).

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“Aggregate Remaining Net Positive Adjustments” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Partners.
 
“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1 , including a Curative Allocation (if appropriate to the context in which the term “ Agreed Allocation” is used).
 
“Agreed Value” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution as determined by the General Partner. The General Partner shall use such method and in the case of an Adjusted Preoperty, the fair market value of such Adjusted Property on the date of the revaluation event as described in Section 5.5(d) , in both cases as determined by the General Partner.
 
“Agreement” means this Second Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, as it may be amended, supplemented or restated from time to time.
 
“AIM Midstream” means AIM Midstream Holdings, LLC, a Delaware limited liability company.
 
“American Midstream GP” means American Midstream GP, LLC, a Delaware limited liability company.
 
“Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer, partner or managing member or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.
 
“Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:
 
(a) the sum of:
 
(i) all cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand at the end of such Quarter; and
 
(ii) if the General Partner so determines, all or any portion of additional cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand on the date of determination of Available Cash with respect to such Quarter resulting from Working Capital Borrowings made subsequent to the end of such Quarter;
 
(b) less the amount of any cash reserves (or the Partnership’s proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) established by the General Partner to:
 
(i) provide for the proper conduct of the business of the Partnership Group (including reserves for future capital expenditures, for anticipated future credit needs of the Partnership Group and for refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing relating to FERC rate proceedings or rate proceedings under applicable state law, if any) subsequent to such Quarter;
 
(ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject; or
 
(iii) provide funds for distributions under Section 6.4 or Section 6.5 in respect of any one or more of the next four Quarters;
 
provided, however , that the General Partner may not establish cash reserves pursuant to clause (iii) above if the effect of establishing such reserves would be that the Partnership is unable to distribute the Minimum Quarterly Distribution on all Common Units, plus any Cumulative Common Unit Arrearage on all Common

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Units, with respect to such Quarter; and, provided further , that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.
 
Notwithstanding the foregoing, “ Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.
 
“Board of Directors” means the board of directors of the General Partner.
 
“Book Basis Derivative Items” means any item of income, deduction, gain or loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, depletion, or gain or loss with respect to an Adjusted Property).
 
“Book-Down Event” means an event that triggers a negative adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).
 
“Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.5 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.
 
“Book-Up Event” means an event that triggers a positive adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).
 
“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Texas shall not be regarded as a Business Day.

“Capital Account” means the capital account maintained for a Partner pursuant to Section 5.5. The “Capital Account” of a Partner in respect of a Partnership Interest shall be the amount that such Capital Account would be it such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

“Capital Contribution” means (i) any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership or that is contributed or deemed contributed to the Partnership on behalf of a Partner (including, in the case of an underwritten offering of Units, the amount of any underwriting discounts or commissions) or (ii) current distributions that a Partner is entitled to receive but otherwise waives.

“Capital Improvement” means any (a) addition or improvement to the capital assets owned by any Group Member, (b) acquisition (through an asset acquisition, merger, stock acquisition or other form of investment) of existing, or the construction of new or improvement or replacement of existing, capital assets (including gathering systems, compressors, processing plants, transmission lines and related or similar midstream assets) or (c) capital contribution by a Group Member to a Person that is not a Subsidiary in which a Group Member has, or after such capital contribution will have, an equity interest to fund such Group Member’s pro rata share of the cost of the addition or improvement to or the acquisition (through an asset acquisition, merger, stock acquisition or other form of investment) of existing, or the construction of new or replacement of existing, capital assets (including gathering systems, compressors, processing plants, transmission lines and related or similar midstream assets) by such Person, in each case if and to the extent such addition, improvement, acquisition, construction or replacement is made to increase the long-term operating capacity, or operating income of the Partnership Group, in the case of clauses (a) and (b), or such Person, in the case of clause (c), from the operating capacity or operating income of the Partnership Group or such Person, as the case may be, existing immediately prior to such addition, improvement, acquisition, construction or replacement.

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“Capital Surplus” has the meaning assigned to such term in Section 6.3(a).
 
“Carrying Value” means (a) with respect to a Contributed Property or Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, amortization and cost recovery deductions charged to the Partners’ Capital Accounts in respect of such Contributed Property or Adjusted Property, and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.5(d) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.
 
“Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.
 
“Certificate” means (a) a certificate (i) substantially in the form of Exhibit A to the First A/R Partnership Agreement (if such certificate was issued on or after November 4, 2009, but prior to the date hereof) or substantially in the form of Exhibit A to this Agreement (if such certificate is issued on or after the date hereof), (ii) issued in global form in accordance with the rules and regulations of the Depositary or (iii) in such other form as may be adopted by the General Partner, in each case issued by the Partnership evidencing ownership of one or more Common Units or (b) a certificate, in such form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more other Partnership Interests.
 
“Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.2 , as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.
 
“Citizenship Eligibility Trigger” has the meaning assigned to such term in Section 4.9(a)(ii).
 
“claim” (as used in Section 7.12(c) ) has the meaning assigned to such term in Section 7.12(c).
 
“Closing Date” means November 4, 2009.

“Closing Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted to trading on the principal National Securities Exchange on which the respective Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests are not listed or admitted to trading on any National Securities Exchange, the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the primary reporting system then in use in relation to such Limited Partner Interests of such class, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner.

“Code” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.
 
“Combined Interest” has the meaning assigned to such term in Section 11.3(a).
 
“Commences Commercial Service” means the date a Capital Improvement is first put into or commences commercial service following completion of construction, acquisition, development and testing, as applicable.
 
“Commission” means the United States Securities and Exchange Commission or any successor agency having jurisdiction under the Securities Act.

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“Commodity Hedge Contract” means any commodity exchange, swap, forward, cap, floor, collar or other similar agreement or arrangement entered into for the purpose of hedging the Partnership Group’s exposure to fluctuations in the price of hydrocarbons or other commodities in their operations and not for speculative purposes.
 
“Common Unit” means a Partnership Interest representing a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Common Units in this Agreement. The term “Common Unit” does not include a Subordinated Unit prior to its conversion into a Common Unit pursuant to the terms hereof.
 
“Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, as to any Quarter within the Subordination Period, the excess, if any, of (a) the Minimum Quarterly Distribution with respect to a Common Unit in respect of such Quarter over (b) the sum of all Available Cash distributed with respect to a Common Unit in respect of such Quarter pursuant to Section 6.4(b)(i).
 
“Conflicts Committee” means a committee of the Board of Directors composed of one or more Independent Directors.
 
“Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.5(d) , such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.
 
“Cumulative Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, and as of the end of any Quarter, the excess, if any, of (a) the sum resulting from adding together the Common Unit Arrearage as to an IPO Common Unit for each of the Quarters within the Subordination Period ending on or before the last day of such Quarter over (b) the sum of any distributions theretofore made pursuant to Section 6.4(b)(ii) and the second sentence of Section 6.5 with respect to an IPO Common Unit (including any distributions to be made in respect of the last of such Quarters).
 
“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).
 
“Current Market Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the average of the daily Closing Prices per Limited Partner Interest of such class for the 20 consecutive Trading Days immediately prior to such date.
 
“Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq ., as amended, supplemented or restated from time to time, and any successor to such statute.
 
“Departing General Partner” means a former general partner from and after the effective date of any withdrawal or removal of such former general partner pursuant to Section 11.1 or Section 11.2.
 
“Disposed of Adjusted Property” has the meaning ascribed to such term in Section 6.1(d)(xii)(B).
 
“Depositary” means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.
 
“Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).
 
“Eligibility Certificate” has the meaning assigned to such term in Section 4.9(b).
 
“Eligible Holder” means a Limited Partner whose (a) federal income tax status would not, in the determination of the General Partner, have the material adverse effect described in Section 4.9(a)(i) or (b) nationality, citizenship or other related status would not, in the determination of the General Partner, create a substantial risk of cancellation or forfeiture as described in Section 4.9(a)(ii).
 
“Estimated Incremental Quarterly Tax Amount” has the meaning assigned to such term in Section 6.9.
 
“Estimated Maintenance Capital Expenditures” means an estimate made in good faith by the Board of Directors (with the concurrence of the Conflicts Committee) of the average quarterly Maintenance Capital

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Expenditures that the Partnership will incur over the long term. The Board of Directors (with the concurrence of the Conflicts Committee) will be permitted to make such estimate in any manner it determines reasonable. The estimate will be made annually and whenever an event occurs that is likely to result in a material adjustment to the amount of Maintenance Capital Expenditures on a long term basis. The Partnership shall disclose to its Partners any change in the amount of Estimated Maintenance Capital Expenditures in its reports made in accordance with Section 8.3 to the extent not previously disclosed. Except as provided in the definition of Subordination Period, any adjustments to Estimated Maintenance Capital Expenditures shall be prospective only.
 
“Event of Withdrawal” has the meaning assigned to such term in Section 11.1(a).
 
“Existing Credit Agreement” means the Revolving Credit and Term Loan Agreement, dated as of October 5, 2009, by and among the Operating Company, the other borrowers party thereto, Comerica Bank, as Administrative Agent, Co-Lead Arranger and Syndication Administrative Agent, BBVA Compass Bank, as Documentation Agent and Co-Lead Arranger, and the other lenders party thereto.

“Expansion Capital Expenditures” means cash expenditures for Acquisitions or Capital Improvements, and shall not include Maintenance Capital Expenditures or Investment Capital Expenditures. Expansion Capital Expenditures shall include interest (and related fees) on debt incurred and distributions on equity issued, in each case, to finance the construction of a Capital Improvement and paid in respect of the period beginning on the date that the Group Member enters into a binding obligation to commence construction of a Capital Improvement and ending on the earlier to occur of the date that such Capital Improvement Commences Commercial Service and the date that such Capital Improvement is abandoned or disposed of. Debt incurred or equity issued to fund such construction period interest payments or such construction period distributions on equity paid during such period, shall also be deemed to be debt incurred or equity issued, as the case may be, to finance the construction of a Capital Improvement. Expansion Capital Expenditures will include cash contributed by a Group Member to an entity of which such Group Member is, or after such contribution will be, directly or indirectly, an equity owner to be used by such entity for Acquisitions or Capital Improvements. Where capital expenditures are made in part for Expansion Capital Expenditures and in part for other purposes, the General Partner, with the concurrence of the Conflicts Committee, shall determine the allocation of such expenditures between Expansion Capital Expenditures and expenditures made for other purposes.

“FERC” means the Federal Energy Regulatory Commission, or successor to powers thereof.
 
“Final Subordinated Units” has the meaning assigned to such term in Section 6.1(d)(x)(A).
 
“First A/R Partnership Agreement” has the meaning assigned to such term in the recitals to this Agreement.
 
“First Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(D).
 
“First Target Distribution” means 115% of the Minimum Quarterly Distribution per Unit (or, with respect to the Quarter that includes the IPO Closing Date, it means the product of 115% of the Minimum Quarterly Distribution per Unit multiplied by a fraction, the numerator of which is the number of days in such Quarter after the IPO Closing Date, and the denominator of which is the total number of days in such Quarter), subject to adjustment in accordance with Section 5.11 , Section 6.6 and Section 6.9.
 
“Fully Diluted Weighted Average Basis” means, when calculating the number of Outstanding Units for any period, a basis that includes (a) the weighted average number of Outstanding Units plus (b) all Partnership Interests and options, rights, warrants, phantom units and appreciation rights relating to an equity interest in the Partnership (i) that are convertible into or exercisable or exchangeable for Units or for which Units are issuable, in each case that are senior to or pari passu with the Subordinated Units, (ii) whose conversion, exercise or exchange price is less than the Current Market Price on the date of such calculation, (iii) that may be converted into or exercised or exchanged for such Units prior to or during the Quarter immediately following the end of the period for which the calculation is being made without the satisfaction of any contingency beyond the control of the holder other than the payment of consideration and the compliance with

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administrative mechanics applicable to such conversion, exercise or exchange and (iv) that were not converted into or exercised or exchanged for such Units during the period for which the calculation is being made; provided, however, that for purposes of determining the number of Outstanding Units on a Fully Diluted Weighted Average Basis when calculating whether the Subordination Period has ended or Subordinated Units are entitled to convert into Common Units pursuant to Section 5.7 , such Partnership Interests, options, rights, warrants and appreciation rights shall be deemed to have been Outstanding Units only for the four Quarters that comprise the last four Quarters of the measurement period; provided, further, that if consideration will be paid to any Group Member in connection with such conversion, exercise or exchange, the number of Units to be included in such calculation shall be that number equal to the difference between (x) the number of Units issuable upon such conversion, exercise or exchange and (y) the number of Units that such consideration would purchase at the Current Market Price.

“General Partner” means American Midstream GP and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in its capacity as general partner of the Partnership (except as the context otherwise requires).
 
“General Partner Interest” means the ownership interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it) that is evidenced by Notional General Partner Units and includes any and all benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.
 
“Gross Liability Value” means, with respect to any Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm’s length transaction.
 
“Group” means a Person that with or through any of its Affiliates or Associates has any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.
 
“Group Member” means a member of the Partnership Group.
 
“Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.
 
“Holder” as used in Section 7.12 , has the meaning assigned to such term in Section 7.12(a).
 
“IDR Reset Common Unit” has the meaning assigned to such term in Section 5.11(a).
 
“IDR Reset Election” has the meaning assigned to such term in Section 5.11(a).
 
“Incentive Distribution Right” means a Limited Partner Interest issued to American Midstream GP, which Limited Partner Interest will confer upon the holder thereof only the rights and obligations specifically provided in this Agreement with respect to Incentive Distribution Rights (and no other rights otherwise available to or other obligations of a holder of a Partnership Interest).
 
“Incentive Distributions” means any amount of cash distributed to the holders of the Incentive Distribution Rights pursuant to Section 6.4.
 
“Incremental Income Taxes” has the meaning assigned to such term in Section 6.9.

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“Indemnified Persons” has the meaning assigned to such term in Section 7.12(c).

“Indemnitee” means (a) the General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a manager, managing member, general partner, director, officer, employee, agent, fiduciary or trustee of any Group Member, the General Partner or any Departing General Partner or any Affiliate of any Group Member, the General Partner or any Departing General Partner, (e) any Person who is or was serving at the request of the General Partner or any Departing General Partner or any Affiliate of the General Partner or any Departing General Partner as a manager, managing member, general partner, director, officer, employee, agent, fiduciary or trustee of another Person owing a fiduciary duty to any Group Member; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, (f) any Person who controls a General Partner or Departing General Partner and (g) any Person the General Partner designates as an Indemnitee for purposes of this Agreement.

“Independent Director” means any director that (a) is not a security holder, officer or employee of the General Partner, (b) is not an officer, director or employee of any Affiliate of the General Partner, (c) is not a holder of any ownership interest in the Partnership Group other than Common Units and awards that may be granted to such director under the Long Term Incentive Plan (or similar plan implemented by the General Partner or the Partnership) and (d) meets the independence standards required of directors who serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission promulgated thereunder and by any National Securities Exchange on which the Common Units are listed or admitted to trading.
 
“Ineligible Holder” has the meaning assigned such term in Section 4.9(c).
 
“Initial Limited Partners” means AIM Midstream, the LTIP Partners and the General Partner (with respect to the Common Units, Subordinated Units and Incentive Distribution Rights held by them).
 
“Initial Public Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement.
 
“Initial Unit Price” means (a) with respect to the Common Units and the Subordinated Units, the IPO Price or (b) with respect to any other class or series of Units, the price per Unit at which such class or series of Units is initially issued by the Partnership, as determined by the General Partner, in each case adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of Units.
 
“Interest Rate Hedge Contract” means any interest rate exchange, swap, forward, cap, floor collar or other similar agreement or arrangement entered into for the purpose of reducing the exposure of the Partnership Group to fluctuations in interest rates in their financing activities and not for speculative purposes.
 
“Interim Capital Transactions” means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness (other than Working Capital Borrowings and other than for items purchased on open account or for a deferred purchase price in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) sales of equity interests of any Group Member; (c) sales or other voluntary or involuntary dispositions of any assets of any Group Member other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and (ii) sales or other dispositions of assets as part of normal asset retirements or replacements; (d) the termination of Commodity Hedge Contracts or Interest Rate Hedge Contracts prior to the respective specified termination dates; (e) capital contributions received by a Group Member or, in the case of capital contributions received by a Person that is not a Subsidiary of the Partnership, capital contributions received from the owner(s) or members of such Person that is not a Group Member; or (f) corporate reorganizations or restructurings.
 
“Investment Capital Expenditures” means capital expenditures other than Maintenance Capital Expenditures and Expansion Capital Expenditures. Investment Capital Expenditures will include cash contributed by a Group Member to an entity of which such Group Member is, or after such contribution will

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be directly or indirectly, an equity owner to be used by such entity for capital expenditures other than Maintenance Capital Expenditures and Expansion Capital Expenditures.

“IPO Closing Date” means the closing date of the sale of the Common Units in the Initial Public Offering.
 
“IPO Common Units” means the Common Units sold in the Initial Public Offering.
 
“IPO Price” means the price per Common Unit at which the Underwriters offer the Common Units for sale to the public as set forth on the cover page of the final prospectus filed pursuant to Rule 424(b) of the rules and regulations of the Commission with respect to the Initial Public Offering.
 
“IPO Proceeds” means the portion of the net proceeds received by the Partnership from the issuance and sale of Common Units in connection with the closing of the Initial Public Offering that, according to the disclosure set forth in the section of the Registration Statement entitled “Use of Proceeds,” are to be distributed to AIM Midstream, the LTIP Partners and the General Partner.
 
“Liability” means any liability or obligation of any nature, whether accrued, contingent or otherwise.
 
“Limited Partner” means, unless the context otherwise requires, each Initial Limited Partner, each Additional Limited Partner and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3 , in each case, in such Person’s capacity as limited partner of the Partnership; provided, however , that when the term “ Limited Partner” is used herein in the context of any vote or other approval, including Article XIII and Article XIV , such term shall not, solely for such purpose, include any holder of an Incentive Distribution Right (solely with respect to its Incentive Distribution Rights and not with respect to any other Limited Partner Interest held by such Person) except as may be required by law.
 
“Limited Partner Interest” means the ownership interest of a Limited Partner in the Partnership, which may be evidenced by Common Units, Subordinated Units, Incentive Distribution Rights or other Partnership Interests or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner to comply with the terms and provisions of this Agreement; provided, however , that when the term “ Limited Partner Interest” is used herein in the context of any vote or other approval, including Article XIII and Article XIV , such term shall not, solely for such purpose, include any Incentive Distribution Right except as may be required by law.
 
“Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2 , the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.
 
“Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.
 
“Long Term Incentive Plan” means the American Midstream GP, LLC Long-Term Incentive Plan of the General Partner, as may be amended, or any equity compensation plan successor thereto or otherwise adopted by the General Partner or the Partnership.
 
“LTIP Partners” means those Limited Partners holding on the date hereof Common Units issued pursuant to the Long Term Incentive Plan, in respect of such Common Units.

“Maintenance Capital Expenditures” means cash expenditures (including expenditures (i) for the addition or improvement to or the replacement of the capital assets owned by any Group Member, (ii) for the acquisition of existing, or the construction or development of new, capital assets or (iii) for any integrity management program, including pursuant to the Gas Transmission Pipeline Integrity Management Rule (49 CFR Part 192, Subpart O) and any corresponding rule of state law) if such expenditures are made to maintain, including over the long term, the operating capacity or operating income of the Partnership Group.

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Maintenance Capital Expenditures shall exclude Expansion Capital Expenditures or Investment Capital Expenditures, but include interest (and related fees) on debt incurred and distributions in respect of equity issued, other than equity issued in the Initial Public Offering, in each case, to finance the construction or development of a replacement asset and paid in respect of the period beginning on the date that a Group Member enters into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that such replacement asset Commences Commercial Service and the date that such replacement asset is abandoned or disposed of. Debt incurred to pay or equity issued, other than equity issued in the Initial Public Offering, to fund construction or development period interest payments, or such construction or development period distributions in respect of equity, shall also be deemed to be debt or equity, as the case may be, incurred to finance the construction or development of a replacement asset and the incremental Incentive Distributions paid relating to newly issued equity shall be deemed to be distributions paid on equity issued to finance the construction or development of a replacement asset. Maintenance Capital Expenditures will include cash contributed by any Group Member to an entity of which such Group Member is, or after such contribution will be, directly or indirectly, an equity owner to be used by such entity for capital expenditures of the types described in clauses (i), (ii) or (iii) above.

“Merger Agreement” has the meaning assigned to such term in Section 14.1.

“Minimum Quarterly Distribution” means $0.4125 per Unit per Quarter (such amount having been determined by the Board of Directors at the time of the Initial Public Offering (or with respect to the Quarter that includes the IPO Closing Date, it means the product of such amount multiplied by a fraction, the numerator of which is the number of days in such Quarter after the IPO Closing Date and the denominator of which is the total number of days in such Quarter)), subject to adjustment in accordance with Section 5.11 , Section 6.6 and Section 6.9 .

“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act and any successor to such statute.
 
“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any Liability either assumed by the Partnership upon such contribution or to which such property is subject when contributed, and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.5(d)(ii) ) at the time such property is distributed, reduced by any Liability either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution, in either case, as determined and required by Treasury Regulations promulgated under Section 704(b) of the Code.
 
“Net Income” means, for any taxable period, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Income shall be determined in accordance with Section 5.5(b) and shall not include any items specially allocated under Section 6.1(d) ; provided , that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xii) .
 
“Net Loss” means, for any taxable period, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.5(b) and shall not include any items specially allocated under Section 6.1(d) ; provided , that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xii) .

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“Net Positive Adjustments” means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.
 
“Net Termination Gain” means, for any taxable period, the sum, if positive, of all items of income, gain, loss or deduction recognized (a) by the Partnership (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or series of related transactions (excluding any disposition to a member of the Partnership Group) or (b) deemed recognized by the Partnership Group pursuant to Section 5.5(d) ; provided, however that the items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.5(b) and shall not include any items of income, gain or loss specially allocated under Section 6.1(d).
 
“Net Termination Loss” means, for any taxable period, the sum, if negative, of all items of income, gain, loss or deduction (a) recognized by the Partnership (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or series of related transactions (excluding any disposition to a member of the Partnership Group) or (b) deemed recognized by the Partnership Group pursuant to Section 5.5(d) ; provided, however the items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.5(b) and shall not include any items of income, gain or loss specially allocated under Section 6.1(d) .

“New Credit Agreement” means the Revolving Credit Agreement, dated as of June   , by and among the Operating Company, as Borrower, the Partnership, Bank of America, N.A., as Administrative Agent, Collateral Agent and L/C Issuer,       , as Syndication Agent, as Documentation Agent, and the other lenders party thereto. Merrill Lynch, Pierce, Fenner & Smith,           and          , as Joint Lead Arrangers and Joint Book Managers.

“New Credit Facility Proceed s” means the portion of the net proceeds of the Partnership’s borrowings made simultaneously with the closing of the Initial Public Offering under its new credit facility that, according to the disclosure set forth in the section of the Registration Statement entitled “Use of Proceeds,” are to be distributed to AIM Midstream.

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Section 6.2(b) . If such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.
 
“Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).
 
“Notice of Election to Purchase” has the meaning assigned to such term in Section 15.1(b) .

“Notional General Partner Unit” means notional units used solely to calculate the General Partner’s Percentage Interest. Notional General Partner Units shall not constitute “Units” for any purpose of this Agreement. There shall initially be           Notional General Partner Units (resulting in the General Partner’s Percentage Interest being 2% after giving effect to any exercise of the Over-Allotment Option). If the General Partner makes additional Capital Contributions pursuant to Section 5.2(b) to maintain its Percentage Interest, the number of Notional General Partner Units shall be increased proportionally to reflect the maintenance of such Percentage Interest.

“Operating Company” means American Midstream, LLC, a Delaware limited liability company, and any successors thereto.
 
“Operating Expenditures” means all Partnership Group cash expenditures (or the Partnership’s proportionate share of expenditures in the case of Subsidiaries that are not wholly owned), including taxes,

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reimbursements of expenses of the General Partner and it Affiliates, interest payments, payments made in the ordinary course of business under Interest Rate Hedge Contracts and Commodity Hedge Contracts ( provided that payments made in connection with the termination (effected on or after the IPO Closing Date) of any Interest Rate Hedge Contract or Commodity Hedge Contract prior to the expiration of its stipulated settlement or termination date shall be included in Operating Expenditures in equal quarterly installments over the remaining scheduled life of such Interest Rate Hedge Contract or Commodity Hedge Contract), Estimated Maintenance Capital Expenditures, director and officer compensation, repayment of Working Capital Borrowings and non-Pro Rata repurchases of Units (other than those made with the proceeds of an Interim Capital Transaction), subject to the following:
 
(a) deemed repayments of Working Capital Borrowings deducted from Operating Surplus pursuant to clause (b)(iii) of the definition of “Operating Surplus” shall not constitute Operating Expenditures when actually repaid;
 
(b) payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than Working Capital Borrowings shall not constitute Operating Expenditures when actually repaid;
 
(c) Operating Expenditures shall not include (i) Expansion Capital Expenditures, (ii) Investment Capital Expenditures, (iii) actual Maintenance Capital Expenditures, (iv) payment of transaction expenses (including taxes) relating to Interim Capital Transactions, (v) distributions to Partners (including any distributions made pursuant to Section 6.4(a) ), (vi) non-Pro Rata purchases of the Units of any class made with the proceeds of an Interim Capital Transaction or (vii) any other payments made in connection with the Initial Public Offering that are described under “Use of Proceeds” in the Registration Statement; and
 
(d) where capital expenditures are made in part for Maintenance Capital Expenditures and in part for other purposes, the General Partner, with the concurrence of the Conflicts Committee, shall determine the allocation of such capital expenditures between Maintenance Capital Expenditures and capital expenditures made for other purposes and, with respect to the part of such capital expenditures consisting of Maintenance Capital Expenditures, the period over which Maintenance Capital Expenditures will be deducted as an Operating Expenditure in calculating Operating Surplus.
 
“Operating Surplus” means, with respect to any period commencing on the IPO Closing Date and ending prior to the Liquidation Date, on a cumulative basis and without duplication,
 
(a) the sum of:

(i) $11.5 million;

(ii) all cash receipts of the Partnership Group (or the Partnership’s proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) for the period beginning on the IPO Closing Date and ending on the last day of such period, but excluding cash receipts from Interim Capital Transactions (except to the extent specified in Section 6.5 and provided that cash receipts from the termination (effected on or after the IPO Closing Date) of a Commodity Hedge Contract or an Interest Rate Hedge Contract prior to its specified termination date shall be included in Operating Surplus in equal quarterly installments over the remaining scheduled life of such Commodity Hedge Contract or Interest Rate Hedge Contract);
 
(iii) all cash receipts of the Partnership Group (or the Partnership’s proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) after the end of such period but on or before the date of determination of Operating Surplus with respect to such period resulting from Working Capital Borrowings; and
 
(iv) cash distributions paid on equity issued to finance all or a portion of the construction, acquisition, development or improvement of a Capital Improvement or replacement of a capital asset (such as equipment or facilities) in respect of the period beginning on the date that the Group Member enters into a binding obligation to commence the construction, acquisition, development or improvement of a Capital Improvement or replacement of a capital asset and ending on the earlier to

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occur of the date the Capital Improvement or capital asset Commences Commercial Service or the date that it is abandoned or disposed of (equity issued to fund construction-, acquisition-, development- or improvement- period interest payments on debt incurred, or construction-, acquisition-, development- or improvement-period distributions on equity issued, to finance the construction, acquisition or development of a Capital Improvement or replacement of a capital asset shall also be deemed to be equity issued to finance the construction, acquisition or development of a Capital Improvement or replacement of a capital asset for purposes of this clause (iv)); less

(b) the sum of:
 
(i) Operating Expenditures for the period beginning on the IPO Closing Date and ending on the last day of such period;
 
(ii) the amount of cash reserves (or the Partnership’s proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) established by the General Partner after the IPO Closing Date to provide funds for future Operating Expenditures; and
 
(iii) all Working Capital Borrowings incurred on or after the IPO Closing Date not repaid within twelve months after having been incurred;
 
provided, however , that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the General Partner so determines.

Notwithstanding the foregoing, “ Operating Surplus” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero. Cash receipts from an Investment Capital Expenditure shall be treated as cash receipts only to the extent they are a return on principal, but in no event shall a return of principal be treated as cash receipts.

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.
 
“Option Closing Date” means the date or dates on which any Common Units are sold by the Partnership to the Underwriters upon exercise of an Over-Allotment Option.
 
“Outstanding” means, with respect to Partnership Interests, all Partnership Interests that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however , that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of the Outstanding Partnership Interests of any class then Outstanding, all Partnership Interests owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Units so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Units shall not, however, be treated as a separate class of Partnership Interests for purposes of this Agreement or the Delaware Act); provided , further , that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of the Outstanding Partnership Interests of any class then Outstanding directly from the General Partner or its Affiliates (other than the Partnership), (ii) any Person or Group who acquired 20% or more of the Outstanding Partnership Interests of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) provided that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 20% or more of any Partnership Interests issued by the Partnership with the prior approval of the Board of Directors.
 
“Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

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“Partner Nonrecourse Debt” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).
 
“Partner Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).
 
“Partner Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.
 
“Partners” means the General Partner and the Limited Partners.
 
“Partnership” means American Midstream Partners, LP, a Delaware limited partnership.
 
“Partnership Group” means collectively the Partnership and its Subsidiaries.
 
“Partnership Interest” means any class or series of equity interest in the Partnership, which shall include any General Partner Interest and Limited Partner Interests but shall exclude any options, rights, warrants and appreciation rights relating to an equity interest in the Partnership.
 
“Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).
 
“Per Unit Capital Amount” means, as of any date of determination, the Capital Account, stated on a per-Unit basis, underlying any Unit held by a Person other than the General Partner or any Affiliate of the General Partner who holds Units.
 
“Percentage Interest” means as of any date of determination (a) as to the General Partner Interest (calculated based upon a number of Notional General Partner Units), and as to any Unitholder with respect to Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of Notional General Partner Units deemed held by the General Partner or the number of Units held by such Unitholder, as the case may be, by (B) the total number of Outstanding Units and Notional General Partner Units, and (b) as to the holders of other Partnership Interests issued by the Partnership in accordance with Section 5.6 , the percentage established as a part of such issuance. The Percentage Interest with respect to an Incentive Distribution Right shall at all times be zero.
 
“Person” means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.
 
“Pro Rata” means (a) when used with respect to Units or any class thereof, apportioned among all designated Units in accordance with their relative Percentage Interests, (b) when used with respect to Partners and/or Record Holders, apportioned among all Partners and/or Record Holders in accordance with their relative Percentage Interests and (c) when used with respect to holders of Incentive Distribution Rights, apportioned among all holders of Incentive Distribution Rights in accordance with the relative number or percentage of Incentive Distribution Rights held by each such holder.
 
“Purchase Date” means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV .

“Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the fiscal quarter of the Partnership that includes the IPO Closing Date, the portion of such fiscal quarter after the IPO Closing Date.

“Rate Eligibility Trigger” has the meaning assigned to such term in Section 4.9(a)(i) .
 
“Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

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“Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.
 
“Record Holder” means (a) with respect to Partnership Interests of any class of Partnership Interests for which a Transfer Agent has been appointed, the Person in whose name a Partnership Interest of such class is registered on the books of the Transfer Agent as of the closing of business on a particular Business Day, or (b) with respect to other classes of Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the closing of business on such Business Day.
 
“Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.10 .
 
“Registration Statement” means the Registration Statement on Form S-1 (Registration No. 333-173191) as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of Common Units in the Initial Public Offering.
 
“Remaining Net Positive Adjustments” means as of the end of any taxable period, (i) with respect to the Unitholders holding Common Units or Subordinated Units, the excess of (a) the Net Positive Adjustments of the Unitholders holding Common Units or Subordinated Units as of the end of such period over (b) the sum of those Partners’ Share of Additional Book Basis Derivative Items for each prior taxable period, (ii) with respect to the General Partner (as holder of the Notional General Partner Units), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period over (b) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the Notional General Partner Units for each prior taxable period, and (iii) with respect to the holders of Incentive Distribution Rights, the excess of (a) the Net Positive Adjustments of the holders of Incentive Distribution Rights as of the end of such period over (b) the sum of the Share of Additional Book Basis Derivative Items of the holders of the Incentive Distribution Rights for each prior taxable period.
 
“Required Allocations” means any allocation of an item of income, gain, loss or deduction pursuant to Section 6.1(d)(i) , Section 6.1(d)(ii) , Section 6.1(d)(iv) , Section 6.1(d)(v) , Section 6.1(d)(vi) , Section 6.1(d)(vii) or Section 6.1(d)(ix) .
 
“Reset MQD” has the meaning assigned to such term in Section 5.11(e) .
 
“Reset Notice” has the meaning assigned to such term in Section 5.11(b) .
 
“Retained Converted Subordinated Unit” has the meaning assigned to such term in Section 5.5(c)(ii) .
 
“Second Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(E) .
 
“Second Target Distribution” means 125% of the Minimum Quarterly Distribution (or, with respect to the Quarter which includes the IPO Closing Date, it means the product of 125% of the Minimum Quarterly Distribution multiplied by a fraction of which the numerator is equal to the number of days in such Quarter after the IPO Closing Date and of which the denominator is the total number of days in such Quarter), subject to adjustment in accordance with Section 5.11 , Section 6.6 and Section 6.9 .
 
“Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.
 
“Securities Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.
 
“Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders holding

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Common Units or Subordinated Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time, (ii) with respect to the General Partner (as holder of the Notional General Partner Units), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustment as of that time, and (iii) with respect to the Partners holding Incentive Distribution Rights, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Remaining Net Positive Adjustments of the Partners holding the Incentive Distribution Rights as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.
 
“Special Approval” means approval by a majority of the members of the Conflicts Committee.
 
“Subordinated Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners and having the rights and obligations specified with respect to Subordinated Units in this Agreement. The term “ Subordinated Unit” does not include a Common Unit. A Subordinated Unit that is convertible into a Common Unit shall not constitute a Common Unit until such conversion occurs.
 
“Subordination Period” means the period commencing immediately following the distributions provided for in Section 6.4(a) on the IPO Closing Date and ending on the first to occur of the following dates:
 
(a) the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter beginning with the Quarter ending September 30, 2014 in respect of which:

(i) (A) distributions of Available Cash from Operating Surplus (excluding the distributions provided for in Section 6.4(a) ) on each of (I) the Outstanding Common Units, Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units and (II) the General Partner Interest, in each case with respect to each of the three consecutive non-overlapping four-Quarter periods immediately preceding such date, equaled or exceeded the sum of the Minimum Quarterly Distribution on all Common Units, Subordinated Units, any other Units that are senior or equal in right of distribution to the Subordinated Units, in each case that were Outstanding at the time such distributions were paid, and the related distributions on the General Partner Interest; and

(B) the Adjusted Operating Surplus for each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of (I) the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units, in each case that were Outstanding during such periods on a Fully Diluted Weighted Average Basis, and (II) the related distributions on the General Partner Interest (for the avoidance of doubt, not including the distribution to the General Partner provided for in Section 6.4(a) ); and
 
(ii) there are no Cumulative Common Unit Arrearages;
 
(b) the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter (beginning with the Quarter ending September 30, 2012) in respect of which:
 
(i) (A) distributions of Available Cash from Operating Surplus (excluding the distributions provided for in Section 6.4(a) ) on each of (I) the Outstanding Common Units, Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units, and (II) the General Partner Interest, in each case with respect to the four-Quarter period immediately preceding such date equaled or exceeded 150% of the Minimum Quarterly Distribution on all of (I) the Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units, in each case that were Outstanding at the time such

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distributions were paid, and (II) the related distributions on the General Partner Interest, in each case in respect of such period; and

(B) the Adjusted Operating Surplus for the four-Quarter period immediately preceding such date equaled or exceeded the sum of (I) 150% of the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units, in each case that were Outstanding during such period on a Fully Diluted Weighted Average Basis, and (II) the related distributions on the General Partner Interest and the corresponding Incentive Distributions (for the avoidance of doubt, not including the distribution to the General Partner provided for in Section 6.4(a) );

(ii) distributions of Available Cash from Operating Surplus (excluding the distributions provided for in Section 6.4(a) ) on each of (A) the Outstanding Common Units, Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units that equaled or exceeded the Minimum Quarterly Distribution, and (B) the General Partner Interest were made, in each case with respect to each Quarter during the four-Quarter period immediately preceding such date; and

(iii) there are no Cumulative Common Unit Arrearages; and
 
(c) the date on which the General Partner is removed as general partner of the Partnership upon the requisite vote by holders of Outstanding Units under circumstances where Cause does not exist and no Units held by the General Partner and its Affiliates are voted in favor of such removal;
 
provided , however , that, for purposes of determining whether the test in clause (a)(i)(B) above has been satisfied, Adjusted Operating Surplus will be adjusted upwards or downwards if the Conflicts Committee determines in good faith that the amount of Estimated Maintenance Capital Expenditures used in the determination of Adjusted Operating Surplus in such clause was materially incorrect, based on circumstances prevailing at the time of original determination of Estimated Maintenance Capital Expenditures, for any one or more of the preceding two four-Quarter periods.
 
“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.
 
“Surviving Business Entity” has the meaning assigned to such term in Section 14.2(b) .
 
“Target Distributions” means each of the Minimum Quarterly Distribution, the First Target Distribution, Second Target Distribution and Third Target Distribution.
 
“Third Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(F) .
 
“Third Target Distribution” means 150% of the Minimum Quarterly Distribution (or, with respect to the Quarter which includes the IPO Closing Date, it means the product of 150% of the Minimum Quarterly Distribution multiplied by a fraction of which the numerator is equal to the number of days in such Quarter after the IPO Closing Date and of which the denominator is the total number of days in such Quarter), subject to adjustment in accordance with Section 5.11 , Section 6.6 and Section 6.9 .

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“Trading Day” means, for the purpose of determining the Current Market Price of any class of Limited Partner Interests, a day on which the principal National Securities Exchange on which such class of Limited Partner Interests are listed is open for the transaction of business or, if Limited Partner Interests of a class are not listed on any National Securities Exchange, a day on which banking institutions in New York City generally are open.
 
“transfer” has the meaning assigned to such term in Section 4.4(a) .
 
“Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as shall be appointed from time to time by the General Partner to act as registrar and transfer agent for the Common Units; provided , that if no Transfer Agent is specifically designated for any other Partnership Interests, the General Partner shall act in such capacity.
 
“Underwriters” means the underwriters in the Initial Public Offering.
 
“Underwriting Agreement” means the underwriting agreement among the Underwriters, the Partnership, the General Partner and the other parties thereto, providing for the purchase of Common Units by the Underwriters in connection with the Initial Public Offering.
 
“Unit” means a Partnership Interest that is designated as a “Unit” and shall include Common Units and Subordinated Units but shall not include (i) Notional General Partner Units (or the General Partner Interest represented thereby) or (ii) Incentive Distribution Rights.
 
“Unitholders” means the holders of Units.
 
“Unit Majority” means (i) during the Subordination Period, at least a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), voting as a separate class, and at least a majority of the Outstanding Subordinated Units, voting as a separate class; and (ii) after the end of the Subordination Period, at least a majority of the Outstanding Common Units, voting as a single class.
 
“Unpaid MQD” has the meaning assigned to such term in Section 6.1(c)(i)(B) .
 
“Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.5(d) )) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date).
 
“Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.5(d) ).
 
“Unrecovered Initial Unit Price” means at any time, with respect to a Unit, the Initial Unit Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of an IPO Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of an IPO Common Unit, adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.
 
“Unrestricted Person” means (a) each Indemnitee, (b) each Partner, (c) each Person who is or was a member, partner, director, officer, employee or agent of any Group Member, a General Partner or any Departing General Partner or any Affiliate of any Group Member, a General Partner or any Departing General Partner and (d) any Person the General Partner designates as an Unrestricted Person for purposes of this Agreement.
 
“U.S. GAAP” means United States generally accepted accounting principles consistently applied.
 
“Withdrawal Opinion of Counsel” has the meaning assigned to such term in Section 11.1(b) .

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“Working Capital Borrowings” means borrowings used solely for working capital purposes or to pay distributions to Partners made pursuant to a credit facility, commercial paper facility or other similar financing arrangements, provided that when such borrowings are incurred it is the intent of the borrower to repay such borrowings within 12 months other than from additional Working Capital Borrowings.

Section 1.2   Construction.

Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include”, “includes”, “including” or words of like import shall be deemed to be followed by the words “without limitation”; and (d) the terms “hereof”, “herein” or “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement.

ARTICLE II
 
ORGANIZATION
 
Section 2.1   Formation.
 
The General Partner and AIM Midstream have previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act. The General Partner hereby amends and restates the First Amended Agreement of Limited Partnership of American Midstream Partners, LP in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act. All Partnership Interests shall constitute personal property of the owner thereof for all purposes.
 
Section 2.2   Name.
 
The name of the Partnership shall be “American Midstream Partners, LP” The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” “LP,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.
 
Section 2.3   Registered Office; Registered Agent; Principal Office; Other Offices.
 
Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 1209 Orange Street, Wilmington, New Castle County, Delaware 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be The Corporation Trust Company. The principal office of the Partnership shall be located at 1614 15th Street, Suite 300, Denver, CO 80202, or such other place as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner shall determine necessary or appropriate. The address of the General Partner shall be 1614 15th Street, Suite 300, Denver, CO 80202, or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

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Section 2.4   Purpose and Business.
 
The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner, in its sole discretion, and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however , that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would be reasonably likely to cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may, in its sole discretion, decline to propose or approve, the conduct by the Partnership of any business free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.
 
Section 2.5   Powers.
 
The Partnership shall be empowered to do any and all acts and things necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.
 
Section 2.6   Term.

The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII . The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.7   Title to Partnership Assets.
 
Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however , that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership as soon as reasonably practicable; provided , further , that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

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ARTICLE III
 
RIGHTS OF LIMITED PARTNERS
 
Section 3.1   Limitation of Liability.
 
The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.
 
Section 3.2   Management of Business.
 
No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. All actions taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall not be deemed to be participating in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.
 
Section 3.3   Outside Activities of the Limited Partners.
 
Subject to the provisions of Section 7.5 , which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, each Limited Partner shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.
 
Section 3.4   Rights of Limited Partners.
 
(a) In addition to other rights provided by this Agreement or by applicable law (other than Section 17-305(a) of the Delaware Act, the obligations of which are expressly replaced in their entirety by the provisions below), and except as limited by Section 3.4(a)(i) , each Limited Partner shall have the right, for a purpose that is reasonably related, as determined by the General Partner, to such Limited Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand and at such Limited Partner’s own expense to obtain:
 
(i) true and full information regarding the status of the business and financial condition of the Partnership ( provided that the requirements of this Section 3.4(a)(i) shall be satisfied to the extent the Limited Partner is furnished the Partnership’s most recent annual report and any subsequent quarterly or periodic reports required to be filed (or which would be required to be filed) with the Commission pursuant to Section 13 of the Exchange Act);
 
(ii) a current list of the name and last known business, residence or mailing address of each Record Holder;
 
(iii) a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed; and
 
(iv) such other information regarding the affairs of the Partnership as the General Partner determines is just and reasonable.
 
(b) The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner believes (A) is not

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in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4 ).
 
ARTICLE IV
 
CERTIFICATES; RECORD HOLDERS; TRANSFER OF
PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS
 
Section 4.1   Certificates.
 
Notwithstanding anything otherwise to the contrary herein, unless the General Partner shall determine otherwise in respect of some or all of any or all classes of Partnership Interests, Partnership Interests shall not be evidenced by certificates. Certificates that may be issued shall be executed on behalf of the Partnership by the Chairman of the Board, President or any Executive Vice President or Vice President and the Chief Financial Officer or the Secretary or any Assistant Secretary of the General Partner. No Certificate for a class of Partnership Interests shall be valid for any purpose until it has been countersigned by the Transfer Agent for such class of Partnership Interests; provided , however , that if the General Partner elects to cause the Partnership to issue Partnership Interests of such class in global form, the Certificate shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Partnership Interests have been duly registered in accordance with the directions of the Partnership. Subject to the requirements of Section 6.7(c) , if Common Units are evidenced by Certificates, on or after the date on which Subordinated Units are converted into Common Units pursuant to the terms of Section 5.7 , the Record Holders of such Subordinated Units (i) if the Subordinated Units are evidenced by Certificates, may exchange such Certificates for Certificates evidencing Common Units or (ii) if the Subordinated Units are not evidenced by Certificates, shall be issued Certificates evidencing Common Units.
 
Section 4.2   Mutilated, Destroyed, Lost or Stolen Certificates.
 
(a) If any mutilated Certificate is surrendered to the Transfer Agent (for Common Units) or the General Partner (for Partnership Interests other than Common Units), the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent (for Common Units) or the General Partner (for Partnership Interests other than Common Units) shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Interests as the Certificate so surrendered.
 
(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent (for Common Units) shall countersign, a new Certificate in place of any Certificate previously issued, or issue uncertificated Common Units, if the Record Holder of the Certificate:
 
(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;
 
(ii) requests the issuance of a new Certificate or the issuance of uncertificated Units before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;
 
(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and
 
(iv) satisfies any other reasonable requirements imposed by the General Partner.
 
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represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate or uncertificated Units.
 
(c) As a condition to the issuance of any new Certificate or uncertificated Units under this Section 4.2 , the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.
 
Section 4.3   Record Holders.
 
The Partnership shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be (a) the Record Holder of such Partnership Interest and (b) bound by this Agreement and shall have the rights and obligations of a Partner, as the case may be, hereunder as, and to the extent, provided herein.
 
Section 4.4   Transfer Generally.
 
(a) The term “transfer ,” when used in this Agreement with respect to a Partnership Interest, shall mean a transaction (i) by which the General Partner assigns its General Partner Interest to another Person, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise or (ii) by which the holder of a Limited Partner Interest assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, excluding a pledge, encumbrance, hypothecation or mortgage but including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV . Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be, to the fullest extent permitted by law, null and void.

(c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of any Partner of any or all of the shares of stock, membership or limited liability company interests, partnership interests or other ownership interests in such Partner, and the term “transfer” shall not mean any such disposition.
 
Section 4.5   Registration and Transfer of Limited Partner Interests.
 
(a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b) , the Partnership will provide for the registration and transfer of Limited Partner Interests.
 
(b) The Partnership shall not recognize any transfer of Limited Partner Interests evidenced by Certificates until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided , that as a condition to the issuance of any new Certificate under this Section 4.5 , the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions hereof, the appropriate officers of the General Partner on behalf of the Partnership shall

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execute and deliver, and in the case of Certificates evidencing Limited Partner Interests, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.
 
(c) By acceptance of the transfer of any Limited Partner Interests in accordance with this Section 4.5 and except as provided in Section 4.9 , each transferee of a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred to such Person when any such transfer or admission is reflected in the books and records of the Partnership and such Limited Partner becomes the Record Holder of the Limited Partner Interests so transferred, (ii) shall become bound, and shall be deemed to have agreed to be bound, by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement and (iv) makes the consents, acknowledgements and waivers contained in this Agreement, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement.
 
(d) Subject to (i) the foregoing provisions of this Section 4.5 , (ii) Section 4.3 , (iii) Section 4.8 , (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or an amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Limited Partner Interests shall be freely transferable.
 
(e) The General Partner and its Affiliates shall have the right at any time to transfer their Subordinated Units, Common Units and Incentive Distribution Rights to one or more Persons.
 
Section 4.6   Transfer of the General Partner’s General Partner Interest.
 
(a) Subject to Section 4.6(c) below, prior to June 30, 2010, the General Partner shall not transfer all or any part of its General Partner Interest (represented by Notional General Partner Units) to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of its General Partner Interest to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into such other Person or the transfer by the General Partner of all or substantially all of its assets to such other Person.
 
(b) Subject to Section 4.6(c) below, on or after June 30, 2020, the General Partner may transfer all or any of its General Partner Interest without Unitholder approval.

(c) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability of any Limited Partner under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or limited liability company membership interest held by the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6 , the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.2 , be admitted to the Partnership as the General Partner effective immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

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Section 4.7   Transfer of Incentive Distribution Rights.
 
The General Partner or any other holder of Incentive Distribution Rights may transfer any or all of its Incentive Distribution Rights without Unitholder approval.
 
Section 4.8   Restrictions on Transfers.

(a) Notwithstanding the other provisions of this Article IV , no transfer of any Partnership Interests shall be made if such transfer would (i) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (ii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if it determines, with the advice of counsel, that such restrictions are necessary or advisable to (i) avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for U.S. federal income tax purposes or (ii) preserve the uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may impose such restrictions by amending this Agreement; provided, however , that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.
 
(c) The transfer of a Subordinated Unit that has converted into a Common Unit shall be subject to the restrictions imposed by Section 6.7(c) .
 
(d) The transfer of Incentive Distribution Rights that have converted into Common Units shall be subject to the restrictions imposed by Section 6.8(b) .
 
(e) Nothing contained in this Agreement, other than Section 4.8(a) , shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.
 
Section 4.9   Eligibility Certifications; Ineligible Holders.
 
(a) If at any time the General Partner determines, with the advice of counsel, that
 
(i) the U.S. federal income tax status (or lack of proof of the U.S. federal income tax status) of one or more Limited Partners has or is reasonably likely to have a material adverse effect on the rates that can be charged to customers by any Group Member on assets that are subject to regulation by the FERC or analogous regulatory body (a “Rate Eligibility Trigger” ); or
 
(ii) any Group Member is subject to any federal, state or local law or regulation that would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Partner (a “Citizenship Eligibility Trigger” );
 
then, the General Partner may adopt such amendments to this Agreement as it determines to be necessary or advisable to (x) in the case of a Rate Eligibility Trigger, obtain such proof of the U.S. federal income tax status of the Limited Partners and, to the extent relevant, their beneficial owners, as the General Partner determines to be necessary to establish those Limited Partners whose U.S. federal income tax status does not or would not have a material adverse effect on the rates that can be charged to customers by any Group Member or (y) in the case of a Citizenship Eligibility Trigger, obtain such proof of the nationality, citizenship or other related status of the Partner (or, if the Partner is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the General Partner determines to be necessary to establish those Partners whose status as Partners does not or would not subject any Group Member to a significant risk of cancellation or forfeiture of any of its properties or interests therein.

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(b) Such amendments may include provisions requiring all Partners to certify as to their (and their beneficial owners’) status as Eligible Holders upon demand and on a regular basis, as determined by the General Partner, and may require transferees of Units to so certify prior to being admitted to the Partnership as a Partner (any such required certificate, an “Eligibility Certificate” ).

(c) Such amendments may provide that any Partner who fails to furnish to the General Partner within a reasonable period requested proof of its (and its beneficial owners’) status as an Eligible Holder or if upon receipt of such Eligibility Certificate or other requested information the General Partner determines that a Partner is not an Eligible Holder (such a Partner an “Ineligible Holder” ) the Partnership Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.10 . In addition, the General Partner shall be substituted for all Limited Partners that are Ineligible Holders as the Partner in respect of the Ineligible Holders’ Partnership Interests.

(d) The General Partner shall, in exercising voting rights in respect of Partnership Interests held by it on behalf of Ineligible Holders, distribute the votes in the same ratios as the votes of Partners (including the General Partner and its Affiliates) in respect of Partnership Interests other than those of Ineligible Holders are cast, either for, against or abstaining as to the matter.
 
(e) Upon dissolution of the Partnership, an Ineligible Holder shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Ineligible Holder’s share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Ineligible Holder of his Partnership Interest (representing his right to receive his share of such distribution in kind).
 
(f) At any time after he can and does certify that he has become an Eligible Holder, an Ineligible Holder may, upon application to the General Partner, request that with respect to any Partnership Interests of such Ineligible Holder not redeemed pursuant to Section 4.10 , such Ineligible Holder be admitted as a Partner, and upon approval of the General Partner, such Ineligible Holder shall be admitted as a Partner and shall no longer constitute an Ineligible Holder and the General Partner shall cease to be deemed to be the Partner in respect of such Ineligible Holder’s Partnership Interests.
 
Section 4.10   Redemption of Partnership Interests of Ineligible Holders.
 
(a) If at any time a Partner fails to furnish an Eligibility Certificate or other information requested within the period of time specified in amendments adopted pursuant to Section 4.9 , or if upon receipt of such Eligibility Certificate or other information the General Partner determines, with the advice of counsel, that a Partner is not an Eligible Holder, the Partnership may, unless the Partner establishes to the satisfaction of the General Partner that such Partner is an Eligible Holder or has transferred his Partnership Interests to a Person who is an Eligible Holder and who furnishes an Eligibility Certificate to the General Partner prior to the date fixed for redemption as provided below, redeem the Partnership Interest of such Partner as follows:
 
(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Partner, at his last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon redemption of the Redeemable Interests (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender of the Certificate evidencing the Redeemable Interests) and that on and after the date fixed for redemption no further allocations or distributions to which the Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.
 
(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Partnership Interests of the class to be so redeemed multiplied by the number of Partnership Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as

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determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.
 
(iii) The Partner or his duly authorized representative shall be entitled to receive the payment for the Redeemable Interests at the place of payment specified in the notice of redemption on the redemption date (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender by or on behalf of the Partner at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank).
 
(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Partnership Interests.
 
(b) The provisions of this Section 4.10 shall also be applicable to Partnership Interests held by a Partner as nominee of a Person determined to be an Ineligible Holder.
 
(c) Nothing in this Section 4.10 shall prevent the recipient of a notice of redemption from transferring his Partnership Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Partnership Interest certifies to the satisfaction of the General Partner that he is an Eligible Holder. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.
 
ARTICLE V
 
CAPITAL CONTRIBUTIONS AND
ISSUANCE OF PARTNERSHIP INTERESTS
 
Section 5.1   Intentionally Omitted.
 
Section 5.2   Contributions by the General Partner and the Initial Limited Partners.
 
(a) Prior to the IPO Closing Date, the General Partner, AIM Midstream and the LTIP Partners made capital contributions in exchange for Partnership Interests.
 
(b) Upon the issuance of any Additional Limited Partner Interests by the Partnership (other than (i) the Common Units issued in the Initial Public Offering (including Common Units issued upon the exercise by the Underwriters of the Over-Allotment Option), (ii) any Common Units issued upon conversion of Subordinated Units and (iii) Common Units issued pursuant to Section 5.11 ), the General Partner may, in order to maintain its Percentage Interest, make additional Capital Contributions in an amount equal to the product obtained by multiplying (i) the quotient determined by dividing (A) the General Partner’s Percentage Interest immediately prior to the issuance of such Additional Limited Partner Interests by the Partnership by (B) 100 less the General Partner’s Percentage Interest immediately prior to the issuance of such Additional Limited Partner Interests by the Partnership times (ii) the amount contributed to the Partnership by the Limited Partners in exchange for such Additional Limited Partner Interests. Except as set forth in Article XII , the General Partner shall not be obligated to make any additional Capital Contributions to the Partnership.
 
Section 5.3   Contributions by Limited Partners.
 
(a) On the IPO Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, as set forth in the Underwriting Agreement.
 
(b) Upon the exercise, if any, of the Over-Allotment Option, each underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

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(c) No Limited Partner will be required to make any Capital Contribution to the Partnership pursuant to this Agreement.
 
Section 5.4   Interest and Withdrawal of Capital Contributions.
 
No interest shall be paid by the Partnership on Capital Contributions. No Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon liquidation of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.
 
Section 5.5   Capital Accounts.
 
(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including income and gain exempt from tax) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1 , and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1 .
 
(b) For purposes of computing the amount of any item of income, gain, loss or deduction that is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for U.S. federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided , that:
 
(i) Solely for purposes of this Section 5.5 , the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement) of all property owned by (x) any other Group Member that is classified as a partnership for U.S. federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for U.S. federal income tax purposes of which a Group Member is, directly or indirectly, a partner, member or other equity holder.
 
(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1 .
 
(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss and deduction shall be made without regard to any election under Section 754 of the Code that may be made by the Partnership and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for U.S. federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

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(iv) Any income, gain or loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.
 
(v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery or amortization attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.5(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery or amortization attributable to such property shall be determined as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment.
 
(vi) The Gross Liability Value of each Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Carrying Values. The amount of any such adjustment shall be treated for purposes hereof as an item of loss (if the adjustment increases the Carrying Value of such Liability of the Partnership) or an item of gain (if the adjustment decreases the Carrying Value of such Liability of the Partnership).
 
(c) (i) A transferee of a Partnership Interest shall succeed to a Pro Rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.
 
(ii) Subject to Section 6.7(c) , immediately prior to the transfer of a Subordinated Unit or of a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 by a holder thereof (other than a transfer to an Affiliate unless the General Partner elects to have this Section 5.5(c)(ii) apply), the Capital Account maintained for such Person with respect to its Subordinated Units or converted Subordinated Units will (A) first, be allocated to the Subordinated Units or converted Subordinated Units to be transferred in an amount equal to the product of (x) the number of such Subordinated Units or converted Subordinated Units to be transferred and (y) the Per Unit Capital Amount for a Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any Subordinated Units or converted Subordinated Units ( “Retained Converted Subordinated Units” ). Following any such allocation, the transferor’s Capital Account, if any, maintained with respect to the retained Subordinated Units or Retained Converted Subordinated Units, if any, will have a balance equal to the amount allocated under clause (B) hereinabove, and the transferee’s Capital Account established with respect to the transferred Subordinated Units or converted Subordinated Units will have a balance equal to the amount allocated under clause (A) hereinabove.
 
(iii) Upon the issuance of IDR Reset Common Units pursuant to Section 5.11(a) , the Capital Account maintained with respect to the Incentive Distribution Rights shall (A) first, be allocated to IDR Reset Common Units in an amount equal to the product of (x) the Aggregate Quantity of IDR Reset Common Units and (y) the Per Unit Capital Amount for an IPO Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the holder of the Incentive Distributions Rights. In the event that there is not a sufficient Capital Account associated with the Incentive Distribution Rights to allocate the full Per Unit Capital Amount for an IPO Common Unit to the IDR Reset Common Units in accordance with clause (A) of this Section 5.5(c)(iii) , the IDR Reset Common Units shall be subject to Section 6.1(d)(x)(B) and Section 6.1(d)(x)(C) .
 
(d) (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services or the conversion of the Combined Interest to Common Units pursuant to Section 11.3(b) , the Capital Account of each Partner and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance for an amount equal to its fair market value and had been allocated to the Partners at such time pursuant to Section 6.1(c) and Section 6.1(d) in the same manner as any item of gain or loss actually recognized following an event

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giving rise to the dissolution of the Partnership would have been allocated; provided , however , that in the event of an issuance of Partnership Interests for a de minimis amount of cash or Contributed Property, or in the event of an issuance of a de minimis amount of Partnership Interests as consideration for the provision of services, the General Partner may determine that such adjustments are unnecessary for the proper administration of the Partnership. In determining such Unrealized Gain or Unrealized Loss, the aggregate fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt; provided, however , that the General Partner, in arriving at such valuation, must take fully into account the fair market value of the Partnership Interests of all Partners at such time. The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines) to arrive at a fair market value for individual properties.
 
(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized in a sale of such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Partners, at such time, pursuant to Section 6.1(c) and Section 6.1(d) in the same manner as any item of gain or loss actually recognized following an event giving rise to the dissolution of the Partnership would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4 , be determined and allocated by the Liquidator using such method of valuation as it may adopt.
 
Section 5.6   Issuances of Additional Partnership Interests.
 
(a) The Partnership may issue additional Partnership Interests and options, rights, warrants and appreciation rights relating to the Partnership Interests (including pursuant to Section 7.4(c) ) for any partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.
 
(b) Each additional Partnership Interest authorized to be issued by the Partnership pursuant to Section 5.6(a) or security authorized to be issued pursuant to Section 7.4(c) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Interests), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may or shall be required to redeem the Partnership Interest (including sinking fund provisions) or other security; (v) whether such Partnership Interest or other security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Interest or other security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Interest; and (viii) the right, if any, of each such Partnership Interest to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Interest.
 
(c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Interests and options, rights, warrants and appreciation rights relating to Partnership Interests pursuant to this Section 5.6 or Section 7.4(c) , (ii) the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, (iii) this issuance of Common Units pursuant to Section 5.11 , (iv) the admission of Additional Limited Partners and (v) all additional issuances of Partnership Interests. The General Partner shall determine the relative rights, powers and duties of the holders

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of the Units or other Partnership Interests being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Interests or in connection with the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Interests are listed or admitted to trading.
 
(d) No fractional Units shall be issued by the Partnership.
 
Section 5.7   Conversion of Subordinated Units.
 
(a) All of the Subordinated Units shall convert into Common Units on a one-for-one basis on the expiration or termination of the Subordination Period.
 
(b) A Subordinated Unit that has converted into a Common Unit shall be subject to the provisions of Section 6.7 .
 
Section 5.8   Limited Preemptive Right.
 
Except as provided in this Section 5.8 and in Section 5.2 or as otherwise provided in a separate agreement by the Partnership, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Interest, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, that it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership Interests from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Interests to Persons other than the General Partner and its Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Interests. Any determination by the General Partner whether to exercise its right pursuant to the immediately preceding sentence shall be a determination made in its individual capacity as the general partner of the Partnership, and such determination may be made in accordance with Section 7.9(c) .
 
Section 5.9   Splits and Combinations.
 
(a) Subject to Section 5.9(d) , Section 6.6 and Section 6.9 (dealing with adjustments of distribution levels), the Partnership may make a Pro Rata distribution of Partnership Interests to all Record Holders or may effect a subdivision or combination of Partnership Interests so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per-Unit basis (including any Common Unit Arrearage or Cumulative Common Unit Arrearage) or stated as a number of Units (including the number of Subordinated Units that may convert prior to the end of the Subordination Period) are proportionately adjusted.
 
(b) Whenever such a Pro Rata distribution, subdivision or combination of Partnership Interests is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Interests to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.
 
(c) If a Pro Rata distribution of Partnership Interests, or a subdivision or combination of Partnership Interests, is made as contemplated in this Section 5.9 , the number of Notional General Partner Units constituting the Percentage Interest of the General Partner (as determined immediately prior to the Record Date for such distribution, subdivision or combination), shall be appropriately adjusted as of the effective date for payment of such distribution, subdivision or combination.

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(d) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates or uncertificated Partnership Interests to the Record Holders of Partnership Interests as of the applicable Record Date representing the new number of Partnership Interests held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Interests Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of such new Certificate or uncertificated Partnership Interests, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.
 
(e) The Partnership shall not issue fractional Units or Notional General Partner Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units or fractional Notional General Partner Units but for the provisions of this Section 5.9(e) , each fractional Unit or fractional Notional General Partner Unit shall be rounded to the nearest whole Unit or Notional General Partner Unit (and a 0.5 Unit or Notional General Partner Unit shall be rounded to the next higher Unit or Notional General Partner Unit).
 
Section 5.10   Fully Paid and Non-Assessable Nature of Limited Partner Interests.
 
All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by either or both of Sections 17-607 and 17-804 of the Delaware Act.
 
Section 5.11   Issuance of Common Units in Connection with Reset of Incentive Distribution Rights.

(a) Subject to the provisions of this Section 5.11 , the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right, exercisable at its option at any time when there are no Subordinated Units Outstanding and the Partnership has made a distribution pursuant to Section 6.4(c)(v) for each of the four most recently completed Quarters and the amount of each such distribution did not exceed Adjusted Operating Surplus for such Quarter, to make an election (the “IDR Reset Election” ) to cause the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive their respective proportionate share of a number of Common Units (the “IDR Reset Common Units” ) derived by dividing (i) the average aggregate amount of cash distributions made by the Partnership for the two full Quarters immediately preceding the giving of the Reset Notice (as defined in Section 5.11(b) ) in respect of the Incentive Distribution Rights by (ii) the average of the cash distributions made by the Partnership in respect of each Common Unit for the two full Quarters immediately preceding the giving of the Reset Notice (the number of Common Units determined by such quotient is referred to herein as the “Aggregate Quantity of IDR Reset Common Units” ). If at the time of any IDR Reset Election the General Partner and its Affiliates are not holders of a majority interest of the Incentive Distribution Rights, then the IDR Reset Election shall be subject to the prior written concurrence of the General Partner that the conditions described in the immediately preceding sentence have been satisfied. The Percentage Interest of the General Partner, with respect to the General Partner Interest, after the issuance of the Aggregate Quantity of IDR Reset Common Units shall equal the Percentage Interest of the General Partner, with respect to the General Partner Interest, prior to the issuance of the Aggregate Quantity of IDR Reset Common Units and the General Partner shall not be obligated to make any additional Capital Contribution to the Partnership in order to maintain its Percentage Interest in connection therewith. The making of the IDR Reset Election in the manner specified in Section 5.11(b) shall cause each of the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive IDR Reset Common Units on the basis specified above, without any further approval required by the General Partner or the Unitholders, at the time specified in Section 5.11(c) unless the IDR Reset Election is rescinded pursuant to Section 5.11(d).

(b) To exercise the right specified in Section 5.11(a) , the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of

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the Incentive Distribution Rights) shall deliver a written notice (the “Reset Notice” ) to the Partnership. Within 10 Business Days after the receipt by the Partnership of such Reset Notice, the Partnership shall deliver a written notice to the holder or holders of the Incentive Distribution Rights of the Partnership’s determination of the aggregate number of IDR Reset Common Units that each holder of Incentive Distribution Rights will be entitled to receive.

 
(c) The holder or holders of the Incentive Distribution Rights will be entitled to receive the Aggregate Quantity of IDR Reset Common Units on the fifteenth Business Day after receipt by the Partnership of the Reset Notice; provided, however, that the issuance of IDR Reset Common Units to the holder or holders of the Incentive Distribution Rights shall not occur prior to the approval of the listing or admission for trading of such IDR Reset Common Units by the principal National Securities Exchange upon which the Common Units are then listed or admitted for trading if any such approval is required pursuant to the rules and regulations of such National Securities Exchange.

 
(d) If the principal National Securities Exchange upon which the Common Units are then traded has not approved the listing or admission for trading of the Common Units to be issued pursuant to this Section 5.11 on or before the 30th calendar day following the Partnership’s receipt of the Reset Notice and such approval is required by the rules and regulations of such National Securities Exchange, then the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right to either rescind the IDR Reset Election or elect to receive other Partnership Interests having such terms as the General Partner may approve, with the approval of a Conflicts Committee, that will provide (i) the same economic value, in the aggregate, as the Aggregate Quantity of IDR Reset Common Units would have had at the time of the Partnership’s receipt of the Reset Notice, as determined by the General Partner, and (ii) for the subsequent conversion (on terms acceptable to the National Securities Exchange upon which the Common Units are then traded) of such Partnership Interests into Common Units within not more than 12 months following the Partnership’s receipt of the Reset Notice upon the satisfaction of one or more conditions that are reasonably acceptable to the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights).

 
(e) The Target Distributions shall be adjusted at the time of the issuance of Common Units or other Partnership Interests pursuant to this Section 5.11 such that (i) the Minimum Quarterly Distribution shall be reset to equal the average cash distribution amount per Common Unit for the two Quarters immediately prior to the Partnership’s receipt of the Reset Notice (the “Reset MQD” ), (ii) the First Target Distribution shall be reset to equal 115% of the Reset MQD, (iii) the Second Target Distribution shall be reset to equal 125% of the Reset MQD and (iv) the Third Target Distribution shall be reset to equal 150% of the Reset MQD.

ARTICLE VI
 
ALLOCATIONS AND DISTRIBUTIONS
 
Section 6.1   Allocations for Capital Account Purposes.
 
For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss and deduction (computed in accordance with Section 5.5(b) ) for each taxable period shall be allocated among the Partners as provided herein below.
 
(a)  Net Income.   After giving effect to the special allocations set forth in Section 6.1(d) , Net Income for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Income for such taxable period shall be allocated as follows:
 
(i) First, to the General Partner until the aggregate of the Net Income allocated to the General Partner pursuant to this Section 6.1(a)(i) and the Net Termination Gain allocated to the General Partner pursuant to Section 6.1(c)(i)(A) or Section 6.1(c)(iv)(A) for the current and all previous taxable periods is equal to the aggregate of the Net Loss allocated to the General Partner pursuant to Section 6.1(b)(ii) for

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all previous taxable periods and the Net Termination Loss allocated to the General Partner pursuant to Section 6.1(c)(ii)(D) or Section 6.1(c)(iii)(B) for the current and all previous taxable periods; and
 
(ii) The balance, if any, (x) to the General Partner in accordance with its Percentage Interest, and (y) to all Unitholders, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x).
 
(b)  Net Loss.   After giving effect to the special allocations set forth in Section 6.1(d) , Net Loss for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Loss for such taxable period shall be allocated as follows:
 
(i)  First , to the General Partner and the Unitholders, Pro Rata; provided , that Net Losses shall not be allocated pursuant to this Section 6.1(b)(i) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit balance in its Adjusted Capital Account); and
 
(ii) The balance, if any, 100% to the General Partner.

(c)  Net Termination Gains and Losses.   After giving effect to the special allocations set forth in Section 6.1(d) , Net Termination Gain or Net Termination Loss (including a pro rata part of each item of income, gain, loss and deduction taken into account in computing Net Termination Gain or Net Termination Loss) for such taxable period shall be allocated in the manner set forth in this Section 6.1(c). All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.4 and Section 6.5 have been made; provided, however, that solely for purposes of this Section 6.1(c) , Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.

(i) Except as provided in Section 6.1(c)(iv) , Net Termination Gain (including a pro rata part of each item of income, gain, loss, and deduction taken into account in computing Net Termination Gain) shall be allocated:
 
(A)  First , to the General Partner until the aggregate of the Net Termination Gain allocated to the General Partner pursuant to this Section 6.1(c)(i)(A) or Section 6.1(c)(iv)(A) and the Net Income allocated to the General Partner pursuant to Section 6.1(a)(i) for the current and all previous taxable periods is equal to the aggregate of the Net Loss allocated to the General Partner pursuant to Section 6.1(b)(ii) for all previous taxable periods and the Net Termination Loss allocated to the General Partner pursuant to Section 6.1(c)(ii)(D) or Section 6.1(c)(iii)(B) for all previous taxable periods;
 
(B)  Second , (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(b)(i) or Section 6.4(c)(i) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter defined as the “Unpaid MQD” ) and (3) any then existing Cumulative Common Unit Arrearage;
 
(C)  Third , if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until the Capital Account in respect of each Subordinated Unit then Outstanding equals the sum of (1) its Unrecovered Initial Unit Price, determined for the taxable year (or portion thereof) to which this allocation of gain relates, and (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(b)(iii) with respect to such Subordinated Unit for such Quarter;

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(D)  Fourth , to the General Partner and all Unitholders, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Unpaid MQD, (3) any then existing Cumulative Common Unit Arrearage, and (4) the excess of (aa) the First Target Distribution less the Minimum Quarterly Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(b)(iv) and Section 6.4(c)(ii) (the sum of (1), (2), (3) and (4) is hereinafter defined as the “First Liquidation Target Amount” );
 
(E)  Fifth , (x) to the General Partner in accordance with its Percentage Interest, (y) 13% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (x) and (y) of this clause (E), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the First Liquidation Target Amount, and (2) the excess of (aa) the Second Target Distribution less the First Target Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(b)(v) and Section 6.4(c)(iii) (the sum of (1) and (2) is hereinafter defined as the “Second Liquidation Target Amount” );
 
(F)  Sixth , (x) to the General Partner in accordance with its Percentage Interest, (y) 23% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (x) and (y) of this clause (F), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the Second Liquidation Target Amount, and (2) the excess of (aa) the Third Target Distribution less the Second Target Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(b)(vi) and Section 6.4(c)(iv) (the sum of (1) and (2) is hereinafter defined as the “Third Liquidation Target Amount” ); and
 
(G) Finally, (x) to the General Partner in accordance with its Percentage Interest, (y) 48% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (x) and (y) of this clause (G).
 
(ii) Except as otherwise provided by Section 6.1(c)(iii) , Net Termination Loss (including a pro rata part of each item of income, gain, loss, and deduction taken into account in computing Net Termination Loss) shall be allocated:
 
(A)  First , if Subordinated Units remain Outstanding, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until the Capital Account in respect of each Subordinated Unit then Outstanding has been reduced to zero;
 
(B)  Second , (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until the Capital Account in respect of each Common Unit then Outstanding has been reduced to zero;
 
(C)  Third , to the General Partner and the Unitholders, Pro Rata; provided that Net Termination Loss shall not be allocated pursuant to this Section 6.1(c)(ii)(C) to the extent such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account (or increase any existing deficit in its Adjusted Capital Account); and
 
(D)  Fourth , the balance, if any, 100% to the General Partner.

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(iii) Any Net Termination Loss deemed recognized pursuant to Section 5.5(d) prior to the Liquidation Date shall be allocated:
 
(A)  First , to the General Partner and the Unitholders, Pro Rata; provided that Net Termination Loss shall not be allocated pursuant to this Section 6.1(c)(iii)(A) to the extent such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit in its Adjusted Capital Account); and
 
(B) The balance, if any, to the General Partner.
 
(iv) If a Net Termination Loss has been allocated pursuant to Section 6.1(c)(iii) , subsequent Net Termination Gain deemed recognized pursuant to Section 5.5(d) prior to the Liquidation Date shall be allocated:
 
(A)  First , to the General Partner until the aggregate Net Termination Gain allocated to the General Partner pursuant to this Section 6.1(c)(iv)(A) is equal to the aggregate Net Termination Loss previously allocated pursuant to Section 6.1(c)(iii)(B) ;
 
(B)  Second , to the General Partner and the Unitholders, Pro Rata, until the aggregate Net Termination Gain allocated pursuant to this Section 6.1(c)(iv)(B) is equal to the aggregate Net Termination Loss previously allocated pursuant to Section 6.1(c)(iii)(A) ; and
 
(C) The balance, if any, pursuant to the provisions of Section 6.1(c)(i) .
 
(d)  Special Allocations .   Notwithstanding any other provision of this Section 6.1 , the following special allocations shall be made for such taxable period:
 
(i)  Partnership Minimum Gain Chargeback.   Notwithstanding any other provision of this Section 6.1 , if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d) , each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii) ). This Section 6.1(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.
 
(ii)  Chargeback of Partner Nonrecourse Debt Minimum Gain.   Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i) ), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d) , each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) , other than Section 6.1(d)(i) and other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii) , with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.
 
(iii)  Priority Allocations .
 
(A) If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4 ) with respect to a Unit exceeds the amount of cash or the Net Agreed Value of property distributed with respect to another Unit (the amount of the excess,

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an “Excess Distribution” and the Unit with respect to which the greater distribution is paid, an “Excess Distribution Unit” ), then (1) there shall be allocated gross income and gain to each Unitholder receiving an Excess Distribution with respect to the Excess Distribution Unit until the aggregate amount of such items allocated with respect to such Excess Distribution Unit pursuant to this Section 6.1(d)(iii)(A) for the current taxable period and all previous taxable periods is equal to the amount of the Excess Distribution; and (2) the General Partner shall be allocated gross income and gain with respect to each such Excess Distribution in an amount equal to the product obtained by multiplying (aa) the quotient determined by dividing (x) the General Partner’s Percentage Interest at the time when the Excess Distribution occurs by (y) a percentage equal to 100% less the General Partner’s Percentage Interest at the time when the Excess Distribution occurs, times (bb) the total amount allocated in clause (1) above with respect to such Excess Distribution.
 
(B) After the application of Section 6.1(d)(iii)(A) , the remaining items of Partnership income or gain for the taxable period, if any, shall be allocated (1) to the holders of Incentive Distribution Rights, Pro Rata, until the aggregate amount of such items allocated to the holders of Incentive Distribution Rights pursuant to this Section 6.1(d)(iii)(B) for the current taxable period and all previous taxable periods is equal to the cumulative amount of all Incentive Distributions made to the holders of Incentive Distribution Rights from the IPO Closing Date to a date 45 days after the end of the current taxable period; and (2) to the General Partner an amount equal to the product of (aa) an amount equal to the quotient determined by dividing (x) the General Partner’s Percentage Interest by (y) the sum of 100 less the General Partner’s Percentage Interest times (bb) the sum of the amounts allocated in clause (1) above.
 
(iv)  Qualified Income Offset.   In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership gross income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible; provided , that an allocation pursuant to this Section 6.1(d)(iv) shall be made only if and to the extent that such Partner would have a deficit balance in its Adjusted Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(iv) were not in this Agreement.
 
(v)  Gross Income Allocations.   In the event any Partner has a deficit balance in its Capital Account at the end of any taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income and gain in the amount of such excess as quickly as possible; provided , that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if Section 6.1(d)(iv) and this Section 6.1(d)(v) were not in this Agreement.
 
(vi)  Nonrecourse Deductions.   Nonrecourse Deductions for any taxable period shall be allocated to the Partners Pro Rata. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.
 
(vii)  Partner Nonrecourse Deductions.   Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be

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allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.
 
(viii)  Nonrecourse Liabilities.   For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners Pro Rata.
 
(ix)  Code Section 754 Adjustments.   To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.
 
(x)  Economic Uniformity; Changes in Law.
 
(A) At the election of the General Partner with respect to any taxable period ending upon, or after, the termination of the Subordination Period, all or a portion of the remaining items of Partnership gross income or gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii) , shall be allocated 100% to each Partner holding Subordinated Units that are Outstanding as of the termination of the Subordination Period ( “Final Subordinated Units” ) in the proportion of the number of Final Subordinated Units held by such Partner to the total number of Final Subordinated Units then Outstanding, until each such Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such Final Subordinated Units to an amount that after taking into account the other allocations of income, gain, loss and deduction to be made with respect to such taxable period will equal the product of (A) the number of Final Subordinated Units held by such Partner and (B) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Final Subordinated Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such Final Subordinated Units into Common Units. This allocation method for establishing such economic uniformity will be available to the General Partner only if the method for allocating the Capital Account maintained with respect to the Subordinated Units between the transferred and retained Subordinated Units pursuant to Section 5.5(c)(ii) does not otherwise provide such economic uniformity to the Final Subordinated Units.
 
(B) With respect to an event triggering an adjustment to the Carrying Value of Partnership property pursuant to Section 5.5(d) during any taxable period of the Partnership ending upon, or after, the issuance of IDR Reset Common Units pursuant to Section 5.11 , after the application of Section 6.1(d)(x)(A) , any Unrealized Gains and Unrealized Losses shall be allocated among the Partners in a manner that to the nearest extent possible results in the Capital Accounts maintained with respect to such IDR Reset Common Units issued pursuant to Section 5.11 equaling the product of (a) the Aggregate Quantity of IDR Reset Common Units and (B) the Per Unit Capital Account for an IPO Common Unit.
 
(C) With respect to any taxable period during which an IDR Reset Common Unit is transferred to any Person who is not an Affiliate of the transferor, all or a portion of the remaining items of Partnership gross income or gain for such taxable period shall be allocated 100% to the transferor Partner of such transferred IDR Reset Common Unit until such transferor Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such transferred IDR Reset Common Unit to an amount equal to the Per Unit Capital Account for an IPO Common Unit.

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(D) For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations of income, gain, loss, deduction, Unrealized Gain or Unrealized Loss; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.1(d)(x)(D) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.
 
(xi)  Curative Allocation .

(A) Notwithstanding any other provision of this Section 6.1 , other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of gross income, gain, loss and deduction allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1 . Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Nonrecourse Debt Minimum Gain. In exercising its discretion under this Section 6.1(d)(xi)(A) , the General Partner may take into account future Required Allocations that, although not yet made, are likely to offset other Required Allocations previously made. Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners. Further, allocations pursuant to this Section 6.1(d)(xi)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the General Partner determines that such allocations are likely to be offset by subsequent Required Allocations.

(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

(xii)  Corrective and other Allocations.   In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

(A) Except as provided in Section 6.1(d)(xii)(B) , in the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) ), the General Partner shall allocate such Additional Book Basis Derivative Items (1) to the holders of Incentive Distribution Rights and the General Partner to the same extent that the Unrealized Gain or Unrealized Loss giving rise to such Additional Book Basis Derivative Items was allocated to them pursuant to Section 5.5(d) and (2) to all Unitholders, Pro Rata, to the extent that the Unrealized Gain or Unrealized Loss giving rise to such Additional Book Basis Derivative Items was allocated to any Unitholders pursuant to Section 5.5(d) .

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(B) In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) or an allocation of Net Termination Gain or Net Termination Loss pursuant to Section 6.1(c) as a result of a sale or other taxable disposition of any Partnership asset that is an Adjusted Property ( “Disposed of Adjusted Property” ), the General Partner shall allocate (1) additional items of gross income and gain (aa) away from the holders of Incentive Distribution Rights and (bb) to the Unitholders, or (2) additional items of deduction and loss (aa) away from the Unitholders and (bb) to the holders of Incentive Distribution Rights, to the extent that the Additional Book Basis Derivative Items allocated to the Unitholders exceed their Share of Additional Book Basis Derivative Items with respect to such Disposed of Adjusted Property. Any allocation made pursuant to this Section 6.1(d)(xii)(B) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.
 
(C) In the case of any negative adjustments to the Capital Accounts of the Partners resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the General Partner, that to the extent possible the aggregate Capital Accounts of the Partners will equal the amount that would have been the Capital Account balances of the Partners if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.

(D) For purposes of this Section 6.1(d)(xii) , the Unitholders shall be treated as being allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders under this Agreement. Without limiting the foregoing, if an Adjusted Property is contributed by the Partnership to another entity classified as a partnership for federal income tax purposes (the “lower tier partnership”), the General Partner may make allocations similar to those described in Sections 6.1(d)(xii)(A)-(C) to the extent the General Partner determines such allocations are necessary to account for the Partnership’s allocable share of income, gain, loss and deduction of the lower tier partnership that relate to the contributed Adjusted Property in a manner that is consistent with the purpose of this Section 6.1(d)(xii) .

(xiii)  Special Curative Allocation in Event of Liquidation Prior to End of Subordination Period. Notwithstanding any other provision of this Section 6.1 (other than the Required Allocations), if the Liquidation Date occurs prior to the conversion of the last Outstanding Subordinated Unit, then items of income, gain, loss and deduction for the taxable period that includes the Liquidation Date (and, if necessary, items arising in previous taxable periods to the extent the General Partner determines such items may be so allocated), shall be specially allocated among the Partners in the manner determined appropriate by the General Partner so as to cause, to the maximum extent possible, the Capital Account in respect of each Common Unit to equal the amount such Capital Account would have been if all prior allocations of Net Termination Gain and Net Termination Loss had been made pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii) , as applicable.
 
Section 6.2   Allocations for Tax Purposes.
 
(a) Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1 .
 
(b) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners in the manner provided under Section 704(c) of the Code, and the Treasury Regulations promulgated under Section 704(b) and 704(c) of the Code, as determined appropriate by the General Partner (taking into account the General Partner’s discretion under Section 6.1(d)(x)(D) ); provided , that the General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) in all events.

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(c) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Unamortized Book-Tax Disparity of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.
 
(d) In accordance with Treasury Regulation Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2 , be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.
 
(e) All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however , that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.
 
(f) Each item of Partnership income, gain, loss and deduction, for federal income tax purposes, shall be determined for each taxable period and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of each month; provided, however , such items for the period beginning on the IPO Closing Date and ending on the last day of the month in which the Option Closing Date or the expiration of the Over-Allotment Option occurs shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the next succeeding month; and provided , further , that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the General Partner, shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.
 
(g) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

Section 6.3   Requirement and Characterization of Distributions; Distributions to Record Holders.

(a) Except as described in Section 6.3(b) or Section 6.3(c) , within 45 days following the end of each Quarter, an amount equal to 100% of Available Cash with respect to such Quarter shall be distributed in accordance with this Article VI by the Partnership to the Partners as of the Record Date selected by the General Partner. All amounts of Available Cash distributed by the Partnership on any date following the IPO Closing Date from any source shall be deemed to be Operating Surplus until the sum of all amounts of

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Available Cash distributed by the Partnership to the Partners following the IPO Closing Date pursuant to Section 6.4(b) equals the Operating Surplus from the IPO Closing Date through the close of the immediately preceding Quarter. Any remaining amounts of Available Cash distributed by the Partnership on such date shall, except as otherwise provided in Section 6.5 , be deemed to be “Capital Surplus.” All distributions required to be made under this Agreement or otherwise made by the Partnership shall be made subject to Sections 17-607 and 17-804 of the Delaware Act.
 
(b) Notwithstanding Section 6.3(a) , in the event of the dissolution and liquidation of the Partnership, all cash received during or after the Quarter in which the Liquidation Date occurs, other than from Working Capital Borrowings, shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4 .
 
(c) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners.
 
(d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.
 
Section 6.4   Distributions of Available Cash from Operating Surplus.
 
(a)  On the IPO Closing Date.   Subject to Section 17-607 of the Delaware Act, on the IPO Closing Date and immediately prior to the commencement of the Subordination Period, the IPO Proceeds and New Credit Facility Proceeds shall be distributed to (x) the General Partner in accordance with its Percentage Interest and (y) AIM Midstream and the LTIP Partners, as Unitholders, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest.
 
(b)  During Subordination Period.   Available Cash with respect to any Quarter within the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5 shall, subject to Section 17-607 of the Delaware Act and after giving effect to the distributions pursuant to Section 6.4(a) , be distributed as follows, except as otherwise contemplated by Section 5.6 in respect of other Partnership Interests issued pursuant thereto:
 
(i)  First , (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(ii)  Second , (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage existing with respect to such Common Unit;

(iii)  Third , (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest until there has been distributed in respect of each Subordinated Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;
 
(iv)  Fourth , to the General Partner and all Unitholders, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;
 
(v)  Fifth , (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v)

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until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;

(vi)  Sixth , (A) to the General Partner in accordance with its Percentage Interest; (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (vi), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and

 
(vii)  Thereafter , (A) to the General Partner in accordance with its Percentage Interest; (B) 48% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (vi);

provided, however , that if the Target Distributions have been reduced to zero pursuant to the second sentence of Section 6.6(a) , the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(b)(vii) .
 
(c)  After Subordination Period.   Available Cash with respect to any Quarter after the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5 shall, subject to Section 17-607 of the Delaware Act, be distributed as follows, except as otherwise required by Section 5.6 in respect of additional Partnership Interests issued pursuant thereto:
 
(i)  First , 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;
 
(ii)  Second , 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;
 
(iii)  Third , (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (iii), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;
 
(iv)  Fourth , (A) to the General Partner in accordance with its Percentage Interest; (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (A) and (B) of this clause (iv), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and
 
(v)  Thereafter , (A) to the General Partner in accordance with its Percentage Interest; (B) 48% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v);
 
provided, however , that if the Target Distributions have been reduced to zero pursuant to the second sentence of Section 6.6(a) , the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(c)(v) .
 
Section 6.5   Distributions of Available Cash from Capital Surplus.
 
Available Cash with respect to any Quarter ending on or after the IPO Closing Date that is deemed to be Capital Surplus pursuant to the provisions of Section 6.3(a) shall, subject to Section 17-607 of the Delaware Act and after giving effect to the distributions pursuant to Section 6.4(a) , be distributed, unless the provisions of Section 6.3 require otherwise, 100% to the General Partner and the Unitholders, Pro Rata, until the

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Minimum Quarterly Distribution has been reduced to zero pursuant to the second sentence of Section 6.6(a) . Available Cash that is deemed to be Capital Surplus shall then be distributed (a) to the General Partner in accordance with its Percentage Interest and (b) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage. Thereafter, all Available Cash shall be distributed as if it were Operating Surplus and shall be distributed in accordance with Section 6.4 .

Section 6.6   Adjustment of Minimum Quarterly Distribution and Target Distribution Levels.
 
(a) The Target Distributions, Common Unit Arrearages and Cumulative Common Unit Arrearages shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Units or otherwise) of Units or other Partnership Interests. In the event of a distribution of Available Cash that is deemed to be from Capital Surplus, the then applicable Target Distributions shall be reduced in the same proportion that the distribution had to the fair market value of the Common Units immediately prior to the announcement of the distribution. If the Common Units are publicly traded on a National Securities Exchange, the fair market value will be the Current Market Price before the ex-dividend date. If the Common Units are not publicly traded, the fair market value will be determined by the Board of Directors.
 
(b) The Target Distributions shall also be subject to adjustment pursuant to Section 5.11 and Section 6.9 .

Section 6.7   Special Provisions Relating to the Holders of Subordinated Units.

(a) Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holder of a Subordinated Unit shall have all of the rights and obligations of a Unitholder holding Common Units hereunder; provided, however , that immediately upon the conversion of Subordinated Units into Common Units pursuant to Section 5.7 , the Unitholder holding a Subordinated Unit shall possess all of the rights and obligations of a Unitholder holding Common Units hereunder with respect to such converted Subordinated Units, including the right to vote as a Common Unitholder and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units; provided, however , that such converted Subordinated Units shall remain subject to the provisions of Section 5.5(c)(ii) , Section 6.1(d)(x)(A) , Section 6.7(b) and Section 6.7(c) .
 
(b) A Unitholder shall not be permitted to transfer a Subordinated Unit or a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder’s Capital Account with respect to the retained Subordinated Units or Retained Converted Subordinated Units would be negative after giving effect to the allocation under Section 5.5(c)(ii)(B) .

(c) A Unitholder holding a Common Unit that has resulted from the conversion of a Subordinated Unit pursuant to Section 5.7 shall not be issued a Common Unit Certificate pursuant to Section 4.1 , if the Common Units are evidenced by Certificates, and shall not be permitted to transfer such Common Unit to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and U.S. federal income tax characteristics, in all material respects, to the intrinsic economic and U.S. federal income tax characteristics of an IPO Common Unit. In connection with the condition imposed by this Section 6.7(c) , the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Section 5.5(c)(ii) , Section 6.1(d)(x) , Section 6.7(b) ; provided, however , that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.

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Section 6.8   Special Provisions Relating to the Holders of Incentive Distribution Rights.

(a) Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Incentive Distribution Rights (i) shall (1) possess the rights and obligations provided in this Agreement with respect to a Limited Partner pursuant to Article III and Article VII and (2) have a Capital Account as a Partner pursuant to Section 5.5 and all other provisions related thereto and (ii) shall not (1) be entitled to vote on any matters requiring the approval or vote of the holders of Outstanding Units, except as provided by law, (2) be entitled to any distributions other than as provided in Section 6.4(b)(v) , Section 6.4(b)(vi) and Section 6.4(b)(vii) , Section 6.4(c)(iii) , Section 6.4(c)(iv) and Section 6.4(c)(v) , and Section 12.4 or (3) be allocated items of income, gain, loss or deduction other than as specified in this Article VI .
 
(b) The Unitholder holding Common Units that have resulted from the conversion of Incentive Distribution Rights pursuant to Section 5.11 shall not be issued a Common Unit Certificate pursuant to Section 4.1 if the Common Units are evidenced by Certificates, and shall not be permitted to transfer such Common Unit to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and U.S. federal income tax characteristics, in all material respects, to the intrinsic economic and U.S. federal income tax characteristics of an IPO Common Unit. In connection with the condition imposed by this Section 6.8(b) , the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Section 5.5(c)(iii) , Section 6.1(d)(x)(B) , or Section 6.1(d)(x)(C) ; provided, however , that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.

Section 6.9   Entity-Level Taxation.

 
If legislation is enacted or the official interpretation of existing legislation is modified by a governmental authority, which after giving effect to such enactment or modification, results in a Group Member becoming subject to federal, state or local or non-U.S. income or withholding taxes in excess of the amount of such taxes due from the Group Member prior to such enactment or modification (including, for the avoidance of doubt, any increase in the rate of such taxation applicable to the Group Member), then the General Partner may, in its sole discretion, reduce the Target Distributions by the amount of income or withholding taxes that are payable by reason of any such new legislation or interpretation (the “Incremental Income Taxes” ), or any portion thereof selected by the General Partner, in the manner provided in this Section 6.9 . If the General Partner elects to reduce the Target Distributions for any Quarter with respect to all or a portion of any Incremental Income Taxes, the General Partner shall estimate for such Quarter the Partnership Group’s aggregate liability (the “Estimated Incremental Quarterly Tax Amount” ) for all (or the relevant portion of) such Incremental Income Taxes; provided that any difference between such estimate and the actual liability for Incremental Income Taxes (or the relevant portion thereof) for such Quarter may, to the extent determined by the General Partner, be taken into account in determining the Estimated Incremental Quarterly Tax Amount with respect to each Quarter in which any such difference can be determined. For each such Quarter, the Target Distributions, shall be the product obtained by multiplying (a) the amounts therefor that are set out herein prior to the application of this Section 6.9 times (b) the quotient obtained by dividing (i) Available Cash with respect to such Quarter by (ii) the sum of Available Cash with respect to such Quarter and the Estimated Incremental Quarterly Tax Amount for such Quarter, as determined by the General Partner. For purposes of the foregoing, Available Cash with respect to a Quarter will be deemed reduced by the Estimated Incremental Quarterly Tax Amount for that Quarter.

ARTICLE VII
 
MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1   Management.

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delegate its rights and powers to other Persons, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3 , shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4 , including the following:
 
(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible or exchangeable into Partnership Interests, and the incurring of any other obligations;
 
(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;
 
(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 and Article XIV );
 
(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; subject to Section 7.6(a) , the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;
 
(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);
 
(vi) the distribution of Partnership cash;
 
(vii) the selection, employment, retention and dismissal of employees (including employees having titles such as “president,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors of the General Partner or the Partnership Group and the determination of their compensation and other terms of employment or hiring;
 
(viii) the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;
 
(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other Persons (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4 ;
 
(x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;
 
(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;
 
(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.8 );

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(xiii) the purchase, sale or other acquisition or disposition of Partnership Interests, or the issuance of options, rights, warrants, appreciation rights and tracking and phantom interests relating to Partnership Interests;
 
(xiv) the undertaking of any action in connection with the Partnership’s participation in any Group Member; and
 
(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.
 
(b) (b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and each other Person who may acquire an interest in Partnership Interests or is otherwise bound by this Agreement hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement, the Underwriting Agreement, the Contribution Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement (in each case other than this Agreement, without giving effect to any amendments, supplements or restatements after the date hereof); (ii) agrees that the General Partner (on its own or on behalf of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the other Persons who may acquire an interest in Partnership Interests or is otherwise bound by this Agreement; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV ) shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty existing at law, in equity or otherwise.

Section 7.2   Certificate of Limited Partnership.

The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a) , the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

Section 7.3   Restrictions on the General Partner’s Authority.

Except as provided in Article XII and Article XIV , the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions without the approval of a Unit Majority; provided, however , that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.

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Section 7.4   Reimbursement of the General Partner.

(a) Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.

(b) The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation, employment benefits and other amounts paid to any Person, including Affiliates of the General Partner to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group), and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group’s business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the General Partner or the Partnership Group. Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7 . Any allocation of expenses to the Partnership by Affiliates of the General Partner in a manner consistent with then-applicable accounting and allocation methodologies generally permitted by FERC for rate-making purposes (or in the absence of then-applicable methodologies permitted by FERC, consistent with the most-recently applicable methodologies) and past business practices shall be deemed to be fair and reasonable to the Partnership.

 
(c) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership benefit plans, programs and practices (including the Long Term Incentive Plan and other plans, programs and practices involving the issuance of Partnership Interests or options to purchase or rights, warrants or appreciation rights or phantom or tracking interests relating to Partnership Interests), or cause the Partnership to issue Partnership Interests in connection with, or pursuant to, any benefit plan, program or practice maintained or sponsored by the General Partner or any of its Affiliates in each case for the benefit of employees and directors of the General Partner or any of its Affiliates, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Interests that the General Partner or such Affiliates are obligated to provide to any employees and directors pursuant to any such benefit plans, programs or practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Interests purchased by the General Partner or such Affiliates, from the Partnership or otherwise, to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.4(b) . Any and all obligations of the General Partner under any benefit plans, programs or practices adopted by the General Partner as permitted by this Section 7.4(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest pursuant to Section 4.6 .

(d) The General Partner and its Affiliates may charge any member of the Partnership Group a management fee to the extent necessary to allow the Partnership Group to reduce the amount of any state franchise or income tax or any tax based upon the revenues or gross margin of any member of the Partnership Group if the tax benefit produced by the payment of such management fee or fees exceeds the amount of such fee or fees.

Section 7.5   Outside Activities.

(a) The General Partner, for so long as it is the General Partner of the Partnership (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a Limited Partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement, (B) the acquiring,

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owning or disposing of debt securities or equity interests in any Group Member or (C) the guarantee of, and mortgage, pledge, or encumbrance of any or all of its assets in connection with, any indebtedness of any Affiliate of the General Partner.
 
(b) Each Unrestricted Person (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty otherwise existing at law, in equity or otherwise, to any Group Member or any Partner. None of any Group Member, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, or the partnership relationship established hereby in any business ventures of any Unrestricted Person.
 
(c) Subject to the terms of Section 7.5(a) and Section 7.5(b) , but otherwise notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Unrestricted Person (other than the General Partner) in accordance with the provisions of this Section 7.5 is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any fiduciary duty or any other obligation of any type whatsoever of the General Partner or any other Unrestricted Person for the Unrestricted Persons (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership and (iii) the Unrestricted Persons shall have no obligation hereunder or as a result of any duty otherwise existing at law, in equity or otherwise, to present business opportunities to the Partnership. Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Unrestricted Person (including the General Partner). No Unrestricted Person (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership, shall have any duty to communicate or offer such opportunity to the Partnership, and such Unrestricted Person (including the General Partner) shall not be liable to the Partnership, to any Limited Partner or any other Person for breach of any fiduciary or other duty by reason of the fact that such Unrestricted Person (including the General Partner) pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership; provided such Unrestricted Person does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Partnership to such Unrestricted Person.
 
(d) The General Partner and each of its Affiliates may acquire Units or other Partnership Interests in addition to those acquired on the IPO Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units or other Partnership Interests acquired by them. The term “Affiliates” when used in this Section 7.5(d) with respect to the General Partner shall not include any Group Member.

(e) Notwithstanding anything to the contrary in this Agreement, to the extent that any provision of this Agreement purports or is interpreted to have the effect of restricting or eliminating the fiduciary duties that might otherwise, as a result of Delaware or other applicable law, be owed by the General Partner to the Partnership and its Limited Partners, or to constitute a waiver or consent by the Limited Partners to any such restriction or elimination, such provisions shall be deemed to have been approved by the Partners.

 
Section 7.6   Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.

(a) The General Partner or any of its Affiliates may, but shall be under no obligation to, lend to any Group Member, and any Group Member may, but shall be under no obligation to, borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts as the General Partner may determine; provided, however , that, in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party, or impose terms less favorable to the borrowing party than would be charged or imposed on

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the borrowing party, by unrelated lenders on comparable loans made on an arm’s-length basis (without reference to the lending party’s financial abilities or guarantees), all as determined by the General Partner. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of this Section 7.6(a) and Section 7.6(b) , the term “Group Member” shall include any Affiliate of a Group Member that is controlled by the Group Member.
 
(b) The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).
 
(c) No borrowing by any Group Member or the approval thereof by the General Partner shall be deemed to constitute a breach of any duty hereunder or otherwise existing at law, in equity or otherwise, of the General Partner or its Affiliates to the Partnership or the Limited Partners existing hereunder, or existing at law, in equity or otherwise by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to (i) enable distributions to the General Partner or its Affiliates (including in their capacities as Limited Partners) to exceed the General Partner’s Percentage Interest of the total amount distributed to all Partners or (ii) hasten the expiration of the Subordination Period or the conversion of any Subordinated Units into Common Units.

Section 7.7   Indemnification.

(a) To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened pending or completed claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee and acting (or refraining to act) in such capacity; provided, that the Indemnitee shall not be indemnified and held harmless pursuant to this Agreement if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Agreement, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful. Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.
 
(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in appearing at, participating in or defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7 , the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be ultimately determined that the Indemnitee is not entitled to be indemnified as authorized by this Section 7.7 .
 
(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law, in equity or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity, and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

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(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates, the Indemnitees and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.
 
(e) For purposes of this Section 7.7 , the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a) ; and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.
 
(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.
 
(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.
 
(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees and their heirs, successors, assigns, executors and administrators and shall not be deemed to create any rights for the benefit of any other Persons.
 
(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8   Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Partners or any other Persons who have acquired interests in the Partnership Interests, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal.
 
(b) Subject to its obligations and duties as General Partner set forth in Section 7.1(a) , the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.
 
(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership or to any Partner for its good faith reliance on the provisions of this Agreement.
 
(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims

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arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.
 
Section 7.9   Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.
 
(a) Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates, on the one hand, and the Partnership, any Group Member, any Partner, on the other, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty hereunder stated or implied by law or equity or otherwise, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), (iii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval or Unitholder approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval or Unitholder approval. If Special Approval is sought, then it shall be presumed that, in making its decision, the Conflicts Committee acted in good faith, and if neither Special Approval nor Unitholder approval is sought and the Board of Directors determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above, then it shall be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Registration Statement and any actions of the General Partner taken in connection therewith are hereby approved by all Partners and shall not constitute a breach of this Agreement or of any duty hereunder or existing at law, in equity or otherwise.
 
(b) Whenever the General Partner, or any committee of the Board of Directors (including the Conflicts Committee), makes a determination or takes or declines to take any other action, or any of its Affiliates causes the General Partner to do so, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the General Partner, such committee or such Affiliates causing the General Partner to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards (including fiduciary standards) imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “good faith” for purposes of this Agreement, the Person or Persons making such determination or taking or declining to take such other action must believe that the determination or other action is in the best interests of the Partnership.
 
(c) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled, to the fullest extent permitted by law, to make such determination or to take or decline to take such other action free of any duty (including any fiduciary duty) or obligation whatsoever to the Partnership, any Limited Partner or any other Person bound by this Agreement, and the General Partner, or such Affiliates causing it to do so, shall not, to the fullest extent permitted by law, be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other

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agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. By way of illustration and not of limitation, whenever the phrases, “at the option of the General Partner,” “in its sole discretion” or some variation of those phrases, are used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be acting in its individual capacity.
 
(d) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts shall be in its sole discretion.
 
(e) Except as expressly set forth in this Agreement, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner or such other Indemnitee.
 
(f) The Limited Partners hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve of actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9 .
 
Section 7.10   Other Matters Concerning the General Partner.
 
(a) The General Partner may rely upon, and shall be protected in acting or refraining from acting upon, any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.
 
(b) The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the advice or opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such advice or opinion.
 
(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership or any Group Member.
 
Section 7.11   Purchase or Sale of Partnership Interests.
 
The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Interests; provided that, except as permitted pursuant to Section 4.10 , the General Partner may not cause any Group Member to purchase Subordinated Units during the Subordination Period. As long as Partnership Interests are held by any Group Member, such Partnership Interests shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Interests for its own account, subject to the provisions of Article IV and Article X .

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Section 7.12   Registration Rights of the General Partner and its Affiliates.

(a) If (i) the General Partner or any Affiliate of the General Partner (including for purposes of this Section 7.12 , any Person that is an Affiliate of the General Partner at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner but excluding any individual who is an Affiliate of the General Partner based on such individual’s status as an officer, director or employee of the General Partner or an Affiliate of the General Partner) holds Partnership Interests that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Partnership Interests (the “Holder” ) to dispose of the number of Partnership Interests it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Interests covered by such registration statement have been sold, a registration statement under the Securities Act registering the offering and sale of the number of Partnership Interests specified by the Holder; provided , however , that the Partnership shall not be required to effect more than three registrations pursuant to this Section 7.12(a) ; and provided further , however , that if the General Partner determines that a postponement of the requested registration would be in the best interests of the Partnership and its Partners due to a pending transaction, investigation or other event, the filing of such registration statement or the effectiveness thereof may be deferred for up to six months, but not thereafter. In connection with any registration pursuant to the immediately preceding sentence, the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Interests subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Interests in such states. Except as set forth in Section 7.12(c) , all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(b) If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of Partnership Interests for cash (other than an offering relating solely to a benefit plan), the Partnership shall use all commercially reasonable efforts to include such number or amount of Partnership Interests held by any Holder in such registration statement as the Holder shall request; provided , that the Partnership is not required to make any effort or take any action to so include the Partnership Interests of the Holder once the registration statement becomes or is declared effective by the Commission, including any registration statement providing for the offering from time to time of Partnership Interests pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 7.12(b) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Partnership and the Holder that in their opinion the inclusion of all or some of the Holder’s Partnership Interests would adversely and materially affect the timing or success of the offering, the Partnership shall include in such offering only that number or amount, if any, of Partnership Interests held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 7.12(c) , all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.
 
(c) If underwriters are engaged in connection with any registration referred to in this Section 7.12 , the Partnership shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Partnership’s obligation under Section 7.7 , the Partnership shall, to the fullest extent

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permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons” ) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(c) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Interests were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or issuer free writing prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however , that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or any free writing prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.
 
(d) The provisions of Section 7.12(a) and Section 7.12(b) shall continue to be applicable with respect to the General Partner (and any of the General Partner’s Affiliates) after it ceases to be a general partner of the Partnership, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Interests with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, however , that the Partnership shall not be required to file successive registration statements covering the same Partnership Interests for which registration was demanded during such two-year period. The provisions of Section 7.12(c) shall continue in effect thereafter.
 
(e) The rights to cause the Partnership to register Partnership Interests pursuant to this Section 7.12 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Partnership Interests, provided (i) the Partnership is, within a reasonable time after such transfer, furnished with written notice of the name and address of such transferee or assignee and the Partnership Interests with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 7.12 .
 
(f) Any request to register Partnership Interests pursuant to this Section 7.12 shall (i) specify the Partnership Interests intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Partnership Interests for distribution, (iii) describe the nature or method of the proposed offer and sale of Partnership Interests, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Interests.
 
(g) The Partnership may enter into separate registration rights agreements with the General Partner or any of its Affiliates.
 
Section 7.13   Reliance by Third Parties.
 
Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Limited Partner

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hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.
 
ARTICLE VIII
 
BOOKS, RECORDS, ACCOUNTING AND REPORTS
 
Section 8.1   Records and Accounting.

The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a) . Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders of Units or other Partnership Interests, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, magnetic tape, photographs, micrographics or any other information storage device; provided , that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP. The Partnership shall not be required to keep books maintained on a cash basis and the General Partner shall be permitted to calculate cash-based measures, including Operating Surplus and Adjusted Operating Surplus, by making such adjustments to its accrual basis books to account for non-cash items and other adjustments as the General Partner determines to be necessary or appropriate.

Section 8.2   Fiscal Year.
 
The fiscal year of the Partnership shall be a fiscal year ending December 31.
 
Section 8.3   Reports.
 
(a) As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available, by any reasonable means to each Record Holder of a Unit or other Partnership Interest as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner.
 
(b) As soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means to each Record Holder of a Unit or other Partnership Interest, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

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(c) The General Partner shall be deemed to have made a report available to each Record Holder as required by this Section 8.3 if it has either (i) filed such report with the Commission via its Electronic Data Gathering, Analysis and Retrieval system, or any successor system, and such report is publicly available on such system or (ii) made such report available on any publicly available website maintained by the Partnership.
 
ARTICLE IX
 
TAX MATTERS
 
Section 9.1   Tax Returns and Information.
 
The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and the taxable period or years that it is required by law to adopt, from time to time, as determined by the General Partner. In the event the Partnership is required to use a taxable period other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable period of the Partnership to a year ending on December 31. The tax information reasonably required by Record Holders for federal, state and local income tax reporting purposes with respect to a taxable period shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable period ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for U.S. federal income tax purposes.
 
Section 9.2   Tax Elections.
 
(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(f) without regard to the actual price paid by such transferee.
 
(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.
 
Section 9.3   Tax Controversies.
 
Subject to the provisions hereof, the General Partner is designated as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.
 
Section 9.4   Withholding.
 
(a) The General Partner may treat taxes paid by the Partnership on behalf of, all or less than all of the Partners, either as a distribution of cash to such Partners or as a general expense of the Partnership, as determined appropriate under the circumstances by the General Partner.
 
(b) Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or

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elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income or from a distribution to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.
 
ARTICLE X
 
ADMISSION OF PARTNERS
 
Section 10.1   Admission of Limited Partners.
 
(a) The General Partner and AIM Midstream were admitted to the Partnership as Initial Limited Partners on November 4, 2009. The LTIP Partners were admitted to the Partnership as Limited Partners at various dates prior to the date hereof.

(b) A Person shall be admitted as a Limited Partner and shall become bound by the terms of this Agreement if such Person purchases or otherwise lawfully acquires any Limited Partner Interest and becomes the Record Holder of such Limited Partner Interests in accordance with the provisions of Article IV or Article V . A Person may become a Record Holder of a Limited Partner Interest without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest and until reflected on the books and records of the Partnership as the Record Holder of such Limited Partner Interest. The rights and obligations of a Person who is an Ineligible Holder shall be determined in accordance with Section 4.9 . Upon the issuance by the Partnership of Common Units to the Underwriters as described in Section 5.3 in connection with the Initial Public Offering, the Underwriters will automatically be admitted to the Partnership as Limited Partners in respect of the Common Units issued to them.

 
(c) The name and mailing address of each Record Holder shall be listed on the books and records of the Partnership maintained for such purpose by the Partnership or the Transfer Agent. The General Partner shall update the books and records of the Partnership from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Limited Partner Interest may be represented by a Certificate, as provided in Section 4.1 .

(d) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.1(b) .
 
Section 10.2   Admission of Successor General Partner.
 
A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest (represented by Notional General Partner Units) pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or Section 11.2 or the transfer of the General Partner Interest (represented by Notional General Partner Units) pursuant to Section 4.6 , provided, however , that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.
 
Section 10.3   Amendment of Agreement and Certificate of Limited Partnership.
 
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required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership.
 
ARTICLE XI
 
WITHDRAWAL OR REMOVAL OF PARTNERS
 
Section 11.1   Withdrawal of the General Partner.
 
(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal” );
 
(i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;
 
(ii) The General Partner transfers all of its General Partner Interest pursuant to Section 4.6 ;
 
(iii) The General Partner is removed pursuant to Section 11.2 ;
 
(iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A)-(C) of this Section 11.1(a)(iv) ; or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;
 
(v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or
 
(vi) (A) in the event the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) in the event the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) in the event the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.
 
If an Event of Withdrawal specified in Section 11.1(a)(iv) , Section 11.1(a)(v) , Section 11.1(a)(vi)(A) , Section 11.1(a)(vi)(B) , Section 11.1(a)(vi)(C) or Section 11.1(a)(vi)(E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time before 12:00 midnight, Central Time, on June 30, 2021, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners; provided , that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel ( “Withdrawal Opinion of Counsel” ) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or any Group Member or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for

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U.S. federal income tax purposes (to the extent not already so treated or taxed); (ii) at any time after 12:00 midnight, Central Time, on June 30, 2021, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2 ; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i) , a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal pursuant to Section 11.1(a)(i) , a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1 unless the business of the Partnership is continued pursuant to Section 12.2 . Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.2.

Section 11.2   Removal of the General Partner.

The General Partner may be removed if such removal is approved by the Unitholders holding at least 66 2 / 3 % of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders holding a majority of the Outstanding Common Units, voting as a separate class and a majority of the Outstanding Subordinated Units (if any Subordinated Units are then Outstanding) voting as a separate class (including, in each case, Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.2 . The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2 , such Person shall, upon admission pursuant to Section 10.2 , automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.2 .

Section 11.3   Interest of Departing General Partner and Successor General Partner.
 
(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 , the Departing General Partner shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner, to require its successor to purchase its General Partner Interest and its or its Affiliates’ general partner interest (or equivalent interest), if any, in the other Group Members and all of its or its Affiliates’ Incentive Distribution Rights (collectively, the “Combined Interest” ) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its withdrawal or removal. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this

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Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.4 , including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.
 
For purposes of this Section 11.3(a) , the fair market value of the Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner’s withdrawal or removal, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such withdrawal or removal, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest. In making its determination, such third independent investment banking firm or other independent expert may consider the value of the Units, including the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership’s assets, the rights and obligations of the Departing General Partner, the value of the Incentive Distribution Rights and the General Partner Interest and other factors it may deem relevant.
 
(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a) , the Departing General Partner (and its Affiliates, if applicable) shall become a Limited Partner and the Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a) , without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest to Common Units will be characterized as if the Departing General Partner (and its Affiliates, if applicable) contributed the Combined Interest to the Partnership in exchange for the newly issued Common Units.
 
(c) If a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner) and the option described in Section 11.3(a) is not exercised by the party entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to the product of (x) the quotient obtained by dividing (A) the Percentage Interest of the General Partner Interest of the Departing General Partner by (B) a percentage equal to 100% less the Percentage Interest of the General Partner Interest of the Departing General Partner and (y) the Net Agreed Value of the Partnership’s assets on such date. In such event, such successor General Partner shall, subject to the following sentence, be entitled to its Percentage Interest of all Partnership allocations and distributions to which the Departing General Partner was entitled. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner’s admission, the successor General Partner’s interest in all Partnership distributions and allocations shall be its Percentage Interest.

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Section 11.4   Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages.
 
Notwithstanding any provision of this Agreement, if the General Partner is removed as general partner of the Partnership under circumstances where Cause does not exist and Units held by the General Partner and its Affiliates are not voted in favor of such removal, (i) the Subordination Period will end and all Outstanding Subordinated Units will immediately and automatically convert into Common Units on a one-for-one basis ( provided, however , that such converted Subordinated Units shall remain subject to the provisions of Section 5.5(c)(ii) , Section 6.1(d)(x) and Section 6.7(c) ), (ii) all Cumulative Common Unit Arrearages on the Common Units will be extinguished and (iii) the General Partner will have the right to convert its General Partner Interest (represented by Notional General Partner Units) and its Incentive Distribution Rights into Common Units or to receive cash in exchange therefor in accordance with Section 11.3 .
 
Section 11.5   Withdrawal of Limited Partners.
 
No Limited Partner shall have any right to withdraw from the Partnership; provided, however , that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.
 
ARTICLE XII
 
DISSOLUTION AND LIQUIDATION
 
Section 12.1   Dissolution.
 
The Partnership shall not be dissolved by the admission of Additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1 , Section 11.2 or Section 12.2 , the Partnership shall not be dissolved and such successor General Partner is hereby authorized to, and shall, continue the business of the Partnership. Subject to Section 12.2 , the Partnership shall dissolve, and its affairs shall be wound up, upon:
 
(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii) ), unless a successor is elected and such successor is admitted to the Partnership pursuant to this Agreement;
 
(b) an election to dissolve the Partnership by the General Partner that is approved by a Unit Majority;
 
(c) the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act; or
 
(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.
 
Section 12.2   Continuation of the Business of the Partnership After Dissolution.
 
Upon an Event of Withdrawal caused by (a) the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or Section 11.1(a)(iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 or Section 11.2 , then within 90 days thereafter, or (b) an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv) , Section 11.1(a)(v) or Section 11.1(a)(vi) , then, to the maximum extent permitted by law, within 180 days thereafter, a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as a successor General Partner a Person approved by a Unit Majority. Unless such

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an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:
 
(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII ;
 
(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3 ; and
 
(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement;
 
provided , that the right of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability under the Delaware Act of any Limited Partner and (y) neither the Partnership nor any Group Member would be treated as an association taxable as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).
 
Section 12.3   Liquidator.
 
Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2 , the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, if any, voting as a single class. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, if any, voting as a single class. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, if any, voting as a single class. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII , the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3 ) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.
 
Section 12.4   Liquidation.
 
The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:
 
(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

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(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3 ) and amounts to Partners otherwise than in respect of their distribution rights under Article VI . With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c) ) for the taxable period of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable period (or, if later, within 90 days after said date of such occurrence).
 
Section 12.5   Cancellation of Certificate of Limited Partnership.
 
Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.
 
Section 12.6   Return of Contributions.
 
The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.
 
Section 12.7   Waiver of Partition.
 
To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.
 
Section 12.8   Capital Account Restoration.
 
No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership. The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable period of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.
 
ARTICLE XIII
 
AMENDMENT OF PARTNERSHIP AGREEMENT;
MEETINGS; RECORD DATE
 
Section 13.1   Amendments to be Adopted Solely by the General Partner.
 
Each Partner agrees that the General Partner, without the approval of any Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:
 
(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

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(b) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;
 
(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;
 
(d) a change that the General Partner determines, (i) does not adversely affect in any material respect the Limited Partners considered as a whole or any particular class of Partnership Interests as compared to other classes of Partnership Interests, (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.9 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;
 
(e) a change in the fiscal year or taxable period of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable period of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;
 
(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;
 
(g) an amendment that the General Partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of any class or series of Partnership Interests and options, rights, warrants and appreciation rights relating to the Partnership Interests pursuant to Section 5.6 , including any amendment that the General Partner determines is necessary or appropriate in connection with (i) the adjustments of the Target Distributions pursuant to the provisions of Section 5.11 , (ii) the implementation of the provisions of Section 5.11 or (iii) any modifications to the Incentive Distribution Rights made in connection with the issuance of Partnership Interests pursuant to Section 5.6 , provided that, with respect to this clause (iii), the modifications to the Incentive Distribution Rights and the related issuance of Partnership Interests have received Special Approval;
 
(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;
 
(i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3 ;
 
(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4 or Section 7.1(a) ;
 
(k) a merger, conveyance or conversion pursuant to Section 14.3(d) ; or
 
(l) any other amendments substantially similar to the foregoing.

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Section 13.2   Amendment Procedures.
 
Except as provided in Section 13.1 and Section 13.3 , all amendments to this Agreement shall be made in accordance with the requirements contained in this Section 13.2 . Amendments to this Agreement may be proposed only by the General Partner; provided, however , that, to the full extent permitted by law, the General Partner shall have no duty or obligation to propose or approve any amendment to this Agreement and may decline to do so free of any duty (including any fiduciary duty) or obligation whatsoever to the Partnership, any Limited Partner, or any other Person bound by this Agreement and, in declining to propose or approve an amendment, to the fullest extent permitted by law shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. A proposed amendment shall be effective upon its approval by the General Partner and, except as otherwise provided by Section 13.1 and Section 13.3 , a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any such proposed amendments. The General Partner shall be deemed to have notified all Record Holders as required by this Section 13.2 if it has either (i) filed such amendment with the Commission via its Electronic Data Gathering, Analysis and Retrieval system, or any successor system, and such amendment is publicly available on such system or (ii) made such amendment available on any publicly available website maintained by the Partnership.

Section 13.3   Amendment Requirements.

 
(a) Notwithstanding the provisions of Section 13.1 and Section 13.2 , no provision of this Agreement that establishes a percentage of Outstanding Units (including Units deemed owned by the General Partner) or requires a vote or approval of Partners (or a subset of the Partners) holding a specified Percentage Interest required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of in the case of any provision of this Agreement other than Section 11.2 or Section 13.4 , reducing such percentage, unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced or increased, as applicable or the affirmative vote of Partners whose aggregate Percentage Interest constitutes not less than the voting requirement sought to be reduced, as applicable.

 
(b) Notwithstanding the provisions of Section 13.1 and Section 13.2 , no amendment to this Agreement may (i) enlarge the obligations of (including requiring any holder of a class of Partnership Interests to make additional Capital Contributions to the Partnership) any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c) , or (ii) enlarge the obligations of, restrict, change or modify in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.

 
(c) Except as provided in Section 14.3 and Section 13.1 , any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected. If the General Partner determines an amendment does not satisfy the requirements of Section 13.1(d)(i) because it adversely affects one or more classes of Partnership Interests, as compared to other classes of Partnership Interests, in any material respect, such amendment shall only be required to be approved by the adversely affected class or classes.

 
(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b) , no amendments shall become effective

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without the approval of the holders of at least 90% of the Percentage Interests of all Limited Partners voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

 
(e) Except as provided in Section 13.1 , this Section 13.3 shall only be amended with the approval of Partners (including the General Partner and its Affiliates) holding at least 90% of the Percentage Interests of all Limited Partners.

Section 13.4   Special Meetings.

All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII . Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the time notice of the meeting is given as provided in Section 16.1 . Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5   Notice of a Meeting.

Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1 . The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

Section 13.6   Record Date.
 
For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading or U.S. federal securities laws, in which case the rule, regulation, guideline or requirement of such National Securities Exchange or U.S. federal securities laws shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (a) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given, and (b) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11 .
 
Section 13.7   Adjournment.
 
When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting,

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the Partnership may transact any business that might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII .
 
Section 13.8   Waiver of Notice; Approval of Meeting; Approval of Minutes.
 
The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.
 
Section 13.9   Quorum and Voting.
 
The holders of a majority, by Percentage Interest, of the Partnership Interests of the class or classes for which a meeting has been called (including Partnership Interests deemed owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Partners of such class or classes unless any such action by the Partners requires approval by holders of a greater Percentage Interest, in which case the quorum shall be such greater Percentage Interest. At any meeting of the Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of Partners holding Partnership Interests that in the aggregate represent a majority of the Percentage Interest of those present in person or by proxy at such meeting shall be deemed to constitute the act of all Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Partners holding Partnership Interests that in the aggregate represent at least such greater or different percentage shall be required; provided, however, that if, as a matter of law or amendment to this Agreement, approval by plurality vote of Partners (or any class thereof) is required to approve any action, no minimum quorum shall be required. The Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by Partners holding the required Percentage Interest specified in this Agreement. In the absence of a quorum any meeting of Partners may be adjourned from time to time by the affirmative vote of Partners with at least a majority, by Percentage Interest, of the Partnership Interests entitled to vote at such meeting (including Partnership Interests deemed owned by the General Partner) represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7 .
 
Section 13.10   Conduct of a Meeting.
 
The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4 , the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

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Section 13.11   Action Without a Meeting.
 
If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting, without a vote and without prior notice, if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage, by Percentage Interest, of the Partnership Interests of the class or classes for which a meeting has been called (including Partnership Interests deemed owned by the General Partner), as the case may be, that would be necessary to authorize or take such action at a meeting at which all the Limited Partners entitled to vote at such meeting were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot, if any, submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner and (b) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners. Nothing contained in this Section 13.11 shall be deemed to require the General Partner to solicit all Limited Partners in connection with a matter approved by the holders of the requisite percentage of Units acting by written consent without a meeting.
 
Section 13.12   Right to Vote and Related Matters.
 
(a) Only those Record Holders of the Outstanding Units on the Record Date set pursuant to Section 13.6 shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.
 
(b) With respect to Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3 .

 
ARTICLE XIV
 
MERGER, CONSOLIDATION OR CONVERSION
 
Section 14.1   Authority.
 
The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any

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other state of the United States of America, pursuant to a written plan of merger or consolidation ( “Merger Agreement” ) in accordance with this Article XIV .
 
Section 14.2   Procedure for Merger, Consolidation or Conversion.
 
(a) Merger or consolidation of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, however , that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger or consolidation of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner and, in declining to consent to a merger or consolidation, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.
 
(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:
 
(i) the name and jurisdiction of formation or organization of each of the business entities proposing to merge or consolidate;
 
(ii) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity” );
 
(iii) the terms and conditions of the proposed merger or consolidation;
 
(iv) the manner and basis of exchanging or converting the equity interests of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity, then the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) that the holders of such interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (ii) in the case of equity interests represented by certificates, upon the surrender of such certificates, which cash, property or interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;
 
(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, certificate of formation or limited liability company agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;
 
(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.5 or a later date specified in or determinable in accordance with the Merger Agreement ( provided , that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain and stated in the certificate of merger); and
 
(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

 
Section 14.3   Approval by Limited Partners.
 
(a) Except as provided in Section 14.3(d) , the General Partner, upon its approval of the Merger Agreement shall direct that the Merger Agreement and the merger or consolidation contemplated thereby, as applicable, be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in

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either case in accordance with the requirements of Article XIII . A copy or a summary of the Merger Agreement shall be included in or enclosed with the notice of a special meeting or the written consent.

(b) Except as provided in Section 14.3(d) and Section 14.3(e) , the Merger Agreement shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement contains any provision that, if contained in an amendment to this Agreement, the provisions of this Agreement or the Delaware Act would require for its approval the vote or consent of a greater percentage of the Outstanding Units or of any class of Limited Partners, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement.
 
(c) Except as provided in Section 14.3(d) and Section 14.3(e) , after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger pursuant to Section 14.5 , the merger or consolidation may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement.
 
(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the merger or conveyance, as the case may be, would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already treated as such), (ii) the sole purpose of such merger or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the Limited Partners and the General Partner with substantially the same rights and obligations as are herein contained.
 
(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already treated as such), (B) the merger or consolidation would not result in an amendment to this Agreement, other than any amendments that could be adopted pursuant to Section 13.1 , (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Partnership Interest outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Partnership Interest of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Interests to be issued by the Partnership in such merger or consolidation does not exceed 20% of the Partnership Interests (other than the Incentive Distribution Rights) Outstanding immediately prior to the effective date of such merger or consolidation.
 
Section 14.4   Amendment of Partnership Agreement.

Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.4 shall be effective at the effective time or date of the merger or consolidation.

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Section 14.5   Certificate of Merger.
 
Upon the required approval by the General Partner and the Unitholders of a Merger Agreement, a certificate of merger shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.
 
Section 14.6   Effect of Merger or Consolidation.
 
At the effective time of the certificate of merger:
 
(a) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;
 
(b) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;
 
(c) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and
 
(d) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.
 
ARTICLE XV
 
RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS
 
Section 15.1   Right to Acquire Limited Partner Interests.
 
(a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 80% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable in its sole discretion, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed.
 
(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a) , the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase” ) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class or classes (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a) ) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in the case of Limited Partner Interests evidenced by Certificates in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading. Any such Notice of Election to Purchase mailed to

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a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1 . If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a) ) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited Partner Interests in the case of Limited Partner Interests evidenced by Certificates, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests.

(c) In the case of Limited Partner Interests evidenced by Certificates, at any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a) , therefor, without interest thereon.
 
ARTICLE XVI
 
GENERAL PROVISIONS
 
Section 16.1   Addresses and Notices; Written Communications.
 
(a) Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Interests at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Interests by reason of any assignment or otherwise. Notwithstanding the foregoing, if (i) a Partner shall consent to receiving notices, demands, requests, reports or proxy materials via electronic mail or by the Internet or (ii) the rules of the Commission shall permit any report or proxy materials to be delivered electronically or made available via the Internet, any such notice, demand, request, report or proxy materials shall be deemed given or made when delivered or made available via such mode of delivery. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report given or made in accordance with the provisions of this Section 16.1 is returned marked to indicate that such notice, payment or report was unable to be delivered, such notice, payment or report and, in the case of notices, payments or reports returned by the United States Postal Service (or other physical mail delivery mail service outside the United States of America), any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) or other delivery if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice

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to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3 . The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

(b) The terms “in writing”, “written communications,” “written notice” and words of similar import shall be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.
 
Section 16.2   Further Action.
 
The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.
 
Section 16.3   Binding Effect.
 
This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.
 
Section 16.4   Integration.
 
This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.
 
Section 16.5   Creditors.
 
None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.
 
Section 16.6   Waiver.
 
No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.
 
Section 16.7   Third-Party Beneficiaries.
 
Each Partner agrees that (a) any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee and (b) any Unrestricted Person shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Unrestricted Person.
 
Section 16.8   Counterparts.
 
This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement (a) immediately upon affixing its signature hereto, (b) in the case of the General Partner and the holders of Limited Partner Interest outstanding immediately prior to the closing of the Initial Public Offering, immediately upon the closing of the Initial Public Offering, without the execution hereof, or (c) in the case of a Person acquiring a Limited Partner Interest pursuant to Section 10.1(b) , immediately upon the acquisition of such Limited Partner Interest, without execution hereof.
 
Section 16.9   Applicable Law; Forum; Venue and Jurisdiction.
 
(a) This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

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(b) Each of the Partners and each Person holding any beneficial interest in the Partnership (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):
 
(i) irrevocably agrees that any claims, suits, actions or proceedings (A) arising out of or relating in any way to this Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of this Agreement or the duties, obligations or liabilities among Partners or of Partners to the Partnership, or the rights or powers of, or restrictions on, the Partners or the Partnership), (B) brought in a derivative manner on behalf of the Partnership, (C) asserting a claim of breach of a fiduciary duty owed by any director, officer, or other employee of the Partnership or the General Partner, or owed by the General Partner, to the Partnership or the Partners, (D) asserting a claim arising pursuant to any provision of the Delaware Act or (E) asserting a claim governed by the internal affairs doctrine shall be exclusively brought in the Court of Chancery of the State of Delaware, in each case regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims;
 
(ii) irrevocably submits to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claim, suit, action or proceeding;
 
(iii) agrees not to, and waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction of the Court of Chancery of the State of Delaware or of any other court to which proceedings in the Court of Chancery of the State of Delaware may be appealed, (B) such claim, suit, action or proceeding is brought in an inconvenient forum, or (C) the venue of such claim, suit, action or proceeding is improper;
 
(iv) expressly waives any requirement for the posting of a bond by a party bringing such claim, suit, action or proceeding; and
 
(v) consents to process being served in any such claim, suit, action or proceeding by mailing, certified mail, return receipt requested, a copy thereof to such party at the address in effect for notices hereunder, and agrees that such services shall constitute good and sufficient service of process and notice thereof; provided, nothing in clause (v) hereof shall affect or limit any right to serve process in any other manner permitted by law.
 
Section 16.10   Invalidity of Provisions.
 
If any provision or part of a provision of this Agreement is or becomes for any reason, invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions and part thereof contained herein shall not be affected thereby and this Agreement shall, to the fullest extent permitted by law, be reformed and construed as if such invalid, illegal or unenforceable provision, or part of a provision, had never been contained herein, and such provision or part reformed so that it would be valid, legal and enforceable to the maximum extent possible.
 
Section 16.11   Consent of Partners.
 
Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.
 
Section 16.12   Facsimile Signatures.
 
The use of facsimile signatures affixed in the name and on behalf of the transfer agent and registrar of the Partnership on Certificates representing Common Units is expressly permitted by this Agreement.

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Section 16.13   Provisions Regarding Effective Time.
 
This Agreement is to become effective upon the closing of the Initial Public Offering, and accordingly in connection therewith the parties hereto agree that the following shall apply:
 
(a) From and after the approval of this Agreement by the Partners in accordance with the First A/R Partnership Agreement, this Agreement shall constitute an agreement binding upon and enforceable by the Partners subject to the application of the provisions hereof generally being effective upon the closing of the Initial Public Offering.
 
(b) The affairs of the Partnership shall continue to be governed by the terms of the First A/R Partnership Agreement until the closing of the Initial Public Offering.
 
(c) If the closing of the Initial Public Offering does not occur on or before December 31, 2011, this Agreement shall be null and void and of no force and effect and the First A/R Partnership Agreement shall continue in full force and effect.
 
ARTICLE XVII
 
CERTAIN TRANSACTIONS IN CONNECTION WITH THE INITIAL PUBLIC OFFERING
 
Section 17.1   Non-Pro Rata Redemption of Common Units.
 
The General Partner is authorized to use the proceeds from any exercise by the Underwriters of the Over-Allotment Option in the Initial Public Offering to redeem from AIM Midstream, but not from other Partners, that number of Common Units that corresponds to the number of Common Units issued upon such exercise at a price per Common Unit equal to the price per Common Unit received by the Partnership for the Common Units issued to the Underwriters upon such exercise.
 
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IN WITNESS WHEREOF , the General Partner has executed this Agreement as of the date first written above.
 
GENERAL PARTNER
 
AMERICAN MIDSTREAM GP, LLC

			
 	By: 	     	

Name:     Brian Bierbach
			
 	Title: 	CEO and President	
 
[Signature Page — Second Amended & Restated Agreement
of Limited Partnership of American Midstream Partners, LP]

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EXHIBIT A
to the Second Amended and Restated
Agreement of Limited Partnership of
American Midstream Partners, LP
 
Certificate Evidencing Common Units
Representing Limited Partner Interests in
American Midstream Partners, LP
		
Certificate No.      	Number of Common Units:          	
 
In accordance with Section 4.1 of the Second Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, as amended, supplemented or restated from time to time (the “Partnership Agreement” ), American Midstream Partners, LP, a Delaware limited partnership (the “Partnership” ), hereby certifies that           (the “Holder” ) is the registered owner of Common Units representing limited partner interests in the Partnership (the “Common Units” ) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 1614 15th Street, Suite 300, Denver, CO 80202. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF AMERICAN MIDSTREAM PARTNERS, LP THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN-APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF AMERICAN MIDSTREAM PARTNERS, LP UNDER THE LAWS OF THE STATE OF DELAWARE OR (C) CAUSE AMERICAN MIDSTREAM PARTNERS, LP TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). AMERICAN MIDSTREAM GP, LLC OR ITS SUCCESSOR, THE GENERAL PARTNER OF AMERICAN MIDSTREAM PARTNERS, LP, MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF AMERICAN MIDSTREAM PARTNERS, LP BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

The Holder, by accepting this Certificate, (i) shall become bound by the terms of the Partnership Agreement, (ii) represents and warrants that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement and (iii) makes the waivers and gives the consents and approvals contained in the Partnership Agreement.

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This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.

Dated:	 	American Midstream Partners, LP	
 	 	 	 	 	
Countersigned and Registered by:	 	By:	 	American Midstream GP, LLC, its General Partner	
 	 	 	 	 	 	 	
 	 	 	 	By:	 	 	

as Transfer Agent and Registrar	 	 	 	 	
 	 	 	 	Name:	

 	 	 	 	 	 	 	
By:	 	 	 	By:	 	 	
 	 	 	 	 	 	 	
 	 	Authorized Signature	 	 	 	Secretary	

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ABBREVIATIONS
 
The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

TEN COM —	 	as tenants in common	 	 	 	 	 	 	 	 	
 	 	 	 	UNIF GIFT/TRANSFERS MIN ACT	 	 	
TEN ENT —	 	as tenants by the entireties	 	                                	 	Custodian	 	                                	 	 	
 	 	 	 	(Cust)	 	 	 	(Minor)	 	 	
JT TEN —	 	as joint tenants with right of survivorship and not as tenants in common	 	under Uniform Gifts/Transfers to CD Minors Act (State)	

Additional abbreviations, though not in the above list, may also be used.

FOR VALUE RECEIVED,                     hereby assigns, conveys, sells and transfers unto

 	 	 	
 	 	 	
(Please print or typewrite name and address of assignee)	 	(Please insert Social Security or other identifying number of assignee)	

 
Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint                    as its attorney-in-fact with full power of substitution to transfer the same on the books of American Midstream Partners, LP

 	 	 	
 Date:	 	NOTE:  The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.	
THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17Ad-15	 	

(Signature)

(Signature)	

 
No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration or transfer and an Application for Transfer of Common Units has been properly completed and executed by a transferee either (a) on the form set forth below or (b) on a separate application that the Partnership will furnish on request without charge. A transferor of the Common Units shall have no duty to the transferee with respect to execution of the Application for Transfer of Common Units in order for such transferee to obtain registration of the transfer of the Common Units.

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APPENDIX B
 
Glossary of Terms
 
Bbl:   One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
 
Bcf/d:   One billion cubic feet per day.
 
condensate:   A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
 
dry gas:   A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.
 
end-use markets:   The ultimate users and consumers of transported energy products.
 
FERC:   Federal Energy Regulatory Commission.
 
gal:   One gallon.
 
gal/d:   One gallon per day.
 
Mcf:   One thousand cubic feet.
 
Mgal/d:   One thousand gallons per day.
 
MMBbl/d:   One million stock tank barrels per day.
 
MMBtu:   One million British Thermal Units.
 
MMBtu/d:   One million British Thermal Units per day.
 
MMcf:   One million cubic feet.
 
MMcf/d:   One million cubic feet per day.
 
NGA:   Natural Gas Act of 1938.
 
NGLs:   Natural gas liquids. The combination of ethane, propane, normal butane, iso-butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
 
NYMEX:   New York Mercantile Exchange.
 
OPIS:   Oil Price Information Service.
 
play:   A proven geological formation that contains commercial amounts of hydrocarbons.
 
receipt point:   The point where production is received by or into a gathering system or transportation pipeline.
 
residue gas:   The natural gas remaining after being processed or treated.
 
tailgate:   Refers to the point at which processed natural gas and natural gas liquids leave a processing facility for end-use markets.
 
Tcf:   One trillion cubic feet.
 
throughput:   The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.
 
wellhead:   The equipment at the surface of a well used to control the well’s pressure; also, the point at which the hydrocarbons and water exit the ground.
 
WTI:   West Texas Intermediate, a type of crude oil commonly used as a price benchmark.

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3,750,000 Common Units

American Midstream Partners, LP
 
Common Units
Representing Limited Partner Interests

 

 
PRELIMINARY PROSPECTUS
 
          , 2011

 
 
Citi
 
BofA Merrill Lynch

Barclays Capital
Wells Fargo Securities

 
Until          , 2011 (25 days after the date of this prospectus), all dealers that buy, sell or trade shares of our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

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PART II
 
INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13.   	Other Expenses of Issuance and Distribution.	
 
Set forth below are the expenses (other than underwriting discounts, commissions and structuring fees) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.

 	 	 	 	 	
SEC registration fee	 	$	8,708	 	
FINRA filing fee	 	 	8,000	 	
NYSE listing fee	 	 	125,000	 	
Printing and engraving expenses	 	 	600,000	 	
Fees and expenses of legal counsel	 	 	1,250,000	 	
Accounting fees and expenses	 	 	900,000	 	
Transfer agent and registrar fees	 	 	10,000	 	
Miscellaneous	 	 	348,292	 	
 	 	 	 	 	
Total	 	$	3,250,000	 	

 
		
Item 14.   	Indemnification of Directors and Officers.	
 
American Midstream Partners, LP
 
Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against any and all claims and demands whatsoever. The section of the prospectus entitled “The Partnership Agreement — Indemnification” discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by reference.
 
The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of American Midstream Partners, LP and our general partner, their officers and directors, and any person who controls our general partner, including indemnification for liabilities under the Securities Act.
 
American Midstream GP, LLC
 
Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.
 
Under the limited liability agreement of our general partner, in most circumstances, our general partner will indemnify the following persons, to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings (whether civil, criminal, administrative or investigative):

 	• 	any person who is or was an affiliate of our general partner (other than us and our subsidiaries);	
 		
 	• 	any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any affiliate of our general partner;	

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 	• 	any person who is or was serving at the request of our general partner or any affiliate of our general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person; and	
 		
 	• 	any person designated by our general partner.	
 
Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.

Item 15.   	Recent Sales of Unregistered Securities.	
 
On November 4, 2009, in connection with our formation, we issued (i) 200,000 general partner units representing a 2.0% general partner interest in us and all of our incentive distribution rights to our general partner in exchange for $2.0 million and (ii) 9,800,000 common units representing a 98.0% limited partner interest in us to AIM Midstream Holdings in exchange for $98.0 million. These transactions were exempt from registration under Section 4(2) of the Securities Act as they did not involve a public offering.
 
On September 27, 2010, we issued (i) 10,000 general partner units to our general partner in exchange for $100,000 and (ii) 490,000 common units to AIM Midstream Holdings in exchange for $4.9 million. These transactions were exempt from registration under Section 4(2) of the Securities Act as they did not involve a public offering.
 
On November 3, 2010, we issued (i) 14,000 general partner units to our general partner in exchange for $140,000 and (ii) 686,000 common units to AIM Midstream Holdings in exchange for $6.9 million. These transactions were exempt from registration under Section 4(2) of the Securities Act as they did not involve a public offering.

Item 16.   	Exhibits and Financial Schedules.	
 
The following documents are filed as exhibits to this registration statement:

 	 	 	 	 	
Number	 	Description	
 		
 	1	.1*	 	Form of Underwriting Agreement	
 	3	.1**	 	Certificate of Limited Partnership of American Midstream Partners, LP	
 	3	.2**	 	Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP	
 	3	.3	 	Form of Second Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP (Included as Appendix A to the Prospectus)	
 	3	.4**	 	Certificate of Formation of American Midstream GP, LLC	
 	3	.5**	 	Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC	
 	5	.1	 	Form of opinion of Andrews Kurth LLP as to the legality of the securities being registered	
 	8	.1	 	Form of opinion of Andrews Kurth LLP relating to tax matters	
 	10	.1	 	Revolving and Term Loan Credit Agreement, dated as of October 5, 2009, by and among American Midstream, LLC, as the initial borrower, Comerica Bank, as the administrative agent, BBVA Compass Bank, as the documentation agent and Comerica Bank and BBVA Compass Bank as co-lead arrangers.	
 	10	.2	 	First Amendment to Revolving and Term Loan Credit Agreement, dated effective as of October 5, 2009, among American Midstream, LLC, American Midstream Marketing, LLC, American Midstream (Alabama Gathering), LLC, American Midstream (Alabama Intrastate), LLC, American Midstream (Alatenn), LLC, American Midstream (Midla), LLC, American Midstream (Mississippi), LLC, American Midstream (Tennessee River), LLC, American Midstream Onshore Pipelines, LLC, Mid Louisiana Gas Transmission, LLC, American Midstream (Louisiana Intrastate), LLC, American Midstream (Sigco Intrastate), LLC and American Midstream Offshore (Seacrest) LP, as borrowers, the Lenders named therein, and Comerica Bank, as administrative agent.	

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Number	 	Description	
 		
 	10	.3	 	Second Amendment and Waiver to Revolving and Term Loan Credit Agreement, dated July 30, 2010, among American Midstream, LLC, American Midstream Marketing, LLC, American Midstream (Alabama Gathering), LLC, American Midstream (Alabama Intrastate), LLC, American Midstream (Alatenn), LLC, American Midstream (Midla), LLC American Midstream (Mississippi), LLC, American Midstream (Tennessee River), LLC, American Midstream Onshore Pipelines, LLC, Mid Louisiana Gas Transmission, LLC, American Midstream (Louisiana Intrastate), LLC, American Midstream (Sigco Intrastate), LLC And American Midstream Offshore (Seacrest) LP, the Lenders named therein), and Comerica Bank, as administrative agent.	
 	10	.4	 	Employment Agreement, dated June 9, 2011, by and between American Midstream GP, LLC and Brian Bierbach.	
 	10	.5	 	Employment Agreement, dated June 9, 2011, by and between American Midstream GP, LLC and Marty W. Patterson.	
 	10	.6	 	Employment Agreement, dated June 9, 2011, by and between American Midstream GP, LLC and John J. Connor II.	
 	10	.7	 	Amended and Restated American Midstream GP, LLC Long-Term Incentive Plan.	
 	10	.8	 	Form of Phantom Unit Grant under American Midstream GP, LLC Long-Term Incentive Plan.	
 	10	.9	 	Membership Interests Purchase and Sale Agreement, dated as of October 2, 2009, by and between Enbridge Midcoast Energy, L.P. and American Midstream, LLC.	
 	10	.10**†	 	Firm Gas Gathering Agreement, dated as of August 1, 2008, by and between American Midstream Offshore (Seacrest) LP, and Contango Resources Company.	
 	10	.11**	 	Letter Agreement, dated December 10, 2009, between American Midstream Offshore (Seacrest) LP and Contango Operators, Inc.	
 	10	.12**†	 	Base Contract for Sale and Purchase of Natural Gas, dated June 1, 2010, between ExxonMobil Gas & Power Marketing Company and Mid Louisiana Gas Transmission, LLC	
 	10	.13**†	 	Gas Processing Agreement, dated July 14, 2010, by and between American Midstream (Mississippi), LLC and Venture Oil & Gas, Inc.	
 	10	.14	 	Gas Transportation Contract, dated as of November 1, 1997, by and between Midcoast Interstate Transmission, Inc. and the City of Decatur Utilities.	
 	10	.15	 	Amendment No. 1 to Gas Transportation Contract, dated November 1, 2003, by and between Enbridge Pipeline (Alatenn), Inc. and The City of Decatur, Alabama.	
 	10	.16	 	Natural Gas Pipeline Construction and Transportation Agreement, dated effective as of June 28, 2000, by and between Bamagas Company and Calpine Energy Services, L.P.	
 	10	.17	 	First Amendment to Natural Gas Pipeline Construction and Transportation Agreement, dated as of September 1, 2001, by and between Bamagas Company and Calpine Energy Services, L.P.	
 	10	.18	 	Natural Gas Pipeline Construction and Transportation Agreement, dated effective as of June 28, 2000, by and between Bamagas Company and Calpine Energy Services, L.P.	
 	10	.19	 	First Amendment to Natural Gas Pipeline Construction and Transportation Agreement, dated as of September 1, 2001, by and between Bamagas Company and Calpine Energy Services, L.P.	
 	10	.20	 	Agreement, dated as of May 1, 2003, by and between Enbridge Pipelines (AlaTenn), L.L.C. and City of Huntsville.	
 	10	.21	 	Service Agreement, dated September 1, 2008, by and between Enbridge Pipelines (Midla) L.L.C. and Enbridge Marketing (US), LP.	
 	10	.22	 	Service Agreement, dated September 1, 2008, by and between Enbridge Pipelines (Midla) L.L.C. and Enbridge Marketing (US), LP.	
 	10	.23	 	Gas Processing Agreement, dated July 1, 2010, by and between American Midstream, LLC and Enterprise Gas Processing, LLC.	
 	10	.24	 	Gas Processing Agreement, dated November 1, 2010, by and between American Midstream, LLC and Enterprise Gas Processing.	
 	10	.25	 	Gas Processing Agreement, dated April 1, 2011, by and between American Midstream (Louisiana Intrastate), LLC and Enterprise Gas Processing, LLC.	

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Number	 	Description	
 		
 	10	.26	 	Employment Agreement, dated June 8, 2011, by and between American Midstream GP, LLC and Sandra M. Flower.	
 	10	.27	 	Employment Agreement, dated June 9, 2011, by and between American Midstream GP, LLC and William B. Mathews.	
 	10	.28	 	Form of Amendment of Grant of Phantom Units under the American Midstream Partners, LP Long-Term Incentive Plan.	
 	10	.29*	 	Form of Credit Agreement.	
 	21	.1**	 	List of Subsidiaries of American Midstream Partners, LP.	
 	23	.1	 	Consent of PricewaterhouseCoopers LLP.	
 	23	.2	 	Consent of PricewaterhouseCoopers LLP.	
 	23	.3	 	Form of consent of Andrews Kurth LLP (contained in Exhibit 5.1).	
 	23	.4	 	Form of consent of Andrews Kurth LLP (contained in Exhibit 8.1).	
 	24	.1**	 	Powers of Attorney (contained on the signature page to this Registration Statement).	

 

			
*		To be filed by amendment.	
 		
**		Previously filed.	
 		
†		Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Securities and Exchange Commission.	

Item 17.   	Undertakings	
 
The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
 
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.
 
The undersigned registrant hereby undertakes that:
 
(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.
 
(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
 
(3) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or

II-4

Table of Contents

prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.
 
(4) That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:
 
(i) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;
 
(ii) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;
 
(iii) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and
 
(iv) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.
 
The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with American Midstream GP, our general partner, or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to American Midstream GP or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.
 
The undersigned registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.

II-5

Table of Contents

SIGNATURES

Pursuant to the to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on June 9, 2011.

American Midstream Partners, LP

 	By: 	American Midstream GP, LLC
its general partner	

 	By:  	/s/   Brian F. Bierbach	

Name:     Brian F. Bierbach
			
 	Title: 	Chief Executive Officer and President	

II-6

Table of Contents

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed by the following persons in the capacities and the dates indicated.

 	 	 	 	 	 	 	
Signature	 	Title	 	Date	

/s/   Brian F. Bierbach

Brian F. Bierbach	 	Chief Executive Officer and President (Principal Executive Officer) and Director	 	June 9, 2011	
 	 	 	 	 	
*

Sandra M. Flower	 	Vice President of Finance
(Principal Financial Officer and Principal
Accounting Officer)	 	June 9, 2011	
 	 	 	 	 	
*

Robert B. Hellman	 	Director	 	June 9, 2011	
 	 	 	 	 	
*

Matthew P. Carbone	 	Director	 	June 9, 2011	
 	 	 	 	 	
*

Edward O. Diffendal	 	Director	 	June 9, 2011	
 	 	 	 	 	
*

L. Kent Moore	 	Director	 	June 9, 2011	
 	 	 	 	 	
*

David L. Page	 	Director	 	June 9, 2011	
 	 	 	 	 	
*

Gerald A. Tywoniuk	 	Director	 	June 9, 2011	
 	 	 	 	 	 	 	
*By:	 	/s/   Brian F. Bierbach

Brian F. Bierbach
Attorney-in-Fact	 	 	 	 	

II-7

Table of Contents
EXHIBIT INDEX

 	 	 	 	 	
Number	 	Description	
 		
 	1	.1*	 	Form of Underwriting Agreement	
 	3	.1**	 	Certificate of Limited Partnership of American Midstream Partners, LP	
 	3	.2**	 	Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP	
 	3	.3	 	Form of Second Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP (Included as Appendix A to the Prospectus)	
 	3	.4**	 	Certificate of Formation of American Midstream GP, LLC	
 	3	.5**	 	Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC	
 	5	.1	 	Form of opinion of Andrews Kurth LLP as to the legality of the securities being registered	
 	8	.1	 	Form of opinion of Andrews Kurth LLP relating to tax matters	
 	10	.1	 	Revolving and Term Loan Credit Agreement, dated as of October 5, 2009, by and among American Midstream, LLC, as the initial borrower, Comerica Bank, as the administrative agent, BBVA Compass Bank, as the documentation agent and Comerica Bank and BBVA Compass Bank as co-lead arrangers.	
 	10	.2	 	First Amendment to Revolving and Term Loan Credit Agreement, dated effective as of October 5, 2009, among American Midstream, LLC, American Midstream Marketing, LLC, American Midstream (Alabama Gathering), LLC, American Midstream (Alabama Intrastate), LLC, American Midstream (Alatenn), LLC, American Midstream (Midla), LLC, American Midstream (Mississippi), LLC, American Midstream (Tennessee River), LLC, American Midstream Onshore Pipelines, LLC, Mid Louisiana Gas Transmission, LLC, American Midstream (Louisiana Intrastate), LLC, American Midstream (Sigco Intrastate), LLC and American Midstream Offshore (Seacrest) LP, as borrowers, the Lenders named therein, and Comerica Bank, as administrative agent.	
 	10	.3	 	Second Amendment and Waiver to Revolving and Term Loan Credit Agreement, dated July 30, 2010, among American Midstream, LLC, American Midstream Marketing, LLC, American Midstream (Alabama Gathering), LLC, American Midstream (Alabama Intrastate), LLC, American Midstream (Alatenn), LLC, American Midstream (Midla), LLC American Midstream (Mississippi), LLC, American Midstream (Tennessee River), LLC, American Midstream Onshore Pipelines, LLC, Mid Louisiana Gas Transmission, LLC, American Midstream (Louisiana Intrastate), LLC, American Midstream (Sigco Intrastate), LLC And American Midstream Offshore (Seacrest) LP, the Lenders named therein), and Comerica Bank, as administrative agent.	
 	10	.4	 	Employment Agreement, dated July 9, by and between American Midstream GP, LLC and Brian Bierbach.	
 	10	.5	 	Employment Agreement, dated July 9, by and between American Midstream GP, LLC and Marty W. Patterson.	
 	10	.6	 	Employment Agreement, dated July 9, by and between American Midstream GP, LLC and John J. Connor II.	
 	10	.7	 	Amended and Restated American Midstream GP, LLC Long-Term Incentive Plan.	
 	10	.8	 	Form of Phantom Unit Grant under American Midstream GP, LLC Long-Term Incentive Plan.	
 	10	.9	 	Membership Interests Purchase and Sale Agreement, dated as of October 2, 2009, by and between Enbridge Midcoast Energy, L.P. and American Midstream, LLC.	
 	10	.10**†	 	Firm Gas Gathering Agreement, dated as of August 1, 2008, by and between American Midstream Offshore (Seacrest) LP, and Contango Resources Company.	
 	10	.11**	 	Letter Agreement, dated December 10, 2009, between American Midstream Offshore (Seacrest) LP and Contango Operators, Inc.	
 	10	.12**†	 	Base Contract for Sale and Purchase of Natural Gas, dated June 1, 2010, between ExxonMobil Gas & Power Marketing Company and Mid Louisiana Gas Transmission, LLC	
 	10	.13**†	 	Gas Processing Agreement, dated July 14, 2010, by and between American Midstream (Mississippi), LLC and Venture Oil & Gas, Inc.	

Table of Contents

 	 	 	 	 	
Number	 	Description	
 		
 	10	.14	 	Gas Transportation Contract, dated as of November 1, 1997, by and between Midcoast Interstate Transmission, Inc. and the City of Decatur Utilities.	
 	10	.15	 	Amendment No. 1 to Gas Transportation Contract, dated November 1, 2003, by and between Enbridge Pipeline (Alatenn), Inc. and The City of Decatur, Alabama.	
 	10	.16	 	Natural Gas Pipeline Construction and Transportation Agreement, dated effective as of June 28, 2000, by and between Bamagas Company and Calpine Energy Services, L.P.	
 	10	.17	 	First Amendment to Natural Gas Pipeline Construction and Transportation Agreement, dated as of September 1, 2001, by and between Bamagas Company and Calpine Energy Services, L.P.	
 	10	.18	 	Natural Gas Pipeline Construction and Transportation Agreement, dated effective as of June 28, 2000, by and between Bamagas Company and Calpine Energy Services, L.P.	
 	10	.19	 	First Amendment to Natural Gas Pipeline Construction and Transportation Agreement, dated as of September 1, 2001, by and between Bamagas Company and Calpine Energy Services, L.P.	
 	10	.20	 	Agreement, dated as of May 1, 2003, by and between Enbridge Pipelines (AlaTenn), L.L.C. and City of Huntsville.	
 	10	.21	 	Service Agreement, dated September 1, 2008, by and between Enbridge Pipelines (Midla) L.L.C. and Enbridge Marketing (US), LP.	
 	10	.22	 	Service Agreement, dated September 1, 2008, by and between Enbridge Pipelines (Midla) L.L.C. and Enbridge Marketing (US), LP.	
 	10	.23	 	Gas Processing Agreement, dated July 1, 2010, by and between American Midstream, LLC and Enterprise Gas Processing, LLC.	
 	10	.24	 	Gas Processing Agreement, dated November 1, 2010, by and between American Midstream, LLC and Enterprise Gas Processing.	
 	10	.25	 	Gas Processing Agreement, dated April 1, 2011, by and between American Midstream (Louisiana Intrastate), LLC and Enterprise Gas Processing, LLC.	
 	10	.26	 	Employment Agreement, dated June 8, 2011, by and between American Midstream GP, LLC and Sandra M. Flower.	
 	10	.27	 	Employment Agreement, dated June 9, 2011, by and between American Midstream GP, LLC and William B. Mathews.	
 	10	.28	 	Form of Amendment of Grant of Phantom Units under the American Midstream Partners LP Long-Term Incentive Plan.	
 	10	.29*	 	Form of Credit Agreement.	
 	21	.1**	 	List of Subsidiaries of American Midstream Partners, LP.	
 	23	.1	 	Consent of PricewaterhouseCoopers LLP.	
 	23	.2	 	Consent of PricewaterhouseCoopers LLP.	
 	23	.3	 	Form of consent of Andrews Kurth LLP (contained in Exhibit 5.1).	
 	23	.4	 	Form of consent of Andrews Kurth LLP (contained in Exhibit 8.1).	
 	24	.1**	 	Powers of Attorney (contained on the signature page to this Registration Statement).	

 

			
*		To be filed by amendment.	
 		
**		Previously filed.	
 		
†		Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Securities and Exchange Commission.	

EXHIBIT 5.1

 	 	600 Travis, Suite 4200	
 	 	Houston, Texas 77002	
	 	713.220.4200 Phone
713.220.4285 Fax
andrewskurth.com	

[ Date ]
American Midstream Partners, LP
1614 15th Street, Suite 300
Denver, Colorado 80202
Ladies and Gentlemen:
     We have acted as special counsel to American Midstream Partners, LP, a Delaware limited partnership (the “ Partnership ”), in connection with the registration under the Securities Act of 1933, as amended (the “ Securities Act ”), of the offering and sale by the Partnership of up to an aggregate of    common units representing limited partner interests in the Partnership (the “ Common Units ”).
     As the basis for the opinion hereinafter expressed, we have examined such statutes, including the Delaware Revised Uniform Limited Partnership Act (the “ Delaware Act ”), regulations, corporate records and documents, certificates of corporate and public officials, and other instruments and documents as we have deemed necessary or advisable for the purposes of this opinion. In making our examination, we have assumed that all signatures on documents examined by us are genuine, the authenticity of all documents submitted to us as originals and the conformity with the original documents of all documents submitted to us as certified, conformed or photostatic copies.
     Based on the foregoing and on such legal considerations as we deem relevant, we are of the opinion that the Common Units, when issued and delivered on behalf of the Partnership against payment therefor as described in the Partnership’s Registration Statement on Form S-1 (Commission File No. 333-173191), as amended, relating to the Common Units (the “ Registration Statement ”), will be duly authorized, validly issued, fully paid and non-assessable.
     We express no opinion other than as to the federal laws of the United States of America and the Delaware Act (including the statutory provisions, all applicable provisions of the Delaware constitution and reported judicial decisions interpreting the foregoing). We hereby consent to the reference to us under the heading “Validity of the Common Units” in the prospectus forming a part of the Registration Statement and to the filing of this opinion as an exhibit to the Registration Statement. In giving this consent, we do not thereby admit that we are

 

American Midstream Partners, LP
[ Date ]
Page 2
included in the category of persons whose consent is required under Section 7 of the Securities Act or the rules and regulations of the Securities and Exchange Commission issued thereunder.
Very truly yours,

EXHIBIT 8.1

 	 	600 Travis, Suite 4200	
 	 	Houston, Texas 77002	
	 	713.220.4200 Phone
713.220.4285 Fax
andrewskurth.com	

[ Date ]
American Midstream Partners, LP
1614 15th Street, Suite 300
Denver, Colorado 80202

      Re:	 	Registration Statement on Form S-1	
Gentlemen:
     We have acted as special counsel to American Midstream Partners, LP, a Delaware limited partnership (the “ Partnership ”), in connection with the offering and sale (the “ Offering ”) of common units representing limited partner interests in the Partnership (the “ Common Units ”). We have also participated in the preparation of a registration statement on Form S-1 and the amendments thereto (Registration No. 333-173191) (such registration statement together with any amendments, the “ Registration Statement ”) to which this opinion is an exhibit. In connection therewith, we have participated in the preparation of the discussion set forth under the caption “Material Federal Income Tax Consequences” (the “ Discussion ”) in the Registration Statement.
     The Discussion, subject to the qualifications and assumptions stated in the Discussion and the limitations and qualifications set forth herein, constitutes our opinion as to the material United States federal income tax consequences for purchasers of the Common Units pursuant to the Offering.
     This opinion letter is limited to the matters set forth herein, and no opinions are intended to be implied or may be inferred beyond those expressly stated herein. Our opinion is rendered as of the date hereof and we assume no obligation to update or supplement this opinion or any matter related to this opinion to reflect any change of fact, circumstances, or law after the

 

American Midstream Partners, LP
[ Date ]
Page 2
effective date of the Registration Statement. In addition, our opinion is based on the assumption that the matter will be properly presented to the applicable court.
     Furthermore, our opinion is not binding on the Internal Revenue Service or a court. In addition, we must note that our opinion represents merely our best legal judgment on the matters presented and that others may disagree with our conclusion. There can be no assurance that the Internal Revenue Service will not take a contrary position or that a court would agree with our opinion if litigated.
     We hereby consent to the filing of this opinion as an exhibit to the Registration Statement and to the references to our firm and this opinion contained in the Discussion. In giving this consent, we do not admit that we are “experts” under the Securities Act of 1933, as amended, or under the rules and regulations of the Securities and Exchange Commission relating thereto, with respect to any part of the Registration Statement, including this exhibit to the Registration Statement.
Very truly yours,

Exhibit 10.1
EXECUTION VERSION

Revolving and Term Loan Credit Agreement
Dated as of October 5, 2009
American Midstream, LLC,
As the initial Borrower,
Comerica Bank,
As the Administrative Agent,
BBVA Compass Bank,
As the Documentation Agent,
And
Comerica Bank and BBVA Compass Bank,
As Co-Lead Arrangers

   

 

TABLE OF CONTENTS
 	 	 	 	 	
 	 	Page	
1. DEFINITIONS	 	 	1	 	
1.1 Certain Defined Terms	 	 	1	 	
 	 	 	 	 	
2. REVOLVING CREDIT	 	 	29	 	
2.1 Commitment	 	 	29	 	
2.2 Accrual of Interest and Maturity; Evidence of Indebtedness	 	 	30	 	
2.3 Requests for and Refundings and Conversions of Advances	 	 	31	 	
2.4 Disbursement of Advances	 	 	32	 	
2.5 Swing Line	 	 	34	 	
2.6 Interest Payments; Default Interest	 	 	39	 	
2.7 Optional Prepayments	 	 	40	 	
2.8 Base Rate Advance in Absence of Election or Upon Default	 	 	41	 	
2.9 Revolving Credit Facility Fee	 	 	41	 	
2.10 Mandatory Repayment of Revolving Credit Advances	 	 	42	 	
2.11 Optional Reduction or Termination of Revolving Credit Aggregate Commitment	 	 	43	 	
2.12 Use of Proceeds of Advances	 	 	44	 	
 	 	 	 	 	
3. LETTERS OF CREDIT	 	 	44	 	
3.1 Letters of Credit	 	 	44	 	
3.2 Conditions to Issuance	 	 	45	 	
3.3 Notice	 	 	46	 	
3.4 Letter of Credit Fees; Increased Costs	 	 	46	 	
3.5 Other Fees	 	 	47	 	
3.6 Participation Interests in and Drawings and Demands for Payment Under Letters of Credit	 	 	48	 	
3.7 Obligations Irrevocable	 	 	50	 	
3.8 Risk Under Letters of Credit	 	 	51	 	
3.9 Indemnification	 	 	52	 	
3.10 Right of Reimbursement	 	 	53	 	
 	 	 	 	 	
4. TERM LOAN	 	 	53	 	
4.1 Term Loan	 	 	53	 	
4.2 Accrual of Interest and Maturity; Evidence of Indebtedness	 	 	54	 	
4.3 Repayment of Principal	 	 	54	 	
4.4 Term Loan Rate Requests; Refundings and Conversions of Advances of Term Loan	 	 	55	 	
4.5 Base Rate Advance in Absence of Election or Upon Default	 	 	56	 	
4.6 Interest Payments; Default Interest	 	 	56	 	
4.7 Optional Prepayment of the Term Loan	 	 	57	 	
4.8 Mandatory Prepayment of Term Loan	 	 	58	 	
4.9 Use of Proceeds	 	 	59	 	
4.10 Term Loan Facility Fee	 	 	59	 	
 -i- 

 

TABLE OF CONTENTS
(Continued)
 	 	 	 	 	
 	 	Page	
5. CONDITIONS	 	 	59	 	
5.1 Conditions of Initial Advances	 	 	60	 	
5.2 Continuing Conditions	 	 	64	 	
 	 	 	 	 	
6. REPRESENTATIONS AND WARRANTIES	 	 	64	 	
6.1 Organizational Authority	 	 	65	 	
6.2 Due Authorization	 	 	65	 	
6.3 Good Title; Leases; Assets; No Liens	 	 	65	 	
6.4 Taxes	 	 	67	 	
6.5 No Defaults	 	 	67	 	
6.6 Enforceability of Agreement and Loan Documents	 	 	67	 	
6.7 Compliance with Laws	 	 	68	 	
6.8 Non-contravention	 	 	68	 	
6.9 Litigation	 	 	68	 	
6.10 Consents, Approvals and Filings, Etc.	 	 	68	 	
6.11 Agreements Affecting Financial Condition	 	 	69	 	
6.12 No Investment Company or Margin Stock	 	 	69	 	
6.13 ERISA	 	 	69	 	
6.14 Conditions Affecting Business or Properties	 	 	70	 	
6.15 Environmental and Safety Matters	 	 	70	 	
6.16 Subsidiaries	 	 	70	 	
6.17 Management Agreements	 	 	70	 	
6.18 Material Contracts	 	 	70	 	
6.19 Franchises, Patents, Copyrights, Trade Names, Etc.	 	 	71	 	
6.20 Capital Structure	 	 	71	 	
6.21 Accuracy of Information	 	 	71	 	
6.22 Solvency	 	 	71	 	
6.23 Employee Matters	 	 	72	 	
6.24 No Misrepresentation	 	 	72	 	
6.25 Corporate Documents and Corporate Existence	 	 	72	 	
6.26 Acquisition Documents	 	 	72	 	
6.27 State and Federal Regulation	 	 	73	 	
6.28 Supplemental Schedules	 	 	74	 	
 	 	 	 	 	
7. AFFIRMATIVE COVENANTS	 	 	74	 	
7.1 Financial Statements	 	 	74	 	
7.2 Certificates; Other Information	 	 	75	 	
7.3 Payment of Obligations	 	 	76	 	
7.4 Conduct of Business and Maintenance of Existence; Compliance with Laws	 	 	76	 	
7.5 Maintenance of Property; Insurance	 	 	77	 	
7.6 Inspection of Property; Books and Records, Discussions	 	 	77	 	
7.7 Notices	 	 	78	 	
7.8 Hazardous Material Laws	 	 	79	 	
7.9 Financial Covenants	 	 	80	 	
 -ii- 

 

TABLE OF CONTENTS
(Continued)
 	 	 	 	 	
 	 	Page	
7.10 Governmental and Other Approvals	 	 	80	 	
7.11 Compliance with ERISA; ERISA Notices	 	 	80	 	
7.12 Defense of Collateral	 	 	81	 	
7.13 Future Subsidiaries; Additional Collateral	 	 	81	 	
7.14 Accounts	 	 	82	 	
7.15 Use of Proceeds	 	 	83	 	
7.16 Hedging Transaction	 	 	83	 	
7.17 Further Assurances and Information	 	 	83	 	
7.18 Notices Relating to Acquisition	 	 	83	 	
7.19 Required Life Insurance	 	 	84	 	
7.20 Enforcement of Material Contracts	 	 	84	 	
7.21 Projections	 	 	84	 	
7.22 Bamagas	 	 	84	 	
 	 	 	 	 	
8. NEGATIVE COVENANTS	 	 	84	 	
8.1 Limitation on Debt	 	 	84	 	
8.2 Limitation on Liens	 	 	85	 	
8.3 Acquisitions	 	 	87	 	
8.4 Limitation on Mergers, Dissolution or Sale of Assets	 	 	87	 	
8.5 Restricted Payments	 	 	88	 	
8.6 Limitation on Investments, Loans and Advances	 	 	88	 	
8.7 Transactions with Affiliates	 	 	90	 	
8.8 Sale-Leaseback Transactions	 	 	90	 	
8.9 Limitations on Other Restrictions	 	 	90	 	
8.10 Reserved	 	 	90	 	
8.11 Reserved	 	 	90	 	
8.12 Modification of Certain Agreements	 	 	90	 	
8.13 Management Fees	 	 	90	 	
8.14 Fiscal Year	 	 	90	 	
8.15 Acquisition Documents	 	 	91	 	
8.16 State and FERC Regulatory Authority	 	 	91	 	
 	 	 	 	 	
9. DEFAULTS	 	 	91	 	
9.1 Events of Default	 	 	91	 	
9.2 Exercise of Remedies	 	 	93	 	
9.3 Rights Cumulative	 	 	94	 	
9.4 Waiver by the Borrowers of Certain Laws	 	 	94	 	
9.5 Waiver of Defaults	 	 	94	 	
9.6 Set Off	 	 	94	 	
 	 	 	 	 	
10. PAYMENTS, RECOVERIES AND COLLECTIONS	 	 	95	 	
10.1 Payment Procedure	 	 	95	 	
10.2 Application of Proceeds of Collateral	 	 	96	 	
10.3 Pro-rata Recovery	 	 	97	 	
 -iii- 

 

TABLE OF CONTENTS
(Continued)
 	 	 	 	 	
 	 	Page	
10.4 Treatment of a Defaulting Lender	 	 	97	 	
 	 	 	 	 	
11. CHANGES IN LAW OR CIRCUMSTANCES; INCREASED COSTS	 	 	98	 	
11.1 Reimbursement of Prepayment Costs	 	 	98	 	
11.2 Eurodollar Lending Office	 	 	99	 	
11.3 Circumstances Affecting LIBOR Rate Availability	 	 	99	 	
11.4 Laws Affecting LIBOR Rate Availability	 	 	100	 	
11.5 Increased Cost of Advances Carried at the LIBOR Rate	 	 	100	 	
11.6 Capital Adequacy and Other Increased Costs	 	 	101	 	
11.7 Right of Lenders to Fund through Branches and Affiliates	 	 	102	 	
11.8 Margin Adjustment	 	 	102	 	
 	 	 	 	 	
12. THE AGENT	 	 	103	 	
12.1 Appointment of the Administrative Agent	 	 	103	 	
12.2 Deposit Account with the Administrative Agent or any Lender	 	 	103	 	
12.3 Scope of the Administrative Agent’s Duties	 	 	104	 	
12.4 Successor Agent	 	 	104	 	
12.5 Credit Decisions	 	 	105	 	
12.6 Authority of the Administrative Agent to Enforce This Agreement	 	 	105	 	
12.7 Indemnification of the Administrative Agent	 	 	105	 	
12.8 Knowledge of Default	 	 	106	 	
12.9 The Administrative Agent’s Authorization; Action by Lenders	 	 	106	 	
12.10 Enforcement Actions by the Administrative Agent	 	 	107	 	
12.11 Collateral Matters	 	 	107	 	
12.12 The Administrative Agents in their Individual Capacities	 	 	108	 	
12.13 The Administrative Agent’s Fees	 	 	108	 	
12.14 Documentation Administrative Agent or other Titles	 	 	108	 	
12.15 No Reliance on the Administrative Agent’s Customer Identification Program	 	 	108	 	
 	 	 	 	 	
13. MISCELLANEOUS	 	 	109	 	
13.1 Accounting Principles	 	 	109	 	
13.2 Consent to Jurisdiction	 	 	109	 	
13.3 GOVERNING LAW	 	 	110	 	
13.4 Interest	 	 	110	 	
13.5 Closing Costs and Other Costs; Indemnification	 	 	110	 	
13.6 Notices	 	 	112	 	
13.7 Reserved	 	 	113	 	
13.8 Successors and Assigns; Participations; Assignments	 	 	113	 	
13.9 Counterparts	 	 	116	 	
13.10 Amendment and Waiver	 	 	116	 	
13.11 Confidentiality	 	 	118	 	
13.12 Substitution or Removal of Lenders	 	 	118	 	
13.13 Withholding Taxes	 	 	120	 	
13.14 Taxes and Fees	 	 	121	 	
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TABLE OF CONTENTS
(Continued)
 	 	 	 	 	
 	 	Page	
13.15 WAIVER OF JURY TRIAL	 	 	121	 	
13.16 USA Patriot Act Notice	 	 	122	 	
13.17 Complete Agreement; Conflicts	 	 	122	 	
13.18 Severability	 	 	122	 	
13.19 Table of Contents and Headings; Section References	 	 	122	 	
13.20 Construction of Certain Provisions	 	 	123	 	
13.21 Independence of Covenants	 	 	123	 	
13.22 Electronic Transmissions	 	 	123	 	
13.23 Advertisements	 	 	123	 	
13.24 Reliance on and Survival of Provisions	 	 	123	 	
13.25 Joint and Several Liability	 	 	124	 	
13.26 Administrative Borrower as Agent for the Borrowers	 	 	126	 	
EXHIBITS

A	 	Form of Request for Revolving Credit Advance	
B	 	Form of Revolving Credit Note	
C	 	Form of Swing Line Note	
D	 	Form of Request for Swing Line Advance	
E	 	Form of Notice of Letters of Credit	
F	 	Form of Security Agreement	
G	 	Form of Assignment Agreement	
H	 	Form of Guaranty	
I	 	Form of Covenant Compliance Report	
J	 	Form of Term Loan Note	
K	 	Form of Term Loan Rate Request	
L	 	Form of Swing Line Participation Certificate	
M	 	Form of Joinder to Credit Agreement	
Schedules

1.1	 	Pricing Matrix	
1.2	 	Revolving Credit Percentages and Allocations	
5.1(c)(i)(D)	 	Related Documentation	
5.1(c)(iii)	 	Effective Financing Statements	
6.3(b)	 	Pipeline Systems and other Real Property	
6.4	 	Taxes	
6.7	 	Compliance with Laws	
6.9	 	Litigation	
6.10	 	Consents, Approvals and Filings, Etc.	
6.13	 	Pension Plans	
6.15	 	Environmental and Safety Matters	
6.16	 	Subsidiaries	
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TABLE OF CONTENTS
(Continued)

 	 	 	Page	
6.17	 	Management and Employment Agreements	 	 	
6.18	 	Material Contracts	 	 	
6.19	 	Trade Names	 	 	
6.20	 	Equity Interests	 	 	
6.23	 	Union Agreements	 	 	
6.25	 	Compliance Information	 	 	
6.27(a)	 	Interstate Pipeline Complaints, Investigations and Proceedings	 	 	
6.27(b)	 	Intrastate Pipeline Complaints, Investigations and Proceedings	 	 	
8.1	 	Debt	 	 	
8.2	 	Liens	 	 	
8.6	 	Investments, Loans and Advances	 	 	
8.7	 	Transactions with Affiliates	 	 	
13.6	 	Notices	 	 	
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REVOLVING CREDIT AND TERM LOAN AGREEMENT
     This Revolving Credit and Term Loan Agreement (“ Agreement ”) is made as of the 5 th day of October, 2009, by and among the financial institutions from time to time signatory hereto (individually a “ Lender ,” and any and all such financial institutions collectively the “ Lenders ”), Comerica Bank, as administrative agent for the Lenders (in such capacity, the “ Administrative Agent ”), Co-Lead Arranger and Syndication Administrative Agent and Compass Bank, as Documentation Agent and Co-Lead Arranger, and American Midstream, LLC (together with any and all other Persons executing a Joinder, collectively the “ Borrowers ” and each, individually, a “ Borrower ”).
RECITALS
     A. The Borrowers have requested that the Lenders extend to them credit and letters of credit on the terms and conditions set forth herein.
     B. The Lenders are prepared to extend such credit as aforesaid, but only on the terms and conditions set forth in this Agreement.
     NOW THEREFORE, in consideration of the covenants contained herein, the Borrowers, the Lenders, and the Administrative Agent agree as follows:
1. DEFINITIONS.
     1.1 Certain Defined Terms . For the purposes of this Agreement the following terms will have the following meanings:
     “ Account(s) ” means any account or account receivable as defined under the UCC, including without limitation, with respect to any Person, any right of such Person to payment for goods sold or leased or for services rendered.
     “ Account Control Agreement(s) ” means those certain account control agreements, or similar agreements that are delivered pursuant to Section 7.14 of this Agreement or otherwise, as the same may be amended, restated or otherwise modified from time to time.
     “ Acquisition ” means the acquisition of certain Pipeline Systems, other Real Property and other properties pursuant to the terms and conditions of the Acquisition Documents.
     “ Acquisition Documents ” means (a) the Purchase and Sale Agreement and (b) all bills of sale, assignments, agreements, instruments and documents executed and delivered in connection therewith, as amended.
     “ Acquisition Properties ” means the Equity Interests, the Pipeline Systems, other Real Property and other properties acquired by the Administrative Borrower or any of its Subsidiaries pursuant to the Acquisition Documents.
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     “ Advance(s) ” means, as the context may indicate, a borrowing requested by the Administrative Borrower, and made by the Revolving Credit Lenders under Section 2.1 hereof, the Term Loan Lenders under Section 4.1 hereof or the Swing Line Lender under Section 2.5 hereof, including without limitation any re-advance, refunding or conversion of such borrowing pursuant to Section 2.3 , 2.5 or 4.4 hereof, and any advance deemed to have been made in respect of a Letter of Credit under Section 3.6(c) hereof, and shall include, as applicable, a Eurodollar-based Advance, a Base Rate Advance and a Quoted Rate Advance.
     “ Administrative Agent ” has the meaning set forth in the preamble, and include any successor agents appointed in accordance with Section 12.4 hereof.
     “ Administrative Agent’s Correspondent ” means for Eurodollar-based Advances, the Administrative Agent’s Grand Cayman Branch (or for the account of said branch office, at the Administrative Agent’s main office in Detroit, Michigan , United States).
     “ Administrative Borrower ” means American Midstream, LLC, a Delaware limited liability company, acting in its capacity as borrowing agent and attorney-in-fact for the Borrowers pursuant to Section 13.26 hereof.
     “ Advisory Services Agreement ” means that certain Advisory Services Agreement dated October 2, 2009, by and between the Administrative Borrower, American Infrastructure MLP Management, L.L.C., a Delaware limited liability company, American Infrastructure MLP PE Management, L.L.C., a Delaware limited liability company, and American Infrastructure MLP Associates Management, L.L.C., a Delaware limited liability company.
     “ Affected Lender ” has the meaning set forth in Section 13.12 hereof.
     “ Affiliate ” means, with respect to any Person, any other Person directly or indirectly controlling (including but not limited to all directors and officers of such Person), controlled by, or under direct or indirect common control with such Person. A Person shall be deemed to control another Person for the purposes of this definition if such Person possesses, directly or indirectly, the power (i) to vote 50% or more of the Equity Interests having ordinary voting power for the election of directors or managers of such other Person or (ii) to direct or cause the direction of the management and policies of such other Person, whether through the ownership of voting securities, by contract or otherwise. The term “ Affiliate ” does not include the holders of Equity Interests in the Ultimate Parent.
     “ Applicable Fee Percentage ” means, as of any date of determination thereof, the applicable percentage used to calculate certain of the fees due and payable hereunder, determined by reference to the appropriate columns in the Pricing Matrix attached to this Agreement as Schedule 1.1 .
     “ Applicable Insolvency Laws ” has the meaning ascribed to such term in Section 13.25(g) hereof.
     “ Applicable Interest Rate ” means, (i) with respect to each Revolving Credit Advance and Term Loan Advance, the Eurodollar-based Rate or the Base Rate, and (ii) with respect to each Swing Line Advance, the Base Rate or, if made available to the Borrowers by the Swing Line
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Lender at its option, the Quoted Rate, in each case as selected by the Administrative Borrower from time to time subject to the terms and conditions of this Agreement.
     “ Applicable Margin ” means, as of any date of determination thereof, the applicable interest rate margin, determined by reference to the appropriate columns in the Pricing Matrix attached to this Agreement as Schedule 1.1 , such Applicable Margin to be adjusted solely as specified in Section 11.8 hereof.
     “ Asset Sale ” means the sale, transfer or other disposition by any Credit Party of any asset (other than the sale or transfer of less than one hundred percent (100%) of the Equity Interests of any Subsidiary) to any Person (other than to a Borrower or a Guarantor), and other than the Permitted Sale/Leaseback Transactions.
     “ Assignment Agreement ” means an Assignment Agreement substantially in the form of Exhibit G hereto, as amended, restated or otherwise modified from time to time.
     “ Authorized Signer ” means each person who has been authorized by the Administrative Borrower to execute and deliver any requests for Advances hereunder pursuant to a written authorization delivered to the Administrative Agent and whose signature card or incumbency certificate has been received by the Administrative Agent.
     “ Bamagas ” means Enbridge Pipelines (Bamagas Intrastate) L.L.C., a Delaware limited liability company.
     “ Bankruptcy Code ” means Title 11 of the United States Code and the rules promulgated thereunder.
     “ Base Rate ” means for any day, that rate of interest which is equal to the Applicable Margin plus the greater of (i) the Daily Adjusting LIBOR Rate and (ii) the Prime-based Rate (being that rate of interest which is equal to the greater of (A) the Prime Rate and (B) an interest rate per annum equal to the Federal Funds Effective Rate in effect on such day, plus one percent (1.0%)).
     “ Base Rate Advance ” means an Advance which bears interest at the Base Rate.
     “ Borrower ” and “ Borrowers ” have the meanings set forth in the preamble to this Agreement.
     “ Business Day ” means any day other than a Saturday or a Sunday on which commercial banks are open for domestic and international business (including dealings in foreign exchange) in Detroit, Michigan and New York, New York, and in the case of a Business Day which relates to a Eurodollar-based Advance, on which dealings are carried on in the London interbank Eurodollar market.
     “ Capitalized Lease ” means, as applied to any Person, any lease of any property (whether real, personal or mixed) with respect to which the discounted present value of the rental obligations of such Person as lessee thereunder, in conformity with GAAP, is required to be capitalized on the balance sheet of that Person.
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     “ Change of Control ” means an event or series of events whereby (i) the Ultimate Parent shall cease to control, directly or indirectly, more than 60% on a fully diluted basis of the aggregate issued and outstanding voting stock (or comparable voting interests) of the Borrowers, (ii) the Administrative Borrower shall cease to control, directly or indirectly, more than 100% on a fully diluted basis of the aggregate issued and outstanding voting stock (or comparable voting interests) of the each other Borrower, or (iii) the Ultimate Parent shall fail to be able, either jointly or severally, to elect a controlling majority of the Board of Managers of the general partner of the sole member of the Administrative Borrower.
     “ CIP Regulations ” has the meaning ascribed to such term in Section 12.15 hereof.
     “ Closing Date ” means the date of the execution of this Agreement by the Lenders, the Administrative Agent and the Administrative Borrower.
     “ Collateral ” means all property, Equity Interests and rights in which a security interest, mortgage, lien or other encumbrance for the benefit of the Lenders is or has been granted or arises or has arisen, under or in connection with this Agreement, the other Loan Documents, or otherwise to secure the Indebtedness.
     “ Collateral Assignment ” means an assignment in form and substance satisfactory to the Administrative Agent and approved by the applicable insurance company, pursuant to which one or more of the Borrowers assigns to the Administrative Agent, for the pro rata benefit of the Lenders, its interest in the key man life insurance policy obtained pursuant to Section 7.19 hereof.
     “ Collateral Documents ” means the Security Agreement, the Pledge Agreements, the Mortgages, the Account Control Agreements, the Collateral Assignment and all other security documents (and any joinders thereto) executed by any Credit Party in favor of the Administrative Agent on or after the Effective Date, in connection with any of the foregoing collateral documents, in each case, as such collateral documents may be amended or otherwise modified from time to time.
     “ Comerica Bank ” means Comerica Bank and its successors or assigns.
     “ Consent ” has the meaning ascribed to such term in Section 5.1(a) hereof.
     “ Consolidated ” (or “ consolidated ”) or “ Consolidating ” (or “ consolidating ”) means, when used with reference to any financial term in this Agreement, the aggregate for two or more Persons of the amounts signified by such term for all such Persons determined on a consolidated (or consolidating) basis in accordance with GAAP, applied on a consistent basis. Unless otherwise specified herein, “ Consolidated ” and “ Consolidating ” shall refer to the Administrative Borrower and its Subsidiaries, determined on a Consolidated or Consolidating basis.
     “ Consolidated Amortization Expense ” means, for any Test Period, the amortization expense of the Administrative Borrower and its Subsidiaries for such Test Period determined on a consolidated basis in accordance with GAAP.
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     “ Consolidated Depreciation Expense ” means, for any Test Period, the depreciation expense of the Administrative Borrower and its Subsidiaries for such Test Period determined on a consolidated basis in accordance with GAAP.
     “ Consolidated EBITDA ” means, for any Test Period, Consolidated Net Income for such Test Period, adjusted by (x) adding thereto , in each case only to the extent (and in the same proportion) deducted in determining Consolidated Net Income:
     (a) Consolidated Interest Expense for such Test Period,
     (b) Consolidated Tax Expense for such Test Period,
     (c) Consolidated Depreciation Expense for such Test Period,
     (d) Consolidated Amortization Expense for such Test Period,
     (e) (i) expenses related to any initial public offering with respect to the Parent and other extraordinary expenses, (ii) audit expenses for the Fiscal Years ended December 31, 2007, and December 31, 2008, and any costs associated with the opening balance sheet valuation of the Administrative Borrower and its Subsidiaries, (iii) Fees, (iv) transaction-related expenses with respect to the Credit Agreement and the Acquisition and (v) the premium paid for the first year of insurance for environmental liability being purchased on or about the Effective Date,
     (f) subject to the approval of the Administrative Agent in its reasonable discretion, the aggregate amount of all other non-cash charges and “other expenses” (determined in accordance with GAAP) reducing Consolidated Net Income (excluding any non-cash charge that results in an accrual of a reserve for cash charges in any future period) for such Test Period, and
(y) subject to the approval of the Administrative Agent in its sole discretion, subtracting therefrom the aggregate amount of all non-cash items and “other income” (determined in accordance with GAAP) increasing Consolidated Net Income (other than the accrual of revenue or recording of receivables in the ordinary course of business) for such Test Period.
     “ Consolidated Interest Expense ” means, for any Test Period, the total consolidated interest expense of the Administrative Borrower and its Subsidiaries for such Test Period net of gross interest income of the Administrative Borrower and its Subsidiaries, in each case determined on a consolidated basis in accordance with GAAP plus (without duplication) to the extent not already included in such total consolidated interest expense:
     (a) imputed interest on Debt attributable to Capitalized Leases and sale and leaseback transactions of the Administrative Borrower or any of its Subsidiaries for such Test Period;
     (b) commissions, discounts and other fees and charges owed by the Administrative Borrower or any of its Subsidiaries with respect to letters of credit securing financial obligations and bankers’ acceptances for such Test Period;
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     (c) amortization of debt issuance costs, debt discount or premium and other financing fees and expenses, but not including any amendment fees less than $250,000, incurred by the Administrative Borrower or any of its Subsidiaries for such Test Period; and
     (d) the interest portion of any deferred payment obligations of the Administrative Borrower or any of its Subsidiaries for such Test Period.
     “ Consolidated Net Income ” means, for any Test Period, the consolidated net income of the Administrative Borrower and its Subsidiaries (excluding extraordinary gains and extraordinary losses) for such Test Period determined in accordance with GAAP.
     “ Consolidated Tax Expense ” means, for any Test Period, the tax expense of the Administrative Borrower and its Subsidiaries, for such Test Period, determined on a consolidated basis in accordance with GAAP.
     “ Contractual Obligation ” means, as to any Person, any provision of any security issued by such Person or of any material agreement, instrument or other undertaking to which such Person is a party or by which it or any of its property is bound.
     “ Covenant Compliance Report ” means the report to be furnished by the Administrative Borrower to the Administrative Agent pursuant to Section 7.2(a) hereof, substantially in the form attached hereto as Exhibit I and certified by a Responsible Officer of the Administrative Borrower, in which report the Administrative Borrower shall set forth the information specified therein and which shall include a statement of then applicable level for the Applicable Margin and Applicable Fee Percentages as specified in Schedule 1.1 attached to this Agreement.
     “ Credit Parties ” means the Borrowers and the Guarantors and “ Credit Party ” means any one of them, as the context indicates or otherwise requires.
     “ Daily Adjusting LIBOR Rate ” means for any day a per annum interest rate which is equal to the sum of one percent (1%) plus the quotient of the following:
     (a) the LIBOR Rate;
divided by
     (b) a percentage (expressed as a decimal) equal to 1.00 minus the maximum rate on such date at which Bank is required to maintain reserves on “ Euro-currency Liabilities ” as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System or, if such regulation or definition is modified, and as long as Bank is required to maintain reserves against a category of liabilities which includes Eurodollar deposits or includes a category of assets which includes Eurodollar loans, the rate at which such reserves are required to be maintained on such category.
     “ Debt ” means as to any Person, without duplication (a) all Funded Debt of a Person, (b) all Guarantee Obligations of such Person, (c) all obligations of such Person under conditional sale or other title retention agreements relating to property or assets purchased by such Person,
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(d) all indebtedness of such Person arising in connection with and due and payable under any Hedging Transaction entered into by such Person, (e) all recourse Debt of any partnership of which such Person is the general partner, and (f) any Off Balance Sheet Liabilities. The term “ Debt ” does not include accounts payable and other current liabilities associated with the purchase of Hydrocarbons, capital expenditures and parts and supplies on customary terms in the trade in the ordinary course of such Person’s business.
     “ Deeds ” has the meaning ascribed to such term in Section 6.3(e) hereof.
     “ Default ” means any event that with the giving of notice or the passage of time, or both, would constitute an Event of Default under this Agreement.
     “ Defaulting Lender ” shall mean a Lender which, in the reasonable determination of the Administrative Agent (a) has failed to fund its Percentage of any Advance or to purchase participations in a Swing Line Advance or any Reimbursement Obligations as required under this Agreement, unless such Lender is disputing its funding obligation in good faith, (b) has otherwise failed to pay to the Administrative Agent or any other Lender any other amount required to be paid by it under the terms of this Agreement or any other Loan Document, unless such Lender is disputing such obligation to pay any such amount in good faith, (c) has been, or whose holding company has been, determined to be insolvent or that has become subject to a bankruptcy, receivership or other similar proceeding, or (d) has had a substantial portion of its assets or management (or a substantial portion of the assets or management of its holding company) taken over by any Governmental Authority or any Governmental Authority has restricted its ability to act under this Agreement, including its ability to enter into amendments, waivers or modifications of this Agreement or any of the other Loan Documents (provided that the exercise of the customary rights of a shareholder by a Governmental Authority which owns shares in such Lender (or its holding company) shall not be covered by this clause (d) ), provided , however , in all cases that a Defaulting Lender shall no longer be deemed a Defaulting Lender when (i) the Defaulting Lender shall have cured the conditions which shall have caused it to be a Defaulting Lender hereunder and (ii) the Administrative Agent has agreed that such Lender shall no longer be deemed a Defaulting Lender hereunder.
     “ Defaulting Lender’s Unfunded Portion ” shall mean such Defaulting Lender’s Revolving Credit Percentage of the Revolving Credit Aggregate Commitment minus the sum of (a) the aggregate principal amount of all Revolving Credit Advances funded by the Defaulting Lender under the Revolving Credit, plus (b) such Defaulting Lender’s Revolving Credit Percentage of the aggregate outstanding principal amount of all Swing Line Advances and Letter of Credit Obligations.
     “ Distribution ” is defined in Section 8.5 hereof.
     “ Dollars ” and the sign “$” means lawful money of the United States of America.
     “ Domestic Subsidiary ” means any Subsidiary of any Borrower incorporated or organized under the laws of the United States of America, or any state or other political subdivision thereof or which is considered to be a “ disregarded entity ” for United States federal income tax purposes and which is not a “ controlled foreign corporation ” as defined under Section 957 of the Internal
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Revenue Code, in each case provided such Subsidiary is owned by the applicable Borrower or a Domestic Subsidiary of such Borrower, and “ Domestic Subsidiaries ” means any or all of them.
     “ Easements ” means, collectively, all of the right-of-way agreements, easements, surface use agreements, servitudes, permits, licenses and other agreements relating to any Pipeline Assets now held or hereafter acquired by the Borrowers or any of their Subsidiaries.
     “ Effective Date ” means the date on which all the conditions precedent set forth in Sections 5.1 and 5.2 have been satisfied.
     “ Electronic Transmission ” means each document, instruction, authorization, file, information and any other communication transmitted, posted or otherwise made or communicated by e-mail or E-Fax, or otherwise to or from an E-System or other equivalent service.
     “ Eligible Assignee ” shall mean (a) a Lender; (b) an Affiliate of a Lender; (c) any Person (other than a natural person) that is or will be engaged in the business of making, purchasing, holding or otherwise investing in commercial loans or similar extensions of credit in the ordinary course of its business, provided that such Person is administered or managed by a Lender, an Affiliate of a Lender or an entity or Affiliate of an entity that administers or manages a Lender; or (d) any other Person (other than a natural person) approved by the (i) Administrative Agent (and in the case of an assignment of a commitment under the Revolving Credit, the Issuing Lender and Swing Line Lender), and (ii) unless a Event of Default has occurred and is continuing, the Administrative Borrower (each such approval not to be unreasonably withheld or delayed); provided that (x) notwithstanding the foregoing, “ Eligible Assignee ” shall not include any Borrower, or any Affiliate or Subsidiary of any Borrower; (y) notwithstanding clause (d)(ii) of this definition, no assignment shall be made to an entity which is a competitor of any Credit Party without the consent of the Administrative Borrower, which consent may be withheld in its sole discretion; and (z) and no assignment shall be made to an Impaired Lender without the consent of the Administrative Agent, and in the case of an assignment of a commitment under the Revolving Credit, the Issuing Lender and the Swing Line Lender and, to the extent no Event of Default is continuing, the Administrative Borrower.
     “ Energy Policy Act ” means the Energy Policy Act of 1992, Pub. L. No. 102-486, 106 Stat. 2776 (codified as amended in scattered sections of 15, 16, 25, 20 and 42 U.S.C.).
     “ Equity Interest ” means (i) in the case of any corporation, all capital stock and any securities exchangeable for or convertible into capital stock, (ii) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents of corporate stock (however designated) in or to such association or entity, (iii) in the case of a partnership or limited liability company, partnership or membership interests (whether general or limited) and (iv) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distribution of assets of, the issuing Person, and including, in all of the foregoing cases described in clauses (i) , (ii) , (iii) or (iv) , any warrants, rights or other options to purchase or otherwise acquire any of the interests described in any of the foregoing cases.
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     “ ERISA ” means the Employee Retirement Income Security Act of 1974, as amended, or any successor act or code and the regulations in effect from time to time thereunder.
     “ E-System ” means any electronic system and any other Internet or extranet-based site, whether such electronic system is owned, operated or hosted by the Administrative Agent, any of its Affiliates or any other Person, providing for access to data protected by passcodes or other security system.
     “ Eurodollar-based Advance ” means any Advance which bears interest at the Eurodollar-based Rate.
     “ Eurodollar-based Rate ” means a per annum interest rate which is equal to the sum of (a) the Applicable Margin, plus (b) the greater of (i) two percent (2.00%) per annum and (ii) the quotient of:
     (A) the LIBOR Rate, divided by
     (B) a percentage equal to 100% minus the maximum rate on such date at which the Administrative Agent is required to maintain reserves on ‘Eurocurrency Liabilities’ as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System or, if such regulation or definition is modified, and as long as the Administrative Agent is required to maintain reserves against a category of liabilities which includes Eurocurrency deposits or includes a category of assets which includes Eurocurrency loans, the rate at which such reserves are required to be maintained on such category,
such sum to be rounded upward, if necessary, in the discretion of the Administrative Agent, to the nearest whole multiple of 1/100th of 1%.
     “ Eurodollar-Interest Period ” means, for any Eurodollar-based Advance, an Interest Period of one, two or three months (or any shorter or longer periods agreed to in advance by the Administrative Borrower, the Administrative Agent and the Lenders) as selected by the Administrative Borrower, for such Eurodollar-based Advance pursuant to Section 2.3 or 4.4 hereof, as the case may be.
     “ Eurodollar Lending Office ” means, (a) with respect to the Administrative Agent, the Administrative Agent’s office located at its Grand Caymans Branch or such other branch of the Administrative Agent, domestic or foreign, as it may hereafter designate as its Eurodollar Lending Office by written notice to the Administrative Borrower and the Lenders and (b) as to each of the Lenders, its office, branch or affiliate located at its address set forth on the signature pages hereof (or identified thereon as its Eurodollar Lending Office), or at such other office, branch or affiliate of such Lender as it may hereafter designate as its Eurodollar Lending Office by written notice to the Administrative Borrower and the Administrative Agent.
     “ Event of Default ” means each of the Events of Default specified in Section 9.1 hereof.
     “ Federal Funds Effective Rate ” means, for any day, a fluctuating interest rate per annum equal to the weighted average of the rates on overnight Federal funds transactions with members
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of the Federal Reserve System arranged by Federal funds brokers, as published for such day (or, if such day is not a Business Day, for the next preceding Business Day) by the Federal Reserve Bank of New York, or, if such rate is not so published for any day which is a Business Day, the average of the quotations for such day on such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by the Administrative Agent, all as conclusively determined by the Administrative Agent, such sum to be rounded upward, if necessary, in the discretion of the Administrative Agent, to the nearest whole multiple of 1/100th of 1%.
     “ Fee Letter ” means the fee letter by and between American Infrastructure MLP Funds and Comerica Bank dated as of August 21, 2009, and executed by American Infrastructure MLP Funds on August 24, 2009, relating to the Indebtedness hereunder, as amended, restated, replaced or otherwise modified from time to time.
     “ Fees ” means the Revolving Credit Facility Fee, the Term Loan Facility Fee, the Letter of Credit Fees and the other fees and charges (including any agency fees) payable by the Borrowers to the Lenders, the Issuing Lender or the Administrative Agent hereunder or under the Fee Letter.
     “ FERC ” means the Federal Energy Regulatory Commission or any of its successors.
     “ Final Maturity Date ” means the last to occur of (i) the Revolving Credit Maturity Date or (ii) the Term Loan Maturity Date.
     “ Fiscal Year ” means the twelve-month period ending on each December 31.
     “ Foreign Subsidiary ” means any Subsidiary, other than a Domestic Subsidiary, and “ Foreign Subsidiaries ” means any or all of them.
     “ Funded Debt ” of any Person means, without duplication, (a) all indebtedness of such Person for borrowed money or for the deferred purchase price of property or services as of such date (other than operating leases and trade liabilities incurred in the ordinary course of business and payable in accordance with customary practices) or which is evidenced by a note, bond, debenture or similar instrument, (b) the principal component of all obligations of such Person under Capitalized Leases, (c) all reimbursement obligations (actual, contingent or otherwise) of such Person in respect of letters of credit, bankers acceptances or similar obligations issued or created for the account of such Person, (d) all liabilities of the type described in (a) , (b) and (c) above that are secured by any Liens on any property owned by such Person as of such date even though such Person has not assumed or otherwise become liable for the payment thereof, the amount of which is determined in accordance with GAAP; provided , however , that so long as such Person is not personally liable for any such liability, the amount of such liability shall be deemed to be the lesser of the fair market value at such date of the property subject to the Lien securing such liability and the amount of the liability secured, and (e) all Guarantee Obligations in respect of any liability which constitutes liabilities of the types described in clauses (a) through (d) above; provided , however , that Funded Debt shall not include any indebtedness under any Hedging Transaction prior to the occurrence of a termination event with respect thereto.
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     “ GAAP ” means, as of any applicable date of determination, generally accepted accounting principles in the United States of America, as applicable on such date, consistently applied, as in effect from time to time, except as expressly provided in Section 13.1 hereof.
     “ Governmental Authority ” means the United States, each state, each county, each city, and each other political subdivision in which all or any portion of the Collateral is located, and each other political subdivision, agency, or instrumentality exercising jurisdiction over the Administrative Agent, the Lenders, any Credit Party, any of the Indebtedness or any Collateral.
     “ Governmental Obligations ” means noncallable direct general obligations of the United States of America or obligations the payment of principal of and interest on which is unconditionally guaranteed by the United States of America.
     “ Guarantee Obligation ” means as to any Person (the “ guaranteeing person ”) any obligation of the guaranteeing Person in respect of any obligation of another Person (the “ primary obligor ”) (including, without limitation, any bank under any letter of credit), the creation of which was induced by a reimbursement agreement, guaranty agreement, keepwell agreement, purchase agreement, counterindemnity or similar obligation issued by the guaranteeing person, in either case guaranteeing or in effect guaranteeing any Debt, leases, dividends or other obligations (the “ primary obligations ”) of the primary obligor in any manner, whether directly or indirectly, including, without limitation, any obligation of the guaranteeing person, whether or not contingent, (i) to purchase any such primary obligation or any property constituting direct or indirect security therefor, (ii) to advance or supply funds (1) for the purchase or payment of any such primary obligation or (2) to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency of the primary obligor, (iii) to purchase property, securities or services primarily for the purpose of assuring the owner of any such primary obligation of the ability of the primary obligor to make payment of such primary obligation or (iv) otherwise to assure or hold harmless the owner of any such primary obligation against loss in respect thereof; provided , however , that the term Guarantee Obligation shall not include endorsements of instruments for deposit or collection in the ordinary course of business. The amount of any Guarantee Obligation of any guaranteeing person shall be deemed to be the lower of (a) an amount equal to the stated or determinable amount of the primary obligation in respect of which such Guarantee Obligation is made and (b) the maximum amount for which such guaranteeing person may be liable pursuant to the terms of the instrument embodying such Guarantee Obligation, unless such primary obligation and the maximum amount for which such guaranteeing person may be liable are not stated or determinable, in which case the amount of such Guarantee Obligation shall be such guaranteeing person’s maximum reasonably anticipated liability in respect thereof as determined by the applicable Person in good faith.
     “ Guarantor(s) ” means the Parent, the Parent General Partner and each Domestic Subsidiary of each Borrower which has executed and delivered to the Administrative Agent a Guaranty (or a joinder to a Guaranty), and a Security Agreement (or a joinder to the Security Agreement).
     “ Guaranty ” means, collectively, the guaranty agreements executed and delivered by the applicable Guarantors on the Effective Date pursuant to Section 5.1 hereof and those guaranty
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agreements executed and delivered from time to time after the Effective Date (whether by execution of joinder agreements or otherwise) pursuant to Section 7.13 hereof or otherwise, in each case substantially in the form attached hereto as Exhibit H , as amended, restated or otherwise modified from time to time.
     “ Hazardous Material ” means any hazardous or toxic waste, substance or material defined or regulated as such in or for purposes of the Hazardous Material Laws.
     “ Hazardous Material Law(s) ” means all laws, codes, ordinances, rules, regulations and other governmental restrictions and requirements issued by any federal, state, local or other Governmental Authority or quasi-Governmental Authority or body (or any agency, instrumentality or political subdivision thereof) pertaining to any substance or material which is regulated for reasons of health, safety or the environment and which is present or alleged to be present on or about or used in any facilities owned, leased or operated by any Credit Party, or any portion thereof including, without limitation, those relating to soil, surface, subsurface ground water conditions and the condition of the indoor and outdoor ambient air; any so-called “ superfund ” or “ superlien ” law; and any other United States federal, state or local statute, law, ordinance, code, rule, regulation, order or decree regulating, relating to, or imposing liability or standards of conduct concerning, any Hazardous Material, as now or at any time during the term of the Agreement in effect.
     “ Hedging Agreement ” means any agreement relating to a Hedging Transaction entered into between any Borrower and any Lender or an Affiliate of a Lender.
     “ Hedging Transaction ” means each interest rate swap transaction, basis swap transaction, forward rate transaction, equity transaction, equity index transaction, foreign exchange transaction, cap transaction and floor transaction, and a swap transaction, collar transaction, cap transaction or other derivative transaction which is intended to reduce or eliminate the risk of fluctuations in the price of Hydrocarbons (including any option with respect to any of these transactions and any combination of any of the foregoing).
     “ Hereof ”, “ hereto ”, “ hereunder ” and similar terms shall refer to this Agreement and not to any particular paragraph or provision of this Agreement.
     “ Hydrocarbons ” means oil, gas, coal seam gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate and all other liquid and gaseous hydrocarbons.
     “ Impaired Lender ” means a Defaulting Lender and any other Lender (a) which the Administrative Agent, the Issuing Lender or Swing Line Lender believes, in good faith, has defaulted (and continues to be in default) in fulfilling its obligations under any other syndicated credit facilities or as a participant in any other credit facility and such Lender is not in good faith disputing that such a failure has occurred, or (b) which, if carrying an investment grade rating of at least BBB- from S&P or Baa3 from Moody’s at the time it became a party to this Agreement, no longer carries a rating of at least BBB- from S&P or Baa3 from Moody’s, provided , however , in all cases that an Impaired Lender shall no longer be deemed an Impaired Lender when (i) the Impaired Lender shall have cured the conditions which shall have caused it to be an Impaired
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Lender hereunder and (ii) the Administrative Agent has agreed that such Lender shall no longer be deemed an Impaired Lender hereunder.
     “ Income Taxes ” means for any period the aggregate amount of taxes based on income or profits for such period with respect to the operations of the Administrative Borrower and its Subsidiaries (including, without limitation, corporate franchise, capital stock, net worth and value-added taxes assessed by state and local governments) determined in accordance with GAAP on a Consolidated basis (to the extent such income and profits were included in computing Consolidated Net Income).
     “ Increased Costs ” has the meaning ascribed to such term in Section 11.6(a) hereof.
     “ Indebtedness ” means all indebtedness and liabilities (including without limitation principal, interest (including without limitation interest accruing at the then applicable rate provided in this Agreement or any other applicable Loan Document after an applicable maturity date and interest accruing at the then applicable rate provided in this Agreement or any other applicable Loan Document after the filing of any petition in bankruptcy, or the commencement of any insolvency, reorganization or like proceeding, relating to the Credit Parties whether or not a claim for post-filing or post-petition interest is allowed in such proceeding), fees, expenses and other charges) arising under this Agreement or any of the other Loan Documents, whether direct or indirect, absolute or contingent, of any Credit Party to any of the Lenders or Affiliates thereof or to the Administrative Agent, in any manner and at any time, whether arising under this Agreement, the Guaranty or any of the other Loan Documents (including without limitation, payment obligations under Hedging Transactions evidenced by Hedging Agreements), due or hereafter to become due, now owing or that may hereafter be incurred by any Credit Party to any of the Lenders or Affiliates thereof or to the Administrative Agent, and which shall be deemed to include protective advances made by the Administrative Agent with respect to the Collateral under or pursuant to the terms of any Loan Document and any liabilities of any Credit Party to the Administrative Agent or any Lender arising in connection with any Lender Products, in each case whether or not reduced to judgment, with interest according to the rates and terms specified, and any and all consolidations, amendments, renewals, replacements, substitutions or extensions of any of the foregoing; provided , however , that for purposes of calculating the Indebtedness outstanding under this Agreement or any of the other Loan Documents, the direct and indirect and absolute and contingent obligations of the Credit Parties (whether direct or contingent) shall be determined without duplication.
     “ Initial Reinvestment Period ” means a ninety (90) day period beginning on the date of the applicable Reinvestment Certificate during which Reinvestment must be commenced under Section 4.8(a) of this Agreement.
     “ Intercompany Note ” means any promissory note issued or to be issued by a Borrower or any of its Subsidiaries to evidence an intercompany loan in form and substance satisfactory to the Administrative Agent.
     “ Interest Coverage Ratio ” means, for any Test Period, the ratio of (a) Consolidated EBITDA for such Test Period to (b) Consolidated Interest Expense for such Test Period.
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     “ Interest Period ” means (a) with respect to a Eurodollar-based Advance, a Eurodollar-Interest Period, commencing on the day a Eurodollar-based Advance is made, or on the effective date of an election of the Eurodollar-based Rate made under Section 2.3 or 4.4 hereof, and (b) with respect to a Swing Line Advance carried at the Quoted Rate, an interest period of 30 days (or any lesser number of days agreed to in advance by the Administrative Borrower, the Administrative Agent and the Swing Line Lender); provided , however , that (i) any Interest Period which would otherwise end on a day which is not a Business Day shall end on the next succeeding Business Day, except that as to an Interest Period in respect of a Eurodollar-based Advance, if the next succeeding Business Day falls in another calendar month, such Interest Period shall end on the next preceding Business Day, (ii) when an Interest Period in respect of a Eurodollar-based Advance begins on a day which has no numerically corresponding day in the calendar month during which such Interest Period is to end, it shall end on the last Business Day of such calendar month, and (iii) no Interest Period in respect of any Advance shall extend beyond the Revolving Credit Maturity Date or the Term Loan Maturity Date, as applicable.
     “ Internal Revenue Code ” means the Internal Revenue Code of 1986 of the United States of America, as amended from time to time, and the regulations promulgated thereunder.
     “ Interstate Commerce Act ” means the body of law commonly known as the Interstate Commerce Act, Chapter 104, 24 Stat. 379 (codified as amended in scattered sections of 49 U.S.C.)
     “ Interstate Pipelines ” has the meaning ascribed to such term in Section 6.27(a) hereof.
     “ Intrastate Pipelines ” has the meaning ascribed to such term in Section 6.27(b) hereof.
     “ Inventory ” means any inventory as defined under the UCC.
     “ Investment ” means, when used with respect to any Person, (a) any loan, investment or advance made by such Person to any other Person (including, without limitation, any Guarantee Obligation) in respect of any Equity Interest, Debt, obligation or liability of such other Person and (b) any other investment made by such Person (however acquired) in Equity Interests in any other Person, including, without limitation, any investment made in exchange for the issuance of Equity Interest of such Person and any investment made as a capital contribution to such other Person.
     “ Issuing Lender ” means Comerica Bank in its capacity as issuer of one or more Letters of Credit hereunder, or its successor designated by the Administrative Borrower and the Revolving Credit Lenders.
     “ Issuing Office ” means such office as Issuing Lender shall designate as its Issuing Office.
     “ Joinder ” means a joinder agreement substantially in the form of Exhibit M hereto, as amended, restated or otherwise modified from time to time.
     “ L/C Indemnified Amounts ” has the meaning ascribed to such term in Section 3.9 hereof.
     “ L/C Indemnified Person ” has the meaning ascribed to such term in Section 3.9 hereof.
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     “ Lender Products ” means any one or more of the following types of services or facilities extended to the Credit Parties by any Lender: (i) credit cards, (ii) credit card processing services, (iii) debit cards, (iv) purchase cards, (v) Automated Clearing House (ACH) transactions, (vi) cash management, including controlled disbursement services, and (vii) establishing and maintaining deposit accounts.
     “ Lenders ” has the meaning set forth in the preamble, and shall include the Revolving Credit Lenders, the Term Loan Lenders, the Swing Line Lender and any assignee which becomes a Lender pursuant to Section 13.8 hereof.
     “ Letter of Credit Agreement ” means, collectively, the letter of credit application and related documentation executed and/or delivered by the Administrative Borrower in respect of each Letter of Credit, in each case satisfactory to the Issuing Lender, as amended, restated or otherwise modified from time to time.
     “ Letter of Credit Documents ” has the meaning ascribed to such term in Section 3.7(a) hereof.
     “ Letter of Credit Fees ” means the fees payable in connection with Letters of Credit pursuant to Section 3.4(a) and (b) hereof.
     “ Letter of Credit Maximum Amount ” means Ten Million Dollars ($10,000,000).
     “ Letter of Credit Obligations ” means at any date of determination, the sum of (a) the aggregate undrawn amount of all Letters of Credit then outstanding, and (b) the aggregate amount of Reimbursement Obligations which remain unpaid as of such date.
     “ Letter of Credit Payment ” means any amount paid or required to be paid by the Issuing Lender in its capacity hereunder as issuer of a Letter of Credit as a result of a draft or other demand for payment under any Letter of Credit.
     “ Letter(s) of Credit ” means any standby letters of credit issued by Issuing Lender at the request of or for the account of one or more of the Borrowers pursuant to Article 3 hereof.
     “ LIBOR Rate ” means,
     (a) with respect the principal amount of any Eurodollar-based Advance outstanding hereunder, the per annum rate of interest determined on the basis of the rate for deposits in United States Dollars for a period equal to the relevant Eurodollar-Interest Period, commencing on the first day of such Eurodollar-Interest Period, appearing on Page BBAM of the Bloomberg Financial Markets Information Service as of 11:00 a.m. (Detroit, Michigan time) (or soon thereafter as practical), two (2) Business Days prior to the first day of such Eurodollar-Interest Period. In the event that such rate does not appear on Page BBAM of the Bloomberg Financial Markets Information Service (or otherwise on such Service), the “ LIBOR Rate ” shall be determined by reference to such other publicly available service for displaying LIBOR rates as may be agreed upon by the Administrative Agent and the Administrative Borrower, or, in the absence of such agreement, the “ LIBOR Rate ” shall, instead, be the per annum rate equal to the average
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(rounded upward, if necessary, to the nearest one-sixteenth of one percent (1/16%)) of the rate at which the Administrative Agent is offered dollar deposits at or about 11:00 a.m. (Detroit, Michigan time) (or soon thereafter as practical), two (2) Business Days prior to the first day of such Eurodollar-Interest Period in the interbank LIBOR market in an amount comparable to the principal amount of the relevant Eurodollar-based Advance which is to bear interest at such Eurodollar-based Rate and for a period equal to the relevant Eurodollar-Interest Period; and
     (b) with respect to the principal amount of any Base Rate Advance carried at the Daily Adjusting LIBOR Rate outstanding hereunder, the per annum rate of interest determined on the basis of the rate for deposits in United States Dollars for a period equal to one (1) month appearing on Page BBAM of the Bloomberg Financial Markets Information Service as of 11:00 a.m. (Detroit, Michigan time) (or soon thereafter as practical) on such day, or if such day is not a Business Day, on the immediately preceding Business Day. In the event that such rate does not appear on Page BBAM of the Bloomberg Financial Markets Information Service (or otherwise on such Service), the “ LIBOR Rate ” shall be determined by reference to such other publicly available service for displaying Eurodollar rates as may be agreed upon by the Administrative Agent and the Administrative Borrower, or, in the absence of such agreement, the “ LIBOR Rate ” shall, instead, be the per annum rate equal to the average of the rate at which the Administrative Agent is offered dollar deposits at or about 11:00 a.m. (Detroit, Michigan time) (or soon thereafter as practical) on such day in the interbank Eurodollar market in an amount comparable to the principal amount of the Indebtedness hereunder which is to bear interest at such “ LIBOR Rate ” and for a period equal to one (1) month.
     “ Lien ” means any security interest in or lien on or against any property arising from any pledge, assignment, hypothecation, mortgage, security interest, deposit arrangement, trust receipt, conditional sale or title retaining contract, sale and leaseback transaction, Capitalized Lease, consignment or bailment for security, or any other type of lien, charge, encumbrance, title exception, preferential or priority arrangement affecting property (including with respect to stock, any stockholder agreements, voting rights agreements, buy-back agreements and all similar arrangements), whether based on common law or statute.
     “ Loan Documents ” means, collectively, this Agreement, the Notes (if issued), the Letters of Credit, the Guaranty, the Collateral Documents and each Hedging Agreement, as such documents may be amended, restated or otherwise modified from time to time.
     “ Majority Lenders ” means at any time (a) so long as the Revolving Credit Aggregate Commitment has not been terminated, Lenders holding more than 50.0% of the sum of (i) the Revolving Credit Aggregate Commitment plus (ii) the aggregate principal amount of Indebtedness then outstanding under the Term Loan and (b) if the Revolving Credit Aggregate Commitment has been terminated (whether by maturity, acceleration or otherwise), Lenders holding more than 50.0% of the aggregate principal amount then outstanding under the Revolving Credit and the Term Loan; provided that , for purposes of determining Majority Lenders hereunder, the Letter of Credit Obligations and principal amount outstanding under the Swing Line shall be allocated among the Revolving Credit Lenders based on their respective Revolving Credit Percentages; provided further that , so long as there are fewer than three
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Lenders, considering any Lender and its Affiliates as a single Lender, “ Majority Lenders ” shall mean all Lenders (excluding any Defaulting Lender).
     “ Majority Revolving Credit Lenders ” means at any time (a) so long as the Revolving Credit Aggregate Commitment has not been terminated, the Revolving Credit Lenders holding more than 50.0% of the Revolving Credit Aggregate Commitment and (b) if the Revolving Credit Aggregate Commitment has been terminated (whether by maturity, acceleration or otherwise), Revolving Credit Lenders holding more than 50.0% of the aggregate principal amount then outstanding under the Revolving Credit; provided that , for purposes of determining Majority Revolving Credit Lenders hereunder, the Letter of Credit Obligations and principal amount outstanding under the Swing Line shall be allocated among the Revolving Credit Lenders based on their respective Revolving Credit Percentages; provided further that , so long as there are fewer than three Revolving Credit Lenders, considering any Revolving Credit Lender and its Affiliates as a single Revolving Credit Lender, “ Majority Revolving Credit Lenders ” shall mean all Revolving Credit Lenders.
     “ Majority Term Loan Lenders ” means at any time with respect to the Term Loan, the Term Loan Lenders holding more than 50.0% of the aggregate principal amount then outstanding under the Term Loan; provided that , so long as there are fewer than three Term Loan Lenders, considering any Term Loan Lender and its Affiliates as a single Term Loan Lender, “ Majority Term Loan Lenders ” shall mean all the Term Loan Lenders.
     “ Material Adverse Effect ” means a material adverse effect on (a) the condition (financial or otherwise), business, performance, operations, properties or prospects of the Credit Parties taken as a whole, (b) the ability of any Credit Party to perform its obligations under this Agreement, the Notes (if issued) or any other Loan Document to which it is a party, or (c) the validity or enforceability of this Agreement, any of the Notes (if issued) or any of the other Loan Documents or the rights or remedies or interests as creditors and/or secured parties of the Administrative Agent or the Lenders hereunder or thereunder.
     “ Material Contract ” means (i) each agreement or contract to which any Credit Party is a party or in respect of which any Credit Party has any liability, that by its terms (without reference to any indemnity or reimbursement provision therein) provides for aggregate future guaranteed payments in respect of any such individual agreement or contract of at least $500,000, (ii) each material gas transportation agreement, interconnect and facilities agreement, gas storage agreement, gas processing agreement and gas marketing agreement and (iii) any other agreement or contract the loss of which would be reasonably likely to result in a Material Adverse Effect; provided that Material Contracts shall not be deemed to include any Pension Plans, collective bargaining agreements, or casualty or liability or other insurance policies maintained in the ordinary course of business.
     “ Material Subsidiary ” means (a) any Person acquired in the Acquisition, (b) any Domestic Subsidiary of any Borrower that owns assets the value of which comprises ten percent (10%) or more of the total book value of all assets of the Borrowers and their Subsidiaries (on a Consolidated basis) or having gross revenues for the immediately preceding Fiscal Year that comprises ten percent (10%) or more of the gross revenues of the Borrowers and their Subsidiaries (on a Consolidated basis) and (c) any other Domestic Subsidiary of any Borrower
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that any Borrower from time to time designates as a “Material Subsidiary” by written notice to the Administrative Agent.
     “ Mortgages ” means the mortgages, deeds of trust and any other similar documents related thereto or required thereby covering the Pipeline Systems and other Real Property and executed and delivered by any Borrower or any of its Subsidiaries on the Effective Date pursuant to Section 5.1 hereof, if any, and executed and delivered after the Effective Date by the any Borrower or any of its Subsidiaries pursuant to Section 7.13 hereof or otherwise, and “ Mortgage ” means any such document, as such documents may be amended, restated or otherwise modified from time to time.
     “ Multiemployer Plan ” means a Pension Plan which is a multiemployer plan as defined in Section 4001(a)(3) of ERISA.
     “ Net Cash Proceeds ” means the aggregate cash payments received by any Credit Party from any Asset Sale or the issuance of Equity Interests, as the case may be, net of the ordinary and customary direct costs incurred in connection with such sale or issuance, as the case may be, such as legal, accounting, advisory and investment banking fees, sales commissions, and other third party charges, and net of property taxes, transfer taxes and any other taxes paid or payable by such Credit Party in respect of any sale or issuance.
     “ Notes ” means the Revolving Credit Notes, the Swing Line Note and the Term Loan Notes.
     “ Off Balance Sheet Liability(ies) ” of a Person means (i) any repurchase obligation or liability of such Person with respect to accounts or notes receivables sold by such Person, (ii) any liability under any sale and leaseback transaction which is not a Capitalized Lease, (iii) any liability under any so-called “ synthetic lease ” transaction entered into by such Person, or (iv) any obligation arising with respect to any other transaction which is the functional equivalent of any of the liabilities set forth in subsections (i) - (iii) of this definition, but which does not constitute a liability on the balance sheets of such Person.
     “ Order ” has the meaning ascribed to such term in Section 7.4(e) hereof.
     “ Parent ” means American Midstream Partners, LP, a Delaware limited partnership.
     “ Parent General Partner ” means American Midstream GP, LLC, a Delaware limited liability company.
     “ PBGC ” means the Pension Benefit Guaranty Corporation or any successor thereto.
     “ Pension Plan ” means any plan established and maintained by a Credit Party, or contributed to by a Credit Party, which is qualified under Section 401(a) of the Internal Revenue Code and subject to the minimum funding standards of Section 412 of the Internal Revenue Code.
     “ Percentage ” means, as applicable, the Revolving Credit Percentage, the Term Loan Percentage or the Weighted Percentage.
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     “ Permitted Acquisition ” means any acquisition by any Borrower or any Guarantor of all or substantially all of the assets of another Person, or of a division or line of business of another Person, or any Equity Interests of another Person which satisfies and/or is conducted in accordance with the following requirements:
     (a) Such acquisition is of a business or Person engaged in a line of business which is the same as, compatible with, or complementary to, the business of such Borrower or such Guarantor;
     (b) If such acquisition is structured as an acquisition of the Equity Interests of any Person, then the Person so acquired shall (X) become a wholly-owned direct Subsidiary of such Borrower or of a Guarantor and such Borrower or Guarantor shall cause such acquired Person to comply with Section 7.13 hereof or (Y) provided that each Borrower and its Subsidiaries continue to comply with Section 7.4(a) hereof, be merged with and into such Borrower or such Guarantor (and, in the case of a Borrower, with such Borrower being the surviving entity);
     (c) If such acquisition is structured as the acquisition of assets, such assets shall be acquired directly by a Borrower or a Guarantor (subject to compliance with Section 7.4(a) hereof);
     (d) The Administrative Borrower shall have delivered to the Administrative Agent not less than ten (10) (or such shorter period of time agreed to by the Administrative Agent) nor more than ninety (90) days prior to the date of such acquisition, notice of such acquisition together with Pro Forma Projected Financial Information, copies of all material documents relating to such acquisition (including the acquisition agreement and any related document), and historical financial information (including income statements, balance sheets and cash flows) covering at least three (3) complete Fiscal Years of the acquisition target, if available, prior to the effective date of the acquisition or the entire credit history of the acquisition target, whichever period is shorter, in each case in form and substance reasonably satisfactory to the Administrative Agent;
     (e) Both immediately before and after the consummation of such acquisition and after giving effect to the Pro Forma Projected Financial Information, no Default or Event of Default shall have occurred and be continuing;
     (f) The Administrative Agent shall have received satisfactory evidence showing that the business or Person being acquired does not have negative EBITDA, calculated on a trailing twelve-month basis.
     (g) The Administrative Agent shall have received satisfactory evidence showing that on and immediately after the date such acquisition is consummated (and taking into account any Advances or Letters of Credit to be made or issued, as the case may be, in connection with the proposed acquisition), (i) the Unused Revolving Credit Availability shall be at least Seven Million Five Hundred Thousand Dollars ($7,500,000) and (ii) the Total Debt to Consolidated EBITDA Ratio is not more than 3.00:1.00;
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     (h) The board of directors (or other Person(s) exercising similar functions) of the seller of the assets or issuer of the Equity Interests being acquired shall not have disapproved such transaction or recommended that such transaction be disapproved;
     (i) All governmental, quasi-governmental, agency, regulatory or similar licenses, authorizations, exemptions, qualifications, consents and approvals necessary under any laws applicable to the Borrower or Guarantor that is making the acquisition, or the acquisition target (if applicable) for or in connection with the proposed acquisition and all necessary non-governmental and other third-party approvals which, in each case, are material to such acquisition shall have been obtained, and all necessary or appropriate declarations, registrations or other filings with any court, governmental or regulatory authority, securities exchange or any other Person, which in each case, are material to the consummation of such acquisition or to the acquisition target, if applicable, have been made, and evidence thereof reasonably satisfactory in form and substance to the Administrative Agent shall have been delivered, or caused to have been delivered, by the Administrative Borrower to the Administrative Agent;
     (j) There shall be no actions, suits or proceedings pending or, to the knowledge of any Borrower or any of its Subsidiaries threatened in writing against the acquisition target in any court or before or by any governmental department, agency or instrumentality, which could reasonably be expected to be decided adversely to the acquisition target and which, if decided adversely, could reasonably be expected to have a material adverse effect on the business, operations, properties or financial condition of the acquisition target and its subsidiaries (taken as a whole) or would materially adversely affect the ability of the acquisition target to enter into or perform its obligations in connection with the proposed acquisition, nor shall there be any actions, suits, or proceedings pending, or to the knowledge of any Borrower or any of its Subsidiaries threatened in writing against any Borrower or any of its Subsidiaries that is making the acquisition which would materially adversely affect the ability of any Borrower or any of its Subsidiaries to enter into or perform its obligations in connection with the proposed acquisition; and
     (k) The purchase price of such proposed new acquisition, computed on the basis of total acquisition consideration paid or incurred, or required to be paid or incurred, with respect thereto, including the amount of Debt (such Debt being otherwise permitted under this Agreement) assumed or to which such assets, businesses or business or Equity Interests, or any Person so acquired is subject and including any portion of the purchase price allocated to any non-compete agreements, (X) is less than Five Million Dollars ($5,000,000), (Y) when added to the purchase price for each other acquisition consummated hereunder as a Permitted Acquisition during the same Fiscal Year as the applicable acquisition (not including acquisitions specifically consented to which fall outside of the terms of this definition), does not exceed Ten Million Dollars ($10,000,000) and (Z) when added to the purchase price for each other acquisition consummated hereunder as a Permitted Acquisition during the term of this agreement (not including acquisitions specifically consented to which fall outside the terms of this definition), does not exceed Twenty Million Dollars ($20,000,000).
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     “ Permitted Investments ” means with respect to any Person:
     (a) Governmental Obligations;
     (b) Obligations of a state or commonwealth of the United States or the obligations of the District of Columbia or any possession of the United States, or any political subdivision of any of the foregoing, which are described in Section 103(a) of the Internal Revenue Code and are graded in any of the highest three (3) major grades as determined by at least one Rating Agency; or secured, as to payments of principal and interest, by a letter of credit provided by a financial institution or insurance provided by a bond insurance company which in each case is itself or its debt is rated in one of the highest three (3) major grades as determined by at least one Rating Agency;
     (c) Banker’s acceptances, commercial accounts, demand deposit accounts, certificates of deposit, other time deposits or depository receipts issued by or maintained with any Lender or any Affiliate thereof, or any bank, trust company, savings and loan association, savings bank or other financial institution whose deposits are insured by the Federal Deposit Insurance Corporation and whose reported capital and surplus equal at least $250,000,000, provided that such minimum capital and surplus requirement shall not apply to demand deposit accounts maintained by any Borrower or any of its Subsidiaries in the ordinary course of business;
     (d) Commercial paper rated at the time of purchase within the two highest classifications established by not less than two Rating Agencies, and which matures within 270 days after the date of issue;
     (e) Secured repurchase agreements against obligations itemized in paragraph (a) above, and executed by a bank or trust company or by members of the association of primary dealers or other recognized dealers in United States government securities, the market value of which must be maintained at levels at least equal to the amounts advanced; and
     (f) Any fund or other pooling arrangement which exclusively purchases and holds the investments itemized in (a) through (e) above.
     “ Permitted Liens ” means with respect to any Person:
     (a) Liens for (i) taxes or governmental assessments or charges or (ii) customs duties in connection with the importation of goods to the extent such Liens attach to the imported goods that are the subject of the duties, in each case (x) to the extent not yet due, (y) as to which the period of grace, if any, related thereto has not expired or (z) which are being contested in good faith by appropriate proceedings, provided that in the case of any such contest, any proceedings for the enforcement of such liens have been suspended and adequate reserves with respect thereto are maintained on the books of such Person in conformity with GAAP;
     (b) carriers’, warehousemen’s, mechanics’, materialmen’s, repairmen’s, processor’s, landlord’s liens or other like liens arising in the ordinary course of business
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which secure obligations that are not overdue for a period of more than 30 days or which are being contested in good faith by appropriate proceedings, provided that in the case of any such contest, (x) any proceedings commenced for the enforcement of such Liens have been suspended and (y) appropriate reserves with respect thereto are maintained on the books of such Person in conformity with GAAP;
     (c) (i) Liens incurred in the ordinary course of business to secure the performance of statutory obligations arising in connection with progress payments or advance payments due under contracts with the United States government or any agency thereof entered into in the ordinary course of business and (ii) Liens incurred or deposits made in the ordinary course of business to secure the performance of statutory obligations (not otherwise permitted under subsection (i) of this definition), bids, leases, fee and expense arrangements with trustees and fiscal agents, trade contracts, surety and appeal bonds, performance bonds and other similar obligations (exclusive of obligations incurred in connection with the borrowing of money, any lease-purchase arrangements or the payment of the deferred purchase price of property), provided, that in each case full provision for the payment of all such obligations has been made on the books of such Person as may be required by GAAP;
     (d) any attachment or judgment lien that does not constitute an Event of Default under Section 9.1(g) hereof or that remains unpaid, unvacated, unbonded or unstayed by appeal or otherwise for a period ending on the earlier of (i) thirty (30) consecutive days from the date of its attachment or entry (as applicable) or (ii) the commencement of enforcement steps with respect thereto, other than the filing of notice thereof in the public record;
     (e) terms, conditions, exceptions, limitations, easements, rights-of-way, restrictions (including zoning restrictions), covenants, licenses, encroachments, protrusions and other similar charges or encumbrances, minor right-of-way gaps and minor title deficiencies on or with respect to any Pipeline System or other Real Property, in each case, whether now or hereafter in existence, that would not, individually or in the aggregate, be reasonably expected to cause a Material Adverse Effect, and for the purposes of this Agreement, any minor title deficiency shall include, but not be limited to, terms, conditions, exceptions, limitations, easements, rights-of-way, servitudes, permits, surface leases and other similar rights in respect of surface operations, and easements for pipelines, streets, alleys, highways, telephone lines, power lines, railways and other easements and rights-of-way on, over or in respect of any of the properties of any Loan Party that are customarily granted or permitted to exist in the midstream pipeline industry or oil and gas industry; provided , however , that such deficiencies do not have, individually or in the aggregate, a Material Adverse Effect;
     (f) rights reserved to or vested in any Governmental Authority by the terms of any right, power, franchise, grant, license or permit, or by any provision of law, to revoke or terminate any such right, power, franchise, grant, license or permit or to condemn or acquire by eminent domain or similar process;
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     (g) rights reserved to or vested by law in any Governmental Authority to in any manner, control or regulate in any manner any of the properties of any Borrower or any of its Subsidiaries or the use thereof or the rights and interest of any Borrower or any of its Subsidiaries therein, in any manner under any and all laws;
     (h) Liens arising in connection with worker’s compensation, unemployment insurance, old age pensions and social security benefits and similar statutory obligations (excluding Liens arising under ERISA), provided that no enforcement proceedings in respect of such Liens are pending and provisions have been made for the payment of such liens on the books of such Person as may be required by GAAP;
     (i) Liens evidenced by UCC financing statements regarding leases permitted hereunder; and
     (j) continuations of Liens that are permitted under subsections (a) - (i) hereof, provided such continuations do not violate the specific time periods set forth in subsections (b) and (d) and provided further that such Liens do not extend to any additional property or assets of any Borrower or any of its Subsidiaries or secure any additional obligations of any Borrower or any of its Subsidiaries.
Regardless of the language set forth in this definition, no Lien over the Equity Interests of any Borrower or any of its Subsidiaries granted to any Person other than to the Administrative Agent for the benefit of the Lenders shall be deemed a “ Permitted Lien ” under the terms of this Agreement.
     “ Permitted Sale/Leaseback Transactions ” means the sale of personal property by a Person with the intent to lease such personal property as lessee provided that the value of all personal property sold does not exceed $2,500,000 in the aggregate.
     “ Person ” means a natural person, corporation, limited liability company, partnership, limited liability partnership, trust, incorporated or unincorporated organization, joint venture, joint stock company, firm or association or a government or any agency or political subdivision thereof or other entity of any kind.
     “ Pipeline Assets ” means, collectively, all gathering systems, tubes and pipelines used for the transportation of Hydrocarbons wherever located whether now owned or hereafter acquired by any Borrower or any of its Subsidiaries, together with all equipment, contracts, fixtures, improvements, records and other property appertaining thereto.
     “ Pipeline Systems ” means, collectively, all of the Pipeline Assets and Real Property and Easements related thereto.
     “ Pledge Agreement(s) ” means any pledge agreement executed and delivered by a Credit Party on the Effective Date pursuant to Section 5.1 hereof, if any, and executed and delivered from time to time after the Effective Date by any Credit Party pursuant to Section 7.13 hereof or otherwise, and any agreements, instruments or documents related thereto, in each case in form and substance satisfactory to the Administrative Agent amended, restated or otherwise modified from time to time.
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     “ Prime-based Rate ” means, for any day, that rate of interest which is equal to the greater of (i) the Prime Rate, and (ii) an interest rate per annum equal to the Federal Funds Effective Rate in effect on such day, plus one percent (1.0%).
     “ Prime Rate ” means the per annum rate of interest announced by the Administrative Agent, at its main office from time to time as its “ prime rate ” (it being acknowledged that such announced rate may not necessarily be the lowest rate charged by the Administrative Agent to any of its customers), which Prime Rate shall change simultaneously with any change in such announced rate.
     “ Pro Forma Balance Sheet ” means the pro forma consolidated balance sheet of the Administrative Borrower which has been certified by a Responsible Officer of the Administrative Borrower that it fairly presents in all material respects the pro forma adjustments reflecting the transactions (including payment of all fees and expenses in connection therewith) contemplated by this Agreement and the other Loan Documents.
     “ Pro Forma Projected Financial Information ” means, as to any proposed acquisition, a statement executed by the Administrative Borrower (supported by reasonable detail) setting forth the total consideration to be paid or incurred in connection with the proposed acquisition, and pro forma combined projected financial information for the Administrative Borrower and its Subsidiaries and the acquisition target (if applicable), consisting of projected balance sheets as of the proposed effective date of the acquisition and as of the end of at least the next succeeding three (3) Fiscal Years following the acquisition and projected statements of income and cash flows for each of those years, including sufficient detail to permit calculation of the ratios described in Section 7.9 hereof, as projected as of the effective date of the acquisition and as of the ends of those Fiscal Years and accompanied by (i) a statement setting forth a calculation of the ratio so described, (ii) a statement in reasonable detail specifying all material assumptions underlying the projections and (iii) such other information as the Administrative Agent shall reasonably request.
     “ Purchases ” has the meaning ascribed to such term in Section 8.5 hereof.
     “ Purchase and Sale Agreement ” means that certain Membership Interests Purchase and Sale Agreement between Enbridge Midcoast Energy, L.P., as Seller, and the Administrative Borrower, as Buyer, dated effective as of October 2, 2009.
     “ Purchasing Lender ” has the meaning set forth in Section 13.12 .
     “ Quoted Rate ” means the rate of interest per annum offered by the Swing Line Lender in its sole discretion with respect to a Swing Line Advance and accepted by the Administrative Borrower.
     “ Quoted Rate Advance ” means any Swing Line Advance which bears interest at the Quoted Rate.
     “ Rating Agency ” means Moody’s Investor Services, Inc., Standard and Poor’s Ratings Services, their respective successors or any other nationally recognized statistical rating organization which is acceptable to the Administrative Agent.
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     “ Real Property ” means, collectively, all right, title and interest, including any leasehold, mineral or other estate, in and to any and all parcels of or interests in real property owned, leased or operated any Person, whether by lease, license or other means, together with, in each case, all easements, hereditaments and appurtenances related thereto, all improvements, including, without limitation, compression stations and processing plants, and appurtenant fixtures and equipment, all general intangibles and contract rights and other property and rights incidental to the ownership, lease or operation thereof. Unless context requires otherwise, the term “ Real Property ” shall refer to the Real Property of each Borrower and its Subsidiaries.
     “ Refunded Swing Line Advances ” has the meaning ascribed to such term in Section 2.5(e)(i) hereof.
     “ Register ” is defined in Section 13.8(g) hereof.
     “ Reimbursement Obligation(s) ” means the aggregate amount of all unreimbursed drawings under all Letters of Credit (excluding for the avoidance of doubt, reimbursement obligations that are deemed satisfied pursuant to a deemed disbursement under Section 3.6(c) ).
     “ Reinvest ” or “ Reinvestment ” means, with respect to any Net Cash Proceeds received by any Person, the application of such monies to (i) repair, improve or replace any tangible personal property (excluding Inventory), Pipeline Systems or other Real Property of the Credit Parties or any intellectual property reasonably necessary in order to use or benefit from any property or (ii) acquire any such property (excluding Inventory) to be used in the business of such Person or (iii) pay for expenses related to such reinvestment.
     “ Reinvestment Certificate ” is defined in Section 4.8(a) hereof.
     “ Reinvestment Period ” means a 270-day period beginning on the date of the applicable Reinvestment Certificate during which Reinvestment must be completed under Section 4.8(a) of this Agreement.
     “ Request for Advance ” means a Request for Revolving Credit Advance or a Request for Swing Line Advance, as the context may indicate or otherwise require.
     “ Request for Revolving Credit Advance ” means a request for a Revolving Credit Advance issued by the Administrative Borrower under Section 2.3 of this Agreement in the form attached hereto as Exhibit A .
     “ Request for Swing Line Advance ” means a request for a Swing Line Advance issued by the Administrative Borrower under Section 2.5(b) of this Agreement in the form attached hereto as Exhibit D .
     “ Requirement of Law ” means as to any Person, the certificate of incorporation and bylaws, the partnership agreement or other organizational or governing documents of such Person and any law, treaty, rule or regulation or determination of an arbitration or a court or other Governmental Authority, in each case applicable to or binding upon such Person or any of its property or to which such Person or any of its property is subject.
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     “ Responsible Officer ” means, with respect to any Person, the chief executive officer, chief financial officer, treasurer, president, vice president or controller of such Person, or with respect to compliance with financial covenants, the chief financial officer, vice president or the treasurer of such Person, or any other officer of such Person having substantially the same authority and responsibility.
     “ Revolving Credit ” means the revolving credit loans to be advanced to the Borrowers by the applicable Revolving Credit Lenders pursuant to Article 2 hereof, in an aggregate amount (subject to the terms hereof), not to exceed, at any one time outstanding, the Revolving Credit Aggregate Commitment.
     “ Revolving Credit Advance ” means a borrowing requested by the Administrative Borrower and made by the Revolving Credit Lenders under Section 2.1 of this Agreement, including without limitation any readvance, refunding or conversion of such borrowing pursuant to Section 2.3 hereof and any deemed disbursement of an Advance in respect of a Letter of Credit under Section 3.6(c) hereof, and may include, subject to the terms hereof, Eurodollar-based Advances and Base Rate Advances.
     “ Revolving Credit Aggregate Commitment ” means Thirty-Five Million Dollars ($35,000,000), subject to reduction or termination under Sections 2.10 , 2.11 or 9.2 hereof.
     “ Revolving Credit Commitment Amount ” means with respect to any Revolving Credit Lender, (i) if the Revolving Credit Aggregate Commitment has not been terminated, the amount specified opposite such Revolving Credit Lender’s name in the column entitled “ Revolving Credit Commitment Amount ” on Schedule 1.2 , as adjusted from time to time in accordance with the terms hereof; and (ii) if the Revolving Credit Aggregate Commitment has been terminated (whether by maturity, acceleration or otherwise), the amount equal to its Revolving Credit Percentage of the aggregate principal amount outstanding under the Revolving Credit (including the outstanding Letter of Credit Obligations and any outstanding Swing Line Advances).
     “ Revolving Credit Facility Fee ” means the fee payable to the Administrative Agent for distribution to the Revolving Credit Lenders in accordance with Section 2.9 hereof.
     “ Revolving Credit Lenders ” means the financial institutions from time to time parties hereto as lenders of the Revolving Credit.
     “ Revolving Credit Maturity Date ” means the earlier to occur of (i) the date that is three (3) years from the Effective Date, and (ii) the date on which the Revolving Credit Aggregate Commitment shall terminate in accordance with the provisions of this Agreement.
     “ Revolving Credit Notes ” means the revolving credit notes described in Section 2.2 hereof, made by the Borrowers to each of the Revolving Credit Lenders in the form attached hereto as Exhibit B , as such notes may be amended or supplemented from time to time, and any other notes issued in substitution, replacement or renewal thereof from time to time.
     “ Revolving Credit Percentage ” means, with respect to any Revolving Credit Lender, the percentage specified opposite such Revolving Credit Lender’s name in the column entitled
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“ Revolving Credit Percentage ” on Schedule 1.2 , as adjusted from time to time in accordance with the terms hereof.
     “ Security Agreement ” means, collectively, the security agreement(s) executed and delivered by the Borrowers and the Guarantors on the Effective Date pursuant to Section 5.1 hereof, and any such agreements executed and delivered after the Effective Date (whether by execution of a joinder agreement to any existing security agreement or otherwise) pursuant to Section 7.13 hereof or otherwise, substantially in the form of the Security Agreement attached hereto as Exhibit F , as amended, restated or otherwise modified from time to time.
     “ Seller ” means Enbridge Midcoast Energy, L.P., which is the seller under the Acquisition Documents.
     “ State Pipeline Regulatory Agencies ” means, collectively, the Alabama Public Service Commission, the Office of Conservation of the State of Louisiana, the Mississippi Public Service Commission, the Tennessee Regulatory Authority and the Texas Railroad Commission, and “ State Pipeline Regulatory Agency ” means any one of the foregoing.
     “ Subsidiary(ies) ” means any other corporation, association, joint stock company, business trust, limited liability company, partnership or any other business entity of which more than fifty percent (50%) of the outstanding voting stock, share capital, membership, partnership or other interests, as the case may be, is owned either directly or indirectly by any Person or one or more of its Subsidiaries, or the management of which is otherwise controlled, directly, or indirectly through one or more intermediaries, or both, by any Person and/or its Subsidiaries. Unless otherwise specified to the contrary herein or the context otherwise requires, Subsidiary(ies) shall refer to the Subsidiary(ies) of the Administrative Borrower.
     “ Successor Agent ” has the meaning ascribed to such term in Section 12.4 hereof.
     “ Sweep Agreement ” means any agreement relating to the “ Sweep to Loan ” automated system of the Administrative Agent or any other cash management arrangement which the Administrative Borrower and the Administrative Agent have executed for the purposes of effecting the borrowing and repayment of Swing Line Advances.
     “ Swing Line ” means the revolving credit loans to be advanced to the Borrowers by the Swing Line Lender pursuant to Section 2.5 hereof, in an aggregate amount (subject to the terms hereof), not to exceed, at any one time outstanding, the Swing Line Maximum Amount.
     “ Swing Line Advance ” means a borrowing requested by the Administrative Borrower and made by Swing Line Lender pursuant to Section 2.5 hereof and may include, subject to the terms hereof, Quoted Rate-Advances and Base Rate Advances.
     “ Swing Line Lender ” means Comerica Bank in its capacity as lender of the Swing Line under Section 2.5 of this Agreement, or its successor as subsequently designated hereunder.
     “ Swing Line Maximum Amount ” means Five Million Dollars ($5,000,000).
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     “ Swing Line Note ” means the swing line note which may be issued by the Borrowers to Swing Line Lender pursuant to Section 2.5(b)(ii) hereof in the form attached hereto as Exhibit C , as such note may be amended or supplemented from time to time, and any note or notes issued in substitution, replacement or renewal thereof from time to time.
     “ Swing Line Participation Certificate ” means the Swing Line Participation Certificate delivered by the Administrative Agent to each Revolving Credit Lender pursuant to Section 2.5(e)(ii) hereof in the form attached hereto as Exhibit L .
     “ Term Loan ” means the term loan to be made to the Borrowers by the Term Loan Lenders pursuant to Section 4.1 hereof, in the aggregate principal amount of Fifty Million Dollars ($50,000,000).
     “ Term Loan Advance ” means a borrowing requested by the Administrative Borrower and made by the Term Loan Lenders pursuant to Section 4.1 hereof, including without limitation any refunding or conversion of such borrowing pursuant to Section 4.4 hereof, and may include, subject to the terms hereof, Eurodollar-based Advances and Base Rate Advances.
     “ Term Loan Amount ” means with respect to any Term Loan Lender, the amount equal to its Term Loan Percentage of the aggregate principal amount outstanding under the Term Loan.
     “ Term Loan Facility Fee ” means the fee payable to the Administrative Agent for distribution to the Term Loan Lenders in accordance with Section 4.10 hereof.
     “ Term Loan Maturity Date ” means the date that is three (3) years from the Effective Date.
     “ Term Loan Notes ” means the term notes described in Section 4.2(e) hereof, made by the Borrowers to each of the Term Loan Lenders in the form attached hereto as Exhibit J attached hereto, as such notes may be amended or supplemented from time to time, and any other notes issued in substitution, replacement or renewal thereof from time to time.
     “ Term Loan Percentage ” means with respect to any Term Loan Lender, the percentage specified opposite such Term Loan Lender’s name in the column entitled “ Term Loan Percentage ” on Schedule 1.2 , as adjusted from time to time in accordance with the terms hereof.
     “ Term Loan Rate Request ” mean a request for the refunding or conversion of any Advance of a Term Loan submitted by the Administrative Borrower under Section 4.4 of this Agreement in the form of Exhibit K attached hereto.
     “ Test Period ” means, at any time, the four consecutive fiscal quarters of the Administrative Borrower then last ended (in each case taken as one accounting period) for which financial statements have been or are required to be delivered pursuant to this Agreement; provided , however , all financial covenant calculations with respect to the Test Periods ending December 31, 2009, March 31, 2010, June 30, 2010, and September 30, 2010, shall be made by multiplying each figure used in the applicable calculation times a fraction, the numerator of which is 360 and the denominator of which is the number of days elapsed from the date of this Agreement through the end of the applicable fiscal quarter.
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     “ Total Debt to Consolidated EBITDA Ratio ” means, for any Test Period, the ratio of (a) total Debt of the Administrative Borrower and its Subsidiaries for such Test Period to (b) Consolidated EBITDA of the Administrative Borrower and its Subsidiaries for such Test Period.
     “ Ultimate Parent ” means AIM Midstream Holdings, LLC, a Delaware limited liability company.
     “ Uniform Commercial Code ” or “ UCC ” means the Uniform Commercial Code as in effect in the State of New York or any state the laws of which are required to be applied to perfect the security interests in the Collateral.
     “ Unused Revolving Credit Availability ” means, on any date of determination, the amount equal to the Revolving Credit Aggregate Commitment minus (x) the aggregate outstanding principal amount of all Advances (including Swing Line Advances) and (y) the Letter of Credit Obligations.
     “ USA Patriot Act ” is defined in Section 6.7 .
     “ Weighted Percentage ” means with respect to any Lender, its percentage share as set forth in Schedule 1.2 , as such Schedule may be revised by the Administrative Agent from time to time, which percentage shall be calculated as follows:
     (a) as to such Lender, so long as the Revolving Credit Aggregate Commitment has not been terminated, its weighted percentage calculated by dividing (i) the sum of (x) its Revolving Credit Commitment Amount plus (y) its Term Loan Amount, by (ii) the sum of (x) the Revolving Credit Aggregate Commitment plus (y) the aggregate principal amount of Indebtedness outstanding under the Term Loan; and
     (b) as to such Lender, if the Revolving Credit Aggregate Commitment has been terminated (whether by maturity, acceleration or otherwise), its weighted percentage calculated by dividing (i) the sum of (x) its applicable Revolving Credit Commitment Amount plus (y) its Term Loan Amount, by (ii) the sum of the aggregate principal amount outstanding under (x) the Revolving Credit (including any outstanding Letter of Credit Obligations and outstanding Swing Line Advances), and (y) the Term Loan.
     “ Withdrawal Liability ” means liability to a Multiemployer Plan as a result of a complete or partial withdrawal from such Multiemployer Plan, as such terms are defined in Part I of Subtitle E of Title IV of ERISA.
2. REVOLVING CREDIT.
     2.1 Commitment . Subject to the terms and conditions of this Agreement (including without limitation Section 2.3 hereof), each Revolving Credit Lender severally and for itself alone agrees to make Advances of the Revolving Credit in Dollars to the Borrowers from time to time on any Business Day during the period from the Effective Date hereof until (but excluding) the Revolving Credit Maturity Date in an aggregate amount, not to exceed at any one time outstanding such Lender’s Revolving Credit Percentage of the Revolving Credit Aggregate
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Commitment. Subject to the terms and conditions set forth herein, advances, repayments and readvances may be made under the Revolving Credit.
     2.2 Accrual of Interest and Maturity; Evidence of Indebtedness .
     (a) The Borrowers, jointly and severally, hereby unconditionally promise to pay to the Administrative Agent for the account of each Revolving Credit Lender the then unpaid principal amount of each Revolving Credit Advance (plus all accrued and unpaid interest) of such Revolving Credit Lender to the Borrowers on the Revolving Credit Maturity Date and on such other dates and in such other amounts as may be required from time to time pursuant to this Agreement. Subject to the terms and conditions hereof, each Revolving Credit Advance shall, from time to time from and after the date of such Advance (until paid), bear interest at its Applicable Interest Rate.
     (b) Each Revolving Credit Lender shall maintain in accordance with its usual practice an account or accounts evidencing indebtedness of the Borrowers to the appropriate lending office of such Revolving Credit Lender resulting from each Revolving Credit Advance made by such lending office of such Revolving Credit Lender from time to time, including the amounts of principal and interest payable thereon and paid to such Revolving Credit Lender from time to time under this Agreement.
     (c) The Administrative Agent shall maintain the Register pursuant to Section 13.8(g) , and a subaccount therein for each Revolving Credit Lender, in which Register and subaccounts (taken together) shall be recorded (i) the amount of each Revolving Credit Advance made hereunder, the type thereof and each Eurodollar-Interest Period applicable to any Eurodollar-based Advance, (ii) the amount of any principal or interest due and payable or to become due and payable from the Borrowers to each Revolving Credit Lender hereunder in respect of the Revolving Credit Advances and (iii) both the amount of any sum received by the Administrative Agent hereunder from the Borrowers in respect of the Revolving Credit Advances and each Revolving Credit Lender’s share thereof.
     (d) The entries made in the Register maintained pursuant to paragraph (c) of this Section 2.2 shall, absent manifest error, to the extent permitted by applicable law, be prima facie evidence of the existence and amounts of the obligations of the Borrowers therein recorded; provided , however , that the failure of any Revolving Credit Lender or the Administrative Agent to maintain the Register or any account, as applicable, or any error therein, shall not in any manner affect the obligation of the Borrowers to repay the Revolving Credit Advances (and all other amounts owing with respect thereto) made to the Borrowers by the Revolving Credit Lenders in accordance with the terms of this Agreement.
     (e) The Borrowers agree that, upon written request to the Administrative Agent by any Revolving Credit Lender, the Borrowers will execute and deliver, to such Revolving Credit Lender, at the Borrowers’ own expense, a Revolving Credit Note evidencing the outstanding Revolving Credit Advances owing to such Revolving Credit Lender.
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     2.3 Requests for and Refundings and Conversions of Advances . The Administrative Borrower may request an Advance of the Revolving Credit, a refund of any Revolving Credit Advance in the same type of Advance or to convert any Revolving Credit Advance to any other type of Revolving Credit Advance only by delivery to the Administrative Agent of a Request for Revolving Credit Advance executed by an Authorized Signer for the Administrative Borrower, subject to the following:
     (a) each such Request for Revolving Credit Advance shall set forth the information required on the Request for Revolving Credit Advance, including without limitation:
     (i) the proposed date of such Revolving Credit Advance (or the refunding or conversion of an outstanding Revolving Credit Advance), which must be a Business Day;
     (ii) whether such Advance is a new Revolving Credit Advance or a refunding or conversion of an outstanding Revolving Credit Advance; and
     (iii) whether such Revolving Credit Advance is to be a Base Rate Advance or a Eurodollar-based Advance, and, except in the case of a Base Rate Advance, the first Eurodollar-Interest Period applicable thereto.
     (b) each such Request for Revolving Credit Advance shall be delivered to the Administrative Agent by 12:00 p.m. (Detroit, Michigan time) three (3) Business Days prior to the proposed date of the Revolving Credit Advance, except in the case of a Base Rate Advance, for which the Request for Revolving Credit Advance must be delivered by 12:00 p.m. (Detroit, Michigan time) on the proposed date for such Revolving Credit Advance;
     (c) on the proposed date of such Revolving Credit Advance, the sum of (x) the aggregate principal amount of all Revolving Credit Advances and Swing Line Advances outstanding on such date (including, without duplication) the Advances that are deemed to be disbursed by the Administrative Agent under Section 3.6(c) hereof in respect of the Borrowers’ Reimbursement Obligations hereunder), plus (y) the Letter of Credit Obligations as of such date, in each case after giving effect to all outstanding requests for Revolving Credit Advances and Swing Line Advances and for the issuance of any Letters of Credit, shall not exceed the Revolving Credit Aggregate Commitment;
     (d) in the case of a Base Rate Advance, the principal amount of the initial funding of such Advance, as opposed to any refunding or conversion thereof, shall be at least $1,000,000 or the remainder available under the Revolving Credit Aggregate Commitment if less than $1,000,000;
     (e) in the case of a Eurodollar-based Advance, the principal amount of such Advance, plus the amount of any other outstanding Revolving Credit Advance to be then combined therewith having the same Eurodollar-Interest Period, if any, shall be at least $1,000,000 (or a larger integral multiple of $100,000) or the remainder available under
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the Revolving Credit Aggregate Commitment if less than $1,000,000 and at any one time there shall not be in effect more than five (5) different Eurodollar-Interest Periods;
     (f) a Request for Revolving Credit Advance, once delivered to the Administrative Agent, shall not be revocable by the Borrowers and shall constitute a certification by the Borrowers as of the date thereof that:
     (i) all conditions to the making of Revolving Credit Advances set forth in this Agreement have been satisfied and shall remain satisfied to the date of such Revolving Credit Advance (both before and immediately after giving effect to such Revolving Credit Advance);
     (ii) there is no Default or Event of Default in existence, and none will exist upon the making of such Revolving Credit Advance (both before and immediately after giving effect to such Revolving Credit Advance); and
     (iii) the representations and warranties of the Credit Parties contained in this Agreement and the other Loan Documents are true and correct in all material respects and shall be true and correct in all material respects as of the date of the making of such Revolving Credit Advance (both before and immediately after giving effect to such Revolving Credit Advance), other than any representation or warranty that expressly speaks only as of a different date;
The Administrative Agent, acting on behalf of the Revolving Credit Lenders, may also, at its option, lend under this Section 2.3 upon the telephone or email request of an Authorized Signer of the Administrative Borrower to make such requests and, in the event the Administrative Agent, acting on behalf of the Revolving Credit Lenders, makes any such Advance upon a telephone or email request, an Authorized Signer shall fax or deliver by electronic file to the Administrative Agent, on the same day as such telephone or email request, an executed Request for Revolving Credit Advance. The Borrowers hereby authorize the Administrative Agent to disburse Advances to the Administrative Borrower under this Section 2.3 pursuant to the telephone or email instructions of any person purporting to be an Authorized Signer. Notwithstanding the foregoing, the Borrowers acknowledge that the Borrowers shall bear all risk of loss resulting from disbursements made upon any telephone or email request. Each telephone or email request for an Advance from an Authorized Signer for the Administrative Borrower shall constitute a certification of the matters set forth in the Request for Revolving Credit Advance form as of the date of such requested Advance.
     2.4 Disbursement of Advances .
     (a) Upon receiving any Request for Revolving Credit Advance from the Administrative Borrower under Section 2.3 hereof, the Administrative Agent shall promptly notify each Revolving Credit Lender by wire, telex or telephone (confirmed by wire, telecopy or telex) of the amount of such Advance being requested and the date such Revolving Credit Advance is to be made by each Revolving Credit Lender in an amount equal to its Revolving Credit Percentage of such Advance. Unless such Revolving Credit Lender’s commitment to make Revolving Credit Advances hereunder shall have been
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suspended or terminated in accordance with this Agreement, each such Revolving Credit Lender shall make available the amount of its Revolving Credit Percentage of each Revolving Credit Advance in immediately available funds to the Administrative Agent, as follows:
     (i) for Base Rate Advances, at the office of the Administrative Agent located at One Detroit Center, Detroit, Michigan 48226, not later than 1:00 p.m. (Detroit, Michigan time) on the date of such Advance; and
     (ii) for Eurodollar-based Advances, at the Administrative Agent’s Correspondent for the account of the Eurodollar Lending Office of the Administrative Agent, not later than 12:00 p.m. (the time of the Administrative Agent’s Correspondent) on the date of such Advance.
     (b) Subject to submission of an executed Request for Revolving Credit Advance by the Administrative Borrower without exceptions noted in the compliance certification therein, the Administrative Agent shall make available to the Borrowers the aggregate of the amounts so received by it from the Revolving Credit Lenders in like funds and currencies:
     (i) for Base Rate Advances, not later than 4:00 p.m. (Detroit, Michigan time) on the date of such Revolving Credit Advance, by credit to an account of the Administrative Borrower maintained with the Administrative Agent or to such other account or third party as the Administrative Borrower may reasonably direct in writing, provided such direction is timely given; and
     (ii) for Eurodollar-based Advances, not later than 4:00 p.m. (the time of the Administrative Agent’s Correspondent) on the date of such Revolving Credit Advance, by credit to an account of the Administrative Borrower maintained with the Administrative Agent’s Correspondent or to such other account or third-party as the Administrative Borrower may direct, provided such direction is timely given.
     (c) The Administrative Agent shall deliver the documents and papers received by it for the account of each Revolving Credit Lender to such Revolving Credit Lender. Unless the Administrative Agent shall have been notified by any Revolving Credit Lender prior to the date of any proposed Revolving Credit Advance that such Revolving Credit Lender does not intend to make available to the Administrative Agent such Revolving Credit Lender’s Revolving Credit Percentage of such Advance, the Administrative Agent may assume that such Revolving Credit Lender has made such amount available to the Administrative Agent on such date, as aforesaid. The Administrative Agent may, but shall not be obligated to, make available to the Borrowers the amount of such payment in reliance on such assumption. If such amount is not in fact made available to the Administrative Agent by such Revolving Credit Lender, as aforesaid, the Administrative Agent shall be entitled to recover such amount on demand from such Revolving Credit Lender. If such Revolving Credit Lender does not pay such amount forthwith upon the Administrative Agent’s demand therefor and the
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Administrative Agent has in fact made a corresponding amount available to the Borrowers, the Administrative Agent shall promptly notify the Administrative Borrower and the Borrowers shall pay such amount to the Administrative Agent, if such notice is delivered to the Administrative Borrower prior to 1:00 p.m. (Detroit, Michigan time) on a Business Day, on the day such notice is received, and otherwise on the next Business Day, and such amount paid by the Borrowers shall be applied as a prepayment of the Revolving Credit (without any corresponding reduction in the Revolving Credit Aggregate Commitment), reimbursing the Administrative Agent for having funded said amounts on behalf of such Revolving Credit Lender. The Borrowers shall retain their claim against such Revolving Credit Lender with respect to the amounts repaid by it to the Administrative Agent and, if such Revolving Credit Lender subsequently makes such amounts available to the Administrative Agent, the Administrative Agent shall promptly make such amounts available to the Borrowers as a Revolving Credit Advance. The Administrative Agent shall also be entitled to recover from such Revolving Credit Lender or the Borrowers, as the case may be, but without duplication, interest on such amount in respect of each day from the date such amount was made available by the Administrative Agent to the Borrowers, to the date such amount is recovered by the Administrative Agent, at a rate per annum equal to:
     (i) in the case of such Revolving Credit Lender, for the first two (2) Business Days such amount remains unpaid, the Federal Funds Effective Rate, and thereafter, at the rate of interest then applicable to such Revolving Credit Advances; and
     (ii) in the case of the Borrowers, the rate of interest then applicable to such Advance of the Revolving Credit.
Until such Revolving Credit Lender has paid the Administrative Agent such amount, such Revolving Credit Lender shall have no interest in or rights with respect to such Advance for any purpose whatsoever. The obligation of any Revolving Credit Lender to make any Revolving Credit Advance hereunder shall not be affected by the failure of any other Revolving Credit Lender to make any Advance hereunder, and no Revolving Credit Lender shall have any liability to the Borrowers or any of their Subsidiaries, the Administrative Agent, any other Revolving Credit Lender, or any other party for another Revolving Credit Lender’s failure to make any loan or Advance hereunder.
     2.5 Swing Line .
     (a) Swing Line Advances . The Swing Line Lender may, on the terms and subject to the conditions hereinafter set forth (including without limitation Section 2.5(c) hereof), but shall not be required to, make one or more Advances (each such advance being a “ Swing Line Advance ”) to the Borrowers from time to time on any Business Day during the period from the Effective Date hereof until (but excluding) the Revolving Credit Maturity Date in an aggregate amount not to exceed at any one time outstanding the Swing Line Maximum Amount. Subject to the terms set forth herein, advances, repayments and readvances may be made under the Swing Line.
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     (b) Accrual of Interest and Maturity; Evidence of Indebtedness .
     (i) Swing Line Lender shall maintain in accordance with its usual practice an account or accounts evidencing indebtedness of the Borrowers to Swing Line Lender resulting from each Swing Line Advance from time to time, including the amount and date of each Swing Line Advance, its Applicable Interest Rate, its Interest Period, if any, and the amount and date of any repayment made on any Swing Line Advance from time to time. The entries made in such account or accounts of Swing Line Lender shall be prima facie evidence, absent manifest error, of the existence and amounts of the obligations of the Borrowers therein recorded; provided , however , that the failure of Swing Line Lender to maintain such account, as applicable, or any error therein, shall not in any manner affect the obligation of the Borrowers to repay the Swing Line Advances (and all other amounts owing with respect thereto) in accordance with the terms of this Agreement.
     (ii) The Borrowers agree that, upon the written request of Swing Line Lender, the Borrowers will execute and deliver to Swing Line Lender a Swing Line Note.
     (iii) The Borrowers, jointly, severally and unconditionally promise to pay to the Swing Line Lender the then unpaid principal amount of such Swing Line Advance (plus all accrued and unpaid interest) on the Revolving Credit Maturity Date and on such other dates and in such other amounts as may be required from time to time pursuant to this Agreement. Subject to the terms and conditions hereof, each Swing Line Advance shall, from time to time after the date of such Advance (until paid), bear interest at its Applicable Interest Rate.
     (c) Requests for Swing Line Advances . The Administrative Borrower may request a Swing Line Advance by the delivery to Swing Line Lender of a Request for Swing Line Advance executed by an Authorized Signer for the Administrative Borrower, subject to the following:
     (i) each such Request for Swing Line Advance shall set forth the information required on the Request for Advance, including without limitation, (A) the proposed date of such Swing Line Advance, which must be a Business Day, (B) whether such Swing Line Advance is to be a Base Rate Advance or a Quoted Rate Advance, and (C) in the case of a Quoted Rate Advance, the duration of the Interest Period applicable thereto;
     (ii) on the proposed date of such Swing Line Advance, after giving effect to all outstanding requests for Swing Line Advances made by the Administrative Borrower as of the date of determination, the aggregate principal amount of all Swing Line Advances outstanding on such date shall not exceed the Swing Line Maximum Amount;
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     (iii) on the proposed date of such Swing Line Advance, after giving effect to all outstanding requests for Revolving Credit Advances and Swing Line Advances and Letters of Credit requested by the Administrative Borrower on such date of determination (including, without duplication, Advances that are deemed disbursed pursuant to Section 3.6(c) hereof in respect of the Borrowers’ Reimbursement Obligations hereunder), the sum of (x) the aggregate principal amount of all Revolving Credit Advances and the Swing Line Advances outstanding on such date plus (y) the Letter of Credit Obligations on such date shall not exceed the Revolving Credit Aggregate Commitment;
     (iv) (A) in the case of a Swing Line Advance that is a Base Rate Advance, the principal amount of the initial funding of such Advance, as opposed to any refunding or conversion thereof, shall be at least Two Hundred Fifty Thousand Dollars ($250,000) or such lesser amount as may be agreed to by the Swing Line Lender, and (B) in the case of a Swing Line Advance that is a Quoted Rate Advance, the principal amount of such Advance, plus any other outstanding Swing Line Advances to be then combined therewith having the same Interest Period, if any, shall be at least Two Hundred Fifty Thousand Dollars ($250,000) or such lesser amount as may be agreed to by the Swing Line Lender, and at any time there shall not be in effect more than two (2) Interest Rates and Interest Periods;
     (v) each such Request for Swing Line Advance shall be delivered to the Swing Line Lender by 11:00 a.m. (Detroit, Michigan time) on the proposed date of the Swing Line Advance;
     (vi) each Request for Swing Line Advance, once delivered to Swing Line Lender, shall not be revocable by the Borrowers, and shall constitute and include a certification by the Borrowers as of the date thereof that:
     (A) all conditions to the making of Swing Line Advances set forth in this Agreement shall have been satisfied and shall remain satisfied to the date of such Swing Line Advance (both before and immediately after giving effect to such Swing Line Advance);
     (B) there is no Default or Event of Default in existence, and none will exist upon the making of such Swing Line Advance (both before and immediately after giving effect to such Swing Line Advance); and
     (C) the representations and warranties of the Credit Parties contained in this Agreement and the other Loan Documents are true and correct in all material respects and shall be true and correct in all material respect as of the date of the making of such Swing Line Advance (both before and immediately after giving effect to such Swing Line Advance), other than any representation or warranty that expressly speaks only as of a different date;
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     (vii) At the option of the Administrative Agent, subject to revocation by the Administrative Agent at any time and from time to time and so long as the Administrative Agent is the Swing Line Lender, the Borrowers, at their option, may utilize the Administrative Agent’s “ Sweep to Loan ” automated system for obtaining Swing Line Advances and making periodic repayments. At any time during which the “ Sweep to Loan ” system is in effect, Swing Line Advances shall be advanced to fund borrowing needs pursuant to the terms of the Sweep Agreement. Each time a Swing Line Advance is made using the “ Sweep to Loan ” system, the Borrowers shall be deemed to have certified to the Administrative Agent and the Lenders each of the matters set forth in clause (vi) of this Section 2.5(c) . Principal and interest on Swing Line Advances requested, or deemed requested, pursuant to this Section shall be paid pursuant to the terms and conditions of the Sweep Agreement without any deduction, setoff or counterclaim whatsoever. Unless sooner paid pursuant to the provisions hereof or the provisions of the Sweep Agreement, the principal amount of the Swing Loans shall be paid in full, together with accrued interest thereon, on the Revolving Credit Maturity Date. The Administrative Agent may suspend or revoke the Borrowers’ privilege to use the “ Sweep to Loan ” system at any time and from time to time for any reason and, immediately upon any such revocation, the “ Sweep to Loan ” system shall no longer be available to the Borrowers for the funding of Swing Line Advances hereunder (or otherwise), and the regular procedures set forth in this Section 2.5 for the making of Swing Line Advances shall be deemed immediately to apply. The Administrative Agent may, at its option, also elect to make Swing Line Advances upon the Administrative Borrower’s telephone requests on the basis set forth in the last paragraph of Section 2.3 , provided that the Borrowers comply with the provisions set forth in this Section 2.5 .
     (d) Disbursement of Swing Line Advances . Upon receiving any executed Request for Swing Line Advance from the Administrative Borrower and the satisfaction of the conditions set forth in Section 2.5(c) hereof, Swing Line Lender shall make available to the Borrowers the amount so requested in Dollars not later than 4:00 p.m. (Detroit, Michigan time) on the date of such Advance, by credit to an account of the Administrative Borrower maintained with the Administrative Agent or to such other account or third party as the Administrative Borrower may reasonably direct in writing, subject to applicable law, provided such direction is timely given. Swing Line Lender shall promptly notify the Administrative Agent of any Swing Line Advance by telephone, telex or telecopier.
     (e) Refunding of or Participation Interest in Swing Line Advances .
     (i) The Administrative Agent, at any time in its sole and absolute discretion, may, in each case on behalf of the Borrowers (which hereby irrevocably direct the Administrative Agent to act on their behalf) request each of the Revolving Credit Lenders (including the Swing Line Lender in its capacity as a Revolving Credit Lender) to make an Advance of the Revolving Credit to the Borrowers, in an amount equal to such Revolving Credit Lender’s Revolving Credit Percentage of the aggregate principal amount of the Swing Line Advances
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outstanding on the date such notice is given (the “ Refunded Swing Line Advances ”); provided , however , that the Swing Line Advances carried at the Quoted Rate which are refunded with Revolving Credit Advances at the request of the Swing Line Lender at a time when no Default or Event of Default has occurred and is continuing shall not be subject to Section 11.1 and no losses, costs or expenses may be assessed by the Swing Line Lender against the Borrowers or the Revolving Credit Lenders as a consequence of such refunding. The applicable Revolving Credit Advances used to refund any Swing Line Advances shall be Base Rate Advances. In connection with the making of any such Refunded Swing Line Advances or the purchase of a participation interest in Swing Line Advances under Section 2.5(e)(ii) hereof, the Swing Line Lender shall retain its claim against the Borrowers for any unpaid interest or fees in respect thereof accrued to the date of such refunding. Unless any of the events described in Section 9.1(i) hereof shall have occurred (in which event the procedures of Section 2.5(e)(ii) shall apply) and regardless of whether the conditions precedent set forth in this Agreement to the making of a Revolving Credit Advance are then satisfied (but subject to Section 2.5(e)(iii) ), each Revolving Credit Lender shall make the proceeds of its Revolving Credit Advance available to the Administrative Agent for the benefit of the Swing Line Lender at the office of the Administrative Agent specified in Section 2.4(a) hereof prior to 11:00 a.m. (Detroit, Michigan time) on the Business Day next succeeding the date such notice is given, in immediately available funds. The proceeds of such Revolving Credit Advances shall be immediately applied to repay the Refunded Swing Line Advances, subject to Section 11.1 hereof.
     (ii) If, prior to the making of an Advance of the Revolving Credit pursuant to Section 2.5(e)(i) hereof, one of the events described in Section 9.1(i) hereof shall have occurred, each Revolving Credit Lender will, on the date such Advance of the Revolving Credit was to have been made, purchase from the Swing Line Lender an undivided participating interest in each Swing Line Advance that was to have been refunded in an amount equal to its Revolving Credit Percentage of such Swing Line Advance. Each Revolving Credit Lender within the time periods specified in Section 2.5(e)(i) hereof, as applicable, shall immediately transfer to the Administrative Agent, for the benefit of the Swing Line Lender, in immediately available funds, an amount equal to its Revolving Credit Percentage of the aggregate principal amount of all Swing Line Advances outstanding as of such date. Upon receipt thereof, the Administrative Agent will deliver to such Revolving Credit Lender a Swing Line Participation Certificate evidencing such participation.
     (iii) Each Revolving Credit Lender’s obligation to make Revolving Credit Advances to refund Swing Line Advances, and to purchase participation interests, in accordance with Section 2.5(e)(i) and (ii) , respectively, shall be absolute and unconditional and shall not be affected by any circumstance, including, without limitation, (A) any set-off, counterclaim, recoupment, defense or other right which such Revolving Credit Lender may have against Swing Line Lender, the Borrowers or any other Person for any reason whatsoever; (B) the
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occurrence or continuance of any Default or Event of Default; (C) any adverse change in the condition (financial or otherwise) of any Borrower or any other Person; (D) any breach of this Agreement or any other Loan Document by any Borrower or any other Person; (E) any inability of the Borrowers to satisfy the conditions precedent to borrowing set forth in this Agreement on the date upon which such Revolving Credit Advance is to be made or such participating interest is to be purchased; (F) the termination of the Revolving Credit Aggregate Commitment hereunder; or (G) any other circumstance, happening or event whatsoever, whether or not similar to any of the foregoing. If any Revolving Credit Lender does not make available to the Administrative Agent the amount required pursuant to Section 2.5(e)(i) or (ii) hereof, as the case may be, the Administrative Agent on behalf of the Swing Line Lender, shall be entitled to recover such amount on demand from such Revolving Credit Lender, together with interest thereon for each day from the date of non-payment until such amount is paid in full (x) for the first two (2) Business Days such amount remains unpaid, at the Federal Funds Effective Rate and (y) thereafter, at the rate of interest then applicable to such Swing Line Advances. The obligation of any Revolving Credit Lender to make available its pro rata portion of the amounts required pursuant to Section 2.5(e)(i) or (ii) hereof shall not be affected by the failure of any other Revolving Credit Lender to make such amounts available, and no Revolving Credit Lender shall have any liability to any Credit Party, the Administrative Agent, the Swing Line Lender, or any other Revolving Credit Lender or any other party for another Revolving Credit Lender’s failure to make available the amounts required under Section 2.5(e)(i) or (ii) hereof.
     (iv) Notwithstanding the foregoing, no Revolving Credit Lender shall be required to make any Revolving Credit Advance to refund a Swing Line Advance or to purchase a participation in a Swing Line Advance if at least two (2) Business Days prior to the making of such Swing Line Advance by the Swing Line Lender, the officers of the Swing Line Lender immediately responsible for matters concerning this Agreement shall have received written notice from the Administrative Agent or any Lender that Swing Line Advances should be suspended based on the occurrence and continuance of a Default or Event of Default and stating that such notice is a “ notice of default ”; provided , however , that the obligation of the Revolving Credit Lenders to make refund such Swing Line Advance or purchase a participation in such Swing Line Advance) shall be reinstated upon the date on which such Default or Event of Default has been waived by the requisite Lenders.
     2.6 Interest Payments; Default Interest .
     (a) Interest on the unpaid balance of all Base Rate Advances of the Revolving Credit and the Swing Line from time to time outstanding shall accrue from the date of such Advance to the date repaid, at a per annum interest rate equal to the Base Rate, and shall be payable in immediately available funds commencing on February 1, 2010, and on the first day of each February, May, August and November thereafter (in respect of the preceding three months or any portion thereof). Whenever any payment under this
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Section 2.6(a) shall become due on a day which is not a Business Day, the date for payment thereof shall be extended to the next Business Day. Interest accruing at the Base Rate shall be computed on the basis of a 360 day year and assessed for the actual number of days elapsed, and in such computation effect shall be given to any change in the interest rate resulting from a change in the Base Rate on the date of such change in the Base Rate.
     (b) Interest on each Eurodollar-based Advance of the Revolving Credit shall accrue at its Eurodollar-based Rate and shall be payable in immediately available funds on the last day of the Eurodollar-Interest Period applicable thereto. Interest accruing at the Eurodollar-based Rate shall be computed on the basis of a 360 day year and assessed for the actual number of days elapsed from the first day of the Eurodollar-Interest Period applicable thereto to but not including the last day thereof.
     (c) Interest on each Quoted Rate Advance of the Swing Line shall accrue at its Quoted Rate and shall be payable in immediately available funds on the last day of the Interest Period applicable thereto. Interest accruing at the Quoted Rate shall be computed on the basis of a 360-day year and assessed for the actual number of days elapsed from the first day of the Interest Period applicable thereto to, but not including, the last day thereof.
     (d) Notwithstanding anything to the contrary in the preceding sections, all accrued and unpaid interest on any Revolving Credit Advance refunded or converted pursuant to Section 2.3 hereof and any Swing Line Advance refunded pursuant to Section 2.5(e) hereof, shall be due and payable in full on the date such Advance is refunded or converted.
     (e) In the case of any Event of Default under Section 9.1(i) , immediately upon the occurrence thereof, and in the case of any other Event of Default, immediately upon receipt by the Administrative Agent of notice from the Majority Revolving Credit Lenders, interest shall accrue and be payable on demand on all Revolving Credit Advances and Swing Line Advances from time to time outstanding at a per annum rate equal to the Applicable Interest Rate in respect of each such Advance plus, in the case of Eurodollar-based Advances and Quoted Rate Advances, two percent (2%) for the remainder of the then existing Interest Period, if any, and at all other such times, and for all Base Rate Advances from time to time outstanding, at a per annum rate equal to the Base Rate plus two percent (2%).
     2.7 Optional Prepayments .
     (a) (i) The Borrowers may prepay all or part of the outstanding principal of any Base Rate Advance(s) of the Revolving Credit at any time, provided that , unless the “ Sweep to Loan ” system shall be in effect in respect of the Revolving Credit, after giving effect to any partial prepayment, the aggregate balance of Base Rate Advance(s) of the Revolving Credit remaining outstanding shall be at least One Million Dollars ($1,000,000), and (ii) subject to Section 2.10(c) hereof, the Borrowers may prepay all or part of the outstanding principal of any Eurodollar-based Advance of the Revolving
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Credit at any time (subject to not less than five (5) Business Day’s notice to the Administrative Agent), provided that , after giving effect to any partial prepayment, the unpaid portion of such Advance which is to be refunded or converted under Section 2.3 hereof shall be at least One Million and Dollars ($1,000,000).
     (b) (i) The Borrowers may prepay all or part of the outstanding principal of any Swing Line Advance carried at the Base Rate at any time, provided that , after giving effect to any partial prepayment, the aggregate balance of such Base Rate Advances remaining outstanding shall be at least Five Hundred Thousand Dollars ($500,000) and (ii) subject to Section 2.10(c) hereof, the Borrowers may prepay all or part of the outstanding principal of any Swing Line Advance carried at the Quoted Rate at any time (subject to not less than one (1) day’s notice to the Swing Line Lender), provided that , after giving effect to any partial prepayment, the aggregate balance of such Quoted Rate Swing Line Advances remaining outstanding shall be at least Two Hundred Fifty Thousand Dollars ($250,000).
     (c) Any prepayment of a Base Rate Advance made in accordance with this Section shall be without premium or penalty and any prepayment of any other type of Advance shall be subject to the provisions of Section 11.1 hereof, but otherwise without premium or penalty.
     2.8 Base Rate Advance in Absence of Election or Upon Default . If, (a) as to any outstanding Eurodollar-based Advance of the Revolving Credit or any outstanding Quoted Rate Advance of the Swing Line, the Administrative Agent has not received payment of all outstanding principal and accrued interest on the last day of the Interest Period applicable thereto, or does not receive a timely Request for Advance meeting the requirements of Section 2.3 or 2.5 hereof with respect to the refunding or conversion of such Advance, or (b) if on the last day of the applicable Interest Period a Default or an Event of Default shall have occurred and be continuing, then, on the last day of the applicable Interest Period the principal amount of any Eurodollar-based Advance or Quoted Rate Advance, as the case may be, which has not been prepaid shall, absent a contrary election of the Majority Revolving Credit Lenders, be converted automatically to a Base Rate Advance and the Administrative Agent shall thereafter promptly notify the Administrative Borrower of said action. All accrued and unpaid interest on any Advance converted to a Base Rate Advance under this Section 2.8 shall be due and payable in full on the date such Advance is converted.
     2.9 Revolving Credit Facility Fee . From the Closing Date to the Revolving Credit Maturity Date, the Borrowers jointly and severally agree to pay to the Administrative Agent for distribution to the Revolving Credit Lenders pro-rata in accordance with their respective Revolving Credit Percentages, a Revolving Credit Facility Fee in arrears from the Closing Date through the earlier of December 10, 2009, and the Effective Date, in advance commencing on the Effective Date for the period from the Effective Date through February 1, 2010, and in advance on the first day of each February, May, August and November thereafter (in respect of the following three months or any portion thereof). The Revolving Credit Facility Fee payable to each Revolving Credit Lender shall be determined by multiplying the Applicable Fee Percentage times the Revolving Credit Aggregate Commitment then in effect (whether used or unused). The Revolving Credit Facility Fee shall be computed on the basis of a year of three hundred sixty
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(360) days and assessed for the actual number of days elapsed. Whenever any payment of the Revolving Credit Facility Fee shall be due on a day which is not a Business Day, the date for payment thereof shall be extended to the next Business Day. Upon receipt of such payment, the Administrative Agent shall make prompt payment to each Revolving Credit Lender of its share of the Revolving Credit Facility Fee based upon its respective Revolving Credit Percentage. It is expressly understood that the Revolving Credit Facility Fees described in this Section are not refundable.
     2.10 Mandatory Repayment of Revolving Credit Advances .
     (a) If at any time and for any reason the aggregate outstanding principal amount of Revolving Credit Advances plus Swing Line Advances, plus the outstanding Letter of Credit Obligations, shall exceed the Revolving Credit Aggregate Commitment, the Borrowers shall immediately reduce any pending request for a Revolving Credit Advance on such day by the amount of such excess and, to the extent any excess remains thereafter, repay any Revolving Credit Advances and Swing Line Advances in an amount equal to the lesser of the outstanding amount of such Advances and the amount of such remaining excess, with such amounts to be applied between the Revolving Credit Advances and Swing Line Advances as determined by the Administrative Agent and then, to the extent that any excess remains after payment in full of all Revolving Credit Advances and Swing Line Advances, to provide cash collateral in support of any Letter of Credit Obligations in an amount equal to the lesser of (x) 110% of the amount of such Letter of Credit Obligations and (y) the amount of such remaining excess, with such cash collateral to be provided on the basis set forth in Section 9.2 hereof. The Borrowers acknowledge that, in connection with any repayment required hereunder, they are also responsible for the reimbursement of any prepayment or other costs required under Section 11.1 hereof. Any payments made pursuant to this Section shall be applied first to outstanding Base Rate Advances under the Revolving Credit, next to Swing Line Advances carried at the Base Rate and then to Eurodollar-based Advances of the Revolving Credit, and then to Swing Line Advances carried at the Quoted Rate.
     (b) Upon the payment in full of the Term Loan, any prepayments required to be made on the Term Loan pursuant to Sections 4.8(a) and (b) of this Agreement shall instead be applied to prepay any amounts outstanding under the Revolving Credit, resulting in a permanent reduction in the Revolving Credit Aggregate Commitment. Immediately upon receipt by any Credit Party of Net Cash Proceeds from the issuance of any Equity Interests of such Person (other than (i) Equity Interests under any stock option or employee incentive plans listed on Schedule 7.13 hereto (or any successor plans) and (ii) Equity Interests issued for the purpose of curing an Event of Default hereunder, as determined by the Administrative Agent in its reasonable discretion, which Net Cash Proceeds shall be prepaid in accordance with Section 4.8(b) hereof and the first sentence of this Section 2.10(b) ) after the Effective Date, the Borrowers shall prepay any amounts outstanding under the Revolving Credit by an amount equal to fifty percent (50%) of such Net Cash Proceeds except to the extent such Equity Interests are issued as consideration in any Permitted Acquisition, in which case no prepayment shall be required. Subject to Section 10.2 hereof, any payments made pursuant to this Section shall be applied first to outstanding Base Rate Advances under the Revolving Credit, next
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to Swing Line Advances carried at the Base Rate, next to Eurodollar-based Advances under the Revolving Credit, and then to Swing Line Advances carried at the Quoted Rate. If any amounts remain thereafter, a portion of such prepayment equivalent to the undrawn amount of any outstanding Letters of Credit shall be held by the Issuing Lender or the Administrative Agent as cash collateral for the Reimbursement Obligations, with any additional prepayment monies being applied to any Fees, costs or expenses due and outstanding under this Agreement, and with the remainder of such prepayment thereafter being returned to the Borrowers.
     (c) To the extent that, on the date any mandatory repayment of the Revolving Credit Advances under this Section 2.10 or payment pursuant to the terms of any of the Loan Documents is due, the Indebtedness under the Revolving Credit or any other Indebtedness to be prepaid is being carried, in whole or in part, at the Eurodollar-based Rate and no Default or Event of Default has occurred and is continuing, the Borrowers may deposit the amount of such mandatory prepayment in a cash collateral account to be held by the Administrative Agent, for and on behalf of the Revolving Credit Lenders, on such terms and conditions as are reasonably acceptable to the Administrative Agent and upon such deposit the obligation of the Borrowers to make such mandatory prepayment shall be deemed satisfied. Subject to the terms and conditions of said cash collateral account, sums on deposit in said cash collateral account shall be applied (until exhausted) to reduce the principal balance of the Revolving Credit on the last day of each Eurodollar-Interest Period attributable to the Eurodollar-based Advances of such Revolving Advance, thereby avoiding breakage costs under Section 11.1 hereof; provided , however , that if a Default or Event of Default shall have occurred at any time while sums are on deposit in the cash collateral account, the Administrative Agent may, in its sole discretion, elect to apply such sums to reduce the principal balance of such Eurodollar-based Advances prior to the last day of the applicable Eurodollar-Interest Period, and the Borrowers will be obligated to pay any resulting breakage costs under Section 11.1 .
     2.11 Optional Reduction or Termination of Revolving Credit Aggregate Commitment . The Administrative Borrower may, upon at least five (5) Business Days’ prior written notice to the Administrative Agent, permanently reduce the Revolving Credit Aggregate Commitment in whole at any time, or in part from time to time, without premium or penalty, provided that: (i) each partial reduction of the Revolving Credit Aggregate Commitment shall be in an aggregate amount equal to Five Million Dollars ($5,000,000) or a larger integral multiple of One Hundred Thousand Dollars ($100,000); (ii) each reduction shall be accompanied by the payment of the Revolving Credit Facility Fee, if any, accrued and unpaid to the date of such reduction; (iii) the Borrowers shall prepay in accordance with the terms hereof the amount, if any, by which the aggregate unpaid principal amount of Revolving Credit Advances and Swing Line Advances (including, without duplication, any deemed Advances made under Section 3.6 hereof) outstanding hereunder, plus the Letter of Credit Obligations, exceeds the amount of the then applicable Revolving Credit Aggregate Commitment as so reduced, together with interest thereon to the date of prepayment; (iv) no reduction shall reduce the Revolving Credit Aggregate Commitment to an amount which is less than the aggregate undrawn amount of any Letters of Credit outstanding at such time; and (v) no such reduction shall reduce the Swing Line Maximum Amount unless the Administrative Borrower so elects, provided that the Swing Line
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Maximum Amount shall at no time be greater than the Revolving Credit Aggregate Commitment; provided , however , that if the termination or reduction of the Revolving Credit Aggregate Commitment requires the prepayment of a Eurodollar-based Advance or a Quoted Rate Advance and such termination or reduction is made on a day other than the last Business Day of the then current Interest Period applicable to such Eurodollar-based Advance or such Quoted Rate Advance, then, pursuant to Section 11.1 , the Borrowers shall compensate the Revolving Credit Lenders and/or the Swing Line Lender for any losses or, so long as no Default or Event of Default has occurred and is continuing, the Borrowers may deposit the amount of such prepayment in a collateral account as provided in Section 2.10(c) . Reductions of the Revolving Credit Aggregate Commitment and any accompanying prepayments of Advances of the Revolving Credit shall be distributed by the Administrative Agent to each Revolving Credit Lender in accordance with such Revolving Credit Lender’s Revolving Percentage thereof, and will not be available for reinstatement by or readvance to the Borrowers, and any accompanying prepayments of Advances of the Swing Line shall be distributed by the Administrative Agent to the Swing Line Lender and will not be available for reinstatement by or readvance to the Borrowers. Any reductions of the Revolving Credit Aggregate Commitment hereunder shall reduce each Revolving Credit Lender’s portion thereof proportionately (based on the applicable Revolving Credit Percentages), and shall be permanent and irrevocable. Any payments made pursuant to this Section shall be applied first to outstanding Base Rate Advances under the Revolving Credit, next to Swing Line Advances carried at the Base Rate and then to Eurodollar-based Advances of the Revolving Credit, and then to Swing Line Advances carried at the Quoted Rate.
     2.12 Use of Proceeds of Advances . Advances of the Revolving Credit shall be used to finance the Acquisition and working capital and other lawful corporate purposes.
3. LETTERS OF CREDIT.
     3.1 Letters of Credit . Subject to the terms and conditions of this Agreement, Issuing Lender may through the Issuing Office, at any time and from time to time from and after the date hereof until thirty (30) days prior to the Revolving Credit Maturity Date, upon the written request of the Administrative Borrower accompanied by a duly executed Letter of Credit Agreement and such other documentation related to the requested Letter of Credit as the Issuing Lender may require, issue Letters of Credit in Dollars for the account of the Borrowers, in an aggregate amount for all Letters of Credit issued hereunder at any one time outstanding not to exceed the Letter of Credit Maximum Amount. Each Letter of Credit shall be in a minimum face amount of One Hundred Thousand Dollars ($100,000) (or such lesser amount as may be agreed to by Issuing Lender) and each Letter of Credit (including any renewal thereof) shall expire not later than the first to occur of (i) one year after the date of issuance thereof and (ii) ten (10) Business Days prior to the Revolving Credit Maturity Date in effect on the date of issuance thereof; provided, however, to the extent the Borrowers cash collateralize any Letter of Credit at least one hundred eighty (180) days prior to the Revolving Credit Maturity Date in cases where such Letter of Credit could be automatically renewed beyond such Revolving Credit Maturity Date, such letter of Credit may contain a customary “evergreen” provision relating to the renewal thereof. The submission of all applications in respect of and the issuance of each Letter of Credit hereunder shall be subject in all respects to the International Standby Practices 98, and any successor documentation thereto and to the extent not inconsistent therewith, the laws of the
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State of New York. In the event of any conflict between this Agreement and any Letter of Credit Document other than any Letter of Credit, this Agreement shall control.
     3.2 Conditions to Issuance . No Letter of Credit shall be issued (including the renewal or extension of any Letter of Credit previously issued) at the request and for the account of the Borrowers unless, as of the date of issuance (or renewal or extension) of such Letter of Credit:
     (a) (i) after giving effect to the Letter of Credit requested, the Letter of Credit Obligations do not exceed the Letter of Credit Maximum Amount; and (ii) after giving effect to the Letter of Credit requested, the Letter of Credit Obligations on such date plus the aggregate amount of all Revolving Credit Advances and Swing Line Advances (including all Advances deemed disbursed by the Administrative Agent under Section 3.6(c) hereof in respect of the Borrowers’ Reimbursement Obligations) hereunder requested or outstanding on such date do not exceed the Revolving Credit Aggregate Commitment;
     (b) the representations and warranties of the Credit Parties contained in this Agreement and the other Loan Documents are true and correct in all material respects and shall be true and correct in all material respects as of date of the issuance of such Letter of Credit (both before and immediately after the issuance of such Letter of Credit), other than any representation or warranty that expressly speaks only as of a different date;
     (c) there is no Default or Event of Default in existence, and none will exist upon the issuance of such Letter of Credit;
     (d) the Administrative Borrower shall have delivered to Issuing Lender at its Issuing Office, not less than three (3) Business Days prior to the requested date for issuance (or such shorter time as the Issuing Lender, in its sole discretion, may permit), the Letter of Credit Agreement related thereto, together with such other documents and materials as may be required pursuant to the terms thereof, and the terms of the proposed Letter of Credit shall be reasonably satisfactory to Issuing Lender;
     (e) no order, judgment or decree of any court, arbitrator or Governmental Authority shall purport by its terms to enjoin or restrain Issuing Lender from issuing the Letter of Credit requested, or any Revolving Credit Lender from taking an assignment of its Revolving Credit Percentage thereof pursuant to Section 3.6 hereof, and no law, rule, regulation, request or directive having the force of law shall prohibit the Issuing Lender from issuing, or any Revolving Credit Lender from taking an assignment of its Revolving Credit Percentage of, the Letter of Credit requested or letters of credit generally;
     (f) there shall have been (i) no introduction of or change in the interpretation of any law or regulation, (ii) no declaration of a general banking moratorium by banking authorities in the United States, New York or the respective jurisdictions in which the Revolving Credit Lenders, any Borrower and the beneficiary of the requested Letter of Credit are located, and (iii) no establishment of any new restrictions by any central bank or other governmental agency or authority on transactions involving letters of credit or on banks generally that, in any case described in this clause (f) , would make it unlawful or
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unduly burdensome for the Issuing Lender to issue or any Revolving Credit Lender to take an assignment of its Revolving Credit Percentage of the requested Letter of Credit or letters of credit generally;
     (g) if any Revolving Credit Lender is an Impaired Lender, the Issuing Lender has entered into arrangements satisfactory to it to eliminate the Issuing Lender’s risk with respect to the participation in Letters of Credit by all such Impaired Lenders, including, without limitation, the creation of a cash collateral account or delivery of other security by the Borrowers to assure payment of such Impaired Lender’s Revolving Credit Percentage of all outstanding Letter of Credit Obligations; and
     (h) Issuing Lender shall have received the issuance fees required in connection with the issuance of such Letter of Credit pursuant to Section 3.4 hereof.
Each Letter of Credit Agreement submitted to Issuing Lender pursuant hereto shall constitute the certification by the Borrowers of the matters set forth in Section 5.2 hereof. The Administrative Agent shall be entitled to rely on such certification without any duty of inquiry.
     3.3 Notice . The Issuing Lender shall deliver to the Administrative Agent, concurrently with or promptly following its issuance of any Letter of Credit, a true and complete copy of each Letter of Credit. Promptly upon its receipt thereof, the Administrative Agent shall give notice, substantially in the form attached as Exhibit E , to each Revolving Credit Lender of the issuance of each Letter of Credit, specifying the amount thereof and the amount of such Revolving Credit Lender’s Revolving Credit Percentage thereof.
     3.4 Letter of Credit Fees; Increased Costs .
     (a) The Borrowers shall pay letter of credit fees as follows:
     (i) A per annum letter of credit fee with respect to the undrawn amount of each Letter of Credit issued pursuant hereto (based on the amount of each Letter of Credit) in the amount of the Applicable Fee Percentage (determined with reference to Schedule 1.1 to this Agreement) shall be paid to the Administrative Agent for distribution to the Revolving Credit Lenders in accordance with their Revolving Credit Percentages.
     (ii) A letter of credit facing fee on the face amount of each Letter of Credit shall be paid to the Administrative Agent for distribution to the Issuing Lender for its own account, in accordance with the terms of the applicable Fee Letter.
     (b) All payments by the Borrowers to the Administrative Agent for distribution to the Issuing Lender or the Revolving Credit Lenders under this Section 3.4 shall be made in Dollars in immediately available funds at the Issuing Office or such other office of the Administrative Agent as may be designated from time to time by written notice to the Administrative Borrower by the Administrative Agent. The fees described in clauses (a)(i) and (ii) above (i) shall be nonrefundable under all circumstances, (ii) in the case of fees due under clause (a)(i) above, shall be payable
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semi-annually in advance and (iii) in the case of fees due under clause (a)(ii) above, shall be annually in advance. The fees due under clause (a)(i) above shall be determined by multiplying the Applicable Fee Percentage times the undrawn amount of the face amount of each such Letter of Credit on the date of determination, and shall be calculated on the basis of a 360 day year and assessed for the actual number of days from the date of the issuance thereof to the stated expiration thereof. The parties hereto acknowledge that, unless the Issuing Lender otherwise agrees, any material amendment and any extension to a Letter of Credit issued hereunder shall be treated as a new Letter of Credit for the purposes of the letter of credit facing fee.
     (c) If any change in any law or regulation or in the interpretation thereof by any court or administrative or Governmental Authority charged with the administration thereof, adopted after the date hereof, shall either (i) impose, modify or cause to be deemed applicable any reserve, special deposit, limitation or similar requirement against letters of credit issued or participated in by, or assets held by, or deposits in or for the account of, Issuing Lender or any Revolving Credit Lender or (ii) impose on Issuing Lender or any Revolving Credit Lender any other condition regarding this Agreement, the Letters of Credit or any participations in such Letters of Credit, and the result of any event referred to in clause (i) or (ii) above shall be to increase the cost or expense to Issuing Lender or such Revolving Credit Lender of issuing or maintaining or participating in any of the Letters of Credit (which increase in cost or expense shall be determined by the Issuing Lender’s or such Revolving Credit Lender’s reasonable allocation of the aggregate of such cost increases and expenses resulting from such events), then, upon demand by the Issuing Lender or such Revolving Credit Lender, as the case may be, the Borrowers shall, within thirty (30) days following demand for payment, pay to Issuing Lender or such Revolving Credit Lender, as the case may be, from time to time as specified by the Issuing Lender or such Revolving Credit Lender, additional amounts which shall be sufficient to compensate the Issuing Lender or such Revolving Credit Lender for such increased cost and expense incurred by the Issuing Lender or such Revolving Credit Lender (together with interest on each such amount from ten days after the date such payment is due until payment in full thereof at the Base Rate), provided that if the Issuing Lender or such Revolving Credit Lender could take any reasonable action, without cost or administrative or other burden or restriction to such Lender, to mitigate or eliminate such cost or expense, it agrees to do so within a reasonable time after becoming aware of the foregoing matters. Each demand for payment under this Section 3.4(c) shall be accompanied by a certificate of Issuing Lender or the applicable Revolving Credit Lender setting forth the amount of such increased cost or expense incurred by the Issuing Lender or such Revolving Credit Lender, as the case may be, as a result of any event mentioned in clause (i) or (ii) above, and in reasonable detail, the methodology for calculating and the calculation of such amount, which certificate shall be prepared in good faith and shall be conclusive evidence, absent manifest error, as to the amount thereof.
     3.5 Other Fees . In connection with the Letters of Credit, and in addition to the Letter of Credit Fees, the Borrowers jointly and severally agree to pay, for the sole account of the Issuing Lender, standard documentation, administration, payment and cancellation charges assessed by Issuing Lender or the Issuing Office, at the times, in the amounts and on the terms
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set forth or to be set forth from time to time in the standard fee schedule of the Issuing Office in effect from time to time.
     3.6 Participation Interests in and Drawings and Demands for Payment Under Letters of Credit .
     (a) Upon issuance by the Issuing Lender of each Letter of Credit hereunder (and on the Effective Date with respect to each Existing Letter of Credit), each Revolving Credit Lender shall automatically acquire a pro rata participation interest in such Letter of Credit and each related Letter of Credit Payment based on its respective Revolving Credit Percentage.
     (b) If the Issuing Lender shall honor a draft or other demand for payment presented or made under any Letter of Credit, the Borrowers agree to pay to the Issuing Lender an amount equal to the amount paid by the Issuing Lender in respect of such draft or other demand under such Letter of Credit and all reasonable expenses paid or incurred by the Administrative Agent relative thereto not later than 1:00 p.m. (Detroit, Michigan time), in Dollars, on (i) the Business Day that the Administrative Borrower received notice of such presentment and honor, if such notice is received prior to 11:00 a.m. (Detroit, Michigan time) or (ii) the Business Day immediately following the day that the Administrative Borrower received such notice, if such notice is received after 11:00 a.m. (Detroit, Michigan time).
     (c) If the Issuing Lender shall honor a draft or other demand for payment presented or made under any Letter of Credit, but the Borrowers do not reimburse the Issuing Lender as required under clause (b) above and the Revolving Credit Aggregate Commitment has not been terminated (whether by maturity, acceleration or otherwise), the Borrowers shall be deemed to have immediately requested that the Revolving Credit Lenders make a Base Rate Advance of the Revolving Credit (which Advance may be subsequently converted at any time into a Eurodollar-based Advance pursuant to Section 2.3 hereof) in the principal amount equal to the amount paid by the Issuing Lender in respect of such draft or other demand under such Letter of Credit and all reasonable expenses paid or incurred by the Administrative Agent relative thereto. The Administrative Agent will promptly notify the Revolving Credit Lenders of such deemed request, and each such Lender shall make available to the Administrative Agent an amount equal to its pro rata share (based on its Revolving Credit Percentage) of the amount of such Advance.
     (d) If the Issuing Lender shall honor a draft or other demand for payment presented or made under any Letter of Credit, but the Borrowers do not reimburse the Issuing Lender as required under clause (b) above, and (i) the Revolving Credit Aggregate Commitment has been terminated (whether by maturity, acceleration or otherwise), or (ii) any reimbursement received by the Issuing Lender from the Borrowers is or must be returned or rescinded upon or during any bankruptcy or reorganization of any Credit Party or otherwise, then the Administrative Agent shall notify each Revolving Credit Lender, and each Revolving Credit Lender will be obligated to pay the Administrative Agent for the account of the Issuing Lender its pro rata share (based on its
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Revolving Credit Percentage) of the amount paid by the Issuing Lender in respect of such draft or other demand under such Letter of Credit and all reasonable expenses paid or incurred by the Administrative Agent relative thereto (but no such payment shall diminish the obligations of the Borrowers hereunder). Upon receipt thereof, the Administrative Agent will deliver to such Revolving Credit Lender a participation certificate evidencing its participation interest in respect of such payment and expenses. To the extent that a Revolving Credit Lender fails to make such amount available to the Administrative Agent by 11:00 am (Detroit, Michigan time) on the Business Day next succeeding the date such notice is given, such Revolving Credit Lender shall pay interest on such amount in respect of each day from the date such amount was required to be paid, to the date paid to the Administrative Agent, at a rate per annum equal to the Federal Funds Effective Rate. The failure of any Revolving Credit Lender to make its pro rata portion of any such amount available under to the Administrative Agent shall not relieve any other Revolving Credit Lender of its obligation to make available its pro rata portion of such amount, but no Revolving Credit Lender shall be responsible for failure of any other Revolving Credit Lender to make such pro rata portion available to the Administrative Agent.
     (e) In the case of any Advance made under this Section 3.6 , each such Advance shall be disbursed notwithstanding any failure to satisfy any conditions for disbursement of any Advance set forth in Article 2 hereof or Article 5 hereof, and, to the extent of the Advance so disbursed, the Reimbursement Obligation of the Borrowers to the Administrative Agent under this Section 3.6 shall be deemed satisfied (unless, in each case, taking into account any such deemed Advances, the aggregate outstanding principal amount of Advances of the Revolving Credit and the Swing Line, plus the Letter of Credit Obligations (other than the Reimbursement Obligations to be reimbursed by this Advance) on such date exceed the then applicable Revolving Credit Aggregate Commitment).
     (f) If the Issuing Lender shall honor a draft or other demand for payment presented or made under any Letter of Credit, the Issuing Lender shall provide notice thereof to the Administrative Borrower on the date such draft or demand is honored, and to each Revolving Credit Lender on such date unless the Borrowers shall have satisfied its reimbursement obligations by payment to the Administrative Agent (for the benefit of the Issuing Lender) as required under this Section 3.6 . The Issuing Lender shall further use reasonable efforts to provide notice to the Administrative Borrower prior to honoring any such draft or other demand for payment, but such notice, or the failure to provide such notice, shall not affect the rights or obligations of the Issuing Lender with respect to any Letter of Credit or the rights and obligations of the parties hereto, including without limitation the obligations of the Borrowers under this Section 3.6 .
     (g) Notwithstanding the foregoing however, no Revolving Credit Lender shall be deemed to have acquired a participation in a Letter of Credit if the officers of the Issuing Lender immediately responsible for matters concerning this Agreement shall have received written notice from the Administrative Agent or any Lender at least two (2) Business Days prior to the date of the issuance or extension of such Letter of Credit or, with respect to any Letter of Credit subject to automatic extension, at least five (5)
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Business Days prior to the date that the beneficiary under such Letter of Credit must be notified that such Letter of Credit will not be renewed, that the issuance or extension of Letters of Credit should be suspended based on the occurrence and continuance of a Default or Event of Default and stating that such notice is a “ notice of default ”; provided , however , that the Revolving Credit Lenders shall be deemed to have acquired such a participation upon the date on which such Default or Event of Default has been waived by the requisite Revolving Credit Lenders, as applicable.
     (h) Nothing in this Agreement shall be construed to require or authorize any Revolving Credit Lender to issue any Letter of Credit, it being recognized that the Issuing Lender shall be the sole issuer of Letters of Credit under this Agreement.
     (i) In the event that any Revolving Credit Lender becomes an Impaired Lender, the Issuing Lender may, at its option, require that the Borrowers enter into arrangements satisfactory to Issuing Lender to eliminate the Issuing Lender’s risk with respect to the participation in Letters of Credit by such Impaired Lender, including creation of a cash collateral account or delivery of other security to assure payment of such Impaired Lender’s Revolving Credit Percentage of all outstanding Letter of Credit Obligations.
     3.7 Obligations Irrevocable . The obligations of the Borrowers to make payments to the Administrative Agent for the account of Issuing Lender or the Revolving Credit Lenders with respect to Letter of Credit Obligations under Section 3.6 hereof, shall be unconditional and irrevocable and not subject to any qualification or exception whatsoever, including, without limitation:
     (a) Any lack of validity or enforceability of any Letter of Credit, any Letter of Credit Agreement, any other documentation relating to any Letter of Credit, this Agreement or any of the other Loan Documents (the “ Letter of Credit Documents ”);
     (b) Any amendment, modification, waiver, consent, or any substitution, exchange or release of or failure to perfect any interest in collateral or security, with respect to or under any Letter of Credit Document;
     (c) The existence of any claim, setoff, defense or other right which any Borrower may have at any time against any beneficiary or any transferee of any Letter of Credit (or any persons or entities for whom any such beneficiary or any such transferee may be acting), the Administrative Agent, the Issuing Lender or any Revolving Credit Lender or any other Person, whether in connection with this Agreement, any of the Letter of Credit Documents, the transactions contemplated herein or therein or any unrelated transactions;
     (d) Any draft or other statement or document presented under any Letter of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect;
     (e) Payment by the Issuing Lender to the beneficiary under any Letter of Credit against presentation of documents which do not comply with the terms of such
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Letter of Credit, including failure of any documents to bear any reference or adequate reference to such Letter of Credit;
     (f) Any failure, omission, delay or lack on the part of the Administrative Agent, Issuing Lender or any Revolving Credit Lender or any party to any of the Letter of Credit Documents or any other Loan Document to enforce, assert or exercise any right, power or remedy conferred upon the Administrative Agent, Issuing Lender, any Revolving Credit Lender or any such party under this Agreement, any of the other Loan Documents or any of the Letter of Credit Documents, or any other acts or omissions on the part of the Administrative Agent, Issuing Lender, any Revolving Credit Lender or any such party; or
     (g) Any other event or circumstance that would, in the absence of this Section 3.7 , result in the release or discharge by operation of law or otherwise of any Borrower from the performance or observance of any obligation, covenant or agreement contained in Section 3.6 hereof.
No setoff, counterclaim, reduction or diminution of any obligation or any defense of any kind or nature which any Borrower has or may have against the beneficiary of any Letter of Credit shall be available hereunder to such Borrower against the Administrative Agent, Issuing Lender or any Revolving Credit Lender. With respect to any Letter of Credit, nothing contained in this Section 3.7 shall be deemed to prevent any Borrower, after satisfaction in full of the absolute and unconditional obligations of the Borrowers hereunder with respect to such Letter of Credit, from asserting in a separate action any claim, defense, set off or other right which they (or any of them) may have against the Administrative Agent, Issuing Lender or any Revolving Credit Lender in connection with such Letter of Credit.
     3.8 Risk Under Letters of Credit .
     (a) In the administration and handling of Letters of Credit and any security therefor, or any documents or instruments given in connection therewith, Issuing Lender shall have the sole right to take or refrain from taking any and all actions under or upon the Letters of Credit.
     (b) Subject to other terms and conditions of this Agreement, Issuing Lender shall issue the Letters of Credit and shall hold the documents related thereto in its own name and shall make all collections thereunder and otherwise administer the Letters of Credit in accordance with Issuing Lender’s regularly established practices and procedures and will have no further obligation with respect thereto. In the administration of Letters of Credit, Issuing Lender shall not be liable for any action taken or omitted on the advice of counsel, accountants, appraisers or other experts selected by Issuing Lender with due care and Issuing Lender may rely upon any notice, communication, certificate or other statement from any Borrower, beneficiaries of Letters of Credit, or any other Person which Issuing Lender believes to be authentic. Issuing Lender will, upon request, furnish the Revolving Credit Lenders with copies of Letter of Credit Documents related thereto.
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     (c) In connection with the issuance and administration of Letters of Credit and the assignments hereunder, Issuing Lender makes no representation and shall have no responsibility with respect to (i) the obligations of the Borrowers or the validity, sufficiency or enforceability of any document or instrument given in connection therewith, or the taking of any action with respect to same, (ii) the financial condition of, any representations made by, or any act or omission of any Borrower or any other Person, or (iii) any failure or delay in exercising any rights or powers possessed by Issuing Lender in its capacity as issuer of Letters of Credit in the absence of its gross negligence or willful misconduct. Each of the Revolving Credit Lenders expressly acknowledges that it has made and will continue to make its own evaluations of the Borrowers’ creditworthiness without reliance on any representation of Issuing Lender or Issuing Lender’s officers, agents and employees.
     (d) If at any time Issuing Lender shall recover any part of any unreimbursed amount for any draw or other demand for payment under a Letter of Credit, or any interest thereon, the Administrative Agent or Issuing Lender, as the case may be, shall receive same for the pro rata benefit of the Revolving Credit Lenders in accordance with their respective Revolving Credit Percentages and shall promptly deliver to each Revolving Credit Lender its share thereof, less such Revolving Credit Lender’s pro rata share of the costs of such recovery, including court costs and attorney’s fees. If at any time any Revolving Credit Lender shall receive from any source whatsoever any payment on any such unreimbursed amount or interest thereon in excess of such Revolving Credit Lender’s Revolving Credit Percentage of such payment, such Revolving Credit Lender will promptly pay over such excess to the Administrative Agent, for redistribution in accordance with this Agreement.
     3.9 Indemnification . The Borrowers hereby, jointly and severally, indemnify and agree to hold harmless the Revolving Credit Lenders, the Issuing Lender and the Administrative Agent and their respective Affiliates, and the respective officers, directors, employees and agents of such Persons (each an “ L/C Indemnified Person ”), from and against any and all claims, damages, losses, liabilities, costs or expenses of any kind or nature whatsoever which the Revolving Credit Lenders, the Issuing Lender or the Administrative Agent or any such Person may incur or which may be claimed against any of them by reason of or in connection with any Letter of Credit (collectively, the “ L/C Indemnified Amounts ”), and none of the L/C Indemnified Persons shall be liable or responsible for:
     (a) the use which may be made of any Letter of Credit or for any acts or omissions of any beneficiary in connection therewith;
     (b) the validity, sufficiency or genuineness of documents or of any endorsement thereon, even if such documents should in fact prove to be in any or all respects invalid, insufficient, fraudulent or forged;
     (c) payment by the Issuing Lender to the beneficiary under any Letter of Credit against presentation of documents which do not strictly comply with the terms of any Letter of Credit (unless such payment resulted from the gross negligence or willful
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misconduct of the Issuing Lender), including failure of any documents to bear any reference or adequate reference to such Letter of Credit;
     (d) any error, omission, interruption or delay in transmission, dispatch or delivery of any message or advice, however transmitted, in connection with any Letter of Credit; or
     (e) any other event or circumstance whatsoever arising in connection with any Letter of Credit.
It is understood that in making any payment under a Letter of Credit the Issuing Lender will rely on documents presented to it under such Letter of Credit as to any and all matters set forth therein without further investigation and regardless of any notice or information to the contrary.
With respect to subparagraphs (a) through (e) hereof, (i) the Borrowers shall be required to indemnify any L/C Indemnified Person for any L/C Indemnified Amounts to the extent such amounts result from the gross negligence or willful misconduct of such L/C Indemnified Person or any officer, director, employee or agent of such L/C Indemnified Person and (ii) the Administrative Agent and the Issuing Lender shall be liable to the Borrowers to the extent, but only to the extent, of any direct, as opposed to consequential or incidental, damages suffered by any Borrower which were caused by the gross negligence or willful misconduct of any L/C Indemnified Person or by the Issuing Lender’s wrongful dishonor of any Letter of Credit after the presentation to it by the beneficiary thereunder of a draft or other demand for payment and other documentation strictly complying with the terms and conditions of such Letter of Credit.
     3.10 Right of Reimbursement . Each Revolving Credit Lender agrees to reimburse the Issuing Lender on demand, pro rata in accordance with its respective Revolving Credit Percentage, for (i) the reasonable costs and expenses of the Issuing Lender to be reimbursed by the Borrowers pursuant to any Letter of Credit Agreement or any Letter of Credit, to the extent not reimbursed by the Borrowers or any other Credit Party and (ii) any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, fees, reasonable expenses or disbursements of any kind and nature whatsoever which may be imposed on, incurred by or asserted against Issuing Lender in any way relating to or arising out of this Agreement (including Section 3.6(c) hereof), any Letter of Credit, any documentation or any transaction relating thereto, or any Letter of Credit Agreement, to the extent not reimbursed by the Borrowers, except to the extent that such liabilities, losses, costs or expenses were incurred by Issuing Lender as a result of Issuing Lender’s gross negligence or willful misconduct or by the Issuing Lender’s wrongful dishonor of any Letter of Credit after the presentation to it by the beneficiary thereunder of a draft or other demand for payment and other documentation strictly complying with the terms and conditions of such Letter of Credit.
4. TERM LOAN.
     4.1 Term Loan . Subject to the terms and conditions hereof, each Term Loan Lender, severally and for itself alone, agrees to lend to the Borrowers, in a single disbursement in Dollars on the Effective Date an amount equal to such Lender’s Term Loan Percentage of the Term Loan.
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     4.2 Accrual of Interest and Maturity; Evidence of Indebtedness .
     (a) (i) The Borrowers hereby unconditionally promise to pay to the Administrative Agent for the account of each Term Loan Lender such Lender’s Term Loan Percentage of the then unpaid aggregate principal amount of the Term Loan outstanding on the Term Loan Maturity Date and on such other dates and in such other amounts as may be required from time to time pursuant to this Agreement. Subject to the terms and conditions hereof, the unpaid principal Indebtedness outstanding under the Term Loan shall, from the Effective Date (until paid), bear interest at the Applicable Interest Rate. There shall be no readvance or reborrowings of any principal reductions of the Term Loan.
     (b) Each Term Loan Lender shall maintain in accordance with its usual practice an account or accounts evidencing indebtedness of the Borrowers to the appropriate lending office of such Term Loan Lender resulting from each Advance of the Term Loan made by such lending office of such Lender from time to time, including the amounts of principal and interest payable thereon and paid to such Term Loan Lender from time to time under this Agreement.
     (c) The Administrative Agent shall maintain the Register pursuant to Section 13.8(g) , and a subaccount therein for each Term Loan Lender, in which Register and subaccounts (taken together) shall be recorded (i) the amount of each Advance of the Term Loan made hereunder, the type thereof and each Eurodollar-Interest Period applicable to any Eurodollar-based Advance, (ii) the amount of any principal or interest due and payable or to become due and payable from the Borrowers to each Term Loan Lender hereunder in respect of the Advances of the Term Loan and (iii) both the amount of any sum received by the Administrative Agent hereunder from the Borrowers in respect of the Advances of the Term Loan and each Term Loan Lender’s share thereof.
     (d) The entries made in the Register pursuant to paragraph (c) of this Section 4.2 shall, absent manifest error, to the extent permitted by applicable law, be prima facie evidence of the existence and amounts of the obligations of the Borrowers therein recorded; provided , however , that the failure of any Term Loan Lender or the Administrative Agent to maintain the Register or any such account, as applicable, or any error therein, shall not in any manner affect the obligation of the Borrowers to repay the Advances of the Term Loan (and all other amounts owing with respect thereto) made to the Borrowers by the Term Loan Lenders in accordance with the terms of this Agreement.
     (e) The Borrowers agree that, upon written request to the Administrative Agent by any Term Loan Lender, the Borrowers will execute and deliver to such Term Loan Lender, at the Borrowers’ expense, a Term Loan Note evidencing the outstanding Advances under the Term Loan owing to such Term Loan Lender.
     4.3 Repayment of Principal .
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     (a) The Borrowers shall repay the Term Loan as set forth below, each such quarterly principal installment to be paid on the first day of each February, May, August and November, commencing on February 1, 2010, until the Term Loan Maturity Date, when all remaining outstanding principal plus accrued interest thereon shall be due and payable in full:
 	 	 	 	 	
 	 	Payment (to be	
 	 	made on each	
Period	 	stated date)	
February 1, 2010	 	$	1,250,000	 	
May 1, 2010	 	$	1,250,000	 	
August 1, 2010	 	$	1,250,000	 	
November 1, 2010	 	$	1,250,000	 	
February 1, 2011	 	$	1,500,000	 	
May 1, 2011	 	$	1,500,000	 	
August 1, 2011	 	$	1,500,000	 	
November 1, 2011	 	$	1,500,000	 	
February 1, 2012	 	$	2,500,000	 	
May 1, 2012	 	$	2,500,000	 	
August 1, 2012	 	$	2,500,000	 	
Term Loan Maturity Date	 	Any amounts of principal or interest then outstanding on the Term Loan	
     (b) Whenever any payment under this Section 4.3 shall become due on a day that is not a Business Day, the date for payment thereunder shall be extended to the next Business Day.
     4.4 Term Loan Rate Requests; Refundings and Conversions of Advances of Term Loan . The Administrative Borrower may refund all or any portion of any Advance of the Term Loan as a Term Loan Advance with a like Eurodollar-Interest Period or convert each such Advance of the Term Loan to an Advance with a different Eurodollar-Interest Period, but only after delivery to the Administrative Agent of a Term Loan Rate Request executed in connection with the Term Loan by an Authorized Signer and subject to the terms hereof and to the following:
     (a) each Term Loan Rate Request shall set forth the information required on the Term Loan Rate Request form with respect to the Term Loan, including without limitation:
     (i) whether the Term Loan Advance is a refunding or conversion of an outstanding Term Loan Advance;
     (ii) in the case of a refunding or conversion of an outstanding Term Loan Advance, the proposed date of such refunding or conversion, which must be a Business Day; and
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     (iii) whether such Term Loan Advance (or any portion thereof) is to be a Base Rate Advance or a Eurodollar-based Advance, and, in the case of a Eurodollar-based Advance, the Eurodollar-Interest Period(s) applicable thereto.
     (b) each such Term Loan Rate Request shall be delivered to the Administrative Agent (i) by 1:00 p.m. (Detroit time) three (3) Business Days prior to the proposed date of the refunding or conversion of a Eurodollar-based Advance or (ii) by 1:00 p.m. on the proposed date of the refunding or conversion of a Base Rate Advance;
     (c) the principal amount of such Advance of the Term Loan plus the amount of any other Advance of the Term Loan to be then combined therewith having the same Applicable Interest Rate and Eurodollar-Interest Period, if any, shall be (i) in the case of a Base Rate Advance, at least One Million Dollars ($1,000,000), or the remaining principal balance outstanding under the Term Loan, whichever is less, and (ii) in the case of a Eurodollar-based Advance, at least One Million Dollars ($1,000,000) or the remaining principal balance outstanding under the Term Loan, whichever is less, or in each case a larger integral multiple of One Hundred Thousand Dollars ($100,000);
     (d) no Term Loan Advance shall have a Eurodollar-Interest Period ending after the Term Loan Maturity Date, and, notwithstanding any provision hereof to the contrary, the Administrative Borrower shall select Eurodollar-Interest Periods (or the Base Rate) for sufficient portions of the Term Loan such that the Borrowers may make the required principal payments hereunder on a timely basis and otherwise in accordance with Section 4.5 below;
     (e) at no time shall there be no more than five (5) Eurodollar-Interest Periods in effect for Advances of the Term Loan; and
     (f) a Term Loan Rate Request, once delivered to the Administrative Agent, shall not be revocable by the Borrowers.
     4.5 Base Rate Advance in Absence of Election or Upon Default . In the event the Administrative Borrower shall fail with respect to any Eurodollar-based Advance of the Term Loan to timely exercise their option to refund or convert such Advance in accordance with Section 4.4 hereof (and such Advance has not been paid in full on the last day of the Eurodollar-Interest Period applicable thereto according to the terms hereof), or, if on the last day of the applicable Eurodollar-Interest Period, a Default or Event of Default shall exist, then, on the last day of the applicable Eurodollar-Interest Period, the principal amount of such Advance which has not been prepaid shall be automatically converted to a Base Rate Advance and the Administrative Agent shall thereafter promptly notify the Administrative Borrower thereof. All accrued and unpaid interest on any Advance converted to a Base Rate Advance under this Section 4.5 shall be due and payable in full on the date such Advance is converted.
     4.6 Interest Payments; Default Interest .
     (a) Interest on the unpaid principal of all Base Rate Advances of the Term Loan from time to time outstanding shall accrue until paid at a per annum interest rate equal to the Base Rate, and shall be payable in immediately available funds quarterly in
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arrears commencing on February 1, 2010, and on the first day of each February, May, August and November thereafter (in respect of the preceding three months or any portion thereof). Whenever any payment under this Section 4.6 shall become due on a day that is not a Business Day, the date for payment shall be extended to the next Business Day. Interest accruing at the Base Rate shall be computed on the basis of a 360 day year and assessed for the actual number of days elapsed, and in such computation effect shall be given to any change in the interest rate resulting from a change in the Base Rate on the date of such change in the Base Rate.
     (b) Interest on the unpaid principal of each Eurodollar-based Advance of the Term Loan having a related Eurodollar-Interest Period of three (3) months or less shall accrue at its applicable Eurodollar-based Rate and shall be payable in immediately available funds on the last day of the Eurodollar-Interest Period applicable thereto. Interest shall be payable in immediately available funds on each Eurodollar-based Advance of the Term Loan outstanding from time to time having a Eurodollar-Interest Period of six (6) months or longer, at intervals of three (3) months after the first day of the applicable Eurodollar-Interest Period, and shall also be payable on the last day of the Eurodollar-Interest Period applicable thereto. Interest accruing at the Eurodollar-based Rate shall be computed on the basis of a 360-day year and assessed for the actual number of days elapsed from the first day of the Eurodollar-Interest Period applicable thereto to, but not including, the last day thereof.
     (c) Notwithstanding anything to the contrary in Section 4.6(a) or (b) hereof, all accrued and unpaid interest on any Term Loan Advance refunded or converted pursuant to Section 4.4 hereof shall be due and payable in full on the date such Term Loan Advance is refunded or converted.
     (d) In the case of any Event of Default under Section 9.1(i) , immediately upon the occurrence thereof, and in the case of any other Event of Default, upon notice from the Majority Term Loan Lenders interest shall be payable on demand on the principal amount of all Advances of the Term Loan from time to time outstanding, at a per annum rate equal to the Applicable Interest Rate in respect of each such Advance, plus, in the case of Eurodollar-based Advances, two percent (2%) for the remainder of the then existing Eurodollar-Interest Period, if any, and at all other such times and for all Base Rate Advances, at a per annum rate equal to the Base Rate plus two percent (2%).
     4.7 Optional Prepayment of the Term Loan .
     (a) Subject to clause (b) hereof, the Borrowers (at their option), may prepay all or any portion of the outstanding principal of any Term Loan Advance bearing interest at the Base Rate at any time, and may prepay all or any portion of the outstanding principal of any Term Loan bearing interest at the Eurodollar-based Rate upon one (1) Business Day’s notice to the Administrative Agent by wire, telecopy or by telephone (confirmed by wire or telecopy), with accrued interest on the principal being prepaid to the date of such prepayment. Any prepayment of a portion of the Term Loan as to which the Applicable Interest Rate is the Base Rate shall be without premium or penalty and any prepayment of a portion of the Term Loan as to which the Applicable Interest Rate is
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the Eurodollar-based Rate shall be without premium or penalty, except to the extent set forth in Section 11.1 .
     (b) Each partial prepayment of the Term Loan shall be applied to all installments of the Term Loan due thereunder in the inverse order of maturity to all such principal payments as follows: first to that portion of the Term Loan outstanding as a Base Rate Advance, second to that portion of the Term Loan outstanding as Eurodollar-based Advances which have Eurodollar-Interest Periods ending on the date of payment, and last to any remaining Advances of the Term Loan being carried at the Eurodollar-based Rate.
     (c) All prepayments of the Term Loan shall be made to the Administrative Agent for distribution ratably to the Term Loan Lenders in accordance with their respective Term Loan Percentages.
     4.8 Mandatory Prepayment of Term Loan .
     (a) Subject to clauses (c) and (d) hereof, immediately upon receipt by any Credit Party of any Net Cash Proceeds from any Asset Sales, which are not Reinvested as described in the following sentence, the Borrowers shall prepay the Term Loan by an amount equal to one hundred percent (100%) of such Net Cash Proceeds to the extent the Net Cash Proceeds from Asset Sales exceed $2,000,000 in the aggregate in the calendar year in which such prepayment is to be made or $5,000,000 in the aggregate during the term of this Agreement, provided , however , that the Borrowers shall not be obligated to prepay the Term Loan with such Net Cash Proceeds if the following conditions are satisfied: (i) promptly following the sale, the Administrative Borrower provides to the Administrative Agent a certificate executed by a Responsible Officer of the Administrative Borrower (“ Reinvestment Certificate ”) stating (x) that the sale has occurred, (y) that no Default or Event of Default has occurred and is continuing either as of the date of the sale or as of the date of the Reinvestment Certificate, and (z) a description of the planned Reinvestment of the proceeds thereof, (ii) the Reinvestment of such Net Cash Proceeds is commenced within the Initial Reinvestment Period and completed within the Reinvestment Period, and (iii) no Default or Event of Default has occurred and is continuing at the time of the sale and at the time of the application of such proceeds to Reinvestment. If any such proceeds have not been Reinvested at the end of the Reinvestment Period, the Borrowers shall promptly pay such proceeds to the Administrative Agent, to be applied to repay the Term Loan in accordance with clauses (c) and (d) hereof.
     (b) Subject to clauses (c) and (d) hereof, immediately upon receipt by any Credit Party of Net Cash Proceeds from the issuance of any Equity Interests of such Person (other than Equity Interests under any stock option or employee incentive plans listed on Schedule 7.13 hereto (or any successor plans) after the Effective Date, to the extent such Equity Interests are issued for the purpose of curing an Event of Default hereunder, as determined by the Administrative Agent in its reasonable discretion, the Borrowers shall prepay the Term Loan by an amount equal to fifty percent (50%) of such Net Cash Proceeds.
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     (c) Subject to clause (d) hereof, each mandatory prepayment under this Section 4.8 or any other mandatory or optional prepayment under this Agreement shall be in addition to any scheduled installments or optional prepayments made prior thereto and shall be subject to Section 11.1 . Each mandatory prepayment of the Term Loan shall be applied to installments of principal on the Term Loan in the inverse order of maturity.
     (d) To the extent that, on the date any mandatory prepayment of the Term Loan under this Section 4.8 is due, the Indebtedness under the Term Loan or any other Indebtedness to be prepaid is being carried, in whole or in part, at the Eurodollar-based Rate and no Default or Event of Default has occurred and is continuing, the Borrowers may deposit the amount of such mandatory prepayment in a cash collateral account to be held by the Administrative Agent, for and on behalf of the Lenders (which shall be an interest-bearing account), on such terms and conditions as are reasonably acceptable to the Administrative Agent and upon such deposit, the obligation of each Borrower to make such mandatory prepayment shall be deemed satisfied. Subject to the terms and conditions of said cash collateral account, sums on deposit in said cash collateral account shall be applied (until exhausted) to reduce the principal balance of the Term Loan on the last day of each Eurodollar-Interest Period attributable to the Eurodollar-based Advances of the Term Loan, thereby avoiding breakage costs under Section 11.1 .
     4.9 Use of Proceeds . Proceeds of the Term Loan shall be used by the Borrowers to finance the Acquisition.
     4.10 Term Loan Facility Fee . From the Closing Date to the Term Loan Maturity Date, the Borrowers jointly and severally agree to pay to the Administrative Agent for distribution to the financial institutions from time to time parties hereto as lenders of the Term Loan (the “Term Loan Lenders”) pro-rata in accordance with their respective Term Loan Percentages, a Term Loan Facility Fee in arrears from the Closing Date through the earlier of December 10, 2009, and the Effective Date, in advance commencing on the Effective Date for the period from the Effective Date through February 1, 2010, and in advance on the first day of each February, May, August and November thereafter (in respect of the following three months or any portion thereof). The Term Loan Facility Fee payable to each Term Loan Lender shall be determined by multiplying the Applicable Fee Percentage times the aggregate principal amount of the Term Loan to be made to the Borrowers by the Term Loan Lenders pursuant to Section 4.1 hereof. The Term Loan Facility Fee shall be computed on the basis of a year of three hundred sixty (360) days and assessed for the actual number of days elapsed. Whenever any payment of the Term Loan Facility Fee shall be due on a day which is not a Business Day, the date for payment thereof shall be extended to the next Business Day. Upon receipt of such payment, the Administrative Agent shall make prompt payment to each Term Loan Lender of its share of the Term Loan Facility Fee based upon its respective Term Loan Percentage. It is expressly understood that the Term Loan Facility Fees described in this Section are not refundable.
5. CONDITIONS.
     The obligations of the Lenders to make Advances or loans pursuant to this Agreement and the obligation of the Issuing Lender to issue Letters of Credit are subject to the following conditions:
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     5.1 Conditions of Initial Advances . The obligations of the Lenders to make initial Advances or loans pursuant to this Agreement and the obligation of the Issuing Lender to issue initial Letters of Credit, in each case, on the Effective Date only, are subject to the following conditions:
     (a) Notes, this Agreement and the other Loan Documents . The Borrowers shall have executed and delivered to the Administrative Agent for the account of each Lender requesting Notes, the Swing Line Note and the Revolving Credit Notes; the Borrowers shall have executed and delivered this Agreement, and, to the extent any Person becomes a Material Subsidiary after the date of this Agreement and before the initial Advance hereunder, a Joinder; and each Credit Party shall have executed and delivered the other Loan Documents to which such Credit Party is required to be a party (including all schedules and other documents to be delivered pursuant hereto); and such Notes (if any), this Agreement and the other Loan Documents shall be in full force and effect. Notwithstanding the foregoing, however, Bamagas shall not be required to execute and deliver a Joinder or any other Loan Document required to be executed and delivered under this Section 5.1 to the extent the consent required to execute and deliver such documents and to perform its obligations thereunder from Calpine Energy Services, L.P. (the “ Consent ”) has not been obtained.
     (b) Authority . Subject to the last sentence of Section 5.1(a) hereof, the Administrative Agent shall have received (i) such certificates of resolutions or other action, incumbency certificates and/or other certificates of a Responsible Officer of each Credit Party as the Administrative Agent may reasonably require evidencing the identity, authority and capacity of each Responsible Officer thereof authorized to act as a Responsible Officer in connection with the Loan Documents to which such Credit Party is a party, (ii) such documents and certificates certified by the appropriate Governmental Authority as of a recent date before the date of this Agreement as the Administrative Agent may require evidencing that each Credit Party is duly organized or formed, validly existing, in good standing and, in the case of each Credit Party, qualified to engage in business in each jurisdiction where its ownership, lease or operation of properties or the conduct of its business requires such qualification, except to the extent that failure to do so would not reasonably be expected to have a Material Adverse Effect and (iii) copies of each organizational or other governing document of each Credit Party certified by a Responsible Officer of such Credit Party and, with respect the articles of organization or formation of each Credit Party, certified by the appropriate Governmental Authority as of a recent date before the date of this Agreement.
     (c) Collateral Documents, Guaranties and other Loan Documents . Subject to the last sentence of Section 5.1(a) hereof, the Administrative Agent shall have received the following documents, each in form and substance satisfactory to the Administrative Agent and fully executed by each party thereto:
     (i) The Collateral Documents, each in form and substance reasonably acceptable to the Administrative Agent and fully executed by each party thereto and dated as of the Effective Date, including:
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     (A) the Security Agreement, executed and delivered by the Credit Parties;
     (B) the Guaranty, executed and delivered by the Guarantors;
     (C) the Collateral Assignment executed and delivered by one or more of the Borrowers; and
     (D) Mortgages covering the Acquisition Properties together with the related documentation specified in Schedule 5.1(c)(i)(D) .
     (ii) The Administrative Agent shall be satisfied that at least eighty percent (80%) of the total value of all Pipeline Systems and other Real Property of the Borrowers and their Subsidiaries are encumbered by the Collateral Documents.
     (iii) Certified copies of uniform commercial code requests for information, or a similar search report certified by a party acceptable to the Administrative Agent, dated a date reasonably prior to the Effective Date, listing all effective financing statements in the jurisdictions noted on Schedule 5.1(c)(iii) which name any Credit Party (under their present names or under any previous names used within five (5) years prior to the date hereof) as debtors, together with (x) copies of such financing statements, and (y) authorized Uniform Commercial Code (Form UCC-3) Termination Statements, if any, necessary to release all Liens and other rights of any Person in any Collateral described in the Collateral Documents previously granted by any Person (other than Liens permitted by Section 8.2 of this Agreement).
     (iv) Any documents (including, without limitation, financing statements, amendments to financing statements and assignments of financing statements, stock powers executed in blank and any endorsements) requested by the Administrative Agent and reasonably required to be provided in connection with the Collateral Documents to create, in favor of the Administrative Agent (for and on behalf of the Lenders), a first priority perfected security interest in the Collateral thereunder shall have been filed, registered or recorded, or shall have been delivered to the Administrative Agent in proper form for filing, registration or recordation.
     (d) Equity . On or before the Effective Date, the Administrative Agent shall have received evidence satisfactory to it that the holders of the Equity Interests of the Administrative Borrower shall have contributed (directly or indirectly) to their equity capital in an aggregate amount of not less than $93,000,000; such contribution being made in a manner and on terms reasonably acceptable to the Administrative Agent and the Lenders.
     (e) Insurance . The Administrative Agent shall have received evidence reasonably satisfactory to it and its insurance consultant that the Credit Parties have obtained the insurance policies required by Section 7.5 hereof and required by any of the
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other Loan Documents, including, without limitation, with respect to all material processing plants as requested by the Administrative Agent, and that such insurance policies are in full force and effect.
     (f) Compliance with Certain Documents and Agreements . Subject to the last sentence of Section 5.1(a) hereof, each Credit Party shall have each performed and complied in all material respects with all agreements and conditions contained in this Agreement and the other Loan Documents, to the extent required to be performed or complied with by such Credit Party. No Person (other than the Administrative Agent, Lenders and Issuing Lender) party to this Agreement or any other Loan Document shall be in material default in the performance or compliance with any of the terms or provisions of this Agreement or the other Loan Documents or shall be in material default in the performance or compliance with any of the material terms or material provisions of, in each case to which such Person is a party.
     (g) Opinions of Counsel . The Credit Parties shall furnish the Administrative Agent prior to the Effective Date, with signed copies for each Lender, opinions of counsel to the Credit Parties, including opinions of local counsel to the extent deemed reasonably necessary by the Administrative Agent, in each case dated the Effective Date and covering such matters as reasonably required by and otherwise reasonably satisfactory in form and substance to the Administrative Agent and each of the Lenders.
     (h) Payment of Fees . The Borrowers shall have paid to Comerica Bank any fees due under the terms of the Fee Letter, along with any other fees, costs or expenses due and outstanding to the Administrative Agent or the Lenders as of the Effective Date (including reasonable, disbursements and other charges of counsel to the Administrative Agent).
     (i) Pro Forma Balance Sheet . The Borrowers shall have delivered to the Administrative Agent, in form and substance satisfactory to the Administrative Agent, the Pro Forma Balance Sheet.
     (j) Material Contracts . The Administrative Agent shall have been provided with access to electronic copies of all Material Contracts described on Schedule 6.18 hereof.
     (k) Management Agreement and Employment Agreements . The Administrative Agent shall have received copies of the Advisory Services Agreement and all employment agreements of the Borrowers and their Subsidiaries which shall remain in effect following the Effective Date.
     (l) Closing Certificate . The Administrative Agent shall have received a certificate of a Responsible Officer of the Administrative Borrower dated the Effective Date (or, if different, the date of the initial Advance hereunder), stating that to the best of his or her respective knowledge after due inquiry, (a) the conditions set forth in this Section 5.1 have been satisfied to the extent required to be satisfied by any Credit Party; (b) the representations and warranties made by the Credit Parties in this Agreement or
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any of the other Loan Documents, as applicable, are true and correct in all material respects; (c) no Default or Event of Default shall have occurred and be continuing; (d) since June 30, 2009, nothing shall have occurred which has had, or could reasonably be expected to have, a material adverse change on the business, results of operations, conditions, property or prospects (financial or otherwise) of any Borrower or any other Credit Party; (e) there shall have been no material adverse change to the Pro Forma Balance Sheet; and (f) there shall have been no material adverse change in each Borrower’s ability to perform its obligations under the Acquisition Documents or otherwise in connection with the Acquisition.
     (m) Acquisition .
     (i) Funds have been escrowed pursuant to the provisions of the Acquisition Documents to protect against certain litigation more particularly described in the Acquisition Documents. The Administrative Borrower hereby grants the Administrative Agent for the ratable benefit of the Lenders a security interest in all of the Administrative Borrower’s right, title and interest in and to the funds escrowed pursuant to the Acquisition Documents.
     (ii) The Administrative Agent and the Lenders shall have received (A) a certificate of a Responsible Officer of the Administrative Borrower certifying: (I) that the Administrative Borrower is concurrently consummating the Acquisition in accordance with the terms of the Acquisition Documents (with all of the material conditions precedent thereto having been satisfied in all material respects by the parties thereto) and acquiring substantially all of the Acquisition Properties contemplated by the Acquisition Documents; (II) as to the final purchase price for the Acquisition Properties after giving effect to all adjustments as of the closing date contemplated by the Acquisition Documents and specifying, by category, the amount of such adjustment; (III) that attached thereto is a true and complete list of the Acquisition Properties which have been excluded from the Acquisition pursuant to the terms of the Acquisition Documents, specifying with respect thereto the basis of exclusion as (1) title defect, (2) preferential purchase right, (3) environmental or (4) casualty loss; (IV) that attached thereto is a true and complete list of all Acquisition Properties for which the Seller has elected to cure a title defect; (V) that attached thereto is a true and complete list of all Acquisition Properties for which the Seller has elected to remediate an adverse environmental condition; and (VI) that attached thereto is a true and complete list of all Acquisition Properties which are currently pending final decision by a third party regarding purchase of such property in accordance with any preferential right; (B) a true and complete executed copy of each of the Acquisition Documents in reasonable form and substance satisfactory to the Administrative Agent and the Lenders; (C) original counterparts or copies, certified as true and complete, of the assignments, deeds and leases for all of the Acquisition Properties; and (D) such other related documents and information as the Administrative Agent shall have reasonably requested.
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     (iii) The Administrative Agent and the Lenders shall have received evidence satisfactory to it that all Liens on the Acquisition Properties associated with any credit facilities and Funded Debt have been released or terminated and that arrangements satisfactory to the Administrative Agent have been made for recording and filing of such releases.
     (n) Environmental Due Diligence, etc. . The Administrative Agent and the Lenders shall have received, in each case in form and substance satisfactory to the Administrative Agent, (i) a Phase I Environmental Assessment prepared by R.W. Beck covering the “Bazor Ridge” facility and (ii) a reliance letter from R.W. Beck with respect to such Phase I Environmental Assessment. The Seller shall have indemnified the Borrowers and their Subsidiaries with respect to the environmental conditions present at the “Harmony” plant located approximately 7 miles southwest of Quitman, Clarke County, Mississippi pursuant to and to the extent provided in the Purchase and Sale Agreement.
     (o) Remaining Availability . After giving effect to the Revolving Credit Advances made to fund the Acquisition, the Borrowers shall have Unused Revolving Credit Availability of at least $10,000,000.
     (p) Funding Limitation . Notwithstanding anything to the contrary contained in this Agreement or in any other Loan Document, the Administrative Agent, the Issuing Lender and the Lenders shall not be obligated to make initial Advances or issue Letters of Credit on the Effective Date in excess of an amount equal to the product of (a) three (3) times (b) $24,764,000, being the Consolidated EBITDA as of June 30, 2009, on a trailing twelve (12) month basis, as reflected in the PricewaterhouseCoopers letter dated as of August 21, 2009.
     (q) Termination . A Revolving Credit Advance and a Term Loan Advance to fund the Acquisition shall occur on or before December 10, 2009.
     5.2 Continuing Conditions . The obligations of each Lender to make Advances (including the initial Advance) under this Agreement and the obligation of the Issuing Lender to issue any Letters of Credit shall be subject to the continuing conditions that:
     (a) No Default or Event of Default shall exist as of the date of the Advance or the request for the Letter of Credit, as the case may be; and
     (b) Each of the representations and warranties contained in this Agreement and in each of the other Loan Documents shall be true and correct in all material respects as of the date of the Advance or Letter of Credit (as the case may be) as if made on and as of such date (other than any representation or warranty that expressly speaks only as of a different date).
6. REPRESENTATIONS AND WARRANTIES.
     Each Borrower represents and warrants to the Administrative Agent, the Lenders, the Swing Line Lender and the Issuing Lender as follows:
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     6.1 Organizational Authority . Each Borrower and each of their Subsidiaries is a corporation (or other business entity) duly organized and existing in good standing under the laws of the state or jurisdiction of its incorporation or formation, as applicable, and each such party is duly qualified and authorized to do business as a foreign corporation or other entity in each jurisdiction where the character of its assets or the nature of its activities makes such qualification and authorization necessary except where failure to be so qualified or be in good standing could not reasonably be expected to have a Material Adverse Effect. Each Borrower and each of Subsidiaries has all requisite corporate, limited liability or partnership power and authority to own all its property (whether real, personal, tangible or intangible or of any kind whatsoever) and to carry on its business in substantially the manner as such business was operated immediately prior to the Effective Date.
     6.2 Due Authorization . Execution, delivery and performance of this Agreement, the other Loan Documents and the Acquisition Documents, to which each Borrower and each of their Subsidiaries is party, and the issuance of the Notes by the Borrowers (if requested) are within such Person’s corporate, limited liability or partnership power, have been duly authorized, are not in contravention of any law applicable to such party or the terms of such party’s organizational documents and, except as have been previously obtained or as referred to in Section 6.10 , below, do not require the consent or approval of any Governmental Authority or any other third party except to the extent that such consent or approval is not material to the transactions contemplated by the Loan Documents or the Acquisition Documents.
     6.3 Good Title; Leases; Assets; No Liens .
     (a) Each Borrower and each of their Subsidiaries, to the extent applicable, has good and valid title (or, in the case of Real Property and Easements, good and defensible title) to all assets owned by it, subject only to the Liens permitted under Section 8.2 hereof, and each Borrower and each of their Subsidiaries has a valid leasehold or interest as a lessee or a licensee in all of its leased Real Property, subject to Permitted Liens;
     (b) Schedule 6.3(b) hereof identifies all of the material Real Property and Easements owned or operated or leased, as lessee thereunder, by the Borrowers and their Subsidiaries on the Effective Date, including all warehouse or bailee locations as of the Effective Date;
     (c) The Pipeline Systems are covered by recorded Easements in favor of each applicable Borrower or its applicable Subsidiaries (or their predecessors in interest) and their respective successors and assigns, except where the failure of the Pipeline Systems to be so covered, individually or in the aggregate, (i) does not materially interfere with the ordinary conduct of the businesses of the Borrowers and their Subsidiaries in substantially the manner as such businesses were operated immediately prior to the Effective Date, (ii) does not materially detract from the value or the use of the portion of the Pipeline Systems which are not covered and (iii) could not reasonably be expected to have a Material Adverse Effect;
     (d) The Easements establish a contiguous and continuous right-of-way for each separate system of tubes and pipelines comprising the Pipeline Systems and, subject
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to the Permitted Liens, grant each applicable Borrower or its applicable Subsidiaries (or their predecessors in interest) and their respective successors and assigns, the right to construct, operate and maintain the Pipeline Systems in, over, under or across the land covered thereby in the same way that a prudent owner and operator in the midstream pipeline business would construct, operate and maintain similar assets;
     (e) The Real Property is covered by fee deeds, real property leases and other instruments (the “ Deeds ”) in favor of each applicable Borrower or its applicable Subsidiaries (or their predecessors in interest) and their respective successors and assigns;
     (f) The Deeds grant to each applicable Borrower or its applicable Subsidiaries (or their predecessors in interest) and their respective successors and assigns, the right to construct, operate and maintain the Real Property in, over and under the land covered thereby in the same way that a prudent owner and operator in the midstream pipeline business would construct, operate and maintain similar assets;
     (g) To the knowledge of the Borrowers and their Subsidiaries after due inquiry and investigation, there has been no and there is not presently any occurrence of any (i) breach or event of default on the part of any Borrower or any of its Subsidiaries with respect to any Easement or Deed, (ii) breach or event of default on the part of any other party to any Easement or Deed, and (iii) event that, with the giving of notice of lapse of time or both, would constitute such breach or event of default on the part of any Borrower or any of its Subsidiaries with respect to any Easement or Deed or on the part of any other party there to, in each case, to the extent such breach or default, individually or in the aggregate, (A) materially interferes with the ordinary conduct of the businesses of the Borrowers and their Subsidiaries in substantially the manner as such businesses were operated immediately prior to the Effective Date, (B) materially detracts from the value or the use of the portion of the Pipeline Systems and/or Real Property covered thereby and (C) could not reasonably be expected to have a Material Adverse Effect;
     (h) To the knowledge of the Borrowers and their Subsidiaries after due inquiry and investigation, (i) the Easements and Deeds (to the extent applicable) are in full force and effect in all material respects and are valid and enforceable against the parties thereto in accordance with their terms (subject to the effect of any applicable bankruptcy, reorganization, insolvency, moratorium, fraudulent transfer, fraudulent conveyance or similar laws affecting creditors’ rights generally and subject to, as to enforceability, general principles of equity) and (ii) all rental and other payments due thereunder by the Borrowers and their Subsidiaries and their predecessors in interest, have been duly paid in accordance with the terms of the Easements and Deeds, except to the extent that the failure to do so, individually or in the aggregate, (A) does not materially interfere with the ordinary conduct of the businesses of the Borrowers and their Subsidiaries in substantially the manner as such businesses were operated immediately prior to the Effective Date, (B) does not materially detract from the value or the use of the portion of the Pipeline System and/or Real Property covered thereby and (C) could not reasonably be expected to have a Materially Adverse Effect;
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     (i) The Pipeline Systems are located with the confines of the descriptions contained in the Easements and do not encroach upon any adjoining property in any one or more material respects;
     (j) The Real Property is located within the confines of description contained in the Deeds and do not encroach upon any adjoining property in any one or more material respects;
     (k) The buildings or improvements owned or leased by any Borrower or any of its Subsidiaries, and the operation and maintenance thereof, do not (i) contravene any applicable zoning or building law or ordinance or other administrative regulation or (ii) violate any applicable restrictive covenant or any Requirement of Law, the contravention of which would materially affect the use of the property subject thereto;
     (l) The Borrowers and their Subsidiaries will collectively own or collectively have a valid leasehold interest in all assets that were owned or leased (as lessee) by the Borrowers and their Subsidiaries immediately prior to the Effective Date to the extent that such assets are necessary for the continued operation of the businesses of the Borrowers and their Subsidiaries in substantially the manner as such businesses were operated immediately prior to the Effective Date;
     (m) To the knowledge of the Borrowers and their Subsidiaries after due inquiry and investigation, no material condemnation, eminent domain or expropriation action has been commenced or threatened against any such owned or leased Real Property; and
     (n) There are no Liens on and no financing statements on file with respect to any of the assets owned by any Borrower or any of its Subsidiaries, except for the Liens permitted pursuant to Section 8.2 of this Agreement.
     6.4 Taxes . Except as set forth on Schedule 6.4 hereof, each Borrower and each of its Subsidiaries has filed on or before their respective due dates or within the applicable grace periods, all United States federal, state, local and other tax returns which are required to be filed or has obtained extensions for filing such tax returns and is not delinquent in filing such returns in accordance with such extensions and has paid all material taxes which have become due pursuant to those returns or pursuant to any assessments received by any such party, as the case may be, to the extent such taxes have become due, except to the extent such taxes are being contested in good faith by appropriate proceedings diligently conducted and with respect to which adequate provision has been made on the books of such party as may be required by GAAP.
     6.5 No Defaults . Neither any Borrower nor any of its Subsidiaries is in default under or with respect to any agreement, instrument or undertaking to which it is a party or by which it or any of its property is bound which would cause or would reasonably be expected to cause a Material Adverse Effect.
     6.6 Enforceability of Agreement and Loan Documents . This Agreement and each of the other Loan Documents to which any Borrower or any of its Subsidiaries is a party (including
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without limitation, each Request for Advance), have each been duly executed and delivered by its duly authorized officers and constitute the valid and binding obligations of such party, enforceable against such party in accordance with their respective terms, except as enforcement thereof may be limited by applicable bankruptcy, reorganization, insolvency, fraudulent conveyance, moratorium or similar laws affecting the enforcement of creditor’s rights, generally and by general principles of equity (regardless of whether enforcement is considered in a proceeding in law or equity).
     6.7 Compliance with Laws . (a) Except as disclosed on Schedule 6.7 , each Borrower and each of its Subsidiaries has complied with all applicable federal, state and local laws, ordinances, codes, rules, regulations and guidelines (including consent decrees and administrative orders) including but not limited to Hazardous Material Laws, and is in compliance with any Requirement of Law, except to the extent that failure to comply therewith could not reasonably be expected to have a Material Adverse Effect; and (b) neither the extension of credit made pursuant to this Agreement or the use of the proceeds thereof by the Borrowers and their Subsidiaries will violate the Trading with the Enemy Act, as amended, or any of the foreign assets control regulations of the United States Treasury Department (31 CFR, Subtitle B, Chapter V, as amended) or any enabling legislation or executive order relating thereto, or The United and Strengthening America by providing appropriate Tools Required to Intercept and Obstruct Terrorism (“ USA Patriot Act ”) Act of 2001, Public Law 10756, October 26, 2001 or Executive Order 13224 of September 23, 2001 issued by the President of the United States (66 Fed. Reg. 49049 (2001)).
     6.8 Non-contravention . The execution, delivery and performance of this Agreement and the other Loan Documents (including each Request for Advance) to which any Borrower and any of its Subsidiaries is a party are not in contravention of the terms of any indenture, agreement or undertaking to which such party is a party or by which it or its properties are bound where such violation could reasonably be expected to have a Material Adverse Effect.
     6.9 Litigation . Except as set forth on Schedule 6.9 hereof, there is no suit, action, proceeding, including, without limitation, any bankruptcy proceeding or governmental investigation pending against or to the knowledge of the Borrowers, threatened in writing against any Borrower or any of its Subsidiaries (other than any suit, action or proceeding in which any Borrower or any of its Subsidiaries is the plaintiff and in which no counterclaim or cross-claim against such party has been filed) or involving the Acquisition, or any judgment, decree, injunction, rule, or order of any court, government, department, commission, agency, instrumentality or arbitrator outstanding against any Borrower or any of its Subsidiaries or involving the Acquisition, nor is any Borrower or any of its Subsidiaries in violation of any applicable law, regulation, ordinance, order, injunction, decree or requirement of any Governmental Authority or court which could in any of the foregoing events reasonably be expected to have a Material Adverse Effect or to impair the consummation of the Acquisition on the time and in the manner contemplated by the Acquisition Documents.
     6.10 Consents, Approvals and Filings, Etc . Except as set forth on Schedule 6.10 hereof, no material authorization, consent, approval, license, qualification or formal exemption from, nor any filing, declaration or registration with, any court, Governmental Authority or any securities exchange or any other Person (whether or not governmental) is required in connection
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with (a) the execution, delivery and performance: (i) by any Borrower or any of its Subsidiaries of this Agreement and any of the other Loan Documents to which such party is a party or (ii) by the Borrowers and their Subsidiaries of the grant of Liens granted, conveyed or otherwise established (or to be granted, conveyed or otherwise established) by or under this Agreement or the other Loan Documents, as applicable, and (b) otherwise necessary to the operation of its business in substantially the manner as such business was operated immediately prior to the Effective Date, except in each case for (x) such matters which have been previously obtained, and (y) such filings to be made concurrently herewith or promptly following the Effective Date as are required by the Collateral Documents to perfect Liens in favor of the Administrative Agent. All such material authorizations, consents, approvals, licenses, qualifications, exemptions, filings, declarations and registrations which have previously been obtained or made, as the case may be, are in full force and effect and, to the knowledge of the Borrowers after due inquiry and investigation, are not the subject of any attack or threatened attack (in each case in any material respect) by appeal or direct proceeding or otherwise.
     6.11 Agreements Affecting Financial Condition . To their knowledge after due inquiry, neither any Borrower nor any Subsidiary expects that any contract for the sale or purchase of goods or services will be cancelled or terminated which, if so cancelled or terminated, would reasonably be expected to have a Material Adverse Effect and that has not been disclosed to the Administrative Agent. However, if such Borrower or Subsidiary suspects such a contract may be terminated or cancelled, commercially reasonable efforts have been undertaken to promptly replace such contract with a commercially reasonable substitute.
     6.12 No Investment Company or Margin Stock . Neither any Borrower nor any of its Subsidiaries is an “ investment company ” within the meaning of the Investment Company Act of 1940, as amended. Neither any Borrower nor any of its Subsidiaries is engaged principally, or as one of its important activities, directly or indirectly, in the business of extending credit for the purpose of purchasing or carrying margin stock. None of the proceeds of any of the Advances will be used by any Borrower or any of its Subsidiaries to purchase or carry margin stock. Terms for which meanings are provided in Regulation U of the Board of Governors of the Federal Reserve System or any regulations substituted therefore, as from time to time in effect, are used in this paragraph with such meanings.
     6.13 ERISA . Neither any Borrower nor any of its Subsidiaries maintains or contributes to any Pension Plan subject to Title IV of ERISA, except as set forth on Schedule 6.13 hereto or otherwise disclosed to the Administrative Agent in writing. There is no accumulated funding deficiency within the meaning of Section 412 of the Internal Revenue Code or Section 302 of ERISA, or any outstanding liability with respect to any Pension Plans owed to the PBGC other than future premiums due and owing pursuant to Section 4007 of ERISA, and no “ reportable event ” as defined in Section 4043(c) of ERISA has occurred with respect to any Pension Plan other than an event for which the notice requirement has been waived by the PBGC. None of the Borrowers or any of their Subsidiaries has engaged in a prohibited transaction with respect to any Pension Plan, other than a prohibited transaction for which an exemption is available and has been obtained, which could subject such parties to a material tax or penalty imposed by Section 4975 of the Internal Revenue Code or Section 502(i) of ERISA. Each Pension Plan is being maintained and funded in accordance with its terms and is in material compliance with the requirements of the Internal Revenue Code and ERISA. Neither any
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Borrower nor any of its Subsidiaries has had a complete or partial withdrawal from any Multiemployer Plan that has resulted or could reasonably be expected to have resulted in any Withdrawal Liability and, except as notified to the Administrative Agent in writing following the Effective Date, no such Multiemployer Plan is in reorganization (within the meaning of Section 4241 of ERISA) or insolvent (within the meaning of Section 4245 of ERISA).
     6.14 Conditions Affecting Business or Properties . Neither the respective businesses nor the properties of any Borrower or any of its Subsidiaries is affected by any fire, explosion, accident, strike, lockout or other dispute, drought, storm, hail, earthquake, embargo, act of god, or other casualty which could reasonably be expected to have a Material Adverse Effect (except to the extent such event is covered by insurance sufficient to ensure that, upon application of the proceeds thereof, no Material Adverse Effect could reasonably be expected to occur).
     6.15 Environmental and Safety Matters . Except as set forth in Schedules 6.9 , 6.10 and 6.15 :
     (a) all facilities and property owned or leased by any Borrower or any of its Subsidiaries are in compliance with all Hazardous Material Laws;
     (b) to the knowledge of the Borrowers after due inquiry and investigation, there have been no unresolved and outstanding past, and there are no pending or threatened:
     (i) claims, complaints, notices or requests for information received by any Borrower or any of its Subsidiaries with respect to any alleged violation of any Hazardous Material Law, or
     (ii) written complaints, written notices or written inquiries to any Borrower or any of its Subsidiaries regarding potential liability of any Borrower or any of its Subsidiaries under any Hazardous Material Law; and
     (c) to the knowledge of the Borrowers after due inquiry and investigation, no conditions exist at, on or under any property now or previously owned or leased by any Borrower or any of its Subsidiaries which, with the passage of time, or the giving of notice or both, are reasonably likely to give rise to liability under any Hazardous Material Law or result in a Material Adverse Effect.
     6.16 Subsidiaries . Except as disclosed on Schedule 6.16 hereto as of the Effective Date, and thereafter, except as disclosed to the Administrative Agent in writing from time to time, neither any Borrower nor any of its Subsidiaries has any Subsidiaries.
     6.17 Management Agreements . Schedule 6.17 attached hereto is an accurate and complete list of all management and significant employment agreements in effect on or as of the Effective Date to which any Borrower or any of its Subsidiaries is a party or is bound.
     6.18 Material Contracts . Schedule 6.18 attached hereto is an accurate and complete list of all Material Contracts in effect on or as of the Effective Date to which any Borrower or any of its Subsidiaries is a party or is bound.
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     6.19 Franchises, Patents, Copyrights, Trade Names, Etc . The Borrowers and their Subsidiaries possess all franchises, patents, copyrights, trademarks, trade names, licenses and permits, and rights in respect of the foregoing, adequate for the conduct of their businesses in substantially the manner as such businesses were operated immediately prior to the Effective Date without known conflict with any rights of others. Schedule 6.19 contains a true and accurate list of all trade names and any and all other names used by any Borrower or any of its Subsidiaries during the five-year period ending as of the Effective Date.
     6.20 Capital Structure . Schedule 6.20 attached hereto sets forth all issued and outstanding Equity Interests of each Borrower and each of its Subsidiaries, including the number of authorized, issued and outstanding Equity Interests of each Borrower and each of its Subsidiaries, the par value of such Equity Interests and the holders of such Equity Interests, all on and as of the Effective Date. All issued and outstanding Equity Interests of each Borrower and each of its Subsidiaries are duly authorized and validly issued, fully paid, nonassessable, free and clear of all Liens (except for the benefit of the Administrative Agent) and such Equity Interests were issued in compliance with all applicable state, federal and foreign laws concerning the issuance of securities. Except as disclosed on Schedule 6.20 , there are no preemptive or other outstanding rights, options, warrants, conversion rights or similar agreements or understandings for the purchase or acquisition from any Borrower or any of its Subsidiaries, of any Equity Interests of any Borrower or any of its Subsidiaries.
     6.21 Accuracy of Information .
     (a) The projections, the Pro Forma Balance Sheet and the other pro forma financial information delivered to the Administrative Agent prior to the Effective Date are based upon good faith estimates and assumptions believed by management of the Borrowers to be accurate and reasonable at the time made, it being recognized by the Lenders that such financial information as it relates to future events is not to be viewed as fact and that actual results during the period or periods covered by such financial information may differ from the projected results set forth therein.
     (b) From June 30, 2009, through the Effective Date, there has been no change in the business, operations, condition, property or prospects (financial or otherwise) of the Borrowers and their Subsidiaries, taken as a whole, that could reasonably be expected to have a Material Adverse Effect.
     (c) To the best knowledge of the Borrowers and their Subsidiaries, as of the Effective Date, (i) neither any Borrower nor any of its Subsidiaries have any material contingent obligations (including any liability for taxes) not disclosed by or reserved against in the opening balance sheet to be delivered hereunder and (ii) there are no unrealized or anticipated losses from any present commitment of the Borrowers and their Subsidiaries which contingent obligations and losses in the aggregate could reasonably be expected to have a Material Adverse Effect.
     6.22 Solvency . After giving effect to the consummation of the transactions contemplated by this Agreement and other Loan Documents, each Borrower and each of its Subsidiaries will be solvent, able to pay its indebtedness as it matures and will have capital
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sufficient to carry on its businesses in substantially the manner as such businesses were operated immediately prior to the Effective Date and all business in which it is about to engage. This Agreement is being executed and delivered by the Borrowers to the Administrative Agent and the Lenders in good faith and in exchange for fair, equivalent consideration. The Borrowers and their Subsidiaries do not intend to nor does management of the Borrowers and their Subsidiaries believe the Borrowers and their Subsidiaries will incur debts beyond their ability to pay as they mature. The Borrowers and their Subsidiaries do not contemplate filing a petition in bankruptcy or for an arrangement or reorganization under the Bankruptcy Code or any similar law of any jurisdiction now or hereafter in effect relating to any Borrower or any of its Subsidiaries, nor does any Borrower or any of its Subsidiaries have any knowledge of any threatened bankruptcy or insolvency proceedings against any Borrower or any of its Subsidiaries.
     6.23 Employee Matters . There are no strikes, slowdowns, work stoppages, unfair labor practice complaints, grievances, arbitration proceedings or controversies pending or, to the best knowledge of the Borrowers, threatened in writing against any Borrower or any of its Subsidiaries by any employees of any Borrower or any of its Subsidiaries, other than non-material employee grievances or controversies arising in the ordinary course of business. Set forth on Schedule 6.23 are all union contracts or agreements to which any Borrower or any of its Subsidiaries is party as of the Effective Date and the related expiration dates of each such contract.
     6.24 No Misrepresentation . Neither this Agreement nor any other Loan Document, certificate, information or report furnished or to be furnished by or on behalf of any Borrower or any of its Subsidiaries to the Administrative Agent or any Lender in writing in connection with any of the transactions contemplated hereby or thereby, contains a misstatement of material fact, or omits to state a material fact required to be stated in order to make the statements contained herein or therein, taken as a whole, not misleading in the light of the circumstances under which such statements were made. There is no fact, other than information known to the public generally, known to any Borrower or any of its Subsidiaries after diligent inquiry, that could reasonably be expected to have a Material Adverse Effect that has not been disclosed to the Administrative Agent in writing.
     6.25 Corporate Documents and Corporate Existence . As to each Borrower and each of its Subsidiaries, (a) it is an organization as described on Schedule 6.25 hereto and has provided the Administrative Agent and the Lenders with complete and correct copies of its articles of incorporation, by-laws and all other applicable charter and other organizational documents, and, if applicable, a good standing certificate and (b) its correct legal name, business address, type of organization and jurisdiction of organization, tax identification number and other relevant identification numbers are set forth on Schedule 6.25 hereto.
     6.26 Acquisition Documents . The copies of the Acquisition Documents previously delivered by any Borrower to the Administrative Agent are true, accurate and complete and have not been amended or modified in any manner, other than pursuant to amendments or modifications previously delivered to the Administrative Agent. No party to any Acquisition Document is in default in respect of any material term or obligation thereunder. The Acquisition Documents comply in all material respects with all applicable laws.
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     6.27 State and Federal Regulation .
     (a) The interstate common carrier pipeline operations comprising a portion of the Pipeline Systems (the “ Interstate Pipelines ”) are subject to rate regulation by the FERC under the Interstate Commerce Act and the Energy Policy Act. With respect to the Interstate Pipelines, (a) the rates on file with the FERC are just and reasonable pursuant to the Energy Policy Act and (b) no provision of the tariff containing such rates is unduly discriminatory or preferential. Except as set forth on Schedule 6.27(a) , neither any Borrower nor any of its Subsidiaries nor any Person that now owns or has owned an interest in the Interstate Pipelines has been or is the subject of a complaint, investigation or other proceeding regarding their respective rates or practices with respect to the Interstate Pipelines. No complaint, investigation or other proceeding set forth on Schedule 6.27(a) , individually or in the aggregate, could result, if adversely determined to the position or interest of any Borrower or any of its Subsidiaries or other such Person, in a Material Adverse Effect.
     (b) With respect to those certain intrastate common carrier pipeline operations that comprise a portion of the Pipeline Systems (the “ Intrastate Pipelines ”), are subject to regulation by the State Pipeline Regulatory Agencies. Each Borrower and each of its Subsidiaries that owns pipelines and conducts pipeline operations has followed prudent practice in the Hydrocarbon transportation, processing and distribution industries, as applicable, regarding the setting of rates for services provided and the implementation of such rates. The rates charged by each applicable Borrower and its applicable Subsidiaries with respect to the Intrastate Pipelines provide no more than a fair return on the aggregate value of the property used to render services on the Intrastate Pipelines, and no such party uses, charges, imposes or implements, or has previously done any of the foregoing, in a discriminatory manner. Except as set forth on Schedule 6.27(b) , neither any Borrower nor any of its Subsidiaries that owns any interest in any of the Intrastate Pipelines has been or is the subject of a complaint, investigation or other proceeding by any Governmental Authority regarding their respective rates or practices with respect to the Intrastate Pipelines. No complaint, investigation or other proceeding set forth on Schedule 6.27(b) , individually or in the aggregate, could result, if adversely determined to the position or interest of any Borrower or any of its Subsidiaries or other such Person, in a Material Adverse Effect.
     (c) Each applicable Borrower and each of its applicable Subsidiaries is in compliance, in all material respects, with all rules, regulations and orders of the FERC and all State Pipeline Regulatory Agencies applicable to the Pipeline Systems.
     (d) As of the Effective Date, neither any Borrower nor any of its Subsidiaries is liable for any refunds or interest thereon as a result of an order from the FERC or any Governmental Authority with jurisdiction over the Pipeline Systems.
     (e) Each applicable Borrower’s and each of its applicable Subsidiary’s report on Form 2 or 2A, as applicable, filed with the FERC, if any, complies with all applicable material legal requirements and does not contain any untrue statement of material fact or omit to state a material fact required to make the statements therein not misleading.
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     (f) Without limiting the generality of Section 6.10 of this Agreement, no certificate, license, permit, consent, authorization or order (to the extent not otherwise obtained) is required by any Borrower or any of its Subsidiaries from any Governmental Authority to construct, own, operate and maintain the Pipeline Systems, or to transport, process and/or distribute Hydrocarbons under existing contracts and agreements as the Pipeline Systems are presently owned, operated and maintained.
     6.28 Supplemental Schedules . Not later than thirty (30) days after the date on which any information on any Schedule to this Agreement changed, the Borrowers shall deliver to the Administrative Agent an updated version of such Schedule; provided , however , the delivery of any updated Schedule hereunder shall not be deemed a waiver of any obligation of any Borrower under any Loan Document, and such updated Schedule shall not be effective until it is accepted by the Administrative Agent.
7. AFFIRMATIVE COVENANTS.
     Each Borrower covenants and agrees, so long as any Lender has any commitment to extend credit hereunder, or any of the Indebtedness remains outstanding and unpaid, that it will, and, as applicable, it will cause each of its Subsidiaries to:
     7.1 Financial Statements . Furnish to the Administrative Agent, in form and detail reasonably satisfactory to the Administrative Agent, the following documents:
     (a) as soon as available, but in any event within one hundred twenty (120) days after the end of each Fiscal Year, or, for the first Fiscal Year end after the Effective Date, within one hundred fifty (150) days after end of such Fiscal Year, a copy of the audited Consolidated and unaudited Consolidating financial statements of the Administrative Borrower and its Consolidated Subsidiaries as at the end of such Fiscal Year and the related audited Consolidated and unaudited Consolidating statements of income, stockholders equity, and cash flows of the Administrative Borrower and its Consolidated Subsidiaries for such Fiscal Year or partial Fiscal Year and underlying assumptions, setting forth in each case in comparative form the figures for the previous Fiscal Year, certified as being fairly stated in all material respects by an independent, nationally recognized certified public accounting firm reasonably satisfactory to the Administrative Agent;
     (b) as soon as available, but in any event within forty-five (45) days after the end of each fiscal quarter of the Administrative Borrower (except the last quarter of each Fiscal Year), Administrative Borrower prepared unaudited Consolidated and Consolidating balance sheets of the Administrative Borrower and its Consolidated Subsidiaries as at the end of such quarter and the related unaudited statements of income, stockholders equity and cash flows of the Administrative Borrower and its Consolidated Subsidiaries for the portion of the Fiscal Year through the end of such quarter, setting forth in each case in comparative form the figures for the corresponding periods in the previous Fiscal Year, and certified by a Responsible Officer of the Administrative Borrower as being fairly stated in all material respects; and
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all such financial statements to be complete and correct in all material respects and to be prepared in reasonable detail and in accordance with GAAP throughout the periods reflected therein and with prior periods (except as approved by a Responsible Officer and disclosed therein), provided , however , that the financial statements delivered pursuant to clauses (b) hereof will not be required to include footnotes and will be subject to change from audit and year-end adjustments.
     7.2 Certificates; Other Information . Furnish to the Administrative Agent, in form and detail acceptable to the Administrative Agent, the following documents:
     (a) Concurrently with the delivery of the financial statements described in Sections 7.1(a) for each fiscal year end, and 7 .1(b) for each fiscal quarter end, a Covenant Compliance Report (or, in the case of the Administrative Borrower prepared financial statements for the last fiscal quarter of each fiscal year, a draft Covenant Compliance Report) duly executed by a Responsible Officer of the Administrative Borrower;
     (b) Promptly upon receipt thereof, copies of all significant reports submitted by the Administrative Borrower’s firm(s) of certified public accountants in connection with each annual, interim or special audit or review of any type of the financial statements or related internal control systems of the Administrative Borrower and its Consolidated Subsidiaries made by such accountants, including any comment letter submitted by such accountants to management in connection with their services;
     (c) Any financial reports, statements, press releases, other material information or written notices delivered to the holders of the Equity Interests of any Credit Party (to the extent not otherwise required hereunder), as and when delivered to such Persons;
     (d) Within thirty (30) days after the end of each Fiscal Year, projections for the Administrative Borrower and its Consolidated Subsidiaries for the next succeeding Fiscal Year, on a quarterly basis and for the following Fiscal Year on an annual basis, including a balance sheet, as at the end of each relevant period and for the period commencing at the beginning of the Fiscal Year and ending on the last day of such relevant period, such projections certified by a Responsible Officer of the Administrative Borrower as being based on reasonable estimates and assumptions taking into account all facts and information known (or reasonably available to the Administrative Borrower or any of its Consolidated Subsidiaries) by a Responsible Officer of the Administrative Borrower;
     (e) Within forty-five (45) days after and as of the end of each fiscal quarter of the Administrative Borrower, a report certified by a Responsible Officer of the Administrative Borrower as to the volume of Hydrocarbons transported through the Pipeline Systems and the volume of Hydrocarbons processed in the processing plants of the Credit Parties, each organized by major operating unit;
     (f) Any additional information as required by any Loan Document, and such additional schedules, certificates and reports respecting all or any of the Collateral, the
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items or amounts received by any Borrower or any of its Subsidiaries in full or partial payment thereof, and any goods (the sale or lease of which shall have given rise to any of the Collateral) possession of which has been obtained by any Borrower or any of its Subsidiaries, all to such extent as the Administrative Agent may reasonably request from time to time, any such schedule, certificate or report to be certified as true and correct in all material respects by a Responsible Officer of the Administrative Borrower and shall be in such form and detail as the Administrative Agent may reasonably specify; and
     (g) Such additional financial and/or other information as the Administrative Agent or any Lender may from time to time reasonably request, promptly following such request.
     7.3 Payment of Obligations . Pay, discharge or otherwise satisfy, at or before maturity or before they become delinquent, as the case may be, all of its material obligations of whatever nature, including without limitation all assessments, governmental charges, claims for labor, supplies, rent or other obligations, except where (a) the amount or validity thereof is currently being appropriately contested in good faith and reserves in conformity with GAAP with respect thereto have been provided on the books of the Borrowers or their Subsidiaries or (ii) the failure to make such payment will not result in a Material Adverse Effect.
     7.4 Conduct of Business and Maintenance of Existence; Compliance with Laws .
     (a) Continue to engage in their respective business and operations substantially as conducted immediately prior to the Effective Date;
     (b) Preserve, renew and keep in full force and effect its existence and maintain its qualifications to do business in each jurisdiction where such qualifications are necessary for its operations, except as otherwise permitted pursuant to Section 8.4 ;
     (c) Take all action it deems necessary in its reasonable business judgment to maintain all rights, privileges, licenses and franchises necessary for the normal conduct of its business except where the failure to so maintain such rights, privileges or franchises could not, either singly or in the aggregate, reasonably be expected to have a Material Adverse Effect;
     (d) Comply with all Contractual Obligations and Requirements of Law, except to the extent that failure to comply therewith could not, either singly or in the aggregate, reasonably be expected to have a Material Adverse Effect; and
     (e) (i) Continue to be a Person whose property or interests in property is not blocked or subject to blocking pursuant to Section 1 of Executive Order 13224 of September 23, 2001 Blocking Property and Prohibiting Transactions With Persons Who Commit, Threaten to Commit or Support Terrorism (66 Fed. Reg. 49079 (2001)) (the “ Order ”), (ii) not engage in the transactions prohibited by Section 2 of that Order or become associated with Persons such that a violation of Section 2 of the Order would arise, and (iii) not become a Person on the list of Specially Designated National and Blocked Persons, or (iv) otherwise not become subject to the limitation of any OFAC regulation or executive order.
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     7.5 Maintenance of Property; Insurance . (a) Keep all material property it deems, in its reasonable business judgment, useful and necessary in its business in working order (ordinary wear and tear excepted), including, without limitation, all material Pipeline Systems and other Real Property; (b) (i) maintain or cause the maintenance of the interests and rights (A) which are necessary to maintain the Easements for the Pipeline Systems and to maintain the other Real Property, and (B) which individually and in the aggregate, could, if not maintained, reasonably be expected to have a Material Adverse Effect; (ii) subject to the Permitted Liens, maintain the Pipeline Systems within the confines of the descriptions contained in the Easements without material encroachment upon any adjoining property and maintain the Real Property within the confines of descriptions contained in the Deeds without material encroachment upon any adjoining property; (iii) maintain such rights of ingress and egress necessary to permit any applicable Borrower or any of its applicable Subsidiaries to inspect, operate, repair and maintain the Pipeline Systems and the other Real Property except to the extent that the failure to maintain such rights, individually or in the aggregate, could not reasonably be expected to have a Material Adverse Effect and provided that any applicable Borrower or any of its applicable Subsidiaries may hire third parties to perform these functions; and (iv) maintain all material agreements, licenses, permits and other rights required for any of the foregoing described in clauses (i) , (ii) and (iii) of this Section 7.5(b) in full force and effect in accordance with their terms, timely make any payments due thereunder, and prevent any default thereunder that could result in a termination or loss thereof, except any such failure to pay or default that could not reasonably, individually or in the aggregate, be expected to cause a Material Adverse Effect; (c) maintain insurance coverage with financially sound and reputable insurance companies on physical assets and against other business risks in such amounts and of such types as are customarily carried by companies similar in size and nature in the midstream oil and gas industry (including without limitation casualty and public liability and property damage insurance), and in the event of acquisition of additional property, real or personal, or of the incurrence of additional risks of any nature, increase such insurance coverage in such manner and to such extent as prudent business judgment and present practice or any applicable Requirements of Law would dictate; (d) in the case of all insurance policies covering any Collateral, such insurance policies shall provide that the loss payable thereunder shall be payable to any applicable Borrower or any of its applicable Subsidiaries, and to the Administrative Agent (as mortgagee, or, in the case of personal property interests, lender loss payee) as their respective interests may appear; (e) in the case of all public liability insurance policies, such policies shall list the Administrative Agent as an additional insured, as the Administrative Agent may reasonably request; and (f) if requested by the Administrative Agent, certificates evidencing such policies, including all endorsements thereto, to be deposited with the Administrative Agent, such certificates being in form and substance reasonably acceptable to the Administrative Agent.
     7.6 Inspection of Property; Books and Records, Discussions . Permit the Administrative Agent, through their authorized attorneys, accountants and representatives (a) at all reasonable times during normal business hours following advance notice if no Default exists, upon the request of the Administrative Agent, to examine each Borrower’s and each of their Subsidiaries’ books, accounts, records, ledgers and assets and properties; (b) from time to time, during normal business hours, upon the request of the Administrative Agent, to conduct full or partial collateral audits of the Accounts and Inventory of the Borrowers and their Subsidiaries and appraisals of all or a portion of the fixed assets (including Pipeline Systems and other Real Property to the extent accompanied by a representative of the applicable Borrower or its
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applicable Subsidiary(ies), such accompaniment to take place at the reasonable request of the Administrative Agent or any Lender, and subject to the terms of any applicable Easements) of the Borrowers and their Subsidiaries, such audits and appraisals to be completed by an appraiser as may be selected by the Administrative Agent and consented to by the Administrative Borrower (such consent not to be unreasonably withheld), with all reasonable costs and expenses of such audits to be reimbursed by the Borrowers and their Subsidiaries, provided that , so long as no Event of Default or Default exists, such audits shall be limited to once each Fiscal Year and the Borrowers shall not be required to reimburse the Administrative Agent for such audits more frequently than once each Fiscal Year; (c) during normal business hours and at their own risk and to the extent accompanied by a representative of the applicable Borrower or its applicable Subsidiary(ies), such accompaniment to take place at the reasonable request of the Administrative Agent or any Lender, and subject to the terms of any applicable Easements, to enter onto the Real Property and Easements owned or leased by any Borrower or any of its Subsidiaries to conduct inspections, investigations or other reviews of such Real Property and Easements; and (d) at reasonable times during normal business hours following advance notice and at reasonable intervals, to visit all of any Borrower’s and any of its Subsidiaries’ offices, discuss each Borrower’s and its Subsidiaries’ respective financial matters with their respective officers, as applicable, and, by this provision, each Borrower authorizes, and will cause each of its Subsidiaries to authorize, its independent certified or chartered public accountants to discuss the finances and affairs of such Borrower and any of its Subsidiaries and examine any of such Borrower’s and any of its Subsidiaries’ books, reports or records held by such accountants, subject, in each case, to the policies and procedures of such certified or chartered public accountants.
     7.7 Notices . Promptly give written notice to the Administrative Agent of:
     (a) the occurrence of any Default or Event of Default of which any Borrower or any of its Subsidiaries has knowledge;
     (b) any (i) litigation or proceeding existing at any time between any Borrower or any of its Subsidiaries and any Governmental Authority or other third party, or any investigation of any Borrower or any of its Subsidiaries conducted by any Governmental Authority, which in any case if adversely determined would have a Material Adverse Effect, including, without limitation, any form of material notice, summons, citation, proceeding or order received from the FERC, any State Pipeline Regulatory Agency or any other Governmental Authority concerning the regulation of any material portion of the Pipeline Systems or other Real Property, or (ii) any material adverse change in the financial condition of any Borrower or any of its Subsidiaries since the date of the last audited financial statements delivered pursuant to Section 7.1(a) hereof;
     (c) the occurrence of any event which any Borrower or any of its Subsidiaries believes could reasonably be expected to have a Material Adverse Effect, promptly after concluding that such event could reasonably be expected to have such a Material Adverse Effect;
     (d) promptly after becoming aware thereof, the taking by the Internal Revenue Service or any foreign taxing jurisdiction of a written tax position (or any such tax
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position taken by any Borrower or any of its Subsidiaries in a filing with the Internal Revenue Service or any foreign taxing jurisdiction) which could reasonably be expected to have a Material Adverse Effect, setting forth the details of such position and the financial impact thereof;
     (e) (i) all jurisdictions in which any Borrower or any of its Subsidiaries proposes to become qualified after the Effective Date to transact business, (ii) the acquisition or creation of any new Subsidiaries, (iii) any material change after the Effective Date in the authorized and issued Equity Interests of any Borrower or any of its Subsidiaries or any other material amendment to any Borrower’s or any of its Subsidiaries’ charter, by-laws or other organizational documents, such notice, in each case, to identify the applicable jurisdictions, capital structures or amendments as applicable, provided that such notice shall be given not less than ten (10) Business Days prior to the proposed effectiveness of such changes, acquisition or creation, as the case may be (or such shorter period to which the Administrative Agent may consent);
     (f) any default or event of default by any Person under any Subordinated Debt Document, concurrently with delivery or promptly after receipt (as the case may be) of any notice of default or event of default under the applicable document, as the case may be; and
     (g) not less than ten (10) days prior to the proposed effective date thereof, any proposed Asset Sale that is not expressly permitted hereby, together with any purchase and sale agreement, bills of sale, assignments, agreements, instruments and other documents to be executed and delivered in connection therewith.
Each notice pursuant to this Section shall be accompanied by a statement of a Responsible Officer of the Administrative Borrower setting forth details of the occurrence referred to therein and, in the case of notices referred to in clauses (a) , (b) , (c) , (d) , (f) and (g) hereof stating what action the applicable Borrower or its applicable Subsidiaries has taken or proposes to take with respect thereto.
     7.8 Hazardous Material Laws .
     (a) Use and operate all of its facilities and properties in material compliance with all applicable Hazardous Material Laws, keep all material required permits, approvals, certificates, licenses and other authorizations required under such Hazardous Material Laws in effect and remain in compliance therewith, and handle all Hazardous Materials in material compliance with all applicable Hazardous Material Laws;
     (b) (i) Promptly notify the Administrative Agent and provide copies upon receipt of all written claims, complaints, notices or inquiries received by any Borrower or any of its Subsidiaries relating to its facilities and properties or compliance with Hazardous Material Laws which, if adversely determined, could reasonably be expected to have a Material Adverse Effect and (ii) promptly cure and have dismissed with prejudice to the reasonable satisfaction of the Administrative Agent and the Majority Lenders any material actions and proceedings relating to compliance with Hazardous
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Material Laws to which any Borrower or any of its Subsidiaries is named a party, other than such actions or proceedings being contested in good faith and with the establishment of reasonable reserves;
     (c) To the extent necessary to comply in all material respects with Hazardous Material Laws, remediate or monitor contamination arising from a release or disposal of Hazardous Material, which solely, or together with other releases or disposals of Hazardous Materials could reasonably be expected to have a Material Adverse Effect;
     (d) Provide such information and certifications which the Administrative Agent or any Lender may reasonably request from time to time to evidence compliance with this Section 7.8 .
     7.9 Financial Covenants .
     (a) Interest Coverage Ratio . Maintain, as of end of each Test Period and as of the date of each Advance and each date of issuance of a Letter of Credit, an Interest Coverage Ratio of not less than 2.50:1.00.
     (b) Total Debt to Consolidated EBITDA Ratio . Maintain, as of the end of each Test Period and as of the date of each Advance and each date of issuance of a Letter of Credit, a Total Debt to Consolidated EBITDA Ratio of not more than 3.50:1.00.
     7.10 Governmental and Other Approvals . Apply for, obtain and/or maintain in effect, as applicable, all authorizations, consents, approvals, licenses, qualifications, exemptions, filings, declarations and registrations (whether with any court, governmental agency, regulatory authority, securities exchange or otherwise) which are necessary in connection with the execution, delivery and performance by any Borrower or any of its Subsidiaries of, as applicable, this Agreement, the other Loan Documents or any other documents or instruments to be executed and/or delivered by any Borrower or any of its Subsidiaries, as applicable in connection therewith or herewith, except where the failure to so apply for, obtain or maintain could not reasonably be expected to have a Material Adverse Effect.
     7.11 Compliance with ERISA; ERISA Notices .
     (a) Comply in all material respects with all material requirements imposed by ERISA and the Internal Revenue Code, including, but not limited to, the minimum funding requirements for any Pension Plan, except to the extent that any noncompliance could not reasonably be expected to have a Material Adverse Effect.
     (b) Promptly notify the Administrative Agent upon the occurrence of any of the following events in writing: (i) the termination, other than a standard termination, as defined in ERISA, of any Pension Plan subject to Subtitle C of Title IV of ERISA by any Borrower or any of its Subsidiaries; (ii) the appointment of a trustee by a United States District Court to administer any Pension Plan subject to Title IV of ERISA; (iii) the commencement by the PBGC, of any proceeding to terminate any Pension Plan subject to Title IV of ERISA; (iv) the failure of any Borrower or any of its Subsidiaries to make any payment in respect of any Pension Plan required under Section 412 of the Internal
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Revenue Code or Section 302 of ERISA; (v) the withdrawal of any Borrower or any of its Subsidiaries from any Multiemployer Plan if any Borrower or any of its Subsidiaries reasonably believes that such withdrawal would give rise to the imposition of Withdrawal Liability with respect thereto; or (vi) the occurrence of (x) a “ reportable event ” which is required to be reported by any Borrower or any of its Subsidiary under Section 4043 of ERISA other than any event for which the reporting requirement has been waived by the PBGC or (y) a “ prohibited transaction ” as defined in Section 406 of ERISA or Section 4975 of the Internal Revenue Code other than a transaction for which a statutory exemption is available or an administrative exemption has been obtained.
     7.12 Defense of Collateral . Defend the Collateral from any Liens other than Liens permitted by Section 8.2 .
     7.13 Future Subsidiaries; Additional Collateral .
     (a) With respect to each Person which becomes a Domestic Subsidiary of any Borrower (directly or indirectly) subsequent to the Effective Date, whether by Permitted Acquisition or otherwise, cause such new Domestic Subsidiary to execute and deliver to the Administrative Agent, for and on behalf of each of the Lenders (unless waived by the Administrative Agent):
     (i) to the extent such new Domestic Subsidiary is not a Material Subsidiary, within thirty (30) days after the date such Person becomes a Domestic Subsidiary (or such longer time period as the Administrative Agent may determine), a Guaranty, or in the event that a Guaranty already exists, a joinder agreement to the Guaranty whereby such Domestic Subsidiary becomes obligated as a Guarantor under the Guaranty;
     (ii) to the extent such new Domestic Subsidiary is a Material Subsidiary, within thirty (30) days after the date such Person becomes a Domestic Subsidiary (or such longer time period as the Administrative Agent may determine), a Joinder whereby such Domestic Subsidiary becomes obligated as a Borrower under this Agreement;
     (iii) within thirty (30) days after the date such Person becomes a Domestic Subsidiary (or such longer time period as the Administrative Agent may determine), a joinder agreement to the Security Agreement whereby such Domestic Subsidiary grants a Lien over its assets (other than Equity Interests which should be governed by (b) of this Section 7.13 ) as set forth in the Security Agreement, and such Domestic Subsidiary shall take such additional actions as may be necessary to ensure a valid first priority perfected Lien over such assets of such Domestic Subsidiary, subject only to the other Liens permitted pursuant to Section 8.2 of this Agreement; and
     (iv) within the time period specified in and to the extent required under clause (c) of this Section 7.13 , a Mortgage and/or other documents required to be delivered in connection therewith.
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     (b) With respect to the Equity Interests of each Person which becomes (whether by Permitted Acquisition or otherwise) (i) a Domestic Subsidiary subsequent to the Effective Date, cause each Borrower or its applicable Subsidiary that holds such Equity Interests to execute and deliver such Pledge Agreements, and take such actions as may be necessary to ensure a valid first priority perfected Lien over one hundred percent (100%) of the Equity Interests of such Domestic Subsidiary held by each applicable Borrower or its applicable Subsidiary, such Pledge Agreements to be executed and delivered (unless waived by the Administrative Agent) within thirty (30) days after the date such Person becomes a Domestic Subsidiary (or such longer time period as the Administrative Agent may determine); and (ii) a Foreign Subsidiary subsequent to the Effective Date, the Equity Interests of which is held directly by any Borrower or one of its Domestic Subsidiaries, cause each applicable Borrower or its applicable Subsidiary that holds such Equity Interests to execute and deliver such Pledge Agreements and take such actions as may be necessary to ensure a valid first priority perfected Lien over sixty-five percent (65%) of the Equity Interests of such Subsidiary, such Pledge Agreements to be executed and delivered (unless waived by the Administrative Agent) within thirty (30) days after the date such Person becomes a Foreign Subsidiary (or such longer time period as the Administrative Agent may determine); and
     (c) With respect to the acquisition of a fee interest in Pipeline Systems and/or other Real Property by any Borrower or any of its Subsidiaries after the Effective Date (whether by Permitted Acquisition or otherwise), not later than thirty (30) days after the acquisition is consummated or the owner of such property becomes a Domestic Subsidiary (or such longer time period as the Administrative Agent may determine), such party shall execute or cause to be executed (unless waived by the Administrative Agent), a Mortgage (or an amendment to an existing mortgage, where appropriate) covering such Pipeline Systems and/or other Real Property, together with such additional real estate documentation and environmental reports, as may be reasonably required by the Administrative Agent;
in each case in form reasonably satisfactory to the Administrative Agent, in its reasonable discretion, together with such supporting documentation, including without limitation corporate authority items, certificates and opinions of counsel, as reasonably required by the Administrative Agent. Upon the Administrative Agent’s request, the Borrowers and their Subsidiaries shall take, or cause to be taken, such additional steps as are necessary or advisable under applicable law to perfect and ensure the validity and priority of the Liens granted under this Section 7.13 .
     7.14 Accounts . Maintain all deposit accounts and securities accounts of each Borrower and its Subsidiaries with the Administrative Agent or a Lender, provided that, with respect to any such accounts maintained with any Lender (other than the Administrative Agent), such party (i) shall cause to be executed and delivered an Account Control Agreement in form and substance satisfactory to the Administrative Agent and (ii) has taken all other steps necessary, or in the opinion of the Administrative Agent, desirable to ensure that the Administrative Agent has a perfected security interest in such account; provided , however , notwithstanding the foregoing, each operating account of each Borrower shall be maintained with the Administrative Agent at all times.
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     7.15 Use of Proceeds . Use all Advances of the Revolving Credit as set forth in Section 2.12 hereof and the proceeds of the Term Loan as set forth in Section 4.9 hereof. The Borrowers shall not use any portion of the proceeds of any such advances for the purpose of purchasing or carrying any “ margin stock ” (as defined in Regulation U of the Board of Governors of the Federal Reserve System) in any manner which violates the provisions of Regulation T, U or X of said Board of Governors or for any other purpose in violation of any applicable statute or regulation.
     7.16 Hedging Transaction . Within thirty (30) days following the Effective Date, the Borrowers shall enter into an interest rate Hedging Agreement sufficient, at the minimum, to cover fifty percent (50%) of the aggregate outstanding principal amount of the Revolving Credit Advances as of the Effective Date and the Term Loan for a two-year period following the execution of such Hedging Agreement. The Hedging Agreement shall be in form and substance reasonably acceptable to the Administrative Agent.
     7.17 Further Assurances and Information .
     (a) Take such actions as the Administrative Agent or Majority Lenders may from time to time reasonably request to establish and maintain first priority perfected security interests in and Liens on all of the Collateral, subject only to those Liens permitted under Section 8.2 hereof, including executing and delivering such additional pledges, assignments, mortgages, lien instruments or other security instruments covering any or all of the Borrowers’ and their Subsidiaries’ assets as the Administrative Agent may reasonably require, such documentation to be in form and substance reasonably acceptable to the Administrative Agent, and prepared at the expense of the Borrowers.
     (b) Execute and deliver or cause to be executed and delivered to the Administrative Agent within a reasonable time following the Administrative Agent’s request, and at the expense of the Borrowers, such other documents or instruments as the Administrative Agent may reasonably require to effectuate more fully the purposes of this Agreement or the other Loan Documents and to provide for Advances under and payment of Notes in accordance with the intents and purposes herein and therein expressed.
     (c) Provide the Administrative Agent, within five (5) Business Days following the Administrative Agent’s request therefor, with any other information required by Section 326 of the USA Patriot Act or necessary for the Administrative Agent and the Lenders to verify the identity of each Borrower and any of its Subsidiaries as required by Section 326 of the USA Patriot Act.
     7.18 Notices Relating to Acquisition . In the event that after the Effective Date: (i) the Administrative Borrower is required or elects to purchase any of the Acquisition Properties which had been excluded from, or return any of the Acquisition Properties which had been included in, the Acquisition Properties in accordance with the terms of the Acquisition Documents, (ii) the Administrative Borrower is required to honor any preferential purchase right in respect of any Acquisition Property which has not been waived, (iii) any matter being disputed in accordance with the terms of the Acquisition Documents is resolved or (iv) the Administrative
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Borrower and the Seller calculate and agree upon the “ closing adjustment statement ” or “ post-closing adjustment statement ” as contemplated by the Acquisition Documents, then, in each such case, promptly give the Administrative Agent notice in reasonable detail of such circumstances.
     7.19 Required Life Insurance . Maintain key man life insurance policy(ies) in reasonable form and substance satisfactory to the Administrative Agent and issued by an insurance company satisfactory to the Administrative Agent insuring the life of the chief executive officer of Administrative Borrower from time to time holding such office, which chief executive officer is Brian Bierbach as of the Effective Date, in the amount of $5,000,000.
     7.20 Enforcement of Material Contracts . Enforce all materials rights and interests under each Material Contract except to the extent any failure to so enforce such rights (i) does not violate the terms of this Agreement or any of the other Loan Documents, (ii) does not material adversely affect the interest of the Lenders as creditors and/or secured parties under any Loan Document and (iii) could not reasonably be expected to have a Material Adverse Effect.
     7.21 Projections . Within sixty (60) days following the Effective Date, the Borrowers shall deliver the monthly projections of the Administrative Borrower and its Consolidated Subsidiaries through December, 2010.
     7.22 Bamagas . Use commercially reasonable efforts to obtain the Consent, and, to the extent the Consent is not obtained prior the Effective Date, within five (5) Business Days of obtaining the Consent, cause Bamagas to execute and deliver to the Administrative Agent, for and on behalf of each of the Lenders (unless waived by the Administrative Agent), the items described in Section 7.13(a) hereof that are otherwise required to be executed and delivered by each Person which becomes a Domestic Subsidiary of any Borrower (directly or indirectly) subsequent to the Effective Date, whether by Permitted Acquisition or otherwise.
8. NEGATIVE COVENANTS.
     Each Borrower covenants and agrees that, so long as any Lender has any commitment to extend credit hereunder, or any of the Indebtedness remains outstanding and unpaid, it will not, and, as applicable, it will not permit any of its Subsidiaries to:
     8.1 Limitation on Debt . Create, incur, assume or suffer to exist any Debt, except:
     (a) Indebtedness of any Borrower or any of its Subsidiaries to the Administrative Agent and the Lenders under this Agreement and/or the other Loan Documents;
     (b) any Debt existing on the Effective Date and set forth in Schedule 8.1 attached hereto and any renewals or refinancing of such Debt (provided that (i) the aggregate principal amount of such renewed or refinanced Debt shall not exceed the aggregate principal amount of the original Debt outstanding on the Effective Date (less any principal payments on term Debt and the amount of any commitment reductions made thereon on or prior to such renewal or refinancing), (ii) the renewal or refinancing of such Debt shall be on substantially the same or better terms as in effect with respect to such Debt on the Effective Date, and shall otherwise be in compliance with this
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Agreement, and (iii) at the time of such renewal or refinancing no Default or Event of Default has occurred and is continuing or would result from the renewal or refinancing of such Debt;
     (c) any Debt of any Borrower or any Subsidiary incurred to finance the acquisition of fixed or capital assets, whether pursuant to a loan or a Capitalized Lease provided that both at the time of and immediately after giving effect to the incurrence thereof (i) no Default or Event of Default shall have occurred and be continuing, and (ii) the aggregate amount of all such Debt at any one time outstanding (including, without limitation, any Debt of the type described in this clause (c) which is set forth on Schedule 8.1 hereof) shall not exceed $1,000,000, and any renewals or refinancings of such Debt on terms substantially the same or better than those in effect at the time of the original incurrence of such Debt;
     (d) any Debt of any Borrower or any Subsidiary that is assumed to finance the cost of Permitted Acquisitions to the extent all such Debt at any one time outstanding does not exceed $1,000,000;
     (e) Debt under any Hedging Transactions, provided that such transaction is entered into for risk management purposes and not for speculative purposes;
     (f) Debt arising from judgments or decrees not deemed to be a Default or Event of Default under subsection (g) of Section 9.1 ;
     (g) Debt owing to a Person that is a Credit Party, but only to the extent permitted under Section 8.6 hereof;
     (h) Debt incurred in connection with the Permitted Sale/Leaseback Transactions; and
     (i) the guarantee of or other reimbursement obligations in connection with performance bonds issued in connection with or related to the Pipeline Systems to the extent all such Debt at any one time outstanding does not exceed $1,000,000; and
     (j) additional unsecured Debt not otherwise described above, provided that both at the time of and immediately after giving effect to the incurrence thereof (i) no Default or Event of Default shall have occurred and be continuing or result therefrom and (ii) the aggregate amount of all such Debt shall not exceed $1,000,000 at any one time outstanding.
Notwithstanding the foregoing, however, Debt of the type described in clauses (c) , (d) and (j) of this Section 8.1 shall not be permitted to be incurred or assumed by Bamagas until such time as the Consent is obtained and the other terms and provisions of Section 7.22 have been satisfied in full.
     8.2 Limitation on Liens . Create, incur, assume or suffer to exist any Lien upon any of its property, assets or revenues, whether now owned or hereafter acquired, except for:
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     (a) Permitted Liens;
     (b) Liens securing Debt permitted by Section 8.1(c) , provided that , (i) such Liens are created upon fixed or capital assets acquired or leased by the applicable Borrower or its applicable Subsidiary after the date of this Agreement (including without limitation by virtue of a loan or a Capitalized Lease), (ii) any such Lien is created solely for the purpose of securing indebtedness representing or incurred to finance the cost of the acquisition, construction or improvement of the item of property subject thereto, (iii) the principal amount of the Debt secured by any such Lien shall at no time exceed 100% of the sum of the purchase price or cost of the applicable property, equipment or improvements and the related costs and charges imposed by the vendors thereof and (iv) the Lien does not cover any property other than the fixed or capital asset acquired; provided , however , that no such Lien shall be created over any owned Pipeline Systems or other Real Property of any Borrower or any of its Subsidiaries for which the Administrative Agent has received a Mortgage or for which such party is required to execute a Mortgage pursuant to the terms of this Agreement;
     (c) Liens created pursuant to the Loan Documents;
     (d) any escrow account of the Administrative Borrower required by the Seller for obligations under the Acquisition documents;
     (e) other Liens, existing on the Effective Date, set forth on Schedule 8.2 and renewals, refinancings and extensions thereof on substantially the same or better terms as in effect on the Effective Date and otherwise in compliance with this Agreement;
     (f) Liens to secure Hedging Transactions with any of the Lenders or Affiliates thereof;
     (g) Liens existing on any property or asset prior to the acquisition thereof by any Borrower or any of its Subsidiaries or existing on any property or asset of any Person that becomes a Subsidiary after the Effective Date prior to the time such Person becomes a Subsidiary; provided that (i) such Liens are not created in contemplation of or in connection with such acquisition or such Person becoming a Subsidiary, as applicable, (ii) such Liens shall not apply to any other property or assets of any Borrower or any of its other Subsidiaries, (iii) such Liens shall secure only those obligations which it secures on the date of such acquisition or the date such Person becomes a Subsidiary, as applicable, and extensions, renewals, refinancings and replacements thereof that do not increase the outstanding principal amount thereof and (iv) the Debt secured by such Lien is Debt permitted under Section 8.1(d) hereof;
     (h) Liens arising solely by virtue of any statutory or common law provisions relating to banker’s Liens, rights of set-off, netting or similar rights and remedies as to deposit, securities and commodities accounts;
     (i) Liens of sellers of goods to any Borrower or any of its Subsidiaries arising under Article 2 of the Uniform Commercial Code or similar provision of applicable law
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and any deposits with vendors in the ordinary course of business solely in connection with the purchase of such goods;
     (j) Liens arising out of conditional sale, title retention, consignment or similar arrangements, or by way of contract that secures Debt under any agreement, for the sale of goods and services, in each case, in the ordinary course of business; and
     (k) Liens arising in connection with the Permitted Sale/Leaseback Transactions.
Regardless of the provisions of this Section 8.2 , no Lien over the Equity Interests of any Borrower or any Subsidiary of any Borrower (except for those Liens for the benefit of the Administrative Agent and the Lenders) shall be permitted under the terms of this Agreement.
     8.3 Acquisitions . Except for Permitted Acquisitions and acquisitions permitted under Section 8.6 , if any, purchase or otherwise acquire or become obligated for the purchase of all or substantially all or any material portion of the assets or business interests or a division or other business unit of any Person, or any Equity Interest of any Person, or any business or going concern.
     8.4 Limitation on Mergers, Dissolution or Sale of Assets . Enter into any merger or consolidation or convey, sell, lease, assign, transfer or otherwise dispose of any of its property, business or assets (including, without limitation, Equity Interests, receivables and leasehold interests), whether now owned or hereafter acquired or liquidate, wind up or dissolve, except:
     (a) Inventory leased or sold in the ordinary course of business;
     (b) obsolete, damaged, uneconomic or worn out machinery, parts, property or equipment, or property or equipment no longer used or useful in the conduct of the businesses of the Borrowers or their Subsidiaries;
     (c) mergers or consolidations of any Subsidiary of any Borrower with or into any Borrower or any Guarantor so long as such Borrower or such Guarantor shall be the continuing or surviving entity; provided that at the time of each such merger or consolidation, both before and after giving effect thereto, no Default or Event of Default shall have occurred and be continuing or result from such merger or consolidation;
     (d) any Subsidiary of any Borrower may liquidate or dissolve into a Borrower or a Guarantor if the Borrowers determine in good faith that such liquidation or dissolution is in the best interests of the Borrowers, so long as no Default or Event of Default has occurred and is continuing or would result therefrom;
     (e) sales or transfers, including without limitation upon voluntary liquidation from any of the Borrowers’ Subsidiaries to a Borrower or a Guarantor, provided that the applicable Borrower or Guarantor takes such actions as the Administrative Agent may reasonably request to ensure the perfection and priority of the Liens in favor of the Lenders over such transferred assets;
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     (f) subject to Section 4.8(a) hereof, (i) Asset Sales (exclusive of asset sales permitted pursuant to all other subsections of this Section 8.4 ) in which the sales price is at least equal to the fair market value of the assets sold and the consideration received is cash or cash equivalents or Debt of any Borrower or any of its Subsidiaries being assumed by the purchaser, provided that the aggregate amount of such Asset Sales does not exceed $2,500,000 in any Fiscal Year and no Default or Event of Default has occurred and is continuing at the time of each such sale (both before and after giving effect to such Asset Sale), and (ii) other Asset Sales approved by the Majority Lenders in their sole discretion;
     (g) the sale or disposition of Permitted Investments and other cash equivalents in the ordinary course of business;
     (h) dispositions of owned or leased vehicles in the ordinary course of business; and
     (i) the Permitted Sale/Leaseback Transactions.
The Lenders hereby consent and agree to the release by the Administrative Agent of any and all Liens on the property sold or otherwise disposed of in compliance with this Section 8.4 .
     8.5 Restricted Payments . Declare or make any distributions, dividend, payment or other distribution of assets, properties, cash, rights, obligations or securities (collectively, “ Distributions ”) on account of any of its Equity Interests, as applicable, or purchase, redeem or otherwise acquire for value any of its Equity Interests, as applicable, or any warrants, rights or options to acquire any of its Equity Interests, now or hereafter outstanding (collectively, “ Purchases ”), except to the extent each of the following conditions are satisfied:
     (a) no Default or Event of Default exists or would, after giving effect thereto, exist;
     (b) the Total Debt to Consolidated EBITDA Ratio is less than 3.00:1.00 as of the most recently ended Test Period, but including any Debt incurred between the end of such Test Period and the date of the applicable Distribution or Purchase and excluding any Debt paid between the end of such Test Period and the date of the applicable Distribution or Purchase; and
     (c) the Borrowers have Unused Revolving Credit Availability of at least $7,500,000.
     8.6 Limitation on Investments, Loans and Advances . Make or allow to remain outstanding any Investment (whether such investment shall be of the character of investment in shares of stock, evidences of indebtedness or other securities or otherwise) in, or any loans or advances to, any Person other than:
     (a) Permitted Investments;
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     (b) Investments existing on the Effective Date and listed on Schedule 8.6 hereof;
     (c) sales on open account in the ordinary course of business;
     (d) intercompany loans or intercompany Investments made by any Borrower or any of its Subsidiaries to or in any Guarantor or any other Borrower; provided that, in the case of any intercompany loans or intercompany Investments made by any Borrower in Guarantors (excluding the Parent and the Parent General Partner), the aggregate amount from time to time outstanding in respect thereof shall not exceed $1,000,000; and provided, further, that in each case, no Default or Event of Default shall have occurred and be continuing at the time of making such intercompany loan or intercompany Investment or result from such intercompany loan or intercompany Investment being made and that any intercompany loans are Collateral pledged to the Administrative Agent under the appropriate Collateral Documents and are, to the extent requested by the Administrative Agent, evidenced by and funded under an Intercompany Note pledged to the Administrative Agent under the appropriate Collateral Documents; provided , however , notwithstanding the foregoing and for the avoidance of doubt, there is no limitation on Investments by any Borrower in the Parent or the Parent General Partner for purposes of reimbursement or payment of employee-related costs such as payroll and benefits;
     (e) Investments in respect of Hedging Transactions provided that such transaction is entered into for risk management purposes and not for speculative purposes;
     (f) loans and advances to employees, officers and directors of any Borrower or any of its Subsidiaries for moving, entertainment, travel and other similar expenses in the ordinary course of business in an aggregate amount not exceed $100,000 at any time outstanding;
     (g) Permitted Acquisitions and Investments in any Person acquired pursuant to a Permitted Acquisition;
     (h) Investments constituting deposits made in connection with the purchase of goods or services in the ordinary course of business in an aggregate amount for such deposits not to exceed $500,000 at any one time outstanding; and
     (i) other Investments not described above provided that both at the time of and immediately after giving effect to any such Investment (i) no Default or Event of Default shall have occurred and be continuing or shall result from the making of such Investment and (ii) the aggregate amount of all such Investments shall not exceed $500,000 at any time outstanding.
In valuing any Investments for the purpose of applying the limitations set forth in this Section 8.6 (except as otherwise expressly provided herein), such Investment shall be taken at the original cost thereof, without allowance for any subsequent write-offs or appreciation or depreciation, but less any amount repaid or recovered on account of capital or principal.
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     8.7 Transactions with Affiliates . Except as set forth in Schedule 8.7 and as limited in Section 8.13 hereof, enter into any transaction, including, without limitation, any purchase, sale, lease or exchange of property or the rendering of any service, with any Affiliates of any Borrower and its Subsidiaries except: (a) transactions with Affiliates that are the Borrowers or Guarantors; (b) transactions otherwise permitted under this Agreement; and (c) transactions in the ordinary course of the businesses of the Borrowers and their Subsidiaries and upon fair and reasonable terms no less favorable to such party than it would obtain in a comparable arms length transaction from unrelated third parties.
     8.8 Sale-Leaseback Transactions . Except for the Permitted Sale/Leaseback Transactions, enter into any arrangement with any Person providing for the leasing by any Borrower or its Subsidiaries of real or personal property which has been or is to be sold or transferred by such party to such Person or to any other Person to whom funds have been or are to be advanced by such Person on the security of such property or rental obligations of such party, as the case may be.
     8.9 Limitations on Other Restrictions . Except for this Agreement or any other Loan Document, enter into any agreement, document or instrument which would (i) restrict the ability of any Subsidiary of any Borrower to pay or make dividends or distributions in cash or kind to any Borrower or any Guarantor, to make loans, advances or other payments of whatever nature to any Borrower or any of its Subsidiaries, or to make transfers or distributions of all or any part of its assets to any Borrower or any of its Subsidiaries; or (ii) restrict or prevent any Borrower or any of its Subsidiaries from granting the Administrative Agent on behalf of Lenders Liens upon, security interests in and pledges of their respective assets, except to the extent such restrictions exist in documents creating Liens permitted by Section 8.2(b) hereunder.
     8.10 Reserved .
     8.11 Reserved .
     8.12 Modification of Certain Agreements . Make, permit or consent to any amendment or other modification to the constitutional documents of any Borrower or any of its Subsidiaries or any Material Contract except to the extent that any such amendment or modification (i) does not violate the terms and conditions of this Agreement or any of the other Loan Documents, and (ii) could not reasonably be expected to have a Material Adverse Effect; provided , however , the Administrative Agent shall have received a true and correct copy of any such amendment or other modification at least five (5) Business Days prior to the execution and delivery thereof.
     8.13 Management Fees . Pay or otherwise advance, directly or indirectly, any management, consulting or other fees to an Affiliate; provided , however , that so long as no Default has occurred and is continuing or, after giving effect to such payment or advance, would exist, the Borrowers may pay management, consulting or other fees as described in the Advisory Services Agreement in effect on the Closing Date, as amended with the consent of the Administrative Agent, such consent not to be unreasonably withheld.
     8.14 Fiscal Year . Permit the Fiscal Year of any Borrower or any of its Subsidiaries to end on a day other than December 31.
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     8.15 Acquisition Documents . Amend, modify or supplement any of the Acquisition Documents if the effect thereof could reasonably be expected to have a Material Adverse Effect (and provided that the Administrative Borrower promptly furnishes to the Administrative Agent a copy of such amendment, modification or supplement).
     8.16 State and FERC Regulatory Authority . Except in the ordinary course of business (to the extent that the Administrative Agent receives notice within five (5) Business Days thereof), knowingly take any action or permit any Borrower or any of its Subsidiaries to take any action which could cause any Borrower’s or any of its Subsidiaries’ business that is not already so regulated or treated to be (a) regulated as a “ utility ”, “ public utility ” or a “ gas utility ” by any State Pipeline Regulatory Agency; (b) deemed to be providing any service that would require the prior approval of any State Pipeline Regulatory Agency in order to discontinue or abandon such service; (c) within the meaning of the regulations of any State Pipeline Regulatory Agency be deemed to be charging a “ residential rate ” or “ commercial rate ” or (ii) providing “ gas utility service to residential and small commercial customers ” (within the meaning of Section 7.45 of the rules of the Texas Railroad Commission); or (d) subject to FERC jurisdiction.
9. DEFAULTS.
     9.1 Events of Default . The occurrence of any of the following events shall constitute an Event of Default hereunder:
     (a) non-payment when due of (i) the principal or interest on the Indebtedness under the Revolving Credit (including the Swing Line) and the Term Loan or (ii) any Reimbursement Obligation;
     (b) non-payment of any other amounts due and owing by the Borrowers under this Agreement or by any Credit Party under any of the other Loan Documents to which it is a party, other than as set forth in subsection (a) above, within three (3) Business Days after the same is due and payable;
     (c) default in the observance or performance of any of the conditions, covenants or agreements of the Borrowers set forth in Sections 7.1 , 7.2 , 7.4(a) and (e) , 7.5(c) , (d) , (e) and (f) , 7.6 , 7.7 , 7.9 , 7.13 , 7.14 , 7.15 , 7.16 , 7.17 or Article 8 in its entirety, provided that an Event of Default arising from a breach of Sections 7.1 or 7.2 shall be deemed to have been cured upon delivery of the required item; and provided further that any Event of Default arising solely due to a breach of Section 7.7 shall be deemed cured upon the earlier of (x) the giving of the notice required by Section 7.7 and (y) the date upon which the Default or Event of Default giving rise to the notice obligation is cured or waived;
     (d) default in the observance or performance of any of the other conditions, covenants or agreements set forth in this Agreement or any of the other Loan Documents by any Credit Party and continuance thereof for a period of thirty (30) consecutive days;
     (e) any representation or warranty made by any Credit Party herein or in any certificate, instrument or other document submitted pursuant hereto proves untrue or misleading in any material adverse respect when made;
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     (f) (i) default by any Credit Party in the payment of any indebtedness for borrowed money, whether under a direct obligation or guaranty (other than Indebtedness hereunder) of any Credit Party in excess of One Million Dollars ($1,000,000) (or the equivalent thereof in any currency other than Dollars) individually or in the aggregate when due and continuance thereof beyond any applicable period of cure and or (ii) failure to comply with the terms of any other obligation of any Credit Party with respect to any indebtedness for borrowed money (other than Indebtedness hereunder) in excess of One Million Dollars ($1,000,000) (or the equivalent thereof in any currency other than Dollars) individually or in the aggregate, which continues beyond any applicable period of cure and which would permit the holder or holders thereto to accelerate such other indebtedness for borrowed money, or require the prepayment, repurchase, redemption or defeasance of such indebtedness;
     (g) the rendering of any judgment(s) (not covered by adequate insurance from a solvent carrier which is defending such action without reservation of rights) for the payment of money in excess of the sum of One Million Dollars ($1,000,000) (or the equivalent thereof in any currency other than Dollars) individually or in the aggregate against any Credit Party, and such judgments shall remain unpaid, unvacated, unbonded or unstayed by appeal or otherwise for a period of thirty (30) consecutive days from the date of its entry;
     (h) the occurrence of (i) a “ reportable event ”, as defined in ERISA, which is determined by the PBGC to constitute grounds for a distress termination of any Pension Plan subject to Title IV of ERISA maintained or contributed to by or on behalf of any Credit Party for the benefit of any of its employees or for the appointment by the appropriate United States District Court of a trustee to administer such Pension Plan and such reportable event is not corrected and such determination is not revoked within sixty (60) days after notice thereof has been given to the plan administrator of such Pension Plan (without limiting any of the Administrative Agent’s or any Lender’s other rights or remedies hereunder), or (ii) the termination or the institution of proceedings by the PBGC to terminate any such Pension Plan, or (iii) the appointment of a trustee by the appropriate United States District Court to administer any such Pension Plan, or (iv) the reorganization (within the meaning of Section 4241 of ERISA) or insolvency (within the meaning of Section 4245 of ERISA) of any Multiemployer Plan, or receipt of notice from any Multiemployer Plan that it is in reorganization or insolvency, or the complete or partial withdrawal by any Credit Party from any Multiemployer Plan, which in the case of any of the foregoing, could reasonably be expected to have a Material Adverse Effect;
     (i) except as expressly permitted under this Agreement, any Credit Party shall be dissolved (other than a dissolution of a Subsidiary of any Borrower which is not a Guarantor or a Borrower) or liquidated (or any judgment, order or decree therefor shall be entered) except as otherwise permitted herein; or if a creditors’ committee shall have been appointed for the business of any Credit Party; or if any Credit Party shall have made a general assignment for the benefit of creditors or shall have been adjudicated bankrupt and if not an adjudication based on a filing by a Credit Party, it shall not have been dismissed within ninety (90) days, or shall have filed a voluntary petition in bankruptcy or for reorganization or to effect a plan or arrangement with creditors or shall
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fail to pay its debts generally as such debts become due in the ordinary course of business (except as contested in good faith and for which adequate reserves are made in such party’s financial statements); or shall file an answer to a creditor’s petition or other petition filed against it, admitting the material allegations thereof for an adjudication in bankruptcy or for reorganization; or shall have applied for or permitted the appointment of a receiver or trustee or custodian for any of its property or assets; or such receiver, trustee or custodian shall have been appointed for any of its property or assets (otherwise than upon application or consent of a Credit Party) and shall not have been removed within ninety (90) days; or if an order shall be entered approving any petition for reorganization of any Credit Party and shall not have been reversed or dismissed within ninety (90) days;
     (j) a Change of Control; or
     (k) any Loan Document shall at any time for any reason cease to be in full force and effect (other than in accordance with the terms thereof or the terms of any other Loan Document), as applicable, or the validity, binding effect or enforceability thereof shall be contested by any party thereto (other than any Lender, the Administrative Agent, Issuing Lender or Swing Line Lender), or any Person shall deny that it has any or further liability or obligation under any Loan Document, or any such Loan Document shall be terminated (other than in accordance with the terms thereof or the terms of any other Loan Document), invalidated, revoked or set aside or in any way cease to give or provide to the Lenders and the Administrative Agent the benefits purported to be created thereby, or any Loan Document purporting to grant a Lien to secure any Indebtedness shall, at any time after the delivery of such Loan Document, fail to create a valid and enforceable Lien on any Collateral purported to be covered thereby or such Lien shall fail to cease to be a perfected Lien with the priority required in the relevant Loan Document.
     9.2 Exercise of Remedies . If an Event of Default has occurred and is continuing hereunder: (a) the Administrative Agent may, and shall, upon being directed to do so by the Majority Revolving Credit Lenders, declare the Revolving Credit Aggregate Commitment terminated; (b) the Administrative Agent may, and shall, upon being directed to do so by the Majority Lenders, declare the entire unpaid principal Indebtedness, including the Notes, immediately due and payable, without presentment, notice or demand, all of which are hereby expressly waived by the Borrowers; (c) upon the occurrence of any Event of Default specified in Section 9.1(i) and notwithstanding the lack of any declaration by the Administrative Agent under preceding clauses (a) or (b) , the entire unpaid principal Indebtedness shall become automatically and immediately due and payable, and the Revolving Credit Aggregate Commitment shall be automatically and immediately terminated; (d) the Administrative Agent shall, upon being directed to do so by the Majority Revolving Credit Lenders, demand immediate delivery of cash collateral, and the Borrowers agree to deliver such cash collateral upon demand, in an amount equal to 110% of the maximum amount that may be available to be drawn at any time prior to the stated expiry of all outstanding Letters of Credit, for deposit into an account controlled by the Administrative Agent; (e) the Administrative Agent may, and shall, upon being directed to do so by the Majority Lenders, notify the Administrative Borrower or any Credit Party that interest shall accrue and be payable on demand on all Indebtedness (other than Revolving Credit Advances, Swing Line Advances and Term Loan Advances with respect to which Sections 2.6
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and 4.6 hereof shall govern) owing from time to time to the Administrative Agent or any Lender, at a per annum rate equal to the then applicable Base Rate plus two percent (2%); and (f) the Administrative Agent may, and shall, upon being directed to do so by the Majority Lenders or the Lenders, as applicable (subject to the terms hereof), exercise any remedy permitted by this Agreement, the other Loan Documents or applicable law.
     9.3 Rights Cumulative . No delay or failure of the Administrative Agent and/or Lenders in exercising any right, power or privilege hereunder shall affect such right, power or privilege, nor shall any single or partial exercise thereof preclude any further exercise thereof, or the exercise of any other power, right or privilege. The rights of the Administrative Agent and Lenders under this Agreement are cumulative and not exclusive of any right or remedies which Lenders would otherwise have.
     9.4 Waiver by the Borrowers of Certain Laws . To the extent permitted by applicable law, the Borrowers hereby agree to waive, and do hereby absolutely and irrevocably waive and relinquish the benefit and advantage of any valuation, stay, appraisement, extension or redemption laws now existing or which may hereafter exist, which, but for this provision, might be applicable to any sale made under the judgment, order or decree of any court, on any claim for interest on the Notes, or any security interest or mortgage contemplated by or granted under or in connection with this Agreement. These waivers have been voluntarily given, with full knowledge of the consequences thereof.
     9.5 Waiver of Defaults . No Event of Default shall be waived by the Lenders except in writing signed by an officer of the Administrative Agent in accordance with Section 13.10 hereof. No single or partial exercise of any right, power or privilege hereunder, nor any delay in the exercise thereof, shall preclude other or further exercise of their rights by the Administrative Agent or the Lenders. No waiver of any Event of Default shall extend to any other or further Event of Default. No forbearance on the part of the Administrative Agent or the Lenders in enforcing any of their rights shall constitute a waiver of any of their rights. The Borrowers expressly agree that this Section may not be waived or modified by the Lenders or the Administrative Agent by course of performance, estoppel or otherwise.
     9.6 Set Off . Upon the occurrence and during the continuance of any Event of Default, each Lender may at any time and from time to time, without notice to the Borrowers but subject to the provisions of Section 10.3 hereof (any requirement for such notice being expressly waived by the Borrowers), setoff and apply against any and all of the obligations of the Borrowers now or hereafter existing under this Agreement, whether owing to such Lender, any Affiliate of such Lender or any other Lender or the Administrative Agent, any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by such Lender to or for the credit or the account of any Borrower and any property of any Borrowers from time to time in possession of such Lender, irrespective of whether or not such deposits held or indebtedness owing by such Lender may be contingent and unmatured and regardless of whether any Collateral then held by the Administrative Agent or any Lender is adequate to cover the Indebtedness. Promptly following any such setoff, such Lender shall give written notice to the Administrative Agent and the Administrative Borrower of the occurrence thereof. The Borrowers hereby grant to the Lenders and the Administrative Agent a lien on and security interest in all such deposits, indebtedness and property as collateral
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security for the payment and performance of all of the obligations of the Borrowers under this Agreement. The rights of each Lender under this Section 9.6 are in addition to the other rights and remedies (including, without limitation, other rights of setoff) which such Lender may have.
10. PAYMENTS, RECOVERIES AND COLLECTIONS.
     10.1 Payment Procedure .
     (a) All payments to be made by the Borrowers shall be made without condition or deduction for any counterclaim, defense, recoupment or setoff. Except as otherwise provided herein, all payments made by the Borrowers of principal, interest or fees hereunder shall be made without setoff or counterclaim on the date specified for payment under this Agreement and must be received by the Administrative Agent not later than 1:00 p.m. (Detroit, Michigan time) on the date such payment is required or intended to be made in Dollars in immediately available funds to the Administrative Agent at the Administrative Agent’s office located at One Detroit Center, Detroit, Michigan 48226-3289, for the ratable benefit of the Revolving Credit Lenders in the case of payments in respect of the Revolving Credit and any Letter of Credit Obligations and for the ratable benefit of the Term Loan Lenders in the case of payments in respect of the Term Loan. Any payment received by the Administrative Agent after 1:00 p.m. (Detroit, Michigan time) shall be deemed received on the next succeeding Business Day and any applicable interest or fee shall continue to accrue. Upon receipt of each such payment, the Administrative Agent shall make prompt payment to each applicable Lender, or, in respect of Eurodollar-based Advances, such Lender’s Eurodollar Lending Office, in like funds and currencies, of all amounts received by it for the account of such Lender.
     (b) Unless the Administrative Agent shall have been notified in writing by the Administrative Borrower at least two (2) Business Days prior to the date on which any payment to be made by the Borrowers is due that the Borrowers do not intend to remit such payment, the Administrative Agent may, in its sole discretion and without obligation to do so, assume that the Borrowers have remitted such payment when so due and the Administrative Agent may, in reliance upon such assumption, make available to each Revolving Credit Lender or Term Loan Lender, as the case may be, on such payment date an amount equal to such Lender’s share of such assumed payment. If the Borrowers have not in fact remitted such payment to the Administrative Agent, each Lender shall forthwith on demand repay to the Administrative Agent the amount of such assumed payment made available or transferred to such Lender, together with the interest thereon, in respect of each day from and including the date such amount was made available by the Administrative Agent to such Lender to the date such amount is repaid to the Administrative Agent at a rate per annum equal to the Federal Funds Effective Rate for the first two (2) Business Days that such amount remains unpaid, and thereafter at a rate of interest then applicable to such Revolving Credit Advances.
     (c) Subject to the definition of “ Interest Period ” in Section 1 of this Agreement, whenever any payment to be made hereunder shall otherwise be due on a day which is not a Business Day, such payment shall be made on the next succeeding
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Business Day and such extension of time shall be included in computing interest, if any, in connection with such payment.
     (d) All payments to be made by the Borrowers under this Agreement or any of the Notes (including without limitation payments under the Swing Line and/or Swing Line Note) shall be made without setoff or counterclaim, as aforesaid, and, subject to full compliance by each Lender (and each assignee and participant pursuant to Section 13.8 ) with Section 13.13 , without deduction for or on account of any present or future withholding or other taxes of any nature imposed by any Governmental Authority or of any political subdivision thereof or any federation or organization of which such Governmental Authority may at the time of payment be a member (other than any taxes on the overall income, net income, net profits or net receipts or similar taxes (or any franchise taxes imposed in lieu of such taxes) on the Administrative Agent or any Lender (or any branch maintained by the Administrative Agent or a Lender) as a result of a present or former connection between the Administrative Agent or such Lender and the Governmental Authority, political subdivision, federation or organization imposing such taxes), unless any Borrower is compelled by law to make payment subject to such tax. In such event, the Borrowers shall:
     (i) pay to the Administrative Agent for the Administrative Agent’s own account and/or, as the case may be, for the account of the Lenders such additional amounts as may be necessary to ensure that the Administrative Agent and/or such Lender or Lenders (including the Swing Line Lender) receive a net amount equal to the full amount which would have been receivable had payment not been made subject to such tax; and
     (ii) remit such tax to the relevant taxing authorities according to applicable law, and send to the Administrative Agent or the applicable Lender or Lenders (including the Swing Line Lender), as the case may be, such certificates or certified copy receipts as the Administrative Agent or such Lender or Lenders shall reasonably require as proof of the payment by any Borrower of any such taxes payable by such Borrower.
As used herein, the terms “ tax ”, “ taxes ” and “ taxation ” include all taxes, levies, imposts, duties, fees, deductions and withholdings or similar charges together with interest (and any taxes payable upon the amounts paid or payable pursuant to this Section 10.1 ) thereon. The Borrowers shall be reimbursed by the applicable Lender for any payment made by the Borrowers under this Section 10.1 if the applicable Lender is not in compliance with its obligations under Section 13.13 at the time of the Borrowers’ payment.
     10.2 Application of Proceeds of Collateral . Notwithstanding anything to the contrary in this Agreement, in the case of any Event of Default under Section 9.1(i) , immediately following the occurrence thereof, and in the case of any other Event of Default, upon the termination of the Revolving Credit Aggregate Commitment, the acceleration of any Indebtedness arising under this Agreement and/or the exercise of any other remedy in each case by the requisite Lenders under Section 9.2 hereof, the Administrative Agent shall apply the proceeds of any Collateral, together with any offsets, voluntary payments by any Credit Party or
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others and any other sums received or collected in respect of the Indebtedness first, to pay all incurred and unpaid fees and expenses of the Administrative Agent under the Loan Documents and any protective advances made by the Administrative Agent with respect to the Collateral under or pursuant to the terms of any Loan Document, next, to pay any fees and expenses owed to the Issuing Lender hereunder, next, to the Indebtedness under the Revolving Credit (including the Swing Line and any Reimbursement Obligations) and the Term Loan, on a pro rata basis, next to any obligations owing by any Credit Party under any Hedging Agreements on a pro rata basis, next, to any other Indebtedness on a pro rata basis, and then, if there is any excess, to the Credit Parties, as the case may be.
     10.3 Pro-rata Recovery . If any Lender shall obtain any payment or other recovery (whether voluntary, involuntary, by application of setoff or otherwise) on account of principal of, or interest on, any of the Advances made by it, or the participations in Letter of Credit Obligations or Swing Line Advances held by it in excess of its pro rata share of payments then or thereafter obtained by all Lenders upon principal of and interest on all such Indebtedness, such Lender shall purchase from the other Lenders such participations in the Revolving Credit, the Term Loan and/or the Letter of Credit Obligation held by them as shall be necessary to cause such purchasing Lender to share the excess payment or other recovery ratably in accordance with the applicable Percentages of the Lenders; provided , however , that if all or any portion of the excess payment or other recovery is thereafter recovered from such purchasing holder, the purchase shall be rescinded and the purchase price restored to the extent of such recovery, but without interest.
     10.4 Treatment of a Defaulting Lender .
     (a) The obligation of any Lender to make any Advance hereunder shall not be affected by the failure of any other Lender to make any Advance under this Agreement, and no Lender shall have any liability to the Borrowers or any of their Subsidiaries, the Administrative Agent, any other Lender, or any other Person for another Lender’s failure to make any loan or Advance hereunder.
     (b) If any Lender shall become a Defaulting Lender, then such Defaulting Lender’s right to participate in the administration of the loans, this Agreement and the other Loan Documents, including without limitation any right to vote in respect of any amendment, consent or waiver of the terms of this Agreement or such other Loan Documents, or to direct or approve any action or inaction by the Administrative Agent shall be suspended for the entire period that such Lender remains a Defaulting Lender and the stated commitment amounts and outstanding Advances of such Defaulting Lender shall not be included in determining whether all Lenders or the Majority Lender (or any class thereof), as the case may be, have taken or may take any action hereunder (including, without limitation, any action to approve any consent, waiver or amendment to this Agreement or the other Loan Documents); provided , however , that the foregoing shall not permit (i) an increase in such Defaulting Lender’s stated commitment amounts, (ii) the waiver, forgiveness or reduction of the principal amount of any Indebtedness outstanding to such Defaulting Lender (unless all other Lenders affected thereby are treated similarly), (iii) the extension of the final maturity date(s) of such Defaulting Lenders’ portion of any of the loans or other extensions of credit or other obligations of
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the Borrowers owing to such Defaulting Lender, in each case without such Defaulting Lender’s consent, or (iv) any other modification which under Section 13.10 requires the consent of all Lenders or the Lender(s) affected thereby which affects the Defaulting Lender differently than the Non-Defaulting Lenders affected by such modification, other than a change to or waiver of the requirements of Section 10.3 which results in a reduction of the Defaulting Lender’s commitment or its share of the Indebtedness on a non pro-rata basis.
     (c) To the extent and for so long as a Lender remains a Defaulting Lender and notwithstanding the provisions of Section 10.3 hereof, the Administrative Agent shall be entitled, without limitation, (i) to withhold or setoff and to apply in satisfaction of those obligations for payment (and any related interest) in respect of which the Defaulting Lender shall be delinquent or otherwise in default to the Administrative Agent or any Lender (or to hold as cash collateral for such delinquent obligations or any future defaults) the amounts otherwise payable to such Defaulting Lender under this Agreement or any other Loan Document, (ii) if the amount of Advances made by such Defaulting Lender is less than its Percentage requires, apply payments of principal made by the Borrowers amongst the Non-Defaulting Lenders on a pro rata basis or to the Defaulting Lender’s obligations as the Administrative Agent deems appropriate in its sole discretion, until all outstanding Advances are held by all Lenders according to their respective Percentages and (iii) to bring an action or other proceeding, in law or equity, against such Defaulting Lender in a court of competent jurisdiction to recover the delinquent amounts, and any related interest. Performance by the Borrowers of their respective obligations under this Agreement and the other Loan Documents shall not be excused or otherwise modified as a result of the operation of this Section, except to the extent expressly set forth herein and in any event the Borrowers shall not be required to pay any Revolving Credit Facility Fee under Section 2.9 of this Agreement in respect of such Defaulting Lender’s Unfunded Portion of the Revolving Credit for the period during which such Lender is a Defaulting Lender. Furthermore, the rights and remedies of the Borrowers, the Administrative Agent, the Issuing Lender, the Swing Line Lender and the other Lenders against a Defaulting Lender under this section shall be in addition to any other rights and remedies such parties may have against the Defaulting Lender under this Agreement or any of the other Loan Documents, applicable law or otherwise, and the Borrowers waive no rights or remedies against any Defaulting Lender.
11. CHANGES IN LAW OR CIRCUMSTANCES; INCREASED COSTS.
     11.1 Reimbursement of Prepayment Costs . If (i) the Borrower make any payment of principal with respect to any Eurodollar-based Advance or Quoted Rate Advance on any day other than the last day of the Interest Period applicable thereto (whether voluntarily, pursuant to any mandatory provisions hereof, by acceleration, or otherwise); (ii) the Borrowers convert or refund (or attempts to convert or refund) any such Advance on any day other than the last day of the Interest Period applicable thereto (except as described in Section 2.5(e) ); (iii) the Borrowers fail to borrow, refund or convert any Eurodollar-based Advance or Quoted Rate Advance after notice has been given by the Administrative Borrower to the Administrative Agent in accordance with the terms hereof requesting such Advance; or (iv) or if the Borrowers fail to make any payment of principal in respect of a Eurodollar-based Advance or Quoted Rate Advance when
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due, the Borrowers shall reimburse the Administrative Agent for itself and/or on behalf of any Lender, as the case may be, within ten (10) Business Days of written demand therefor for any resulting loss, cost or expense incurred (excluding the loss of any Applicable Margin) by the Administrative Agent and Lenders, as the case may be, as a result thereof, including, without limitation, any such loss, cost or expense incurred in obtaining, liquidating, employing or redeploying deposits from third parties, whether or not the Administrative Agent and Lenders, as the case may be, shall have funded or committed to fund such Advance. The amount payable hereunder by the Borrowers to the Administrative Agent for itself and/or on behalf of any Lender, as the case may be, shall be deemed to equal an amount equal to the excess, if any, of (a) the amount of interest which would have accrued on the amount so prepaid, or not so borrowed, refunded or converted, for the period from the date of such prepayment or of such failure to borrow, refund or convert, through the last day of the relevant Interest Period, at the applicable rate of interest for said Advance(s) provided under this Agreement, over (b) the amount of interest (as reasonably determined by the Administrative Agent and Lenders, as the case may be) which would have accrued to the Administrative Agent and Lenders, as the case may be, on such amount by placing such amount on deposit for a comparable period with leading banks in the interbank Eurocurrency market. Calculation of any amounts payable to any Lender under this paragraph shall be made as though such Lender shall have actually funded or committed to fund the relevant Advance through the purchase of an underlying deposit in an amount equal to the amount of such Advance and having a maturity comparable to the relevant Interest Period; provided , however , that any Lender may fund any Eurodollar-based Advance or Quoted Rate Advance, as the case may be, in any manner it deems fit and the foregoing assumptions shall be utilized only for the purpose of the calculation of amounts payable under this paragraph. Upon the written request of the Administrative Borrower, the Administrative Agent and Lenders shall deliver to the Administrative Borrower a certificate setting forth the basis for determining such losses, costs and expenses, which certificate shall be conclusively presumed correct, absent manifest error.
     11.2 Eurodollar Lending Office . For any Eurodollar Advance, if the Administrative Agent or a Lender, as applicable, shall designate a Eurodollar Lending Office which maintains books separate from those of the rest of the Administrative Agent or such Lender, the Administrative Agent or such Lender, as the case may be, shall have the option of maintaining and carrying the relevant Advance on the books of such Eurodollar Lending Office.
     11.3 Circumstances Affecting LIBOR Rate Availability . If the Administrative Agent or the Majority Lenders (after consultation with the Administrative Agent) shall determine in good faith that, by reason of circumstances affecting the foreign exchange and interbank markets generally, deposits in Eurodollars in the applicable amounts are not being offered to the Administrative Agent or such Lenders at the applicable LIBOR Rate, then the Administrative Agent shall forthwith give notice thereof to the Administrative Borrower. Thereafter, until the Administrative Agent notifies the Administrative Borrower that such circumstances no longer exist, (i) the obligation of Lenders to make Advances which bear interest at or by reference to the LIBOR Rate, and the right of the Borrowers to convert an Advance to or refund an Advance as an Advance which bear interest at or by reference to the LIBOR Rate shall be suspended, (ii) effective upon the last day of each Eurodollar-Interest Period related to any existing Eurodollar-based Advance, each such Eurodollar-based Advance shall automatically be converted into an Advance which bears interest at or by reference to the Prime-based Rate (plus
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the Applicable Margin) (without regard to satisfaction of any conditions to conversion contained elsewhere herein), and (iii) effective immediately following such notice, each Advance which bears interest at or by reference to the Daily Adjusting LIBOR Rate shall automatically be converted into an Advance which bears interest at or by reference to the Prime-based Rate (plus the Applicable Margin) (without regard to satisfaction of any conditions to conversion contained elsewhere herein).
     11.4 Laws Affecting LIBOR Rate Availability . If, after the date of this Agreement, the adoption or introduction of, or any change in, any applicable law, rule or regulation or in the interpretation or administration thereof by any Governmental Authority charged with the interpretation or administration thereof, or compliance by any of the Lenders (or any of their respective Eurodollar Lending Offices) with any request or directive (whether or not having the force of law) of any such authority, shall make it unlawful or impossible for any of the Lenders (or any of their respective Eurodollar Lending Offices) to honor its obligations hereunder to make or maintain any Advance which bears interest at or by reference to the LIBOR Rate, such Lender shall forthwith give notice thereof to the Administrative Borrower and to the Administrative Agent. Thereafter, (a) the obligations of the applicable Lenders to make Advances which bear interest at or by reference to the LIBOR Rate and the right of the Borrowers to convert an Advance into or refund an Advance as an Advance which bears interest at or by reference to the LIBOR Rate shall be suspended and thereafter only the Prime-based Rate, plus the Applicable Margin shall be available, and (b) if any of the Lenders may not lawfully continue to maintain an Advance which bears interest at or by reference to the LIBOR Rate, the applicable Advance shall immediately be converted to an Advance which bears interest at or by reference to the Prime-based Rate (plus the Applicable Margin). For purposes of this Section, a change in law, rule, regulation, interpretation or administration shall include, without limitation, any change made or which becomes effective on the basis of a law, rule, regulation, interpretation or administration presently in force, the effective date of which change is delayed by the terms of such law, rule, regulation, interpretation or administration.
     11.5 Increased Cost of Advances Carried at the LIBOR Rate . If, after the date of this Agreement, the adoption or introduction of, or any change in, any applicable law, rule or regulation or in the interpretation or administration thereof by any Governmental Authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by any of the Lenders (or any of their respective Eurodollar Lending Offices) with any request or directive (whether or not having the force of law) of any such authority, central bank or comparable agency:
     (a) shall subject any of the Lenders (or any of their respective Eurodollar Lending Offices) to any tax, duty or other charge with respect to any Advance or shall change the basis of taxation of payments to any of the Lenders (or any of their respective Eurodollar Lending Offices) of the principal of or interest on any Advance or any other amounts due under this Agreement in respect thereof (except for changes in the rate of tax on the overall net income of any of the Lenders or any of their respective Eurodollar Lending Offices); or
     (b) shall impose, modify or deem applicable any reserve (including, without limitation, any imposed by the Board of Governors of the Federal Reserve System),
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special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, any of the Lenders (or any of their respective Eurodollar Lending Offices) or shall impose on any of the Lenders (or any of their respective Eurodollar Lending Offices) or the foreign exchange and interbank markets any other condition affecting any Advance;
and the result of any of the foregoing matters is to increase the costs to any of the Lenders of maintaining any part of the Indebtedness hereunder as an Advance which bears interest at or by reference to the LIBOR Rate to reduce the amount of any sum received or receivable by any of the Lenders under this Agreement in respect of an Advance which bears interest at or by reference to the LIBOR Rate, then such Lender shall promptly notify the Administrative Agent, and the Administrative Agent shall promptly notify the Administrative Borrower of such fact and demand compensation therefor and, within ten (10) Business Days after such notice, the Borrowers agree to pay to such Lender or Lenders such additional amount or amounts as will compensate such Lender or Lenders for such increased cost or reduction, provided that each Lender agrees to take any reasonable action, to the extent such action could be taken without cost or administrative or other burden or restriction to such Lender, to mitigate or eliminate such cost or reduction, within a reasonable time after becoming aware of the foregoing matters. The Administrative Agent will promptly notify the Administrative Borrower of any event of which it has knowledge which will entitle Lenders to compensation pursuant to this Section, or which will cause the Borrowers to incur additional liability under Section 11.1 hereof, provided that the Administrative Agent shall incur no liability whatsoever to the Lenders or the Borrowers in the event it fails to do so. A certificate of the Administrative Agent (or such Lender, if applicable) setting forth the basis for determining such additional amount or amounts necessary to compensate such Lender or Lenders shall accompany such demand and shall be conclusively presumed to be correct absent manifest error.
     11.6 Capital Adequacy and Other Increased Costs .
     (a) If, after the Effective Date, the adoption or introduction of, or any change in any applicable law, treaty, rule or regulation (whether domestic or foreign) now or hereafter in effect and whether or not presently applicable to any Lender or the Administrative Agent, or any interpretation or administration thereof by any Governmental Authority charged with the interpretation or administration thereof, or compliance by any Lender or the Administrative Agent with any guideline, request or directive of any such authority (whether or not having the force of law), including any risk based capital guidelines, affects or would affect the amount of capital required to be maintained by such Lender or the Administrative Agent (or any corporation controlling such Lender or the Administrative Agent) and such Lender or the Administrative Agent, as the case may be, determines that the amount of such capital is increased by or based upon the existence of such Lender’s or the Administrative Agent’s obligations or Advances hereunder and such increase has the effect of reducing the rate of return on such Lender’s or the Administrative Agent’s (or such controlling corporation’s) capital as a consequence of such obligations or Advances hereunder to a level below that which such Lender or the Administrative Agent (or such controlling corporation) could have achieved but for such circumstances (taking into consideration its policies with respect to capital adequacy) by an amount deemed by such Lender or the Administrative Agent to
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be material (collectively, “ Increased Costs ”), then the Administrative Agent or such Lender shall notify the Administrative Borrower, and thereafter the Borrowers shall pay to such Lender or the Administrative Agent, as the case may be, within ten (10) Business Days of written demand therefor from such Lender or the Administrative Agent, additional amounts sufficient to compensate such Lender or the Administrative Agent (or such controlling corporation) for any increase in the amount of capital and reduced rate of return which such Lender or the Administrative Agent reasonably determines to be allocable to the existence of such Lender’s or the Administrative Agent’s obligations or Advances hereunder. A statement setting forth the amount of such compensation, the methodology for the calculation and the calculation thereof which shall also be prepared in good faith and in reasonable detail by such Lender or the Administrative Agent, as the case may be, shall be submitted by such Lender or by the Administrative Agent to the Administrative Borrower, reasonably promptly after becoming aware of any event described in this Section 11.6(a) and shall be conclusively presumed to be correct, absent manifest error.
     (b) Notwithstanding the foregoing, however, the Borrowers shall not be required to pay any increased costs under Sections 11.5 , 11.6 or 3.4(c) for any period ending prior to the date that is 180 days prior to the making of a Lender’s initial request for such additional amounts unless the applicable change in law or other event resulting in such increased costs is effective retroactively to a date more than 180 days prior to the date of such request, in which case a Lender’s request for such additional amounts relating to the period more than 180 days prior to the making of the request must be given not more than 180 days after such Lender becomes aware of the applicable change in law or other event resulting in such increased costs.
     11.7 Right of Lenders to Fund through Branches and Affiliates . Each Lender (including without limitation the Swing Line Lender) may, if it so elects, fulfill its commitment as to any Advance hereunder by designating a branch or Affiliate of such Lender to make such Advance; provided that (a) such Lender shall remain solely responsible for the performances of its obligations hereunder and (b) no such designation shall result in any material increased costs to the Borrowers.
     11.8 Margin Adjustment . Adjustments to the Applicable Margins and the Applicable Fee Percentages, based on Schedule 1.1 , shall be implemented on a quarterly basis as follows:
     (a) Such adjustments shall be given prospective effect only, effective as to all Advances outstanding hereunder, the Applicable Fee Percentage and the Letter of Credit Fee, upon the date of delivery of the financial statements under Sections 7.1(a) and 7.1(b) hereunder and the Covenant Compliance Report under Section 7.2(a) hereof, in each case establishing applicability of the appropriate adjustment and in each case with no retroactivity or claw-back. In the event the Borrowers shall fail timely to deliver such financial statements or the Covenant Compliance Report and such failure continues for three (3) days, then (but without affecting the Event of Default resulting therefrom) from the date delivery of such financial statements and report was required until such financial statements and report are delivered, the Applicable Margins and Applicable Fee
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Percentages shall be at the highest level on the Pricing Matrix attached to this Agreement as Schedule 1.1 .
     (b) From the Effective Date until the required date of delivery (or, if earlier, delivery) of the financial statements under Section 7.1(a) or 7.1(b) hereof, as applicable, and the Covenant Compliance Report under Section 7.2(a) hereof, for the fiscal quarter ending December 31, 2009, the Applicable Margins and Applicable Fee Percentages shall be those set forth under the Level III column of the pricing matrix attached to this Agreement as Schedule 1.1 . Thereafter, Applicable Margins and Applicable Fee Percentages shall be based upon the quarterly financial statements and Covenant Compliance Reports, subject to recalculation as provided in Section 11.8(a) above.
     (c) Notwithstanding the foregoing, however, if, prior to the payment and discharge in full (in cash) of the Indebtedness and the termination of any and all commitments hereunder, as a result of any restatement of or adjustment to the financial statements of the Administrative Borrower and any of its Subsidiaries (relating to the current or any prior fiscal period) or for any other reason, the Administrative Agent determines that the Applicable Margin and/or the Applicable Fee Percentages as calculated by the Borrowers as of any applicable date of determination were inaccurate in any respect and a proper calculation thereof would have resulted in different pricing for any fiscal period, then (x) if the proper calculation thereof would have resulted in higher pricing for any such period, the Borrowers shall automatically and retroactively be obligated to pay to the Administrative Agent, promptly upon demand by the Administrative Agent or the Majority Lenders, an amount equal to the excess of the amount of interest and fees that should have been paid for such period over the amount of interest and fees actually paid for such period and, if the current fiscal period is affected thereby, the Applicable Margin and/or the Applicable Fee Percentages for the current period shall be adjusted based on such recalculation; and (y) if the proper calculation thereof would have resulted in lower pricing for such period, the Administrative Agent and Lenders shall have no obligation to recalculate such interest or fees or to repay any interest or fees to the Borrowers.
12. THE AGENT.
     12.1 Appointment of the Administrative Agent . Each Lender and the holder of each Note (if issued) irrevocably appoints and authorizes the Administrative Agent to act on behalf of such Lender or holder under this Agreement and the other Loan Documents and to exercise such powers hereunder and thereunder as are specifically delegated to the Administrative Agent by the terms hereof and thereof, together with such powers as may be reasonably incidental thereto, including without limitation the power to execute or authorize the execution of financing or similar statements or notices, and other documents. In performing its functions and duties under this Agreement, the Administrative Agent shall act solely as agent of the Lenders and does not assume and shall not be deemed to have assumed any obligation towards or relationship of agency or trust with or for any Credit Party.
     12.2 Deposit Account with the Administrative Agent or any Lender . Each Borrower authorizes the Administrative Agent and each Lender, in the Administrative Agent’s or such
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Lender’s sole discretion, upon notice to the Administrative Borrower to charge its general deposit account(s), if any, maintained with the Administrative Agent or such Lender for the amount of any principal, interest, or other amounts or costs due under this Agreement when the same become due and payable under the terms of this Agreement or the Notes.
     12.3 Scope of the Administrative Agent’s Duties . The Administrative Agent shall have no duties or responsibilities except those expressly set forth herein, and shall not, by reason of this Agreement or otherwise, have a fiduciary relationship with any Lender (and no implied covenants or other obligations shall be read into this Agreement against the Administrative Agent). None of the Administrative Agent, its Affiliates nor any of their respective directors, officers, employees or agents shall be liable to any Lender for any action taken or omitted to be taken by it or them under this Agreement or any document executed pursuant hereto, or in connection herewith or therewith with the consent or at the request of the Majority Lenders (or all of the Lenders for those acts requiring consent of all of the Lenders) (except for its or their own willful misconduct or gross negligence), nor be responsible for or have any duties to ascertain, inquire into or verify (a) any recitals or warranties made by the Credit Parties or any Affiliate of the Credit Parties, or any officer thereof contained herein or therein, (b) the effectiveness, enforceability, validity or due execution of this Agreement or any document executed pursuant hereto or any security thereunder, (c) the performance by the Credit Parties of their respective obligations hereunder or thereunder, or (d) the satisfaction of any condition hereunder or thereunder, including without limitation in connection with the making of any Advance or the issuance of any Letter of Credit. The Administrative Agent and its Affiliates shall be entitled to rely upon any certificate, notice, document or other communication (including any cable, telegraph, telex, facsimile transmission or oral communication) believed by it to be genuine and correct and to have been sent or given by or on behalf of a proper person. The Administrative Agent may treat the payee of any Note as the holder thereof. The Administrative Agent may employ agents and may consult with legal counsel, independent public accountants and other experts selected by it and shall not be liable to the Lenders (except as to money or property received by them or their authorized agents), for the negligence or misconduct of any such agent selected by it with reasonable care or for any action taken or omitted to be taken by it in good faith in accordance with the advice of such counsel, accountants or experts.
     12.4 Successor Agent . The Administrative Agent may resign as such at any time upon at least thirty (30) days prior notice to the Administrative Borrower and each of the Lenders. If the Administrative Agent at any time shall resign or if the office of the Administrative Agent shall become vacant for any other reason, Majority Lenders shall, by written instrument, appoint successor agent(s) (“ Successor Agent ”) satisfactory to such Majority Lenders and, so long as no Default or Event of Default has occurred and is continuing, to the Administrative Borrower (which approval shall not be unreasonably withheld or delayed); provided , however , that any such Successor Agent shall be a bank or a trust company or other financial institution which maintains an office in the United States, or a commercial bank organized under the laws of the United States or any state thereof, or any Affiliate of such bank or trust company or other financial institution which is engaged in the banking business, and shall have a combined capital and surplus of at least $500,000,000. Such Successor Agent shall thereupon become the Administrative Agent hereunder, as applicable, and the Administrative Agent shall deliver or cause to be delivered to any successor agent such documents of transfer and assignment as such Successor Agent may reasonably request. If a Successor Agent is not so appointed or does not
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accept such appointment before the resigning Administrative Agent’s resignation becomes effective, the resigning Administrative Agent may appoint a temporary successor (subject to the approval of the Administrative Borrower so long as no Default or Event of Default, which approval shall not be unreasonably withheld or delayed) to act until such appointment by the Majority Lenders and, if applicable, the Administrative Borrower, is made and accepted, or if no such temporary successor is appointed as provided above by the resigning Administrative Agent, the Majority Lenders shall thereafter perform all of the duties of the resigning Administrative Agent hereunder until such appointment by the Majority Lenders and, if applicable, the Administrative Borrower, is made and accepted. Such Successor Agent shall succeed to all of the rights and obligations of the resigning Administrative Agent as if originally named. The resigning Administrative Agent shall duly assign, transfer and deliver to such Successor Agent all moneys at the time held by the resigning Administrative Agent hereunder after deducting therefrom its expenses for which it is entitled to be reimbursed hereunder. Upon such succession of any such Successor Agent, the resigning Administrative Agent shall be discharged from its duties and obligations, in its capacity as the Administrative Agent hereunder, except for its gross negligence or willful misconduct arising prior to its resignation hereunder, and the provisions of this Article 12 shall continue in effect for the benefit of the resigning Administrative Agent in respect of any actions taken or omitted to be taken by it while it was acting as the Administrative Agent.
     12.5 Credit Decisions . Each Lender acknowledges that it has, independently of the Administrative Agent and each other Lender and based on the financial statements of the Borrowers and such other documents, information and investigations as it has deemed appropriate, made its own credit decision to extend credit hereunder from time to time. Each Lender also acknowledges that it will, independently of the Administrative Agent and each other Lender and based on such other documents, information and investigations as it shall deem appropriate at any time, continue to make its own credit decisions as to exercising or not exercising from time to time any rights and privileges available to it under this Agreement, any Loan Document or any other document executed pursuant hereto.
     12.6 Authority of the Administrative Agent to Enforce This Agreement . Each Lender, subject to the terms and conditions of this Agreement, grants the Administrative Agent full power and authority as attorney-in-fact to institute and maintain actions, suits or proceedings for the collection and enforcement of any Indebtedness outstanding under this Agreement or any other Loan Document and to file such proofs of debt or other documents as may be necessary to have the claims of the Lenders allowed in any proceeding relative to any Credit Party, or their respective creditors or affecting their respective properties, and to take such other actions which the Administrative Agent considers to be necessary or desirable for the protection, collection and enforcement of the Notes, this Agreement or the other Loan Documents.
     12.7 Indemnification of the Administrative Agent . The Lenders agree (which agreement shall survive the expiration or termination of this Agreement) to indemnify the Administrative Agent and its Affiliates (to the extent not reimbursed by the Borrowers, but without limiting any obligation of the Borrowers to make such reimbursement), ratably according to their respective Weighted Percentages, from and against any and all claims, damages, losses, liabilities, costs or expenses of any kind or nature whatsoever (including, without limitation, reasonable fees and expenses of house and outside counsel) which may be
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imposed on, incurred by, or asserted against the Administrative Agent and its Affiliates in any way relating to or arising out of this Agreement, any of the other Loan Documents or the transactions contemplated hereby or any action taken or omitted by the Administrative Agent and its Affiliates under this Agreement or any of the Loan Documents; provided , however , that no Lender shall be liable for any portion of such claims, damages, losses, liabilities, costs or expenses resulting from the Administrative Agent’s or its Affiliate’s gross negligence or willful misconduct. Without limitation of the foregoing, each Lender agrees to reimburse the Administrative Agent and its Affiliates promptly upon demand for its ratable share of any reasonable expenses (including, without limitation, reasonable fees and expenses of house and outside counsel) incurred by the Administrative Agent and its Affiliates in connection with the preparation, execution, delivery, administration, modification, amendment or enforcement (whether through negotiations, legal proceedings or otherwise) of, or legal advice in respect of rights or responsibilities under, this Agreement or any of the other Loan Documents, to the extent that the Administrative Agent and its Affiliates are not reimbursed for such expenses by the Borrowers, but without limiting the obligation of the Borrowers to make such reimbursement. Each Lender agrees to reimburse the Administrative Agent and its Affiliates promptly upon demand for its ratable share of any amounts owing to the Administrative Agent and its Affiliates by the Lenders pursuant to this Section, provided that, if the Administrative Agent or its Affiliates are subsequently reimbursed by the Borrowers for such amounts, they shall refund to the Lenders on a pro rata basis the amount of any excess reimbursement. If the indemnity furnished to the Administrative Agent and its Affiliates under this Section shall become impaired as determined in the Administrative Agent’s reasonable judgment or the Administrative Agent shall elect in its sole discretion to have such indemnity confirmed by the Lenders (as to specific matters or otherwise), the Administrative Agent shall give notice thereof to each Lender and, until such additional indemnity is provided or such existing indemnity is confirmed, the Administrative Agent may cease, or not commence, to take any action. Any amounts paid by the Lenders hereunder to the Administrative Agent or its Affiliates shall be deemed to constitute part of the Indebtedness hereunder.
     12.8 Knowledge of Default . It is expressly understood and agreed that the Administrative Agent shall be entitled to assume that no Default or Event of Default has occurred and is continuing, unless the officers of the Administrative Agent immediately responsible for matters concerning this Agreement shall have received a written notice from a Lender or any Borrower specifying such Default or Event of Default and stating that such notice is a “ notice of default ”. Upon receiving such a notice, the Administrative Agent shall promptly notify each Lender of such Default or Event of Default and provide each Lender with a copy of such notice and shall endeavor to provide such notice to the Lenders within three (3) Business Days (but without any liability whatsoever in the event of its failure to do so). The Administrative Agent shall also furnish the Lenders, promptly upon receipt, with copies of all other notices or other information required to be provided by the applicable Borrower hereunder.
     12.9 The Administrative Agent’s Authorization; Action by Lenders . Except as otherwise expressly provided herein, whenever the Administrative Agent is authorized and empowered hereunder on behalf of the Lenders to give any approval or consent, or to make any request, or to take any other action on behalf of the Lenders (including without limitation the exercise of any right or remedy hereunder or under the other Loan Documents), the Administrative Agent shall be required to give such approval or consent, or to make such request
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or to take such other action only when so requested in writing by the Majority Lenders or the Lenders, as applicable hereunder. Action that may be taken by the Majority Lenders, any other specified Percentage of the Lenders or all of the Lenders, as the case may be (as provided for hereunder) may be taken (i) pursuant to a vote of the requisite percentages of the Lenders as required hereunder at a meeting (which may be held by telephone conference call), provided that the Administrative Agent exercises good faith, diligent efforts to give all of the Lenders reasonable advance notice of the meeting, or (ii) pursuant to the written consent of the requisite percentages of the Lenders as required hereunder, provided that all of the Lenders are given reasonable advance notice of the requests for such consent.
     12.10 Enforcement Actions by the Administrative Agent . Except as otherwise expressly provided under this Agreement or in any of the other Loan Documents and subject to the terms hereof, the Administrative Agent will take such action, assert such rights and pursue such remedies under this Agreement and the other Loan Documents as the Majority Lenders or all of the Lenders, as the case may be (as provided for hereunder), shall direct; provided , however , that the Administrative Agent shall not be required to act or omit to act if, in the reasonable judgment of the Administrative Agent, such action or omission may expose the Administrative Agent to personal liability for which the Administrative Agent has not been satisfactorily indemnified hereunder or is contrary to this Agreement, any of the Loan Documents or applicable law. Except as expressly provided above or elsewhere in this Agreement or the other Loan Documents, no Lender (other than the Administrative Agent, acting in its capacity as agent) shall be entitled to take any enforcement action of any kind under this Agreement or any of the other Loan Documents.
     12.11 Collateral Matters .
     (a) The Administrative Agent is authorized on behalf of all the Lenders, without the necessity of any notice to or further consent from the Lenders, from time to time to take any action with respect to any Collateral or the Collateral Documents which may be necessary to perfect and maintain a perfected security interest in and Liens upon the Collateral granted pursuant to the Loan Documents.
     (b) The Lenders irrevocably authorize the Administrative Agent, in its reasonable discretion, to the full extent set forth in the post-amble to Section 13.10 hereof, (1) to release or terminate any Lien granted to or held by the Administrative Agent upon any Collateral and release any Guaranty (a) upon termination of the Revolving Credit Aggregate Commitment and payment in full of all Indebtedness payable under this Agreement and under any other Loan Document; (b) constituting property (including, without limitation, Equity Interests in any Person) sold or to be sold or disposed of as part of or in connection with any disposition (whether by sale, by merger or by any other form of transaction and including the property of any Subsidiary that is disposed of as permitted hereby) permitted in accordance with the terms of this Agreement; (c) constituting property in which a Credit Party owned no interest at the time the Lien was granted or at any time thereafter; or (d) if approved, authorized or ratified in writing by the Majority Lenders, or all the Lenders, as the case may be, as provided in Section 13.10 ; (2) to subordinate the Lien granted to or held by the Administrative Agent on any Collateral to any other holder of a Lien on such Collateral
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which is permitted by Section 8.2(b) hereof; and (3) if all of the Equity Interests held by the Credit Parties in any Person are sold or otherwise transferred to any transferee other than any Borrower or a Subsidiary of any Borrower as part of or in connection with any disposition (whether by sale, by merger or by any other form of transaction) permitted in accordance with the terms of this Agreement, to release such Person from all of its obligations under the Loan Documents (including, without limitation, under any Guaranty). Upon request by the Administrative Agent at any time, the Lenders will confirm in writing the Administrative Agent’s authority to release particular types or items of Collateral pursuant to this Section 12.11(b) .
     12.12 The Administrative Agents in their Individual Capacities . Comerica Bank and its Affiliates, successors and assigns shall each have the same rights and powers hereunder as any other Lender and may exercise or refrain from exercising the same as though such Lender were not the Administrative Agent. Comerica Bank and its Affiliates may (without having to account therefor to any Lender) accept deposits from, lend money to, and generally engage in any kind of banking, trust, financial advisory or other business with the Credit Parties as if such Lender were not acting as the Administrative Agent hereunder, and may accept fees and other consideration therefor without having to account for the same to the Lenders.
     12.13 The Administrative Agent’s Fees . Until the Indebtedness has been repaid and discharged in full and no commitment to extend any credit hereunder is outstanding, the Borrowers jointly and severally agree to pay to the Administrative Agent, as applicable, any agency or other fee(s) set forth (or to be set forth from time to time) in the applicable Fee Letter on the terms set forth therein. The agency fees referred to in this Section 12.13 shall not be refundable under any circumstances.
     12.14 Documentation Administrative Agent or other Titles . Any Lender identified on the facing page or signature page of this Agreement or in any amendment hereto or as designated with consent of the Administrative Agent in any assignment agreement as Lead Arranger, Documentation Administrative Agent, Syndications Administrative Agent or any similar titles, shall not have any right, power, obligation, liability, responsibility or duty under this Agreement as a result of such title other than those applicable to all Lenders as such. Without limiting the foregoing, the Lenders so identified shall not have or be deemed to have any fiduciary relationship with any Lender as a result of such title. Each Lender acknowledges that it has not relied, and will not rely, on the Lender so identified in deciding to enter into this Agreement or in taking or not taking action hereunder.
     12.15 No Reliance on the Administrative Agent’s Customer Identification Program .
     (a) Each Lender acknowledges and agrees that neither such Lender, nor any of its Affiliates, participants or assignees, may relay on the Administrative Agent to carry out such Lender’s, Affiliate’s, participant’s or assignee’s customer identification program, or other obligations required or imposed under or pursuant to the USA Patriot Act or the regulations thereunder, including the regulations contained in 31 CFR 103.121 (as hereafter amended or replaced, the “ CIP Regulations ”), or any other Anti-Terrorism Law, including any programs involving any of the following items relating to or in connection with any Borrower or any of its Subsidiaries, any of their respective Affiliates or agents,
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the Loan Documents or the transactions hereunder: (i) any identify verification procedures, (ii) any record keeping, (iii) any comparisons with government lists, (iv) any customer notices or (v) any other procedures required under the CIP Regulations or such other laws.
     (b) Each Lender or assignee or participant of a Lender that is not organized under the laws of the United States or a state thereof (and is not excepted from the certification requirement contained in Section 313 of the USA Patriot Act and the applicable regulations because it is both (i) an affiliate of a depository institution or foreign bank that maintains a physical presence in the United States or foreign country, and (ii) subject to supervision by a banking authority regulating such affiliated depository institution or foreign bank) shall deliver to the Administrative Agent the certification, or, if applicable, recertification, certifying that such Lender is not a “ shell ” and certifying to other matters as required by Section 313 of the USA Patriot Act and the applicable regulations: (x) within 10 days after the Effective Date, and (y) at such other times as are required under the USA Patriot Act.
13. MISCELLANEOUS.
     13.1 Accounting Principles . Where the character or amount of any asset or liability or item of income or expense is required to be determined or any consolidation or other accounting computation is required to be made for the purposes of this Agreement, it shall be done, unless otherwise specified herein, in accordance with GAAP; provided , however , if the Administrative Borrower notifies the Administrative Agent that the Administrative Borrower requests an amendment to any provision hereof to eliminate the effect of any change occurring after the date of this Agreement in GAAP or in the application thereof on the operation of such provision (or if the Administrative Agent notifies the Administrative Borrower that the Majority Lenders request an amendment to any provision hereof for such purpose), regardless of whether any such notice is given before or after such change in GAAP or in the application thereof, then such provision shall be interpreted on the basis of GAAP as in effect and applied immediately before such change shall have become effective until such notice shall have been withdrawn or such provision amended in accordance herewith; provided , further , however , nothing in this Section 13.1 shall obligate the Administrative Agent or any Lender to amend this Agreement pursuant to such request of the Administrative Borrower.
     13.2 CONSENT TO JURISDICTION . EACH BORROWER, THE ADMINISTRATIVE AGENT AND LENDERS HEREBY IRREVOCABLY SUBMIT TO THE NON-EXCLUSIVE JURISDICTION OF ANY UNITED STATES FEDERAL COURT OR NEW YORK STATE COURT SITTING IN NEW YORK, NEW YORK IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY OF THE LOAN DOCUMENTS AND EACH BORROWER, THE ADMINISTRATIVE AGENT AND LENDERS HEREBY IRREVOCABLY AGREE THAT ALL CLAIMS IN RESPECT OF SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN ANY SUCH UNITED STATES FEDERAL COURT OR NEW YORK STATE COURT. EACH BORROWER IRREVOCABLY CONSENTS TO THE SERVICE OF ANY AND ALL PROCESS IN ANY SUCH ACTION OR PROCEEDING BROUGHT IN ANY COURT IN OR OF THE STATE OF NEW YORK BY THE DELIVERY OF COPIES OF SUCH PROCESS TO
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IT AT THE APPLICABLE ADDRESSES SPECIFIED ON THE SIGNATURE PAGE HERETO OR BY CERTIFIED MAIL DIRECTED TO SUCH ADDRESS OR SUCH OTHER ADDRESS AS MAY BE DESIGNATED BY IT IN A NOTICE TO THE OTHER PARTIES THAT COMPLIES AS TO DELIVERY WITH THE TERMS OF SECTION 13.6 . NOTHING IN THIS SECTION SHALL AFFECT THE RIGHT OF THE LENDERS AND THE ADMINISTRATIVE AGENT TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY LAW OR LIMIT THE RIGHT OF THE LENDERS OR THE ADMINISTRATIVE AGENT (OR ANY OF THEM) TO BRING ANY SUCH ACTION OR PROCEEDING AGAINST ANY CREDIT PARTY OR ANY OF THEIR PROPERTY IN THE COURTS WITH SUBJECT MATTER JURISDICTION OF ANY OTHER JURISDICTION. EACH BORROWER IRREVOCABLY WAIVES ANY OBJECTION TO THE LAYING OF VENUE OF ANY SUCH SUIT OR PROCEEDING IN THE ABOVE DESCRIBED COURTS.
     13.3 GOVERNING LAW . THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.
     13.4 Interest . In the event the obligation of the Borrowers to pay interest on the principal balance of the Notes or on any other amounts outstanding hereunder or under the other Loan Documents is or becomes in excess of the maximum interest rate which the Borrowers are permitted by law to contract or agree to pay, giving due consideration to the execution date of this Agreement, then, in that event, the rate of interest applicable thereto with respect to such Lender’s applicable Percentages shall be deemed to be immediately reduced to such maximum rate and all previous payments in excess of the maximum rate shall be deemed to have been payments in reduction of principal and not of interest.
     13.5 Closing Costs and Other Costs; Indemnification .
     (a) The Borrowers shall pay or reimburse (i) the Administrative Agent and its Affiliates for payment of, on demand, all reasonable costs and expenses, including, by way of description and not limitation, reasonable outside attorney fees and advances, appraisal and accounting fees, lien search fees, and required travel costs, incurred by the Administrative Agent and its Affiliates in connection with the commitment, syndication, negotiation, consummation, closing and funding of the loans contemplated hereby, or in connection with the preparation, administration or enforcement of this Agreement or the other Loan Documents (including the obtaining of legal advice regarding the rights and responsibilities of the parties hereto) or any refinancing or restructuring of the loans or Advances provided under this Agreement or the other Loan Documents, or any amendment, revision, modification, consent or waiver thereof requested by any Borrower, and (ii) the Administrative Agent and its Affiliates and each of the Lenders, as the case may be, for all stamp and other taxes and duties payable or determined to be payable in connection with the execution, delivery, filing or recording of this Agreement and the other Loan Documents and the consummation of the transactions contemplated hereby, and any and all liabilities with respect to or resulting from any delay in paying or omitting to pay such taxes or duties. Furthermore, all reasonable costs and expenses, including without limitation outside attorney fees, incurred by the Administrative Agent and its Affiliates and, after the occurrence and during the continuance of an Event of Default, by the Lenders in revising, preserving, protecting, exercising or enforcing any of
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its or any of the Lenders’ rights against any Borrower or any other Credit Party, or otherwise incurred by the Administrative Agent and its Affiliates and the Lenders in connection with any Event of Default or the enforcement of the loans (whether incurred through negotiations, legal proceedings or otherwise), including by way of description and not limitation, such charges in any court or bankruptcy proceedings or arising out of any claim or action by any person against the Administrative Agent, its Affiliates, or any Lender which would not have been asserted were it not for the Administrative Agent’s or such Affiliate’s or Lender’s relationship with the Borrowers hereunder or otherwise, shall also be paid by the Borrowers. All of said amounts required to be paid by the Borrowers hereunder and not paid within five (5) Business Days upon demand, as aforesaid, shall bear interest, from the date incurred to the date payment is received by the Administrative Agent, at the Base Rate, plus two percent (2%).
     (b) EACH BORROWER AGREES TO INDEMNIFY AND HOLD THE ADMINISTRATIVE AGENT AND EACH OF THE LENDERS (AND THEIR RESPECTIVE AFFILIATES) HARMLESS FROM ALL LOSS, COST, DAMAGE, LIABILITY OR EXPENSES, INCLUDING REASONABLE OUTSIDE ATTORNEYS’ FEES AND DISBURSEMENTS (BUT WITHOUT DUPLICATION OF SUCH FEES AND DISBURSEMENTS FOR THE SAME SERVICES), INCURRED BY THE ADMINISTRATIVE AGENT AND EACH OF THE LENDERS BY REASON OF AN EVENT OF DEFAULT, OR ENFORCING THE OBLIGATIONS OF ANY CREDIT PARTY UNDER THIS AGREEMENT OR ANY OF THE OTHER LOAN DOCUMENTS, AS APPLICABLE, OR IN THE PROSECUTION OR DEFENSE OF ANY ACTION OR PROCEEDING CONCERNING ANY MATTER GROWING OUT OF OR CONNECTED WITH THIS AGREEMENT OR ANY OF THE LOAN DOCUMENTS, EXCLUDING, HOWEVER, ANY LOSS, COST, DAMAGE, LIABILITY OR EXPENSES TO THE EXTENT ARISING AS A RESULT OF THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF THE PARTY SEEKING TO BE INDEMNIFIED UNDER THIS SECTION 13.5(B) , PROVIDED THAT, THE BORROWERS SHALL BE OBLIGATED TO REIMBURSE THE ADMINISTRATIVE AGENT AND THE LENDERS FOR ONLY A SINGLE FINANCIAL CONSULTANT SELECTED BY THE ADMINISTRATIVE AGENT IN CONSULTATION WITH THE LENDERS.
     (c) EACH BORROWER AGREES TO DEFEND, INDEMNIFY AND HOLD HARMLESS THE ADMINISTRATIVE AGENT AND EACH LENDER (AND THEIR RESPECTIVE AFFILIATES), AND THEIR RESPECTIVE EMPLOYEES, AGENTS, OFFICERS AND DIRECTORS FROM AND AGAINST ANY AND ALL CLAIMS, DEMANDS, PENALTIES, FINES, LIABILITIES, SETTLEMENTS, DAMAGES, COSTS OR EXPENSES OF WHATEVER KIND OR NATURE (INCLUDING WITHOUT LIMITATION, REASONABLE ATTORNEYS AND CONSULTANTS FEES, INVESTIGATION AND LABORATORY FEES, ENVIRONMENTAL STUDIES REQUIRED BY THE ADMINISTRATIVE AGENT OR ANY LENDER IN CONNECTION WITH THE VIOLATION OF HAZARDOUS MATERIAL LAWS), COURT COSTS AND LITIGATION EXPENSES, ARISING OUT OF OR RELATED TO (I) THE PRESENCE, USE, DISPOSAL, RELEASE OR THREATENED RELEASE OF ANY HAZARDOUS MATERIALS ON, FROM OR
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AFFECTING ANY PREMISES OWNED OR OCCUPIED BY ANY CREDIT PARTY IN VIOLATION OF OR THE NON-COMPLIANCE WITH APPLICABLE HAZARDOUS MATERIAL LAWS, (II) ANY PERSONAL INJURY (INCLUDING WRONGFUL DEATH) OR PROPERTY DAMAGE (REAL OR PERSONAL) ARISING OUT OF OR RELATED TO SUCH HAZARDOUS MATERIALS, (III) ANY LAWSUIT OR OTHER PROCEEDING BROUGHT OR THREATENED, SETTLEMENT REACHED OR GOVERNMENTAL ORDER OR DECREE RELATING TO SUCH HAZARDOUS MATERIALS, AND/OR (IV) COMPLYING OR COMING INTO COMPLIANCE WITH ALL HAZARDOUS MATERIAL LAWS (INCLUDING THE COST OF ANY REMEDIATION OR MONITORING REQUIRED IN CONNECTION THEREWITH) OR ANY OTHER REQUIREMENT OF LAW; PROVIDED , HOWEVER , THAT THE BORROWERS SHALL HAVE NO OBLIGATIONS UNDER THIS SECTION 13.5(C) WITH RESPECT TO CLAIMS, DEMANDS, PENALTIES, FINES, LIABILITIES, SETTLEMENTS, DAMAGES, COSTS OR EXPENSES TO THE EXTENT ARISING AS A RESULT OF THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF THE ADMINISTRATIVE AGENT OR SUCH LENDER, AS THE CASE MAY BE. THE OBLIGATIONS OF THE BORROWERS UNDER THIS SECTION 13.5(C) SHALL BE IN ADDITION TO ANY AND ALL OTHER OBLIGATIONS AND LIABILITIES THE BORROWERS MAY HAVE TO THE ADMINISTRATIVE AGENT OR ANY OF THE LENDERS AT COMMON LAW OR PURSUANT TO ANY OTHER AGREEMENT.
     13.6 Notices .
     (a) Except as expressly provided otherwise in this Agreement (and except as provided in clause (b) below), all notices and other communications provided to any party hereto under this Agreement or any other Loan Document shall be in writing and shall be given by personal delivery, by mail, by reputable overnight courier or by facsimile and addressed or delivered to it at its address set forth on Schedule 13.6 or at such other address as may be designated by such party in a notice to the other parties that complies as to delivery with the terms of this Section 13.6 or posted to an E-System set up by or at the direction of the Administrative Agent (as set forth below). Any notice, if personally delivered or if mailed and properly addressed with postage prepaid and sent by registered or certified mail, shall be deemed given when received or when delivery is refused; any notice, if given to a reputable overnight courier and properly addressed, shall be deemed given two (2) Business Days after the date on which it was sent, unless it is actually received sooner by the named addressee; and any notice, if transmitted by facsimile, shall be deemed given when received. The Administrative Agent may, but, except as specifically provided herein, shall not be required to, take any action on the basis of any notice given to it by telephone, but the giver of any such notice shall promptly confirm such notice in writing or by facsimile, and such notice will not be deemed to have been received until such confirmation is deemed received in accordance with the provisions of this Section set forth above. If such telephonic notice conflicts with any such confirmation, the terms of such telephonic notice shall control. Any notice given by the Administrative Agent or any Lender to any Borrower shall be deemed to be a notice to all of the Credit Parties.
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     (b) Notices and other communications provided to the Administrative Agent and the Lenders party hereto under this Agreement or any other Loan Document may be delivered or furnished by electronic communication (including email and Internet or intranet websites) pursuant to procedures approved by the Administrative Agent. The Administrative Agent or any Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications (including email and any E-System) pursuant to procedures approved by it. Unless otherwise agreed to in a writing by and among the parties to a particular communication, (i) notices and other communications sent to an email address shall be deemed received upon the sender’s receipt of an acknowledgment from the intended recipient (such as by the “ return receipt requested ” function, return email, or other written acknowledgment) and (ii) notices and other communications posted to any E-System shall be deemed received upon the deemed receipt by the intended recipient at its email address as described in the foregoing clause (i) of notification that such notice or other communication is available and identifying the website address therefore.
     13.7 Reserved .
     13.8 Successors and Assigns; Participations; Assignments .
     (a) This Agreement shall be binding upon and shall inure to the benefit of the Borrowers and the Lenders and their respective successors and assigns.
     (b) The foregoing shall not authorize any assignment by any Borrower of its rights or duties hereunder, and, except as otherwise provided herein, no such assignment shall be made (or be effective) without the prior written approval of the Lenders.
     (c) No Lenders may at any time assign or grant participations in such Lender’s rights and obligations hereunder and under the other Loan Documents except (i) by way of assignment to any Eligible Assignee in accordance with clause (d) of this Section, (ii) by way of a participation in accordance with the provisions of clause (e) of this Section or (iii) by way of a pledge or assignment of a security interest subject to the restrictions of clause (f) of this Section (and any other attempted assignment or transfer by any Lender shall be deemed to be null and void).
     (d) Each assignment by a Lender of all or any portion of its rights and obligations hereunder and under the other Loan Documents, shall be subject to the following terms and conditions:
     (i) each such assignment shall be made on a pro rata basis, and shall be in a minimum amount of the lesser of (x) Five Million Dollars ($5,000,000) or such lesser amount as the Administrative Agent shall agree and (y) the entire remaining amount of assigning Lender’s aggregate interest in the Revolving Credit (and participations in any outstanding Letters of Credit) and the Term Loan; provided , however , that, after giving effect to such assignment, in no event shall the entire remaining amount (if any) of assigning Lender’s aggregate interest
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in the Revolving Credit (and participations in any outstanding Letters of Credit) and the Term Loan be less than $5,000,000; and
     (ii) the parties to any assignment shall execute and deliver to the Administrative Agent an Assignment Agreement substantially (as determined by the Administrative Agent) in the form attached hereto as Exhibit G (with appropriate insertions acceptable to the Administrative Agent), together with a processing and recordation fee in the amount, if any, required as set forth in the Assignment Agreement ( provided , however , that such Lender need not deliver an Assignment Agreement in connection with assignments to such Lender’s Affiliates or to a Federal Reserve Bank).
Until the Assignment Agreement becomes effective in accordance with its terms, and the Administrative Agent has confirmed that the assignment satisfies the requirements of this Section 13.8 , the Borrowers and the Administrative Agent shall be entitled to continue to deal solely and directly with the assigning Lender in connection with the interest so assigned. From and after the effective date of each Assignment Agreement that satisfies the requirements of this Section 13.8 , the assignee thereunder shall be deemed to be a party to this Agreement, such assignee shall have the rights and obligations of a Lender under this Agreement and the other Loan Documents (including without limitation the right to receive fees payable hereunder in respect of the period following such assignment) and the assigning Lender shall relinquish its rights and be released from its obligations under this Agreement and the other Loan Documents.
     The words “ execution ,” “ signed ,” “ signature ,” and words of like import in any Assignment Agreement shall be deemed to include electronic signatures or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act.
     Upon request, the Borrowers shall execute and deliver to the Administrative Agent, new Note(s) payable to the order of the assignee in an amount equal to the amount assigned to the assigning Lender pursuant to such Assignment Agreement, and with respect to the portion of the Indebtedness retained by the assigning Lender, to the extent applicable, new Note(s) payable to the order of the assigning Lender in an amount equal to the amount retained by such Lender hereunder. The Administrative Agent, the Lenders and the Borrowers acknowledge and agree that any such new Note(s) shall be given in renewal and replacement of the Notes issued to the assigning lender prior to such assignment and shall not effect or constitute a novation or discharge of the Indebtedness evidenced by such prior Note, and each such new Note may contain a provision confirming such agreement.
     (e) The Borrowers and the Administrative Agent acknowledge that each of the Lenders may at any time and from time to time, subject to the terms and conditions hereof, grant participations in such Lender’s rights and obligations hereunder (on a pro rata basis only) and under the other Loan Documents to any Person (other than a natural
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person or to any Borrower or any of such Borrower’s Affiliates or Subsidiaries); provided that any participation permitted hereunder shall comply with all applicable laws and shall be subject to a participation agreement that incorporates the following restrictions:
     (i) such Lender shall remain the holder of its Notes hereunder (if such Notes are issued), notwithstanding any such participation;
     (ii) a participant shall not reassign or transfer, or grant any sub-participations in its participation interest hereunder or any part thereof; and
     (iii) such Lender shall retain the sole right and responsibility to enforce the obligations of the Credit Parties relating to the Notes and the other Loan Documents, including, without limitation, the right to proceed against any Guarantors, or cause the Administrative Agent to do so (subject to the terms and conditions hereof), and the right to approve any amendment, modification or waiver of any provision of this Agreement without the consent of the participant (unless such participant is an Affiliate of such Lender), except for those matters covered by Section 13.10(a) through (e) hereof (provided that a participant may exercise approval rights over such matters only on an indirect basis, acting through such Lender and the Credit Parties, the Administrative Agent and the other Lenders may continue to deal directly with such Lender in connection with such Lender’s rights and duties hereunder). Notwithstanding the foregoing, however, in the case of any participation granted by any Lender hereunder, the participant shall not have any rights under this Agreement or any of the other Loan Documents against the Administrative Agent, any other Lender or any Credit Party; provided , however , that the participant may have rights against such Lender in respect of such participation as may be set forth in the applicable participation agreement and all amounts payable by the Credit Parties hereunder shall be determined as if such Lender had not sold such participation. Each such participant shall be entitled to the benefits of Article 11 of this Agreement to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to clause (d) of this Section, provided that no participant shall be entitled to receive any greater amount pursuant to such the provisions of Article 11 than the issuing Lender would have been entitled to receive in respect of the amount of the participation transferred by such issuing Lender to such participant had no such transfer occurred and each such participant shall also be entitled to the benefits of Section 9.6 hereof as though it were a Lender, provided that such participant agrees to be subject to Section 10.3 hereof as though it were a Lender.
     (f) Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement (including its Notes, if any) to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank; provided that no such pledge or assignment or enforcement thereof shall release such Lender from any of its obligations hereunder or substitute any such pledge or assignee for such Lender as a party hereto.
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     (g) The Administrative Agent shall maintain at its principal office a copy of each Assignment Agreement delivered to it and a register (the “ Register ”) for the recordation of the names and addresses of the Lenders, the Percentages of such Lenders and the principal amount of each type of Advance owing to each such Lender from time to time. The entries in the Register shall be conclusive evidence, absent manifest error, and the Borrowers, the Administrative Agent, and the Lenders may treat each Person whose name is recorded in the Register as the owner of the Advances recorded therein for all purposes of this Agreement. The Register shall be available for inspection by any Borrower or any Lender upon reasonable notice to the Administrative Agent and a copy of such information shall be provided to any such party on their prior written request. The Administrative Agent shall give prompt written notice to the Administrative Borrower of the making of any entry in the Register or any change in such entry.
     (h) The Borrowers authorize each Lender to disclose to any prospective assignee or participant which has satisfied the requirements hereunder, any and all financial information in such Lender’s possession concerning the Credit Parties which has been delivered to such Lender pursuant to this Agreement, provided that each such prospective assignee or participant shall execute a confidentiality agreement consistent with the terms of Section 13.11 hereof or shall otherwise agree to be bound by the terms thereof.
     (i) Nothing in this Agreement, the Notes or the other Loan Documents, expressed or implied, is intended to or shall confer on any Person other than the respective parties hereto and thereto and their successors and assignees and participants permitted hereunder and thereunder any benefit or any legal or equitable right, remedy or other claim under this Agreement, the Notes or the other Loan Documents.
     13.9 Counterparts . This Agreement may be executed in several counterparts, and each executed copy shall constitute an original instrument, but such counterparts shall together constitute but one and the same instrument.
     13.10 Amendment and Waiver .
     (a) No amendment or waiver of any provision of this Agreement or any other Loan Document, nor consent to any departure by any Credit Party therefrom, shall in any event be effective unless the same shall be in writing and signed by the Administrative Agent and the Majority Lenders (or by the Administrative Agent at the written request of the Majority Lenders) or, if this Agreement expressly so requires with respect to the subject matter thereof, by all Lenders (and, with respect to any amendments to this Agreement or the other Loan Documents, by any Credit Party or the Guarantors that are signatories thereto), and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given; provided , however , that no amendment, waiver or consent shall, unless in writing and signed by the Lender or Lenders affected thereby, do any of the following: (a) increase or decrease the stated amount of such Lender’s commitment hereunder, (b) reduce the amortization or principal of, or interest on, any outstanding Indebtedness or any Fees or other amounts payable hereunder, (c) postpone any date fixed for any payment of principal of, or interest on, any
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outstanding Indebtedness or any Fees or other amounts payable hereunder, (d) except as expressly permitted hereunder or under the Collateral Documents, release all or substantially all of the Collateral (provided that neither the Administrative Agent nor any Lender shall be prohibited thereby from proposing or participating in a consensual or nonconsensual debtor-in-possession or similar financing), or release any material guaranty provided by any Person in favor of the Administrative Agent and the Lenders, provided , however , that the Administrative Agent shall be entitled, without notice to or any further action or consent of the Lenders, to release any Collateral which any Credit Party is permitted to sell, assign or otherwise transfer in compliance with this Agreement or the other Loan Documents or release any guaranty to the extent expressly permitted in this Agreement or any of the other Loan Documents (whether in connection with the sale, transfer or other disposition of the applicable Guarantor or otherwise), (e) terminate or modify any indemnity provided to the Lenders hereunder or under the other Loan Documents, except as shall be otherwise expressly provided in this Agreement or any other Loan Document, or (f) change the definitions of “ Revolving Credit Percentage ”, “ Term Loan Percentage ”, “ Weighted Percentage ”, “ Interest Periods ”, “ Majority Lenders ”, “ Majority Revolving Credit Lenders ”, “ Majority Term Loan Lenders ”, Sections 10.2 or 10.3 hereof or this Section 13.10 ; provided , further , that notwithstanding the foregoing, the Revolving Credit Maturity Date may be postponed or extended, only with the consent of all of the Revolving Credit Lenders; and the Term Loan Maturity Date may be postponed or extended only with the consent of all of the Term Loan Lenders; and provided further , that no amendment, waiver or consent shall, unless in a writing signed by the Swing Line Lender, do any of the following: (x) reduce the principal of, or interest on, the Swing Line Note or (y) postpone any date fixed for any payment of principal of, or interest on, the Swing Line Note and provided further , that no amendment, waiver or consent shall, unless in a writing signed by Issuing Lender affect the rights or duties of Issuing Lender under this Agreement or any of the other Loan Documents and no amendment, waiver, or consent shall, unless in a writing signed by the Administrative Agent affect the rights or duties of the Administrative Agent under this Agreement or any other Loan Document. All references in this Agreement to “ Lenders ” or “ the Lenders ” shall refer to all Lenders, unless expressly stated to refer to Majority Lenders (or the like).
     (b) The Administrative Agent shall, upon the written request of the Administrative Borrower, execute and deliver to the Credit Parties such documents as may be necessary to evidence (1) the release of any Lien granted to or held by the Administrative Agent upon any Collateral: (a) upon termination of the Revolving Credit Aggregate Commitment and payment in full of all Indebtedness payable under this Agreement and under any other Loan Document; (b) which constitutes property (including, without limitation, Equity Interests in any Person) sold or to be sold or disposed of as part of or in connection with any disposition (whether by sale, by merger or by any other form of transaction and including the property of any Subsidiary that is disposed of as permitted hereby) permitted in accordance with the terms of this Agreement; (c) which constitutes property in which a Credit Party owned no interest at the time the Lien was granted or at any time thereafter; or (d) if approved, authorized or ratified in writing by the Majority Lenders, or all the Lenders, as the case may be, as provided in this Section 13.10 ; or (2) the release of any Person from its obligations under
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the Loan Documents (including without limitation the Guaranty) if all of the Equity Interests of such Person that were held by a Credit Party are sold or otherwise transferred to any transferee other than any Borrower or a Subsidiary of any Borrower as part of or in connection with any disposition (whether by sale, by merger or by any other form of transaction) permitted in accordance with the terms of this Agreement; provided that (i) the Administrative Agent shall not be required to execute any such release or subordination agreement under clauses (1) or (2) above on terms which, in the Administrative Agent’s opinion, would expose the Administrative Agent to liability or create any obligation or entail any consequence other than the release of such Liens without recourse or warranty or such release shall not in any manner discharge, affect or impair the Indebtedness or any Liens upon any Collateral retained by any Credit Party, including (without limitation) the proceeds of the sale or other disposition, all of which shall constitute and remain part of the Collateral.
     13.11 Confidentiality . Each Lender agrees that it will not disclose without the prior consent of the Administrative Borrower (other than to its employees, its Subsidiaries, another Lender, an Affiliate of a Lender or to its auditors or counsel) any information with respect to the Credit Parties which is furnished pursuant to this Agreement or any of the other Loan Documents; provided that any Lender may disclose any such information (a) as has become generally available to the public or has been lawfully obtained by such Lender from any third party under no duty of confidentiality to any Credit Party, (b) as may be required or appropriate in any report, statement or testimony submitted to, or in respect to any inquiry, by, any municipal, state or federal regulatory body having or claiming to have jurisdiction over such Lender, including the Board of Governors of the Federal Reserve System of the United States, the Office of the Comptroller of the Currency or the Federal Deposit Insurance Corporation or similar organizations (whether in the United States or elsewhere) or their successors, (c) as may be required or appropriate in respect to any summons or subpoena or in connection with any litigation, (d) in order to comply with any law, order, regulation, ruling or other requirement of law applicable to such Lender, and (e) to any prospective assignee or participant in accordance with Section 13.8(h) hereof.
     13.12 Substitution or Removal of Lenders .
     If (a) the obligation of any Lender to make Eurocurrency-based Advances has been suspended pursuant to Section 11.3 or 11.4 , (b) any Lender has demanded compensation under Sections 3.4(c) , 11.5 or 11.6 , (c) any Lender has become an Impaired Lender or (d) any Lender has not approved an amendment, waiver or other modification of this Agreement, if such amendment, waiver or modification has been approved by the Majority Lenders and the consent of such Lender is required (in each case, an “ Affected Lender ”), then the Borrowers shall have the following rights in addition to any other rights or remedies it may have hereunder:
     (i) Subject to Section 12.8 hereof, the Borrowers may, with the assistance of the Administrative Agent, seek a substitute Lender or Lenders (which may be one or more of the Lenders (the “ Purchasing Lender ” or “ Purchasing Lenders ”) to purchase the Advances of the Revolving Credit, the Swing Line and/or the Term Loan, as the case may be and assume the Revolving Credit Aggregate Commitment (including without limitation the participations in
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Swing Line Advances and Letters of Credit) under this Agreement of such Affected Lender, and require the Affected Lender to sell its Advances of the Revolving Credit, the Swing Line and the Term Loan, as the case may be, and assign its Revolving Credit Aggregate Commitment to such Purchasing Lender or Purchasing Lenders within two (2) Business Days after receiving notice from the Administrative Borrower requiring it to do so, at an aggregate price equal to the outstanding principal amount thereof, plus unpaid interest accrued thereon up to but excluding the date of the sale, payable (in immediately available funds) in cash. In connection with any such sale, and as a condition thereof, the Borrowers shall pay to the Affected Lender all fees accrued for its account hereunder to but excluding the date of such sale, plus, if demanded by the Affected Lender within ten (10) Business Days after such sale, (x) the amount of any compensation which would be due to the Affected Lender under Section 11.1 if the Borrowers had prepaid the outstanding Eurocurrency-based Advances of the Affected Lender on the date of such sale (unless such Affected Lender is an Impaired Lender, in which case no such compensation shall be due) and (y) any additional compensation accrued for its account under Sections 3.4(c) , 11.5 and 11.6 to but excluding said date. Upon such sale, the Purchasing Lender or Purchasing Lenders shall assume the Affected Lender’s commitment, the rights of the Affected Lender shall be terminated hereunder and the Affected Lender shall be released from its obligations hereunder to a corresponding extent. The Affected Lender, as assignor, such Purchasing Lender, as assignee, the Borrowers and the Administrative Agent, shall enter into an Assignment Agreement pursuant to Section 13.8 hereof, whereupon such Purchasing Lender shall be a Lender party to this Agreement, shall be deemed to be an assignee hereunder and shall have all the rights and obligations of a Lender with a Revolving Credit Percentage equal to its ratable share of the then applicable Revolving Credit Aggregate Commitment and the applicable Percentages of the Term Loan of the Affected Lender, provided , however , that if the Affected Lender does not execute such Assignment Agreement within (2) Business Days of receipt thereof, the Administrative Agent may execute the Assignment Agreement as the Affected Lender’s attorney-in-fact. Each of the Lenders hereby irrevocably constitutes and appoints the Administrative Agent and any officer or agent thereof, with full power of substitution, as its true and lawful attorney-in-fact with full power and authority in the name of such Lender or in its own name to execute and deliver an Assignment Agreement while such Lender is an Affected Lender hereunder (such power of attorney to be deemed coupled with an interest and irrevocable). In connection with any assignment pursuant to this Section 13.12 , the Borrowers or the Purchasing Lender shall pay to the Administrative Agent the administrative fee for processing such assignment referred to in Section 13.8 ; and
     (ii) With respect to any Affected Lender that is an Impaired Lender, the Administrative Borrower may, with the prior written consent of the Administrative Agent and notwithstanding Section 10.3 of this Agreement or any other provisions requiring pro rata payments to the Lenders, elect to reduce the Revolving Credit Aggregate Commitment by the amount of the Revolving Credit Aggregate Commitment of such Affected Lender and repay all amounts (both any
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outstanding Term Loan Advances, subject to subclause (D) below, if such Affected Lender is a Defaulting Lender, and any Revolving Credit Advances) owing to such Affected Lender, subject to the following:
     (A) such Affected Lender shall receive an amount in cash equal to the outstanding principal amount owing to such Affected Lender under this Agreement, plus unpaid interest accrued thereon up to but excluding the date of the repayment. In addition, and as a condition thereof, the Borrowers shall pay to the Affected Lender all fees accrued for its account hereunder to but excluding the date of such repayment, plus, if demanded by the Affected Lender within ten (10) Business Days after such repayment, any additional compensation accrued for its account under Sections 3.4(c) , 11.5 and 11.6 to but excluding said date;
     (B) after giving effect to the reduction in the Revolving Credit Aggregate Commitment and the payments required under subclause (A) above, the Borrowers shall have Unused Revolving Credit Availability of at least $5,000,000 (after taking into account the sum on such date of the outstanding principal amount of all Revolving Credit Advances, Swing Line Advances and Letter of Credit Obligations);
     (C) the stated dollar commitment of any other Lender is not increased thereby; and
     (D) if such Affected Lender is a Defaulting Lender and such Defaulting Lender holds no share of the Revolving Credit Aggregate Commitment, or with respect to which the Borrowers have elected to reduce the Revolving Credit Aggregate Commitment of such Defaulting Lender by such Defaulting Lender’s Revolving Credit Percentage in accordance with the foregoing provisions of this clause (ii) , the Borrowers may repay all amounts owing to such Lender in connection with the Term Loan, provided that (I) the Majority Lenders have consented to such payment in writing, (II) after giving effect to any reduction of the Revolving Credit Aggregate Commitment or payments on the Revolving Credit under clause (ii) above and payments on the Term Loan under this clause (D) , the Borrowers shall have availability, on the date of the repayment, to borrow additional Revolving Credit Advances under the Revolving Credit Aggregate Commitment of at least $5,000,000 (after taking into account the sum on such date of the outstanding principal amount of all Revolving Credit Advances, Swing Line Advances and Letter of Credit Obligations) and (III) the stated dollar commitment of any other Lender is not increased thereby.
     13.13 Withholding Taxes . If any Lender is not a “ united states person ” within the meaning of Section 7701(a)(30) of the Internal Revenue Code, such Lender shall promptly (but in any event prior to the initial payment of interest hereunder or prior to its accepting any assignment under Section 13.8 hereof, as applicable) deliver to the Administrative Agent two
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original executed copies of (i) Internal Revenue Service Form W-8BEN or any successor form specifying the applicable tax treaty between the United States and the jurisdiction of such Lender’s domicile which provides for the exemption from withholding on interest payments to such Lender, (ii) Internal Revenue Service Form W-8ECI or any successor form evidencing that the income to be received by such Lender hereunder is effectively connected with the conduct of a trade or business in the United States or (iii) other evidence satisfactory to the Administrative Agent that such Lender is exempt from United States income tax withholding with respect to such income; provided , however , that such Lender shall not be required to deliver to the Administrative Agent the aforesaid forms or other evidence with respect to Advances to the Borrowers, if such Lender has assigned its entire interest hereunder (including its Revolving Credit Commitment Amount, any outstanding Advances hereunder and participations in Letters of Credit issued hereunder and any Notes issued to it by the Borrowers), to an Affiliate which is incorporated under the laws of the United States or a state thereof, and so notifies the Administrative Agent. Such Lender shall amend or supplement any such form or evidence as required to insure that it is accurate, complete and non-misleading at all times. Promptly upon notice from the Administrative Agent of any determination by the Internal Revenue Service that any payments previously made to such Lender hereunder were subject to United States income tax withholding when made, such Lender shall pay to the Administrative Agent the excess of the aggregate amount required to be withheld from such payments over the aggregate amount actually withheld by the Administrative Agent. In addition, from time to time upon the reasonable request and the sole expense of the Borrowers, each Lender and the Administrative Agent shall (to the extent it is able to do so based upon applicable facts and circumstances), complete and provide the Administrative Borrower with such forms, certificates or other documents as may be reasonably necessary to allow any Borrower, as applicable, to make any payment under this Agreement or the other Loan Documents without any withholding for or on the account of any tax under Section 10.1(d) hereof (or with such withholding at a reduced rate), provided that the execution and delivery of such forms, certificates or other documents does not adversely affect or otherwise restrict the rights and benefits (including without limitation economic benefits) available to such Lender or the Administrative Agent, as the case may be, under this Agreement or any of the other Loan Documents, or under or in connection with any transactions not related to the transactions contemplated hereby.
     13.14 Taxes and Fees . Should any tax (other than as a result of a Lender’s failure to comply with Section 13.13 or a tax based upon the net income or capitalization of any Lender or the Administrative Agent by any jurisdiction where a Lender or the Administrative Agent is or has been located), or recording or filing fee become payable in respect of this Agreement or any of the other Loan Documents or any amendment, modification or supplement hereof or thereof, the Borrowers agree to pay the same, together with any interest or penalties thereon arising from any Borrower’s actions or omissions, and agrees to hold the Administrative Agent and the Lenders harmless with respect thereto, provided , however , that the Borrowers shall not be responsible for any such interest or penalties which were incurred prior to the date that notice is given to the Credit Parties of such tax or fees. Notwithstanding the foregoing, nothing contained in this Section 13.14 shall affect or reduce the rights of any Lender or the Administrative Agent under Section 11.5 hereof.
     13.15 WAIVER OF JURY TRIAL . THE LENDERS, THE AGENT AND EACH BORROWER KNOWINGLY, VOLUNTARILY AND INTENTIONALLY WAIVE ANY
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RIGHT ANY OF THEM MAY HAVE TO A TRIAL BY JURY IN ANY LITIGATION BASED UPON OR ARISING OUT OF THIS AGREEMENT OR ANY RELATED INSTRUMENT OR AGREEMENT OR ANY OF THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY COURSE OF CONDUCT, DEALING, STATEMENTS (WHETHER ORAL OR WRITTEN) OR ACTION OF ANY OF THEM. NEITHER THE LENDERS, THE AGENT NOR ANY BORROWER SHALL SEEK TO CONSOLIDATE, BY COUNTERCLAIM OR OTHERWISE, ANY SUCH ACTION IN WHICH A JURY TRIAL HAS BEEN WAIVED WITH ANY OTHER ACTION IN WHICH A JURY TRIAL CANNOT BE OR HAS NOT BEEN WAIVED. THESE PROVISIONS SHALL NOT BE DEEMED TO HAVE BEEN MODIFIED IN ANY RESPECT OR RELINQUISHED BY THE LENDERS AND THE AGENT OR ANY BORROWER EXCEPT BY A WRITTEN INSTRUMENT EXECUTED BY ALL OF THEM.
     13.16 USA Patriot Act Notice . Pursuant to Section 326 of the USA Patriot Act, the Administrative Agent and the Lenders hereby notify the Credit Parties that if they or any of their Subsidiaries open an account, including any loan, deposit account, treasury management account, or other extension of credit with the Administrative Agent or any Lender, the Administrative Agent or the applicable Lender will request the applicable Person’s name, tax identification number, business address and other information necessary to identify such Person (and may request such Person’s organizational documents or other identifying documents) to the extent necessary for the Administrative Agent and the applicable Lender to comply with the USA Patriot Act.
     13.17 Complete Agreement; Conflicts . This Agreement, the Notes (if issued), any Requests for Revolving Credit Advance and Requests for Swing Line Advance and Term Loan Rate Requests, and the Loan Documents contain the entire agreement of the parties hereto, superseding all prior agreements, discussions and understandings relating to the subject matter hereof, and none of the parties shall be bound by anything not expressed in writing. In the event of any conflict between the terms of this Agreement and the other Loan Documents, this Agreement shall govern.
     13.18 Severability . In case any one or more of the obligations of the Credit Parties under this Agreement, the Notes or any of the other Loan Documents shall be invalid, illegal or unenforceable in any jurisdiction, the validity, legality and enforceability of the remaining obligations of the Credit Parties shall not in any way be affected or impaired thereby, and such invalidity, illegality or unenforceability in one jurisdiction shall not affect the validity, legality or enforceability of the obligations of the Credit Parties under this Agreement, the Notes or any of the other Loan Documents in any other jurisdiction.
     13.19 Table of Contents and Headings; Section References . The table of contents and the headings of the various subdivisions hereof are for convenience of reference only and shall in no way modify or affect any of the terms or provisions hereof and references herein to “ sections ,” “ subsections ,” “ clauses ,” “ paragraphs ,” “ subparagraphs ,” “ exhibits ” and “ schedules ” shall be to sections, subsections, clauses, paragraphs, subparagraphs, exhibits and schedules, respectively, of this Agreement unless otherwise specifically provided herein or unless the context otherwise clearly indicates.
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     13.20 Construction of Certain Provisions . If any provision of this Agreement or any of the Loan Documents refers to any action to be taken by any Person, or which such Person is prohibited from taking, such provision shall be applicable whether such action is taken directly or indirectly by such Person, whether or not expressly specified in such provision.
     13.21 Independence of Covenants . Each covenant hereunder shall be given independent effect (subject to any exceptions stated in such covenant) so that if a particular action or condition is not permitted by any such covenant (taking into account any such stated exception), the fact that it would be permitted by an exception to, or would be otherwise within the limitations of, another covenant shall not avoid the occurrence of a Default or an Event of Default.
     13.22 Electronic Transmissions .
     (a) Each of the Administrative Agent, the Credit Parties, the Lenders, and each of their Affiliates is authorized (but not required) to transmit, post or otherwise make or communicate, in its sole discretion, Electronic Transmissions in connection with any Loan Document and the transactions contemplated therein. Each Borrower and each other Credit Party hereby acknowledges and agrees that the use of Electronic Transmissions is not necessarily secure and that there are risks associated with such use, including risks of interception, disclosure and abuse and each indicates it assumes and accepts such risks by hereby authorizing the transmission of Electronic Transmissions.
     (b) All uses of an E-System shall be governed by and subject to, in addition to Section 13.6 and this Section 13.22 , separate terms and conditions posted or referenced in such E-System and related contractual obligations executed by the Administrative Agent, the Credit Parties and the Lenders in connection with the use of such E-System.
     (c) All E-Systems and Electronic Transmissions shall be provided “ as is ” and “ as available ”. None of the Administrative Agent or any of its Affiliates warrants the accuracy, adequacy or completeness of any E-Systems or Electronic Transmission, and each disclaims all liability for errors or omissions therein. No warranty of any kind is made by the Administrative Agent or any of its Affiliates in connection with any E Systems or Electronic Transmission, including any warranty of merchantability, fitness for a particular purpose, non-infringement of third-party rights or freedom from viruses or other code defects. The Administrative Agent, the Credit Parties and the Lenders agree that the Administrative Agent has no responsibility for maintaining or providing any equipment, software, services or any testing required in connection with any Electronic Transmission or otherwise required for any E-System.
     13.23 Advertisements . The Administrative Agent and the Lenders may disclose the names of the Credit Parties and the existence of the Indebtedness in general advertisements and trade publications.
     13.24 Reliance on and Survival of Provisions . All terms, covenants, agreements, representations and warranties of the Credit Parties to any of the Loan Documents made herein or in any of the Loan Documents or in any certificate, report, financial statement or other
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document furnished by or on behalf of any Credit Party in connection with this Agreement or any of the Loan Documents shall be deemed to have been relied upon by the Lenders, notwithstanding any investigation heretofore or hereafter made by any Lender or on such Lender’s behalf, and those covenants and agreements of the Borrowers set forth in Section 13.5 hereof (together with any other indemnities of any Credit Party contained elsewhere in this Agreement or in any of the other Loan Documents) and of Lenders set forth in Section 12.7 hereof shall survive the repayment in full of the Indebtedness and the termination of any commitment to extend credit.
     13.25 Joint and Several Liability .
     (a) Each of the Borrowers acknowledges and agrees that it is the intent of the parties that each such Borrower be primarily liable for the obligations as a joint and several obligor. It is the intention of the parties that with respect to liability of any Borrower hereunder arising solely by reason of its being jointly and severally liable for Advances and other extensions of credit taken by the Borrowers, the obligations of such Borrower shall be absolute, unconditional and irrevocable irrespective of:
     (i) any lack of validity, legality or enforceability of this Agreement or any Note as to any Borrower, as the case may be;
     (ii) the failure of any Lender or any holder of any Note:
     (A) to enforce any right or remedy against any Borrower, as the case may be, or any other Person (including any Guarantor) under the provisions of this Agreement, such Note, or otherwise, or
     (B) to exercise any right or remedy against any guarantor of, or collateral securing, any obligations;
     (iii) any change in the time, manner or place of payment of, or in any other term of, all or any of the Indebtedness, or any other extension, compromise or renewal of any Indebtedness;
     (iv) any reduction, limitation, impairment or termination of any Indebtedness with respect to any Borrower, as the case may be, for any reason, including any claim of waiver, release, surrender, alteration or compromise, and shall not be subject to (and each of the Borrowers hereby waives any right to or claim of) any defense (other than the defense of payment in full of the Indebtedness) or setoff, counterclaim, recoupment or termination whatsoever by reason of the invalidity, illegality, nongenuineness, irregularity, compromise, unenforceability of, or any other event or occurrence affecting, any Indebtedness with respect to any Borrower, as the case may be;
     (v) any addition, exchange, release, surrender or nonperfection of any collateral, or any amendment to or waiver or release or addition of, or consent to departure from, any guaranty, held by any Lender or any holder of the Notes securing any of the Indebtedness; or
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     (vi) any other circumstance which might otherwise constitute a defense (other than the defense of payment in full of the Indebtedness) available to, or a legal or equitable discharge of, any Borrower, as the case may be, any surety or any guarantor.
     (b) Each of the Borrowers agrees that its joint and several liability hereunder shall continue to be effective or be reinstated, as the case may be, if at any time any payment (in whole or in part) of any of the Indebtedness is rescinded or must be restored by any Lender or any holder of any Note, upon the insolvency, bankruptcy or reorganization of any Borrower, as the case may be, as though such payment had not been made;
     (c) Each of the Borrowers hereby expressly waives: (i) notice of the Lenders’ acceptance of this Agreement; (ii) notice of the existence or creation or non payment of all or any of the Indebtedness other than notices expressly provided for in this Agreement; (iii) presentment, demand, notice of dishonor, protest, and all other notices whatsoever other than notices expressly provided for in this Agreement; (iv) any claim or defense based on an election of remedies; and (v) all diligence in collection or protection of or realization upon the Indebtedness or any part thereof, any obligation hereunder, or any security for or guaranty of any of the foregoing.
     (d) No delay on any of the Lenders part in the exercise of any right or remedy shall operate as a waiver thereof, and no single or partial exercise by any of the Lenders of any right or remedy shall preclude other or further exercise thereof or the exercise of any other right or remedy. No action of any of the Lenders permitted hereunder shall in any way affect or impair any such Lenders’ rights or any Borrower’s Indebtedness under this Agreement.
     (e) Each of the Borrowers hereby represents and warrants to each of the Lenders that it now has and will continue to have independent means of obtaining information concerning the Borrowers’ affairs, financial condition and business. Lenders shall not have any duty or responsibility to provide any Borrower with any credit or other information concerning such Borrower’s affairs, financial condition or business which may come into the Lenders’ possession.
     (f) Each of the Borrowers represents and warrants (i) that the business operations of the Borrowers are interrelated and that the business operations of the Borrowers complement one another, and such entities have a common business purpose, and (ii) that, to permit their uninterrupted and continuous operations, such entities now require and will from time to time hereafter require funds and credit accommodations for general business purposes and that (iii) the proceeds of advances under the Revolving Credit, the Term Loan, the Swing Line and the other credit facilities extended hereunder will directly or indirectly benefit the Borrowers hereunder, severally and jointly, regardless of which the Borrowers receives part or all of the proceeds of such Advances.
     (g) Notwithstanding anything to the contrary contained herein, it is the intention of the Borrowers, the Agent and the Lenders that the amount of the respective
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Borrowers’ obligations hereunder shall be in, but not in excess of, the maximum amount thereof not subject to avoidance or recovery by operation of applicable law governing bankruptcy, reorganization, arrangement, adjustment of debts, relief of debtors, dissolution, insolvency, fraudulent transfers or conveyances or other similar laws (collectively, “ Applicable Insolvency Laws ”). To that end, but only in the event and to the extent that the Borrowers’ respective obligations hereunder or any payment made pursuant thereto would, but for the operation of the foregoing proviso, be subject to avoidance or recovery under Applicable Insolvency Laws, the amount of the Borrowers’ respective obligations hereunder shall be limited to the largest amount which, after giving effect thereto, would not, under Applicable Insolvency Laws, render the Borrowers’ respective obligations hereunder unenforceable or avoidable or subject to recovery under Applicable Insolvency Laws. To the extent any payment actually made hereunder exceeds the limitation contained in this Section 13.25(g) , then the amount of such excess shall, from and after the time of payment by the Borrowers (or any of them), be reimbursed by the Lenders upon demand by such Borrowers. The foregoing proviso is intended solely to preserve the rights of the Agent and the Lenders hereunder against the Borrowers to the maximum extent permitted by Applicable Insolvency Laws and neither any Borrower nor any Guarantor nor any other Person shall have any right or claim under this Section 13.25(g) that would not otherwise be available under Applicable Insolvency Laws.
     13.26 Administrative Borrower as Agent for the Borrowers . Each Borrower hereby irrevocably appoints the Administrative Borrower as the borrowing agent and attorney-in-fact for all Borrowers, which appointment shall remain in full force and effect unless and until the Administrative Agent shall have received prior written notice signed by each Borrower that such appointment has been revoked and that another Borrower has been appointed Administrative Borrower. Each Borrower hereby irrevocably appoints and authorizes the Administrative Borrower (i) to provide the Administrative Agent with all notices with respect to Advances and Letters of Credit obtained for the benefit of any Borrower and all other notices and instructions under this Agreement and (ii) to take such action as the Administrative Borrower deems appropriate on its behalf to obtain Advances and Letters of Credit and to exercise such other powers as are reasonably incidental thereto to carry out the purposes of this Agreement. It is understood that the handling of the Register pursuant to Sections 2.2(c) , 4.2(c) and 13.8(g) hereof and Collateral of the Borrowers in a combined fashion, as more fully set forth herein and in the other Loan Documents, is done solely as an accommodation to the Borrowers in order to utilize the collective borrowing powers of the Borrowers in the most efficient and economical manner and at their request, and that the Administrative Agent and the Lenders shall not incur liability to any Borrower as a result hereof. Each Borrower expects to derive benefit, directly or indirectly, from the handling of the Register and the Collateral in a combined fashion since the operation of each Borrower is dependent on the performance of the integrated group. To induce the Administrative Agent and the Lenders to do so, and in consideration thereof, each Borrower hereby jointly and severally agrees to indemnify the Administrative Agent and the Lenders and hold the Administrative Agent and the Lenders harmless against any and all liability, expense, loss or claim of damage or injury, made against the Administrative Agent or any Lender by any Borrower or by any third-party whosoever, arising from or incurred by reason of (a) the handling of the Register and Collateral of the Borrowers as herein provided, (b) the Administrative Agent and the Lenders relying on any instructions of the Administrative Borrower, or (c) any other
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action taken by the Administrative Agent or the Lenders hereunder or under the other Loan Documents, except that the Borrowers will have no liability to the Administrative Agent or any Lender, as applicable, under this Section 13.26 with respect to any liability that has been finally determined by a court of competent jurisdiction to have resulted solely from the gross negligence or willful misconduct of such party, as the case may be.
[Signatures Follow On Succeeding Page]
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     WITNESS the due execution hereof as of the day and year first above written.

 	 	AMERICAN MIDSTREAM, LLC,
as the Administrative Borrower and as a Borrower	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Brian Bierbach	 	 	
 	 	 	 	 	 	 	
 	 	 	 	Brian Bierbach, CEO and President	 	 	
Signature Page — Credit Agreement

 

 	 	 	 	 	
 	COMERICA BANK ,
as the Administrative Agent
 	 	
 	By:  	/s/ Caroline M. McClurg  	 	
 	 	Caroline M. McClurg, Vice President 	 	

 	COMERICA BANK ,
as a Lender, as Issuing Lender
and as Swing Line Lender
 	 	
 	By:  	Caroline M. McClurg  	 	
 	 	Caroline M. McClurg, Vice President 	 	

Signature Page — Credit Agreement

 

 	 	 	 	 	 	 	
		
 	 	COMPASS BANK,
as the Documentation Agent and as a Lender	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Greg Determann	 	 	
 	 	 	 	 	 	 	
 	 	Name:	 	Greg Determann	 	 	
 	 	Title:	 	Vice President	 	 	
Signature Page — Credit Agreement

 

 	 	 	 	 	 	 	
		
 	 	ROYAL BANK OF CANADA ,
as a Lender	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Jason S. York	 	 	
 	 	 	 	 	 	 	
 	 	Name:	 	Jason S. York	 	 	
 	 	Title:	 	Authorized Signatory	 	 	
Signature Page — Credit Agreement

 

Schedule 1.1
Applicable Margin Grid
Revolving Credit and Term Loan Facilities *
(basis points per annum)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basis for Pricing	 	Level I	 	Level II	 	Level III	 	Level IV	
 	 	 	 	 	 	≥ 2.00:1.00 but	 	≥ 2.50:1.00 but	 	 	
Total Debt to Consolidated EBITDA Ratio	 	< 2.00:1.00	 	< 2.50:1.00	 	< 3.00:1.00	 	≥ 3.00:1.00	
Revolving Credit Eurodollar Margin	 	 	325.00	 	 	 	350.00	 	 	 	375.00	 	 	 	400.00	 	
Revolving Credit Base Rate Margin	 	 	225.00	 	 	 	250.00	 	 	 	275.00	 	 	 	300.00	 	
Revolving Credit Facility Fee	 	 	100.00	 	 	 	100.00	 	 	 	100.00	 	 	 	100.00	 	
Letter of Credit Fees (exclusive of facing fees)	 	 	325.00	 	 	 	350.00	 	 	 	375.00	 	 	 	400.00	 	
Term Loan Eurodollar Margin	 	 	325.00	 	 	 	350.00	 	 	 	375.00	 	 	 	400.00	 	
Term Loan Base Rate Margin	 	 	225.00	 	 	 	250.00	 	 	 	275.00	 	 	 	300.00	 	
Term Loan Facility Fee	 	 	100.00	 	 	 	100.00	 	 	 	100.00	 	 	 	100.00	 	

*	 	Definitions as set forth in the Credit Agreement.	
 		
**	 	Level III pricing shall be in effect until the delivery of the audited financial statements for the fiscal year ending December 31, 2009, after which time the pricing grid shall govern.	

 
Schedule 1.2
Percentages and Allocations
Revolving Credit and Term Loan Facilities
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	REVOLVING	 	REVOLVING	 	 	 	 	 	 	
 	 	CREDIT	 	CREDIT	 	TERM LOAN	 	TERM LOAN	 	WEIGHTED	
LENDERS	 	PERCENTAGE	 	ALLOCATIONS	 	PERCENTAGE	 	ALLOCATIONS	 	PERCENTAGE	
Comerica Bank	 	 	35.296	%	 	$	12,353,600	 	 	 	35.296	%	 	$	17,648,000	 	 	 	 	 	
Compass Bank	 	 	35.294	%	 	$	12,352,900	 	 	 	35.294	%	 	$	17,647,000	 	 	 	 	 	
Royal Bank of Canada	 	 	29.41	%	 	$	10,293,500	 	 	 	29.41	%	 	$	14,705,000	 	 	 	 	 	
TOTALS	 	 	100	%	 	$	35,000,000	 	 	 	100	%	 	$	50,000,000	 	 	 	100	%	

Exhibit 10.2
FIRST AMENDMENT
TO
REVOLVING AND TERM LOAN CREDIT AGREEMENT
     This FIRST AMENDMENT TO REVOLVING AND TERM LOAN CREDIT AGREEMENT (this “ Amendment ”) is entered into as of April 19, 2010, to be effective as of October 5, 2009, among AMERICAN MIDSTREAM, LLC, AMERICAN MIDSTREAM MARKETING, LLC, AMERICAN MIDSTREAM (ALABAMA GATHERING), LLC, AMERICAN MIDSTREAM (ALABAMA INTRASTATE), LLC, AMERICAN MIDSTREAM (ALATENN), LLC, AMERICAN MIDSTREAM (MIDLA), LLC, AMERICAN MIDSTREAM (MISSISSIPPI), LLC, AMERICAN MIDSTREAM (TENNESSEE RIVER), LLC, AMERICAN MIDSTREAM ONSHORE PIPELINES, LLC, MID LOUISIANA GAS TRANSAMISSION, LLC, AMERICAN MIDSTREAM (LOUISIANA INTRASTATE), LLC, AMERICAN MIDSTREAM (SIGCO INTRASTATE), LLC and AMERICAN MIDSTREAM OFFSHORE (SEACREST) LP, (collectively, the “ Borrowers ”) the LENDERS (as hereinafter defined), and COMERICA BANK , as administrative agent for the Lenders, (in such capacity, the “ Administrative Agent ”).
     WHEREAS, the Borrowers, the financial institutions party thereto (collectively, together with their respective successors and assigns, the “ Lenders ”), and the Administrative Agent are parties to that certain Revolving and Term Loan Credit Agreement dated as of October 5, 2009 (as amended hereby and as hereafter renewed, extended, amended or restated, the “ Credit Agreement ”);
     WHEREAS, the Borrowers have requested that the Lenders amend the Credit Agreement as hereinafter provided;
     WHEREAS, subject to the terms and conditions set forth herein, the Administrative Agent and the Lenders are willing to agree to such amendment; and
     WHEREAS, the Borrowers, the Lenders and the Administrative Agent acknowledge that the terms of this Amendment constitute an amendment and modification of, and not a novation of, the Credit Agreement.
     NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:
     SECTION 1. Definitions . Unless otherwise defined in this Amendment, terms used in this Amendment that are defined in the Credit Agreement shall have the meanings assigned to such terms in the Credit Agreement.
     SECTION 2. Amendments to the Credit Agreement . Subject to satisfaction of the conditions precedent set forth in Section 3 of this Amendment, the parties hereto agree that:
     (a)  Section 1.1 is hereby amended to amend and restate the following definition in its entirety to read as follows:
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     “ Test Period ” means, at any time, the four consecutive fiscal quarters of the Administrative Borrower then last ended (in each case taken as one accounting period) for which financial statements have been or are required to be delivered pursuant to this Agreement; provided , however , all financial covenant calculations with respect to the Test Periods ending December 31, 2009, March 31, 2010, June 30, 2010, and September 30, 2010, shall be made by multiplying each figure used in the applicable calculation times a fraction, the numerator of which is 360 and the denominator of which is the number of days elapsed from the Effective Date through the end of the applicable fiscal quarter.
     SECTION 3. (c) Conditions of Effectiveness . The amendments set forth in Section 2 of this Amendment, as well as any other terms and conditions set forth herein shall be effective as of date first above written, provided that the Administrative Agent shall have received the following:
     (a) a counterpart of this Amendment executed by the Borrowers and the Lenders (which may be by telecopy or pdf transmission); and
     (b) such other assurances, certificates, documents, consents or opinions as the Administrative Agent reasonably may require.
     SECTION 4. Acknowledgment and Ratification . As a material inducement to the Administrative Agent and the Lenders to execute and deliver this Amendment, the Borrowers acknowledge and agree that the execution, delivery, and performance of this Amendment shall, except as expressly provided herein, in no way release, diminish, impair, reduce, or otherwise affect the obligations of the Credit Parties under the Loan Documents, which Loan Documents shall remain in full force and effect.
     SECTION 5. Borrowers’ Representations and Warranties . As a material inducement to the Administrative Agent and the Lenders to execute and deliver this Amendment, the Borrowers represent and warrant to the Administrative Agent and the Lenders (with the knowledge and intent that the Administrative Agent and the Lenders are relying upon the same in entering into this Amendment) that, as of the date of its execution of this Amendment:
     (a) This Amendment, the Credit Agreement and each of the other Loan Documents to which it is a party, have each been duly executed and delivered by its duly authorized officers and constitute the valid and binding obligations of such party, enforceable against such party in accordance with their respective terms, except as enforcement thereof may be limited by applicable bankruptcy, reorganization, insolvency, fraudulent conveyance, moratorium or similar laws affecting the enforcement of creditor’s rights, generally and by general principles of equity (regardless of whether enforcement is considered in a proceeding at law or in equity).
     (b) The representations and warranties set forth in Article 6 of the Credit Agreement are true and correct in all material respects, after giving effect to this Amendment, as if made on
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and as of the date of this Amendment (except to the extent such representations and warranties relate solely to an earlier date, in which case, they are true and correct as of such date).
     (c) At the time of and after giving effect to this Amendment, no Default or Event of Default exists.
     (d) The execution, delivery and performance of this Amendment are within each Borrower’s limited liability company or limited partnership power, as the case may be, have been duly authorized, are not in contravention of any law applicable to such party or the terms of such party’s organizational documents and, except as have been previously obtained or as referred to in Section 6.10 of the Credit Agreement, do not require the consent or approval of any Governmental Authority or any other third party except to the extent that such consent or approval is not material to the transactions contemplated by this Amendment.
     SECTION 6. Administrative Agent and Lenders Make No Representations or Warranties . By execution of this Amendment, neither the Administrative Agent nor any Lender (a) makes any representation or warranty or assumes any responsibility with respect to any statements, warranties, or representations made in or in connection with the Loan Documents or the execution, legality, validity, enforceability, genuineness, sufficiency, or value of this Amendment, the Credit Agreement, the Loan Documents or any other instrument or document furnished pursuant thereto, or (b) makes any representation or warranty or assumes any responsibility with respect to the financial condition of the Borrowers or any other Person or the performance or observance by such Persons of any of their obligations under the Loan Documents, or any other instrument or document furnished pursuant thereto.
     SECTION 7. Effect of Amendment . This Amendment (a) except as expressly provided herein, shall not be deemed to be a consent to the modification or waiver of any other term or condition of the Credit Agreement, any Collateral Document, the other Loan Documents or any of the instruments or agreements referred to therein, (b) shall not prejudice any right or rights which the Administrative Agent or the Lenders may now or hereafter have under or in connection with the Credit Agreement, any Collateral Document or any other Loan Document, including, without limitation, the right to accelerate the Indebtedness, institute foreclosure proceedings, exercise their respective rights under the UCC or other applicable law, and/or institute collection proceedings against the Borrowers, to the extent provided therein or by law, and except as expressly provided herein, and (c) shall not be deemed to be a waiver of any existing or future Default or Event of Default under the Credit Agreement, the Collateral Documents or any other Loan Document.
     SECTION 8. Miscellaneous . This Amendment shall be governed by, and construed in accordance with, the law of the State of New York. The captions in this Amendment are for convenience of reference only and shall not define or limit the provisions hereof. This Amendment may be executed in separate counterparts, each of which when so executed and delivered shall be an original, but all of which together shall constitute one instrument. In proving this Amendment, it shall not be necessary to produce or account for more than one such counterpart. This Amendment, and any documents required or requested to be delivered pursuant to Section 3 hereof, may be delivered by telecopy or pdf transmission of the relevant signature pages hereof and thereof, as applicable.
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     SECTION 9. Ratification . The Borrowers ratify and acknowledge the Loan Documents are valid, subsisting and enforceable.
[Remainder of page intentionally left blank. Signature pages follow.]
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     IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorized officers as of the date and year first above written.

 	 	American Midstream, LLC ,
a Delaware limited liability company	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Brian Bierbach
 
Brian Bierbach, CEO and President	 	 	

 	 	American Midstream Marketing, LLC ,	
 	 	a Delaware limited liability company	
 	 	American Midstream (Alabama Gathering), LLC ,	
 	 	an Alabama limited liability company	
 	 	American Midstream (Alabama Intrastate), LLC ,	
 	 	an Alabama limited liability company	
 	 	American Midstream (AlaTenn), LLC ,	
 	 	an Alabama limited liability company	
 	 	American Midstream (Midla), LLC ,	
 	 	a Delaware limited liability company	
 	 	American Midstream (Mississippi), LLC ,	
 	 	a Delaware limited liability company	
 	 	American Midstream (Tennessee River), LLC ,	
 	 	an Alabama limited liability company	
 	 	American Midstream Onshore Pipelines, LLC ,	
 	 	a Delaware limited liability company	
 	 	Mid Louisiana Gas Transmission, LLC ,	
 	 	a Delaware limited liability company	

 	 	Each By:	 	American Midstream, LLC,	 	 	
 	 	 	 	a Delaware limited liability company,	 	 	
 	 	 	 	its sole member	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Brian Bierbach
 
Brian Bierbach, CEO and President	 	 	
Signature Page to First Amendment to
Revolving and Term Loan Credit Agreement

 

 	 	 	
		
 	 	American Midstream (Louisiana Intrastate), LLC ,	
 	 	a Delaware limited liability company	
 	 	American Midstream (SIGCO Intrastate), LLC ,	
 	 	a Delaware limited liability company	

 	 	Each By:	 	Mid Louisiana Gas Transmission, LLC,
a Delaware limited liability company,
its sole member	 	 	
 	 	 	 	 	 	 	 	 	
 	 	By:	 	American Midstream, LLC,
a Delaware limited liability company,
its sole member	 	 	
 	 	 	 	 	 	 	 	 	
 	 	 	 	By:	 	/s/ Brian Bierbach
 
Brian Bierbach, CEO and President	 	 	

 	 	American Midstream Offshore (Seacrest) LP ,
a Texas limited partnership	 	 	
 	 	 	 	 	 	 	 	 	
 	 	By:	 	American Midstream, LLC,
a Delaware limited liability company,
its general partner	 	 	
 	 	 	 	 	 	 	 	 	
 	 	 	 	By:	 	/s/ Brian Bierbach
 
Brian Bierbach, CEO and President	 	 	
Signature Page to First Amendment to
Revolving and Term Loan Credit Agreement

 

 	 	 	 	 	 	 	
		
 	 	COMERICA BANK ,
as the Administrative Agent	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Caroline M. McClurg
 
Caroline M. McClurg, Vice President	 	 	
 	 	 	 	 	 	 	
 	 	COMERICA BANK ,
as a Lender	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Caroline M. McClurg
 
Caroline M. McClurg, Vice President	 	 	
Signature Page to First Amendment to
Revolving and Term Loan Credit Agreement

 

 	 	 	 	 	 	 	
		
 	 	COMPASS BANK ,
as a Lender	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Greg Determann
 
Greg Determann, Vice President	 	 	
Signature Page to First Amendment to
Revolving and Term Loan Credit Agreement

 

 	 	 	 	 	 	 	
		
 	 	ROYAL BANK OF CANADA ,
as a Lender	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Jason S. York
 
Jason S. York, Authorized Signatory	 	 	
Signature Page to First Amendment to
Revolving and Term Loan Credit Agreement

Exhibit 10.3
EXECUTION VERSION
SECOND AMENDMENT AND WAIVER
TO
REVOLVING AND TERM LOAN CREDIT AGREEMENT
     This SECOND AMENDMENT AND WAIVER TO REVOLVING AND TERM LOAN CREDIT AGREEMENT (this “ Amendment ”) is entered into as of July 30, 2010, among AMERICAN MIDSTREAM, LLC, AMERICAN MIDSTREAM MARKETING, LLC, AMERICAN MIDSTREAM (ALABAMA GATHERING), LLC, AMERICAN MIDSTREAM (ALABAMA INTRASTATE), LLC, AMERICAN MIDSTREAM (ALATENN), LLC, AMERICAN MIDSTREAM (MIDLA), LLC, AMERICAN MIDSTREAM (MISSISSIPPI), LLC, AMERICAN MIDSTREAM (TENNESSEE RIVER), LLC, AMERICAN MIDSTREAM ONSHORE PIPELINES, LLC, MID LOUISIANA GAS TRANSMISSION, LLC, AMERICAN MIDSTREAM (LOUISIANA INTRASTATE), LLC, AMERICAN MIDSTREAM (SIGCO INTRASTATE), LLC and AMERICAN MIDSTREAM OFFSHORE (SEACREST) LP, (collectively, the “ Borrowers ”) the LENDERS (as hereinafter defined), and COMERICA BANK , as administrative agent for the Lenders (in such capacity, the “ Administrative Agent ”).
     WHEREAS, the Borrowers, the financial institutions party thereto (collectively, together with their respective successors and assigns, the “ Lenders ”), and the Administrative Agent are parties to that certain Revolving and Term Loan Credit Agreement dated as of October 5, 2009, as amended by First Amendment to Revolving and Term Loan Credit Agreement dated as of April 19, 2010 (as amended hereby and as hereafter renewed, extended, amended or restated, the “ Credit Agreement ”);
     WHEREAS, (a) the Borrowers were not in compliance with the affirmative covenant set forth in Section 7.1(b) of the Credit Agreement whereby the Borrowers were required to furnish to the Administrative Agent quarterly financial statements in comparative form for the corresponding periods in the previous Fiscal Year for the fiscal quarters ended March 31, 2010, and June 30, 2010, (b) the Administrative Borrower was not in compliance with the negative covenant set forth in Section 8.1 of the Credit Agreement whereby the Borrowers were prohibited from incurring Debt except as otherwise permitted therein and (c) the Administrative Borrower was not in compliance with the negative covenant set forth in Section 8.2 of the Credit Agreement whereby the Borrowers were prohibited from creating Liens except as otherwise permitted therein. The Administrative Borrower incurred Debt in connection with the financing of its insurance premiums in violation of Section 8.1 of the Credit Agreement and created a Lien in connection with such financing in violation of Section 8.2 of the Credit Agreement. Such events of non-compliance constitute Events of Default under Section 9.1(c) of the Credit Agreement (collectively, the “ Existing Events of Default ”);
     WHEREAS, the Borrowers have requested that the Lenders amend the Credit Agreement and waive the Existing Events of Default as hereinafter provided;
     WHEREAS, subject to the terms and conditions set forth herein, the Administrative Agent and the Lenders are willing to agree to such amendments and waiver; and
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     WHEREAS, the Borrowers, the Lenders and the Administrative Agent acknowledge that the terms of this Amendment constitute an amendment and modification of, and not a novation of, the Credit Agreement.
     NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties, although they are under no obligation to do so, are willing to (i) waive the Existing Events of Default and (ii) amend certain provisions of the Credit Agreement, all on terms and conditions set forth herein.
     SECTION 1. Definitions . Unless otherwise defined in this Amendment, terms used in this Amendment that are defined in the Credit Agreement shall have the meanings assigned to such terms in the Credit Agreement.
     SECTION 2. Amendments to the Credit Agreement . Subject to satisfaction of the conditions of effectiveness set forth in Section 4 of this Amendment, the parties hereto agree that:
     (a)  Section 1.1 is hereby amended to amend and restate the following definitions in their entirety to read as follows:
     “ Consolidated EBITDA ” means, for any Test Period, Consolidated Net Income for such Test Period, adjusted by (x) adding thereto , in each case only to the extent (and in the same proportion) deducted in determining Consolidated Net Income:
     (a) Consolidated Interest Expense for such Test Period,
     (b) Consolidated Tax Expense for such Test Period,
     (c) Consolidated Depreciation Expense for such Test Period,
     (d) Consolidated Amortization Expense for such Test Period,
     (e) (i) expenses related to any initial public offering with respect to the Parent and other extraordinary expenses, (ii) audit expenses for the Fiscal Years ended December 31, 2007, and December 31, 2008, the stub period from January 1, 2009, to October 13, 2009, and any costs associated with the opening balance sheet valuation of the Administrative Borrower and its Subsidiaries, (iii) Fees (which include amendment fees), (iv) transaction-related expenses with respect to the Credit Agreement and the Acquisition, (v) the premium paid for the first year of insurance for environmental liability being purchased on or about the Effective Date, and (vi) payments of up to an aggregate of $700,000 per Fiscal Year that have been made by any of the Borrowers or their Subsidiaries with respect to any equity incentive plan adopted by any of the Borrowers and their Subsidiaries (including, without limitation, the American Midstream GP, LLC Long-Term Incentive Plan dated November 2, 2009, as amended and as the same may be further amended, modified or extended from time to time),
     (f) subject to the approval of the Administrative Agent in its reasonable discretion, the aggregate amount of all other non-cash charges and “other expenses”
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(determined in accordance with GAAP) reducing Consolidated Net Income (excluding any non-cash charge that results in an accrual of a reserve for cash charges in any future period) for such Test Period, and
(y) subject to the approval of the Administrative Agent in its sole discretion, subtracting therefrom the aggregate amount of all non-cash items and “other income” (determined in accordance with GAAP) increasing Consolidated Net Income (other than the accrual of revenue or recording of receivables in the ordinary course of business) for such Test Period.
     “ Total Debt to Consolidated EBITDA Ratio ” means, for any Test Period, the ratio of (a) without duplication, total Debt of the Administrative Borrower and its Subsidiaries for such Test Period to (b) Consolidated EBITDA of the Administrative Borrower and its Subsidiaries for such Test Period; provided , however , Insurance Premium Financing Debt shall not be included as Debt in the calculation of the Total Debt to Consolidated EBITDA Ratio for any Test Period.
     (b)  Section 1.1 is hereby amended to add the following definitions in alphabetical order to the Credit Agreement to read as follows:
     “ Insurance Financing Contract ” means that certain Premium Financing Agreement, Disclosure Statement and Security Agreement dated November 1, 2009, by and among the Administrative Borrower, Lockton Insurance Agency and AICCO, Inc., as the same may be amended, modified, extended or refinanced from time to time.
     “ Insurance Premium Financing Debt ” means the Debt incurred by the Administrative Borrower under the Insurance Financing Contract.
     “ Insurance Premium Financing Lien ” means the Lien created by the Administrative Borrower under the Insurance Financing Contract.
     (c)  Section 7.1(b) is hereby amended to amend and restate Section 7.1(b) in its entirety to read as follows:
     (b) as soon as available, but in any event within forty five (45) days after the end of each fiscal quarter of the Administrative Borrower (except the last quarter of each Fiscal Year), Administrative Borrower prepared unaudited Consolidated balance sheets of the Administrative Borrower and its Consolidated Subsidiaries as at the end of such quarter and the related unaudited statements of income, stockholders equity and cash flows of the Administrative Borrower and its Consolidated Subsidiaries for the portion of the Fiscal Year through the end of such quarter, setting forth in each case (beginning with the fiscal quarter ending March 31, 2011) in comparative form the figures for the corresponding periods in the previous Fiscal Year, and certified by a Responsible Officer of the Administrative Borrower as being fairly stated in all material respects; and
     (d)  Section 8.1(h) is hereby amended by removing the word “and” at the end thereof.
     (e)  Section 8.1(i) is hereby amended by removing the word “and” at the end thereof.
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     (f)  Section 8.1(j) is hereby amended by removing the “.” at the end thereof and substituting “;” in lieu thereof.
     (g)  Section 8.1 is hereby amended by adding a new subsection (k) in its entirety to read as follows:
     (k) Insurance Premium Financing Debt not to exceed $1,300,000 at any time outstanding; and
     (h)  Section 8.1 is hereby amended by adding a new subsection (l) in its entirty to read as follows:
     (l) Guarantee Obligations of the Administrative Borrower in respect of Debt otherwise permitted hereunder of any other Borrower or wholly-owned Subsidiary.
     (i)  Section 8.2(j) is hereby amended by removing the word “and” at the end thereof.
     (j)  Section 8.2(k) is hereby amended by removing the “.” at the end thereof and substituting “; and” in lieu thereof.
     (k)  Section 8.2 is hereby amended by adding new subsection (l) in its entirety to read as follows:
     (l) the Insurance Premium Financing Lien.
     (l)  Section 8.5(b) is hereby amended to remove the reference to “3.00:1.00” therein and substitute “3.25:1.00” in lieu thereof.
     SECTION 3. Limited Waiver . The Administrative Agent and the Lenders hereby waive the Existing Events of Default and any and all rights and remedies the Administrative Agent and the Lenders may have under the Credit Agreement, the other Loan Documents or applicable law with respect thereto. Other than as expressly set forth herein, the foregoing waiver shall not constitute a waiver of any other Default or Event of Default that is now in existence or that may hereafter occur, or any rights or remedies the Administrative Agent and the Lenders may have under the Credit Agreement, the other Loan Documents or applicable law with respect thereto, all of which rights and remedies the Administrative Agent and the Lenders specifically reserve in accordance with the terms hereof.
     SECTION 4. (a) Conditions of Effectiveness . The amendments set forth in Section 2 and the Limited Waiver set forth in Section 3 of this Amendment, as well as any other terms and conditions set forth herein shall be effective as of date first above written, provided that the Administrative Agent shall have received the following:
     (b) a counterpart of this Amendment executed by the Borrowers and the Lenders (which may be by telecopy or pdf transmission); and
     (c) payment for distribution to (i) the Revolving Credit Lenders pro-rata in accordance with their respective Revolving Credit Percentages an amendment fee in an amount
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equal to 10.0 basis points times the Revolving Credit Aggregate Commitment in effect as of the date hereof and (ii) the Term Loan Lenders pro-rata in accordance with their respective Term Loan Percentages an amendment fee in an amount equal to 10.0 basis points times the aggregate outstanding principal amount of the Term Loan as of the date hereof.
     SECTION 5. Acknowledgment and Ratification . As a material inducement to the Administrative Agent and the Lenders to execute and deliver this Amendment, the Borrowers acknowledge and agree that the execution, delivery, and performance of this Amendment shall, except as expressly provided herein, in no way release, diminish, impair, reduce, or otherwise affect the obligations of the Credit Parties under the Loan Documents, which Loan Documents shall remain in full force and effect.
     SECTION 6. Borrowers’ Representations and Warranties . As a material inducement to the Administrative Agent and the Lenders to execute and deliver this Amendment, the Borrowers represent and warrant to the Administrative Agent and the Lenders (with the knowledge and intent that the Administrative Agent and the Lenders are relying upon the same in entering into this Amendment) that, as of the date of its execution of this Amendment:
     (a) This Amendment, the Credit Agreement and each of the other Loan Documents to which it is a party, have each been duly executed and delivered by its duly authorized officers and constitute the valid and binding obligations of such party, enforceable against such party in accordance with their respective terms, except as enforcement thereof may be limited by applicable bankruptcy, reorganization, insolvency, fraudulent conveyance, moratorium or similar laws affecting the enforcement of creditor’s rights, generally and by general principles of equity (regardless of whether enforcement is considered in a proceeding at law or in equity).
     (b) The representations and warranties set forth in Article 6 of the Credit Agreement are true and correct in all material respects, after giving effect to this Amendment, as if made on and as of the date of this Amendment (except to the extent such representations and warranties relate solely to an earlier date, in which case, they are true and correct as of such date).
     (c) At the time of and after giving effect to this Amendment, except for the Existing Events of Default, no Default or Event of Default exists.
     (d) The execution, delivery and performance of this Amendment are within each Borrower’s limited liability company or limited partnership power, as the case may be, have been duly authorized, are not in contravention of any law applicable to such party or the terms of such party’s organizational documents and, except as have been previously obtained or as referred to in Section 6.10 of the Credit Agreement, do not require the consent or approval of any Governmental Authority or any other third party except to the extent that such consent or approval is not material to the transactions contemplated by this Amendment.
     SECTION 7. Administrative Agent and Lenders Make No Representations or Warranties . By execution of this Amendment, neither the Administrative Agent nor any Lender (a) makes any representation or warranty or assumes any responsibility with respect to any statements, warranties, or representations made in or in connection with the Loan Documents or the execution, legality, validity, enforceability, genuineness, sufficiency, or value of this
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Amendment, the Credit Agreement, the Loan Documents or any other instrument or document furnished pursuant thereto, or (b) makes any representation or warranty or assumes any responsibility with respect to the financial condition of the Borrowers or any other Person or the performance or observance by such Persons of any of their obligations under the Loan Documents, or any other instrument or document furnished pursuant thereto.
     SECTION 8. Effect of Amendment . This Amendment (a) except as expressly provided herein, shall not be deemed to be a consent to the modification or waiver of any other term or condition of the Credit Agreement, any Collateral Document, the other Loan Documents or any of the instruments or agreements referred to therein, (b) shall not prejudice any right or rights which the Administrative Agent or the Lenders may now or hereafter have under or in connection with the Credit Agreement, any Collateral Document or any other Loan Document, including, without limitation, the right to accelerate the Indebtedness, institute foreclosure proceedings, exercise their respective rights under the UCC or other applicable law, and/or institute collection proceedings against the Borrowers, to the extent provided therein or by law, and except as expressly provided herein, and (c) shall not be deemed to be a waiver of any existing or future Default or Event of Default under the Credit Agreement, the Collateral Documents or any other Loan Document.
     SECTION 9. Miscellaneous . This Amendment shall be governed by, and construed in accordance with, the laws of the State of New York. The captions in this Amendment are for convenience of reference only and shall not define or limit the provisions hereof. This Amendment may be executed in separate counterparts, each of which when so executed and delivered shall be an original, but all of which together shall constitute one instrument. In proving this Amendment, it shall not be necessary to produce or account for more than one such counterpart. This Amendment, and any documents required or requested to be delivered pursuant to Section 4 hereof, may be delivered by telecopy or pdf transmission of the relevant signature pages hereof and thereof, as applicable.
     SECTION 10. Ratification . The Borrowers ratify and acknowledge the Loan Documents are valid, subsisting and enforceable.
[Remainder of page intentionally left blank. Signature pages follow.]
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Revolving and Term Loan Credit Agreement
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     IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorized officers as of the date and year first above written.

 	 	American Midstream, LLC ,	
 	 	a Delaware limited liability company	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Brian Bierbach
 	 	 	
 	 	 	 	Brian Bierbach, CEO and President	 	 	
 	 	 	 	 	 	 	
 	 	American Midstream Marketing, LLC ,	
 	 	a Delaware limited liability company	
 	 	American Midstream (Alabama Gathering), LLC ,	
 	 	an Alabama limited liability company	
 	 	American Midstream (Alabama Intrastate), LLC ,	
 	 	an Alabama limited liability company	
 	 	American Midstream (AlaTenn), LLC ,	
 	 	an Alabama limited liability company	
 	 	American Midstream (Midla), LLC ,	
 	 	a Delaware limited liability company	
 	 	American Midstream (Mississippi), LLC ,	
 	 	a Delaware limited liability company	
 	 	American Midstream (Tennessee River), LLC ,	
 	 	an Alabama limited liability company	
 	 	American Midstream Onshore Pipelines, LLC ,	
 	 	a Delaware limited liability company	
 	 	Mid Louisiana Gas Transmission, LLC ,	
 	 	a Delaware limited liability company	
 	 	 	 	 	 	 	
 	 	Each By:	 	American Midstream, LLC,	 	 	
 	 	 	 	a Delaware limited liability company,	 	 	
 	 	 	 	its sole member	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Brian Bierbach
 
Brian Bierbach, CEO and President	 	 	
Signature Page to Second Amendment and Waiver to
Revolving and Term Loan Credit Agreement

 

 	 	 	 	 	 	 	
		
 	 	American Midstream (Louisiana Intrastate), LLC ,	
 	 	a Delaware limited liability company	
 	 	American Midstream (SIGCO Intrastate), LLC ,	
 	 	a Delaware limited liability company	
 	 	 	 	 	 	 	
 	 	Each By:	 	Mid Louisiana Gas Transmission, LLC,	 	 	
 	 	 	 	a Delaware limited liability company,	 	 	
 	 	 	 	its sole member	 	 	

 	 	By:	 	American Midstream, LLC,	 	 	
 	 	 	 	a Delaware limited liability company,	 	 	
 	 	 	 	its sole member	 	 	

 	 	By:	 	/s/ Brian Bierbach
 
Brian Bierbach, CEO and President	 	 	

 	 	American Midstream Offshore (Seacrest) LP ,  	
 	 	a Texas limited partnership	
 	 	 	 	 	 	 	
 	 	By:	 	American Midstream, LLC,	 	 	
 	 	 	 	a Delaware limited liability company,	 	 	
 	 	 	 	its general partner	 	 	

 	 	By:	 	/s/ Brian Bierbach
 
Brian Bierbach, CEO and President	 	 	
Signature Page to Second Amendment and Waiver to
Revolving and Term Loan Credit Agreement

 

 	 	 	 	 	
 	COMERICA BANK ,
as the Administrative Agent
 	 	
 	By:  	/s/ Caroline M. McClurg  	 	
 	 	Caroline M. McClurg, Vice President 	 	
 	 	 	 	
 	COMERICA BANK ,
as a Lender
 	 	
 	By:  	/s/ Caroline M. McClurg  	 	
 	 	Caroline M. McClurg, Vice President 	 	
Signature Page to Second Amendment and Waiver to
Revolving and Term Loan Credit Agreement

 

 	 	 	 	 	
 	COMPASS BANK ,
as a Lender
 	 	
 	By:  	/s/ Greg Determann  	 	
 	 	Greg Determann, Vice President 	 	
Signature Page to Second Amendment and Waiver to
Revolving and Term Loan Credit Agreement

 

 	 	 	 	 	
 	ROYAL BANK OF CANADA ,
as a Lender
 	 	
 	By:  	/s/ Jason S. York  	 	
 	 	Jason S. York, Authorized Signatory 	 	
Signature Page to Second Amendment and Waiver to
Revolving and Term Loan Credit Agreement

Exhibit 10.4
EMPLOYMENT AGREEMENT
     THIS EMPLOYMENT AGREEMENT (“Agreement”) is made by and between American Midstream GP, LLC, a Delaware limited liability company (“Company”), and Brian F. Bierbach (“Executive”).
W I T N E S S E T H:
     WHEREAS, Executive is currently employed by Company, which is the general partner of American Midstream Partners, LP (“American Midstream LP”), pursuant to that certain Employment Agreement by and between Executive and Company dated November 2, 2009 (the “Existing Agreement”); and
     WHEREAS, in connection with the initial public offering of the common units of American Midstream LP, Company and Executive desire to amend the Existing Agreement in certain respects and, in connection therewith, the parties desire to enter into this Agreement to replace and supersede the Existing Agreement in its entirety as provided herein;
     NOW, THEREFORE, for and in consideration of the mutual promises, covenants and obligations contained herein, Company and Executive agree as follows:
ARTICLE 1: EMPLOYMENT AND DUTIES
     1.1 Employment; Effective Date . Effective as of, and contingent upon, the closing of the initial public offering of the common units of American Midstream LP (the “Effective Date”), and continuing for the period of time set forth in Article 2 of this Agreement, Executive’s employment by Company shall be subject to the terms and conditions of this Agreement.
     1.2 Positions . Company shall employ Executive in the position of President and Chief Executive Officer reporting to the Board of Directors of Company (the “Board”), or in such other positions as the parties mutually may agree.
     1.3 Duties and Services . Executive agrees to serve in the position referred to in paragraph 1.2 and to perform diligently and to the best of his or her abilities the duties and services appertaining to such office, as well as such additional duties and services appropriate to such office which the parties mutually may agree upon from time to time. Executive’s employment shall also be subject to the policies maintained and established by Company that are of general applicability to Company’s executive employees, as such policies may be amended from time to time, provided that in the event of any inconsistency between such policies and any term of this Agreement, this Agreement shall control.
     1.4 Other Interests . Executive agrees, during the period of his or her employment by Company, to devote substantially all of his or her primary business time, energy and best efforts to the business and affairs of Company and its affiliates and not to engage, directly or indirectly, in any other business or businesses, whether or not similar to that of Company, except with the consent of the Board.

 

     1.5 Duty of Loyalty . Executive acknowledges and agrees that Executive owes a fiduciary duty of loyalty to act at all times in the best interests of Company. In keeping with such duty, Executive shall make full disclosure to Company of all business opportunities pertaining to Company’s business and shall not appropriate for Executive’s own benefit business opportunities concerning Company’s business.
ARTICLE 2: TERM AND TERMINATION OF EMPLOYMENT
     2.1 Term . Unless sooner terminated pursuant to other provisions hereof, Company agrees to continue to employ Executive for the period beginning on the Effective Date and ending on the second anniversary of the Effective Date (the “Initial Expiration Date”); provided, however, that beginning on the Initial Expiration Date, and on each anniversary of the Initial Expiration Date thereafter, if this Agreement has not been terminated pursuant to paragraph 2.2 or 2.3, then the term of this Agreement shall automatically be extended for an additional one-year period, unless on or before the date that is 90 days prior to the first day of any such extension period, either party shall give written notice to the other that no such automatic extension shall occur.
     2.2 Company’s Right to Terminate . Notwithstanding the provisions of paragraph 2.1, Company shall have the right to terminate Executive’s employment under this Agreement for any of the following reasons:
     (i) upon Executive’s death;
     (ii) upon Executive’s disability, which shall mean Executive’s becoming incapacitated by accident, sickness, or other circumstances which renders him or her mentally or physically incapable of performing the duties and services required of him or her hereunder for 90 or more days (whether or not consecutive) out of any consecutive 180-day period;
     (iii) for “Cause,” which shall mean Executive has (A) engaged in gross negligence, gross incompetence or willful misconduct in the performance of the duties required of him or her hereunder; (B) refused without proper reason to perform the duties and responsibilities required of him or her hereunder; (C) willfully engaged in conduct that is materially injurious to Company or its affiliates (monetarily or otherwise); (D) committed an act of fraud, embezzlement or willful breach of fiduciary duty to Company or an affiliate (including the unauthorized disclosure of confidential or proprietary material information of Company or an affiliate) or (E) been convicted of (or pleaded no contest to) a crime involving fraud, dishonesty or moral turpitude or any felony; or
     (iv) at any time for any other reason, or for no reason whatsoever, in the sole discretion of the Board.
     2.3 Executive’s Right to Terminate . Notwithstanding the provisions of paragraph 2.1, Executive shall have the right to terminate his or her employment under this Agreement for any of the following reasons:
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     (i) for “Good Reason,” which shall mean, in connection with or based upon a nonconsensual (A) material diminution in Executive’s responsibilities, duties or authority; (B) material diminution in Executive’s base compensation; (C) assignment of Executive to a principal office located beyond a 50-mile radius of Executive’s then current work place, or (D) material breach by Company of any material provision of this Agreement; or
     (ii) at any time for any other reason, or for no reason whatsoever, in the sole discretion of Executive.
     2.4 Notice of Termination . If Company desires to terminate Executive’s employment hereunder at any time prior to expiration of the term of employment as provided in paragraph 2.1, it shall do so by giving a 30-day written notice to Executive that it has elected to terminate Executive’s employment hereunder and stating the effective date and reason for such termination, provided that no such action shall alter or amend any other provisions hereof or rights arising hereunder. If Executive desires to terminate his or her employment hereunder at any time prior to expiration of the term of employment as provided in paragraph 2.1, he or she shall do so by giving a 30-day written notice to Company that he or she has elected to terminate his or her employment hereunder and stating the effective date and reason for such termination, provided that no such action shall alter or amend any other provisions hereof or rights arising hereunder. In the case of any notice by Executive of his or her intent to terminate his or her employment hereunder for Good Reason, Executive shall provide Company with notice of the existence of the condition(s) constituting the Good Reason within 60 days after Executive has actual knowledge of the initial existence of such condition(s) and Company shall have 30 days following Executive’s provision of such notice to remedy such condition(s). If Company remedies the condition(s) constituting the Good Reason within such 30 day period, then Executive’s employment hereunder shall continue and his or her notice of termination shall become void and of no further effect. If Company does not remedy the condition(s) constituting the Good Reason within such 30 day period, Executive’s employment with Company shall terminate on the date that is 31 days following the date of Executive’s notice of termination and Executive shall be entitled to receive the payments and benefits described in paragraph 4.3, if applicable. The notice, remedy rights and termination timing provisions applicable under this paragraph 2.4 in the case of Executive’s election to terminate his or her employment for Good Reason are referred to collectively as the “Good Reason Termination Procedure.”
     2.5 Deemed Resignations . Any termination of Executive’s employment shall constitute an automatic resignation of Executive as an officer of Company and each affiliate of Company, an automatic resignation of Executive from the Board and from the board of directors or similar governing body of any affiliate of Company, and an automatic resignation from the board of directors or similar governing body of any corporation, limited liability company or other entity in which Company or any affiliate holds an equity interest and with respect to which board or similar governing body Executive serves as Company’s or such affiliate’s designee or other representative.
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ARTICLE 3: COMPENSATION AND BENEFITS
     3.1 Base Salary . During the period of this Agreement, Executive shall receive an annual base salary of $275,000. Executive’s annual base salary shall be reviewed by the Compensation Committee of the Board (“Compensation Committee”) on an annual basis, and, in the sole discretion of the Compensation Committee, such annual base salary may be increased, but not decreased (except for a decrease that is consistent with reductions taken generally by other executives of Company), effective as of any date determined by the Compensation Committee. Executive’s annual base salary shall be paid in equal installments in accordance with Company’s standard policy regarding payment of compensation to executives, but no less frequently than monthly.
     3.2 Bonus Opportunity . During the period of this Agreement, Executive shall be provided with the opportunity to earn and receive an annual incentive performance bonus payable in cash in an amount equal to 100 percent (pro-rated for any period of less than 12 months) of Executive’s annual base salary (at the rate in effect at the time the bonus opportunity is awarded), 20 percent of which shall be conditioned and determined on the attainment of personal performance goals and 80 percent of which shall be conditioned and determined on the attainment of organizational performance goals, in each case as set by, and based on performance criteria established by, the Compensation Committee. The Compensation Committee shall notify Executive of the bonus opportunity by no later than the end of the first 90 days of each annual performance period and shall, at that time, set and communicate to Executive the personal and organizational performance goals on which the bonus (and each component thereof) shall be conditioned and the criteria on which the attainment of such goals and the resulting bonus, if any, shall be determined. All determinations with respect to the bonus hereunder shall be made by the Compensation Committee and its determinations shall be final and binding.
     3.3 Incentive Compensation . Executive shall be eligible to receive awards under the Company’s Long Term Incentive Plan, as determined by the Compensation Committee.
     3.4 Other Perquisites . During his or her employment hereunder, Executive shall be afforded the following benefits as incidences of his or her employment:
     (i) Business and Entertainment Expenses — Subject to Company’s standard policies and procedures with respect to expense reimbursement as applied to its executive employees generally, Company shall reimburse Executive for, or pay on behalf of Executive, reasonable and appropriate expenses incurred by Executive for business related purposes, including dues and fees to industry and professional organizations and costs of entertainment and business development.
     (ii) Vacation — During his or her employment hereunder, Executive shall be entitled to four weeks of paid vacation each calendar year (pro-rated for the calendar year containing the Effective Date) and to all holidays provided to executives of Company generally.
     (iii) Other Company Benefits — Executive and, to the extent applicable, Executive’s spouse, dependents and beneficiaries, shall be allowed to participate in, and
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in accordance with the terms of, all benefits, plans and programs, including improvements or modifications of the same, which are now, or may hereafter be, available to other executive employees of Company. Such benefits, plans and programs shall include, without limitation, any profit sharing plan, thrift plan, health insurance or health care plan, life insurance, disability insurance, pension plan, supplemental retirement plan, vacation and sick leave plan, and the like which may be maintained by Company. Company shall not, however, by reason of this paragraph be obligated to institute, maintain, or refrain from changing, amending, or discontinuing, any such benefit plan or program, so long as such changes are similarly applicable to executive employees generally.
ARTICLE 4: EFFECT OF TERMINATION ON COMPENSATION
     4.1 Payment of Accrued Obligations . Upon termination of Executive’s employment hereunder for any reason and by any means, Executive shall be entitled to, and shall be paid, any annual base salary that is accrued and unpaid as of the date of such termination, which shall be paid on the next regularly scheduled pay day for the payment of Executive’s annual base salary, and any expense reimbursement payable in accordance with paragraph 3.4(i) for reimbursable expenses incurred by Executive prior to the date of such termination, which shall be paid at the time and in the manner provided by Company’s reimbursement policy and in accordance with this Agreement. Other than the foregoing amounts and any Severance Pay pursuant to paragraph 4.3, all compensation and benefits to Executive hereunder shall terminate contemporaneously with the termination of Executive’s employment. Any other benefits to which Executive shall be entitled shall be governed by the plan, policy or agreement providing for such benefits and applicable law.
     4.2 Other Terminations . If Executive’s employment hereunder shall terminate at any time (including, but not limited to, upon or following a change of control of the Company), (i) upon expiration of the term provided in paragraph 2.1 hereof because either party has provided the notice contemplated in such paragraph (except as provided in Section 5.6 hereof), (ii) by Executive for Good Reason and in accordance with the Good Reason Termination Procedure or (iii) by Company other than in any event or circumstance described in paragraph 2.2(i), 2.2(ii), or 2.2(iii), then, subject to paragraph 4.4, Company shall pay Executive an amount equal one times the sum of Executive’s annual base salary at the rate in effect under paragraph 3.1 on the date of such termination, plus one times the amount, if any, paid to Executive under paragraph 3.2 for the calendar year ending immediately prior to the date of such termination of Executive’s employment (the “Severance Amount”), which shall be paid as provided in paragraph 4.3.
     4.3 Severance Payments . Subject to paragraph 4.4 below, the Severance Amount, if any shall be due, shall be divided into amounts (each, a “Severance Payment”) to be paid in installments. The amount of each Severance Payment shall be equal to the Severance Amount divided by the number of regular pay days scheduled (in accordance with Company’s regular payroll practices) to occur between the date of Executive’s termination of employment (“Termination Date”) and the first anniversary of the Termination Date (“Scheduled Paydays”). If any Severance Amount would otherwise be owed under this Agreement, but the requirements of paragraph 4.4 are not satisfied, then no Severance Amount and no amount in lieu of the Severance Amount, shall be owed or paid. If the requirements of paragraph 4.4 are satisfied,
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then, subject to paragraph 7.14(iv), a portion of the Severance Amount equal to the product of one Severance Payment and the number of Scheduled Paydays during the 60-day period beginning on the Termination Date shall be paid in a lump sum amount on the 60 th day following the Termination Date, and the remainder of the Severance Amount shall be paid in regular installments, each one equal to the amount of one Severance Payment, with the first such payment being due on due on the Scheduled Payday immediately following the 60 th day after the Termination Date, with like payments on each Scheduled Payday thereafter until the remaining Severance Amount is paid in full.
     4.4 Release and Full Settlement . Anything to the contrary herein notwithstanding, as a condition to the receipt of any portion of the Severance Amount, Executive shall execute a release, in the form established by the Board, releasing the Board, Company, and Company’s parent corporation, subsidiaries, affiliates, and their respective shareholders, partners, officers, directors, employees, attorneys and agents from any and all claims and from any and all causes of action of any kind or character including, but not limited to, all claims or causes of action arising out of Executive’s employment with Company or its affiliates or the termination of such employment, but excluding all claims to vested benefits and payments Executive may have under any compensation or benefit plan, program or arrangement, including this Agreement. Executive shall provide such release to Company no later than 50 days after the Termination Date and, as a condition to Company’s obligation to pay all or any portion of the Severance Amount, Executive shall not revoke such release. The performance of Company’s obligations hereunder shall constitute full settlement of all such claims and causes of action.
     4.5 No Duty to Mitigate Losses . Executive shall have no duty to find new employment following the termination of his or her employment under circumstances which require Company to pay any amount to Executive pursuant to this Article 4. Any salary or remuneration received by Executive from a third party for the providing of personal services (whether by employment or by functioning as an independent contractor) following the termination of his or her employment under circumstances pursuant to which this Article 4 apply shall not reduce Company’s obligation to make a payment to Executive (or the amount of such payment) pursuant to the terms of this Article 4.
     4.6 Liquidated Damages . In light of the difficulties in estimating the damages for an early termination of Executive’s employment under this Agreement, Company and Executive hereby agree that the payments and benefits, if any, to be received by Executive pursuant to this Article 4 shall be received by Executive as liquidated damages.
     4.7 Other Benefits . This Agreement governs the rights and obligations of Executive and Company with respect to Executive’s base salary, bonus and certain perquisites of employment. Except as expressly provided herein, Executive’s rights and obligations both during the term of his or her employment and thereafter with respect to his or her ownership rights in Company and American Midstream LP, and other benefits under the plans and programs maintained by Company shall be governed by the terms (which are not, and are not required to be, affected, altered or amended) of the separate agreements, plans and the other documents and instruments governing such matters.
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ARTICLE 5: PROTECTION OF CONFIDENTIAL INFORMATION
     5.1 Disclosure to and Property of Company . All information, designs, ideas, concepts, improvements, product developments, discoveries and inventions, whether patentable or not, that are conceived, made, developed or acquired by Executive, individually or in conjunction with others, during the period of Executive’s employment by Company (whether during business hours or otherwise and whether on Company’s premises or otherwise) that relate to Company’s (or any of its affiliates’) business, trade secrets, products or services (including, without limitation, all such information relating to corporate opportunities, product specification, compositions, manufacturing and distribution methods and processes, research, financial and sales data, pricing terms, evaluations, opinions, interpretations, acquisitions prospects, the identity of customers or their requirements, the identity of key contacts within the customer’s organizations or within the organization of acquisition prospects, marketing and merchandising techniques, business plans, computer software or programs, computer software and database technologies, prospective names and marks) (collectively, “Confidential Information”) shall be disclosed to Company and are and shall be the sole and exclusive property of Company (or its affiliates). Moreover, all documents, videotapes, written presentations, brochures, drawings, memoranda, notes, records, files, correspondence, manuals, models, specifications, computer programs, E-mail, voice mail, electronic databases, maps, drawings, architectural renditions, models and all other writings or materials of any type embodying any of such information, ideas, concepts, improvements, discoveries, inventions and other similar forms of expression (collectively, “Work Product”) are and shall be the sole and exclusive property of Company (or its affiliates). Upon Executive’s termination of employment with Company, for any reason, Executive promptly shall deliver such Confidential Information and Work Product, and all copies thereof, to Company.
     5.2 Disclosure to Executive . In reliance upon Executive’s representations and agreements in this Agreement, Company has and will disclose to Executive, and will place Executive in a position to have access to and to develop, Confidential Information and Work Product of Company (or its affiliates); and/or has and will entrust Executive with business opportunities of Company (or its affiliates); and/or has and will place Executive in a position to develop business good will on behalf of Company (or its affiliates). Executive agrees to preserve and protect the confidentiality of all Confidential Information or Work Product of Company (or its affiliates).
     5.3 No Unauthorized Use or Disclosure . Executive agrees that he or she will not, at any time during or after Executive’s employment by Company, make any unauthorized disclosure of, and will prevent the removal from Company premises of, Confidential Information or Work Product of Company (or its affiliates), or make any use thereof, except in the carrying out of Executive’s responsibilities during the course of Executive’s employment with Company. Executive shall use commercially reasonable efforts to cause all persons or entities to whom any Confidential Information shall be disclosed by him or her hereunder to observe the terms and conditions set forth herein as though each such person or entity was bound hereby. Executive shall have no obligation hereunder to keep confidential any Confidential Information if and to the extent disclosure thereof is specifically required by law; provided, however, that in the event disclosure is required by applicable law, Executive shall provide Company with prompt notice of such requirement prior to making any such disclosure, so that Company may seek an appropriate
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protective order or otherwise contest such disclosure. At the request of Company at any time, Executive agrees to deliver to Company all Confidential Information that he or she may possess or control. Executive agrees that all Confidential Information of Company (whether now or hereafter existing) conceived, discovered or made by him or her during the period of Executive’s employment by Company exclusively belongs to Company (and not to Executive), and Executive will promptly disclose such Confidential Information to Company and perform all actions reasonably requested by Company to establish and confirm such exclusive ownership. Affiliates of Company shall be third party beneficiaries of Executive’s obligations under this Article 5. As a result of Executive’s employment by Company, Executive may also from time to time have access to, or knowledge of, Confidential Information or Work Product of third parties, such as customers, suppliers, partners, joint venturers, and the like, of Company and its affiliates. Executive also agrees to preserve and protect the confidentiality of such third party Confidential Information and Work Product to the same extent, and on the same basis, as Company’s Confidential Information and Work Product.
     5.4 Ownership by Company . If, during Executive’s employment by Company, Executive creates any work of authorship fixed in any tangible medium of expression that is the subject matter of copyright (such as videotapes, written presentations, or acquisitions, computer programs, E-mail, voice mail, electronic databases, drawings, maps, architectural renditions, models, manuals, brochures, or the like) relating to Company’s business, products, or services, whether such work is created solely by Executive or jointly with others (whether during business hours or otherwise and whether on Company’s premises or otherwise), including any Work Product, Company shall be deemed the author of such work if the work is prepared by Executive in the scope of Executive’s employment; or, if the work is not prepared by Executive within the scope of Executive’s employment but is specially ordered by Company as a contribution to a collective work, as a part of a motion picture or other audiovisual work, as a translation, as a supplementary work, as a compilation, or as an instructional text, then the work shall be considered to be work made for hire and Company shall be the author of the work. If such work is neither prepared by Executive within the scope of Executive’s employment nor a work specially ordered that is deemed to be a work made for hire, then Executive hereby agrees to assign, and by these presents does assign, to Company all of Executive’s worldwide right, title, and interest in and to such work and all rights of copyright therein.
     5.5 Assistance by Executive . During the period of Executive’s employment by Company and thereafter, Executive shall assist Company and its nominee, at any time, in the protection of Company’s (or its affiliates’) worldwide right, title and interest in and to Work Product and the execution of all formal assignment documents requested by Company or its nominee and the execution of all lawful oaths and applications for patents and registration of copyright in the United States and foreign countries.
     5.6 Non-Competition Obligations . Both as part of the consideration for the compensation and benefits to be paid to Executive hereunder; and to protect the trade secrets and Confidential Information of Company and its affiliates that have been or will in the future be disclosed or entrusted to Executive, the business good will of Company and its affiliates that has been and will in the future be developed in Executive, and the business opportunities that have been and will in the future be disclosed or entrusted to Executive by Company and its affiliates; Executive agrees that during the period that Executive is employed by Company and for 12
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months after the date of the termination of Executive’s employment with the Company for any reason, Executive shall not, directly or indirectly for Executive or for others, in the geographic areas and markets where Company conducts any business during Executive’s employment with the Company (as identified on Schedule A attached hereto, and amended by the Company from time to time), as well as any other geographic area or market where Company is conducting any business as of the date of termination of the employment relationship:

 	(i)	 	engage in the business of acquiring, developing, improving, managing, providing services with respect to, operating and disposing of mid-stream energy projects, including pipelines, treatment and processing facilities and gas storage fields or any other business that is competitive with the business conducted by Company;	
 		
 	(ii)	 	render any advice or services to, or otherwise assist, any other person, association, or entity who is engaged, directly or indirectly, with any business that is competitive with the business conducted by Company;	
 		
 	(iii)	 	induce any employee of Company or its affiliates to terminate his or her employment with Company or its affiliates, or hire or assist in the hiring of any such employee by any person, association, or entity not affiliated with Company; or	
 		
 	(iv)	 	request or cause any customer of Company or its affiliates to terminate any business relationship with Company or its affiliates.	
Executive understands that the foregoing restrictions may limit Executive’s ability to engage in certain businesses anywhere in the world during the period provided for above, but acknowledges and represents that the restrictions are both reasonable and necessary to protect Company’s legitimate business interests, and that Executive will receive sufficiently high remuneration and other benefits under this Agreement to compensate for and to justify such restrictions. Notwithstanding the foregoing, in the event that the Executive’s employment is terminated upon expiration of the initial or extended term pursuant to Section 2.1 hereof because either party has provided the notice contemplated in such paragraph, the Board may, in its discretion, release the Executive from the covenants contained in this Section 5.6; provided, however, that in such case, the Executive shall not receive the Severance Amount provided in Section 4.2 hereof.
     5.7 Enforcement and Remedies . Executive acknowledges and agrees that money damages would not be sufficient remedy for any breach of this Article 5 by Executive, and Company or its affiliates shall be entitled to enforce the provisions of this Article 5 by terminating payments then owing to Executive under this Agreement or otherwise, by specific performance and injunctive relief as remedies for such breach or any threatened breach. Such remedies shall not be deemed the exclusive remedies for a breach of this Article 5, but shall be in addition to all remedies available at law or in equity, including, without limitation, the recovery of damages from Executive and Executive’s agents involved in such breach and remedies available to Company pursuant to other agreements with Executive.
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     5.8 Reformation . It is expressly understood and agreed that Company and Executive consider the restrictions contained in this Article 5 to be reasonable and necessary to protect the proprietary information of Company and its affiliates. Nevertheless, if any of the aforesaid restrictions are found by a court having jurisdiction to be unreasonable, or overly broad as to geographic area or time, or otherwise unenforceable, the parties intend for the restrictions therein set forth to be modified by such courts so as to be reasonable and enforceable and, as so modified by the court, to be fully enforced.
ARTICLE 6: NONDISPARAGEMENT
     Executive shall refrain, both during the employment relationship and after the employment relationship terminates, from publishing any oral or written statements about Company, its affiliates, or any of such entities’ officers, employees, agents or representatives that (i) are slanderous, libelous, or defamatory; (ii) disclose private or confidential information about Company, its affiliates, or any of such entities’ business affairs, officers, employees, agents, or representatives; (iii) constitute an intrusion into the seclusion or private lives of the officers, employees, agents, or representatives of Company or its affiliates; (iv) give rise to unreasonable publicity about the private lives of the officers, employees, agents, or representatives of Company or its affiliates; (v) place Company, its affiliates, or any of such entities’ officers, employees, agents, or representatives in a false light before the public; or (vi) constitute a misappropriation of the name or likeness of Company, its affiliates, or any of such entities’ officers, employees, agents, or representatives. A violation or threatened violation of this prohibition may be enjoined by the courts. The rights afforded Company and its affiliates under this provision are in addition to any and all rights and remedies otherwise afforded by law.
     Company agrees that, both during Executive’s employment relationship and after the employment relationship terminates, Company, its affiliates, and such entities’ officers, employees, agents or representatives shall refrain from publishing any oral or written statements about Executive that (i) are slanderous, libelous, or defamatory; (ii) disclose private or confidential information about Executive; (iii) that constitute an intrusion into the seclusion or private life of Executive; (iv) give rise to unreasonable publicity about the private life of Executive; (v) place Executive in a false light before the public; or (vi) constitute a misappropriation of the name or likeness of Executive. A violation or threatened violation of this prohibition may be enjoined by the courts. The rights afforded Executive under this provision are in addition to any and all rights and remedies otherwise afforded by law.
     The nondisparagement obligations of this Article 6 shall not apply to communications with law enforcement or required testimony under law or court process.
ARTICLE 7: MISCELLANEOUS
     7.1 Notices . For purposes of this Agreement, notices and all other communications provided for herein shall be in writing and shall be deemed to have been duly given when personally delivered or when mailed by United States registered or certified mail, return receipt requested, postage prepaid, addressed as follows:
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 	 	If to Company to:	 	American Midstream GP, LLC
1614 15th Street
Suite 300
Denver, CO 80202
Attention: Chairman of the Board	
 	 	 	 	 	
 	 	with a copy to:	 	American Infrastructure MLP Fund, L.P.
950 Tower Lane
Suite 800
Foster City, CA 94404
Attention: Ed Diffendal and Robert B. Hellman, Jr.	
 	 	 	 	 	
 	 	If to Executive to:	 	Brian F. Bierbach
12933 Silver Elk Lane
Littleton, CO 80127	
or to such other address as either party may furnish to the other in writing in accordance herewith, except that notices or changes of address shall be effective only upon receipt.
     7.2 Applicable Law . This Agreement is entered into under, and shall be governed for all purposes by, the laws of the State of Delaware.
     7.3 No Waiver . No failure by either party hereto at any time to give notice of any breach by the other party of, or to require compliance with, any condition or provision of this Agreement shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.
     7.4 Severability . If a court of competent jurisdiction determines that any provision of this Agreement is invalid or unenforceable, then the invalidity or unenforceability of that provision shall not affect the validity or enforceability of any other provision of this Agreement, and all other provisions shall remain in full force and effect.
     7.5 Counterparts . This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same Agreement.
     7.6 Withholding of Taxes and Other Employee Deductions . Company may withhold from any benefits and payments made pursuant to this Agreement or otherwise all federal, state, city and other taxes as may be required pursuant to any law or governmental regulation or ruling and all other normal employee deductions made with respect to Company’s employees generally.
     7.7 Headings . The paragraph headings have been inserted for purposes of convenience and shall not be used for interpretive purposes.
     7.8 Gender and Plurals . Wherever the context so requires, the masculine gender includes the feminine or neuter, and the singular number includes the plural and conversely.
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     7.9 Affiliate . As used in this Agreement, the term “affiliate” shall mean any entity which owns or controls, is owned or controlled by, or is under common ownership or control with, Company.
     7.10 Term . This Agreement has a term co-extensive with the term of employment provided in Article 2. Termination shall not affect any right or obligation of any party which is accrued or vested prior to such termination. The provisions of paragraphs 2.4 and 2.5 and Articles 4, 5, 6, and 7 shall survive any termination of this Agreement.
     7.11 Entire Agreement . Except as provided in (i) the written benefit plans and programs referenced in paragraph 3.4(iii) (and any agreements between Company and Executive that have been executed under such plans and programs) and paragraph 4.7 and (ii) any signed written agreement contemporaneously or hereafter executed by Company and Executive, this Agreement constitutes the entire agreement of the parties with regard to the subject matter hereof, and contains all the covenants, promises, representations, warranties and agreements between the parties with respect to employment of Executive by Company. Without limiting the scope of the preceding sentence, all understandings and agreements preceding the date of execution of this Agreement and relating to the subject matter hereof (other than (A) under the agreements described in clause (i) of the preceding sentence; (B) as provided herein or (C) under the agreements forming and/or operating Company and American Midstream, LP or any investor rights agreement related thereto) are hereby null and void and of no further force and effect. Any modification of this Agreement will be effective only if it is in writing and signed by the party to be charged.
     7.12 Legal Expenses . If Executive incurs legal costs and expenses (including reasonable attorneys’ fees) in any contest relating to rights under this Agreement and prevails in such contest, Company shall reimburse Executive for his or her reasonable legal costs and expenses (including reasonable attorneys’ fees) incurred with respect to such contest.
     7.13 Liability Insurance . Company shall maintain a directors’ and officers’ insurance liability policy throughout the term of this Agreement and shall provide Executive with coverage under such policy on terms not less favorable than provided to other Company directors and officers.
     7.14 Compliance with Section 409A of the Code .
     (i) All references in this Agreement to the termination of Executive’s employment with Company shall mean and shall be deemed to occur if and when a termination of employment that constitutes a “separation from service” within the meaning of Section 409A(a)(2)(A)(i) of the Internal Revenue Code of 1986, as amended (the “Code”), and applicable administrative guidance issued thereunder has occurred.
     (ii) To the extent that any reimbursement or benefit in kind hereunder constituted deferred compensation under Section 409A of the Code, such reimbursement or benefit shall be administered consistently with the following additional requirements as set forth in Treas. Reg. §1.409A-3(i)(1)(iv): (1) Executive’s eligibility for or receipt of benefits or reimbursements in one calendar year will not affect Executive’s eligibility for
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or the amount of benefits or reimbursements in any other calendar year, (2) any reimbursement of eligible expenses will be made on or before the last day of the year following the year in which the expense was incurred, (3) Executive’s right to benefits or reimbursement is not subject to liquidation or exchange for another benefit, and (4) the right to reimbursement of expenses incurred or to the provision of benefits in kind shall terminate ten (10) years from Executive’s termination of employment, if not before.
     (iii) Executive’s right to installment payments, if any, hereunder, shall be treated as the right to receive a series of separate and distinct individual payments for purposes of Section 409A of the Code.
     (iv) Notwithstanding any provision in this Agreement to the contrary, if Executive is a “specified employee” (within the meaning of Section 409A(a)(2)(B)(i) of the Code, and applicable administrative guidance thereunder and determined in accordance with any method selected by Company that is permitted under the regulations issued under Section 409A of the Code), and any amount paid or benefit provided under this Agreement to or on behalf of Executive would be subject to additional taxes under Section 409A of the Code because the timing of such payment is not delayed as provided in Section 409A(a)(2)(B)(i) of the Code and the regulations thereunder, then any such payment or benefit that Executive would otherwise be entitled to during the first six months following the date of Executive’s separation from service (within the meaning of Section 409A(a)(2)(A)(i) of the Code and applicable administrative guidance thereunder) shall be accumulated and paid or provided, as applicable, on the date that is six months plus one day after Executive’s separation from service (or if such date does not fall on a business day of Company, the next following business day of Company), or such earlier date upon which such amount can be paid or provided under Section 409A of the Code without being subject to such additional taxes and interest; provided, however, that Executive shall be entitled to receive the maximum amount permissible under Section 409A of the Code and the applicable administrative guidance thereunder during the six-month period following his or her separation from service that will not result in the imposition of any additional tax or penalties on such amount.
     (v) To the extent that Section 409A of the Code is applicable to this Agreement, the provisions of this Agreement shall be interpreted as necessary to comply with such section and the applicable administrative guidance issued thereunder.
     7.15 Arbitration .
     (i) Company and Executive agree to submit to final and binding arbitration any and all disputes or disagreements concerning the interpretation or application of this Agreement, the termination of this Agreement, or any other aspect of Executive’s employment relationship with Company. Any such dispute or disagreement will be resolved by arbitration in accordance with the National Rules for the Resolution of Employment Disputes of the American Arbitration Association (the “AAA Rules”) before a single arbitrator. Arbitration will take place in Delaware, unless the parties mutually agree to a different location. Company and Executive agree that the decision of the arbitrator will be final and binding on both parties. Any court having jurisdiction may
 13 

 

enter a judgment upon the award rendered by the arbitrator. The costs of the proceedings shall be borne equally by the parties unless the arbitrator orders otherwise.
     (ii) Notwithstanding the provisions of paragraph 7.15(i), (a) Company may, if it so chooses, bring an action in any court of competent jurisdiction for injunctive relief to enforce Executive’s obligations under Articles 5 or 6 hereof, pending a decision by the arbitrator in accordance with paragraph 7.15(i), and (b) Executive may, if he or she so chooses, bring an action in any court of competent jurisdiction for temporary or preliminary injunctive relief to enforce Company’s obligations under Article 6 hereof, pending a decision by the arbitrator in accordance with paragraph 7.15(i).
     7.16 Provisions Regarding Effective Date . As indicated in this Agreement, this Agreement is effective as of the Effective Date, and accordingly in connection therewith the parties agree that the following shall apply:
     (i) This Agreement shall from and after its execution by the parties be an agreement binding upon and enforceable by both Company and Executive subject to the application of the provisions hereof generally being effective as of the Effective Date.
     (ii) The employment of Executive by Company shall continue to be governed by the terms of the Existing Agreement until the Effective Date.
     (iii) In the event that the employment of Executive by Company terminates at any time prior to the Effective Date, such termination shall be governed by the terms of the Existing Agreement and this Agreement shall be null and void and of no force and effect.
     (iv) In the event that the Effective Date does not occur on or before July 31, 2011, this Agreement shall be null and void and of no force and effect and the Existing Agreement shall continue in full force and effect.
Signature page follows.
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      IN WITNESS WHEREOF , the parties hereto have executed this Agreement on the 9th day of June, 2011, to be effective as of the Effective Date.

 	 	American Midstream GP, LLC	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Robert B. Hellman, Jr. 	 	 	
 	 	 	 	 
Robert B. Hellman, Jr.,	 	 	
 	 	 	 	Chairman, Compensation Committee	 	 	
 	 	 	 	 	 	 	
 	 	“EXECUTIVE”	 	 	
 	 	 	 	/s/ Brian F. Bierbach 	 	 	
 	 	 		 	 	 	
 	 	 	 	Brian F. Bierbach	 	 	
Signature Page to Employment Agreement
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SCHEDULE A
NONCOMPETITION GEOGRAPHIC AREAS AND SCOPE
Every State of the United States in which the Company does business on the Executive’s date of termination.
All customers of the Company on the Executive’s date of termination.

Exhibit 10.5
EMPLOYMENT AGREEMENT
     THIS EMPLOYMENT AGREEMENT (“Agreement”) is made by and between American Midstream GP, LLC, a Delaware limited liability company (“Company”), and Marty W. Patterson (“Executive”).
W I T N E S S E T H:
     WHEREAS, Executive is currently employed by Company, which is the general partner of American Midstream Partners, LP (“American Midstream LP”), pursuant to that certain Employment Agreement by and between Executive and Company dated November 2, 2009 (the “Existing Agreement”); and
     WHEREAS, in connection with the initial public offering of the common units of American Midstream LP, Company and Executive desire to amend the Existing Agreement in certain respects and, in connection therewith, the parties desire to enter into this Agreement to replace and supersede the Existing Agreement in its entirety as provided herein;
     NOW, THEREFORE, for and in consideration of the mutual promises, covenants and obligations contained herein, Company and Executive agree as follows:
ARTICLE 1: EMPLOYMENT AND DUTIES
     1.1 Employment; Effective Date . Effective as of, and contingent upon, the closing of the initial public offering of the common units of American Midstream LP (the “Effective Date”), and continuing for the period of time set forth in Article 2 of this Agreement, Executive’s employment by Company shall be subject to the terms and conditions of this Agreement.
     1.2 Positions . Company shall employ Executive in the position of Senior Vice President of Commercial Services reporting to the President and Chief Executive Officer of the Company, or in such other positions as the parties mutually may agree.
     1.3 Duties and Services . Executive agrees to serve in the position referred to in paragraph 1.2 and to perform diligently and to the best of his or her abilities the duties and services appertaining to such office, as well as such additional duties and services appropriate to such office which the parties mutually may agree upon from time to time. Executive’s employment shall also be subject to the policies maintained and established by Company that are of general applicability to Company’s executive employees, as such policies may be amended from time to time, provided that in the event of any inconsistency between such policies and any term of this Agreement, this Agreement shall control.
     1.4 Other Interests . Executive agrees, during the period of his or her employment by Company, to devote substantially all of his or her primary business time, energy and best efforts to the business and affairs of Company and its affiliates and not to engage, directly or indirectly, in any other business or businesses, whether or not similar to that of Company, except with the consent of the Board of Directors of the Company (the “Board”).

 

     1.5 Duty of Loyalty . Executive acknowledges and agrees that Executive owes a fiduciary duty of loyalty to act at all times in the best interests of Company. In keeping with such duty, Executive shall make full disclosure to Company of all business opportunities pertaining to Company’s business and shall not appropriate for Executive’s own benefit business opportunities concerning Company’s business.
ARTICLE 2: TERM AND TERMINATION OF EMPLOYMENT
     2.1 Term . Unless sooner terminated pursuant to other provisions hereof, Company agrees to continue to employ Executive for the period beginning on the Effective Date and ending on the second anniversary of the Effective Date (the “Initial Expiration Date”); provided, however, that beginning on the Initial Expiration Date, and on each anniversary of the Initial Expiration Date thereafter, if this Agreement has not been terminated pursuant to paragraph 2.2 or 2.3, then the term of this Agreement shall automatically be extended for an additional one-year period, unless on or before the date that is 90 days prior to the first day of any such extension period, either party shall give written notice to the other that no such automatic extension shall occur.
     2.2 Company’s Right to Terminate . Notwithstanding the provisions of paragraph 2.1, Company shall have the right to terminate Executive’s employment under this Agreement for any of the following reasons:
     (i) upon Executive’s death;
     (ii) upon Executive’s disability, which shall mean Executive’s becoming incapacitated by accident, sickness, or other circumstances which renders him or her mentally or physically incapable of performing the duties and services required of him or her hereunder for 90 or more days (whether or not consecutive) out of any consecutive 180-day period;
     (iii) for “Cause,” which shall mean Executive has (A) engaged in gross negligence, gross incompetence or willful misconduct in the performance of the duties required of him or her hereunder; (B) refused without proper reason to perform the duties and responsibilities required of him or her hereunder; (C) willfully engaged in conduct that is materially injurious to Company or its affiliates (monetarily or otherwise); (D) committed an act of fraud, embezzlement or willful breach of fiduciary duty to Company or an affiliate (including the unauthorized disclosure of confidential or proprietary material information of Company or an affiliate) or (E) been convicted of (or pleaded no contest to) a crime involving fraud, dishonesty or moral turpitude or any felony; or
     (iv) at any time for any other reason, or for no reason whatsoever, in the sole discretion of the Board.
     2.3 Executive’s Right to Terminate . Notwithstanding the provisions of paragraph 2.1, Executive shall have the right to terminate his or her employment under this Agreement for any of the following reasons:
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     (i) for “Good Reason,” which shall mean, in connection with or based upon a nonconsensual (A) material diminution in Executive’s responsibilities, duties or authority; (B) material diminution in Executive’s base compensation; (C) assignment of Executive to a principal office located beyond a 50-mile radius of Executive’s then current work place, or (D) material breach by Company of any material provision of this Agreement; or
     (ii) at any time for any other reason, or for no reason whatsoever, in the sole discretion of Executive.
     2.4 Notice of Termination . If Company desires to terminate Executive’s employment hereunder at any time prior to expiration of the term of employment as provided in paragraph 2.1, it shall do so by giving a 30-day written notice to Executive that it has elected to terminate Executive’s employment hereunder and stating the effective date and reason for such termination, provided that no such action shall alter or amend any other provisions hereof or rights arising hereunder. If Executive desires to terminate his or her employment hereunder at any time prior to expiration of the term of employment as provided in paragraph 2.1, he or she shall do so by giving a 30-day written notice to Company that he or she has elected to terminate his or her employment hereunder and stating the effective date and reason for such termination, provided that no such action shall alter or amend any other provisions hereof or rights arising hereunder. In the case of any notice by Executive of his or her intent to terminate his or her employment hereunder for Good Reason, Executive shall provide Company with notice of the existence of the condition(s) constituting the Good Reason within 60 days after Executive has actual knowledge of the initial existence of such condition(s) and Company shall have 30 days following Executive’s provision of such notice to remedy such condition(s). If Company remedies the condition(s) constituting the Good Reason within such 30 day period, then Executive’s employment hereunder shall continue and his or her notice of termination shall become void and of no further effect. If Company does not remedy the condition(s) constituting the Good Reason within such 30 day period, Executive’s employment with Company shall terminate on the date that is 31 days following the date of Executive’s notice of termination and Executive shall be entitled to receive the payments and benefits described in paragraph 4.3, if applicable. The notice, remedy rights and termination timing provisions applicable under this paragraph 2.4 in the case of Executive’s election to terminate his or her employment for Good Reason are referred to collectively as the “Good Reason Termination Procedure.”
     2.5 Deemed Resignations . Any termination of Executive’s employment shall constitute an automatic resignation of Executive as an officer of Company and each affiliate of Company, an automatic resignation of Executive from the Board and from the board of directors or similar governing body of any affiliate of Company, and an automatic resignation from the board of directors or similar governing body of any corporation, limited liability company or other entity in which Company or any affiliate holds an equity interest and with respect to which board or similar governing body Executive serves as Company’s or such affiliate’s designee or other representative.
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ARTICLE 3: COMPENSATION AND BENEFITS
     3.1 Base Salary . During the period of this Agreement, Executive shall receive an annual base salary of $220,000. Executive’s annual base salary shall be reviewed by the Compensation Committee of the Board (“Compensation Committee”) on an annual basis, and, in the sole discretion of the Compensation Committee, such annual base salary may be increased, but not decreased (except for a decrease that is consistent with reductions taken generally by other executives of Company), effective as of any date determined by the Compensation Committee. Executive’s annual base salary shall be paid in equal installments in accordance with Company’s standard policy regarding payment of compensation to executives, but no less frequently than monthly.
     3.2 Bonus Opportunity . During the period of this Agreement, Executive shall be provided with the opportunity to earn and receive an annual incentive performance bonus payable in cash in an amount equal to $130,000 (pro-rated for any period of less than 12 months), 20 percent of which shall be conditioned and determined on the attainment of personal performance goals and 80 percent of which shall be conditioned and determined on the attainment of organizational performance goals, in each case as set by, and based on performance criteria established by, the Compensation Committee. The Compensation Committee shall notify Executive of the bonus opportunity by no later than the end of the first 90 days of each annual performance period and shall, at that time, set and communicate to Executive the personal and organizational performance goals on which the bonus (and each component thereof) shall be conditioned and the criteria on which the attainment of such goals and the resulting bonus, if any, shall be determined. All determinations with respect to the bonus hereunder shall be made by the Compensation Committee and its determinations shall be final and binding.
     3.3 Incentive Compensation . Executive shall be eligible to receive awards under the Company’s Long Term Incentive Plan, as determined by the Compensation Committee.
     3.4 Other Perquisites . During his or her employment hereunder, Executive shall be afforded the following benefits as incidences of his or her employment:
     (i) Business and Entertainment Expenses — Subject to Company’s standard policies and procedures with respect to expense reimbursement as applied to its executive employees generally, Company shall reimburse Executive for, or pay on behalf of Executive, reasonable and appropriate expenses incurred by Executive for business related purposes, including dues and fees to industry and professional organizations and costs of entertainment and business development.
     (ii) Vacation — During his or her employment hereunder, Executive shall be entitled to four weeks of paid vacation each calendar year (pro-rated for the calendar year containing the Effective Date) and to all holidays provided to executives of Company generally.
     (iii) Other Company Benefits — Executive and, to the extent applicable, Executive’s spouse, dependents and beneficiaries, shall be allowed to participate in, and in accordance with the terms of, all benefits, plans and programs, including
 4 

 

improvements or modifications of the same, which are now, or may hereafter be, available to other executive employees of Company. Such benefits, plans and programs shall include, without limitation, any profit sharing plan, thrift plan, health insurance or health care plan, life insurance, disability insurance, pension plan, supplemental retirement plan, vacation and sick leave plan, and the like which may be maintained by Company. Company shall not, however, by reason of this paragraph be obligated to institute, maintain, or refrain from changing, amending, or discontinuing, any such benefit plan or program, so long as such changes are similarly applicable to executive employees generally.
ARTICLE 4: EFFECT OF TERMINATION ON COMPENSATION
     4.1 Payment of Accrued Obligations . Upon termination of Executive’s employment hereunder for any reason and by any means, Executive shall be entitled to, and shall be paid, any annual base salary that is accrued and unpaid as of the date of such termination, which shall be paid on the next regularly scheduled pay day for the payment of Executive’s annual base salary, and any expense reimbursement payable in accordance with paragraph 3.4(i) for reimbursable expenses incurred by Executive prior to the date of such termination, which shall be paid at the time and in the manner provided by Company’s reimbursement policy and in accordance with this Agreement. Other than the foregoing amounts and any Severance Pay pursuant to paragraph 4.3, all compensation and benefits to Executive hereunder shall terminate contemporaneously with the termination of Executive’s employment. Any other benefits to which Executive shall be entitled shall be governed by the plan, policy or agreement providing for such benefits and applicable law.
     4.2 Other Terminations . If Executive’s employment hereunder shall terminate at any time (including, but not limited to, upon or following a change of control of the Company), (i) upon expiration of the term provided in paragraph 2.1 hereof because either party has provided the notice contemplated in such paragraph (except as provided in Section 5.6 hereof), (ii) by Executive for Good Reason and in accordance with the Good Reason Termination Procedure or (iii) by Company other than in any event or circumstance described in paragraph 2.2(i), 2.2(ii), or 2.2(iii), then, subject to paragraph 4.4, Company shall pay Executive an amount equal one times the sum of Executive’s annual base salary at the rate in effect under paragraph 3.1 on the date of such termination, plus one times the amount, if any, paid to Executive under paragraph 3.2 for the calendar year ending immediately prior to the date of such termination of Executive’s employment (the “Severance Amount”), which shall be paid as provided in paragraph 4.3.
     4.3 Severance Payments . Subject to paragraph 4.4 below, the Severance Amount, if any shall be due, shall be divided into amounts (each, a “Severance Payment”) to be paid in installments. The amount of each Severance Payment shall be equal to the Severance Amount divided by the number of regular pay days scheduled (in accordance with Company’s regular payroll practices) to occur between the date of Executive’s termination of employment (“Termination Date”) and the first anniversary of the Termination Date (“Scheduled Paydays”). If any Severance Amount would otherwise be owed under this Agreement, but the requirements of paragraph 4.4 are not satisfied, then no Severance Amount and no amount in lieu of the Severance Amount, shall be owed or paid. If the requirements of paragraph 4.4 are satisfied, then, subject to paragraph 7.14(iv), a portion of the Severance Amount equal to the product of
 5 

 

one Severance Payment and the number of Scheduled Paydays during the 60-day period beginning on the Termination Date shall be paid in a lump sum amount on the 60 th day following the Termination Date, and the remainder of the Severance Amount shall be paid in regular installments, each one equal to the amount of one Severance Payment, with the first such payment being due on due on the Scheduled Payday immediately following the 60 th day after the Termination Date, with like payments on each Scheduled Payday thereafter until the remaining Severance Amount is paid in full.
     4.4 Release and Full Settlement . Anything to the contrary herein notwithstanding, as a condition to the receipt of any portion of the Severance Amount, Executive shall execute a release, in the form established by the Board, releasing the Board, Company, and Company’s parent corporation, subsidiaries, affiliates, and their respective shareholders, partners, officers, directors, employees, attorneys and agents from any and all claims and from any and all causes of action of any kind or character including, but not limited to, all claims or causes of action arising out of Executive’s employment with Company or its affiliates or the termination of such employment, but excluding all claims to vested benefits and payments Executive may have under any compensation or benefit plan, program or arrangement, including this Agreement. Executive shall provide such release to Company no later than 50 days after the Termination Date and, as a condition to Company’s obligation to pay all or any portion of the Severance Amount, Executive shall not revoke such release. The performance of Company’s obligations hereunder shall constitute full settlement of all such claims and causes of action.
     4.5 No Duty to Mitigate Losses . Executive shall have no duty to find new employment following the termination of his or her employment under circumstances which require Company to pay any amount to Executive pursuant to this Article 4. Any salary or remuneration received by Executive from a third party for the providing of personal services (whether by employment or by functioning as an independent contractor) following the termination of his or her employment under circumstances pursuant to which this Article 4 apply shall not reduce Company’s obligation to make a payment to Executive (or the amount of such payment) pursuant to the terms of this Article 4.
     4.6 Liquidated Damages . In light of the difficulties in estimating the damages for an early termination of Executive’s employment under this Agreement, Company and Executive hereby agree that the payments and benefits, if any, to be received by Executive pursuant to this Article 4 shall be received by Executive as liquidated damages.
     4.7 Other Benefits . This Agreement governs the rights and obligations of Executive and Company with respect to Executive’s base salary, bonus and certain perquisites of employment. Except as expressly provided herein, Executive’s rights and obligations both during the term of his or her employment and thereafter with respect to his or her ownership rights in Company and American Midstream LP, and other benefits under the plans and programs maintained by Company shall be governed by the terms (which are not, and are not required to be, affected, altered or amended) of the separate agreements, plans and the other documents and instruments governing such matters.
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ARTICLE 5: PROTECTION OF CONFIDENTIAL INFORMATION
     5.1 Disclosure to and Property of Company . All information, designs, ideas, concepts, improvements, product developments, discoveries and inventions, whether patentable or not, that are conceived, made, developed or acquired by Executive, individually or in conjunction with others, during the period of Executive’s employment by Company (whether during business hours or otherwise and whether on Company’s premises or otherwise) that relate to Company’s (or any of its affiliates’) business, trade secrets, products or services (including, without limitation, all such information relating to corporate opportunities, product specification, compositions, manufacturing and distribution methods and processes, research, financial and sales data, pricing terms, evaluations, opinions, interpretations, acquisitions prospects, the identity of customers or their requirements, the identity of key contacts within the customer’s organizations or within the organization of acquisition prospects, marketing and merchandising techniques, business plans, computer software or programs, computer software and database technologies, prospective names and marks) (collectively, “Confidential Information”) shall be disclosed to Company and are and shall be the sole and exclusive property of Company (or its affiliates). Moreover, all documents, videotapes, written presentations, brochures, drawings, memoranda, notes, records, files, correspondence, manuals, models, specifications, computer programs, E-mail, voice mail, electronic databases, maps, drawings, architectural renditions, models and all other writings or materials of any type embodying any of such information, ideas, concepts, improvements, discoveries, inventions and other similar forms of expression (collectively, “Work Product”) are and shall be the sole and exclusive property of Company (or its affiliates). Upon Executive’s termination of employment with Company, for any reason, Executive promptly shall deliver such Confidential Information and Work Product, and all copies thereof, to Company.
     5.2 Disclosure to Executive . In reliance upon Executive’s representations and agreements in this Agreement, Company has and will disclose to Executive, and will place Executive in a position to have access to and to develop, Confidential Information and Work Product of Company (or its affiliates); and/or has and will entrust Executive with business opportunities of Company (or its affiliates); and/or has and will place Executive in a position to develop business good will on behalf of Company (or its affiliates). Executive agrees to preserve and protect the confidentiality of all Confidential Information or Work Product of Company (or its affiliates).
     5.3 No Unauthorized Use or Disclosure . Executive agrees that he or she will not, at any time during or after Executive’s employment by Company, make any unauthorized disclosure of, and will prevent the removal from Company premises of, Confidential Information or Work Product of Company (or its affiliates), or make any use thereof, except in the carrying out of Executive’s responsibilities during the course of Executive’s employment with Company. Executive shall use commercially reasonable efforts to cause all persons or entities to whom any Confidential Information shall be disclosed by him or her hereunder to observe the terms and conditions set forth herein as though each such person or entity was bound hereby. Executive shall have no obligation hereunder to keep confidential any Confidential Information if and to the extent disclosure thereof is specifically required by law; provided, however, that in the event disclosure is required by applicable law, Executive shall provide Company with prompt notice of such requirement prior to making any such disclosure, so that Company may seek an appropriate
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protective order or otherwise contest such disclosure. At the request of Company at any time, Executive agrees to deliver to Company all Confidential Information that he or she may possess or control. Executive agrees that all Confidential Information of Company (whether now or hereafter existing) conceived, discovered or made by him or her during the period of Executive’s employment by Company exclusively belongs to Company (and not to Executive), and Executive will promptly disclose such Confidential Information to Company and perform all actions reasonably requested by Company to establish and confirm such exclusive ownership. Affiliates of Company shall be third party beneficiaries of Executive’s obligations under this Article 5. As a result of Executive’s employment by Company, Executive may also from time to time have access to, or knowledge of, Confidential Information or Work Product of third parties, such as customers, suppliers, partners, joint venturers, and the like, of Company and its affiliates. Executive also agrees to preserve and protect the confidentiality of such third party Confidential Information and Work Product to the same extent, and on the same basis, as Company’s Confidential Information and Work Product.
     5.4 Ownership by Company . If, during Executive’s employment by Company, Executive creates any work of authorship fixed in any tangible medium of expression that is the subject matter of copyright (such as videotapes, written presentations, or acquisitions, computer programs, E-mail, voice mail, electronic databases, drawings, maps, architectural renditions, models, manuals, brochures, or the like) relating to Company’s business, products, or services, whether such work is created solely by Executive or jointly with others (whether during business hours or otherwise and whether on Company’s premises or otherwise), including any Work Product, Company shall be deemed the author of such work if the work is prepared by Executive in the scope of Executive’s employment; or, if the work is not prepared by Executive within the scope of Executive’s employment but is specially ordered by Company as a contribution to a collective work, as a part of a motion picture or other audiovisual work, as a translation, as a supplementary work, as a compilation, or as an instructional text, then the work shall be considered to be work made for hire and Company shall be the author of the work. If such work is neither prepared by Executive within the scope of Executive’s employment nor a work specially ordered that is deemed to be a work made for hire, then Executive hereby agrees to assign, and by these presents does assign, to Company all of Executive’s worldwide right, title, and interest in and to such work and all rights of copyright therein.
     5.5 Assistance by Executive . During the period of Executive’s employment by Company and thereafter, Executive shall assist Company and its nominee, at any time, in the protection of Company’s (or its affiliates’) worldwide right, title and interest in and to Work Product and the execution of all formal assignment documents requested by Company or its nominee and the execution of all lawful oaths and applications for patents and registration of copyright in the United States and foreign countries.
     5.6 Non-Competition Obligations . Both as part of the consideration for the compensation and benefits to be paid to Executive hereunder; and to protect the trade secrets and Confidential Information of Company and its affiliates that have been or will in the future be disclosed or entrusted to Executive, the business good will of Company and its affiliates that has been and will in the future be developed in Executive, and the business opportunities that have been and will in the future be disclosed or entrusted to Executive by Company and its affiliates; Executive agrees that during the period that Executive is employed by Company and for 12
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months after the date of the termination of Executive’s employment with the Company for any reason, Executive shall not, directly or indirectly for Executive or for others, in the geographic areas and markets where Company conducts any business during Executive’s employment with the Company (as identified on Schedule A attached hereto, and amended by the Company from time to time), as well as any other geographic area or market where Company is conducting any business as of the date of termination of the employment relationship:

 	(i)	 	engage in the business of acquiring, developing, improving, managing, providing services with respect to, operating and disposing of mid-stream energy projects, including pipelines, treatment and processing facilities and gas storage fields or any other business that is competitive with the business conducted by Company;	
 		
 	(ii)	 	render any advice or services to, or otherwise assist, any other person, association, or entity who is engaged, directly or indirectly, with any business that is competitive with the business conducted by Company;	
 		
 	(iii)	 	induce any employee of Company or its affiliates to terminate his or her employment with Company or its affiliates, or hire or assist in the hiring of any such employee by any person, association, or entity not affiliated with Company; or	
 		
 	(iv)	 	request or cause any customer of Company or its affiliates to terminate any business relationship with Company or its affiliates.	
Executive understands that the foregoing restrictions may limit Executive’s ability to engage in certain businesses anywhere in the world during the period provided for above, but acknowledges and represents that the restrictions are both reasonable and necessary to protect Company’s legitimate business interests, and that Executive will receive sufficiently high remuneration and other benefits under this Agreement to compensate for and to justify such restrictions. Notwithstanding the foregoing, in the event that the Executive’s employment is terminated upon expiration of the initial or extended term pursuant to Section 2.1 hereof because either party has provided the notice contemplated in such paragraph, the Board may, in its discretion, release the Executive from the covenants contained in this Section 5.6; provided, however, that in such case, the Executive shall not receive the Severance Amount provided in Section 4.2 hereof.
     5.7 Enforcement and Remedies . Executive acknowledges and agrees that money damages would not be sufficient remedy for any breach of this Article 5 by Executive, and Company or its affiliates shall be entitled to enforce the provisions of this Article 5 by terminating payments then owing to Executive under this Agreement or otherwise, by specific performance and injunctive relief as remedies for such breach or any threatened breach. Such remedies shall not be deemed the exclusive remedies for a breach of this Article 5, but shall be in addition to all remedies available at law or in equity, including, without limitation, the recovery of damages from Executive and Executive’s agents involved in such breach and remedies available to Company pursuant to other agreements with Executive.
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     5.8 Reformation . It is expressly understood and agreed that Company and Executive consider the restrictions contained in this Article 5 to be reasonable and necessary to protect the proprietary information of Company and its affiliates. Nevertheless, if any of the aforesaid restrictions are found by a court having jurisdiction to be unreasonable, or overly broad as to geographic area or time, or otherwise unenforceable, the parties intend for the restrictions therein set forth to be modified by such courts so as to be reasonable and enforceable and, as so modified by the court, to be fully enforced.
ARTICLE 6: NONDISPARAGEMENT
     Executive shall refrain, both during the employment relationship and after the employment relationship terminates, from publishing any oral or written statements about Company, its affiliates, or any of such entities’ officers, employees, agents or representatives that (i) are slanderous, libelous, or defamatory; (ii) disclose private or confidential information about Company, its affiliates, or any of such entities’ business affairs, officers, employees, agents, or representatives; (iii) constitute an intrusion into the seclusion or private lives of the officers, employees, agents, or representatives of Company or its affiliates; (iv) give rise to unreasonable publicity about the private lives of the officers, employees, agents, or representatives of Company or its affiliates; (v) place Company, its affiliates, or any of such entities’ officers, employees, agents, or representatives in a false light before the public; or (vi) constitute a misappropriation of the name or likeness of Company, its affiliates, or any of such entities’ officers, employees, agents, or representatives. A violation or threatened violation of this prohibition may be enjoined by the courts. The rights afforded Company and its affiliates under this provision are in addition to any and all rights and remedies otherwise afforded by law.
     Company agrees that, both during Executive’s employment relationship and after the employment relationship terminates, Company, its affiliates, and such entities’ officers, employees, agents or representatives shall refrain from publishing any oral or written statements about Executive that (i) are slanderous, libelous, or defamatory; (ii) disclose private or confidential information about Executive; (iii) that constitute an intrusion into the seclusion or private life of Executive; (iv) give rise to unreasonable publicity about the private life of Executive; (v) place Executive in a false light before the public; or (vi) constitute a misappropriation of the name or likeness of Executive. A violation or threatened violation of this prohibition may be enjoined by the courts. The rights afforded Executive under this provision are in addition to any and all rights and remedies otherwise afforded by law.
     The nondisparagement obligations of this Article 6 shall not apply to communications with law enforcement or required testimony under law or court process.
ARTICLE 7: MISCELLANEOUS
     7.1 Notices . For purposes of this Agreement, notices and all other communications provided for herein shall be in writing and shall be deemed to have been duly given when personally delivered or when mailed by United States registered or certified mail, return receipt requested, postage prepaid, addressed as follows:
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If to Company to:	 	American Midstream GP, LLC	
 	 	1614 15th Street	
 	 	Suite 300	
 	 	Denver, CO 80202	
 	 	Attention: Chairman of the Board	
 	 	 	
with a copy to:	 	American Infrastructure MLP Fund, L.P.	
 	 	950 Tower Lane	
 	 	Suite 800	
 	 	Foster City, CA 94404	
 	 	Attention: Ed Diffendal and Robert B. Hellman, Jr.	
 	 	 	
If to Executive to:	 	Marty W. Patterson	
 	 	13803 Frio Springs Court	
 	 	Cypress, Texas 77429	
or to such other address as either party may furnish to the other in writing in accordance herewith, except that notices or changes of address shall be effective only upon receipt.
     7.2 Applicable Law . This Agreement is entered into under, and shall be governed for all purposes by, the laws of the State of Delaware.
     7.3 No Waiver . No failure by either party hereto at any time to give notice of any breach by the other party of, or to require compliance with, any condition or provision of this Agreement shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.
     7.4 Severability . If a court of competent jurisdiction determines that any provision of this Agreement is invalid or unenforceable, then the invalidity or unenforceability of that provision shall not affect the validity or enforceability of any other provision of this Agreement, and all other provisions shall remain in full force and effect.
     7.5 Counterparts . This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same Agreement.
     7.6 Withholding of Taxes and Other Employee Deductions . Company may withhold from any benefits and payments made pursuant to this Agreement or otherwise all federal, state, city and other taxes as may be required pursuant to any law or governmental regulation or ruling and all other normal employee deductions made with respect to Company’s employees generally.
     7.7 Headings . The paragraph headings have been inserted for purposes of convenience and shall not be used for interpretive purposes.
     7.8 Gender and Plurals . Wherever the context so requires, the masculine gender includes the feminine or neuter, and the singular number includes the plural and conversely.
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     7.9 Affiliate . As used in this Agreement, the term “affiliate” shall mean any entity which owns or controls, is owned or controlled by, or is under common ownership or control with, Company.
     7.10 Term . This Agreement has a term co-extensive with the term of employment provided in Article 2. Termination shall not affect any right or obligation of any party which is accrued or vested prior to such termination. The provisions of paragraphs 2.4 and 2.5 and Articles 4, 5, 6, and 7 shall survive any termination of this Agreement.
     7.11 Entire Agreement . Except as provided in (i) the written benefit plans and programs referenced in paragraph 3.4(iii) (and any agreements between Company and Executive that have been executed under such plans and programs) and paragraph 4.7 and (ii) any signed written agreement contemporaneously or hereafter executed by Company and Executive, this Agreement constitutes the entire agreement of the parties with regard to the subject matter hereof, and contains all the covenants, promises, representations, warranties and agreements between the parties with respect to employment of Executive by Company. Without limiting the scope of the preceding sentence, all understandings and agreements preceding the date of execution of this Agreement and relating to the subject matter hereof (other than (A) under the agreements described in clause (i) of the preceding sentence; (B) as provided herein or (C) under the agreements forming and/or operating Company and American Midstream, LP or any investor rights agreement related thereto) are hereby null and void and of no further force and effect. Any modification of this Agreement will be effective only if it is in writing and signed by the party to be charged.
     7.12 Legal Expenses . If Executive incurs legal costs and expenses (including reasonable attorneys’ fees) in any contest relating to rights under this Agreement and prevails in such contest, Company shall reimburse Executive for his or her reasonable legal costs and expenses (including reasonable attorneys’ fees) incurred with respect to such contest.
     7.13 Liability Insurance . Company shall maintain a directors’ and officers’ insurance liability policy throughout the term of this Agreement and shall provide Executive with coverage under such policy on terms not less favorable than provided to other Company directors and officers.
     7.14 Compliance with Section 409A of the Code .
     (i) All references in this Agreement to the termination of Executive’s employment with Company shall mean and shall be deemed to occur if and when a termination of employment that constitutes a “separation from service” within the meaning of Section 409A(a)(2)(A)(i) of the Internal Revenue Code of 1986, as amended (the “Code”), and applicable administrative guidance issued thereunder has occurred.
     (ii) To the extent that any reimbursement or benefit in kind hereunder constituted deferred compensation under Section 409A of the Code, such reimbursement or benefit shall be administered consistently with the following additional requirements as set forth in Treas. Reg. §1.409A-3(i)(1)(iv): (1) Executive’s eligibility for or receipt of benefits or reimbursements in one calendar year will not affect Executive’s eligibility for
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or the amount of benefits or reimbursements in any other calendar year, (2) any reimbursement of eligible expenses will be made on or before the last day of the year following the year in which the expense was incurred, (3) Executive’s right to benefits or reimbursement is not subject to liquidation or exchange for another benefit, and (4) the right to reimbursement of expenses incurred or to the provision of benefits in kind shall terminate ten (10) years from Executive’s termination of employment, if not before.
     (iii) Executive’s right to installment payments, if any, hereunder, shall be treated as the right to receive a series of separate and distinct individual payments for purposes of Section 409A of the Code.
     (iv) Notwithstanding any provision in this Agreement to the contrary, if Executive is a “specified employee” (within the meaning of Section 409A(a)(2)(B)(i) of the Code, and applicable administrative guidance thereunder and determined in accordance with any method selected by Company that is permitted under the regulations issued under Section 409A of the Code), and any amount paid or benefit provided under this Agreement to or on behalf of Executive would be subject to additional taxes under Section 409A of the Code because the timing of such payment is not delayed as provided in Section 409A(a)(2)(B)(i) of the Code and the regulations thereunder, then any such payment or benefit that Executive would otherwise be entitled to during the first six months following the date of Executive’s separation from service (within the meaning of Section 409A(a)(2)(A)(i) of the Code and applicable administrative guidance thereunder) shall be accumulated and paid or provided, as applicable, on the date that is six months plus one day after Executive’s separation from service (or if such date does not fall on a business day of Company, the next following business day of Company), or such earlier date upon which such amount can be paid or provided under Section 409A of the Code without being subject to such additional taxes and interest; provided, however, that Executive shall be entitled to receive the maximum amount permissible under Section 409A of the Code and the applicable administrative guidance thereunder during the six-month period following his or her separation from service that will not result in the imposition of any additional tax or penalties on such amount.
     (v) To the extent that Section 409A of the Code is applicable to this Agreement, the provisions of this Agreement shall be interpreted as necessary to comply with such section and the applicable administrative guidance issued thereunder.
     7.15 Arbitration .
     (i) Company and Executive agree to submit to final and binding arbitration any and all disputes or disagreements concerning the interpretation or application of this Agreement, the termination of this Agreement, or any other aspect of Executive’s employment relationship with Company. Any such dispute or disagreement will be resolved by arbitration in accordance with the National Rules for the Resolution of Employment Disputes of the American Arbitration Association (the “AAA Rules”) before a single arbitrator. Arbitration will take place in Delaware, unless the parties mutually agree to a different location. Company and Executive agree that the decision of the arbitrator will be final and binding on both parties. Any court having jurisdiction may
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enter a judgment upon the award rendered by the arbitrator. The costs of the proceedings shall be borne equally by the parties unless the arbitrator orders otherwise.
     (ii) Notwithstanding the provisions of paragraph 7.15(i), (a) Company may, if it so chooses, bring an action in any court of competent jurisdiction for injunctive relief to enforce Executive’s obligations under Articles 5 or 6 hereof, pending a decision by the arbitrator in accordance with paragraph 7.15(i), and (b) Executive may, if he or she so chooses, bring an action in any court of competent jurisdiction for temporary or preliminary injunctive relief to enforce Company’s obligations under Article 6 hereof, pending a decision by the arbitrator in accordance with paragraph 7.15(i).
     7.16 Provisions Regarding Effective Date . As indicated in this Agreement, this Agreement is effective as of the Effective Date, and accordingly in connection therewith the parties agree that the following shall apply:
     (i) This Agreement shall from and after its execution by the parties be an agreement binding upon and enforceable by both Company and Executive subject to the application of the provisions hereof generally being effective as of the Effective Date.
     (ii) The employment of Executive by Company shall continue to be governed by the terms of the Existing Agreement until the Effective Date.
     (iii) In the event that the employment of Executive by Company terminates at any time prior to the Effective Date, such termination shall be governed by the terms of the Existing Agreement and this Agreement shall be null and void and of no force and effect.
     (iv) In the event that the Effective Date does not occur on or before July 31, 2011, this Agreement shall be null and void and of no force and effect and the Existing Agreement shall continue in full force and effect.
Signature page follows.
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      IN WITNESS WHEREOF , the parties hereto have executed this Agreement on the 9th day of June, 2011, to be effective as of the Effective Date.
 	 	 	 	 	
 	American Midstream GP, LLC
 	 	
 	By:  	/s/ Robert B. Hellman, Jr. 	 	
 	 	Robert B. Hellman, Jr., 	 	
 	 	Chairman, Compensation Committee 	 	
 	
 	“EXECUTIVE”
 	 	
 	 	/s/ Marty W. Patterson  	 	
 	 	Marty W. Patterson 	 	

Signature Page to Employment Agreement

 

SCHEDULE A
NONCOMPETITION GEOGRAPHIC AREAS AND SCOPE
Every State of the United States in which the Company does business on the Executive’s date of termination.
All customers of the Company on the Executive’s date of termination.

Exhibit 10.6
EMPLOYMENT AGREEMENT
     THIS EMPLOYMENT AGREEMENT (“Agreement”) is made by and between American Midstream GP, LLC, a Delaware limited liability company (“Company”), and John J. Connor II (“Executive”).
W I T N E S S E T H:
     WHEREAS, Executive is currently employed by Company, which is the general partner of American Midstream Partners, LP (“American Midstream LP”), pursuant to that certain Employment Agreement by and between Executive and Company dated November 2, 2009 (the “Existing Agreement”); and
     WHEREAS, in connection with the initial public offering of the common units of American Midstream LP, Company and Executive desire to amend the Existing Agreement in certain respects and, in connection therewith, the parties desire to enter into this Agreement to replace and supersede the Existing Agreement in its entirety as provided herein;
     NOW, THEREFORE, for and in consideration of the mutual promises, covenants and obligations contained herein, Company and Executive agree as follows:
ARTICLE 1: EMPLOYMENT AND DUTIES
     1.1 Employment; Effective Date . Effective as of, and contingent upon, the closing of the initial public offering of the common units of American Midstream LP (the “Effective Date”), and continuing for the period of time set forth in Article 2 of this Agreement, Executive’s employment by Company shall be subject to the terms and conditions of this Agreement.
     1.2 Positions . Company shall employ Executive in the position of Senior Vice President of Operations and Engineering reporting to the President and Chief Executive Officer of the Company, or in such other positions as the parties mutually may agree.
     1.3 Duties and Services . Executive agrees to serve in the position referred to in paragraph 1.2 and to perform diligently and to the best of his or her abilities the duties and services appertaining to such office, as well as such additional duties and services appropriate to such office which the parties mutually may agree upon from time to time. Executive’s employment shall also be subject to the policies maintained and established by Company that are of general applicability to Company’s executive employees, as such policies may be amended from time to time, provided that in the event of any inconsistency between such policies and any term of this Agreement, this Agreement shall control.
     1.4 Other Interests . Executive agrees, during the period of his or her employment by Company, to devote substantially all of his or her primary business time, energy and best efforts to the business and affairs of Company and its affiliates and not to engage, directly or indirectly, in any other business or businesses, whether or not similar to that of Company, except with the consent of the Board of Directors of the Company (the “Board”).
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     1.5 Duty of Loyalty . Executive acknowledges and agrees that Executive owes a fiduciary duty of loyalty to act at all times in the best interests of Company. In keeping with such duty, Executive shall make full disclosure to Company of all business opportunities pertaining to Company’s business and shall not appropriate for Executive’s own benefit business opportunities concerning Company’s business.
ARTICLE 2: TERM AND TERMINATION OF EMPLOYMENT
     2.1 Term . Unless sooner terminated pursuant to other provisions hereof, Company agrees to continue to employ Executive for the period beginning on the Effective Date and ending on the second anniversary of the Effective Date (the “Initial Expiration Date”); provided, however, that beginning on the Initial Expiration Date, and on each anniversary of the Initial Expiration Date thereafter, if this Agreement has not been terminated pursuant to paragraph 2.2 or 2.3, then the term of this Agreement shall automatically be extended for an additional one-year period, unless on or before the date that is 90 days prior to the first day of any such extension period, either party shall give written notice to the other that no such automatic extension shall occur.
     2.2 Company’s Right to Terminate . Notwithstanding the provisions of paragraph 2.1, Company shall have the right to terminate Executive’s employment under this Agreement for any of the following reasons:
     (i) upon Executive’s death;
     (ii) upon Executive’s disability, which shall mean Executive’s becoming incapacitated by accident, sickness, or other circumstances which renders him or her mentally or physically incapable of performing the duties and services required of him or her hereunder for 90 or more days (whether or not consecutive) out of any consecutive 180-day period;
     (iii) for “Cause,” which shall mean Executive has (A) engaged in gross negligence, gross incompetence or willful misconduct in the performance of the duties required of him or her hereunder; (B) refused without proper reason to perform the duties and responsibilities required of him or her hereunder; (C) willfully engaged in conduct that is materially injurious to Company or its affiliates (monetarily or otherwise); (D) committed an act of fraud, embezzlement or willful breach of fiduciary duty to Company or an affiliate (including the unauthorized disclosure of confidential or proprietary material information of Company or an affiliate) or (E) been convicted of (or pleaded no contest to) a crime involving fraud, dishonesty or moral turpitude or any felony; or
     (iv) at any time for any other reason, or for no reason whatsoever, in the sole discretion of the Board.
     2.3 Executive’s Right to Terminate . Notwithstanding the provisions of paragraph 2.1, Executive shall have the right to terminate his or her employment under this Agreement for any of the following reasons:
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     (i) for “Good Reason,” which shall mean, in connection with or based upon a nonconsensual (A) material diminution in Executive’s responsibilities, duties or authority; (B) material diminution in Executive’s base compensation; (C) assignment of Executive to a principal office located beyond a 50-mile radius of Executive’s then current work place, or (D) material breach by Company of any material provision of this Agreement; or
     (ii) at any time for any other reason, or for no reason whatsoever, in the sole discretion of Executive.
     2.4 Notice of Termination . If Company desires to terminate Executive’s employment hereunder at any time prior to expiration of the term of employment as provided in paragraph 2.1, it shall do so by giving a 30-day written notice to Executive that it has elected to terminate Executive’s employment hereunder and stating the effective date and reason for such termination, provided that no such action shall alter or amend any other provisions hereof or rights arising hereunder. If Executive desires to terminate his or her employment hereunder at any time prior to expiration of the term of employment as provided in paragraph 2.1, he or she shall do so by giving a 30-day written notice to Company that he or she has elected to terminate his or her employment hereunder and stating the effective date and reason for such termination, provided that no such action shall alter or amend any other provisions hereof or rights arising hereunder. In the case of any notice by Executive of his or her intent to terminate his or her employment hereunder for Good Reason, Executive shall provide Company with notice of the existence of the condition(s) constituting the Good Reason within 60 days after Executive has actual knowledge of the initial existence of such condition(s) and Company shall have 30 days following Executive’s provision of such notice to remedy such condition(s). If Company remedies the condition(s) constituting the Good Reason within such 30 day period, then Executive’s employment hereunder shall continue and his or her notice of termination shall become void and of no further effect. If Company does not remedy the condition(s) constituting the Good Reason within such 30 day period, Executive’s employment with Company shall terminate on the date that is 31 days following the date of Executive’s notice of termination and Executive shall be entitled to receive the payments and benefits described in paragraph 4.3, if applicable. The notice, remedy rights and termination timing provisions applicable under this paragraph 2.4 in the case of Executive’s election to terminate his or her employment for Good Reason are referred to collectively as the “Good Reason Termination Procedure.”
     2.5 Deemed Resignations . Any termination of Executive’s employment shall constitute an automatic resignation of Executive as an officer of Company and each affiliate of Company, an automatic resignation of Executive from the Board and from the board of directors or similar governing body of any affiliate of Company, and an automatic resignation from the board of directors or similar governing body of any corporation, limited liability company or other entity in which Company or any affiliate holds an equity interest and with respect to which board or similar governing body Executive serves as Company’s or such affiliate’s designee or other representative.
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ARTICLE 3: COMPENSATION AND BENEFITS
     3.1 Base Salary . During the period of this Agreement, Executive shall receive an annual base salary of $220,000. Executive’s annual base salary shall be reviewed by the Compensation Committee of the Board (“Compensation Committee”) on an annual basis, and, in the sole discretion of the Compensation Committee, such annual base salary may be increased, but not decreased (except for a decrease that is consistent with reductions taken generally by other executives of Company), effective as of any date determined by the Compensation Committee. Executive’s annual base salary shall be paid in equal installments in accordance with Company’s standard policy regarding payment of compensation to executives, but no less frequently than monthly.
     3.2 Bonus Opportunity . During the period of this Agreement, Executive shall be provided with the opportunity to earn and receive an annual incentive performance bonus payable in cash in an amount equal to $130,000 (pro-rated for any period of less than 12 months), 20 percent of which shall be conditioned and determined on the attainment of personal performance goals and 80 percent of which shall be conditioned and determined on the attainment of organizational performance goals, in each case as set by, and based on performance criteria established by, the Compensation Committee. The Compensation Committee shall notify Executive of the bonus opportunity by no later than the end of the first 90 days of each annual performance period and shall, at that time, set and communicate to Executive the personal and organizational performance goals on which the bonus (and each component thereof) shall be conditioned and the criteria on which the attainment of such goals and the resulting bonus, if any, shall be determined. All determinations with respect to the bonus hereunder shall be made by the Compensation Committee and its determinations shall be final and binding.
     3.3 Incentive Compensation . Executive shall be eligible to receive awards under the Company’s Long Term Incentive Plan, as determined by the Compensation Committee.
     3.4 Other Perquisites . During his or her employment hereunder, Executive shall be afforded the following benefits as incidences of his or her employment:
     (i) Business and Entertainment Expenses — Subject to Company’s standard policies and procedures with respect to expense reimbursement as applied to its executive employees generally, Company shall reimburse Executive for, or pay on behalf of Executive, reasonable and appropriate expenses incurred by Executive for business related purposes, including dues and fees to industry and professional organizations and costs of entertainment and business development.
     (ii) Vacation — During his or her employment hereunder, Executive shall be entitled to four weeks of paid vacation each calendar year (pro-rated for the calendar year containing the Effective Date) and to all holidays provided to executives of Company generally.
     (iii) Other Company Benefits — Executive and, to the extent applicable, Executive’s spouse, dependents and beneficiaries, shall be allowed to participate in, and in accordance with the terms of, all benefits, plans and programs, including
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improvements or modifications of the same, which are now, or may hereafter be, available to other executive employees of Company. Such benefits, plans and programs shall include, without limitation, any profit sharing plan, thrift plan, health insurance or health care plan, life insurance, disability insurance, pension plan, supplemental retirement plan, vacation and sick leave plan, and the like which may be maintained by Company. Company shall not, however, by reason of this paragraph be obligated to institute, maintain, or refrain from changing, amending, or discontinuing, any such benefit plan or program, so long as such changes are similarly applicable to executive employees generally.
ARTICLE 4: EFFECT OF TERMINATION ON COMPENSATION
     4.1 Payment of Accrued Obligations . Upon termination of Executive’s employment hereunder for any reason and by any means, Executive shall be entitled to, and shall be paid, any annual base salary that is accrued and unpaid as of the date of such termination, which shall be paid on the next regularly scheduled pay day for the payment of Executive’s annual base salary, and any expense reimbursement payable in accordance with paragraph 3.4(i) for reimbursable expenses incurred by Executive prior to the date of such termination, which shall be paid at the time and in the manner provided by Company’s reimbursement policy and in accordance with this Agreement. Other than the foregoing amounts and any Severance Pay pursuant to paragraph 4.3, all compensation and benefits to Executive hereunder shall terminate contemporaneously with the termination of Executive’s employment. Any other benefits to which Executive shall be entitled shall be governed by the plan, policy or agreement providing for such benefits and applicable law.
     4.2 Other Terminations . If Executive’s employment hereunder shall terminate at any time (including, but not limited to, upon or following a change of control of the Company), (i) upon expiration of the term provided in paragraph 2.1 hereof because either party has provided the notice contemplated in such paragraph (except as provided in Section 5.6 hereof), (ii) by Executive for Good Reason and in accordance with the Good Reason Termination Procedure or (iii) by Company other than in any event or circumstance described in paragraph 2.2(i), 2.2(ii), or 2.2(iii), then, subject to paragraph 4.4, Company shall pay Executive an amount equal one times the sum of Executive’s annual base salary at the rate in effect under paragraph 3.1 on the date of such termination, plus one times the amount, if any, paid to Executive under paragraph 3.2 for the calendar year ending immediately prior to the date of such termination of Executive’s employment (the “Severance Amount”), which shall be paid as provided in paragraph 4.3.
     4.3 Severance Payments . Subject to paragraph 4.4 below, the Severance Amount, if any shall be due, shall be divided into amounts (each, a “Severance Payment”) to be paid in installments. The amount of each Severance Payment shall be equal to the Severance Amount divided by the number of regular pay days scheduled (in accordance with Company’s regular payroll practices) to occur between the date of Executive’s termination of employment (“Termination Date”) and the first anniversary of the Termination Date (“Scheduled Paydays”). If any Severance Amount would otherwise be owed under this Agreement, but the requirements of paragraph 4.4 are not satisfied, then no Severance Amount and no amount in lieu of the Severance Amount, shall be owed or paid. If the requirements of paragraph 4.4 are satisfied, then, subject to paragraph 7.14(iv), a portion of the Severance Amount equal to the product of
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one Severance Payment and the number of Scheduled Paydays during the 60-day period beginning on the Termination Date shall be paid in a lump sum amount on the 60 th day following the Termination Date, and the remainder of the Severance Amount shall be paid in regular installments, each one equal to the amount of one Severance Payment, with the first such payment being due on due on the Scheduled Payday immediately following the 60 th day after the Termination Date, with like payments on each Scheduled Payday thereafter until the remaining Severance Amount is paid in full.
     4.4 Release and Full Settlement . Anything to the contrary herein notwithstanding, as a condition to the receipt of any portion of the Severance Amount, Executive shall execute a release, in the form established by the Board, releasing the Board, Company, and Company’s parent corporation, subsidiaries, affiliates, and their respective shareholders, partners, officers, directors, employees, attorneys and agents from any and all claims and from any and all causes of action of any kind or character including, but not limited to, all claims or causes of action arising out of Executive’s employment with Company or its affiliates or the termination of such employment, but excluding all claims to vested benefits and payments Executive may have under any compensation or benefit plan, program or arrangement, including this Agreement. Executive shall provide such release to Company no later than 50 days after the Termination Date and, as a condition to Company’s obligation to pay all or any portion of the Severance Amount, Executive shall not revoke such release. The performance of Company’s obligations hereunder shall constitute full settlement of all such claims and causes of action.
     4.5 No Duty to Mitigate Losses . Executive shall have no duty to find new employment following the termination of his or her employment under circumstances which require Company to pay any amount to Executive pursuant to this Article 4. Any salary or remuneration received by Executive from a third party for the providing of personal services (whether by employment or by functioning as an independent contractor) following the termination of his or her employment under circumstances pursuant to which this Article 4 apply shall not reduce Company’s obligation to make a payment to Executive (or the amount of such payment) pursuant to the terms of this Article 4.
     4.6 Liquidated Damages . In light of the difficulties in estimating the damages for an early termination of Executive’s employment under this Agreement, Company and Executive hereby agree that the payments and benefits, if any, to be received by Executive pursuant to this Article 4 shall be received by Executive as liquidated damages.
     4.7 Other Benefits . This Agreement governs the rights and obligations of Executive and Company with respect to Executive’s base salary, bonus and certain perquisites of employment. Except as expressly provided herein, Executive’s rights and obligations both during the term of his or her employment and thereafter with respect to his or her ownership rights in Company and American Midstream LP, and other benefits under the plans and programs maintained by Company shall be governed by the terms (which are not, and are not required to be, affected, altered or amended) of the separate agreements, plans and the other documents and instruments governing such matters.
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ARTICLE 5: PROTECTION OF CONFIDENTIAL INFORMATION
     5.1 Disclosure to and Property of Company . All information, designs, ideas, concepts, improvements, product developments, discoveries and inventions, whether patentable or not, that are conceived, made, developed or acquired by Executive, individually or in conjunction with others, during the period of Executive’s employment by Company (whether during business hours or otherwise and whether on Company’s premises or otherwise) that relate to Company’s (or any of its affiliates’) business, trade secrets, products or services (including, without limitation, all such information relating to corporate opportunities, product specification, compositions, manufacturing and distribution methods and processes, research, financial and sales data, pricing terms, evaluations, opinions, interpretations, acquisitions prospects, the identity of customers or their requirements, the identity of key contacts within the customer’s organizations or within the organization of acquisition prospects, marketing and merchandising techniques, business plans, computer software or programs, computer software and database technologies, prospective names and marks) (collectively, “Confidential Information”) shall be disclosed to Company and are and shall be the sole and exclusive property of Company (or its affiliates). Moreover, all documents, videotapes, written presentations, brochures, drawings, memoranda, notes, records, files, correspondence, manuals, models, specifications, computer programs, E-mail, voice mail, electronic databases, maps, drawings, architectural renditions, models and all other writings or materials of any type embodying any of such information, ideas, concepts, improvements, discoveries, inventions and other similar forms of expression (collectively, “Work Product”) are and shall be the sole and exclusive property of Company (or its affiliates). Upon Executive’s termination of employment with Company, for any reason, Executive promptly shall deliver such Confidential Information and Work Product, and all copies thereof, to Company.
     5.2 Disclosure to Executive . In reliance upon Executive’s representations and agreements in this Agreement, Company has and will disclose to Executive, and will place Executive in a position to have access to and to develop, Confidential Information and Work Product of Company (or its affiliates); and/or has and will entrust Executive with business opportunities of Company (or its affiliates); and/or has and will place Executive in a position to develop business good will on behalf of Company (or its affiliates). Executive agrees to preserve and protect the confidentiality of all Confidential Information or Work Product of Company (or its affiliates).
     5.3 No Unauthorized Use or Disclosure . Executive agrees that he or she will not, at any time during or after Executive’s employment by Company, make any unauthorized disclosure of, and will prevent the removal from Company premises of, Confidential Information or Work Product of Company (or its affiliates), or make any use thereof, except in the carrying out of Executive’s responsibilities during the course of Executive’s employment with Company. Executive shall use commercially reasonable efforts to cause all persons or entities to whom any Confidential Information shall be disclosed by him or her hereunder to observe the terms and conditions set forth herein as though each such person or entity was bound hereby. Executive shall have no obligation hereunder to keep confidential any Confidential Information if and to the extent disclosure thereof is specifically required by law; provided, however, that in the event disclosure is required by applicable law, Executive shall provide Company with prompt notice of such requirement prior to making any such disclosure, so that Company may seek an appropriate
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protective order or otherwise contest such disclosure. At the request of Company at any time, Executive agrees to deliver to Company all Confidential Information that he or she may possess or control. Executive agrees that all Confidential Information of Company (whether now or hereafter existing) conceived, discovered or made by him or her during the period of Executive’s employment by Company exclusively belongs to Company (and not to Executive), and Executive will promptly disclose such Confidential Information to Company and perform all actions reasonably requested by Company to establish and confirm such exclusive ownership. Affiliates of Company shall be third party beneficiaries of Executive’s obligations under this Article 5. As a result of Executive’s employment by Company, Executive may also from time to time have access to, or knowledge of, Confidential Information or Work Product of third parties, such as customers, suppliers, partners, joint venturers, and the like, of Company and its affiliates. Executive also agrees to preserve and protect the confidentiality of such third party Confidential Information and Work Product to the same extent, and on the same basis, as Company’s Confidential Information and Work Product.
     5.4 Ownership by Company . If, during Executive’s employment by Company, Executive creates any work of authorship fixed in any tangible medium of expression that is the subject matter of copyright (such as videotapes, written presentations, or acquisitions, computer programs, E-mail, voice mail, electronic databases, drawings, maps, architectural renditions, models, manuals, brochures, or the like) relating to Company’s business, products, or services, whether such work is created solely by Executive or jointly with others (whether during business hours or otherwise and whether on Company’s premises or otherwise), including any Work Product, Company shall be deemed the author of such work if the work is prepared by Executive in the scope of Executive’s employment; or, if the work is not prepared by Executive within the scope of Executive’s employment but is specially ordered by Company as a contribution to a collective work, as a part of a motion picture or other audiovisual work, as a translation, as a supplementary work, as a compilation, or as an instructional text, then the work shall be considered to be work made for hire and Company shall be the author of the work. If such work is neither prepared by Executive within the scope of Executive’s employment nor a work specially ordered that is deemed to be a work made for hire, then Executive hereby agrees to assign, and by these presents does assign, to Company all of Executive’s worldwide right, title, and interest in and to such work and all rights of copyright therein.
     5.5 Assistance by Executive . During the period of Executive’s employment by Company and thereafter, Executive shall assist Company and its nominee, at any time, in the protection of Company’s (or its affiliates’) worldwide right, title and interest in and to Work Product and the execution of all formal assignment documents requested by Company or its nominee and the execution of all lawful oaths and applications for patents and registration of copyright in the United States and foreign countries.
     5.6 Non-Competition Obligations . Both as part of the consideration for the compensation and benefits to be paid to Executive hereunder; and to protect the trade secrets and Confidential Information of Company and its affiliates that have been or will in the future be disclosed or entrusted to Executive, the business good will of Company and its affiliates that has been and will in the future be developed in Executive, and the business opportunities that have been and will in the future be disclosed or entrusted to Executive by Company and its affiliates; Executive agrees that during the period that Executive is employed by Company and for 12
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months after the date of the termination of Executive’s employment with the Company for any reason, Executive shall not, directly or indirectly for Executive or for others, in the geographic areas and markets where Company conducts any business during Executive’s employment with the Company (as identified on Schedule A attached hereto, and amended by the Company from time to time), as well as any other geographic area or market where Company is conducting any business as of the date of termination of the employment relationship:

 	(i)	 	engage in the business of acquiring, developing, improving, managing, providing services with respect to, operating and disposing of mid-stream energy projects, including pipelines, treatment and processing facilities and gas storage fields or any other business that is competitive with the business conducted by Company;	
 		
 	(ii)	 	render any advice or services to, or otherwise assist, any other person, association, or entity who is engaged, directly or indirectly, with any business that is competitive with the business conducted by Company;	
 		
 	(iii)	 	induce any employee of Company or its affiliates to terminate his or her employment with Company or its affiliates, or hire or assist in the hiring of any such employee by any person, association, or entity not affiliated with Company; or	
 		
 	(iv)	 	request or cause any customer of Company or its affiliates to terminate any business relationship with Company or its affiliates.	
Executive understands that the foregoing restrictions may limit Executive’s ability to engage in certain businesses anywhere in the world during the period provided for above, but acknowledges and represents that the restrictions are both reasonable and necessary to protect Company’s legitimate business interests, and that Executive will receive sufficiently high remuneration and other benefits under this Agreement to compensate for and to justify such restrictions. Notwithstanding the foregoing, in the event that the Executive’s employment is terminated upon expiration of the initial or extended term pursuant to Section 2.1 hereof because either party has provided the notice contemplated in such paragraph, the Board may, in its discretion, release the Executive from the covenants contained in this Section 5.6; provided, however, that in such case, the Executive shall not receive the Severance Amount provided in Section 4.2 hereof.
     5.7 Enforcement and Remedies . Executive acknowledges and agrees that money damages would not be sufficient remedy for any breach of this Article 5 by Executive, and Company or its affiliates shall be entitled to enforce the provisions of this Article 5 by terminating payments then owing to Executive under this Agreement or otherwise, by specific performance and injunctive relief as remedies for such breach or any threatened breach. Such remedies shall not be deemed the exclusive remedies for a breach of this Article 5, but shall be in addition to all remedies available at law or in equity, including, without limitation, the recovery of damages from Executive and Executive’s agents involved in such breach and remedies available to Company pursuant to other agreements with Executive.
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     5.8 Reformation . It is expressly understood and agreed that Company and Executive consider the restrictions contained in this Article 5 to be reasonable and necessary to protect the proprietary information of Company and its affiliates. Nevertheless, if any of the aforesaid restrictions are found by a court having jurisdiction to be unreasonable, or overly broad as to geographic area or time, or otherwise unenforceable, the parties intend for the restrictions therein set forth to be modified by such courts so as to be reasonable and enforceable and, as so modified by the court, to be fully enforced.
ARTICLE 6: NONDISPARAGEMENT
     Executive shall refrain, both during the employment relationship and after the employment relationship terminates, from publishing any oral or written statements about Company, its affiliates, or any of such entities’ officers, employees, agents or representatives that (i) are slanderous, libelous, or defamatory; (ii) disclose private or confidential information about Company, its affiliates, or any of such entities’ business affairs, officers, employees, agents, or representatives; (iii) constitute an intrusion into the seclusion or private lives of the officers, employees, agents, or representatives of Company or its affiliates; (iv) give rise to unreasonable publicity about the private lives of the officers, employees, agents, or representatives of Company or its affiliates; (v) place Company, its affiliates, or any of such entities’ officers, employees, agents, or representatives in a false light before the public; or (vi) constitute a misappropriation of the name or likeness of Company, its affiliates, or any of such entities’ officers, employees, agents, or representatives. A violation or threatened violation of this prohibition may be enjoined by the courts. The rights afforded Company and its affiliates under this provision are in addition to any and all rights and remedies otherwise afforded by law.
     Company agrees that, both during Executive’s employment relationship and after the employment relationship terminates, Company, its affiliates, and such entities’ officers, employees, agents or representatives shall refrain from publishing any oral or written statements about Executive that (i) are slanderous, libelous, or defamatory; (ii) disclose private or confidential information about Executive; (iii) that constitute an intrusion into the seclusion or private life of Executive; (iv) give rise to unreasonable publicity about the private life of Executive; (v) place Executive in a false light before the public; or (vi) constitute a misappropriation of the name or likeness of Executive. A violation or threatened violation of this prohibition may be enjoined by the courts. The rights afforded Executive under this provision are in addition to any and all rights and remedies otherwise afforded by law.
     The nondisparagement obligations of this Article 6 shall not apply to communications with law enforcement or required testimony under law or court process.
ARTICLE 7: MISCELLANEOUS
     7.1 Notices . For purposes of this Agreement, notices and all other communications provided for herein shall be in writing and shall be deemed to have been duly given when personally delivered or when mailed by United States registered or certified mail, return receipt requested, postage prepaid, addressed as follows:
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 	 	If to Company to:	 	American Midstream GP, LLC	
 	 	 	 	1614 15th Street	
 	 	 	 	Suite 300	
 	 	 	 	Denver, CO 80202	
 	 	 	 	Attention: Chairman of the Board	
 		
 	 	with a copy to:	 	American Infrastructure MLP Fund, L.P.	
 	 	 	 	950 Tower Lane	
 	 	 	 	Suite 800	
 	 	 	 	Foster City, CA 94404	
 	 	 	 	Attention: Ed Diffendal and Robert B. Hellman, Jr.	
 		
 	 	If to Executive to:	 	John J. Connor II	
 	 	 	 	1206 Forest Street	
 	 	 	 	Denver, CO 80220-2553	
or to such other address as either party may furnish to the other in writing in accordance herewith, except that notices or changes of address shall be effective only upon receipt.
     7.2 Applicable Law . This Agreement is entered into under, and shall be governed for all purposes by, the laws of the State of Delaware.
     7.3 No Waiver . No failure by either party hereto at any time to give notice of any breach by the other party of, or to require compliance with, any condition or provision of this Agreement shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.
     7.4 Severability . If a court of competent jurisdiction determines that any provision of this Agreement is invalid or unenforceable, then the invalidity or unenforceability of that provision shall not affect the validity or enforceability of any other provision of this Agreement, and all other provisions shall remain in full force and effect.
     7.5 Counterparts . This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same Agreement.
     7.6 Withholding of Taxes and Other Employee Deductions . Company may withhold from any benefits and payments made pursuant to this Agreement or otherwise all federal, state, city and other taxes as may be required pursuant to any law or governmental regulation or ruling and all other normal employee deductions made with respect to Company’s employees generally.
     7.7 Headings . The paragraph headings have been inserted for purposes of convenience and shall not be used for interpretive purposes.
     7.8 Gender and Plurals . Wherever the context so requires, the masculine gender includes the feminine or neuter, and the singular number includes the plural and conversely.
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     7.9 Affiliate . As used in this Agreement, the term “affiliate” shall mean any entity which owns or controls, is owned or controlled by, or is under common ownership or control with, Company.
     7.10 Term . This Agreement has a term co-extensive with the term of employment provided in Article 2. Termination shall not affect any right or obligation of any party which is accrued or vested prior to such termination. The provisions of paragraphs 2.4 and 2.5 and Articles 4, 5, 6, and 7 shall survive any termination of this Agreement.
     7.11 Entire Agreement . Except as provided in (i) the written benefit plans and programs referenced in paragraph 3.4(iii) (and any agreements between Company and Executive that have been executed under such plans and programs) and paragraph 4.7 and (ii) any signed written agreement contemporaneously or hereafter executed by Company and Executive, this Agreement constitutes the entire agreement of the parties with regard to the subject matter hereof, and contains all the covenants, promises, representations, warranties and agreements between the parties with respect to employment of Executive by Company. Without limiting the scope of the preceding sentence, all understandings and agreements preceding the date of execution of this Agreement and relating to the subject matter hereof (other than (A) under the agreements described in clause (i) of the preceding sentence; (B) as provided herein or (C) under the agreements forming and/or operating Company and American Midstream, LP or any investor rights agreement related thereto) are hereby null and void and of no further force and effect. Any modification of this Agreement will be effective only if it is in writing and signed by the party to be charged.
     7.12 Legal Expenses . If Executive incurs legal costs and expenses (including reasonable attorneys’ fees) in any contest relating to rights under this Agreement and prevails in such contest, Company shall reimburse Executive for his or her reasonable legal costs and expenses (including reasonable attorneys’ fees) incurred with respect to such contest.
     7.13 Liability Insurance . Company shall maintain a directors’ and officers’ insurance liability policy throughout the term of this Agreement and shall provide Executive with coverage under such policy on terms not less favorable than provided to other Company directors and officers.
     7.14 Compliance with Section 409A of the Code .
     (i) All references in this Agreement to the termination of Executive’s employment with Company shall mean and shall be deemed to occur if and when a termination of employment that constitutes a “separation from service” within the meaning of Section 409A(a)(2)(A)(i) of the Internal Revenue Code of 1986, as amended (the “Code”), and applicable administrative guidance issued thereunder has occurred.
     (ii) To the extent that any reimbursement or benefit in kind hereunder constituted deferred compensation under Section 409A of the Code, such reimbursement or benefit shall be administered consistently with the following additional requirements as set forth in Treas. Reg. §1.409A-3(i)(1)(iv): (1) Executive’s eligibility for or receipt of benefits or reimbursements in one calendar year will not affect Executive’s eligibility for
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or the amount of benefits or reimbursements in any other calendar year, (2) any reimbursement of eligible expenses will be made on or before the last day of the year following the year in which the expense was incurred, (3) Executive’s right to benefits or reimbursement is not subject to liquidation or exchange for another benefit, and (4) the right to reimbursement of expenses incurred or to the provision of benefits in kind shall terminate ten (10) years from Executive’s termination of employment, if not before.
     (iii) Executive’s right to installment payments, if any, hereunder, shall be treated as the right to receive a series of separate and distinct individual payments for purposes of Section 409A of the Code.
     (iv) Notwithstanding any provision in this Agreement to the contrary, if Executive is a “specified employee” (within the meaning of Section 409A(a)(2)(B)(i) of the Code, and applicable administrative guidance thereunder and determined in accordance with any method selected by Company that is permitted under the regulations issued under Section 409A of the Code), and any amount paid or benefit provided under this Agreement to or on behalf of Executive would be subject to additional taxes under Section 409A of the Code because the timing of such payment is not delayed as provided in Section 409A(a)(2)(B)(i) of the Code and the regulations thereunder, then any such payment or benefit that Executive would otherwise be entitled to during the first six months following the date of Executive’s separation from service (within the meaning of Section 409A(a)(2)(A)(i) of the Code and applicable administrative guidance thereunder) shall be accumulated and paid or provided, as applicable, on the date that is six months plus one day after Executive’s separation from service (or if such date does not fall on a business day of Company, the next following business day of Company), or such earlier date upon which such amount can be paid or provided under Section 409A of the Code without being subject to such additional taxes and interest; provided, however, that Executive shall be entitled to receive the maximum amount permissible under Section 409A of the Code and the applicable administrative guidance thereunder during the six-month period following his or her separation from service that will not result in the imposition of any additional tax or penalties on such amount.
     (v) To the extent that Section 409A of the Code is applicable to this Agreement, the provisions of this Agreement shall be interpreted as necessary to comply with such section and the applicable administrative guidance issued thereunder.
     7.15 Arbitration .
     (i) Company and Executive agree to submit to final and binding arbitration any and all disputes or disagreements concerning the interpretation or application of this Agreement, the termination of this Agreement, or any other aspect of Executive’s employment relationship with Company. Any such dispute or disagreement will be resolved by arbitration in accordance with the National Rules for the Resolution of Employment Disputes of the American Arbitration Association (the “AAA Rules”) before a single arbitrator. Arbitration will take place in Delaware, unless the parties mutually agree to a different location. Company and Executive agree that the decision of the arbitrator will be final and binding on both parties. Any court having jurisdiction may
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enter a judgment upon the award rendered by the arbitrator. The costs of the proceedings shall be borne equally by the parties unless the arbitrator orders otherwise.
     (ii) Notwithstanding the provisions of paragraph 7.15(i), (a) Company may, if it so chooses, bring an action in any court of competent jurisdiction for injunctive relief to enforce Executive’s obligations under Articles 5 or 6 hereof, pending a decision by the arbitrator in accordance with paragraph 7.15(i), and (b) Executive may, if he or she so chooses, bring an action in any court of competent jurisdiction for temporary or preliminary injunctive relief to enforce Company’s obligations under Article 6 hereof, pending a decision by the arbitrator in accordance with paragraph 7.15(i).
     7.16 Provisions Regarding Effective Date . As indicated in this Agreement, this Agreement is effective as of the Effective Date, and accordingly in connection therewith the parties agree that the following shall apply:
     (i) This Agreement shall from and after its execution by the parties be an agreement binding upon and enforceable by both Company and Executive subject to the application of the provisions hereof generally being effective as of the Effective Date.
     (ii) The employment of Executive by Company shall continue to be governed by the terms of the Existing Agreement until the Effective Date.
     (iii) In the event that the employment of Executive by Company terminates at any time prior to the Effective Date, such termination shall be governed by the terms of the Existing Agreement and this Agreement shall be null and void and of no force and effect.
     (iv) In the event that the Effective Date does not occur on or before July 31, 2011, this Agreement shall be null and void and of no force and effect and the Existing Agreement shall continue in full force and effect.
Signature page follows.
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      IN WITNESS WHEREOF , the parties hereto have executed this Agreement on the 9th day of June, 2011, to be effective as of the Effective Date.

 	 	American Midstream GP, LLC	
 	 	 	 	 	
 	 	By:	 	/s/ Robert B. Hellman, Jr. 	
 	 	 	 	 
 Robert B. Hellman, Jr.,	
 	 	 	 	Chairman, Compensation Committee	
 	 	 	 	 	
 	 	“EXECUTIVE”	

 	 	 	 	/s/ John J. Connor II 	
 	 	 	 	 
 John J. Connor II	
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SCHEDULE A
NONCOMPETITION GEOGRAPHIC AREAS AND SCOPE
Every State of the United States in which the Company does business on the Executive’s date of termination.
All customers of the Company on the Executive’s date of termination.
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Exhibit 10.7
AMENDED AND RESTATED
AMERICAN MIDSTREAM GP, LLC
LONG-TERM INCENTIVE PLAN
1. Purpose of the Plan . This Amended and Restated American Midstream GP, LLC Long-Term Incentive Plan (the “ Plan ”) has been adopted by American Midstream GP, LLC, a Delaware limited liability company (the “ Company ”), the general partner of American Midstream Partners, LP a Delaware limited partnership (the “ Partnership ”). The Plan is intended to promote the interests of the Partnership, the Company and their Affiliates by providing to employees, consultants and directors of the Partnership, the Company and their Affiliates incentive compensation awards for superior performance that are based on Units. The Plan is also contemplated to enhance the ability of the Partnership, the Company and their Affiliates to attract and retain the services of individuals who are essential for the growth and profitability of the Company, the Partnership and their Affiliates, and to encourage them to devote their best efforts to advancing the business of the Company, the Partnership and their Affiliates.
2. Definitions; Construction .
     (a)  Definitions . As used in the Plan, the following terms shall have the meanings set forth below:
     “ Affiliate ” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise. Notwithstanding the immediately preceding two sentences, to the extent that Section 409A of the Code applies to Options or Unit Appreciation Rights granted under the Plan, the term “Affiliate” means all Persons with whom the Partnership could be considered a single employer under Section 414(b) or Section 414(c) of the Code substituting “50 percent” in place of “80 percent” in determining a controlled group of corporations under Section 414(b) of the Code and in determining trades or businesses (whether or not incorporated) that are under common control for purposes of Section 414(c) of the Code.
     “ Award ” means an Option, UAR, Restricted Unit, Phantom Unit, Other Unit-Based Award, Unit Award or Replacement Award, and shall also include any tandem DERs granted with respect to an Award.
     “ Award Agreement ” means the written or electronic agreement by which an Award shall be evidenced.
     “ Board ” means the Board of Directors of the Company.
     “ Change of Control ” means, and shall be deemed to have occurred upon the occurrence of, one or more of the following events:
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     (i) any “Person” or “group” within the meaning of those terms as used in Section 13(d) and Section 14(d)(2) of the Exchange Act, other than an Affiliate of the Company or the Partnership, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Company or the Partnership;
     (ii) the limited partners of the Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership;
     (iii) the sale, lease or other disposition by either the Company or the Partnership of all or substantially all of its assets in one or more transactions to any Person other than the Company or an Affiliate of the Company; or
     (iv) a transaction resulting in a Person other than the Company or an Affiliate of the Company being the general partner of the Partnership.
; provided , however , that, notwithstanding the foregoing, with respect to an Award that is subject to Section 409A of the Code and with respect to which a Change of Control will accelerate payment, “Change of Control” shall only include a Change of Control that constitutes a “change in control event” as defined in the regulations and guidance issued under Section 409A of the Code; and provided further , however , that, notwithstanding the foregoing, for purposes of determining whether the vesting of any Award accelerates, “Change of Control” shall not include any initial public offering of the Partnership’s equity securities that is registered under the Securities Act of 1933 or any private offering undertaken by or for the Partnership as an alternative to such an initial public offering.
     “ Code ” means the Internal Revenue Code of 1986, as amended. Reference to any section of the Code shall include reference to such section and the regulations and other authoritative guidance promulgated thereunder.
     “ Committee ” means the Board or such committee of the Board, if any, as may be appointed by the Board to administer the Plan.
     “ Consultant ” means an independent contractor, other than a Director, who performs services for the benefit of the Company or the Partnership or an Affiliate of either of them.
     “ DER ” or “ Distribution Equivalent Right ” means a contingent right, granted in tandem with a specific Option, UAR or Phantom Unit, to receive an amount in cash equal to the cash distributions made by the Partnership with respect to a Unit during the period such DER is outstanding.
     “ Director ” means a member of the Board or a board of directors of an Affiliate who is not an Employee or a Consultant.
     “ Employee ” means any employee of the Company or the Partnership or an Affiliate of either of them who performs services for the benefit of the Company or the Partnership or an Affiliate of either of them.
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     “ Exchange Act ” means the Securities Exchange Act of 1934, as amended.
     “ Fair Market Value ” means the closing sales price of a Unit on the principal national securities exchange or other market in which trading in Units occurs on the applicable date (or if there is no trading in the Units on such date, on the next preceding date on which there was trading) as reported in The Wall Street Journal (or other reporting service approved by the Committee). In the event Units are not traded on a national securities exchange or other market at the time a determination of fair market value is required to be made hereunder, the determination of fair market value shall be made in good faith by the Committee by the reasonable application of a reasonable method. Notwithstanding the foregoing, with respect to an Award granted on the effective date of the initial public offering of Units, Fair Market Value on such date shall mean the initial offering price per Unit as stated on the cover page of the Registration Statement on Form S-1 (or successor form thereto) for such offering.
     “ Option ” means an option to purchase Units granted under the Plan.
     “ Other Unit-Based Award ” means an award granted pursuant to Section 6(f) .
     “ Participant ” means any Employee, Consultant or Director granted an Award under the Plan.
     “ Person ” means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.
     “ Phantom Unit ” means a phantom (notional) unit granted under the Plan that entitles the Participant to receive an amount of cash equal to the Fair Market Value of one Unit upon vesting of the Phantom Unit; however, the Committee, in its discretion, may elect to pay such vested Phantom Unit with a Unit in lieu of cash.
     “ Replacement Award ” means an Award granted pursuant to Section 6(g) .
     “ Restricted Period ” means the period established by the Committee with respect to an Award during which the Award is not transferable, remains subject to forfeiture and is either not exercisable by or payable to the Participant, as the case may be.
     “ Restricted Unit ” means a Unit granted under the Plan that is subject to a Restricted Period.
     “ Rule 16b-3 ” means Rule 16b-3 promulgated by the SEC under the Exchange Act, or any successor rule or regulation thereto as in effect from time to time.
     “ SEC ” means the Securities and Exchange Commission, or any successor thereto.
     “ Unit ” means a Common Unit of the Partnership.
     “ UAR ” or “ Unit Appreciation Right ” means an Award that, upon exercise, entitles the holder to receive the excess of the Fair Market Value of a Unit on the exercise date over the
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exercise price established for such Unit Appreciation Right. Such excess may be paid in cash, Units or any combination thereof, as determined by the Committee in its discretion.
     “ Unit Award ” means the grant of a Unit that is not subject to a Restricted Period.
     “ UDR ” or “ Unit Distribution Right ” means a right to receive distributions made by the Partnership with respect to a Restricted Unit.
     (b)  Construction . In this Plan, unless a clear contrary intention appears: (i) the gender of all words used in this Plan includes the masculine, feminine and neuter; (ii) the singular forms of nouns, pronouns and verbs shall include the plural and vice versa; (iii) all references to Articles and Sections refer to articles and sections in this Plan, each of which is made a part for all purposes; (iv) the terms “ include ” and “ includes ” mean “includes, without limitation,” and “ including ” means “including, without limitation,”; (v) all Article and Section headings in this Plan are for convenience only and shall not be deemed to control or affect the meaning or construction of any of the provisions hereof; and (vi) the words “hereof,” “herein” and “hereunder” and words of similar import, when used in this Plan, refer to this Plan as a whole and not to any particular provision of this Plan.
3. Administration .
     (a)  Governance . The Plan shall be administered by the Committee.
     (b)  Delegation . Subject to the following and applicable law, the Committee, in its sole discretion, may delegate any or all of its powers and duties under the Plan, including the power to grant Awards under the Plan, to the Chief Executive Officer of the Company, subject to such limitations on such delegated powers and duties as the Committee may impose, if any. Upon any such delegation, all references in the Plan to the “ Committee ”, other than in Section 7 , shall be deemed to include the Chief Executive Officer; provided, however, that such delegation shall not limit the Chief Executive Officer’s right to receive Awards under the Plan. Notwithstanding the foregoing, the Chief Executive Officer may not grant Awards to, or take any action with respect to any Award previously granted to, a Person who is an officer subject to Rule 16b-3 or a member of the Board.
     (c)  Authority and Powers . Subject to the terms of the Plan and applicable law, and in addition to other express powers and authorizations conferred on the Committee by the Plan, the Committee shall have full power and authority to: (i) designate Participants; (ii) determine the type or types of Awards to be granted to a Participant; (iii) determine the number of Units to be covered by Awards; (iv) determine the terms and conditions of any Award; (v) determine whether, to what extent, and under what circumstances Awards may be vested, settled, exercised, canceled, or forfeited; (vi) interpret and administer the Plan and any instrument or agreement relating to an Award made under the Plan; (vii) establish, amend, suspend, or waive such rules and regulations and appoint such agents as it shall deem appropriate for the proper administration of the Plan; and (viii) make any other determination and take any other action that the Committee deems necessary or desirable for the administration of the Plan. The Committee may correct any defect, supply any omission or reconcile any inconsistency in the Plan or an Award Agreement in such manner and to such extent as the Committee deems necessary or appropriate. Unless
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otherwise expressly provided in the Plan, all designations, determinations, interpretations, and other decisions under or with respect to the Plan or any Award shall be within the sole discretion of the Committee, may be made at any time and shall be final, conclusive, and binding upon all Persons, including the Company, the Partnership, any Affiliate, any Participant, and any beneficiary of any Participant.
4. Units .
     (a)  Limits on Units Deliverable . Subject to adjustment as provided in Section 4(c) , the number of Units that may be delivered with respect to Awards under the Plan may not exceed 625,532 Units; provided , however , if any Award (including Restricted Units) is terminated, cancelled, forfeited or expires for any reason without the actual delivery of Units covered by such Award or Units are withheld from an Award to satisfy the exercise price or the employer’s tax withholding obligation with respect to such Award, such Units shall again be available for delivery pursuant to other Awards granted under the Plan. Notwithstanding the foregoing, (i) there shall not be any limitation on the number of Awards that may be granted under the Plan and paid in cash, and (ii) any Units allocated to an Award shall, to the extent such Award is paid in cash, be again available for delivery under the Plan with respect to other Awards.
     (b)  Sources of Units Deliverable Under Awards . Any Units delivered pursuant to an Award shall consist, in whole or in part, of Units acquired in the open market or from any Affiliate, the Partnership or any other Person, or any combination of the foregoing, as determined by the Committee in its sole discretion.
     (c)  Anti-Dilution Adjustments . With respect to any “equity restructuring” event that could result in an additional compensation expense to the Company or the Partnership pursuant to the provisions of Statement of Financial Accounting Standards No. 123 (“ FAS 123R ”) if adjustments to Awards with respect to such event were discretionary, the Committee shall equitably adjust the number and type of Units covered by each outstanding Award and the terms and conditions, including the exercise price and performance criteria (if any), of such Award to equitably reflect such restructuring event and shall adjust the number and type of Units (or other securities or property) with respect to which Awards may be granted after such event. With respect to any other similar event that would not result in a FAS 123R accounting charge if the adjustment to Awards with respect to such event were subject to discretionary action, the Committee shall have complete discretion to adjust Awards in such manner as it deems appropriate with respect to such other event. In the event the Committee makes any adjustment pursuant to the foregoing provisions of this Section 4(c) , the Committee shall make a corresponding and proportionate adjustment with respect to the maximum number of Units that may be delivered with respect to Awards under the Plan as provided in Section 4(a) and the kind of Units or other securities available for grant under the Plan. Notwithstanding the foregoing, the Committee shall not take any action otherwise authorized under this Section 4(c) to the extent that such action would cause the application of Section 409A of the Code to the Award or create adverse tax consequences under Section 409A of the Code should that Code section apply to the Award.
5. Eligibility . Any Employee, Consultant or Director shall be eligible to be designated a Participant by the Committee and receive any number of Awards under the Plan.
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6. Awards .
     (a)  Options . The Committee shall have the authority to determine the Employees, Consultants and Directors to whom Options shall be granted, the number of Units to be covered by each Option, whether DERS are granted with respect to such Option, and the conditions and limitations applicable to the exercise of such Option, including the following terms and conditions and such additional terms and conditions, as the Committee shall determine, that are not inconsistent with the provisions of the Plan.
     (i) Exercise Price . The exercise price per Unit under an Option shall be determined by the Committee at the time the Option is granted and, except with respect to a Replacement Award, may not be less than its Fair Market Value as of the date of grant.
     (ii) Time and Method of Exercise . The Committee shall determine (A) the time or times at which an Option may be exercised in whole or in part, which may include accelerated vesting upon the achievement of specified performance goals or other events, and (B) in its discretion the method or methods by which payment of the exercise price with respect thereto may be made or deemed to have been made, which may include cash, check acceptable to the Company, a “cashless-broker” exercise through a program approved by the Company, with the consent of the Company, the withholding of Units that would otherwise be delivered to the Participant upon the exercise of the Option, or the tender of other securities or other property (including previously acquired Units), or any combination thereof, having a Fair Market Value on the exercise date equal to the relevant exercise price.
     (iii) Forfeitures . Except as otherwise provided in the terms of the Award Agreement, upon termination of a Participant’s employment or consulting with the Company, the Partnership and their Affiliates or membership as a Director, whichever is applicable, for any reason during the applicable Restricted Period, all Options shall be forfeited by the Participant. The Committee may, in its discretion, waive in whole or in part such forfeiture with respect to a Participant’s Options.
     (iv) DERs . To the extent provided by the Committee, in its discretion, a grant of Options may include a tandem DER grant, which may provide that such DERs shall be paid directly to the Participant, be credited to a bookkeeping account (with or without interest in the discretion of the Committee) subject to the same vesting restrictions as the tandem Award, or be subject to such other provisions or restrictions as determined by the Committee in its discretion. Absent any provision to the contrary with regard to the DERs in the Award Agreement, DERs shall be subject to the same vesting restrictions as apply to the Options with respect to which they were granted. Further, as required by Section 409A of the Code, DERs granted in tandem with Options shall not be directly or indirectly contingent on the exercise of the Options with respect to which they were granted. Settlement of DERs, if any, granted in tandem with Options shall comply with Section 6(h)(viii) .
     (b)  UARs . The Committee shall have the authority to determine the Employees, Consultants and Directors to whom Unit Appreciation Rights shall be granted, the number of
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Units to be covered by each grant, whether DERs are granted with respect to such Unit Appreciation Right, the exercise price therefor and the conditions and limitations applicable to the exercise of the Unit Appreciation Right, including the following terms and conditions and such additional terms and conditions, as the Committee shall determine, that are not inconsistent with the provisions of the Plan.
     (i) Exercise Price . The exercise price per Unit Appreciation Right shall be determined by the Committee at the time the Unit Appreciation Right is granted but may not be less than the Fair Market Value of a Unit as of the date of grant.
     (ii) Time of Exercise . The Committee shall determine the Restricted Period, i.e., the time or times at which a Unit Appreciation Right may be exercised in whole or in part, which may include accelerated vesting upon the achievement of specified performance goals.
     (iii) Forfeitures . Except as otherwise provided in the terms of the Award Agreement, upon termination of a Participant’s employment or consulting with the Company and its Affiliates or membership as a Director, whichever is applicable, for any reason during the applicable Restricted Period, all outstanding Unit Appreciation Rights awarded to the Participant shall be automatically forfeited on such termination. The Committee may, in its discretion, waive in whole or in part such forfeiture with respect to a Participant’s Unit Appreciation Rights.
     (iv) Unit Appreciation Right DERs . To the extent provided by the Committee, in its discretion, a grant of Unit Appreciation Rights may include a tandem DER grant, which may provide that such DERs shall be paid directly to the Participant, be credited to a bookkeeping account (with or without interest in the discretion of the Committee) subject to the same vesting restrictions as the tandem Unit Appreciation Rights Award, or be subject to such other provisions or restrictions as determined by the Committee in its discretion. Absent any provision to the contrary with regard to the DERs in the Award Agreement, DERs shall be subject to the same vesting restrictions as apply to the Unit Appreciation Rights with respect to which they were granted. Further, as required by Section 409A of the Code, DERs granted in tandem with UARs shall not be directly or indirectly contingent on the exercise of the UARs with respect to which they were granted. Settlement of DERs, if any, granted in tandem with UARs shall comply with Section 6(h)(viii) .
     (c)  Phantom Units . The Committee shall have the authority to determine the Employees, Consultants, and Directors to whom Phantom Units shall be granted, the number of Phantom Units to be granted to each such Participant, the Restricted Period, the time or conditions under which the Phantom Units may become vested or forfeited, which may include the accelerated vesting upon the achievement of specified performance goals or other events, and such other terms and conditions as the Committee may establish with respect to such Awards, including whether DERs are granted with respect to such Phantom Units.
     (i) DERs . To the extent provided by the Committee in its discretion, a grant of Phantom Units may include a tandem DER grant, which provides that such DERs shall
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be credited to a bookkeeping account (without interest) and shall be paid to the Participant in cash upon the vesting of the tandem Phantom Unit. However, the Committee, in its discretion, may provide such other terms, including different vesting and payment forms and mediums and the “investment” of such DERs in additional Phantom Units, as it may choose with respect to DERs and may also provide that a grant of Phantom Units does not include tandem DERs. Absent any provision to the contrary in the Award Agreement, any DERs granted in tandem with UARs shall be subject to the same vesting restrictions as the UARs so granted. Settlement of DERs, if any, granted in tandem with Phantom Units shall comply with Section 6(h)(viii) .
     (ii) Forfeitures . Except as otherwise provided in the terms of the Award Agreement, upon termination of a Participant’s employment or consulting arrangement with the Company, the Partnership and their Affiliates or membership as a Director, whichever is applicable, for any reason during the applicable Restricted Period, all outstanding Phantom Units awarded to the Participant, and any outstanding tandem DERs credited to such Participant, shall be automatically forfeited on such termination. The Committee may, in its discretion, waive in whole or in part such forfeiture with respect to a Participant’s Phantom Units and tandem DERs.
     (iii) Lapse of Restrictions . Upon or as soon as reasonably practicable following the vesting of each Phantom Unit, subject to the provisions of Section 8(b) , the Participant shall be entitled to settlement of such Phantom Unit by receiving from the Company cash equal to the Fair Market Value of one Unit as of the date on which the Restricted Period ends by vesting; however, the Committee, in its discretion, may elect to pay such vested Phantom Unit in the form of one Unit in lieu of cash. In all events, settlement shall be made no later than the 15 th day of the 3 rd calendar month following the date on which the Restricted Period ends by vesting.
     (d)  Restricted Units . The Committee shall have the authority to determine the Employees, Consultants and Directors to whom Restricted Units shall be granted, the number of Restricted Units to be granted to each such Participant, the Restricted Period, the conditions under which the Restricted Units may become vested or forfeited, which may include the accelerated vesting upon the achievement of specified performance goals or other events, and such other terms and conditions as the Committee may establish with respect to such Awards.
     (i) UDRs . To the extent provided by the Committee, in its discretion, a grant of Restricted Units may provide that distributions made by the Partnership with respect to the Restricted Units shall be subject to such forfeiture and other restrictions as the Committee may choose and, if so restricted, such distributions shall be held, without interest, until the UDR vests or is forfeited. In addition, the Committee may provide that such distributions be used to acquire additional Restricted Units for the Participant. Such additional Restricted Units may be subject to such vesting and other terms as the Committee may prescribe. Absent such a restriction on the UDRs in the Award Agreement, UDRs shall be paid to the holder of the Restricted Unit without restriction. Settlement of UDRs, if any, granted in tandem with Restricted Units shall comply with Section 6(h)(viii) .
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     (ii) Forfeitures . Except as otherwise provided in the terms of the Award Agreement, upon termination of a Participant’s employment or consulting with the Company, the Partnership and their Affiliates or membership as a Director, whichever is applicable, for any reason during the applicable Restricted Period, all outstanding unvested Restricted Units awarded the Participant, and any unpaid UDRs credited to the Participant, shall be automatically forfeited on such termination. The Committee may, in its discretion, waive in whole or in part such forfeitures with respect to a Participant’s Restricted Units and UDRs.
     (iii) Lapse of Restrictions . Upon or as soon as reasonably practical following the vesting of each Restricted Unit, subject to the provisions of Section 8(b) , the Participant shall be entitled to have the restrictions removed from his or her Unit certificate so that the Participant then holds an unrestricted Unit.
     (e)  Unit Awards . Unit Awards may be granted under the Plan to such Employees, Consultants and Directors and in such amounts as the Committee, in its discretion, may select.
     (f)  Other Unit-Based Awards . Other Unit-Based Awards may be granted under the Plan to such Employees, Consultants and Directors as the Committee, in its discretion, may select. An Other Unit-Based Award shall be an award denominated or payable in, valued in or otherwise based on or related to Units, in whole or in part, and shall include unrestricted Units paid in lieu of any bonus or incentive compensation otherwise payable in cash. The Committee shall determine the terms and conditions, if any, of any such Other Unit-Based Award. Upon or as soon as reasonably practicable following vesting, an Other Unit-Based Award may be settled, as determined by the Committee in its discretion, in cash, Units (including Restricted Units) or any combination thereof as determined by the Committee, in its discretion. In all events, settlement shall be made no later than the 15 th day of the 3 rd calendar month following the date on which the Restricted Period ends by vesting.
     (g)  Replacement Awards . Awards may be granted under the Plan in substitution or replacement for similar equity awards cancelled or forfeited by Employees, Consultants and Directors as a result of a merger or acquisition by the Partnership or an Affiliate of an entity or the assets of an entity. Such Replacement Awards may have such terms and conditions as the Committee may determine and the exercise price of an Option may be less than the Fair Market Value of a Unit on the date of such substitution or replacement. Notwithstanding the foregoing, Replacement Awards may not be granted to the extent that such grant would cause the application of Section 409A of the Code to the Award or create adverse tax consequences under Section 409A of the Code should that Code section apply to the Award.
     (h)  General .
     (i) Awards May Be Granted Separately or Together . Awards may, in the discretion of the Committee, be granted either alone or in addition to, in tandem with, or in substitution for any other Award granted under the Plan or any award granted under any other plan of the Company, the Partnership or any Affiliate. No Award shall be issued in tandem with another Award if the tandem Awards would result in adverse tax consequences under Section 409A of the Code. Awards granted in addition to or in
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tandem with other Awards or awards granted under any other plan of the Company, the Partnership or any Affiliate may be granted either at the same time as or at a different time from the grant of such other Awards or awards.
     (ii) Limits on Transfer of Awards .
     (A) Except as provided in Section 6(h)(ii)(C) , each Option and Unit Appreciation Right shall be exercisable only by the Participant during the Participant’s lifetime, or by the Person to whom the Participant’s rights shall pass by will or the laws of descent and distribution.
     (B) Except as provided in Section 6(h)(ii)(C) , no Award and no right under any such Award may be assigned, alienated, pledged, attached, sold or otherwise transferred or encumbered by a Participant and any such purported assignment, alienation, pledge, attachment, sale, transfer or encumbrance shall be void and unenforceable against the Company, the Partnership or any Affiliate.
     (C) To the extent specifically provided by the Committee with respect to an Award, an Award may be transferred by a Participant without consideration to immediate family members or related family trusts, limited partnerships or similar entities on such terms and conditions as the Committee may from time to time establish.
     (iii) Term of Awards . The term of each Award shall be for such period as may be determined by the Committee, but shall not exceed 10 years.
     (iv) Issuance of Units . The Units purchased or delivered pursuant to an Award may be evidenced in any manner deemed appropriate by the Committee in its sole discretion, including in the form of a certificate issued in the name of the Participant or by book entry, electronic or otherwise, subject to such stop transfer orders and other restrictions as the Committee may deem advisable under the Plan or the rules, regulations, and other requirements of the SEC, any stock exchange upon which such Units or other securities are then listed, and any applicable federal or state laws, and the Committee may cause a legend or legends to be inscribed on any certificates to make appropriate reference to such restrictions.
     (v) Consideration for Grants . Awards may be granted for such consideration, including services, as the Committee determines.
     (vi) Delivery of Units or Other Securities and Payment by Participant of Consideration . Notwithstanding anything in the Plan or any Award Agreement to the contrary, if the Company is not reasonably able to obtain Units to deliver pursuant to such Award without violating the rules or regulations of any applicable law or securities exchange, no delivery shall occur until such time as the Committee, in good faith, determines that the delivery of Units may be made without violating applicable law or the applicable rules or regulations of any governmental agency or securities exchange. No Units or other securities shall be delivered pursuant to any Award until payment in full of
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any amount required to be paid pursuant to the Plan or the applicable Award Agreement (including any exercise price or tax withholding) is received by the Company.
     (vii) Change of Control, Similar Events . Upon the occurrence of a Change of Control, a recapitalization, reorganization, merger, consolidation, combination, exchange or other relevant change in capitalization of or involving the Partnership, any change in applicable law or regulation affecting the Plan or Awards thereunder, or any change in accounting principles affecting the financial statements of the Partnership, the Committee, in its sole discretion, without the consent of any Participant or holder of an Award, and on such terms and conditions as it deems appropriate, may take any one or more of the following actions in order to either prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the Plan or an outstanding Award or mitigate any unfavorable accounting consequences:
     (A) provide for either (1) the cancellation and termination of any Award in exchange for an amount of cash, other property or securities, if any, equal to the amount that would have been attained upon the exercise of such Award or realization of the Participant’s rights or if the Participant were a unitholder on the occurrence of such event (and, for the avoidance of doubt, if as of the date of the occurrence of such transaction or event the Committee determines in good faith that no amount would have been attained upon the exercise of such Award or realization of the Participant’s rights, then such Award may be terminated by the Company without payment) or (2) the replacement of such Award with or the conversion of such Award into cash or other securities with other rights or property selected by the Committee in its sole discretion;
     (B) provide that such Award be assumed by the successor or survivor entity, or a parent or subsidiary thereof, or be exchanged for similar options, rights or awards covering the equity of the successor or survivor, or a parent or subsidiary thereof, with appropriate adjustments as to the number and kind of equity interests and prices;
     (C) make adjustments in the number and type of Units (or other securities or property) subject to outstanding Awards, and in the number and kind of outstanding Awards or in the terms and conditions of (including the exercise price), and the vesting and performance criteria included in, outstanding Awards, or both;
     (D) provide that such Award shall be exercisable or payable, notwithstanding anything to the contrary in the Plan or the applicable Award Agreement; and
     (E) provide that the Award cannot be exercised or become payable after such event, i.e. , that it shall terminate upon such event.
; provided , however , that notwithstanding the foregoing, with respect to an above event that is an “equity restructuring” event that would be subject to a compensation expense
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pursuant FAS 123R if a discretionary change were made, the provisions in Section 4(c) shall control to the extent they are in conflict with the discretionary provisions of this Section 6 ; and provided further , however , that, notwithstanding the foregoing, the Committee shall have no discretion under this Section 6(h)(vii) to modify the time at which a payment related to an award that provides for the deferral of compensation within the meaning of Section 409A of the Code shall be made to any Participant except that, upon a Change in Control that constitutes change in the ownership or effective control of the Partnership or in the ownership of a substantial portion of the assets of the Partnership (both as defined for purposes of Section 409A of the Code), all such awards shall become immediately payable, to the extent then vested, unless and to the extent the Committee specifically provides to the contrary in the applicable Award Agreement.
     (viii) Payment of DERs and UDRs . Except as otherwise provided in the Award Agreement, DERs and UDRs that are not subject to a Restricted Period (whether because the DERs or UDRs were originally granted without restrictions or the Restricted Period ended by vesting) shall be currently paid to the Participant at the time of the distribution are made to unitholders. Except as otherwise provided in the Award Agreement, to the extent DERs or UDRs are subject to a Restricted Period, such amounts shall be paid to the Participant in a single lump sum no later than the 15 th day of the 3 rd calendar month following the date on which the Restricted Period ends by vesting.
7. Amendment and Termination . Except to the extent prohibited by applicable law:
     (a)  Amendments to the Plan . Except as required by the rules of the principal securities exchange or inter-dealer quotation system on which the Units are traded or listed, by the Code or by the Exchange Act or other applicable law, and subject to Section 7(b) , the Board or the Committee may amend, alter, suspend, discontinue, or terminate the Plan in any manner, including increasing the number of Units available for Awards under the Plan, without the consent of any Partner, Participant, other holder or beneficiary of an Award, or any other Person. Notwithstanding the foregoing, no amendment, alteration, suspension, discontinuance, or termination of the Plan will modify the time at which a payment related to an award that provides for the deferral of compensation within the meaning of Section 409A of the Code shall be made to any Participant except to the extent such a modification is permitted by, and in compliance with, Section 409A and the applicable guidance issued thereunder.
     (b)  Amendments to Awards . Subject to Section 7(a) , the Committee may waive any conditions or rights under, amend any terms of, or alter any Award theretofore granted, provided no change, other than pursuant to Section 6(h)(vii) or, as determined by the Committee, in its sole discretion, as being necessary or appropriate to comply with applicable law in any Award shall materially reduce the benefit of a Participant without the consent of such Participant. Notwithstanding the foregoing, if the terms of an Award would result in the imposition of the additional tax under Section 409A of the Code, the Award will be reformed, if possible, to avoid imposition of such tax in a manner that will result in the least adverse economic impact on the Participant and, for purposes of the Plan, such reformation shall be deemed not to reduce the Participant’s rights thereunder and shall not require the Participant’s consent.
8. General Provisions .
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     (a)  No Rights to Award . No Person shall have any claim to be granted any Award under the Plan, and there is no obligation for uniformity of treatment of Participants. The terms and conditions of Awards need not be the same with respect to each Participant.
     (b)  Tax Withholding . Unless other arrangements have been made that are acceptable to the Company, the Company or any Affiliate is authorized to withhold from any Award, from any payment due or transfer made under any Award or from any compensation or other amount owing to a Participant the amount (in cash, Units, other securities or property, or Units that would otherwise be issued or delivered pursuant to such Award) of any applicable taxes payable in respect of the grant or settlement of an Award, its exercise, the lapse of restrictions thereon, or any payment or transfer under an Award or under the Plan and to take such other action as may be necessary in the opinion of the Company to satisfy its withholding obligations for the payment of such taxes.
     (c)  No Right to Employment or Services . The grant of an Award shall not be construed as giving a Participant the right to be retained in the employ of the Company, the Partnership or any Affiliate or to remain a Director or continue to provide services as a Consultant, as applicable. Further, the Company, the Partnership or an Affiliate may at any time dismiss a Participant from employment or services, free from any liability or any claim under the Plan, unless otherwise expressly provided in the Plan or in any Award Agreement or other agreement.
     (d)  Governing Law . The validity, construction, and effect of the Plan and any rules and regulations relating to the Plan shall be determined in accordance with the laws of the State of Delaware without regard to its conflicts of laws principles.
     (e)  Compliance with Section 409A of the Code . Nothing in the Plan or any Award Agreement shall operate or be construed to cause the Plan or an Award, to the extent subject to Section 409A, to fail to comply with the requirements of Section 409A of the Code. With respect to any Award that is subject to Section 409A of the Code, the applicable provisions of Section 409A the Code and the regulations thereunder are hereby incorporated by reference and shall control over any provision of the Plan or any Award Agreement that is in conflict therewith. For purposes of such compliance, in the event that an Award that is subject to Section 409A of the Code is payable in connection with a Participant’s termination of service as an Employee, Consultant or Director, such payments shall be made only in connection with a “separation from service” within the meaning of Section 409A of the Code and the regulations thereunder (a “ Separation from Service ”) and the provisions of the Plan (including the adjustment provisions of Section 4(c) , Section 6(g) and Section 6(h)(vii) ) shall be applied in a manner consistent with the requirements of Section 409A. Further, notwithstanding anything to the contrary in this Plan, in the event an Award issued under the Plan is subject to Section 409A of the Code, if upon a Participant’s Separation from Service, the Participant is a “specified employee” within the meaning of Section 409A of the Code, and the deferral of any amounts or benefits otherwise payable or to be provided under any Award made pursuant to this Plan as a result of the Participant’s Separation from Service is necessary in order to prevent any accelerated or additional tax to the Participant under Section 409A of the Code, then the Company will delay the payment of any such amounts or the provision of any such benefits hereunder until the earliest of (x) the date that is six (6) months following the date of the
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Participant’s Separation from Service and (y) the date of the Participant’s death following such Separation from Service. Upon the expiration of the applicable deferral period, any delayed amounts will be paid to the Participant in a single lump sum, with interest from the date otherwise payable, at the prime rate as published in The Wall Street Journal on the Participant’s Separation from Service, and any delayed benefits will be provided on such date.
     (f)  Severability . If any provision of the Plan or any Award is or becomes or is deemed to be invalid, illegal, or unenforceable in any jurisdiction or as to any Person or Award, or would disqualify the Plan or any Award under any law deemed applicable by the Committee, such provision shall be construed or deemed amended to conform to the applicable laws, or if it cannot be construed or deemed amended without, in the determination of the Committee, materially altering the intent of the Plan or the Award, such provision shall be stricken as to such jurisdiction, Person or Award and the remainder of the Plan and any such Award shall remain in full force and effect.
     (g)  Other Laws . The Committee may refuse to issue or transfer any Units or other consideration under an Award if, in its sole discretion, it determines that the issuance or transfer of such Units or such other consideration might violate any applicable law or regulation, the rules of the principal securities exchange on which the Units are then traded, or result in recoverable short-swing profits under Section 16(b) of the Exchange Act, and any payment tendered to the Company by a Participant, other holder or beneficiary in connection with the exercise of such Award shall be promptly refunded to the relevant Participant, holder or beneficiary.
     (h)  No Trust or Fund Created . Neither the Plan nor any Award shall create or be construed to create a trust or separate fund of any kind or a fiduciary relationship between the Company or any participating Affiliate and a Participant or any other Person. To the extent that any Person acquires a right to receive payments from the Company or any participating Affiliate pursuant to an Award, such right shall be no greater than the right of any general unsecured creditor of the Company or any participating Affiliate.
     (i)  No Fractional Units . No fractional Units shall be issued or delivered pursuant to the Plan or any Award, and the Committee shall determine, in its sole discretion, whether cash, other securities, or other property shall be paid or transferred in lieu of any fractional Units or whether such fractional Units or any rights thereto shall be canceled, terminated, or otherwise eliminated, with or without consideration.
     (j)  Facility Payment . Any amounts payable hereunder to any Person under legal disability or who, in the judgment of the Committee, is unable to properly manage his or her financial affairs, may be paid to the legal representative of such Person, or may be applied for the benefit of such Person in any manner that the Committee may select, and the Company shall be relieved of any further liability for payment of such amounts.
     (k)  No Guarantee of Tax Consequences . None of the Board, the Partnership, nor the Committee makes any commitment or guarantee that any federal, state or local tax treatment will apply or be available to any person participating or eligible to participate hereunder.
 14 

 

9. Term of the Plan . The Plan shall become effective on the date of its approval by the Board and shall terminate on, and no Awards may be granted after, the earliest of (a) the date established by the Board or the Committee, (b) the 10th anniversary of the date the Plan was adopted by the Company (or such earlier anniversary, if any, required by the rules of the exchange on which Units are traded) or (c) the date Units are no longer available for delivery pursuant to Awards under the Plan. Unless otherwise expressly provided in the Plan or in an applicable Award Agreement, any Award granted prior to any Plan termination, and the authority of the Board or the Committee to amend, alter, adjust, suspend, discontinue, or terminate any such Award or to waive any conditions or rights under such Award, shall extend beyond such termination date.
[SIGNATURE ON NEXT PAGE]
 15 

 

      IN WITNESS WHEREOF , the Company has caused this instrument to be executed as of May 25, 2010 by the undersigned officer of the Company.

 	American Midstream GP, LLC
 	 	
 	/s/ Brian Bierbach  	 	
 	Brian Bierbach 	 	
 	Chief Executive Officer 	 	
 	
 16 

Exhibit 10.8
American Midstream Partners, LP
Long-Term Incentive Plan
Grant of Phantom Units
Grantee : [ • ]
Grant Date : [ • ]

1.	 	Grant of Phantom Units . American Midstream GP, LLC (the “ Company ”) hereby grants to you [ • ] Phantom Units under the American Midstream Partners, LP Long-Term Incentive Plan (the “ Plan ”) on the terms and conditions set forth herein and in the Plan, which is incorporated herein by reference as a part of this Agreement. In the event of any conflict between the terms of this Agreement and the Plan, the Plan shall control. Capitalized terms used in this Agreement but not defined herein shall have the meanings ascribed to such terms in the Plan, unless the context requires otherwise.	
 		
2.	 	Vesting . Except as otherwise provided in Paragraph 3 below, the Phantom Units granted hereunder shall vest on the anniversary of the Grant Date as follows:	
 	 	 	
Anniversary of	 	Cumulative	
Grant Date	 	Vested Percentage	
prior to 1st anniversary	 	0%	
on the 1st anniversary	 	25%	
on the 2nd anniversary	 	50%	
on the 3rd anniversary	 	75%	
on and after the 4 th anniversary	 	100%	

3.	 	Events Occurring Prior to Full Vesting .	

 	(a)	 	Death or Disability . If your employment with the Company terminates as a result of your death or Total and Permanent Disability, the Phantom Units then held by you automatically will become fully vested upon such termination. For purposes of this Agreement, your “Total and Permanent Disability” means that you are qualified for long-term disability benefits under the Company’s long-term disability plan or insurance policy; or, if no such plan or policy is then in existence or you are not eligible to participate in such plan or policy, that you, because of a physical or mental condition resulting from bodily injury, disease, or	

 

 	 	 	mental disorder, are unable to perform your duties of employment for a period of six (6) continuous months, as determined in good faith by the Committee.	
 		
 	(b)	 	Other Terminations . If your employment with the Company terminates for any reason other than as provided in Paragraph 3(a) above, all unvested Phantom Units then held by you automatically shall be forfeited without payment upon such termination.	

 	 	For purposes of this Paragraph 3, “employment with the Company” shall include being an Employee or a Director of the Company or an Affiliate.	
 		
4.	 	Payment . As soon as administratively practicable after the vesting of a Phantom Unit, but not later than seven days thereafter, you shall be paid a lump sum payment in cash equal to the Fair Market Value of one Unit as of the vesting date in settlement of such Phantom Unit; provided, however, the Committee may, in its sole discretion, direct that payment be made to you in the form of one Unit in lieu of cash. Prior to the consummation of any initial public offering of Units by the Partnership, if the Committee determines, in its sole discretion, to deliver Units in settlement of a vested Phantom Unit(s), you shall be required to execute, as a condition of delivery of such Units, a Unitholder’s agreement in a form approved by the Committee (the “ Unitholder’s Agreement ”). The Unitholder’s Agreement may contain (i) restrictions on your transfer and sale of such Units, (ii) obligations for you to sell such Units in connection with a sale of interests in the Partnership by the Company, AIM Midstream Holdings, LLC or their respective Affiliates and (iii) such other restrictions and obligations as the Committee determines, in its sole discretion, to impose, all of which will be applicable prior to the consummation of any initial public offering of Units by the Partnership. If you fail to execute such Unitholder’s Agreement within the deadline established by the Committee therefor, the vested Phantom Unit as to which such Unitholder’s Agreement was required will be cancelled without payment of any consideration therefor.	
 		
5.	 	Limitations Upon Transfer . All rights under this Agreement shall belong to you alone and may not be transferred, assigned, pledged, or hypothecated by you in any way (whether by operation of law or otherwise), other than by will or the laws of descent and distribution and shall not be subject to execution, attachment, or similar process. Upon any attempt by you to transfer, assign, pledge, hypothecate, or otherwise dispose of such rights contrary to the provisions in this Agreement or the Plan, or upon the levy of any attachment or similar process upon such rights, such rights shall immediately become null and void.	
 		
6.	 	Restrictions . By accepting this grant, you agree that any Units that you may acquire upon payment of this Award will not be sold or otherwise disposed of in any manner that would constitute a violation of any applicable federal or state securities laws. You also agree that (i) any certificates representing the Units acquired under this Award may bear such legend or legends as the Committee deems appropriate in order to assure compliance with applicable securities laws and any restrictions set forth in a Unitholder’s Agreement, (ii) the Company may refuse to register the transfer of the Units to be acquired under this Award on the transfer records of the Partnership if such proposed	
 2 

 

 	 	transfer would in the opinion of counsel satisfactory to the Partnership constitute a violation of any applicable securities law, and (iii) the Partnership may give related instructions to its transfer agent, if any, to stop registration of the transfer of the Units to be acquired under this Award.	
 		
7.	 	Withholding of Taxes . To the extent that the grant, vesting or payment of a Phantom Unit results in the receipt of compensation by you with respect to which the Company or an Affiliate has a tax withholding obligation pursuant to applicable law, unless other arrangements have been made by you that are acceptable to the Company or such Affiliate, you shall deliver to the Company or the Affiliate such amount of money as the Company or the Affiliate may require to meet its withholding obligations under such applicable law. If you fail to do so, the Company is authorized to withhold from any cash or Unit remuneration (including withholding any Units to be distributed to you under this Agreement) then or thereafter payable to you any tax required to be withheld by reason of such resulting compensation income. No payment of a vested Phantom Unit shall be made pursuant to this Agreement until you have paid or made arrangements approved by the Company or the Affiliate to satisfy in full the applicable tax withholding requirements of the Company or Affiliate with respect to such event. You may request that the Committee settle in cash, rather than in Units, a portion of any vested and payable Phantom Units to provide for the satisfaction of any tax withholding obligation resulting from such Phantom Units, and the Committee will not unreasonably withhold its approval or the Company’s performance of such request.	
 		
8.	 	Rights as Unitholder . You, or your executor, administrator, heirs, or legatees shall have the right to vote and receive distributions on Units and all the other privileges of a unitholder of the Partnership only from the date of issuance of a Unit certificate in your name representing payment of a vested Phantom Unit.	
 		
9.	 	Insider Trading Policy . The terms of the Company’s Insider Trading Policy with respect to Units are incorporated herein by reference. The timing of the delivery of any Units pursuant to a vested Phantom Unit shall be subject to and comply with such Policy.	
 		
10.	 	Binding Effect . This Agreement shall be binding upon and inure to the benefit of any successor or successors of the Company and upon any person lawfully claiming under you.	
 		
11.	 	Entire Agreement . Subject to the terms of any written employment or severance agreement between you and the Company in effect on your date of termination (the “ Employment Agreemen t”) concerning the vesting of equity-based awards, this Agreement constitutes the entire agreement of the parties with regard to the subject matter hereof, and contains all the covenants, promises, representations, warranties and agreements between the parties with respect to the Award granted hereby. To the extent such vesting terms of the Employment Agreement are more favorable to you than the vesting terms of this Agreement, the vesting terms of the Employment Agreement shall control.	
 3 

 

12.	 	Modifications . Except as provided below, any modification of this Agreement shall be effective only if it is in writing and signed by both you and an authorized officer of the Company.	
 		
13.	 	Governing Law . This grant shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to conflicts of laws principles thereof.	
 	 	 	 	 	
 	American Midstream GP, LLC
 	 	
 	By:  	 	 	
 	 	Brian F. Bierbach, President and CEO 	 	

 	Employee

 	[ • ] 	 	

 4 

Exhibit 10.9
EXECUTION VERSION

MEMBERSHIP INTERESTS
PURCHASE AND SALE AGREEMENT
by and between
ENBRIDGE MIDCOAST ENERGY, L.P.,
as “Seller”
and
AMERICAN MIDSTREAM, LLC
as “Buyer”
dated as of
October 2, 2009

   

 

TABLE OF CONTENTS

ARTICLE I DEFINITIONS AND RULES OF CONSTRUCTION	 	 	1	 	
Section 1.1 Definitions	 	 	1	 	
Section 1.2 Rules of Construction	 	 	11	 	
 	 	 	 	 	
ARTICLE II PURCHASE AND SALE; CLOSING	 	 	12	 	
Section 2.1 Purchase and Sale of the Interests	 	 	12	 	
Section 2.2 Purchase Price	 	 	12	 	
Section 2.3 The Closing	 	 	12	 	
Section 2.4 Post-Closing Purchase Price Reconciliation	 	 	14	 	
Section 2.5 Effect of Closing	 	 	15	 	
 	 	 	 	 	
ARTICLE III REPRESENTATIONS AND WARRANTIES RELATING TO SELLER	 	 	16	 	
Section 3.1 Organization of Seller	 	 	16	 	
Section 3.2 Authorization; Enforceability	 	 	16	 	
Section 3.3 No Conflict	 	 	17	 	
Section 3.4 Litigation	 	 	17	 	
Section 3.5 Brokers’ Fees	 	 	17	 	
Section 3.6 Ownership of Interests	 	 	17	 	
 	 	 	 	 	
ARTICLE IV REPRESENTATIONS AND WARRANTIES RELATING TO THE ENBRIDGE ENTITIES	 	 	18	 	
Section 4.1 Organization of Enbridge Entities	 	 	18	 	
Section 4.2 No Conflict	 	 	18	 	
Section 4.3 Subsidiaries	 	 	19	 	
Section 4.4 Financial Statements	 	 	19	 	
Section 4.5 Absence of Certain Changes	 	 	20	 	
Section 4.6 Contracts	 	 	20	 	
Section 4.7 Litigation	 	 	22	 	
Section 4.8 Employee Benefit Plans	 	 	22	 	
Section 4.9 Taxes	 	 	24	 	
Section 4.10 Environmental Matters	 	 	25	 	
Section 4.11 Legal Compliance	 	 	25	 	
Section 4.12 Permits	 	 	26	 	
Section 4.13 Title	 	 	26	 	
Section 4.14 Employees and Labor Relations	 	 	26	 	
Section 4.15 Insurance	 	 	26	 	
Section 4.16 Regulatory and Administrative Matters	 	 	26	 	
Section 4.17 Preferential Purchase Rights	 	 	27	 	
Section 4.18 Intellectual Property Rights	 	 	27	 	
 	 	 	 	 	
ARTICLE V REPRESENTATIONS AND WARRANTIES RELATING TO BUYER	 	 	27	 	
Section 5.1 Organization of Buyer	 	 	27	 	
 i 

 

 	 	 	 	 	
		
Section 5.2 Authorization; Enforceability	 	 	27	 	
Section 5.3 No Conflict	 	 	27	 	
Section 5.4 Litigation	 	 	28	 	
Section 5.5 Brokers’ Fees	 	 	28	 	
Section 5.6 Investment Representation	 	 	28	 	
Section 5.7 Funds	 	 	28	 	
Section 5.8 Ownership of Buyer	 	 	28	 	
 	 	 	 	 	
ARTICLE VI COVENANTS	 	 	29	 	
Section 6.1 Conduct of Business	 	 	29	 	
Section 6.2 Access	 	 	30	 	
Section 6.3 Third Party Approvals	 	 	31	 	
Section 6.4 Regulatory Filings	 	 	31	 	
Section 6.5 Books and Records	 	 	32	 	
Section 6.6 Employee and Benefit Matters	 	 	33	 	
Section 6.7 Excluded Assets	 	 	39	 	
Section 6.8 Seller Marks	 	 	39	 	
Section 6.9 Permits	 	 	39	 	
Section 6.10 Insurance	 	 	40	 	
Section 6.11 Guarantees	 	 	40	 	
Section 6.12 LaCrosse Option Rights	 	 	40	 	
Section 6.13 Preference Right	 	 	40	 	
Section 6.14 Damage or Casualty Loss	 	 	40	 	
Section 6.15 Confidentiality	 	 	41	 	
Section 6.16 EnerVest Contract	 	 	42	 	
Section 6.17 EOP	 	 	42	 	
Section 6.18 Certain Rights	 	 	42	 	
Section 6.19 Certain Personal Property	 	 	42	 	
Section 6.20 Transition Services Agreement	 	 	42	 	
 	 	 	 	 	
ARTICLE VII TAX MATTERS	 	 	43	 	
Section 7.1 Tax Returns	 	 	43	 	
Section 7.2 Transfer Taxes	 	 	43	 	
Section 7.3 Purchase Price Allocation	 	 	44	 	
Section 7.4 Property Tax Allocation	 	 	44	 	
Section 7.5 Tax Cooperation	 	 	44	 	
Section 7.6 Tax Indemnification	 	 	44	 	
Section 7.7 Tax Contests	 	 	45	 	
Section 7.8 Refunds	 	 	46	 	
 	 	 	 	 	
ARTICLE VIII CONDITIONS TO OBLIGATIONS	 	 	46	 	
Section 8.1 Conditions to Obligations of Buyer	 	 	46	 	
Section 8.2 Conditions to the Obligations of Seller	 	 	47	 	
 ii 

 

 	 	 	 	 	
		
ARTICLE IX INDEMNIFICATION	 	 	48	 	
Section 9.1 Survival	 	 	48	 	
Section 9.2 Indemnification	 	 	49	 	
Section 9.3 Indemnification Procedures	 	 	49	 	
Section 9.4 Limitations on Liability of Seller	 	 	51	 	
Section 9.5 Waiver of Other Representations and Warranties	 	 	51	 	
Section 9.6 Purchase Price Adjustment	 	 	52	 	
Section 9.7 Exclusive Remedy	 	 	52	 	
 	 	 	 	 	
ARTICLE X TERMINATION	 	 	53	 	
Section 10.1 Termination	 	 	53	 	
Section 10.2 Effect of Termination	 	 	53	 	
 	 	 	 	 	
ARTICLE XI MISCELLANEOUS	 	 	54	 	
Section 11.1 Notices	 	 	54	 	
Section 11.2 Assignment	 	 	55	 	
Section 11.3 Rights of Third Parties	 	 	55	 	
Section 11.4 Expenses	 	 	55	 	
Section 11.5 Counterparts	 	 	55	 	
Section 11.6 Entire Agreement	 	 	55	 	
Section 11.7 Disclosure Schedules	 	 	55	 	
Section 11.8 Amendments	 	 	56	 	
Section 11.9 Publicity	 	 	56	 	
Section 11.10 Severability	 	 	56	 	
Section 11.11 Governing Law; Jurisdiction	 	 	56	 	
Section 11.12 Further Assurances	 	 	57	 	
Section 11.13 Enbridge Entity Plan	 	 	57	 	
 iii 

 

Disclosure Schedules

Schedule 1.1(a)	 	-	 	Included Intellectual Property	
Schedule 1.1(b)	 	-	 	Certain Excluded Assets	
Schedule 1.1(c)	 	-	 	Guarantees	
Schedule 1.1(d)	 	-	 	Knowledge (Buyer)	
Schedule 1.1(e)	 	-	 	Knowledge (Seller)	
Schedule 2.4(a)	 	-	 	Form of Final Net Working Capital Statement	
Schedule 3.3	 	-	 	Seller Approvals	
Schedule 3.4	 	-	 	Litigation Relating to the Interests	
Schedule 4.3	 	-	 	Subsidiaries	
Schedule 4.4	 	-	 	Financial Matters	
Schedule 4.5	 	-	 	Absence of Certain Changes	
Schedule 4.6(a)	 	-	 	Material Contracts	
Schedule 4.6(c)	 	-	 	Material Contracts — Exceptions	
Schedule 4.7	 	-	 	Litigation Relating to Enbridge Entities	
Schedule 4.8(a)	 	-	 	Certain Seller Plans	
Schedule 4.8(c)	 	-	 	Enbridge Entity Plans	
Schedule 4.8(f)	 	-	 	Post-Employment Benefits	
Schedule 4.9	 	-	 	Taxes	
Schedule 4.10	 	-	 	Environmental Matters	
Schedule 4.11	 	-	 	Legal Compliance	
Schedule 4.12	 	-	 	Absence of Permits	
Schedule 4.13	 	-	 	Title Exceptions	
Schedule 4.15	 	-	 	Insurance	
Schedule 4.16	 	-	 	Regulatory and Administrative Matters	
Schedule 4.17	 	-	 	Preference Rights	
Schedule 5.3	 	-	 	Buyer Approvals	
Schedule 6.1	 	-	 	Conduct of Business	
Schedule 6.6(a)	 	-	 	Enbridge Entity Plan	
Schedule 6.6(b)	 	-	 	Affiliate Employees	
Schedule 6.13(a)	 	-	 	Preference Interests Allocated Purchase Price	
Schedule 6.19	 	-	 	Certain Personal Property	
Exhibits

Exhibit 1.1(a)	 	-	 	Form of Assignment of Interests	
Exhibit 1.1(b)	 	-	 	Transition Services Agreement Form	
Exhibit 1.1(c)	 	-	 	Form of Guarantee Agreement	
Exhibit 1.1(d)	 	-	 	Form of EOP GP Interest Assignment	
Exhibit 1.1(e)	 	-	 	Seller Severance Plan	
Exhibit 2.3(b)(vi)	 	-	 	Form of Non-Foreign Affidavit	
Exhibit 6.12	 	-	 	Form of LaCrosse Option Agreement	
Exhibit 6.16(a)	 	-	 	Form of EnerVest Contract Assignment	
Exhibit 6.16(b)	 	-	 	Form of Gas Purchase Contract	
 iv 

 

MEMBERSHIP INTERESTS PURCHASE AND SALE AGREEMENT
     THIS MEMBERSHIP INTERESTS PURCHASE AND SALE AGREEMENT dated as of October 2, 2009 (this “ Agreement ”), is entered into by and between Enbridge Midcoast Energy , L.P. , a Texas limited partnership (“ Seller ”), and American Midstream, LLC , a Delaware limited liability company (“ Buyer ”).
RECITALS
     WHEREAS, Seller owns all (100%) of the membership interests (the “ Interests ”) in each of Enbridge Processing (Mississippi) L.L.C., a Delaware limited liability company, Enbridge Pipelines (Midla) L.L.C., a Delaware limited liability company, Enbridge Pipelines (Alabama Intrastate) L.L.C., an Alabama limited liability company, Enbridge Pipelines (Bamagas Intrastate) L.L.C., a Delaware limited liability company (“ Enbridge Bamagas ”), Enbridge Pipelines (Tennessee River) L.L.C., an Alabama limited liability company, Enbridge Pipelines (Alabama Gathering) L.L.C., an Alabama limited liability company, Enbridge Pipelines (AlaTenn) L.L.C., an Alabama limited liability company, Midcoast Holdings No. One, L.L.C., a Delaware limited liability company, and Mid Louisiana Gas Transmission, L.L.C., a Delaware limited liability company (“ MLGT ”) (collectively referred to herein as the “ Enbridge Entities ” and individually referred to herein as an “ Enbridge Entity ”); and
     WHEREAS, Seller desires to sell to Buyer, and Buyer desires to purchase from Seller, the Interests.
     NOW, THEREFORE, in consideration of the premises and mutual covenants contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows:
ARTICLE I
DEFINITIONS AND RULES OF CONSTRUCTION
      Section 1.1 Definitions . As used herein, the following terms shall have the following meanings:
     “ Accountant ” has the meaning set forth in Section 2.4(d) .
     “ Affiliate ” means, with respect to any Person, any other Person that, directly or indirectly, controls, is controlled by or is under common control with, such specified Person through one or more intermediaries or otherwise. For the purposes of this definition, “control” means, where used with respect to any Person, the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities, by contract or otherwise, and the terms “controlling” and “controlled” have correlative meanings.
     “ Affiliate Employees ” has the meaning set forth in Section 6.6(b) .
     “ Agreement ” has the meaning set forth in the Preamble to this Membership Interests Purchase and Sale Agreement.

 

     “ Alliance Refinery Retained Liability ” means any costs and expenses to the extent resulting from or relating to the tank overflow of volumes from the Lafitte Pipeline System which occurred at the COP Alliance Refinery near Belle Chase, Louisiana on November 20, 2008.
     “ AM Marketing ” means American Midstream Marketing, LLC, a Delaware limited liability company and a wholly owned, indirect subsidiary of Buyer.
     “ Assignment of Interests ” means the Assignment of Membership Interests in the form attached as Exhibit 1.1(a) to this Agreement.
     “ Bamagas Preference Right ” has the meaning set forth in Section 6.13(b) .
     “ Base Purchase Price ” has the meaning set forth in Section 2.2 .
     “ Benefit Plan ” means (a) each “employee benefit plan,” as such term is defined in Section 3(3) of ERISA, (b) each plan that would be an employee benefit plan if it was subject to ERISA, such as plans for directors, (c) each stock bonus, stock ownership, stock option, stock purchase, stock appreciation rights, phantom stock or other stock plan (whether qualified or nonqualified), (d) each bonus, deferred compensation or incentive compensation plan, (e) each employment, consulting, severance pay, change in control, or other plan, arrangement, policy or commitment, and (f) any holiday or vacation practice, or workers compensation plan or program.
     “ Business ” means the business and operations of the Enbridge Entities and Enbridge Entities Subsidiaries as currently conducted by the Enbridge Entities and Enbridge Entities Subsidiaries.
     “ Business Day ” means any day that is not a Saturday, Sunday or legal holiday in the State of Texas or a federal holiday in the United States of America.
     “ Buyer ” has the meaning set forth in the Preamble to this Agreement.
     “ Buyer Approvals ” has the meaning set forth in Section 5.3 .
     “ Buyer Indemnified Parties ” has the meaning set forth in Section 9.2(a) .
     “ Buyer’s Auditors ” has the meaning set forth in Section 6.5(c) .
     “ Buyer Guarantee ” means that certain Guarantee Agreement dated of even date herewith by American Infrastructure MLP Fund, L.P., American Infrastructure MLP Private Equity Fund, L.P., and American Infrastructure MLP Associates Fund, L.P. to and in favor of Seller.
     “ Buyer Tax Act ” has the meaning set forth in Section 7.6 .
     “ CAP ” has the meaning set forth in the definition of Harmony Plant Retained Liability set forth in this Section 1.1 .
     “ Casualty Loss ” has the meaning set forth in Section 6.14(a) .
 2 

 

     “ Cause ” has the meaning set forth in Section 6.6(g) .
     “ Claim Notice ” has the meaning set forth in Section 9.3(a) .
     “ Closing ” has the meaning set forth in Section 2.3(a) .
     “ Closing Date ” has the meaning set forth in Section 2.3(a) .
     “ Code ” means the Internal Revenue Code of 1986, as amended.
     “ Commonly Controlled Entity ” means each trade or business, whether or not incorporated, that together with Seller would be treated as a “single employer” under Code Section 414.
     “ Confidentiality Agreement ” means that certain Confidentiality Agreement dated effective as of April 27, 2009, by and between American Infrastructure MLP Funds, L.P. and Seller.
     “ Continuing Employee ” has the meaning set forth in Section 6.6(c) .
     “ Contract ” means any legally binding agreement, commitment, lease, license or contract, whether oral or written.
     “ Disclosure Schedules ” means the schedules attached hereto.
     “ Dollars ” and “ $ ” means the lawful currency of the United States of America.
     “ EEP ” means Enbridge Energy Partners, L.P., a Delaware limited partnership.
     “ EES ” means Enbridge Employee Services, Inc., a Delaware corporation.
     “ Effective Time ” means, if the Closing occurs on November 2, 2009, 12:01 a.m. (Central Time) on November 1, 2009; provided , however , if the Closing Date (i) is extended to December 1, 2009 pursuant to Section 6.13(b) , the “Effective Time” shall mean 12:01 a.m. (Central Time) on December 1, 2009 or (ii) occurs on the first day of any other month pursuant to Section 2.3(a) , the “Effective Time” shall mean 12:01 a.m. ( Central Time) on such day.
     “ EH ” means Enbridge Holdings (Texas Systems) L.L.C., a Delaware limited liability company and a wholly owned subsidiary of Seller.
     “ EMLP ” means Enbridge Marketing (U.S.) L.P., a Texas limited partnership and a wholly owned, indirect subsidiary of EEP.
     “ Enbridge Bamagas ” has the meaning set forth in the Recitals to this Agreement.
     “ Enbridge Entities ” has the meaning set forth in the Recitals to this Agreement.
     “ Enbridge Entity ” has the meaning set forth in the Recitals to this Agreement.
 3 

 

     “ Enbridge Entity Plan ” means each Benefit Plan that is sponsored by an Enbridge Entity or Enbridge Entity Subsidiary.
     “ Enbridge Entities Subsidiaries ” means each of Enbridge Pipelines (Louisiana Intrastate) L.L.C., Enbridge Pipelines (SIGCO Intrastate) L.L.C. and EOP.
     “ Enbridge Entity Subsidiary ” means any of the Enbridge Entities Subsidiaries, individually.
     “ EnerVest Contract ” means that certain Gas Purchase Contract dated July 1, 2001, by and between EnerVest Monroe Marketing, Ltd., as “Seller”, and Midcoast Marketing, Inc., as “Buyer”, as amended pursuant to that certain (a) Amended and Restated Gas Purchase Contract dated effective July 1, 2001, as amended January 1, 2003, by and between EnerVest Monroe Marketing, Ltd., as “Seller”, and EMLP, as “Buyer”, and (b) Amendment to Gas Purchase Contract dated effective as of November 1, 2005, by and between EMLP and EnerVest Monroe Marketing, Ltd.
     “ EnerVest Contract Assignment ” has the meaning set forth in Section 6.16(a) .
     “ Entities Liabilities ” means all obligations and liabilities of any kind whatsoever of the Enbridge Entities or Enbridge Entities Subsidiaries arising from or relating to the Interests or the Business, whether known or unknown, liquidated or contingent, and regardless of whether the same are deemed to have arisen, accrued or are attributable to periods before, on or after the Effective Time.
     “ Environmental Law ” means any applicable Law relating to the environment, natural resources, or the protection thereof, including any applicable provisions of the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq. , the Hazardous Materials Transportation Act, 49 U.S.C. § 5101 et seq. , the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq. , the Clean Water Act, 33 U.S.C. § 1251 et seq. , the Clean Air Act, 42 U.S.C. § 7401 et seq. , the Toxic Substances Control Act, 15 U.S.C. § 2601 et seq. , the Federal Insecticide, Fungicide, and Rodenticide Act, 7 U.S.C. § 136 et seq. , and the Oil Pollution Act of 1990, 33 U.S.C. § 2701 et seq. , and all analogous state or local statutes, and the regulations promulgated pursuant thereto.
     “ Environmental Permit ” means all permits, licenses, approvals, authorizations, consents or registrations required by any applicable Environmental Law.
     “ EOP ” means Enbridge Offshore Pipelines (Seacrest) L.P., a Texas limited partnership.
     “ EOP GP Interest ” has the meaning set forth in Section 6.17 .
     “ EOP GP Interest Assignment ” means the Assignment of Partnership Interest in the form attached as Exhibit 1.1(d) to this Agreement.
     “ EPLL ” means Enbridge Pipelines (Louisiana Liquids) L.L.C., a Delaware limited liability company.
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     “ ERISA ” means the Employee Retirement Income Security Act of 1974, as amended.
     “ Estimated Net Working Capital ” means $0.
     “ Excluded Assets ” means (a) other than those described in Schedule 1.1(a) (the “ Included Intellectual Property ”), all system applications, licenses for computer or communications software and other intellectual property used in connection with the Business, including, without limitation, those described in Schedule 1.1(b) , (b) each Contract between a Seller or an Affiliate of a Seller (other than any of the Enbridge Entities or Enbridge Entities Subsidiaries), on the one hand, and any of the Enbridge Entities or Enbridge Entities Subsidiaries, on the other hand, other than those listed under item (iv) on Schedule 4.6(a) , (c) the membership interests of EPLL, which are owned by MLGT, and (d) all items retained by Seller in accordance with Section 2.5(a) .
     “ FERC ” means the Federal Energy Regulatory Commission.
     “ Final Net Working Capital ” has the meaning set forth in Section 2.4(a) .
     “ Final Net Working Capital Statement ” has the meaning set forth in Section 2.4(a) .
     “ Financial Data ” has the meaning set forth in Section 4.4(b) .
     “ Financial Statements ” has the meaning set forth in Section 4.4(a) .
     “ GAAP ” means generally accepted accounting principles of the United States of America, consistently applied.
     “ Gas Purchase Contract ” has the meaning set forth in Section 6.16(b) .
     “ General Proceedings ” means all Proceedings other than Other Proceedings.
     “ Governmental Authority ” means any federal, state, municipal, local or similar governmental authority, regulatory or administrative agency, court or arbitral body.
     “ Guarantees ” means the guarantees, letters of credit, bonds, sureties and other credit support or assurances for the benefit of the Enbridge Entities or Enbridge Entities Subsidiaries listed on Schedule 1.1(c) .
     “ Guarantee Agreement ” means the Guarantee Agreement from EEP for the benefit of Buyer in the form attached as Exhibit 1.1(c) to this Agreement.
     “ Harmony Plant Retained Liability ” means any and all costs and expenses associated with the implementation of the Correction Action Plan (the “ CAP ”) submitted on November 20, 2008 to the Mississippi Department of Environmental Quality to remediate the groundwater impact that exists as a result of the historical operation of the Harmony Processing Plant and any and all Losses arising from any Proceeding relating to the release, leak, contamination, leaching or other occurrence from operations at the Harmony Processing Plant that resulted in the
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groundwater impact that is the subject of the CAP (whether or not such Proceeding is commenced before or after Closing).
     “ HSR Act ” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.
     “ Included Intellectual Property ” has the meaning set forth in the definition of Excluded Assets set forth in this Section 1.1 .
     “ Indemnified Party ” has the meaning set forth in Section 9.3(a) .
     “ Indemnifying Party ” has the meaning set forth in Section 9.3(a) .
     “ Interests ” has the meaning set forth in the Recitals to this Agreement.
     “ Knowledge ” as to Buyer means the actual knowledge of any fact, circumstance or condition by any of the Persons listed in Schedule 1.1(d) and as to Seller means the actual knowledge of any fact, circumstance or condition by any of the Persons listed in Schedule 1.1(e) . The foregoing references to “actual knowledge” of a Person means information actually personally known by such Person, excluding any information which may be imputed to such Person by Law.
     “ LaCrosse Option Agreement ” has the meaning set forth in Section 6.12 .
     “ Law ” means any applicable law, rule, regulation, ordinance, order, judgment or decree of a Governmental Authority and any applicable common law.
     “ LIBOR ” means the rate for any one month loan which appears on Page 3750 of the Dow Jones Market Service (or on any successor or substitute page of such service, or any successor to or substitute for such service, providing rate quotations comparable to those currently provided on such page of such service, for purposes of providing quotations of interest rates applicable to Dollar deposits in the London interbank market) at approximately 11:00 a.m., London time, two Business Days prior to the commencement of any period for which interest may be due under this Agreement.
     “ Lien(s) ” means any charges, pledges, options, reversionary rights, mortgages, deeds of trust, hypothecations, security interests, and other encumbrances.
     “ Losses ” means all actual liabilities, losses, damages, claims, awards, causes of action, fines, penalties, costs and expenses (including reasonable fees and expenses of counsel); provided , however , that Losses shall not include any special, punitive, exemplary, incidental, consequential or indirect damages or any lost profits, lost benefits, loss of enterprise value, diminution in value of any business, damage to reputation or loss to goodwill; provided , further , however , that the preceding proviso shall not apply to the extent a Party is required to pay such damages to a third party in connection with a matter for which such Party is entitled to indemnification under Article IX .
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     “ Material Adverse Effect ” means any circumstance, change or effect that is materially adverse to the Business or the assets, properties, operations or financial condition of the Enbridge Entities and Enbridge Entities Subsidiaries, taken as a whole, or materially and adversely affects the ability of Seller to consummate the transactions contemplated by this Agreement, but shall exclude any circumstance, change or effect resulting or arising from:
     (i) any change in general economic conditions (including any change in prices for natural gas or other commodities) in the industries or markets in which any Enbridge Entity or Enbridge Entity Subsidiary operates or conducts business;
     (ii) seasonal reductions in revenues and/or earnings of any Enbridge Entity or Enbridge Entity Subsidiary in the ordinary course of its business;
     (iii) national or international political conditions, including any engagement in hostilities, whether or not pursuant to the declaration of a national emergency or war, or the occurrence of any military or terrorist attack;
     (iv) changes in GAAP;
     (v) the entry into or announcement of this Agreement;
     (vi) matters that will be reflected in the determination of Final Net Working Capital; and
     (vii) the loss of any employee involved in the Business.
     “ Material Contracts ” has the meaning set forth in Section 4.6(a) .
     “ Midla Retained Liability ” means any costs or expenses to the extent resulting from or relating to the leak which occurred on September 2, 2001 on the Midla Pipeline System near mile marker 2.25 located 2.25 miles south of Midla’s Desaird Compressor Station, and resulted in a Department of Transportation Corrective Action Order, in docket CPF No. 4-200-1006-H.
     “ MLGT ” has the meaning set forth in the Recitals to this Agreement.
     “ Net Working Capital ”, which may be positive or negative, means an amount equal to the total current assets of the Enbridge Entities and Enbridge Entities Subsidiaries minus the total current liabilities of the Enbridge Entities and Enbridge Entities Subsidiaries (excluding for purposes of such calculation any current assets or liabilities related to the following: debt; Taxes; prepaid insurance relating to Seller’s Policies; other Excluded Assets; other than gas imbalances, (i) trade payables, accounts payable and other similar costs and expenses for which Seller retains liability pursuant to Section 2. 5(b) and (ii) proceeds, accounts receivable, income, revenues, monies and other items belonging to Seller pursuant to Section 2.5(a) ; or transactions with Affiliates of the Enbridge Entities or the Enbridge Entities Subsidiaries (other than one of the other Enbridge Entities or the Enbridge Entities Subsidiaries) to the extent related to an Excluded Asset or Taxes of the Enbridge Entities or the Enbridge Entities Subsidiaries), in each case determined (a) in accordance with GAAP, and (b) without giving effect to the transactions contemplated hereby.
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     “ Organizational Documents ” means any charter, certificate of incorporation, certificate of formation, articles of association, bylaws, operating agreement, partnership agreement or similar formation or governing documents and instruments.
     “ Other Proceedings ” means claims and investigations that constitute Proceedings.
     “ Operations Employees ” has the meaning set forth in Section 6.6(b) .
     “ Parties ” means Seller and Buyer.
     “ PBGC ” has the meaning set forth in Section 4.8(d) .
     “ Permits ” means authorizations, licenses, permits or certificates issued by Governmental Authorities; provided , however , right-of-way agreements and similar rights and approvals are not included in the definition of Permits.
     “ Permitted Liens ” means:
     (a) preferential purchase rights applicable to this or to any future transaction;
     (b) third-party consent and notice requirements and similar restrictions with respect to which waivers or consents are obtained by Seller from the appropriate parties prior to the Closing Date or the appropriate time period for asserting the right has expired or which, in the case of notice requirements, need not be satisfied prior to transfer;
     (c) Liens for current Taxes or assessments not yet delinquent or, if delinquent, being contested in good faith by appropriate actions;
     (d) materialmans’, mechanics’, repairmans’, workers’, contractors’, operators’, carriers’ and other similar liens and charges arising in the ordinary course of business for amounts not yet delinquent (including any amounts being withheld as provided by Law), or if delinquent, being contested in good faith by appropriate actions;
     (e) all rights to consent by, required notices to, filings with, or other actions by Governmental Authorities in connection with the sale or conveyance of the Interests if they are not required to be obtained prior to the sale or conveyance and will not subject Buyer or any of the Enbridge Entities or Enbridge Entities Subsidiaries to any liability or disability after the Closing due to the failure to make or obtain same prior to Closing;
     (f) all rights reserved to or vested in any Governmental Authority to control or regulate any of the assets of any Enbridge Entity or Enbridge Entity Subsidiary in any manner and all obligations and duties under all Laws of such Governmental Authority or under any franchise, grant, license or permit issued by any such Governmental Authority;
     (g) imbalances associated with any of the assets of any Enbridge Entity or Enbridge Entity Subsidiary;
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     (h) defects based solely on (i) the fact that information, whether in paper or electronic format, may be missing from the books and records of Seller maintained by or on behalf of or relating to the Enbridge Entities, the Enbridge Entities Subsidiaries or the Business; provided , however , that any fact, circumstances, event, development, change or condition constituting the missing information or any portion thereof shall not constitute a Permitted Lien; or (ii) references to document(s) if such referenced document(s) do not constitute a defect;
     (i) with respect to assets and properties owned by any of the Enbridge Entities or Enbridge Entities Subsidiaries, defects arising out of lack of corporate or other entity authorization unless the action was not authorized and is affirmatively established by documentation to result in another party’s actual and superior claim of title to the relevant interest;
     (j) defects that have been cured by Laws of limitations or prescription;
     (k) reversionary rights contained in easements, rights-of-way and similar agreements; and
     (l) any other agreements, instruments, liens, charges, encumbrances, defects, discrepancies or irregularities in title which do not, individually or in the aggregate, interfere in any material respect with the value, operation or ownership of the assets, business and operations of the Enbridge Entity or Enbridge Entity Subsidiary (as currently conducted by such Enbridge Entity or Enbridge Entity Subsidiary) to which they relate, including, without limitation, the terms of the agreements referenced in Schedule 4.17 .
     “ Person ” means any individual, firm, corporation, partnership, limited liability company, incorporated or unincorporated association, joint venture, joint stock company, Governmental Authority or other entity of any kind.
     “ Pre-Closing Tax Period ” means (i) any Tax period ending on or before the day before the day that includes the Effective Time and (ii) the portion of any Straddle Period that ends on the day before the day that includes the Effective Time.
     “ Preference Interests ” has the meaning set forth in Section 6.13(a) .
     “ Preference Right ” has the meaning set forth in Section 4.17 .
     “ Proceedings ” means all proceedings, actions, claims, suits and investigations by and before any mediator, arbitrator, or Governmental Authority.
     “ Property Taxes ” has the meaning set forth in Section 7.4 .
     “ Purchase Price ” has the meaning set forth in Section 2.2 .
     “ Qualifying Offer ” has the meaning set forth in Section 6.6(b) .
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     “ Reasonable Efforts ” means efforts in accordance with reasonable commercial practice and without the incurrence of unreasonable expense.
     “ Related Agreements ” means the Transition Services Agreement, the Guarantee Agreement, the LaCrosse Option Agreement, and any other document or agreement delivered at the Closing pursuant to Section 2.3 .
     “ Representatives ” means, as to any Person, its officers, directors, employees, counsel, accountants, financial advisers and consultants.
     “ SEC ” has the meaning set forth in Section 6.5(c) .
     “ Seller ” has the meaning set forth in the Preamble to this Agreement.
     “ Seller Approvals ” has the meaning set forth in Section 3.3 .
     “ Seller Indemnified Parties ” has the meaning set forth in Section 9.2(c) .
     “ Seller Marks ” has the meaning set forth in Section 6.8 .
     “ Seller Plan ” means each Benefit Plan (including any Enbridge Entity Plan) that is or was sponsored, maintained, contributed to or required to be contributed to by Seller or by any Commonly Controlled Entity.
     “ Seller’s Policies ” has the meaning set forth in Section 4.15 .
     “ Seller Retained Liabilities ” means all liabilities and obligations of any kind whatsoever of the Enbridge Entities arising from (i) the Alliance Refinery Retained Liability, (ii) the Harmony Plant Retained Liability, (iii) the Midla Retained Liability, (iv) the Excluded Assets, (v) any business sold by any Enbridge Entity or Enbridge Entity Subsidiary to a third party from and after October 1, 2002, (vi) the accounts payable and other costs and expenses retained by Seller pursuant to Section 2.5(b) , (vii) claims raised by EnerVest Monroe Marketing, Ltd. (or any successor to the interest of EnerVest Monroe Marketing, Ltd.) under the EnerVest Contract as a result of any matter which occurred prior to the Effective Time, (viii) the Seller Plans other than the Seller Plan listed on Schedule 4.8(c) , and (ix) the pending insurance claims described in Schedule 4.15 , in each case, whether known or unknown, liquidated or contingent, and, other than in the case of items (vii) and (ix) above, regardless of whether the same are deemed to have arisen, accrued, or are attributable to periods before, on, or after the Effective Time.
     “ Seller Severance Plan ” means that certain U.S. Enbridge Natural Gas Operations Severance Plan, effective June 1, 2009, attached as Exhibit 1.1(e) to this Agreement and excluding any amendments thereto.
     “ Severance Pay Amount ” has the meaning set forth in Section 6.6(g) .
     “ Straddle Period ” has the meaning set forth in Section 7.4 .
     “ Support Employees ” has the meaning set forth in Section 6.6(b) .
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     “ Tax ” or “ Taxes ” means any federal, state, local or foreign income, gross receipts, license, payroll, employment, excise, severance, premium, windfall profits, environmental, customs duties, capital stock, capital gain, petroleum profits, value added, franchise, profits, withholding, social security (or similar), unemployment, disability, real property, personal property, sales, use, transfer, registration, minimum, alternative or add-on minimum, estimated or other tax of any kind whatsoever, including any interest, penalty or addition thereto, whether disputed or not. For purposes of this Agreement, “ Tax ” or “ Taxes ” also includes any obligation under any Law, agreement or arrangement with any other Person with respect to Taxes of such other Person (including pursuant to Treasury Regulation Section 1.1502-6 or comparable provisions of state, local or foreign tax Law) and including any liability for Taxes of any predecessor entity.
     “ Tax Authority ” means any Governmental Authority having jurisdiction over the assessment, determination, collection or imposition of any Tax.
     “ Tax Claim ” has the meaning set forth in Section 7.7(a) .
     “ Tax Returns ” means any report, return, election, document, estimated tax filing, declaration or other filing provided to any Tax Authority including any amendments thereto.
     “ Third Party Claim ” has the meaning set forth in Section 9.3(a) .
     “ Transfer Taxes ” has the meaning set forth in Section 7.2 .
     “ Transition Services Agreement ” has the meaning set forth in Section 6.20 .
     “ Transition Services Agreement Form ” means the form of the Transition Services Agreement attached as Exhibit 1.1(b) to this Agreement.
     “ Weekly Base Pay ” means, in the case of a Continuing Employee who is paid a salary, his or her annualized base salary as reflected on the Buyer’s payroll records on the date of such Continuing Employee’s date of termination divided by 52, and in the case of a Continuing Employee who is paid an hourly wage, his or her hourly wage rate as reflected on the Buyer’s payroll records on the date of such Continuing Employee’s date of termination multiplied by 40.
     “ Welfare Benefits ” has the meaning set forth in Section 6.6(f) .
      Section 1.2 Rules of Construction .
     (a) All article, section, schedule and exhibit references used in this Agreement are to articles, sections, schedules and exhibits to this Agreement unless otherwise specified. The schedules and exhibits attached to this Agreement constitute a part of this Agreement and are incorporated herein for all purposes.
     (b) If a term is defined as one part of speech (such as a noun), it shall have a corresponding meaning when used as another part of speech (such as a verb). Terms defined in the singular have the corresponding meanings in the plural, and vice versa. Unless the context of this Agreement clearly requires otherwise, words importing the
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masculine gender shall include the feminine and neutral genders and vice versa. The term “includes” or “including” shall mean “including without limitation.” The words “hereof,” “hereto,” “hereby,” “herein,” “hereunder” and words of similar import, when used in this Agreement, shall refer to this Agreement as a whole and not to any particular section or article in which such words appear.
     (c) The Parties acknowledge that each Party and its attorney have reviewed this Agreement and that any rule of construction to the effect that any ambiguities are to be resolved against the drafting Party, or any similar rule operating against the drafter of an agreement, shall not be applicable to the construction or interpretation of this Agreement.
     (d) The captions in this Agreement are for convenience only and shall not be considered a part of or affect the construction or interpretation of any provision of this Agreement.
     (e) All references to currency herein shall be to, and all payments required hereunder shall be paid in, Dollars.
     (f) All accounting terms used herein and not expressly defined herein shall have the meanings given to them under GAAP.
     (g) Any event hereunder requiring the payment of cash or cash equivalents and any action to be taken hereunder on a day that is not a Business Day shall be deferred until the first Business Day occurring after such day.
ARTICLE II
PURCHASE AND SALE; CLOSING
      Section 2.1 Purchase and Sale of the Interests . At the Closing, upon the terms and subject to the conditions set forth in this Agreement, Seller shall sell, assign, transfer and convey to Buyer, and Buyer shall purchase and acquire from Seller, the Interests.
      Section 2.2 Purchase Price . The aggregate consideration payable by Buyer to Seller for the Interests shall consist of One Hundred Fifty Million Eight Hundred Seventeen Thousand Eight Hundred Ninety-Eight and No/100 Dollars ($150,817,898.00) (the “ Base Purchase Price ”), as adjusted in accordance with Section 2.4 and Section 6. 13(b) (the “ Purchase Price ”).
      Section 2.3 The Closing .
     (a) The closing of the transactions contemplated by this Agreement (the “ Closing ”) shall take place at the offices of Fulbright & Jaworski L.L.P., Fulbright Tower, 1301 McKinney, Suite 5100, Houston, Texas 77010, commencing at 10:00 a.m. local time on (i) November 2, 2009, or if all conditions in Article VIII to be satisfied at Closing have not yet been satisfied or waived, then on the first day of the month immediately following the date on which such conditions have been satisfied or waived subject to the rights of the Parties set forth in Article X , or (ii) such other date as Buyer
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and Seller may mutually determine (the “ Closing Date ”). The Closing shall be deemed to have been consummated at the Effective Time.
     (b) At the Closing, Seller will deliver the following documents and deliverables to Buyer:
     (i) the Assignment of Interests, duly executed by Seller;
     (ii) the Transition Services Agreement, duly executed by EES;
     (iii) the Guarantee Agreement, duly executed by EEP;
     (iv) the resignations (or evidence of removal) of each officer and director of each Enbridge Entity, effective as of the Effective Time;
     (v) the certificate referenced in Section 8.1(d) , duly executed by Seller;
     (vi) a non-foreign affidavit, as such affidavit is referred to in Section 1445(b)(2) of the Code, in the form attached hereto as Exhibit 2. 3(b)(vi) , duly executed by EEP (the Person from whom Seller is disregarded as an entity for U.S. federal income tax purposes);
     (vii) the LaCrosse Option Agreement, duly executed by Seller or any Affiliate of Seller;
     (viii) the EnerVest Contract Assignment, duly executed by EMLP;
     (ix) the Gas Purchase Contract, duly executed by EMLP;
     (x) the EOP GP Interest Assignment, duly executed by EH;
     (xi) evidence of receipt of each of Seller Approvals (other than any Seller Approval constituting a notice requirement that by the terms of such requirement is not required to be satisfied prior to the Closing Date, provided that Seller shall undertake to provide such notice after Closing) and any other consents and waivers of any other Person, if any, required for Seller to enter into this Agreement and complete the transactions contemplated herein; and
     (xii) such other certificates, instruments and documents as may be reasonably requested by Buyer prior to the Closing Date to carry out the intent and purposes of this Agreement.
     (c) At the Closing, Buyer will deliver the following documents and deliverables to Seller:
     (i) the Assignment of Interests, duly executed by Buyer;
     (ii) the Transition Services Agreement, duly executed by Buyer;
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     (iii) an amount equal to the Base Purchase Price by wire transfer of immediately available funds to an account or accounts specified by Seller;
     (iv) the certificate referenced in Section 8.2(d) , duly executed by Buyer;
     (v) the LaCrosse Option Agreement, duly executed by MLGT;
     (vi) the EnerVest Contract Assignment, duly executed by AM Marketing;
     (vii) the Gas Purchase Contract, duly executed by AM Marketing;
     (viii) the EOP GP Interest Assignment, duly executed by Buyer;
     (ix) evidence of receipt of each of Buyer Approvals and any other consents and waivers of any other Person, if any, required for Buyer to enter into this Agreement and complete the transactions contemplated herein; and
     (x) such other certificates, instruments and documents as may be reasonably requested by Seller prior to the Closing Date to carry out the intent and purposes of this Agreement.
      Section 2.4 Post-Closing Purchase Price Reconciliation .
     (a) The Net Working Capital as of the Effective Time (the “ Final Net Working Capital ”) shall be determined in accordance with GAAP and with the procedures set forth in this Section 2.4 and the Final Net Working Capital as so determined shall be final and binding on Buyer and Seller. As soon as reasonably practicable following the Closing Date, and in any event within ninety (90) days thereafter, Seller shall prepare and deliver to Buyer a calculation of the Final Net Working Capital in substantially the form of Schedule 2.4(a) , together with reasonably detailed supporting information (the “ Final Net Working Capital Statement ”).
     (b) From and after the date Seller delivers to Buyer the Final Net Working Capital Statement, Seller shall provide Buyer and its Representatives full access to the records of the Enbridge Entities to the extent related to the Final Net Working Capital and shall cause the employees of Seller to cooperate with Buyer and the Enbridge Entities in connection with Buyer’s review of the Final Net Working Capital Statement.
     (c) Within sixty (60) days after Buyer’s receipt of the Final Net Working Capital Statement, Buyer shall notify Seller as to whether Buyer agrees or disagrees with the Final Net Working Capital Statement and, if Buyer disagrees, such notice shall set forth in reasonable detail the particulars of such disagreement. If Buyer provides a notice of agreement or does not provide a notice of disagreement within such sixty (60) day period, then Buyer shall be deemed to have accepted the calculations and the amounts set forth in the Final Net Working Capital Statement delivered by Seller, which shall then be final, binding and conclusive for all purposes hereunder. If any such notice of
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disagreement is timely provided, then Buyer and Seller shall each use Reasonable Efforts for a period of thirty (30) days thereafter to resolve any disagreements with respect to the calculations in the Final Net Working Capital Statement and the determination of the Final Net Working Capital.
     (d) If, at the end of the thirty (30) day resolution period, the Parties are unable to resolve any disagreements as to items in the Final Net Working Capital Statement, then PricewaterhouseCoopers, LLP (or such other independent accounting firm of recognized national standing as may be mutually selected by Buyer and Seller) shall resolve any remaining disagreements. If PricewaterhouseCoopers, LLP is not willing or able to serve in such capacity, then Seller shall within ten (10) days deliver to Buyer a listing of three other accounting firms of recognized national or regional standing that do not have a current relationship with Seller or any of its Affiliates and Buyer shall within ten (10) days after receipt of such list, select one of such three accounting firms (such firm as is ultimately selected pursuant to the aforementioned procedures being the “ Accountant ”). The Accountant shall be charged with determining as promptly as practicable, but in any event within thirty (30) days after the date on which such dispute is referred to the Accountant, any disputed items required to determine the Final Net Working Capital. The Accountant will act as an arbitrator to determine and resolve, based solely on presentations by Buyer and Seller, and not by independent review, only those issues still in dispute. The costs and expenses of the Accountant shall be borne 50% by Seller and 50% by Buyer. The determination of the Accountant shall be final, binding and conclusive for all purposes hereunder. Such amounts as finally determined by the Accountant shall be used to determine the Purchase Price.
     (e) Within five (5) Business Days of the date on which the last disputed item required to determine the Final Net Working Capital is resolved pursuant to this Section 2.4 (whether by agreement of the Parties, any failure by Buyer to provide a timely notice of disagreement pursuant to subsection (c) or a final determination by the Accountant pursuant to subsection (d)), (i) if the Final Net Working Capital exceeds the Estimated Net Working Capital, then Buyer shall pay to Seller an amount equal to the excess of the Final Net Working Capital over the Estimated Net Working Capital, or (ii) if the Estimated Net Working Capital exceeds the Final Net Working Capital, then Seller shall pay to Buyer an amount equal to the excess of the Estimated Net Working Capital over the Final Net Working Capital, in each case together with interest at a rate equal to LIBOR (determined, as applicable, on the Closing Date and at the end of each 30 day period thereafter) plus 1% on such excess from the Closing Date to the date of payment.
      Section 2.5 Effect of Closing .
     (a) Buyer covenants and agrees that (except for gas imbalances) all proceeds, accounts receivable, income, revenues, monies and other items included in or attributable to the Enbridge Entities and Enbridge Entities Subsidiaries for periods prior to the Effective Time (in each case, whether or not recorded in the financial statements or financial data of the Enbridge Entities or Enbridge Entities Subsidiaries on the Closing Date) shall belong to Seller and, following the Closing, Buyer shall cause the Enbridge
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Entities and Enbridge Entities Subsidiaries to use Reasonable Efforts to collect same on Seller’s behalf. Seller acknowledges and agrees that all other proceeds, accounts receivable, income, revenues, monies and other items included in or attributable to the Enbridge Entities or Enbridge Entities Subsidiaries shall belong to the applicable Enbridge Entities or the applicable Enbridge Entities Subsidiaries.
     (b) Seller covenants and agrees that (except for gas imbalances) all trade or accounts payable and other similar costs and expenses payable for materials, equipment, goods, utilities and services furnished to or performed for the Enbridge Entities and Enbridge Entities Subsidiaries prior to the Effective Time, together with rent payable by the Enbridge Entities and Enbridge Entities Subsidiaries for equipment or other property leased by the Enbridge Entities and Enbridge Entities Subsidiaries and accruing prior to the Effective Time (in each case, whether or not recorded in the financial statements or financial data of the Enbridge Entities or Enbridge Entities Subsidiaries on the Closing Date) shall be the obligation of and be paid by Seller. Buyer acknowledges and agrees that all other accounts payable and other similar costs and expenses shall be the obligation of and be paid by the applicable Enbridge Entities or the applicable Enbridge Entities Subsidiaries.
     (c) If monies are received by any Party which, under the terms of this Section 2.5 , belong to the other Party, the same shall promptly be paid over to the proper Party. If an invoice or other evidence of an obligation is received which, under the terms of this Section 2.5 , is partially the obligation of each of Seller and Buyer, then the Parties shall consult each other and each shall promptly pay its portion of such obligation to the obligee.
ARTICLE III
REPRESENTATIONS AND WARRANTIES RELATING TO SELLER
     Seller hereby represents and warrants to Buyer as follows:
      Section 3.1 Organization of Seller . Seller is a limited partnership, duly formed, validly existing and in good standing under the Laws of the State of Texas.
      Section 3.2 Authorization; Enforceability . (a) Seller and each Affiliate of Seller entering into a Related Agreement in connection herewith has all requisite power and authority to execute and deliver this Agreement and such Related Agreement to which it is a party and to perform all obligations to be performed by it hereunder and thereunder, (b) the execution and delivery of this Agreement and each such Related Agreement and the consummation of the transactions contemplated hereby and thereby have been duly and validly authorized and approved by all requisite partnership, limited liability company or corporate action on the part of Seller and such Seller Affiliate, and (c) this Agreement has been and each of such Related Agreements will be duly and validly executed and delivered by Seller and such Seller Affiliate, and this Agreement constitutes and each such Related Agreement will constitute a valid and binding obligation of Seller and such Seller Affiliate, enforceable against Seller and such Seller Affiliate in accordance with its terms, subject to applicable bankruptcy, insolvency, fraudulent
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conveyance, reorganization, moratorium and similar Laws affecting creditors’ rights generally and subject, as to enforceability, to general principles of equity.
      Section 3.3 No Conflict . The execution and delivery of this Agreement by Seller and the execution and delivery of each Related Agreement by Seller and/or each Affiliate of Seller entering into a Related Agreement in connection herewith and the consummation of the transactions contemplated hereby and thereby (assuming all required filings, consents, approvals, authorizations and notices set forth in Schedule 3.3 (collectively, the “ Seller Approvals ”) have been made, given or obtained and the procedures relating to each Preference Right set forth on Schedule 4.17 have been followed) do not and shall not:
     (a) violate any Organizational Document of Seller and such Seller Affiliate; or
     (b) except as would not reasonably be expected to have a Material Adverse Effect, (i) violate any Law applicable to Seller or such Seller Affiliate or require any filing with, consent, approval or authorization of, or notice to, any Governmental Authority or (ii) (A) breach the terms of any contract, agreement, lease, mortgage, indenture, license, franchise, or other instrument to which Seller or such Seller Affiliate is a party or by which Seller or such Seller Affiliate (or its properties and assets) may be bound, (B) result in the termination of any such contract, agreement, lease, mortgage, indenture, license, franchise, or other instrument, or (C) result in the creation of any Lien upon any of the Interests or the assets and properties of Seller, such Seller Affiliate, the Enbridge Entities or the Enbridge Entities Subsidiaries other than obligations imposed by or resulting from this Agreement or the Related Agreements.
      Section 3.4 Litigation . Except as set forth on Schedule 3.4 , (a) there are no General Proceedings pending or, to the Knowledge of Seller, there are no Other Proceedings pending and there are no Proceedings threatened in writing against Seller with respect to the Interests that, if determined or resolved adversely, would reasonably be expected to have a material and adverse impact on the ability of Seller to perform its obligations under this Agreement or to result in any Losses of any of the Enbridge Entities or, without duplication, the Enbridge Entities Subsidiaries exceeding $500,000, individually or in the aggregate, and (b) there are no material orders or unsatisfied judgments from any Governmental Authority binding upon Seller with respect to the Interests.
      Section 3.5 Brokers’ Fees . No broker, finder, investment banker or other Person is entitled to any brokerage fee, finders’ fee or other commission in connection with the transactions contemplated by this Agreement based upon arrangements made by Seller or any of its Affiliates except for fees and commissions which are payable by Seller.
      Section 3.6 Ownership of Interests .
     (a) Seller holds of record and owns beneficially the Interests free and clear of any Liens other than transfer restrictions imposed thereon by applicable securities Laws.
     (b) There are no outstanding options, warrants, rights or other securities convertible into or exchangeable or exercisable for equity securities in any of the
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Enbridge Entities or the Enbridge Entities Subsidiaries, any other commitments or agreements providing for the issuance of additional equity interests in any of the Enbridge Entities or the Enbridge Entities Subsidiaries or the repurchase or redemption of equity interests in any of the Enbridge Entities or the Enbridge Entities Subsidiaries, and there are no agreements of any kind which may obligate any of the Enbridge Entities or the Enbridge Entities Subsidiaries to issue, purchase, redeem or otherwise acquire any of its equity interests. There are no voting agreements, proxies or other similar agreements or understandings with respect to the equity interests of any of the Enbridge Entities or the Enbridge Entities Subsidiaries.
ARTICLE IV
REPRESENTATIONS AND WARRANTIES RELATING TO
THE ENBRIDGE ENTITIES
     Seller hereby represents and warrants to Buyer as follows:
      Section 4.1 Organization of Enbridge Entities . Each Enbridge Entity and each of the Enbridge Entities Subsidiaries is duly organized, validly existing and in good standing under the Laws of its respective jurisdiction of formation and has the requisite limited liability company or limited partnership, as applicable, power and authority to own or lease its assets and to conduct its business as it is now being conducted. Each Enbridge Entity and each of the Enbridge Entities Subsidiaries is duly licensed or qualified in each jurisdiction in which the ownership or operation of its assets or the character of its activities is such as to require it to be so licensed or qualified.
      Section 4.2 No Conflict . The execution and delivery of this Agreement by Seller and the consummation of the transactions contemplated hereby by Seller (assuming all of the Seller Approvals have been made, given or obtained and the procedures relating to each Preference Right set forth on Schedule 4.17 have been followed) do not and shall not:
     (a) violate any Organizational Document of the Enbridge Entities or the Enbridge Entities Subsidiaries; or
     (b) except as would not reasonably be expected to have a Material Adverse Effect or to result in any Losses of any of the Enbridge Entities or, without duplication, the Enbridge Entities Subsidiaries exceeding $500,000, individually or in the aggregate, (i) violate any Law applicable to any of the Enbridge Entities or the Enbridge Entities Subsidiaries or its assets or require any filing with, consent, approval or authorization of, or notice to, any Governmental Authority or (ii) (A) breach the terms of any contract, agreement, lease, mortgage, indenture, license, franchise, or other instrument to which any of the Enbridge Entities or the Enbridge Entities Subsidiaries is a party or by which any of the Enbridge Entities or the Enbridge Entities Subsidiaries (or its properties and assets) are bound, (B) result in the termination of any such contract, agreement, lease, mortgage, indenture, license, franchise, or other instrument, or (C) result in the creation of any Lien upon any of the Interests or the assets or properties of any of the Enbridge Entities or the Enbridge Entities Subsidiaries other than obligations imposed by this Agreement or the Related Agreements.
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      Section 4.3 Subsidiaries . Except as set forth in Schedule 4.3 , no Enbridge Entity or Enbridge Entity Subsidiary owns, either directly or indirectly, any equity interests in any Person.
      Section 4.4 Financial Statements .
     (a) Seller has previously delivered to Buyer the audited financial statements of FERC regulated interstate pipeline companies that constitute Enbridge Entities as of and for the years ended December 31, 2007 and December 31, 2008, and the unaudited financial statements for such FERC regulated interstate pipeline companies as of and for the six-month periods ended June 30, 2008 and June 30, 2009 (collectively, the “ Financial Statements ”). Except as disclosed on Schedule 4.4 , the Financial Statements were prepared in accordance with the accounting requirements of FERC, as set forth in its applicable Uniform System of Accounts and published accounting releases. Except as disclosed on Schedule 4.4 , the Financial Statements present fairly in all material respects the results of operations and cash flows of the Enbridge Entity to which they relate for the respective period covered, and the balance sheets present fairly in all material respects their financial condition as of their respective dates.
     (b) Seller has previously delivered to Buyer true, complete and correct copies of unaudited trial balances financial data, for the fiscal year ended December 31, 2008 and for the six-month periods ended June 30, 2008 and June 30, 2009, related to the business and operations of the Enbridge Entities and Enbridge Entities Subsidiaries for the respective periods covered thereby (the “ Financial Data ”), including FERC filings for the interstate natural gas entities that constitute Enbridge Entities for the years then ended. Except as disclosed on Schedule 4.4 , the Financial Data was prepared based on the books and records of Seller on a consistent basis throughout the periods covered thereby.
     (c) To the Knowledge of Seller and except as disclosed on Schedule 4.4 , the Financial Data fairly presents the gross product and transportation revenues, total product purchases, other cost of sales, imbalance settlement costs, operating expenses and capital expenditures with respect to the business and operations of the Enbridge Entities and Enbridge Entities Subsidiaries for the respective periods indicated therein.
     (d) None of the Enbridge Entities or the Enbridge Entities Subsidiaries has any off-balance sheet arrangements that have or are reasonably likely to have a current or future material effect on the financial condition, change in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources of the Enbridge Entities and the Enbridge Entities Subsidiaries on a consolidated basis.
     (e) EEP has established and maintains disclosure controls and procedures that are designed to ensure that material information relating to EEP is made known to its ultimate parent company’s principal executive officer and its principal financial officer by others within that entity. To Seller’s Knowledge, there are no significant deficiencies, including material weaknesses, in the design or operation of internal controls over EEP’s financial reporting.
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     (f) No Enbridge Entity or Enbridge Entity Subsidiary has any liability or obligation except (i) liabilities reflected in the Financial Statements and the Financial Data, (ii) liabilities which have arisen since March 31, 2009, in the ordinary course of business consistent with past practice, (iii) liabilities disclosed on Schedule 4.4 , and (iv) other liabilities which, individually or in the aggregate, have not had and would not be reasonably expected to have a Material Adverse Effect.
      Section 4.5 Absence of Certain Changes . Except as disclosed on Schedule 4.5 , since June 30, 2009, (a) there has not been any Material Adverse Effect, (b) the Business has been conducted, in all material respects, only in the ordinary course consistent with past practices (except to the extent contemplated by Section 6.7 , Section 6.11 , Section 6.12 and Section 6.16 ), (c) no Enbridge Entity or Enbridge Entity Subsidiary has incurred any material liability or entered into any material agreement, in each case, outside the ordinary course of business consistent with past practice, and (d) the Enbridge Entities and Enbridge Entities Subsidiaries have not made any material change in the compensation levels of their senior executives, any changes in the manner in which other employees of the Enbridge Entities or the Enbridge Entities Subsidiaries are generally compensated, or any provision of additional or supplemental benefits for employees of the Enbridge Entities or the Enbridge Entities Subsidiaries, generally, except normal periodic increases or promotions effected in the ordinary course of business consistent with past practice. Except as disclosed on Schedule 4.5 , since June 30, 2009 through the date of this Agreement, other than losses, damages, destruction or other casualty that are not, individually or in the aggregate, material, no Enbridge Entity or Enbridge Entity Subsidiary has suffered any unrepaired loss, damage, destruction, or other casualty to any of its property, plant, equipment, or inventories (whether or not covered by insurance).
      Section 4.6 Contracts .
     (a) Schedule 4.6(a) contains a true and complete listing of the following Contracts to which any of the Enbridge Entities or the Enbridge Entities Subsidiaries is a party or by which any of the assets of the Enbridge Entities or the Enbridge Entities Subsidiaries is bound as of the date of this Agreement and will be bound after the Closing (the Contracts listed on Schedule 4.6(a) being “ Material Contracts ”):
     (i) each natural gas gathering, processing, sales, storage, or transportation Contract which generated revenues in February, 2009;
     (ii) each Contract involving a remaining commitment to pay capital expenditures in excess of $50,000 in any single calendar year or $100,000 in the aggregate;
     (iii) each Contract for lease of personal property or real property or lease of pipeline capacity involving aggregate payments in excess of $50,000 in 2009 or in any single future calendar year;
     (iv) each Contract between Seller or an Affiliate of Seller (other than an Enbridge Entity or Enbridge Entity Subsidiary), on the one hand, and an
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Enbridge Entity or Enbridge Entity Subsidiary, on the other hand, which will survive the Closing;
     (v) each Contract that provides for a limit on the ability of an Enbridge Entity or Enbridge Entity Subsidiary to compete in any line of business or with any Person or in any geographic area during any period of time after the Closing;
     (vi) any note, loan, evidence of indebtedness, letter of credit or guarantee of the indebtedness or performance of any obligations of another Person;
     (vii) any Contract that grants to any Person any right of first refusal, right of first offer or participation right in any future business, business opportunity or expansion;
     (viii) any employment agreement or any other contractual right that provides for (A) continued employment with, or retention by, any Enbridge Entity or Enbridge Entity Subsidiary or (B) any payments due or payable as a result of this Agreement or the consummation of the transactions contemplated by this Agreement;
     (ix) any obligation to make deferred cash purchase price payments to a third party after the Closing Date arising out of or relating to the acquisition of any business or assets of any Enbridge Entity or Enbridge Entity Subsidiary;
     (x) any joint venture, joint development, partnership or similar agreement;
     (xi) any natural gas or other futures or options trading agreement or any price swaps, hedges, futures or similar instruments;
     (xii) documents granting any power of attorney with respect to the material affairs of any Enbridge Entity or Enbridge Entity Subsidiary;
     (xiii) stockholder agreements or agreements relating to the issuance of any securities or ownership interests of the Enbridge Entities or the Enbridge Entities Subsidiaries or the granting of any registration rights with respect thereto;
     (xiv) any operational balancing agreement relating to the gas volumes of any Enbridge Entity or Enbridge Entity Subsidiary;
     (xv) any Tax sharing agreement;
     (xvi) any collective bargaining agreement; and
     (xvii) except for Contracts of the nature described in clauses (i) through (xvi) above, each Contract to which an Enbridge Entity or Enbridge Entity Subsidiary is a party or by which its assets are bound involving aggregate
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payments or receipts in excess of $250,000 in 2009 or in any single future calendar year that cannot be terminated by such Enbridge Entity or Enbridge Entity Subsidiary upon sixty (60) days or less notice without payment penalty.
     (b) True and complete copies of all Material Contracts as amended and modified through the date of this Agreement (other than any Material Contracts that contain confidentiality provisions prohibiting their disclosure) have been made available to Buyer.
     (c) Except as set forth in Schedule 4.6(c) , each Material Contract (i) is in full force and effect and (ii) represents the legal, valid and binding obligation of the applicable Enbridge Entity or Enbridge Entity Subsidiary, enforceable by it in all material respects in accordance with its terms, except as the enforceability may be limited by applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium and similar Laws affecting creditors’ rights generally and subject to general principles of equity. Except as set forth in Schedule 4.6(c) , neither the applicable Enbridge Entity or Enbridge Entity Subsidiary nor, to the Knowledge of Seller, any other party thereto is in breach of, in any material respect, any Material Contract, and neither Seller nor the applicable Enbridge Entity or Enbridge Entity Subsidiary has received any written notice of termination or material breach of any Material Contract.
      Section 4.7 Litigation . Except as set forth in Schedule 4.7 , (a) there are no General Proceedings pending or, to the Knowledge of Seller, there are no Other Proceedings pending and there are no Proceedings threatened in writing against any Enbridge Entity or Enbridge Entity Subsidiary that, if determined or resolved adversely, would reasonably be expected to have a material and adverse impact on the ability of Seller to perform its obligations under this Agreement or to result in Losses of any of the Enbridge Entities or, without duplication, the Enbridge Entities Subsidiaries exceeding $500,000, individually or in the aggregate, and (b) there is no injunction or material order or unsatisfied judgment pending against any Enbridge Entity from any Governmental Authority.
      Section 4.8 Employee Benefit Plans .
     (a) Except as set forth Schedule 4.8(a) , neither the execution and delivery of this Agreement nor the consummation of the transactions contemplated hereby will (either alone or in conjunction with any other event, such as termination of employment): (i) result in any payment (including, without limitation, severance, unemployment compensation, parachute or otherwise) becoming due to any Affiliate Employee under the terms of any Seller Plan, (ii) increase any benefits otherwise payable under any Seller Plan, or (iii) result in any acceleration of the time of payment or vesting of benefits under the terms of any Seller Plan. Seller has made available true and complete copies of all plan documents, texts and agreements and summary plan descriptions for each Seller Plan relevant to the items set forth in Schedule 4.8(a) .
     (b) Each Seller Plan which is intended to qualify under Section 401(a) of the Code has either received a favorable determination letter from the IRS as to its qualified status or the remedial amendment period for such Seller Plan has not yet expired, and
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each trust established in connection with any Seller Plan which is intended to be exempt from federal income taxation under Section 501(a) of the Code is so exempt, and to the Seller’s Knowledge (i) no fact or event has occurred that could adversely affect the qualified status of any such Seller Plan or the exempt status of any such trust, and (ii) there has been no prohibited transaction (within the meaning of Section 406 of ERISA or Section 4975 of the Code, other than a transaction that is exempt under a statutory or administrative exemption) with respect to any Seller Plan that could result in material liability to the Seller or a Commonly Controlled Entity. No General Proceeding has been brought or, to the Knowledge of the Seller, no Other Proceeding has been brought and no Proceeding is threatened, against or with respect to any such Seller Plan, including any audit or inquiry by the IRS or United States Department of Labor (other than routine benefits claims).
     (c) Each Seller Plan has been administered in all material respects in accordance with its terms and all applicable Laws, including ERISA and the Code, and contributions required to be made under the terms of any of the Seller Plans as of the date of this Agreement have been timely made or, if not yet due, have been properly accrued prior to the date of this Agreement. Every Enbridge Entity Plan is set forth in Schedule 4.8(c) . With respect to the Seller Plans (other than any Enbridge Entity Plan), no event has occurred and there exists no condition or set of circumstances in connection with which the Buyer or any Enbridge Entity or any Enbridge Entity Subsidiary could be subject to or incur any liens, material Losses or other material liabilities (other than those set forth in Schedule 4.8(c) with respect to each Enbridge Entity Plan noted therein) under the terms of, or with respect to, such Seller Plans, ERISA, the Code or any other applicable Law. With respect to each Enbridge Entity Plan, Seller has made available to Buyer true and complete copies of all plan documents, trust agreements and other related agreements, the three most recent Forms 5500 filed with the IRS and the related summary annual report distributed to participants (if applicable), and the three most recent actuarial reports; all summary plan descriptions and summaries of material modifications required by ERISA or other applicable Law; all correspondence with the IRS or the United States Department of Labor relating to plan qualification, filings of required forms and plan audits by a Governmental Authority; and a list of all participants and their dependents and beneficiaries benefitting under such Enbridge Entity Plan as of the date of this Agreement.
     (d) With respect to each Seller Plan that is subject to Title IV or Part 3 of Title I of ERISA or Section 412 of the Code (other than a “multiemployer plan” within the meaning of Section 4001(a)(3) of ERISA), (i) no “reportable event” (within the meaning of Section 4043 of ERISA, other than an event for which the reporting requirements have been waived by regulations) has occurred or is expected to occur, (ii) there was not an “accumulated funding deficiency” (within the meaning of Section 302 of ERISA or Section 412 of the Code), whether or not waived, as of the most recently ended plan year of such Seller Plan, (iii) there is no “unfunded benefit liability” (within the meaning of Section 4001(a)(18) of ERISA, but excluding from the definition of “current value” of “assets” accrued but unpaid contributions), (iv) the Seller and each Commonly Controlled Entity has made when due any “required installments” within the meaning of Section 412(m) of the Code and Section 302(e) of ERISA, whichever may
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apply, (v) neither the Seller nor any Commonly Controlled Entity is required to provide security under Section 401(a)(29) of the Code, (vi) all premiums (and interest charges and penalties for late payment, if applicable) have been paid when due to the Pension Benefit Guaranty Corporation (“ PBGC ”), and (vii) no filing has been made by the Seller or any Commonly Controlled Entity with the PBGC and no General Proceeding has been commenced by the PBGC (and, in the case of an Other Proceeding, to the Knowledge of Seller, no such Other Proceeding has been commenced by the PBGC) to terminate any Seller Plan and, to the Knowledge of Seller, no condition exists which could constitute grounds for the termination of any such Seller Plan by the PBGC.
     (e) With respect to each Seller Plan that is a multiemployer plan (within the meaning of Section 4001(a)(3) of ERISA) (i) neither the Seller nor any Commonly Controlled Entity has incurred any withdrawal liability under Section 4201 of ERISA nor does the Seller or any Commonly Controlled Entity expect to withdraw in a “complete withdrawal” or “partial withdrawal” within the meaning of Sections 4203 and 4205 of ERISA, (ii) all contributions required to be made to any such Seller Plan have been timely made, and (iii) no such multiemployer plan has been terminated or has been in or is about to be in reorganization under ERISA so as to result directly or indirectly in any increase in contributions under Section 4243 of ERISA or in liability contingent or otherwise to the Seller or any Commonly Controlled Entity.
     (f) Except as required by Law, no Seller Plan, other than any set forth in Schedule 4.8(f) , (i) provides any of the following retiree or post-employment benefits to any Affiliate Employee: medical, disability or life insurance benefits, in any way that such benefits would become an obligation or liability of Buyer in any respect, or (ii) is a voluntary employee’s beneficiary association under Section 501(c)(9) of the Code.
      Section 4.9 Taxes . Except as set forth on Schedule 4.9 , (a) each of the Enbridge Entities and Enbridge Entities Subsidiaries has duly and timely filed (including extensions) all Tax Returns required to be filed by it under applicable Law and all such Tax Returns were accurate and complete in all material respects and were prepared in material compliance with all applicable Laws, (b) all Taxes owed by or with respect to each of the Enbridge Entities and Enbridge Entities Subsidiaries (whether disputed or not and whether or not shown or required to be shown on any Tax Return) have been timely paid in full, (c) none of the Enbridge Entities and Enbridge Entities Subsidiaries is currently the beneficiary of any extension of time within which to file any Tax Return, (d) none of such Tax Returns of or with respect to any of the Enbridge Entities and Enbridge Entities Subsidiaries is currently under audit or examination by any Tax Authority; to the Knowledge of Seller, none of the Enbridge Entities and Enbridge Entities Subsidiaries has received any information request or written notice of inquiry from any Tax Authority; and there are no outstanding requests for rulings with any Tax Authority, (e) except for Liens for Taxes not yet due and payable, there are no Liens on any of the assets of the Enbridge Entities or the Enbridge Entities Subsidiaries that have arisen as a result of any failure (or alleged failure) to pay any Tax, (f) no Enbridge Entity or Enbridge Entity Subsidiary (i) is a party to, or is bound by, any Tax allocation, Tax indemnity, Tax sharing, or similar agreement or arrangement that imposes or could impose liability on any Enbridge Entity or Enbridge Entity Subsidiary for the Taxes of another Person, (ii) has any liability for the Taxes of another Person under Treasury Regulation Section 1.1502-6 or any other provision of applicable Law, including
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as a transferee or successor, or (iii) is a party to any record retention, transfer pricing, closing, or other agreement or arrangement with any Tax Authority related to Taxes of or with respect to any Enbridge Entity or Enbridge Entity Subsidiary that will survive the Closing or impose any liability on any Enbridge Entity or Enbridge Entity Subsidiary after Closing, (g) each Enbridge Entity and Enbridge Entity Subsidiary has withheld and timely paid to the applicable Tax Authority all Taxes required to have been withheld and paid by it, (h) there is no dispute or claim concerning any Tax liability of any Enbridge Entity or Enbridge Entity Subsidiary claimed or raised by any Tax Authority in writing, (i) no Enbridge Entity or Enbridge Entity Subsidiary has any outstanding agreements or waivers extending the statutory period of limitations applicable to the assessment of any Tax or the filing of any Tax Return, (j) each Enbridge Entity and Enbridge Entity Subsidiary is currently, and has been from the date of its organization, disregarded as an entity separate from EEP for U.S. federal income tax purposes as described in Treasury Regulations Section 301.7701-3, and (k) no Enbridge Entity or Enbridge Entity Subsidiary has made an election (nor will such election be made prior to the Closing Date) to be treated as an association taxable as a corporation for U.S. federal income Tax purposes.
      Section 4.10 Environmental Matters . Except as set forth on Schedule 4.10 or as would not reasonably be expected to have a Material Adverse Effect or result in any Losses of the Enbridge Entities or, without duplication, the Enbridge Entities Subsidiaries exceeding $5,000,000, individually or in the aggregate, (i) the Enbridge Entities and the Enbridge Entities Subsidiaries and their respective operations are in compliance with all Environmental Laws, (ii) the Enbridge Entities and the Enbridge Entities Subsidiaries possess, and are in compliance with, all Environmental Permits required under all applicable Environmental Laws, such Environmental Permits are in full force and effect, and none of the Enbridge Entities or the Enbridge Entities Subsidiaries has received written notice of violation of any such Environmental Permit; (iii) there have been no pipeline ruptures resulting in injury, loss of life, or property damage, except to the extent that any liabilities or costs arising as a result of such pipeline ruptures have been fully resolved so that Seller does not reasonably expect that the Enbridge Entities or Enbridge Entities Subsidiaries will incur liabilities or costs related thereto after the Closing Date; (iv) none of the Enbridge Entities or the Enbridge Entities Subsidiaries is the subject of any outstanding order or judgment from a Governmental Authority under Environmental Laws requiring remediation or payment of a fine; (v) neither Seller nor any of the Enbridge Entities and Enbridge Entities Subsidiaries have received any written notice of any liability or violation by any Governmental Authority under any Environmental Law, other than such notices that have been resolved with the applicable Governmental Authority without any liability or cost related thereto after the Closing Date; and (vi) no condition exists on any property currently owned or leased by the Enbridge Entities or Enbridge Entities Subsidiaries which would subject any Enbridge Entity or Enbridge Entity Subsidiary or such property to any remedial obligations or liabilities (including liabilities to third parties or to private tort plaintiffs) under any Environmental Laws.
      Section 4.11 Legal Compliance . Except with respect to (a) matters set forth in Schedule 4.7 and Schedule 4.11 , (b) compliance with Laws concerning Taxes (as to which certain representations and warranties are made pursuant to Section 4.9 ) and (c) compliance with Environmental Laws (as to which certain representations and warranties are made pursuant to Section 4.10 ), the Enbridge Entities and Enbridge Entities Subsidiaries are in compliance with
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all applicable Laws except for noncompliances which would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.
      Section 4.12 Permits . Except as set forth on Schedule 4.12 , the Enbridge Entities and Enbridge Entities Subsidiaries possess all material Permits necessary for them to own their assets and operate the Business. All such Permits are in full force and effect, each Enbridge Entity and Enbridge Entity Subsidiary is in compliance with all such Permits in all material respects, there are no lawsuits or other proceedings before any Governmental Authority pending or threatened in writing that seek the revocation, cancellation, suspension or material adverse modification thereof, and none of the Enbridge Entities has received written notification of a material violation of any such Permits.
      Section 4.13 Title . Except as would not reasonably be expected to have a Material Adverse Effect or result in any Losses of the Enbridge Entities or, without duplication, Enbridge Entities Subsidiaries exceeding $1,500,000, individually or in the aggregate, and except as disclosed on Schedule 4.13 , (a) one of more of the Enbridge Entities and Enbridge Entities Subsidiaries own or have the right to use all real property interests necessary for the operation of the Business and (b) each of such real property interests is free and clear of all Liens (other than Permitted Liens) granted or suffered by any action of any Enbridge Entity or Enbridge Entity Subsidiary or any Person claiming by, through or under any Enbridge Entity or Enbridge Entity Subsidiary.
      Section 4.14 Employees and Labor Relations . No Enbridge Entity or Enbridge Entity Subsidiary directly employs any individual nor has directly employed any individual in the past five years. No Enbridge Entity or Enbridge Entity Subsidiary is a party to any collective bargaining agreement.
      Section 4.15 Insurance . Schedule 4.15 sets forth a true and complete list of all of the policies of insurance carried by Seller or any Enbridge Entity or Enbridge Entity Subsidiary that insure the operation of the Business and the assets of any Enbridge Entity or Enbridge Entity Subsidiary on or prior to the Closing Date (the “ Seller’s Policies ”). All premiums due and payable with respect to the Seller’s Policies have been timely paid. No written notice of cancellation of, or written notice of an intention not to renew, any of Seller’s Policies has been received by Seller or any Enbridge Entity or Enbridge Entity Subsidiary. Set forth on Schedule 4.15 is an accurate and complete list of all claims pending as of the date of this Agreement in excess of $50,000 made by, or related to, the Enbridge Entities or Enbridge Entities Subsidiaries under any of the Seller’s Policies, including the following information with respect to each accident, loss, or other event: (i) the identity of the claimant; (ii) the date of the occurrence; (iii) the status as of the report date; and (iv) the amounts paid or expected to be paid or recovered.
      Section 4.16 Regulatory and Administrative Matters . Except as disclosed on Schedule 4.16 , there are no administrative or regulatory General Proceedings pending or, to the Knowledge of Seller, there are no administrative or regulatory Other Proceedings pending and there are no administrative or regulatory Proceedings threatened, against any Enbridge Entity or Enbridge Entity Subsidiary that challenge the rates, charges and/or fees for transportation or gathering services or any other terms and conditions of service currently in effect under the tariff or tariffs or gathering or transportation agreements, currently in effect or the result of which
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would be to materially change, alter, or modify the rates, charges and/or fees for gas transportation or gathering service or any other terms and conditions of service currently in effect under the tariff or tariffs or gathering or transportation agreements currently in effect.
      Section 4.17 Preferential Purchase Rights . Schedule 4.17 lists all of the preferential purchase rights or options or other purchase rights held by any Person to purchase or acquire any of the Interests or any of the assets of the Enbridge Entities or Enbridge Entities Subsidiaries, which are triggered as a result of the execution of this Agreement by Seller or the sale by Seller to Buyer of the Interests as contemplated by this Agreement (a “ Preference Right ”).
      Section 4.18 Intellectual Property Rights . Subject to Buyer obtaining the appropriate licenses by the Closing, the Enbridge Entities or Enbridge Entities Subsidiaries shall continue to have the right to use the Included Intellectual Property following the Closing of the transactions contemplated under this Agreement so long as such licenses are maintained in full force and effect.
ARTICLE V
REPRESENTATIONS AND WARRANTIES RELATING TO BUYER
     Buyer hereby represents and warrants to Seller as follows:
      Section 5.1 Organization of Buyer . Buyer is a limited liability company duly organized, validly existing and in good standing under the Laws of the State of Delaware.
      Section 5.2 Authorization; Enforceability . (a) Buyer and each Affiliate of Buyer entering into a Related Agreement in connection herewith has all requisite power and authority to execute and deliver this Agreement and such Related Agreement to which it is a party and to perform all obligations to be performed by it hereunder and thereunder, (b) the execution and delivery of this Agreement and each such Related Agreement and the consummation of the transactions contemplated hereby and thereby have been duly and validly authorized and approved by all requisite limited liability company action on the part of Buyer and such Buyer Affiliate, and (c) this Agreement has been and each of such Related Agreements will be duly and validly executed and delivered by Buyer and such Buyer Affiliate, and this Agreement constitutes and each such Related Agreement will constitute a valid and binding obligation of Buyer and such Buyer Affiliate, enforceable against Buyer and such Buyer Affiliate in accordance with its terms, subject to applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium and similar Laws affecting creditors’ rights generally and subject, as to enforceability, to general principles of equity.
      Section 5.3 No Conflict . The execution and delivery of this Agreement by Buyer and the execution and delivery of each Related Agreement by Buyer and/or each Affiliate of Buyer entering into a Related Agreement in connection herewith and the consummation of the transactions contemplated hereby and thereby (assuming all required filings, consents, approvals, authorizations and notices set forth in Schedule 5.3 (collectively, the “ Buyer Approvals ”) have been made, given or obtained) does not and shall not:
     (a) violate any Organizational Document of Buyer or such Buyer Affiliate; or
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     (b) except as would not reasonably be expected to have a material and adverse impact on the ability of Buyer to enter into and perform its obligations under this Agreement, (i) violate any Law applicable to Buyer or such Buyer Affiliate or require any filing with, consent, approval or authorization of, or notice to, any Governmental Authority or (ii)(A) breach the terms of any contract, agreement, lease, mortgage, indenture, license, franchise or other instrument to which Buyer or such Buyer Affiliate is a party or by which Buyer or such Buyer Affiliate (or its properties or assets) may be bound, (B) result in the termination of any such contract, agreement, lease, mortgage, indenture, license, franchise or other instrument, or (C) result in the creation of any Lien upon any of the properties or assets of Buyer or such Buyer Affiliate.
      Section 5.4 Litigation . (a) There are no General Proceedings pending or, to the Knowledge of Buyer, there are no Other Proceedings pending and there are no Proceedings threatened in writing against Buyer that would reasonably be expected to have a material and adverse impact on the ability of Buyer to perform its obligations under this Agreement and (b) there are no orders or unsatisfied judgments from any Governmental Authority binding upon Buyer that would reasonably be expected to have a material and adverse impact on the ability of Buyer to perform its obligations under this Agreement.
      Section 5.5 Brokers’ Fees . No broker, finder, investment banker or other Person is entitled to any brokerage fee, finders’ fee or other commission in connection with the transactions contemplated by this Agreement based upon arrangements made by Buyer or any of its Affiliates except for fees and commissions which are payable by Buyer.
      Section 5.6 Investment Representation . Buyer is purchasing the Interests for its own account with the present intention of holding the Interests for investment purposes and not with a view to or for sale in connection with any public distribution of the Interests in violation of any federal or state securities Laws. Buyer has such knowledge and experience in financial and business matters that it is capable of evaluating the merits and risks of an investment in the Interests. Buyer acknowledges that the Interests have not been registered under applicable federal and state securities Laws and that the Interests may not be sold, transferred, offered for sale, pledged, hypothecated or otherwise disposed of unless such transfer, sale, assignment, pledge, hypothecation or other disposition is registered under applicable federal and state securities Laws or pursuant to an exemption from registration under any federal or state securities Laws.
      Section 5.7 Funds . At Closing, Buyer will have sufficient funds available to enable Buyer to consummate the transactions contemplated hereby and to pay the Purchase Price and all related fees and expenses of Buyer.
      Section 5.8 Ownership of Buyer . No Person owning, directly or indirectly, an interest in American Midstream Holdings, LLC has the right to receive fifty percent (50%) or more of (a) the profits of Buyer or (b) the assets of Buyer upon the dissolution of Buyer, such that American Midstream Holdings, LLC is not treated as the “ultimate parent entity” of Buyer under the HSR Act or the rules or regulations promulgated thereunder.
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ARTICLE VI
COVENANTS
      Section 6.1 Conduct of Business . From the date of this Agreement through the Closing, except as set forth on Schedule 6.1 , as contemplated by Section 6.7 , Section 6.11 , Section 6.12 and Section 6.16 , or as consented to by Buyer in writing (which consent shall not be unreasonably withheld, conditioned or delayed), Seller shall cause the Business to be operated in the ordinary course (including the expenditure of capital reasonably necessary to maintain the Business), consistent with past practices and shall use Reasonable Efforts to cause the Enbridge Entities or Enbridge Entities Subsidiaries to maintain, preserve, and protect their material assets, rights, and properties. Without limiting the foregoing, prior to Closing, Seller shall not permit any Enbridge Entity or Enbridge Entity Subsidiary, without the prior written consent of Buyer (which consent shall not be unreasonably withheld, conditioned or delayed), to:
     (a) amend its certificate of formation or operating agreement or other governing instruments in a manner which would reasonably be expected to adversely impact Buyer;
     (b) (i) issue or sell any limited liability company interests or any other securities or equity equivalents; or (ii) amend in any material respect any of the terms of any such securities outstanding as of the date hereof;
     (c) (i) reclassify its limited liability company interests or outstanding equity; (ii) repurchase, redeem or otherwise acquire any of its securities; or (iii) adopt a plan of complete or partial liquidation or resolutions providing for or authorizing a liquidation, dissolution, merger, consolidation, restructuring, recapitalization, or other reorganization;
     (d) (i) create, incur, guarantee, or assume any indebtedness for borrowed money or otherwise become liable or responsible for the obligations of any other Person; (ii) make any loans, advances, or capital contributions to, or investments in, any other Person; or (iii) mortgage or pledge any of its assets, tangible or intangible, or, except in the ordinary course of business consistent with past practices, create any Liens thereupon;
     (e) except to the extent contemplated by Section 6.7 , acquire, sell, lease, transfer, or otherwise dispose of, directly or indirectly, any assets outside the ordinary course of business, consistent with past practices;
     (f) acquire (by merger, consolidation, or acquisition of stock or assets or otherwise) any corporation, partnership, or other business organization or division thereof;
     (g) except in the ordinary course of business consistent with past practices, amend, modify, or change in any material respect or assign, terminate or enter into any Material Contract ( provided , however , that Seller shall furnish Buyer with a copy of any such new Material Contract entered into between the date of this Agreement and the Closing);
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     (h) except in the ordinary course of business consistent with past practices, declare or pay any dividends or make any distributions in respect of its member interests or other equity securities;
     (i) (i) change any of the accounting principles or practices used by it, except for any change required by reason of a concurrent change in Tax or other Law or GAAP, (ii) make or change an election relating to Taxes, (iii) adopt or change an accounting method related to Taxes, unless required by a concurrent change in Law or GAAP, (iv) enter into any closing agreement related to Taxes, (v) settle any claim or assessment relating to Taxes or (vi) consent to any claim or assessment relating to Taxes or any waiver of the statute of limitations for any such claim or assessment;
     (j) adopt or become plan sponsor or administrator (as such terms are defined in Section 3(16) of ERISA) of any Seller Plan other than an Enbridge Entity Plan;
     (k) enter into any settlement of any pending or threatened Proceeding that will (i) result in the payment of money damages by an Enbridge Entity or Enbridge Entity Subsidiary of more than $100,000, in the aggregate, after the Closing Date or (ii) impose an injunction or similar equitable relief upon an Enbridge Entity or Enbridge Entity Subsidiary or materially impair the defense by an Enbridge Entity or Enbridge Entity Subsidiary of any other Proceeding then pending or threatened; or
     (l) commit to do any of the foregoing actions.
      Section 6.2 Access .
     (a) From the date hereof through the Closing, Seller shall afford to Buyer and its authorized Representatives reasonable access, during normal business hours and in such manner as not to unreasonably interfere with the normal operation of the Business, to the assets, properties, books, contracts, records and appropriate officers and employees of the Enbridge Entities, the Enbridge Entities Subsidiaries and Seller, and shall furnish such authorized Representatives with all financial and operating data and other information concerning the Enbridge Entities, the Enbridge Entities Subsidiaries and the Business as Buyer and such Representatives may reasonably request; provided , however , in no event shall Buyer have the right to perform invasive or subsurface investigations of the properties of the Enbridge Entities or Enbridge Entities Subsidiaries without the prior written consent of Seller. Seller shall have the right to have a Representative present at all times during any such inspections, interviews, and examinations. Additionally, Buyer shall hold in confidence all such information on the terms and subject to the conditions contained in the Confidentiality Agreement. Notwithstanding the foregoing, Buyer shall have no right of access to, and Seller shall have no obligation to provide to Buyer, (i) any information the disclosure of which would jeopardize any privilege available to any Enbridge Entity or Enbridge Entity Subsidiary, Seller or any Affiliate of Seller relating to such information or would cause any Enbridge Entity, Enbridge Entity Subsidiary, Seller or any Affiliate of Seller to breach a confidentiality obligation to any third party ( provided , however , Seller shall consult with Buyer to attempt to devise an arrangement whereby Seller could provide such information to Buyer without jeopardizing such
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privilege or breaching such confidentiality obligation, as the case may be), or (ii) any information the disclosure of which would result in a violation of Law.
     (b) Buyer shall indemnify, defend and hold harmless the Seller Indemnified Parties from and against any and all Losses relating to death, injury to persons or damage to property arising out of or resulting from any due diligence activity conducted by Buyer or its authorized Representatives, EVEN IF SUCH LOSSES ARISE OUT OF OR RESULT FROM (IN WHOLE OR IN PART) THE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY SELLER, ANY ENBRIDGE ENTITY, OR ANY ENBRIDGE ENTITY SUBSIDIARY, ANY MEMBER OF THE SELLER INDEMNIFIED PARTIES OR ANY OTHER PERSON, EXCLUDING THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF SELLER, ANY ENBRIDGE ENTITY OR ANY ENBRIDGE ENTITY SUBSIDIARY. This indemnity shall survive any termination of this Agreement and the Closing.
      Section 6.3 Third Party Approvals . Subject to the terms and conditions set forth in this Agreement (including, without limitation, the terms and conditions set forth in Section 6.13(b) ), from the date hereof through the Closing Date, each of Buyer and Seller shall use its Reasonable Efforts (subject to, and in accordance with, applicable Law) to take promptly, or to cause to be taken, all actions, and to do promptly, or to cause to be done, and to assist and to cooperate with the other Party in doing, all things necessary, proper or advisable to consummate and make effective the Closing and the other transactions contemplated hereby as soon as reasonably practicable, including, (a) Buyer shall (and shall cause each of its Affiliates to) use Reasonable Efforts to obtain all of the Buyer Approvals and (b) Seller shall (and shall cause each of its Affiliates to) use Reasonable Efforts to obtain all of the Seller Approvals.
      Section 6.4 Regulatory Filings . From the date of this Agreement until the Closing, subject to the terms and conditions of this Agreement, each of Buyer and Seller shall, and shall cause their respective Affiliates to undertake Reasonable Efforts to make or cause to be promptly made (and, in the case of filings required to be made pursuant to the HSR Act, not later than the date of this Agreement) the filings required of such Party or any of its Affiliates under any Laws with respect to the transactions contemplated by this Agreement and to pay any fees due of it in connection with such filings. In furtherance and not in limitation of the foregoing, each of Buyer and Seller shall, to the extent permissible by Law, (i) reasonably cooperate with the other Party and furnish to the other Party all non-confidential information in such Party’s possession that is necessary in connection with such other Party’s filings, (ii) use Reasonable Efforts to cause the early termination or the expiration of the applicable waiting periods under the HSR Act and any other Laws with respect to the transactions contemplated by this Agreement as promptly as is reasonably practicable, (iii) promptly inform the other Party of any significant communication from or to, and any proposed understanding or agreement with, any Governmental Authority in respect of such filings, (iv) consult and reasonably cooperate with the other Party in connection with any analyses, appearances, presentations, memoranda, briefs, arguments and opinions made or submitted by or on behalf of any Party in connection with all meetings, actions and proceedings with any Governmental Authority relating to such filings, and (v) comply, as promptly as is reasonably practicable, with any requests received by such Party or any of its Affiliates under the HSR Act and any other Laws for additional information, documents or other materials. If a Party intends to participate in any face-to-face meeting with any Governmental
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Authority with respect to such filings, it shall give the other Party reasonable prior notice of, and to the extent permitted by the Governmental Authority, an opportunity to participate face-to-face in, such meeting.
      Section 6.5 Books and Records .
     (a) From and after the Closing, Seller and its authorized Representatives may retain a copy of any or all of the books and records (other than Tax records which are addressed in Article VII ) relating to the business or operations of the Enbridge Entities or Enbridge Entities Subsidiaries on or before the Effective Time. Seller shall not use such books and records to compete with the Enbridge Entities or Enbridge Entities Subsidiaries or in a manner that results in the violation of any Laws (including those of FERC).
     (b) Within twenty (20) days after the expiration of the term of the Transition Services Agreement, Seller shall deliver to Buyer all books, records, Contracts, and files (other than Tax records which are addressed in Article VII ) relating to the business or operations of the Enbridge Entities and Enbridge Entities Subsidiaries ( provided , however , until such time that Seller delivers such books, records, Contracts and files to Buyer, Seller shall provide Buyer access to the same during normal business hours and in such a manner as not to unreasonably interfere with the normal operation of Seller’s business or the performance by EES of its obligations under the Transition Services Agreement). Buyer shall preserve and keep a copy of all books and records (other than Tax records which are addressed in Article VII ) relating to the business or operations of the Enbridge Entities or Enbridge Entities Subsidiaries on or before the Effective Time in Buyer’s possession for a period of at least five (5) years after the Closing Date. After such five (5) year period, before Buyer shall dispose of any such books and records, Buyer shall give Seller at least ninety (90) days prior notice to such effect, and Seller shall be given an opportunity, at its cost and expense, to remove and retain all or any part of such books and records as Seller may select. Buyer shall provide to Seller and its designees (including its Affiliates) and their respective Representatives, at no cost or expense to Seller or such designees, reasonable access to such books and records, including Tax records, as remain in Buyer’s possession and full access to the properties and employees of Buyer and the Enbridge Entities or Enbridge Entities Subsidiaries in connection with matters relating to the business or operations of the Enbridge Entities or Enbridge Entities Subsidiaries on or before the Effective Time and any disputes relating to this Agreement.
     (c) Prior to and for a period of twenty-four (24) months following Closing, Seller agrees to make available to Buyer during normal business hours and in such a manner as not to unreasonably interfere with the normal operation of the business of Seller or any Affiliate of Seller any and all existing information and documents in the possession of Seller or any of its Affiliates relating to the Enbridge Entities and Enbridge Entities Subsidiaries or to the Business that Buyer may reasonably require to comply with Buyer’s financial reporting requirements and audits, including information and documents necessary to comply with the requirements, if any, to file with the United States Securities and Exchange Commission (“ SEC ”) audited financial statements;
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provided , however , that as a condition to Seller providing Buyer with access to such information and documents, Buyer and the independent auditors chosen by Buyer (“ Buyer’s Auditors ”) shall be required to agree to maintain such information and documents confidential on terms and subject to conditions that are reasonably acceptable to Seller. Without limiting the generality of the foregoing, Seller will use Reasonable Efforts after execution of this Agreement and for twenty-four (24) months following Closing to cooperate with Buyer’s Auditors in connection with their audit of any annual financial statements with respect to any of the Enbridge Entities and their respective Enbridge Entity Subsidiary that Buyer reasonably requires to comply with its financial reporting requirements. Seller’s cooperation will include (i) such reasonable access to Seller’s employees who were responsible for preparing the work papers and other supporting documents used in the preparation of such financial statements as may be reasonably required by Buyer’s Auditors to perform an audit in accordance with generally accepted auditing standards, and (ii) delivery of one or more customary representation letters from Seller to Buyer’s Auditors that are requested by Buyer to allow such auditors to complete an audit (or review of any interim quarterly financial statements), and to issue an opinion as required by the SEC with respect to an audit or review of those financial statements required pursuant to this Section 6.5(c) . Buyer will reimburse Seller, within ten (10) Business Days after request therefor, for any reasonable costs and expenses incurred by Seller (taking into account, with respect to costs and expenses associated with any employee of Seller or any Affiliate of Seller, the amount of time such employee devotes to tasks relating to Seller complying with the provisions of this Section 6. 5(c) ) , including the hiring of temporary employees, in complying with the provisions of this Section 6.5(c) .
      Section 6.6 Employee and Benefit Matters.
     (a) On or before the Closing, Seller shall take any actions necessary to cause the Enbridge Entities and Enbridge Entities Subsidiaries to cease to be adopting or participating employers, as applicable, of all Seller Plans and sponsoring, adopting or participating employers, as applicable, of all Enbridge Entity Plans, other than the Enbridge Entity Plan(s) listed on Schedule 6.6(a) . Except as expressly provided in the remaining paragraphs of this Section 6.6 and as set forth on Schedule 6.6(a) with respect to an Enbridge Entity Plan, Buyer shall not, and from and after the Closing Date the Enbridge Entities and Enbridge Entities Subsidiaries shall not, have any responsibility or liability with respect to Seller Plans, or to Enbridge Entity Plans established prior to the Closing Date, and Seller will be responsible for such responsibilities and liabilities.
     (b) Schedule 6.6(b) sets forth a list of certain employees of Seller or its Affiliates who provide services relating to the Business and which Seller and such Affiliates shall make available to Buyer to discuss potential employment, with any such employment to be contingent upon, and to begin after, the Closing, with Buyer or an Affiliate of Buyer (such employees being collectively the “ Affiliate Employees ”). Schedule 6.6(b) shall be divided into two lists, one containing the Affiliate Employees who are assigned on a full time or primary basis to operations functions of the Business (the “ Operations Employees ”) and another containing those Affiliate Employees who provide technical, legal, finance, treasury or other support services to the Business (the
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“ Support Employees ”). Prior to execution of this Agreement, Seller provided to Buyer a schedule in a readily-accessible electronic format listing for each Affiliate Employee his or her (i) name, employee identification number, job title, and assigned work location, (ii) dates of employment by Seller or its Affiliates and date of employment for each of the purposes identified in Section 6.6(e) , (iii) base salary or hourly rate of compensation, prior year’s actual, and current year’s targeted, bonus and incentive compensation (if any), and (iv) whether or not such Affiliate Employee is actively at work and if not, whether on an approved leave, and for those Affiliate Employees on an approved leave, the reason for, and the expected duration of, the approved leave. Seller shall not, and shall cause each of its Affiliates not to, alter, promise to alter, or take any action that would have the effect of altering, with respect to any Affiliate Employee, any term or aspect of employment of such Affiliate Employee that is required to be disclosed to Buyer pursuant to this Section 6.6(b ) or that is the subject of any obligation of Buyer under this Section 6.6 without the prior written consent of Buyer. Without limiting the foregoing, Seller shall promptly update Schedule 6.6(b) and the information provided to Buyer pursuant to this Section 6. 6(b) from time to time prior to Closing as necessary to ensure its continuing accuracy. Subject to Seller’s timely provision of complete and accurate information as required by this Section 6.6 , within twenty (20) days after the date of this Agreement, Buyer shall, or shall cause its Affiliates to, offer employment (which shall be contingent on the occurrence of the Closing) to each Operations Employee and may, or may cause its Affiliates to, at its discretion after interviews, offer employment (which shall be contingent on the occurrence of the Closing), to any or all Support Employees, at, in each case, a base salary or hourly rate that is at least equal to such Affiliate Employee’s then current base salary or hourly rate as then correctly reflected in the information provided to Buyer pursuant to this Section 6. 6(b) and with a principal place of employment no greater than forty-nine (49) miles from the location where the Affiliate Employee is currently employed as then correctly reflected in the information provided to Buyer pursuant to this Section 6. 6(b) (a “ Qualifying Offer ”); provided, however , that Buyer (or its Affiliates) will not be required to offer employment to, or to employ or continue to employ, any Affiliate Employee that does not satisfactorily complete Buyer’s normal drug testing procedure. Each Qualifying Offer shall be consistent with the provisions of this Section 6.6 , may contain such other provisions and terms not inconsistent with this Section 6.6 as the Buyer or its Affiliates may deem appropriate, and shall remain open for a period of at least five (5) days. On or before the date that is five (5) Business Days prior to the Closing Date, Buyer shall notify Seller as to each Affiliate Employee who has accepted a Qualifying Offer and each Affiliate Employee who has not accepted a Qualifying Offer. If Buyer or its Representatives acts unlawfully or violates the requirements of this Section 6.6(b) , and if any such unlawful action or violation of this Section 6. 6(b) is not a result of, and is not caused by, any action or inaction by Seller, including Seller’s failure to comply with this Section 6.6, Buyer shall indemnify and hold harmless Seller and its Affiliates with respect to all Losses relating to or arising out of Buyer’s (or its Representatives’) unlawful actions or Buyer’s violation of the requirements of this Section 6. 6(b) (including, without limitation, any claim of discrimination or other illegality by Buyer in such selection and offer process and also including any severance benefits that may become due and owing under the Seller Severance Plan as a result of Buyer’s unlawful
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acts or violation of this Section 6.6(b) ). The employment with Buyer or an Affiliate of Buyer of each Affiliate Employee who accepts a Qualifying Offer and reports to work with Buyer or an Affiliate of Buyer in a timely manner and otherwise in accordance with the Qualifying Offer shall be effective as of the Closing Date.
     (c) For a period of one (1) year beginning on the Closing Date and subject to the provisions of this Section 6.6 and an individual’s employment with an Enbridge Entity, Buyer or any of their respective Affiliates, Buyer shall cause each Affiliate Employee who accepts Buyer’s Qualifying Offer of employment (“ Continuing Employee ”) to be provided with (i) compensation (including bonus and incentive compensation) on a basis substantially similar to that provided by Seller and its Affiliates to such employee so that, in the aggregate, such compensation shall be at least equal to the lesser of (1) the Continuing Employee’s base salary or hourly rate of compensation, as applicable, and target bonus or incentive compensation in effect on the Closing Date, and (2) the amounts disclosed by Seller to Buyer in accordance with this Section 6.6 as the base salary or hourly rate of compensation and target bonus or incentive compensation of such Continuing Employee, and (ii) employee and fringe benefits on a basis substantially similar to those provided to similarly situated employees (and their dependents and beneficiaries) of Buyer and its Affiliates, including coverage under the Benefit Plans maintained by Buyer and its Affiliates. Seller agrees that in consideration of Buyer’s commitments hereunder that neither Seller nor its Affiliates will (x) prior to the Closing Date, solicit or offer to any Affiliate Employee any employment opportunity that is an alternative to the offer of employment to be made by Buyer hereunder, or (y) during the one (1) year period beginning on the Closing Date, solicit for employment or employ any Continuing Employee; provided, however , that a general advertisement or general solicitation for potential employees shall not be considered a breach of this Section 6.6(c) , and a decision to hire any Affiliate Employee or Continuing Employee who applies in response to such solicitation shall not be considered a breach of this Section 6.6(c) .
     (d) Subject to Seller’s timely provision of complete and accurate information as required by this Section 6.6(d) , Buyer shall cause each Continuing Employee and all of such Continuing Employee’s eligible dependents that are covered as of the Closing Date by a Seller Plan that is a group health, prescription drug, dental or similar type welfare benefit plan to be offered coverage under group health, prescription drug, dental or similar type of Benefit Plan, as the case may be, maintained by Buyer or an Affiliate of Buyer, under which the Continuing Employee and such eligible dependents, if any, of the Continuing Employee shall be (i) eligible effective immediately upon the inception of their employment with Buyer or an Affiliate of Buyer, and (ii) credited, for the year during which such coverage under such plans begin, with any deductibles, out-of-pocket maximums and co-payments already incurred during such year under Seller Plans that provide similar benefits. Seller shall provide, or shall cause to be provided, to Buyer within five (5) Business Days of Buyer’s request all information reasonably requested by Buyer for the purpose of complying with the provisions of this Section 6. 6(d) .
     (e) Subject to Seller’s timely provision of complete and accurate information as required by this Section 6.6(e) , Buyer shall cause the Benefit Plans and programs
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maintained after the Closing by Buyer, the Enbridge Entities and the Affiliates of Buyer to recognize each Continuing Employee’s years of service prior to the Closing Date with Seller, the Business, the Enbridge Entities and their Affiliates (including service with any other employer that was recognized by Seller, the Enbridge Entities or their respective Affiliates) for purposes of terms of employment and eligibility, vesting, benefit accrual and benefit determination under such plans and programs, including paid vacation, paid sick time, severance benefits and employer contribution rates under retirement plans. Any vacation time that has been accrued, but unused, by a Continuing Employee as of the Closing shall be extinguished and paid out to the Continuing Employee by Seller or its Affiliates. To the extent required by Law, Buyer shall cause each group health plan sponsored by Buyer or one of its Affiliates that a Continuing Employee may be eligible to participate in on or after the Closing Date to waive any preexisting condition exclusions applicable to such Continuing Employee and his eligible dependents. Seller shall provide, or shall cause to be provided, to Buyer within five (5) Business Days of Buyer’s request all information reasonably requested by Buyer for the purpose of complying with the provisions of this Section 6. 6(e) .
     (f) Claims of Continuing Employees and their eligible beneficiaries and dependents for medical, dental, prescription, drug, life insurance, and/or other welfare benefits (“ Welfare Benefits ”) (other than disability benefits) that are incurred before the Closing Date shall be the sole responsibility of the Seller Plans. Claims of Continuing Employees and their eligible beneficiaries and dependents for Welfare Benefits (other than disability benefits) that are incurred on or after the Closing Date shall not be the responsibility or liability, in any way, of Seller, its Affiliates or the Seller Plans. For purposes of the preceding provisions of this paragraph, a medical/dental claim shall be considered incurred on the date when the medical/dental services are rendered or medical/dental supplies are provided, and not when the condition arose or when the course of treatment began. Claims of individuals receiving disability benefits under a Seller Plan as of the Closing Date shall be the sole responsibility of the Seller Plans pursuant to their terms and conditions. Except as provided in the preceding sentence, claims of Continuing Employees and their eligible beneficiaries and dependents for disability benefits from and after the Closing Date shall be based upon the disability benefits provided to similarly situated employees under Benefit Plans maintained by Buyer or an Affiliate of Buyer and shall, subject to the terms and conditions of such plan(s), be the sole responsibility of plans maintained by Buyer or an Affiliate and shall not be the responsibility or liability, in any way, of Seller, its Affiliates or the Seller Plans.
     (g) Subject to Seller’s timely provision of complete and accurate information as required by this Section 6.6(g) , and the timely execution and delivery without revocation of a release as provided herein, Buyer shall pay an amount equal to the Severance Pay Amount to each Continuing Employee whose employment with Buyer or its Affiliates is involuntarily terminated (other than termination for Cause) within the one (1) year period beginning with the Closing Date. The Buyer’s obligation to pay the Severance Pay Amount shall be conditioned upon the terminated Continuing Employee’s execution and delivery of a release reasonably suitable to Buyer (and which shall be consistent with applicable Law and no different than the form of release that Buyer
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requires any similarly situated employee to execute and deliver as a condition to the payment to them of any severance amount) within thirty (30) days of the Continuing Employee’s termination of employment and, further, to the lapse of any period of time during which the release is otherwise revocable under applicable Law. The Severance Pay Amount shall be paid in a lump sum payment, less applicable withholding, within ten (10) Business Days after the timely satisfaction of the conditions in the preceding sentence. The term “ Severance Pay Amount ” means, in the case of Continuing Employee whose termination of employment is subject to Section 6.6(g) , an amount equal to the sum of:
     (i) The Weekly Base Pay of such Continuing Employee multiplied by the lesser of
     (a) 52, and
     (b) the sum of:
     (i) the greater of:
     (a) two times the number of whole years of service completed by a Continuing Employee with Buyer or its Affiliates (determined in accordance with Section 6.6(e) ) as of the date of his or her termination of employment, and
     (b) eight (8);
     (ii) in the case of a Continuing Employee whose age as of the date of his or her termination is —

below 40	 	 	0	 	
at least 40, but below 45	 	 	4	 	
at least 45, but below 50	 	 	6	 	
at least 50, but below 55	 	 	8	 	
at least 55	 	10; and	
     (iii) in the case of a Continuing Employee whose position with Seller as of the Closing Date was designated in Seller’s payroll records as

Grade 12	 	 	4	 	
Grade 13 or above	 	8; and	
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     (ii) An amount equal to the prorata portion of any target bonus or target incentive compensation assigned to such Continuing Employee by Buyer as of the date of such Continuing Employee’s termination, based on the number of days such termination follows the Closing Date divided by 365, and adjusted for any bonus or incentive compensation paid by Buyer to such Continuing Employee during that same period; and
     (iii) An amount that, after taking into account all required payroll and income tax withholding (without regard to any election by such Continuing Employee for additional tax withholding), is equal to three (3) times the monthly premium allowed under Code Section 4980B for continuation of the healthcare coverage in effect as of the date of termination for such Continuing Employee under Buyer’s healthcare plan.
For purposes of this Section 6.6(g) , “ Cause ” means any of the following reasons that the Continuing Employee’s employment with Buyer or its Affiliate has been terminated: material workplace misconduct; violation of safety or other workplace rules, guidelines or procedures; any act or omission that is in breach of or that is contrary to any material obligation, responsibility or duty of the Continuing Employee to the Buyer or its Affiliates; violation of the employer’s code of conduct or ethics policy; material fraud or other dishonesty against the employer; engagement in conduct that the Continuing Employee knows or should know is materially injurious to the business or reputation of the employer; falsifying the employer’s or the Continuing Employee’s records (including an employment application); on-the-job intoxication or being under the influence of alcohol while on-the-job or a drug not being used as prescribed; unauthorized use of the employer’s equipment or the confidential information of the Buyer or an Affiliate of Buyer; or conviction of a felony or a misdemeanor involving moral turpitude.
Seller shall provide, or shall cause to be provided, to Buyer within five (5) Business Days of Buyer’s request all information reasonably requested by Buyer for the purpose of complying with the provisions of this Section 6. 6(g) .
     (h) Seller shall be responsible for all liabilities (including liabilities for associated administrative functions) for workers’ compensation claims made for compensable injuries occurring before the Closing Date. From and after Closing, Buyer shall be responsible for all liabilities (including liabilities for associated administrative functions) for all workers’ compensation claims made on or after the inception of employment of the Continuing Employee by Buyer or its Affiliates. For purposes of this Section 6.6(h) , a workers’ compensation claim shall be “made” at the time of the occurrence of the event giving rise to eligibility for workers’ compensation benefits or at the time the occupational disease becomes manifest, as applicable, under the respective workers’ compensation act governing the alleged injury or disease. Seller will notify applicable Governmental Authorities, if and as appropriate, of any on-the-job injuries or workers’ compensation claims for which they are responsible for under this Section 6.6(h) . Buyer will notify applicable Governmental Authorities, if and as appropriate, of any on-the-job injuries or workers’ compensation claims for which it is responsible for
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under this Section 6.6(h) . Seller and Buyer will cooperate in providing to each other information needed for these notifications and related filings.
      Section 6.7 Excluded Assets . Buyer acknowledges and agrees that (a) the transactions contemplated by this Agreement exclude the Excluded Assets, (b) prior to the Closing Date, Seller may take such reasonable actions which are necessary to exclude the Excluded Assets from the Interests and from the assets of the Enbridge Entities and Enbridge Entities Subsidiaries, (c) neither Buyer nor any of the Enbridge Entities or Enbridge Entities Subsidiaries shall have any right to use the Excluded Assets from and after the Closing Date and (d) Buyer shall be responsible for obtaining any and all licenses for computer and communications software that may be necessary for the ownership and operation of the Business from and after the Closing Date.
      Section 6.8 Seller Marks . Buyer shall obtain no right, title, interest, license or any other right whatsoever to use the word “Enbridge” or “Midcoast” or any trademarks containing or comprising the foregoing, or any trademark confusingly similar thereto or dilutive thereof (collectively, the “ Seller Marks ”). From and after the Closing, Buyer agrees (a) to cease using, and to cause each Enbridge Entity and each Enbridge Entity Subsidiary to cease using, the Seller Marks in any manner, directly or indirectly, except for such limited uses as cannot be promptly terminated ( e.g ., signage, e-mail addresses, and as a referral or pointer to the acquired website), and to cease such limited usage of the Seller Marks as promptly as possible after the Closing and in any event within three (3) days following the Closing Date, (b) to remove, strike over or otherwise obliterate all Seller Marks from the assets of the Enbridge Entities and Enbridge Entities Subsidiaries and from all assets and all other materials owned, possessed or used by any of the Enbridge Entities and Enbridge Entities Subsidiaries within forty-five (45) days after the Closing Date; provided, however , that such time period shall be extended to one hundred eighty (180) days with respect to removing, striking over or otherwise obliterating all Seller Marks from any field markers in or on such assets, (c) to use Reasonable Efforts to cause any third parties identified by Seller prior to Closing that use or license Seller Marks in respect of the assets of the Enbridge Entities or Enbridge Entities Subsidiaries or on behalf of or with the consent of any Enbridge Entity or Enbridge Entity Subsidiary, to remove, strike over or otherwise obliterate all Seller Marks from all materials owned, possessed or used by such third parties within forty-five (45) days after the Closing Date and (d) to change the name of each of the Enbridge Entities and Enbridge Entities Subsidiaries to remove the names “Enbridge” and “Midcoast” and any variations thereof and to amend all Organizational Documents of the Enbridge Entities and Enbridge Entities Subsidiaries to reflect such name change within fifteen (15) days after the Closing Date. The Parties agree, because damages would be an inadequate remedy, that a Party seeking to enforce this Section 6.8 shall be entitled to seek specific performance and injunctive relief as remedies for any breach thereof in addition to other remedies available at law or in equity.
      Section 6.9 Permits . Buyer shall provide all notices and otherwise take all actions reasonably required to transfer or reissue any Permits that are required on or after the Closing Date to be transferred or reissued, including those required under Environmental Laws, as a result of or in furtherance of the transactions contemplated by this Agreement. Seller shall use Reasonable Efforts to cooperate with Buyer to provide information necessary to apply for such Permits.
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      Section 6.10 Insurance . Seller agrees to maintain the Seller’s Policies in full force and effect until Closing. All coverage and benefits under the Seller’s Policies and any other insurance policies of Seller or its Affiliates (subject to the terms thereof) relating to the Enbridge Entities, the Enbridge Entities Subsidiaries and the Business shall cease at the Closing. On and after the Closing Date, Buyer shall obtain and maintain any and all insurance coverage and protection relating to the Enbridge Entities, the Enbridge Entities Subsidiaries and the Business.
      Section 6.11 Guarantees . Buyer acknowledges and agrees that (a) Seller shall have the right to terminate effective as of the Closing Date each of the Guarantees insofar as such Guarantees relate to obligations of an Enbridge Entity or Enbridge Entity Subsidiary and (b) Buyer shall bear all costs and liabilities arising or resulting from such termination (other than costs and liabilities relating to any act, event or circumstance occurring prior to the Effective Time, which shall be an obligation of the guarantor of the applicable Guarantee) and shall also bear all costs and expenses associated with obtaining any and all substitute guarantees or other credit support which may be required under the terms of any Contract to which such Guarantees relate.
      Section 6.12 LaCrosse Option Rights . Pursuant to an option agreement in the form of the Option Agreement attached as Exhibit 6.12 to this Agreement (the “ LaCrosse Option Agreement ”), Seller, or any Affiliate of Seller designated by it, shall have the option to reserve capacity on the MLGT Pipeline System for production volumes that are contemplated to be transported in the future through the LaCrosse Pipeline System.
      Section 6.13 Preference Right .
     (a) Buyer acknowledges that its right to purchase the Interests in Enbridge Bamagas (the “ Preference Interests ”) is subject to a Preference Right. The portion of the Base Purchase Price allocated to the Preference Interests is set forth in Schedule 6.13(a) .
     (b) Seller shall use Reasonable Efforts to obtain the waiver of such Preference Right (the “ Bamagas Preference Right ”); provided, however , Seller shall not be obligated to pay any consideration to (or incur any cost or expense for the benefit of) the holder of the Bamagas Preference Right in order to obtain the waiver thereof or compliance therewith. If the holder of the Bamagas Preference Right elects to purchase the Preference Interests in accordance with the terms of the Bamagas Preference Right, then the Preference Interests will be eliminated from the Interests and the Base Purchase Price shall be reduced by the portion of the Base Purchase Price allocated to the Preference Interests in Schedule 6.13(a) . The Parties agree that if the holder of the Bamagas Preference Right elects to purchase the Preference Interests in accordance with the terms of the Bamagas Preference Right, the Closing shall be delayed until December 1, 2009 in order to permit Buyer to address its funding requirements to pay the Base Purchase Price, as reduced pursuant to this Section 6.13(b) .
      Section 6.14 Damage or Casualty Loss .
     (a) As used herein, the term “ Casualty Loss ” means, with respect to all or any portion of the assets and properties of any of the Enbridge Entities or Enbridge Entities
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Subsidiaries, any destruction by fire, explosion, storm, hurricane, or other casualty of all or any portion of the assets and properties of such Enbridge Entity or Enbridge Entity Subsidiary from and after the date hereof until the Closing Date. Seller shall promptly notify the Buyer of any Casualty Loss of which Seller becomes aware. If one or more Casualty Losses occur and the estimated costs to repair or replace the damaged assets or properties exceed, individually or in the aggregate, $1,000,000, Seller will have the right to repair or replace the assets or properties damaged by such Casualty Losses prior to Closing or, if such damage cannot be repaired or replaced by the Closing Date, to commit to repair or replace such damage no later than ninety (90) days following the Closing Date. If Seller refuses or is unable to cure such Casualty Losses prior to the Closing (or within ninety (90) days following the Closing Date), Buyer may either (i) purchase the Interests notwithstanding such Casualty Losses or (ii) terminate this Agreement upon ten (10) days’ prior written notice to Seller.
     (b) In the event of Casualty Losses for which the estimated costs, net to the direct or indirect interest of any of the Enbridge Entities or Enbridge Entities Subsidiaries, to repair or replace the damaged assets or properties are, individually or in the aggregate, equal to or less than $1,000,000, Buyer shall purchase the Interests notwithstanding such Casualty Losses (without any reduction in the Base Purchase Price), and Seller shall: (i) pay to Buyer, promptly upon receipt by Seller, all sums paid to Seller by third parties by reason of such Casualty Losses and (ii) on the Closing Date, assign, transfer, and set over to Buyer all of the rights and interests of Seller in and to any unpaid awards or other payments (including insurance proceeds not expended or committed to expenditure by Seller to repair such Casualty Losses) from third parties arising out of the Casualty Loss.
      Section 6.15 Confidentiality .
     (a) For two years after Closing, except as required by any Law, Governmental Authority, or applicable stock exchange rule, Seller shall not, and shall cause its Affiliates not to, directly or indirectly, disclose to any Person any information not in the public domain or generally known in the industry, in any form, whether acquired prior to or after the Closing Date, relating to the business and operations of the Enbridge Entities or Enbridge Entities Subsidiaries (including information regarding customers, vendors, suppliers, trade secrets, training programs, manuals or materials, technical information, contracts, systems, procedures, mailing lists, know-how, trade names, improvements, price lists, financial or other data, business plans, marketing strategies, tariff or rate models, rate strategies, code books, invoices and other financial statements, computer programs, software systems, data bases, discs and printouts, customer and industry lists, correspondence, internal reports, personnel files, sales and advertising material, telephone numbers, names, addresses or any other compilation of information, written or unwritten), regardless of whether such information was or is owned on the date hereof or on the Closing Date by Seller or its Affiliates. For two years after Closing, Seller agrees that neither Seller nor any of its Affiliates shall seek to compete with the Business; provided, however, the foregoing shall not be construed as prohibiting or limiting the ability of Seller or any of its Affiliates to (i) construct, purchase or operate any interstate pipeline system that may have a service area or areas coincident with or near to the area
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of operations of one or more of the Enbridge Entities or the Enbridge Entities Subsidiaries or (ii) acquire all or any portion of one or more entities that may own or operate assets that include intrastate pipelines or gathering systems that may be coincident with or near to the area of operations of one or more of the Enbridge Entities or the Enbridge Entities Subsidiaries.
     (b) The Parties acknowledge that American Infrastructure MLP Funds, L.P. previously executed the Confidentiality Agreement. The Confidentiality Agreement shall continue in full force and effect until the Closing, at which time the Confidentiality Agreement shall automatically terminate and be of no further force or effect.
      Section 6.16 EnerVest Contract . At the Closing, (a) Seller shall cause EMLP to assign the EnerVest Contract to AM Marketing pursuant to an assignment substantially in the form of the Assignment of Contract attached hereto as Exhibit 6.16(a) (the “ EnerVest Contract Assignment ”) and Buyer shall cause AM Marketing to accept assignment of the EnerVest Contract from EMLP pursuant to the EnerVest Contract Assignment and (b) Seller shall cause EMLP and Buyer shall cause AM Marketing to execute a gas purchase contract in substantially the form of the Gas Purchase Contract attached hereto as Exhibit 6.16(b) (the “ Gas Purchase Contract ”).
      Section 6.17 EOP . MLGT owns a 99.999% limited partnership interest in EOP and EH owns a .001% general partnership interest in EOP (the “ EOP GP Interest ”). At the Closing, Seller shall cause EH, its wholly-owned subsidiary, to assign the EOP GP Interest to Buyer pursuant to the EOP GP Interest Assignment.
      Section 6.18 Certain Rights . If any matter arises after the Closing relating to the assets or operations of any of the Enbridge Entities or the Enbridge Entities Subsidiaries for which Seller or EEP has rights to indemnification or contribution pursuant to any merger or acquisition agreement, then Seller shall (a) assign (or cause EEP to assign) such rights to Buyer (or to the Enbridge Entity or Enbridge Entity Subsidiary to which they relate) or (b) assert (or cause EEP to assert) a claim for indemnification or contribution thereunder and use Reasonable Efforts to collect same and shall promptly pay any amount so collected (net of costs and expenses incurred in connection with such collection efforts) to Buyer.
      Section 6.19 Certain Personal Property . If it is determined after Closing that title to the boat, or any of the vehicles or other personal property listed on Schedule 6.19 is in the name of Seller or any Affiliate of Seller other than an Enbridge Entity or any Enbridge Entity Subsidiary, Seller shall promptly cause such title to be transferred to an Enbridge Entity or an Enbridge Entity Subsidiary.
      Section 6.20 Transition Services Agreement . Prior to the Closing, the Parties shall negotiate in good faith to agree upon a form of Transition Services Agreement which is reasonably acceptable to the Parties and is substantially in the form of the Transition Services Agreement Form (the “ Transition Services Agreement ”).
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ARTICLE VII
TAX MATTERS
      Section 7.1 Tax Returns .
     (a) With respect to Tax Returns that are required to be filed on or before the Closing Date by the Enbridge Entities and the Enbridge Entities Subsidiaries for any Pre-Closing Tax Period (other than a Straddle Period), Seller shall cause the Enbridge Entities and the Enbridge Entities Subsidiaries to prepare all such Tax Returns and shall cause the Enbridge Entities and the Enbridge Entities Subsidiaries to timely pay all Taxes shown to be due on such Tax Returns. With respect to Tax Returns that are required to be filed (i) after the Closing Date by the Enbridge Entities and the Enbridge Entities Subsidiaries for any Pre-Closing Tax Period (other than a Straddle Period) and (ii) by the Enbridge Entities and the Enbridge Entities Subsidiaries for a Straddle Period, Buyer shall cause the Enbridge Entities and the Enbridge Entities Subsidiaries to prepare and properly file all such Tax Returns and timely pay all Taxes shown to be due on such Tax Returns. Pursuant to the Seller’s obligations described in Section 7.4 and Section 7.6 , Seller shall pay to Buyer an amount equal to the Taxes attributable to the Pre-Closing Tax Period (other than a Straddle Period) and the Pre-Closing Tax Period portion of such Straddle Period.
     (b) Any Tax Return prepared pursuant to the provisions of this Section 7.1 shall be prepared in a manner consistent with practices followed in prior years with respect to similar Tax Returns, except as otherwise required by Law or fact.
     (c) As a result of the Enbridge Entities and the Enbridge Entities Subsidiaries being disregarded as entities separate from EEP for U.S. federal income tax purposes (and state, local, and foreign Tax purposes where applicable), Seller and Buyer acknowledge that the purchase of the Interests will be treated as a purchase by Buyer from EEP of the assets, subject to the liabilities, of the Enbridge Entities and the Enbridge Entities Subsidiaries for U.S. federal income tax purposes (and state, local, and foreign Tax purposes where applicable). Buyer and Seller agree to report and file their U.S. federal income Tax Returns (and applicable state, local, and foreign Tax Returns) in all respects and for all purposes consistent with such treatment.
      Section 7.2 Transfer Taxes . All transfer, documentary, sales, use, fees, and other similar Taxes (“ Transfer Taxes ”) resulting directly from the sale and transfer by Seller to Buyer of the Interests shall be borne by Buyer. Any Tax Returns that must be filed in connection with Transfer Taxes shall be prepared and filed when due by the Party primarily or customarily responsible under the applicable Law for filing such Tax Returns, and such Party will use its Reasonable Efforts to provide such Tax Returns to the other Party at least ten (10) days prior to the due date for such Tax Returns. Not later than five (5) days after receiving a copy of such Tax Return, the other Party shall pay to the Party responsible for filing such Tax Return the portion of the Transfer Taxes shown as due on such Tax Return that such other Party is responsible for under this Section 7.2 .
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      Section 7.3 Purchase Price Allocation . Within a reasonable period of time after the Closing, Buyer and Seller shall cooperate in good faith to agree to an allocation of the Purchase Price (plus other capitalized costs) among the EnerVest Contract and the assets of the Enbridge Entities and the Enbridge Entities Subsidiaries in accordance with Section 1060 of the Code and the Treasury Regulations promulgated thereunder. Buyer and Seller further agree that they will report, and cause their Affiliates to report, the Tax consequences of the purchase and sale hereunder in a manner consistent with such allocations and that they will not take any positions inconsistent therewith in connection with the filing of any Tax Return.
      Section 7.4 Property Tax Allocation . With respect to any real property, personal property, ad valorem and other similar Tax (“ Property Taxes ”), assessed on any of the assets of the Enbridge Entities for any period that begins on or before and ends after the day before the day that includes the Effective Time (a “ Straddle Period ”), the liability for such Property Tax shall be prorated on a daily basis between Buyer and Seller as of the day before the day that includes the Effective Time, with Seller being liable for the portion of such Property Taxes equal to the product of (i) the amount of such Property Taxes for the entirety of the Straddle Period, multiplied by (ii) a fraction, the numerator of which is the number of days in the Straddle Period ending on the day before the day that includes the Effective Time, and the denominator of which is the total number of days in the Straddle Period, and with Buyer being liable for the remainder of such Property Taxes. Buyer shall receive a credit against the Purchase Price to the extent of Seller’s portion of such prorated Property Taxes. If the Closing Date shall occur before the applicable Tax rate or assessment is fixed for such Straddle Period, the apportionment of such Property Taxes and payments at the Closing shall be based upon the most recently ascertainable Property Tax bills; provided , that Buyer and Seller shall recalculate and re-prorate said Property Taxes and payments and make the necessary cash adjustments promptly upon the issuance, and on the basis, of the actual Property Tax bills received for the Straddle Period in which the Closing occurs.
      Section 7.5 Tax Cooperation . Each of Buyer and Seller will provide the other Party with such information and records and make such of its Representatives available as may reasonably be requested by such other Party in connection with the preparation of any Tax Return or any audit or other Proceeding that relates to the Enbridge Entities.
      Section 7.6 Tax Indemnification . Seller will indemnify, defend and hold the Buyer Indemnified Parties harmless from and against any Losses attributable to (i) all Taxes (or nonpayment thereof) of the Enbridge Entities that are attributable to the Pre-Closing Tax Period, (ii) all Taxes of Seller or any other Person (other than the Enbridge Entities) which is or has ever been affiliated with the Enbridge Entities, or with whom the Enbridge Entities otherwise join or have ever joined (or are or has ever been required to join) in filing any combined or unitary Tax Return, prior to the Closing Date, and (iii) any breach of Seller’s representations and warranties contained in Section 4. 8(a) or the Seller’s covenants contained in this Article VII . Notwithstanding the foregoing, Seller will not indemnify, defend or hold harmless any member of the Buyer Indemnified Parties from any liability for Taxes attributable to any action taken on or after the Closing Date by Buyer, any of its Affiliates (including the Enbridge Entities after the Closing), or any transferee of Buyer or any of its Affiliates (other than any such action taken in the ordinary course of business or expressly required or otherwise expressly contemplated by this Agreement) (a “ Buyer Tax Act ”).
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     (a) Buyer will indemnify, defend and hold the Seller Indemnified Parties harmless from and against any Losses attributable to (i) all Taxes (or nonpayment thereof) of the Enbridge Entities for any taxable period beginning on or after the day that includes the Effective Time and the portion of any Straddle Period beginning on or after the day that includes the Effective Time, (ii) all Taxes attributable to a Buyer Tax Act, and (iii) any breach of Buyer’s covenants contained in this Article VII .
     (b) The obligations of each Party to indemnify, defend and hold harmless the other Party or parties and other Persons, pursuant to Section 7.6 and Section 7.6(a) , will terminate on the date that is 60 days after the expiration of all applicable statutes of limitations (giving effect to any extensions thereof); provided, however , that such obligations to indemnify, defend and hold harmless will not terminate with respect to any individual item as to which an Indemnified Party has, before the expiration of the applicable period, previously made a claim by delivering a notice (stating in reasonable detail the basis of such claim) to the applicable Indemnifying Party.
     (c) In the case of any Tax, other than a Property Tax, imposed on the Enbridge Entities that is attributable to a Straddle Period, the amount of such Tax allocated to the Pre-Closing Tax Period of such Straddle Period for purposes of Section 7. 6(i) shall be determined based on an interim closing of the books as of the end of the day before the day that includes the Effective Time.
     (d) Any indemnity payment required to be made pursuant to this Section 7.6 will be paid within 30 days after the Indemnified Party makes written demand upon the Indemnifying Party, but in no case earlier than five (5) Business Days prior to the date on which the relevant Taxes are required to be paid (or would be required to be paid if no such Taxes are due) to the relevant Tax Authority (including estimated Tax payments).
     (e) Notwithstanding any provisions of this Agreement to the contrary, including Article IX , the indemnification obligations of Seller contained in this Section 7.6 represent the Seller’s only indemnification obligations of Buyer with respect to Taxes.
      Section 7.7 Tax Contests .
     (a) If a claim is made by any Tax Authority which, if successful, might result in an indemnity payment to any member of the Buyer Indemnified Parties or Seller Indemnified Parties pursuant to Section 7.6 , the Indemnified Party will promptly notify the Indemnifying Party of such claim (a “ Tax Claim ”); provided, however , that the failure to give such notice will not affect the indemnification provided hereunder except to the extent the Indemnifying Party has actually been prejudiced as a result of such failure.
     (b) With respect to any Tax Claim relating to Taxes that are attributable to a Pre-Closing Tax Period or to any other taxable period in which any Enbridge Entity’s or Enbridge Entity Subsidiary’s income or operating results attributable to a Pre-Closing Tax Period were includable on another Person’s Tax Return, Seller will control all proceedings and may make all decisions in connection with such Tax Claim (including
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selection of counsel) and, without limiting the foregoing, may in its sole discretion pursue or forego any and all administrative appeals, proceedings, hearings and conferences with any Tax Authority with respect thereto, and may, in its sole discretion, either pay the Tax claimed and sue for a refund where applicable Law permits such refund suits or contest the Tax Claim in any permissible manner; provided , however , that if such Tax Claim could reasonably be expected to have an adverse effect on Buyer or the Enbridge Entities in any Tax period or portion of a Straddle Period beginning on or after the Closing Date, the Tax Claim shall not be settled or resolved without the prior written consent of the Buyer (which consent shall not be unreasonably withheld, conditioned, or delayed). Buyer will control all proceedings and may, in its sole discretion, make all decisions in connection with any Tax Claim other than a Tax Claim described in the first sentence of this Section 7. 7(b) or a Tax Claim described in Section 7. 7(c) (including selection of counsel).
     (c) Seller and Buyer will jointly control and participate in all proceedings taken in connection with any Tax Claim relating to Taxes of any Enbridge Entity or Enbridge Entity Subsidiary for any Straddle Period. Neither Seller nor Buyer will settle any such Tax Claim without the prior written consent of the other (which consent shall not be unreasonably withheld, conditioned or delayed).
     (d) Each of Buyer, the Enbridge Entities, the Enbridge Entities Subsidiaries and their respective Affiliates, on the one hand, and the Seller and its respective Affiliates, on the other, will cooperate in contesting any Tax Claim, which cooperation will include the retention and (upon request) the provision to the requesting party of records and information that are reasonably relevant to such Tax Claim, and making employees available on a mutually convenient basis to provide additional information or explanation of any material provided hereunder or to testify at proceedings relating to such Tax Claim.
      Section 7.8 Refunds . If after the Closing Date, Buyer or any of the Enbridge Entities or Enbridge Entities Subsidiaries receives a refund of any Tax attributable to the Pre-Closing Tax Period (whether received in cash, or as a credit against other Taxes), Buyer shall pay to Seller within fifteen (15) days after such receipt an amount equal to such refund (or so much of such refund as relates to the Pre-Closing Tax Period determined in accordance with applicable principles of Section 7.4 and Section 7.6(c) ), together with any interest received or credited thereon.
ARTICLE VIII
CONDITIONS TO OBLIGATIONS
      Section 8.1 Conditions to Obligations of Buyer . The obligation of Buyer to consummate the transactions contemplated by this Agreement is subject to the satisfaction of the following conditions, any one or more of which may be waived in writing by Buyer:
     (a) The Buyer Approvals set forth in Schedule 5.3 and the Seller Approvals set forth in Schedule 3.3 (other than any Seller Approval constituting a notice requirement that by the terms of such requirement is not required to be satisfied prior to
 46 

 

the Closing Date) shall have been duly made, given or obtained and shall be in full force and effect;
     (b) Each of the representations and warranties of Seller contained in this Agreement shall be true and correct in all material respects (and in all respects, in the case of representations and warranties (including the representation in Section 4.5(a) ) which are qualified by materiality or by Material Adverse Effect) on the Closing Date as though made on the Closing Date, except to the extent such representations or warranties expressly relate to an earlier date, in which case they shall be true and correct in all material respects (and in all respects, in the case of representations and warranties which are qualified by materiality or by Material Adverse Effect) as of such earlier date;
     (c) Seller shall have performed or complied in all material respects with all of the covenants and agreements required by this Agreement to be performed or complied with by it at or before the Closing;
     (d) Seller shall have delivered to Buyer a certificate executed by an officer of Seller, dated the Closing Date, certifying that the conditions specified in Section 8.1(b) and Section 8. 1(c) have been fulfilled;
     (e) The Bamagas Preference Right has been exercised, waived or expired;
     (f) No preliminary or permanent injunction or other order, decree or ruling issued by a Governmental Authority, and no Law, statute, rule, regulation or executive order promulgated or enacted by a Governmental Authority, shall be in effect which restrains, enjoins, prohibits, or otherwise makes illegal the consummation of the transactions contemplated hereby. No Proceeding (excluding any initiated by Buyer or any of its Affiliates) is pending or threatened seeking to enjoin or restrain the consummation of the Closing or to recover damages from Buyer or any Affiliate of Buyer resulting therefrom; and
     (g) The Parties have agreed upon the Transition Services Agreement.
      Section 8.2 Conditions to the Obligations of Seller . The obligation of Seller to consummate the transactions contemplated by this Agreement is subject to the satisfaction of the following conditions, any one or more of which may be waived in writing by Seller:
     (a) The Seller Approvals set forth in Schedule 3.3 (other than any Seller Approval constituting a notice requirement that by the terms of such requirement is not required to be satisfied prior to the Closing Date) and the Buyer Approvals set forth in Schedule 5.3 shall have been duly made, given or obtained and shall be in full force and effect;
     (b) Each of the representations and warranties of Buyer contained in this Agreement shall be true and correct in all material respects (and in all respects, in the case of the representation and warranty in Section 5.8 and the representations and warranties which are qualified by materiality) on the Closing Date as though made on the Closing Date, except to the extent such representations or warranties expressly relate
 47 

 

to an earlier date, in which case they shall be true and correct in all material respects (and in all respects, in the case of representations and warranties which are qualified by materiality) as of such earlier date;
     (c) Buyer shall have performed or complied in all material respects with all of the covenants and agreements required by this Agreement to be performed or complied with by Buyer on or before the Closing;
     (d) Buyer shall have delivered to Seller a certificate executed by an officer of Buyer, dated the Closing Date, certifying that the conditions specified in Section 8. 2(b) and Section 8. 2(c) have been fulfilled;
     (e) The Bamagas Preference Right has been exercised, waived or expired;
     (f) No preliminary or permanent injunction or other order, decree or ruling issued by a Governmental Authority, and no Law, statute, rule, regulation or executive order promulgated or enacted by a Governmental Authority, shall be in effect which restrains, enjoins, prohibits, or otherwise makes illegal the consummation of the transactions contemplated hereby. No Proceeding (excluding any initiated by Seller or any of its Affiliates) is pending or threatened seeking to enjoin or restrain the consummation of the Closing or to recover damages from Seller or any Affiliate of Seller resulting therefrom; and
     (g) The Parties have agreed upon the Transition Services Agreement.
ARTICLE IX
INDEMNIFICATION
      Section 9.1 Survival . The representations, warranties, covenants, and agreements of the Parties contained in this Agreement shall survive the consummation of the transactions contemplated in this Agreement and shall continue after the Closing Date indefinitely; provided , however , that all representations and warranties contained in this Agreement (other than those contained in Article III (other than Section 3.4 ), Article V (other than Sections 5.4 and 5.7 ), and Sections 4.1, 4.2 , 4.8, and 4.9 , which shall terminate on the date that is 60 days after the expiration of all applicable statutes of limitation relating to the representations and warranties made in Article III (other than Section 3.4 ), Article V (other than Sections 5.4 and 5.7 ), and Sections 4.1 , 4.2 , 4.8, and 4.9 ) shall survive the Closing only until eighteen (18) months after the Closing Date. Neither Party shall have any liability for indemnification claims made under this Article IX with respect to any such representation, warranty, covenant or agreement unless a written notice of claim (describing in reasonable detail the claim, including an estimate of Losses attributable to such claim to the extent then known) is provided by Buyer to Seller or Seller to Buyer, as applicable, prior to the expiration of the applicable survival period for such representation, warranty, covenant or agreement. If a written notice of claim has been timely given in accordance with this Agreement prior to the expiration of the applicable survival period for such representation, warranty, covenant or agreement, then the applicable representation, warranty, covenant or agreement shall survive as to such claim, until such claim has been finally resolved.
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      Section 9.2 Indemnification .
     (a) Subject to the provisions of this Article IX , from and after the Closing, Seller shall indemnify, defend, and hold harmless Buyer and its Affiliates and their respective Representatives (the “ Buyer Indemnified Parties ”) from and against all Losses that the Buyer Indemnified Parties incur arising from (i) any breach of any representation or warranty of Seller in this Agreement or (ii) any breach of any covenant or agreement of Seller in this Agreement.
     (b) In addition to Section 9.2(a) , from and after the Closing, Seller shall indemnify, defend and hold harmless Buyer and its Affiliates from and against all Losses that arise out of or relate to the Seller Retained Liabilities.
     (c) Subject to the provisions of this Article IX , from and after the Closing, Buyer shall indemnify and hold harmless Seller and its Affiliates and their respective Representatives (the “ Seller Indemnified Parties ”) from and against all Losses that the Seller Indemnified Parties incur arising from (i) to the extent such Losses are not subject to the provisions of Section 9. 2(a) and do not pertain to a matter that is the subject of a claim notice delivered by Buyer by the date specified in Section 9.1 , the Entities Liabilities, (ii) any breach of any representation or warranty of Buyer in this Agreement or (iii) any breach of any covenant or agreement of Buyer in this Agreement.
     (d) Notwithstanding anything to the contrary herein, the Parties shall have a duty to use Reasonable Efforts to mitigate any Loss (which duty shall include the obligation to seek and use Reasonable Efforts to collect available insurance proceeds and indemnification and reimbursement payments) arising out of or relating to this Agreement or the transactions contemplated hereby.
      Section 9.3 Indemnification Procedures . Claims for indemnification under this Agreement shall be asserted and resolved as follows:
     (a) Any Buyer Indemnified Party or Seller Indemnified Party claiming indemnification under this Agreement (an “ Indemnified Party ”) with respect to any claim asserted against the Indemnified Party by a third party (“ Third Party Claim ”) in respect of any matter that is subject to indemnification under Section 9.2 shall promptly (i) notify the other Party (the “ Indemnifying Party ”) of the Third Party Claim and (ii) transmit to the Indemnifying Party a written notice (“ Claim Notice ”) describing in reasonable detail the nature of the Third Party Claim, a copy of all papers served with respect to such claim (if any), the Indemnified Party’s reasonable estimate of the amount of Losses attributable to the Third Party Claim and the basis of the Indemnified Party’s request for indemnification under this Agreement. Failure to timely provide such Claim Notice shall not affect the right of the Indemnified Party’s indemnification hereunder, except to the extent the Indemnifying Party is prejudiced by such delay or omission.
     (b) The Indemnifying Party shall have the right to defend the Indemnified Party against such Third Party Claim. If the Indemnifying Party notifies the Indemnified Party that the Indemnifying Party elects to assume the defense of the Third Party Claim
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(such election to be without prejudice to the right of the Indemnifying Party to dispute whether such claim is an indemnifiable Loss under this Article IX ), then the Indemnifying Party shall have the right to defend such Third Party Claim with counsel selected by the Indemnifying Party (who shall be reasonably satisfactory to the Indemnified Party), by all appropriate proceedings, to a final conclusion or settlement at the discretion of the Indemnifying Party in accordance with this Section 9.3(b) . The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof; provided that the Indemnifying Party shall not enter into any settlement agreement without the written consent of the Indemnified Party (which consent shall not be unreasonably withheld, conditioned or delayed); provided further , that such consent shall not be required if (i) the settlement agreement contains a complete and unconditional general release by the third party asserting the claim to all Indemnified Parties affected by the claim and (ii) the settlement agreement does not contain any sanction or restriction upon the conduct of any business by the Indemnified Party or its Affiliates. If requested by the Indemnifying Party, the Indemnified Party agrees, at the sole cost and expense of the Indemnifying Party, to cooperate with the Indemnifying Party and its counsel in contesting any Third Party Claim which the Indemnifying Party elects to contest, including the making of any related counterclaim against the Person asserting the Third Party Claim or any cross complaint against any Person. The Indemnified Party may participate in, but not control, any defense or settlement of any Third Party Claim controlled by the Indemnifying Party pursuant to this Section 9.3(b) , and the Indemnified Party shall bear its own costs and expenses with respect to such participation.
     (c) If the Indemnifying Party does not notify the Indemnified Party that the Indemnifying Party elects to defend the Indemnified Party pursuant to Section 9.3(b) , then the Indemnified Party shall have the right to defend, and be reimbursed for its reasonable cost and expense (but only if the Indemnified Party is actually entitled to indemnification hereunder) in regard to the Third Party Claim with counsel selected by the Indemnified Party (who shall be reasonably satisfactory to the Indemnifying Party), by all appropriate proceedings, which proceedings shall be prosecuted diligently by the Indemnified Party. In such circumstances, the Indemnified Party shall defend any such Third Party Claim in good faith and have full control of such defense and proceedings; provided , however , that the Indemnified Party may not enter into any compromise or settlement of such Third Party Claim if indemnification is to be sought hereunder, without the Indemnifying Party’s consent (which consent shall not be unreasonably withheld, conditioned or delayed). The Indemnifying Party may participate in, but not control, any defense or settlement controlled by the Indemnified Party pursuant to this Section 9.3(c) , and the Indemnifying Party shall bear its own costs and expenses with respect to such participation.
     (d) Subject to the other provisions of this Article IX , a claim for indemnification for any matter not involving a Third Party Claim may be asserted by notice to the Party from whom indemnification is sought.
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     (e) In the event an Indemnified Party shall recover Losses in respect of a claim of indemnification under this Article IX , no other Indemnified Party shall be entitled to recover the same Losses in respect of a claim for indemnification.
     (f) Notwithstanding anything to the contrary in this Section 9.3 , the indemnification procedures set forth in Article VII shall control any indemnities relating to Taxes.
      Section 9.4 Limitations on Liability of Seller .
     (a) Notwithstanding anything to the contrary herein, (i) Seller shall not be required to indemnify any Person under Section 9. 2(a)(i) with respect to a breach of any representation or warranty set forth in this Agreement unless the amount of Losses attributable to such breach exceed $50,000 and (ii) to the extent that the Losses attributable to such breach exceed $50,000, Seller shall not be required to indemnify any Person under Section 9. 2(a)(i) with respect to such breach unless the aggregate amount of Losses attributable to all such breaches in excess of $50,000 exceed $1,000,000, and in such event, Seller shall be responsible for only the amount in excess of $1,000,000. Furthermore, notwithstanding anything to the contrary herein, in no event shall Seller’s indemnification obligations under Section 9. 2(a)(i) exceed, in the aggregate, $16,000,000. The limitations in this Section 9. 4(a) shall not apply to any indemnification claims for breach of Seller’s representations or warranties in Article III (other than Section 3.4 ) and Sections 4.1 , 4.2 , 4.8, and 4.9 , or any Tax Losses, the liability with respect to which shall be as set forth in Section 7.6 .
     (b) No Buyer Indemnified Party shall be entitled to indemnification under Section 9. 2(a) to the extent Buyer has otherwise been compensated by reasons of adjustments (pursuant to Section 2.4 ) in the calculation of the Net Working Capital component of the Purchase Price relative to what it would have been absent such Loss.
      Section 9.5 Waiver of Other Representations and Warranties .
     (a) NOTWITHSTANDING ANYTHING TO THE CONTRARY HEREIN, IT IS THE EXPLICIT INTENT OF EACH PARTY HERETO, AND THE PARTIES HEREBY AGREE, THAT NEITHER SELLER NOR ANY OF ITS AFFILIATES OR REPRESENTATIVES HAS MADE OR IS MAKING ANY REPRESENTATION OR WARRANTY WHATSOEVER, EXPRESS OR IMPLIED, WRITTEN OR ORAL, INCLUDING ANY IMPLIED REPRESENTATION OR WARRANTY AS TO THE CONDITION, MERCHANTABILITY, USAGE, SUITABILITY OR FITNESS FOR ANY PARTICULAR PURPOSE WITH RESPECT TO THE INTERESTS, THE ENBRIDGE ENTITIES, THE ENBRIDGE ENTITIES SUBSIDIARIES OR THE ASSETS OF THE ENBRIDGE ENTITIES OR THE ENBRIDGE ENTITIES SUBSIDIARIES, THE BUSINESS OR ANY PART THEREOF, EXCEPT THOSE REPRESENTATIONS AND WARRANTIES EXPRESSLY CONTAINED IN THIS AGREEMENT, AND WITHOUT IN ANY WAY LIMITING THE FOREGOING, SELLER MAKES NO REPRESENTATION OR WARRANTY TO BUYER WITH RESPECT TO ANY FINANCIAL PROJECTIONS OR FORECASTS RELATING TO
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THE ENBRIDGE ENTITIES, THE ENBRIDGE ENTITIES SUBSIDIARIES OR THE BUSINESS.
     (b) EXCEPT AS OTHERWISE EXPRESSLY PROVIDED HEREIN, SELLER’S INTEREST IN THE ENBRIDGE ENTITIES AND THE ENBRIDGE ENTITIES SUBSIDIARIES AND THE ASSETS OF THE ENBRIDGE ENTITIES AND THE ENBRIDGE ENTITIES SUBSIDIARIES AND THE BUSINESS ARE BEING TRANSFERRED “AS IS, WHERE IS, WITH ALL FAULTS,” AND SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATIONS OR WARRANTIES OF ANY KIND OR NATURE, EXPRESS OR IMPLIED, AS TO THE CONDITION, VALUE OR QUALITY OF THE ENBRIDGE ENTITIES AND THE ENBRIDGE ENTITIES SUBSIDIARIES AND THE ASSETS OF THE ENBRIDGE ENTITIES AND THE ENBRIDGE ENTITIES SUBSIDIARIES, THE BUSINESS OR THE PROSPECTS (FINANCIAL OR OTHERWISE), RISKS AND OTHER INCIDENTS OF THE ENBRIDGE ENTITIES AND THE ASSETS OF THE ENBRIDGE ENTITIES, THE ENBRIDGE ENTITIES SUBSIDIARIES AND THE BUSINESS.
     (c) Without limiting the generality of the foregoing, the representations and warranties contained in Section 4.10 shall be the exclusive representations and warranties with regard to Environmental Laws and related matters.
      Section 9.6 Purchase Price Adjustment . The Parties agree to treat all payments made pursuant to Article VII and this Article IX as adjustments to the Purchase Price for Tax purposes.
      Section 9.7 Exclusive Remedy .
     (a) EXCEPT AS PROVIDED IN THE RELATED AGREEMENTS OR FOR CLAIMS FOR COMMON LAW ACTUAL FRAUD THAT IS ESTABLISHED BY A PARTY TO HAVE OCCURRED, THE PARTIES ACKNOWLEDGE AND AGREE THAT EACH PARTY’S SOLE AND EXCLUSIVE REMEDY WITH RESPECT TO THE SUBJECT MATTER OF THIS AGREEMENT FOLLOWING CLOSING SHALL BE PURSUANT TO THE INDEMNIFICATION PROVISIONS SET FORTH IN THIS AGREEMENT.
     (b) NOTWITHSTANDING ANYTHING TO THE CONTRARY HEREIN, NO PARTY SHALL BE LIABLE FOR SPECIAL, PUNITIVE, EXEMPLARY, INCIDENTAL, CONSEQUENTIAL OR INDIRECT DAMAGES, LOST PROFITS OR LOST BENEFITS, LOSS OF ENTERPRISE VALUE, DIMINUTION IN VALUE OF ANY BUSINESS, DAMAGES TO REPUTATION OR LOSS TO GOODWILL, WHETHER BASED ON CONTRACT, TORT, STRICT LIABILITY, OTHER LAW OR OTHERWISE AND WHETHER OR NOT ARISING FROM ANY OTHER PARTY’S SOLE, JOINT OR CONCURRENT NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT; PROVIDED , HOWEVER , THAT THIS SECTION 9.7(b) SHALL NOT LIMIT A PARTY’S RIGHT TO RECOVERY HEREUNDER FOR ANY SUCH DAMAGES TO THE EXTENT SUCH PARTY IS REQUIRED TO PAY SUCH DAMAGES TO A
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THIRD PARTY IN CONNECTION WITH A MATTER FOR WHICH SUCH PARTY IS OTHERWISE ENTITLED TO INDEMNIFICATION HEREUNDER.
ARTICLE X
TERMINATION
      Section 10.1 Termination . At any time prior to the Closing, this Agreement may be terminated and the transactions contemplated hereby abandoned:
     (a) by the mutual consent of Buyer and Seller as evidenced in a writing signed by each of Buyer and Seller;
     (b) by Buyer, if there has been a breach by Seller of any representation, warranty, covenant or agreement contained in this Agreement which has prevented the satisfaction of any condition to the obligations of Buyer to consummate the transactions contemplated hereunder at the Closing and, if such breach is of a character that it is capable of being cured, such breach has not been cured by Seller within thirty (30) days after written notice thereof from Buyer;
     (c) by Seller, if there has been a breach by Buyer of any representation, warranty, covenant or agreement contained in this Agreement which has prevented the satisfaction of any condition to the obligations of Seller to consummate the transactions contemplated hereunder at the Closing and, if such breach is of a character that it is capable of being cured, such breach has not been cured by Buyer within thirty (30) days after written notice thereof from Seller;
     (d) by either Buyer or Seller if any Governmental Authority having competent jurisdiction has issued a final, non-appealable order, decree, ruling or injunction (other than a temporary restraining order) or taken any other action permanently restraining, enjoining or otherwise prohibiting the transactions contemplated by this Agreement;
     (e) by either Buyer or Seller, if the Closing has not occurred on or before December 31, 2009 ( provided the Party seeking to terminate this Agreement is not in breach of any representation, warranty, covenant or agreement of such Party contained in this Agreement which has prevented the satisfaction of any condition to the obligations of the other Party to consummate the transactions contemplated hereunder at the Closing), or such later date as the Parties may agree upon; or
     (f) by Buyer as provided in Section 6.14 .
      Section 10.2 Effect of Termination . In the event of termination and abandonment of this Agreement pursuant to Section 10.1 , this Agreement shall forthwith become void and have no effect, without any liability on the part of any Party hereto; provided , however , that if this Agreement is validly terminated by a Party as a result of an intentional and material breach of this Agreement by the non-terminating Party, then the terminating Party shall be entitled to all rights and remedies available under Law or equity. Notwithstanding the foregoing, the provisions of Section 6.2(b) , Section 6. 6(b) and Article XI shall survive any termination of this
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Agreement. The Confidentiality Agreement shall not be affected by a termination of this Agreement.
ARTICLE XI
MISCELLANEOUS
      Section 11.1 Notices . All notices and other communications between the Parties shall be in writing and shall be deemed to have been duly given when (a) delivered in person, (b) one Business Day after delivery to an overnight delivery service ( e.g. , FedEx), freight prepaid, or (c) delivered by facsimile and contemporaneously delivered in person or by overnight delivery service, freight prepaid, addressed as follows:
     (i) If to Seller, to:
Enbridge Midcoast Energy, L.P.
1100 Louisiana Street, Suite 3300
Houston, Texas 77002
Attention: Controller
Facsimile: (713) 821-6710
with a copy (which shall not constitute notice) to:
Enbridge Midcoast Energy, L.P.
1100 Louisiana Street, Suite 3300
Houston, Texas 77002
Attention: Vice President Law
Facsimile: (713) 821-2229
with a copy (which shall not constitute notice) to:
Fulbright & Jaworski L.L.P.
Fulbright Tower
1301 McKinney, Suite 5100
Houston, Texas 77010
Attention: Ms. Deborah A. Gitomer
Facsimile: (713) 651-5246
     (ii) If to Buyer, to:
American Midstream, LLC
950 Tower Lane, Suite 800
Foster City, CA 94404
Attention: Mr. Matt Carbone or Mr. Ed Diffendal
Facsimile: (650) 854-0853
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with a copy (which shall not constitute notice) to:
Andrews Kurth LLP
600 Travis, Suite 4200
Houston, Texas 77002
Attention: Mr. G. Michael O’Leary
Facsimile: (713) 238-7130
or to such other address or addresses as the Parties may from time to time designate in writing.
      Section 11.2 Assignment . No Party shall assign this Agreement or any part hereof without the prior written consent of the other Party. Subject to the foregoing, this Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and permitted assigns.
      Section 11.3 Rights of Third Parties . Nothing in this Agreement shall entitle any Person other than Buyer and Seller to any Losses, remedy or right of any kind, except as to those rights expressly provided to the Seller Indemnified Parties and the Buyer Indemnified Parties ( provided, however , any claim for indemnity hereunder on behalf of a Seller Indemnified Party or a Buyer Indemnified Party must be made and administered by a Party).
      Section 11.4 Expenses . Except as otherwise provided herein, each Party shall bear its own expenses incurred in connection with this Agreement and the transactions herein contemplated whether or not such transactions shall be consummated, including all fees of its legal counsel, financial advisers and accountants.
      Section 11.5 Counterparts . This Agreement may be executed in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument. Any facsimile copies hereof or signatures hereon shall, for all purposes, be deemed originals.
      Section 11.6 Entire Agreement . This Agreement (together with the Disclosure Schedules and exhibits to this Agreement), the Buyer Guarantee and the Confidentiality Agreement constitute the entire agreement among the Parties and supersede any other agreements, whether written or oral, that may have been made or entered into by or among any of the Parties or any of their respective Affiliates relating to the transactions contemplated hereby.
      Section 11.7 Disclosure Schedules . Unless the context otherwise requires, all capitalized terms used in the Disclosure Schedules shall have the respective meanings assigned in this Agreement. No reference to or disclosure of any item or other matter in the Disclosure Schedules shall be construed as an admission or indication that such item or other matter is material or that such item or other matter is required to be referred to or disclosed in the Disclosure Schedules. No disclosure in the Disclosure Schedules relating to any possible breach or violation of any agreement or Law shall be construed as an admission or indication that any such breach or violation exists or has actually occurred. The inclusion of any information in the
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Disclosure Schedules shall not be deemed to be an admission or acknowledgment by Seller, in and of itself, that such information is material to or outside the ordinary course of the business of the Enbridge Entities or the Enbridge Entities Subsidiaries or required to be disclosed on the Disclosure Schedules.
      Section 11.8 Amendments . This Agreement may be amended or modified in whole or in part, and terms and conditions may be waived, only by a duly authorized agreement in writing which makes reference to this Agreement executed by each Party.
      Section 11.9 Publicity . All press releases or other public communications of any nature whatsoever relating to the transactions contemplated by this Agreement, and the method of the release for publication thereof, shall be subject to the prior written consent of Buyer and Seller, which consent shall not be unreasonably withheld, conditioned or delayed by any Party; provided , however , that a Party may publish such press releases or other public communications as such Party may consider necessary in order to satisfy such Party’s obligations at Law or under the rules of any stock or commodities exchange after consultation with the other Party as is reasonable under the circumstances and providing the other Party the opportunity to review such press release or other public communication.
      Section 11.10 Severability . If any provision of this Agreement is held invalid or unenforceable by any court of competent jurisdiction, the other provisions of this Agreement shall remain in full force and effect. The Parties further agree that if any provision contained herein is, to any extent, held invalid or unenforceable in any respect under the Laws governing this Agreement, they shall take any actions necessary to render the remaining provisions of this Agreement valid and enforceable to the fullest extent permitted by Law and, to the extent necessary, shall amend or otherwise modify this Agreement to replace any provision contained herein that is held invalid or unenforceable with a valid and enforceable provision giving effect to the intent of the Parties to the greatest extent legally permissible.
      Section 11.11 Governing Law; Jurisdiction .
     (a) This Agreement shall be governed and construed in accordance with the Laws of the State of Delaware without regard to the Laws that might be applicable under conflicts of laws principles.
     (b) The Parties agree that the appropriate, exclusive and convenient forum for any disputes between any of the Parties hereto arising out of this Agreement or the transactions contemplated hereby shall be in any state or federal court in Wilmington, Delaware, and each of the Parties hereto irrevocably submits to the jurisdiction of such courts solely in respect of any legal proceeding arising out of or related to this Agreement. The Parties further agree that the Parties shall not bring suit with respect to any disputes arising out of this Agreement or the transactions contemplated hereby in any court or jurisdiction other than the above specified courts; provided , however , that the foregoing shall not limit the rights of the Parties to obtain execution of judgment in any other jurisdiction. The Parties further agree, to the extent permitted by Law, that a final and unappealable judgment against a Party in any action or proceeding contemplated above shall be conclusive and may be enforced in any other jurisdiction within or outside
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the United States by suit on the judgment, a certified copy of which shall be conclusive evidence of the fact and amount of such judgment. Except to the extent that a different determination or finding is mandated due to the applicable law being that of a different jurisdiction, the Parties agree that all judicial determinations or findings by a state or federal court in Wilmington, Delaware with respect to any matter under this Agreement shall be binding.
     (c) To the extent that any Party hereto has or hereafter may acquire any immunity from jurisdiction of any court or from any legal process (whether through service or notice, attachment prior to judgment, attachment in aid of execution, execution or otherwise) with respect to itself or its property, each such party hereby irrevocably (i) waives such immunity in respect of its obligations with respect to this Agreement and (ii) submits to the personal jurisdiction of any court described in Section 11.11(b) .
     (d) THE PARTIES HERETO AGREE THAT THEY HEREBY IRREVOCABLY WAIVE THE RIGHT TO TRIAL BY JURY IN ANY ACTION TO ENFORCE OR INTERPRET THE PROVISIONS OF THIS AGREEMENT.
      Section 11.12 Further Assurances . Seller will execute and deliver or cause to be executed and delivered to Buyer, and Buyer will execute and deliver or cause to be executed and delivered to Seller, such further instruments of transfer, assignment and conveyance and take such other action as the other Party may reasonably require to more effectively carry out the consummation of the transactions contemplated by this Agreement.
      Section 11.13 Enbridge Entity Plan . Notwithstanding anything herein provided to the contrary, Buyer does hereby acknowledge and agree that it shall not claim that Seller is in breach of any representation, warranty, covenant or agreement under this Agreement on account of the fact that the documentation evidencing the plan referenced in Schedule 4.8(c) has not been finalized or executed. Seller does hereby covenant and agree that it shall finalize and execute such documentation with ten (10) days following the date of this Agreement and shall promptly furnish Buyer with copies of same. Seller does hereby confirm that (a) such plan (i) is consistent with the description of the plan that has been previously furnished by Seller to Buyer, (ii) has been fully funded to date, and (iii) has been administered in accordance with the established plan provisions and (b) Seller has fully disclosed to Buyer all eligible participants of such plan.
[SIGNATURE PAGE FOLLOWS]
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IN WITNESS WHEREOF this Agreement has been duly executed and delivered by each Party as of the date first above written.
 	 	 	 	 	
 	SELLER:

ENBRIDGE MIDCOAST ENERGY, L.P.
 	 	
 	By:  	Enbridge Midcoast Holdings, L.L.C.,
its general partner  	 	

 	By:  	/s/ Terrance L. McGill  	 	
 	 	Terrance L. McGill 	 	
 	 	President 	 	

 	BUYER:

AMERICAN MIDSTREAM, LLC
 	 	
 	By:  	/s/ Brian Bierbach  	 	
 	 	Brian Bierbach 	 	
 	 	Chief Executive Officer and President 	 	
 	
Signature Page to Membership Interests
Purchase and Sale Agreement

Exhibit 10.14
GAS TRANSPORTATION CONTRACT
BETWEEN
MIDCOAST INTERSTATE TRANSMISSION, INC.
AND
CITY OF DECATUR UTILITIES
CONTRACT NO. 6050
NOVEMBER 1, 1997

 

CONTRACT NO. 6050
GAS TRANSPORTATION CONTRACT
(For Use Under Rate Schedule FT)
          THIS CONTRACT is made and entered into as of the 1st day of November, 1997, by and between MIDCOAST INTERSTATE TRANSMISSION, INC., an Alabama Corporation, hereinafter referred to as “Transporter” and the CITY OF DECATUR UTILITIES, a Municipal corporation, hereinafter referred to as “Shipper.” Transporter and Shipper shall collectively be referred to herein as the “Parties.”
WITNESSETH:
          That in consideration of the premises and of the mutual covenants and agreements herein contained, Transporter and Shipper agree as follows:
ARTICLE I
DEFINITIONS

1.1	 	TRANSPORTATION QUANTITY — shall mean the Maximum Daily Quantity (“MDQ”) of gas which Transporter agrees to receive and transport, subject to Article II herein, for the account of Shipper hereunder, which on each day shall be 1,745 dekatherms. Any limitations of the quantities to be received from each Point of Receipt and/or delivered to each Point of Delivery shall be as specified on Exhibit(s) A and B attached hereto.	
 		
1.2	 	EQUIVALENT QUANTITY — shall mean that the quantities of gas delivered hereunder at the Point(s) of Delivery shall be the thermal equivalent of the quantities of gas received at the Point(s) of Receipt for transportation less, the Fuel and Losses Quantity associated with this transportation service in accordance with Section 6 of Rate Schedule FT.	
 		
1.3	 	OTHER CAPITALIZED TERMS — other capitalized terms utilized in this Contract shall have the same meanings provided for in Transporter’s FERC Gas Tariff.	
ARTICLE II
TRANSPORTATION SERVICE
          Transporter agrees to accept and receive daily on a firm basis, at the Point(s) of Receipt from Shipper or for Shipper’s account such quantity of gas as Shipper makes available up to the MDQ, excluding Fuel and Losses Quantity, as specified in Section 1.1 and to transport and deliver to or for the account of Shipper to the Point(s)
 1 

 

of Delivery an equivalent quantity of gas; provided, that Transporter, at its option, may agree to receive, transport and deliver quantities of gas in excess of the amounts specified in Section 1.1, subject to the limitations and conditions specified in Section 2 of Rate Schedule FT.
ARTICLE III
PRIMARY POINT(S) OF RECEIPT AND DELIVERY

3.1	 	The Primary Point(s) of Receipt and Delivery shall be those points specified on Exhibit(s) A and B attached hereto.	
 		
3.2	 	Shipper may supplement Primary Point(s) of Receipt and/or Point(s) of Delivery provided by this Contract by submitting to Transporter a Customer Nomination Form. Such request form, after having been fully processed and accepted by Transporter, shall be deemed to have the full force and effect of a written Contract and shall qualify as a supplementary written consent pursuant to Paragraph 17.3 of this Contract. Priority of transportation service to such additional Points of Receipt and/or Delivery shall be determined pursuant to Section 3 of the General Terms and Conditions of Transporter’s FERC Gas Tariff. Shipper may nominate Secondary Point(s) of Receipt and/or Delivery within Shipper’s MDQ by submitting to Transporter a revised Customer Nomination Form.	
ARTICLE IV
FACILITIES

4.1	 	All facilities are in place to render the service provided for in this Contract.	
ARTICLE V
RECEIPT AND DELIVERY PRESSURES
          Shipper shall deliver or cause to be delivered to Transporter the gas to be transported hereunder at pressures sufficient to deliver such gas into Transporter’s system at the Point(s) of Receipt. Transporter shall deliver the gas to be transported hereunder to or for the account of Shipper at the pressures existing in Transporter’s system at the Point(s) of Delivery.
ARTICLE VI
QUALITY SPECIFICATIONS AND STANDARDS FOR MEASUREMENT
          For all gas received, transported and delivered hereunder the parties agree to the Quality Specifications and Standards for Measurement as specified in the General Terms and Conditions of Transporter’s FERC Gas Tariff Second Revised Volume No. 1. To the extent that no new measurement facilities are installed to provide service
 2 

 

hereunder, measurement operations will continue in the manner in which they have previously been handled. In the event that such facilities are not operated by Transporter then responsibility for operations shall be deemed to be Shipper’s. Any exceptions to this Article shall be specified on Exhibits(s) N/A attached hereto.
ARTICLE VII
RATES AND CHARGES FOR GAS TRANSPORTATION

7.1	 	TRANSPORTATION RATES — Commencing with the date of execution the compensation to be paid by Shipper to Transporter for the transportation service provided herein, including system fuel and losses, shall be in accordance with Transporter’s Rate Schedule FT and the General Terms and Conditions of Transporter’s FERC Gas Tariff.	
 		
7.2	 	NEW FACILITIES CHARGE — N/A	
 		
7.3	 	INCIDENTAL CHARGES — Shipper agrees to reimburse Transporter for any filing or similar fees and taxes, which have not been previously paid by Shipper, which Transporter incurs in rendering service hereunder.	
 		
7.4	 	OTHER CHARGES — Shipper agrees to pay, if applicable, other charges as listed in Section 5.4, 5.5, 5.6, 5.7 and 5.8 of Rate Schedule FT.	
 		
7.5	 	CHANGES IN RATES AND CHARGES — Transporter shall have the unilateral right to file and make effective changes in the rates and charges stated in this Article, the rates and charges applicable to service pursuant to Transporter’s Rate Schedule FT, the Rate Schedule pursuant to which this service is rendered and/or any provisions of the General Terms and Conditions in Transporter’s FERC Gas Tariff applicable to this service. Without prejudice to Shipper’s right to contest such changes, Shipper agrees to pay the effective rates and charges for service rendered pursuant to this Contract.	
ARTICLE VIII
BILLINGS AND PAYMENT
          Transporter shall bill and Shipper shall pay all rates and charges in accordance with Section 5 and 6, respectively, of the General Terms and Conditions of Transporter’s FERC Gas Tariff.
 3 

 

ARTICLE IX 1
TAXES
          Shipper agrees to pay the amount of any tax and/or any increase of any additional tax (as tax and additional tax is defined in the next sentence hereof) which Transporter shall be required to pay. The term “tax” and “additional tax” shall mean collectively any sales (wholesale or retail), transactions, occupation, privilege license or franchise, service, production, severance, gathering, transmission, export or excise tax, assessment, fee, gross receipts or other exaction, whether of the kind herein enumerated, or otherwise (not including income, excess profits, capital stock, state franchise or general property taxes) hereafter levied, accessed or fixed by the United States or any state or other governmental authority, measured by, in respect of or applicable to the natural gas to be delivered by Transporter to Shipper under this Contract, and which Transporter may be liable for in any month either directly or indirectly through any obligation of Transporter to reimburse others.
X
GENERAL TERMS AND CONDITIONS
          This Contract shall be subject to the provisions of Transporter’s Rate Schedule FT and to the General Terms and Conditions of Transporter’s FERC Gas Tariff incorporated therein, as the same may be changed or superseded from time to time in accordance with the rules and regulations of the FERC, which Rate Schedule and General Terms and Conditions are incorporated herein by reference and made a part hereof for all purposes.
ARTICLE XI
REGULATION
          This Contract shall be subject to all applicable and lawful governmental statutes, orders, rules and regulations and is contingent upon the receipt and continuation of all necessary regulatory approvals or authorizations upon terms acceptable to Transporter. This Contract shall be void and of no force and effect if any necessary regulatory approval is not so obtained or continued. All parties hereto shall cooperate to obtain or continue all necessary approvals or authorizations, but no party shall be liable to any other party for failure to obtain or continue such approvals or authorizations.

1	 	This provision presently applies to the Alabama Utility Gross Receipts Tax. Taxes collected pursuant to this Article shall not be included in Transporter’s FERC cost of service used for the design of jurisdictional rates.	
 4 

 

ARTICLE XII
RESPONSIBILITY DURING TRANSPORTATION
          Except as herein specified, the responsibility for gas during transportation shall be as stated in the General Terms and Conditions of Transporter’s FERC Gas Tariff.
ARTICLE XIII
WARRANTIES
          In addition to the warranties set forth in Section 9 of the General Terms and Conditions of Transporter’s FERC Gas Tariff, Shipper warrants the following:

13.1	 	Shipper warrants that all upstream and downstream transportation arrangements are in place, or will be in place as of the requested effective date of service, and that it has advised the upstream and downstream transporters of the Receipt and Delivery Point(s) under this Contract and any quantity limitations for each point as specified on Exhibits(s) A and B attached hereto. Shipper agrees to indemnify and hold Transporter harmless for refusal to transport gas hereunder in the event any upstream or downstream transporter fails to receive or deliver gas as contemplated by this Contract.	
 		
13.2	 	If transportation hereunder is pursuant to Subpart B of Part 284 of the FERC’s Regulations, Shipper warrants that the service provided hereunder is on behalf of an intrastate pipeline or a local distribution company within the meaning of Section 311(a)(l) of the Natural Gas Policy Act of 1978.	
 		
13.3	 	Shipper agrees to indemnify and hold Transporter harmless from all suits, actions, debts, accounts, damages, costs, losses and expenses (including reasonable attorneys fees) arising from or out of breach of any warranty, express or implied, by Shipper herein.	
 		
13.4	 	Transporter shall not be obligated to provide or continue service hereunder in the event of any breach of warranty.	
ARTICLE XIV
TERM

14.1	 	The term of this Contract shall commence November 1, 1997 and shall continue in full force and effect until November 1, 2002 (the “Primary Term”). Providing Shipper is paying Transporter’s Maximum FT transportation rate, the term of this Contract shall continue after the Primary Term for successive periods of one (1) year each (the “Renewal Terms”), unless terminated as of the end of any such Primary Term or Renewal Term by written notice given by either party to the other not less than twelve (12) months prior to the end of any such term. If the	
 5 

 

 	 	FERC or other governmental body having jurisdiction over the service rendered pursuant to the Contract authorizes abandonment of such service, this Contract shall terminate on the abandonment date permitted by the FERC or such other governmental body.	
 		
14.2	 	Any portions of this Contract necessary to correct or cash-out imbalances under this Contract as required by the General Terms and Conditions of Transporter’s FERC Gas Tariff, shall survive the other parts of this Contract until such time as such balancing has been accomplished.	
 		
14.3	 	Transporter may elect to terminate this Contract in the event Shipper fails to pay all of the amount of any bill for service rendered by Transporter hereunder in accord with the terms and conditions of Section 6 of the General Terms and Conditions of Transporter’s FERC Gas Tariff.	
ARTICLE XV
NOTICE
          Except as otherwise provided in the General Terms and Conditions applicable to this Contract, any notice under this Contract shall be in writing and mailed to the post office address of the party intended to receive the same, as follows:

 	 	Midcoast Interstate Transmission, Inc.	
 	 	3230 Second Street	
 	 	P.O. Box 3869	
 	 	Muscle Shoals, AL 35662-3869	
 	 	ATTENTION: Transportation Services	
 	 	Facsimile: 205-381-2858	
SHIPPER:	 	 	
NOTICES:	 	City of Decatur Utilities	
 	 	Post Office Box 2232	
 	 	Decatur, AL 35609	
 	 	Attention: David L. Parks	
 	 	Business Development & Assistant General Manager	
 	 	Tel: (205) 552-1440	
 	 	Fax:(205) 552-1410	
 	 	 	
BILLINGS:	 	City of Decatur Utilities	
 	 	Post Office Box 2232	
 	 	Decatur, AL 35609	
 	 	Attention: David L. Parks	
 	 	Business Development & Assistant General Manager	
 	 	Tel: (205) 552-1440	
 	 	Fax:(205) 552-1410	
 6 

 

or to such other address as either Party shall designate by formal written notice to the other.
ARTICLE XVI
ASSIGNMENTS

16.1	 	Either Party may assign or pledge this Contract and all rights and obligations hereunder under the provisions of any mortgagee, deed of trust, indenture, or other instrument which it has executed or may execute hereafter as security for indebtedness. Either Party may, without relieving itself of its obligations under this Contract, assign any of its rights hereunder to a company with which it is affiliated, otherwise Shipper shall not assign this Contract or any of its rights hereunder, except in accord with Section 3 of the General Terms and Conditions of Transporter’s FERC Gas Tariff, unless it shall first have obtained the written consent of Transporter.	
 		
16.2	 	Any person which shall succeed by purchase, merger, or consolidation to the properties, substantially as an entirety, of either party hereto shall be entitled to the right and shall be subject to the obligations of its predecessor in interest under this Contract.	
ARTICLE XVII
MISCELLANEOUS

17.1	 	This Contract shall be interpreted under the laws of the State of Alabama.	
 		
17.2	 	If any provision of this Contract is declared null and void, or voidable, by a court of competent jurisdiction, then that provision will be considered severable upon consent of Transporter and the Shipper; and if the severability option is exercised, the remaining provisions of the Contract shall remain in full force and effect.	
 		
17.3	 	No modification of or supplement to the terms and provisions hereof shall be or become effective, except by the execution of supplementary written consent.	
 		
17.4	 	Exhibit(s) A and B attached hereto is/are incorporated herein by reference and made a part hereof for all purposes.	
 7 

 

          IN WITNESS WHEREOF, the parties hereto have caused this Contract to be duly executed in several counterparts as of the date first hereinabove written.

 	 	MIDCOAST INTERSTATE TRANSMISSION, INC.	 	 	
 	 	 	 	 	 	 	
Attest: /s/ Donald R. Whittington	 	By:	 	/s/ I.P. Morinos 	 	 	
 	 	 	 	 	 	 	
 	 	 	 	Agent and Attorney-in-fact	 	 	
 	 	 	 	 	 	 	
 	 	Accepted and Agreed to this
24 th day of October, 1997	 	 	
 	 	 	 	 	 	 	
SHIPPER:	 	CITY OF DECATUR UTILITIES	 	 	
 	 	 	 	 	 	 	
Attest:	 	By:	 	/s/ David L. Parker 	 	 	

  	 	Accepted and Agreed to this
23 day of October, 1997

Business Development & Asst. General Mgr.	 	 	
 8 

 

EXHIBIT “A”
TO FIRM GAS TRANSPORTATION AGREEMENT
DATED NOVEMBER 1, 1997
BETWEEN
MIDCOAST INTERSTATE TRANSMISSION, INC.
AND
CITY OF DECATUR UTILITIES
CONTRACT NO. 6050
POINT(S) OF RECEIPT
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	METER NO.	 	DESCRIPTION	 	VOLUME	
 	*	 	 	10160	 	 	Barton-TGP, Colbert County, AL	 	 	1,745	 	
 	 	 	 	10040	 	 	Corinth-TGP, Alcorn County, MS	 	 	 	 	
 	 	 	 	10060	 	 	Corinth-CGT, Alcorn County, MS	 	 	 	 	
 	 	 	 	10180	 	 	TRIGAS-TETCO, Colbert County, AL	 	 	 	 	
 	 	 	 	10290	 	 	Florence #2 - TGP, Lauderdale Co., AL	 	 	 	 	

*	 	Denotes Primary Receipt Point(s)	

 
EXHIBIT “B”
TO FIRM GAS TRANSPORTATION AGREEMENT
DATED NOVEMBER 1, 1997
BETWEEN
MIDCOAST INTERSTATE TRANSMISSION, INC.
AND
CITY OF DECATUR UTILITIES
CONTRACT NO. 6050
POINT(S) OF DELIVERY
 	 	 	 	 	 	 	 	 	
METER NO.	 	DESCRIPTION	 	VOLUME	
 	10010	 	 	Selmer Delivery	 	 	 	 	
 	10020	 	 	Kimberly-Clark Delivery	 	 	 	 	
 	10030	 	 	PCA Delivery	 	 	 	 	
 	10070	 	 	Counce Delivery	 	 	 	 	
 	10080	 	 	Burnsville Delivery	 	 	 	 	
 	10090	 	 	Lockheed Delivery	 	 	 	 	
 	10100	 	 	luka Delivery	 	 	 	 	
 	10110	 	 	Tishomingo Delivery	 	 	 	 	
 	10120	 	 	Margerum Delivery	 	 	 	 	
 	10130	 	 	Cherokee Delivery	 	 	 	 	
 	10140	 	 	Laroche Delivery	 	 	 	 	
 	10150	 	 	Barton Delivery	 	 	 	 	
 	10170	 	 	TVA Turbines Delivery	 	 	 	 	
 	10200	 	 	Sheffield #4 - Dry Creek	 	 	 	 	
 	10210	 	 	Pride #1 Delivery	 	 	 	 	
 	10220	 	 	Pride #2 Delivery	 	 	 	 	
 	10230	 	 	Sheffield #2	 	 	 	 	
 	10240	 	 	Tuscumbia Delivery	 	 	 	 	
 	10250	 	 	Russellville Delivery	 	 	 	 	
 	10260	 	 	Avalon Delivery	 	 	 	 	
 	10270	 	 	Sheffield #1	 	 	 	 	
 	10280	 	 	Florence #1 Delivery	 	 	 	 	
 	10290	 	 	Florence #2 - Oakland	 	 	 	 	
 	10300	 	 	TVA NFERC Delivery	 	 	 	 	
 	10310	 	 	MSC #3 Occidental Chemical	 	 	 	 	
 	10330	 	 	Sheffield #3 TVA	 	 	 	 	
 	10350	 	 	Key Equipment	 	 	 	 	
 	10370	 	 	MSC#1	 	 	 	 	
 	10380	 	 	Sheffield #5 - Rogers Group	 	 	 	 	
 	10390	 	 	U.S. Die Casting Delivery	 	 	 	 	
 	10440	 	 	David King	 	 	 	 	
 	10450	 	 	Reynolds Reclamation Delivery	 	 	 	 	
 	10460	 	 	Listerhill Delivery	 	 	 	 	
 	10470	 	 	Reynolds Delivery	 	 	 	 	
 	10480	 	 	Nitrate City Delivery	 	 	 	 	
 	10490	 	 	MSC #2 Industrial Park	 	 	 	 	
 	10500	 	 	Leighton Delivery	 	 	 	 	
 	10510	 	 	Town Creek Delivery	 	 	 	 	

 

EXHIBIT “B”
TO FIRM GAS TRANSPORTATION AGREEMENT
DATED NOVEMBER 1, 1997
BETWEEN
MIDCOAST INTERSTATE TRANSMISSION, INC.
AND
CITY OF DECATUR UTILITIES
CONTRACT NO. 6050
POINT(S) OF DELIVERY
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	METER NO.	 	DESCRIPTION	 	VOLUME	
 	 	 	 	10520	 	 	Courtland Delivery	 	 	 	 	
 	 	 	 	10530	 	 	Moulton Delivery	 	 	 	 	
 	 	 	 	10540	 	 	Champion Delivery	 	 	 	 	
 	 	 	 	10550	 	 	Hillsboro Delivery	 	 	 	 	
 	 	 	 	10554	 	 	TRICO Steel Delivery	 	 	 	 	
 	 	 	 	10558	 	 	Trinity Delivery	 	 	 	 	
 	 	 	 	10560	 	 	Amoco Delivery	 	 	 	 	
 	*	 	 	10600	 	 	Decatur Delivery	 	 	1,745	 	
 	 	 	 	10610	 	 	TRIGAS-Morgan County	 	 	 	 	
 	 	 	 	10618	 	 	Priceville Delivery	 	 	 	 	
 	 	 	 	10620	 	 	Hartselle Delivery	 	 	 	 	
 	 	 	 	10630	 	 	Flint Delivery	 	 	 	 	
 	 	 	 	10660	 	 	Pryor Field #1 Delivery	 	 	 	 	
 	 	 	 	10670	 	 	Pryor Field #2 Delivery	 	 	 	 	
 	 	 	 	10680	 	 	Tanner #1 Delivery	 	 	 	 	
 	 	 	 	10690	 	 	Tanner #2 Delivery	 	 	 	 	
 	 	 	 	10700	 	 	Strain Nursery	 	 	 	 	
 	 	 	 	10710	 	 	Athens Delivery	 	 	 	 	
 	 	 	 	10720	 	 	Belle Mina Delivery	 	 	 	 	
 	 	 	 	10730	 	 	Greenbrier Delivery	 	 	 	 	
 	 	 	 	10740	 	 	Huntsville #2 Delivery	 	 	 	 	
 	 	 	 	10750	 	 	Madison #3 Delivery	 	 	 	 	
 	 	 	 	10760	 	 	Madison #2 Delivery	 	 	 	 	
 	 	 	 	10770	 	 	Madison #1 Delivery	 	 	 	 	
 	 	 	 	10780	 	 	Huntsville #1 Delivery	 	 	 	 	

*	 	Denotes Primary Delivery Point(s)	
FUEL AND LOSS
o PURCHASED                     PROVIDED þ
MIT’s currently effective fuel and loss percentage is — 0.8%

Exhibit 10.15
AMENDMENT NO. 1 TO GAS TRANSPORTATION CONTRACT
     THIS AGREEMENT entered into on November 1, 2003, by and between ENBRIDGE PIPELINE (Alatenn), INC., hereinafter referred to as “Transporter”, and THE CITY OF DECATUR, ALABAMA, hereinafter referred to as “Shipper”;
W I T N E S S E T H :
     WHEREAS, Transporter and Shipper are parties to that certain FT Contract No. 6050 dated November 1, 1997 (Contract), relating to the firm transportation of natural gas; and
     WHEREAS, Transporter and Shipper desire to amend the Contract as set out below;
     NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein, the parties hereto do hereby agree as follows:

 	A.	 	Effective November 1, 2004, Paragraph 1.1 of ARTICLE I is deleted in its entirety and replaced by the following:	
 		
 	 	 	“1.1 TRANSPORTATION QUANTITY — shall mean the Maximum Daily Quantity (“MDQ”) of gas which Transporter agrees to receive and transport, subject to Article II herein, for the account of Shipper hereunder, which on each day shall be 500 dekatherms. Any limitations of the quantities to be received from each Point of Receipt and/or delivered to each Point of Delivery shall be as specified on Exhibit(s) A-1 and B-1 attached hereto.”	
 		
 	B.	 	Effective November 1, 2004, Paragraph 14.1 of ARTICLE XIV is deleted in its entirety and replaced by the following:	
 		
 	 	 	“14.1 The term of the contract shall commence November 1, 1997 and shall continue in full force and effect until November 1, 2007 (the “Primary Term”). Providing Shipper is paying Transporter’s Maximum FT transportation rate, the term of this Contract shall continue after the Primary Term for successive periods of one (1) year each (the “Renewal Terms”), unless terminated as of the end of any such Primary Term or Renewal Term by written notice given by either party to the other not less than twelve (12) months prior to the end of any such term. If the FERC or other governmental body having jurisdiction over the service rendered pursuant to the Contract authorizes abandonment of such service, this Contract shall terminate on the abandonment date permitted by the FERC or such other governmental body.	
 		
 	C.	 	Effective November 1, 2004, Exhibit A and Exhibit B are deleted and replaced by Exhibit A-1 and Exhibit B-1.	

 

Signature page to Amendment No. 1 to Gas Transportation Contract dated November 1, 1997
between
ENBRIDGE PIPELINE (Alatenn), INC. and THE CITY OF DECATUR, ALABAMA
     IN WITNESS WHEREOF, this Agreement has been executed by the parties to be effective as of the date first written above.

 	 	 	 	TRANSPORTER:	 	 	
 	 	 	 	 	 	 	 	 	
 	 	 	 	ENBRIDGE PIPELINE (Alatenn), INC.	 	 	

 	 	 	 	By:	 	/s/ Terrence L. McGill 	 	 	

 	 	 	 	 	 	 	 	 	
 	 	 	 	Name: Terrance L. McGill	 	 	
 	 	 	 	 	 	 	 	 	
 	 	 	 	Title:	 	Vice-President Commercial Activity	 	 	
 	 	 	 	 	 	 	 	 	
 	 	 	 	Date:	 	10-27-03 	 	 	

 	 	 	 	 	 	 	 	 	
 	 	 	 	SHIPPER:	 	 	
 	 	 	 	 	 	 	 	 	
 	 	 	 	THE CITY OF DECATUR, ALABAMA	 	 	

 	 	 	 	By:	 	/s/ Kem M. Carr 	 	 	

 	 	 	 	 	 	 	 	 	
 	 	 	 	Name:	 	Kem M. Carr 	 	 	

 	 	 	 	Title:	 	General Manager 	 	 	

 	 	 	 	Date:	 	10-23-03 	 	 	

   

 

REVISED EXHIBIT “A-1”
TO FIRM GAS TRANSPORTATION CONTRACT
DATED NOVEMBER 1, 1997
BETWEEN
ENBRIDGE PIPELINE (Alatenn), INC.
AND
THE CITY OF DECATUR, ALABAMA
CONTRACT NO. 6050
PRIMARY POINT(S) OF RECEIPT
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	MAXIMUM	 	
METER NO.	 	 	DESCRIPTION	 	Dth/day	 	
 	10160	 	 	TGP — BARTON, COLBERT COUNTY, AL	 	 	500	 	
 	10040	 	 	TGP — CORINTH, ALCORN COUNTY, MS	 	 	500	 	
 	10060	 	 	CGT — CORINTH, ALCORN COUNTY, MS	 	 	500	 	
 	10180	 	 	TRl GAS — TETCO, COLBERT COUNTY, AL	 	 	500	 	

 
REVISED EXHIBIT “B-1”
TO FIRM GAS TRANSPORTATION CONTRACT
DATED NOVEMBER 1, 1997
BETWEEN
ENBRIDGE PIPELINE (Alatenn), INC.
AND
THE CITY OF DECATUR, ALABAMA
CONTRACT NO. 6050
PRIMARY POINT(S) OF DELIVERY
 	 	 	 	 	 	 	 	 	
METER NO.	 	 	DESCRIPTION	 	MAXIMUM VOLUME	 	
 	10600	 	 	DECATUR DELIVERY	 	 	500	 	

Exhibit 10.16
NATURAL GAS PIPELINE CONSTRUCTION
AND TRANSPORTATION AGREEMENT
BETWEEN
BAMAGAS COMPANY
CALPINE ENERGY SERVICES, L.P.

 

TABLE OF CONTENTS

ARTICLE I DEFINITIONS	 	 	1	 	
 	 	 	 	 	
ARTICLE II CONSTRUCTION AND OPERATION OF PIPELINE; TRANSPORTATION AND DELIVERIES	 	 	6	 	
 	 	 	 	 	
Section 2.1 Development of Pipeline	 	 	6	 	
Section 2.2 Construction of Pipeline	 	 	6	 	
Section 2.3 Milestone Schedule	 	 	6	 	
Section 2.4 Notice to Proceed	 	 	7	 	
Section 2.5 BAMAGAS Lateral(s)	 	 	7	 	
Section 2.6 Operation of Pipeline	 	 	7	 	
Section 2.7 Transportation and Delivery	 	 	7	 	
Section 2.8 Curtailment	 	 	8	 	
Section 2. 9 Scheduling Gas Flow	 	 	8	 	
Section 2.10 Imbalance Charges	 	 	9	 	
Section 2.11 Gas Delivery Rates	 	 	9	 	
 	 	 	 	 	
ARTICLE III TERM OF AGREEMENT	 	 	9	 	
 	 	 	 	 	
ARTICLE IV QUALITY AND PRESSURE	 	 	9	 	
 	 	 	 	 	
Section 4.1 Quality	 	 	9	 	
Section 4.2 Pressure	 	 	10	 	
 	 	 	 	 	
ARTICLE V MEASUREMENTS AND MEASURING EQUIPMENT	 	 	10	 	
 	 	 	 	 	
Section 5.1 Transportation Units	 	 	10	 	
Section 5.2 Measuring Station	 	 	10	 	
 	 	 	 	 	
ARTICLE VI CHARGES TO BE PAID BY CES	 	 	12	 	
 	 	 	 	 	
Section 6.1 Transportation Charges	 	 	12	 	
Section 6.2 Taxes	 	 	12	 	
Section 6.3 Other Charges	 	 	13	 	
Section 6.4 Price Reduction	 	 	13	 	
 	 	 	 	 	
ARTICLE VII BILLING AND PAYMENTS	 	 	13	 	
 	 	 	 	 	
Section 7.1 Billing Dates	 	 	13	 	
Section 7.2 Payment Date	 	 	13	 	
Section 7.3 Right of Examination	 	 	14	 	
Section 7.4 Adjustment of Errors in Billing	 	 	14	 	
Section 7.5 Interest on Past Due Payments	 	 	14	 	
 	 	 	 	 	
ARTICLE VIII POSSESSION OF NATURAL GAS	 	 	14	 	
 	 	 	 	 	
ARTICLE IX REPRESENTATIONS AND WARRANTIES AND COVENANTS	 	 	14	 	
 	 	 	 	 	
Section 9.1 Warranty of Title	 	 	14	 	
Section 9.2 Warranty Regarding Intrastate Pipeline	 	 	14	 	
Section 9.3 Corporate Representations and Warranties	 	 	14	 	
Section 9.4 BAMAGAS Covenants	 	 	15	 	
 	 	 	 	 	
ARTICLE X INDEMNIFICATION	 	 	16	 	
 	 	 	 	 	
Section 10.1 BAMAGAS Indemnity	 	 	16	 	
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Section 10.2 CES Indemnity	 	 	16	 	
Section 10.3 Scope	 	 	16	 	
Section 10.4 Notice and Opportunity to Defend	 	 	16	 	
 	 	 	 	 	
ARTICLE XI FORCE MAJEURE	 	 	17	 	
 	 	 	 	 	
Section 11.1 Force Majeure Defined	 	 	17	 	
Section 11.2 Effect of Force Majeure	 	 	17	 	
 	 	 	 	 	
ARTICLE XII EVENTS OF DEFAULT	 	 	18	 	
 	 	 	 	 	
Section 12.1 Definition	 	 	18	 	
Section 12.2 Right of Termination for Default	 	 	19	 	
Section 12.3 CES Purchase Rights	 	 	19	 	
Section 12.4 Remedies Not Exclusive	 	 	19	 	
Section 12.5 Limitation of Liability	 	 	20	 	
Section 12.6 Non-Recourse	 	 	20	 	
 	 	 	 	 	
ARTICLE XIII TRANSFER AND ASSIGNMENT	 	 	20	 	
 	 	 	 	 	
Section 13.1 Assignment	 	 	20	 	
Section 13.2 Right of First Refusal	 	 	21	 	
 	 	 	 	 	
ARTICLE XIV REGULATION	 	 	21	 	
 	 	 	 	 	
ARTICLE XV MORGAN ENERGY CENTER	 	 	21	 	
 	 	 	 	 	
ARTICLE XVI DISPUTE RESOLUTION; GOVERNING LAW	 	 	22	 	
 	 	 	 	 	
Section 16.1 Procedure	 	 	22	 	
Section 16.2 Initial Resolution Attempts	 	 	22	 	
Section 16.3 Arbitration	 	 	22	 	
Section 16.4 General Rules and Provisions	 	 	22	 	
Section 16.5 Governing Law	 	 	23	 	
 	 	 	 	 	
ARTICLE XVII NOTICES	 	 	23	 	
 	 	 	 	 	
Section 17.1 Writing	 	 	23	 	
Section 17.2 Timing of Receipt	 	 	24	 	
 	 	 	 	 	
ARTICLE XVIII MISCELLANEOUS	 	 	24	 	
 	 	 	 	 	
Section 18.1 Financial Responsibility	 	 	24	 	
Section 18.2 Captions	 	 	24	 	
Section 18.3 Non Disclosure	 	 	24	 	
Section 18.4 Press Release	 	 	25	 	
Section 18.5 Amendments	 	 	25	 	
Section 18.6 Severability	 	 	25	 	
Section 18.7 Entire Agreement	 	 	25	 	
Section 18.8 No Waiver	 	 	25	 	
Section 18.9 Further Assurances	 	 	25	 	
Section 18.10 Counterparts	 	 	25	 	
Section 18.11 Exhibits, Attachments and Schedules	 	 	25	 	
EXHIBIT 1
MILESTONE SCHEDULE
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EXHIBIT 2
GAS SPECIFICATIONS
EXHIBIT 3
POINTS OF DELIVERY/RECEIPT
EXHIBIT 4
PIPELINE TERMINNATION VALUE
EXHIBIT 5
MIDCOAST GUARANTEE
EXHIBIT 6
CES GUARANTY
EXHIBIT 7
PROPERTY RIGHTS ASSIGNABLE TO BAMAGAS
EXHIBIT 8
OPERATIONAL BALANCING AGREEMENT
EXHIBIT 9
USE RESTRICTIONS
EXHIBIT 10
HYDRAULIC MODEL
EXHIBIT 11
TRANSPORTATION RIGHTS
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NATURAL GAS PIPELINE CONSTRUCTION AND TRANSPORTATION AGREEMENT
(DECATUR ENERGY CENTER)

     This Natural Gas Pipeline Construction and Transportation Agreement for the Decatur Energy Center (this “Agreement”) entered into effective as of the 28th day of June, 2000 (“Effective Date”) by and between BAMAGAS Company, a Delaware corporation (together with its successors and permitted assigns, “BAMAGAS”), and Calpine Energy Services, L.P. (“CES”), a Delaware limited partnership (together with its successors and permitted assigns, “CES”). BAMAGAS, and CES may also be referred to herein individually as “Party” or jointly as “Parties.”

Recitals
     WHEREAS, Decatur Energy Center, LLC (together with its successors and permitted assigns, “DEC”) is constructing a power generation facility in Morgan County, Alabama (“Decatur Energy Center”, as more fully described below) and an affiliate of it, Morgan Energy Center, LLC, a Delaware limited liability company (together with its successors and permitted assigns, “MEC”), is constructing another power generation facility in Morgan County, Alabama (“Morgan Energy Center”); and
     WHEREAS, DEC and CES have agreed that CES will provide fuel management services for natural gas to be used at the Decatur Energy Center; and
     WHEREAS, BAMAGAS is willing to construct, own, operate and maintain a new intrastate pipeline and related facilities (whether existing or new) to be located wholly within the State of Alabama (the “Pipeline”, as more fully described below) to receive and transport on a firm basis natural gas for the Decatur Energy Center, and to make available Equivalent Quantities of natural gas at the Point(s) of Delivery, and CES desires for BAMAGAS to do so; and
     WHEREAS, contemporaneously with the execution of this Agreement by the Parties, BAMAGAS is entering into a Natural Gas Transportation Agreement with CES to also receive and transport on a firm basis natural gas for the Morgan Energy Center (the “Natural Gas Transportation Agreement for the Morgan Energy Center”);
     NOW, THEREFORE, in consideration of the premises and of the mutual agreements herein contained, the Parties hereto agree as follows:
ARTICLE I
DEFINITIONS
     Except where the context expressly states another meaning the following terms when used in this Agreement and in the Exhibits to this Agreement shall be construed to have the following meanings:
     “AAA” shall have the meaning set forth in Section 16.3.
     “Affiliate” shall mean any Person that directly or indirectly Controls or is Controlled by or is under common Control with, the Person in question. “Person” means an individual, partnership, limited partnership, corporation, limited liability company, association, trust, unincorporated organization, or a government authority or agency or political subdivision thereof. “Control” means the possession, directly or indirectly, through one or more intermediaries, of either of the following: (a) (i) in the case of a corporation, 50% or more of the outstanding voting securities thereof; (ii) in the case of a limited liability company, partnership, limited partnership or venture, the right to 50% or more of the distributions therefrom (including liquidating distributions); (iii) in the case of a trust or estate, 50% or more of the beneficial interest therein; or (iv) in the case of any other entity, 50% or more of the economic or beneficial interest therein; or (b) in the case of any entity, the power or authority, through the ownership of voting securities, by contract or otherwise, to direct the management, activities or policies of the entity.

 

     “Affiliated Transportation Parties” shall have the meaning set forth in Exhibit 11.
     “Agreement” shall have the meaning set forth in the opening paragraph.
     “Applicable Law” shall mean any federal, state, local or other constitution, charter, act, statute, law, ordinance, code, rule, regulation or order or other legislative or administrative action of the United States of America or the State of Alabama, or any agency, department, authority, political subdivision or other instrumentality or either of them, or a final decree, judgment or order of a court applicable to the Pipeline, the Lateral(s), the Decatur Energy Center, the Parties or this Agreement.
     “BAMAGAS” shall have the meaning set forth in the opening paragraph hereof.
     “BAMAGAS Activities” shall have the meaning set forth in Section 9.4(a).
     “BAMAGAS Group” shall have the meaning set forth in Section 10.3(b).
     “BAMAGAS Lateral(s)” shall mean the non FERC jurisdictional pipeline(s) to be constructed by BAMAGAS for the purpose of transporting Natural Gas from the pipeline facilities of Midcoast Interstate Transmission, Inc. to the Primary Point(s) of Delivery and the points of delivery specified under the Natural Gas Transportation Agreement for Morgan Energy Center, which pipeline(s) shall be used for the testing of the Decatur Energy Center and for Gas transportation service during time periods that the Pipeline is unavailable to transport the Firm Transportation Quantity as provided for herein.
     “Beneficial Rate(s)” shall have the meaning set forth in Section 6.4.
     “British Thermal Unit” or “Btu” shall mean the amount of heat required to raise the temperature of one (1) pound of water from fifty-nine (59) degrees Fahrenheit to sixty (60) degrees Fahrenheit at a constant pressure of 14.73 psia.
     “Business Day” shall mean any Day that is not a Saturday, Sunday or day on which banks are permitted or required to be closed in Houston, Texas.
     “Calpine” shall mean Calpine Corporation, a Delaware corporation, together with its successors and assigns.
     “Calpine Corporation Guaranty” shall mean the guaranty furnished by Calpine pursuant to Section 18.1.
     “Competing Use” shall have the meaning set forth in Section 6.4.
     “Completion Period” shall mean the number of Days described in the column under the heading “Completion Period” in Exhibit 1.
     “CCT” or “Central Clock Time” shall mean Central Standard Time except when Daylight Savings Time is in effect, when it shall mean one hour in advance of Central Standard Time.
     “CES” shall have the meaning set forth in the opening paragraph hereof.
     “Cure Period” shall have the meaning set forth in Section 2.3.
     “Cure Plan” shall have the meaning set forth in Section 2.3.
     “Day” shall mean a period beginning at 9:00 a.m. CCT on one calendar day and ending at 9:00 a.m. CCT on the next succeeding calendar day. The date of a Day shall be that of its beginning.
     “DEC” shall have the meaning set forth in the opening paragraph hereof.
     “CES’ Lateral Supply Cost” shall have the meaning set forth in Section 4.1.
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     “CES’ Pipeline Supply Cost” shall have the meaning set forth in Section 4.1.
     “Decatur Energy Center” shall mean a power generation facility to be constructed in Morgan County, Alabama by DEC, as designated by CES in writing to BAMAGAS on or before the date specified as “Notice to Proceed” on the Milestone Schedule attached as Exhibit 1 for pipe and equipment ordered for development and construction of the BAMAGAS Lateral for the Decatur Energy Center.
     “Effective Date” shall have the meaning set forth in the opening paragraph.
     “Enbridge” shall mean Enbridge (U.S.) Inc.
     “Equivalent Quantity(ies)” shall mean a thermally equivalent quantity of Natural Gas (i.e., an equal number of MMBtu), as received by BAMAGAS at the Point(s) of Receipt less the quantity of Natural Gas lost and unaccounted for in the transmission of such Natural Gas. For purposes of determining the Equivalent Quantity: Natural Gas lost and unaccounted for after receipt by BAMAGAS shall not exceed 1.5%, in each case of the total quantity (in MMBtu) received by BAMAGAS at the Point(s) of Receipt in any given Month. BAMAGAS shall provide any quantities of Natural Gas lost and unaccounted for in excess of 1.5%, at no cost to CES, to ensure delivery of the Equivalent Quantity to CES at the Point(s) of Delivery.
     “Event of Default” shall mean any of the events or circumstances set forth in Section 12.1.
     “Excusable Events” shall have the meaning set forth in Section 2.8.
     “Extension Period” shall have the meaning set forth in Section 11.2.
     “Exercise Period” shall have the meaning set forth in Section 13.2.
     “Favorable Rate(s)” shall have the meaning set forth in Section 6.4.
     “FERC” shall have the meaning set forth in Section 9.2.
     “Firm” or “Firm Transportation” shall mean that the receipt, delivery and transportation of Natural Gas shall not be subject to interruption or curtailment, other than by reason of express written consent of CES, Force Majeure, Applicable Law or an Excusable Event, or as otherwise provided in this Agreement.
     “Firm Transportation Quantity” shall mean 138,000 MMBtu of Natural Gas per Day.
     “First Delivery Date” shall mean February 1, 2002.
     “Force Majeure” shall have the meaning set forth in Section 11.1.
     “Gas” or “Natural Gas” shall mean the effluent vapor stream in its natural state produced from wells, including all hydrocarbon and nonhydrocarbon constituents, if any, and including casinghead Gas produced with crude oil and residue Gas resulting from the processing of Gas well or casinghead Gas.
     “Governmental Approvals” shall mean all permits, licenses or other authorizations required to be obtained with respect to the construction, ownership and operation of the Pipeline and the BAMAGAS Lateral(s).
     “Governmental Authority” shall mean any federal, state or local governmental entity, authority or agency, court, tribunal, regulatory commission or other body, whether legislative, judicial or executive, having authority over this Agreement or the Parties hereto.
     “Hydraulic Model” shall mean the hydraulic simulation model described in Exhibit 10.
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     “Imbalance(s)” shall mean the difference between scheduled and actual receipt quantities of Natural Gas at Point(s) of Receipt.
     “Indemnitee” shall have the meaning; set forth in Section 10.4.
     “Indemnitor” shall have the meaning set forth in Section 10.4.
     “Initial Term” shall have the meaning set forth in Article III.
     “Initial Term Demand Charge” shall have the meaning set forth in Section 6.1.
     “Initial Term Transportation Rate” shall have the meaning set forth in Section 6.1.
     “MEC” shall have the meaning set forth in the first paragraph of the “Recitals” hereof.
     “Milestone(s)” shall have the meaning set forth in Exhibit 1.
     “Milestone Schedule” shall have the meaning set forth in Section 2.3.
     “MIT Lateral” shall mean the existing lateral pipeline that ties into the Midcoast Interstate Transmission Company 8” and 12” systems that currently deliver Natural Gas directly into Solutia.
     “MMBtu” or “Dekatherm” or “dth” shall mean one million (1,000,000) Btu.
     “Month” shall mean a period beginning at 9:00 a.m. CCT on the first day of the calendar month and ending at 9:00 a.m. CCT on the first day of the next succeeding calendar month.
     “Morgan Energy Center” shall have the meaning set forth in the first paragraph of the “Recitals” hereof.
     “New Taxes” shall have the meaning set forth in Section 6.2.
     “Notice” shall have the meaning set forth in Section 12.2.
     “Notice Period” shall have the meaning set forth in Section 12.2.
     “Offer Notice” shall have the meaning set forth in Section 13.2.
     “Party” or “Parties” shall have the meaning set forth in the opening paragraph hereof.
     “Pipeline” shall mean a contiguous, new pipeline and related facilities (whether existing or new) for the transmission of Natural Gas, including all of the necessary pipe, fittings, valves, measuring equipment and regulators to be constructed or acquired, owned and operated by BAMAGAS beginning at Tennessee Gas Pipeline Company’s 500 leg near Barton in Colbert County, Alabama, and ending at the Primary Point(s) of Delivery as described in Exhibit 3, including the pipeline interconnections between Tennessee Gas Pipeline Company and BAMAGAS, Texas Eastern Transmission Company and BAMAGAS, and Midcoast Interstate Transmission Company and BAMAGAS, respectively.
     “Point(s) of Delivery” shall mean any or all of the Primary Point(s) of Delivery and Secondary Point(s) of Delivery
     “Point(s) of Receipt” shall mean the point(s) of interconnection between the Pipeline and CES’ upstream suppliers or transporters, as identified on Exhibit 3, and such other point(s) of interconnection, if any, which BAMAGAS and CES shall mutually agree upon to be made between the Pipeline and other pipelines or which may be unilaterally added or deleted by CES provided that no additional facilities are required to be added by BAMAGAS to the Pipeline at BAMAGAS expense.
 4 

 

     “Pressure Variance” shall have the meaning set forth in Section 4.2.
     “Pressure Variance Event” shall have the meaning set forth in Section 4.2.
     “Primary Point(s) of Delivery” shall mean the point of interconnection between the Pipeline and/or the BAMAGAS Lateral(s) and the facilities, for delivery of Natural Gas to the Decatur Energy Center as identified on Exhibit 3.
     “Procurement Deadline” shall have the meaning set forth in Article XV.
     “Purchase Price” shall have the meaning set forth in Section 12.3.
     “Renewal Term” shall have the meaning set forth in Article III.
     “Renewal Term Demand Charge” shall have the meaning set forth in Section 6.1.
     “Renewal Term Transportation Rate” shall have the meaning set forth in Section 6.1.
     “ROW” shall mean all rights-of-way, land use rights, sites and easements acquired and/or utilized by BAMAGAS for the purpose of the Pipeline and the BAMAGAS Lateral(s) and their interconnections with Decatur Energy Center.
     “Secondary Point(s) of Delivery” shall mean the point(s) of interconnection between the Pipeline and the pipelines of CES’ upstream suppliers or transporters, as identified on Exhibit 3, and such other point(s) of interconnection, if any, which BAMAGAS and CES shall mutually agree upon to be made between the Pipeline and other interstate pipelines or which may be unilaterally added by CES for redelivery of Natural Gas to interstate pipelines provided that no additional facilities are required to be added by BAMAGAS to the Pipeline at BAMAGAS’ expense.
     “Second Owner” shall have the meaning set forth in Section 13.1.
     “Shipper Group” shall have the meaning set forth in Section 10.3.b.
     “Supply Notice” shall have the meaning set forth in Section 2.8.
     “Term” shall mean the Initial Term and any Renewal Term(s).
     “Termination Value” shall have the meaning set forth in Section 12.3.
     “Testing Period” shall mean the period during which the Decatur Energy Center facility is utilizing Natural Gas for the purpose of testing.
     “Third Party Transportation Contract” shall have the meaning set forth in Section 6.4.
     “Third Party Offer” shall have the meaning set forth in Section 13.2.
     “Third Party Sales Contract” shall have the meaning set forth in Section 6.4.
     “Transportation Capacity” shall mean the design capacity of the Pipeline as determined in accordance with the Hydraulic Model.
     “Transportation Rights” shall have the meaning set forth in Section 12.3.
     “Unexcused Curtailment” shall have the meaning set forth in Section 12.1.c.
     “Use Restrictions” shall have the meaning set forth in Section 12.3.
 5 

 

ARTICLE II
CONSTRUCTION AND OPERATION OF
PIPELINE; TRANSPORTATION AND DELIVERIES
     2.1 Development of Pipeline. BAMAGAS hereby agrees that it will seek to: obtain all necessary Governmental Approvals, acquire all ROW, procure all materials, and engineer, design and construct the Pipeline and BAMAGAS Lateral(s) (or cause the same to be done) with all diligence required such that the Pipeline and the BAMAGAS Lateral(s) will be commercially operable in accordance with Applicable Law by the First Delivery Date to receive, transmit and deliver each Day a quantity of Natural Gas equal to the Firm Transportation Quantity. To the extent reasonably obtainable, all ROW acquired by BAMAGAS for the Pipeline shall be of perpetual duration unless otherwise agreed by CES. CES shall within thirty (30) Days following the execution of this Agreement assign to BAMAGAS the property rights, if any, identified on Exhibit 7 that CES or its Affiliates have acquired for the purpose of construction of a pipeline to serve the Decatur Energy Center. To the extent reasonably obtainable, all contracts and agreements entered into by BAMAGAS for the ROW shall be reasonably assignable to a successor owner of the Pipeline unless otherwise agreed by CES.
     2.2 Construction of Pipeline. CES or its designee shall have the right to monitor the progress of construction of the Pipeline and the BAMAGAS Lateral(s). BAMAGAS shall provide reasonable access to information related to the design, engineering and construction of the Pipeline and the BAMAGAS Lateral(s) and to its construction sites for the purpose of such monitoring and shall make appropriate personnel available for a monthly meeting or as frequently as reasonably requested by CES or its designee, to discuss the progress of the Pipeline and the BAMAGAS Lateral(s), with CES or its designee. BAMAGAS shall provide to CES or its designee a written report on the last day of each month on the progress of its activities in obtaining Governmental Approvals, acquiring ROW and constructing the Pipeline and the BAMAGAS Lateral(s). Such report shall describe the status of Governmental Approvals, ROW acquisition, engineering and material(s) procurement, construction, any pending or threatened litigation or other circumstances affecting the progress of the Pipeline and the BAMAGAS Lateral(s) and such other matters as reasonably requested by CES. Such report shall also contain an estimate of the date the Pipeline and the BAMAGAS Lateral(s) will be ready for service as provided hereunder.
     2.3 Milestone Schedule. The Parties have agreed upon a schedule (the “Milestone Schedule”), appended hereto as Exhibit 1, for the performance by BAMAGAS of the activities required to complete the Pipeline and the BAMAGAS Lateral(s). Any changes to the Milestone Schedule must be agreed to in writing by the Parties. BAMAGAS shall notify CES in writing when a Milestone has been completed. In the event that BAMAGAS fails to meet any Milestone upon the expiration date of the Completion Period provided for in the Milestone Schedule after the applicable notice to proceed in writing has been received by BAMAGAS from CES or within any extension period agreed to in writing by CES, BAMAGAS shall, within ten (10) Days following such failure, provide to CES a plan (the “Cure Plan”) stating the actions it will endeavor to undertake to meet such Milestone within a period not to exceed thirty (30) Days after submission of the Cure Plan (“Cure Period”). In the event that BAMAGAS fails to provide a Cure Plan as required, or fails to diligently pursue a Cure Plan, or fails to meet the Milestone within the Cure Period, CES shall have the right (but not the obligation), upon ten (10) Days advance written notice given to BAMAGAS, to take over the construction of the Pipeline and the BAMAGAS Lateral(s) and to cause to be taken such actions to carry out BAMAGAS obligations to complete the Pipeline and/or BAMAGAS Lateral(s), at CES sole risk and expense. Upon the earlier of (a) such time as BAMAGAS can demonstrate to CES that it can fulfill its obligations hereunder and complete the construction of the Pipeline and BAMAGAS Lateral(s), as applicable, or (b) the completion of construction of the Pipeline and the BAMAGAS Lateral(s) by CES pursuant to its step in rights, and provided that BAMAGAS reimburses CES for one hundred ten percent (110%) of the reasonable expenses incurred by it in the execution of its step in rights (or if such expenses or a portion thereof are disputed, shall pay the undisputed portion and deposit the disputed portion in escrow with a mutually agreeable escrow agent pending arbitration of such disputed expenses pursuant to Article XVI hereof), BAMAGAS shall have the right to complete construction and take over the Pipeline and the BAMAGAS Lateral(s). CES shall assign to BAMAGAS all contracts, materials and property rights it acquired in the execution of its step in rights and shall provide a complete and detailed accounting of its expenses. The provisions of this Section 2.3 shall in no way limit CES’ rights under Article XII hereof. Notwithstanding the foregoing, if BAMAGAS determines that the expenses incurred by CES in the exercise of its step in rights are more than BAMAGAS is willing to
 6 

 

reimburse CES for (whether determined by BAMAGAS before or after the arbitration as to any disputed expenses), then CES shall (i) pay BAMAGAS 110% of all its reasonable expenses incurred in the construction of the Pipeline and BAMAGAS Lateral(s) and (ii) reimburse BAMAGAS for any and all sums paid by BAMAGAS to CES for expenses incurred by CES in the exercise of its step in rights, and BAMAGAS shall assign to CES all contracts, materials and property rights it acquired in connection with its construction of the Pipeline and the BAMAGAS Lateral(s).
     2.4 Notice to Proceed. BAMAGAS shall not commence any activity that will incur costs to the Pipeline and/or the BAMAGAS Lateral(s) until notice to proceed for each specific Milestone has been given by CES as described in Exhibit 1. In the event that the notice to proceed with the procurement of specific materials and/or the notice to proceed with construction for both the Pipeline and the BAMAGAS Lateral(s) have not been issued on or before November 1, 2002, BAMAGAS shall have the right to terminate this Agreement upon written notice to CES given at any time within thirty (30) Days thereafter. Upon termination, neither Party shall have any obligation to the other Party, except that (i) subject to the payment to be made by CES to BAMAGAS pursuant to subsection (ii) hereinafter, BAMAGAS shall assign or otherwise convey to CES or its designee all Governmental Approvals obtained specifically for and limited to the Pipeline and the BAMAGAS Lateral(s) (to the extent transferable) and all ROW obtained by it specifically for and limited to the Pipeline and the BAMAGAS Lateral(s), and (ii) CES shall pay to BAMAGAS one hundred ten percent (110%) of all reasonable costs incurred by BAMAGAS (including all third party out-of-pocket costs) regarding activities on which BAMAGAS received notice to proceed in accordance with the Milestone Schedule.
     2.5 BAMAGAS Lateral(s). BAMAGAS shall construct the BAMAGAS Lateral that will serve the Decatur Energy Center so that such BAMAGAS Lateral shall be completed and operational pursuant to the Milestone Schedule. CES shall notify BAMAGAS in writing of the expected date for the first Day of each such Testing Period at least one hundred eighty (180) Days in advance of such date and shall promptly notify BAMAGAS in writing in the event of any delay in such date.
     2.6 Operation of Pipeline. During the Term hereof, BAMAGAS shall operate and maintain the Pipeline and the BAMAGAS Lateral(s) in a prudent manner and in accordance with all applicable Governmental Approvals. Except in cases when prior scheduling is not reasonable, any maintenance (including but not limited to repair and replacement) of the Pipeline and/or the BAMAGAS Lateral(s) that causes or is likely to cause curtailment of transportation on the Pipeline and/or the BAMAGAS Lateral(s) shall be conducted by BAMAGAS only after prior scheduling with CES.
     2.7 Transportation and Delivery. From the First Delivery Date until the end of the Term, BAMAGAS agrees: (a) on a Firm basis, to accept and receive collectively at the Point(s) of Receipt such quantities of Natural Gas as CES or its agent delivers or makes available for delivery into the Pipeline or the BAMAGAS Lateral(s) each Day up to an amount that will enable BAMAGAS to deliver the Equivalent Quantity of the Firm Transportation Quantity during each Day at the specified Point of Delivery and (b) on an interruptible basis, and subject to interruption, curtailment and available pipeline capacity, to accept and receive collectively at the Point(s) of Receipt such quantities of Natural Gas in excess of the Firm Transportation Quantity which CES or its agent delivers or makes available for delivery into the Pipeline or the BAMAGAS Lateral(s) each Day. BAMAGAS shall have the right to transport and deliver Equivalent Quantities of the Gas to the Point(s) of Delivery via the Pipeline, the BAMAGAS Lateral(s), the MIT Lateral or any other available pipeline, and if transported and delivered by any such means or any combination thereof, BAMAGAS shall be deemed to be in compliance with this Agreement. The Point of Delivery shall be a Primary Point of Delivery unless a Secondary Point of Delivery is specified by CES to BAMAGAS upon not less than one (1) hour prior notice to BAMAGAS. By written notice to BAMAGAS, CES shall have the right to add or delete Point(s) of Receipt and Secondary Point(s) of Delivery from time to time at no incremental cost to CES, subject to the availability of Firm Capacity and provided that the addition of a Point of Receipt (which may be located on an intrastate or interstate pipeline) or Secondary Point of Delivery (which shall be limited to interstate pipelines) does not require BAMAGAS to add any facilities to the Pipeline or the BAMAGAS Lateral(s) at BAMAGAS’ expense. Each such notice shall be deemed to amend Exhibit 3 of this Agreement. CES shall have the right to resell any or all of the quantities of Gas received by it at Point(s) of Delivery; provided, however (a) CES shall endeavor to purchase only those quantities of Gas necessary for internal uses at the Decatur Energy Center and (b) CES
 7 

 

covenants not to resell and shall cause DEC not to resell any Gas transported on the Pipeline other than at the Secondary Point(s) of Delivery.
     2.8 Curtailment. All quantities of Natural Gas delivered by or for the account of CES to BAMAGAS at the Point(s) of Receipt each Day, up to the Firm Transportation Quantity, shall be transported and delivered each Day, by BAMAGAS to the Points of Delivery without curtailment or interruption, except for curtailments or interruptions by reason of the express consent of CES, Force Majeure, Applicable Law, or any of the following events: (i) failure on any Day by CES to deliver or cause to be delivered at the Point(s) of Receipt sufficient Gas quantities to enable BAMAGAS to redeliver Equivalent Quantities at the Point(s) of Delivery; (ii) failure by CES to transport and redeliver the Equivalent Quantities at a pressure sufficient for BAMAGAS to deliver the Gas quantities at the Point(s) of Delivery at a pressure of no less than 500 psig; (iii) failure by CES to deliver Gas quantities at the Point(s) of Receipt that meet the quality specifications set forth in Exhibit 2; and (iv) failure by CES to deliver Gas quantities at the Point(s) of Receipt at a rate of flow that will enable BAMAGAS to comply with the requirements of the Hydraulic Model for delivery of Gas at the Point(s) of Delivery. (The events described in the preceding sentence under (i), (ii), (iii) and (iv) shall be collectively referred to in this Agreement as “Excusable Events”). In the event a Force Majeure event or any other event other than an Excusable Event(s) causes BAMAGAS to curtail or interrupt transportation service on the Pipeline, BAMAGAS shall deliver, as directed by CES the Equivalent Quantity delivered by or for the account of CES into the Pipeline, up to the Firm Transportation Quantity, to the Point(s) of Delivery prior to making deliveries pursuant to BAMAGAS obligations under any other firm or interruptible transportation contracts with third parties and/or BAMAGAS and/or its affiliated companies transporting Natural Gas on the Pipeline. BAMAGAS warrants that it shall include in any transportation agreement it may enter into with its Affiliates and/or third parties a covenant that states that the transportation rights on the Pipeline and/or the BAMAGAS Lateral(s) shall be subject to interruption or curtailment prior to interruption or curtailment of all quantities up to the Firm Transportation Quantity for CES regardless of the level of service retained by such parties. BAMAGAS shall not enter into transportation contracts for itself or its Affiliates’ account and/or with any third parties that have as a matter of law or regulation, a right to a higher priority of service than CES other than with respect to quantities of Natural Gas that can be transported on the Pipeline in excess of the Firm Transportation Quantity, and shall not enter into transportation contracts for itself or its Affiliates’ account and/or with any third parties for an equivalent priority of service if the quantities of Gas under those contracts, in addition to the Firm Transportation Quantity hereunder, will exceed the Transportation Capacity of the Pipeline in accordance with the Hydraulic Model. In the event that BAMAGAS curtails or interrupts transportation service on the Pipeline due to reasons other than express written consent of CES, Force Majeure, Applicable Law or an Excusable Event, CES shall have the right to transport Gas on the BAMAGAS Lateral(s) at no cost to CES, provided that CES has made and continues to make all payments to BAMAGAS required under Article VI of this Agreement. If the cost to CES for the delivery of Gas supplies from its upstream transporters or suppliers to the BAMAGAS Lateral point(s) of receipt is greater than the cost CES would have incurred for the delivery of such Gas to the Pipeline Point(s) of Receipt, BAMAGAS shall pay CES such excess cost, if such curtailment or interruption is due to cause(s) other than express written consent of CES, Force Majeure, Applicable Law or an Excusable Event; provided however BAMAGAS or its designee shall have the right (but not the obligation) to provide alternate Gas supplies to CES (at CES’ cost) no later than thirty (30) minutes after notice by telephone from CES in connection with an event of curtailment (“Supply Notice”) at a cost equal to that which CES would otherwise pay to its upstream transporters or suppliers for delivery to the BAMAGAS Lateral(s) during all such periods. If, after receipt of the Supply Notice, BAMAGAS or its designee fails or declines to supply the Gas quantities curtailed or interrupted, CES has the right to enter into alternate supply agreements with third parties provided such agreements do not exceed a term of twenty-four (24) hours. BAMAGAS or its designee shall have a continuing right to provide Gas supplies to CES for the price hereinbefore specified during any period of continuation of such curtailment or interruption beyond such twenty-four (24) hour period and, to that end, BAMAGAS and CES shall fully cooperate with each other.
     2.9 Scheduling Gas Flow. At least two (2) Days prior to the beginning of each Month, CES shall furnish BAMAGAS with a schedule showing the estimated quantities of Natural Gas each Day during such Month it desires BAMAGAS to receive, transport and deliver during such Month to each Point of Delivery with the quantities specified for each of the Points of Receipt and each of the Points of Delivery. CES shall use reasonable efforts to inform BAMAGAS promptly and confirm in writing all changes in the quantity of
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Natural Gas, which it desires BAMAGAS to transport hereunder from the quantity of Natural Gas then being transported by BAMAGAS hereunder. All such schedules are provided by CES to BAMAGAS for planning purposes, and CES shall have the right to alter without prior notice the quantities to be furnished at a Point of Receipt or a Point of Delivery at any time, up to the Firm Transportation Quantity. Notwithstanding the immediately preceding sentence, CES shall use reasonable efforts to notify BAMAGAS by telephone or other timely means of any known or anticipated swings in previously scheduled quantities of Gas.
     2.10 Imbalance Charges. CES shall have the right but not the obligation to enter into balancing service agreements with upstream pipelines and suppliers as are necessary to provide for balancing of the quantities of Natural Gas received at the Point(s) of Receipt. All Imbalance charges and any other payments due in accordance with such agreements or otherwise for CES’ Gas shall be the responsibility of and shall be paid by CES unless an Imbalance is caused by BAMAGAS, in which case BAMAGAS shall be liable for any such Imbalance charges. BAMAGAS and CES shall endeavor to keep Imbalances to a minimum and shall make adjustments in receipts and deliveries as promptly as is consistent with their operating conditions in order to balance any excess or deficiency so shown. The provisions of this Section 2.10 shall survive the termination of this Agreement until such time as complete balancing can be attained. BAMAGAS and CES shall enter into an operational balancing agreement in a form substantially similar to Exhibit 8, which will govern the rights and obligations of each Party regarding Imbalances.
     2.11 Gas Delivery Rates. CES shall have the right to deliver or cause to be delivered to BAMAGAS for transportation hereunder any quantities of Gas from zero to the Firm Transportation Quantity and shall not be required to cause such deliveries to be maintained at a uniform or daily rate of flow. Nothing in this Agreement shall prevent BAMAGAS from taking such action as it deems necessary to adjust such hourly and daily rates of flow to meet operating constraints or capacity limitations as determined in accordance with the Hydraulic Model referenced in Exhibit 10 and to protect the operational integrity of the Pipeline. BAMAGAS shall maintain the linepack (i.e., the total amount of Gas contained in the Pipeline) on the Pipeline at all times during the Term of this Agreement at the quantities required by the Hydraulic Model except by reason of express written consent of CES, Force Majeure, Applicable Law, or an Excusable Event.
ARTICLE III
TERM OF AGREEMENT
     The Term of this Agreement shall commence on the Effective Date and, unless earlier terminated in accordance herewith, shall remain in full force and effect until the expiration of twenty (20) years from the First Delivery Date (the “Initial Term’’) and shall thereafter continue in full force and effect for consecutive periods of one (1) year each (each, a “Renewal Term”) unless CES gives written notice of termination of this Agreement to BAMAGAS at least ninety (90) Days prior to the end of the Initial Term or the then current Renewal Term. Provided, however, BAMAGAS shall have the right, exercisable within thirty (30) Days of the beginning of each Renewal Term, to terminate this Agreement as of the expiration of the Initial Term or the then Renewal Term, as applicable, by written notice delivered to CES, in which case CES or its designee shall have the right to purchase the Pipeline and/or the BAMAGAS Lateral(s) in accordance with the terms of Section 12.3.
ARTICLE IV
QUALITY AND PRESSURE
     4.1 Quality. CES shall endeavor to ensure that all Natural Gas delivered by it or for its account to BAMAGAS hereunder shall meet the quality specifications set forth in Exhibit 2 to this Agreement. The Parties agree that Exhibit 2 sets forth the quality specifications required by transporters immediately upstream from the Pipeline and that Exhibit 2 will be amended from time to time as necessary to reflect any changes to those requirements. All Natural Gas delivered by BAMAGAS at the Points of Delivery shall be at least of the same quality as that received by BAMAGAS for CES’ account at the Point(s) of Receipt. BAMAGAS shall perform chromatograph analyses of all Natural Gas delivered hereunder and shall furnish such analyses to CES on a “real-time” basis (i.e., through a direct communication link to the Decatur Energy Center). In the event that either Party receives nonconforming Gas from or on behalf of the other Party, it shall promptly notify the other Party of such nonconformance and shall not be required
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to accept such nonconforming Gas. In the event that BAMAGAS delivers nonconforming Gas to CES that is rejected by CES and such nonconformance was not caused by CES’ upstream suppliers, CES shall have the right, until such time as BAMAGAS causes the Gas in the Pipeline to meet the quality specifications set forth in Exhibit 2, to transport Gas on the BAMAGAS Lateral(s) at no cost to CES for all quantities per Day up to the Firm Transportation Quantity (provided that CES shall continue to pay to BAMAGAS the Initial Term Demand Charge or the Renewal Term Demand Charge, as applicable), but shall pay for all quantities per Day in excess of the Firm Transportation Quantity at the rates specified in Section 6.1 hereof. If the third party cost to CES for the delivery of Gas from its upstream transporters or suppliers to the BAMAGAS Lateral point(s) of receipt (“CES’ Lateral Supply Cost”) is greater than the third party cost CES would have incurred for the delivery of such Gas to the Pipeline Point(s) of Receipt (“CES Pipeline Supply Cost”), BAMAGAS shall reimburse CES for the positive difference between CES’ Lateral Supply Cost and CES’ Pipeline Supply Cost; provided, however, if BAMAGAS notifies CES that it is able to provide or cause to be provided (and does so provide or cause to provide if timely authorized by CES) Gas to CES (at CES’ expense) at the BAMAGAS Lateral points or receipt at a cost which is less than that incurred or to be incurred by CES from its upstream Gas suppliers, then BAMAGAS shall reimburse CES only for the positive difference, if any, between CES’ Lateral Supply Cost and CES’ Pipeline Supply Cost. CES shall reimburse BAMAGAS for all its costs incurred in connection with the purging of nonconforming Gas delivered by or for the account of CES into the Pipeline or the BAMAGAS Lateral(s) or in otherwise causing such nonconforming Gas to meet the quality specifications set forth in Exhibit 2 provided such non conformance was caused by CES or its upstream Gas suppliers. The Parties agree that BAMAGAS has no obligation to odorize CES’ Natural Gas received by BAMAGAS at the Point(s) of Receipt, unless BAMAGAS is required to do so pursuant to Applicable Law.
     4.2 Pressure. BAMAGAS shall deliver Natural Gas to CES at prevailing line pressure as it may vary from time to time. CES will endeavor to have the Gas delivered by the upstream transporters at the Point(s) of Receipt at a pressure equal to or greater than 675 psig. If the Gas is delivered by the upstream transporters at the Point(s) of Receipt at a pressure equal to or greater than 675 psig, then the variance between the pressure at the Point(s) of Receipt and the Point(s) of Delivery (the “Pressure Variance”) shall be such that the pressure at the Point(s) of Delivery is not less than 500 psig. If the Gas is delivered by the upstream transporters at the Point(s) of Receipt at a pressure of less than 675 psig, then the Pressure Variance shall not exceed that provided for in accordance with the Hydraulic Model. Other than by reason of the express written consent of CES, Force Majeure, Applicable Law, or an Excusable Event, if the Pressure Variance exceeds that allowed under the following provisions of this Section 4.2 on more than three (3) occasions for a duration of one (1) hour or more after notice thereof has been received by BAMAGAS (“Pressure Variance Event”), BAMAGAS shall be required to remedy the problem by adding compression and/or performing other pipeline improvements. If BAMAGAS is successful in remedying the problem as determined by both Parties in accordance with the requirements of the Hydraulic Model, then no Pressure Variance Event shall be deemed to have occurred.
ARTICLE V
MEASUREMENTS AND MEASURING EQUIPMENT
     5.1 Transportation Units. The transportation unit of the Natural Gas received and delivered by BAMAGAS hereunder shall be one (1) MMBtu.
     5.2 Measuring Station. BAMAGAS or the appropriate upstream transporter will install, own and operate, at the Point(s) of Receipt and the Point(s) of Delivery, a measuring station properly equipped with meters and other necessary measuring equipment by which the quantity of Natural Gas delivered under this Agreement shall be measured. Orifice meters or other AGA approved measurement devices, which include turbine or ultrasonic meters, shall be installed, operated and equipped with electronic flow measurement equipment in accordance with the latest applicable Measurement Committee Report of the American Gas Association. Nothing hereinabove shall preclude BAMAGAS or CES or its designee, at such Party’s sole cost, risk and expense, from installing, owning, operating and maintaining measuring equipment at or near the Point(s) of Receipt or Point(s) of Delivery to measure Natural Gas delivered under this Agreement. Each BAMAGAS and CES agree to grant each other a right to enter onto such Party’s property for the purpose of installing, reading and maintaining measuring equipment as provided for herein.
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 	a.	 	Check Measuring Equipment: CES or its designee may install, own, maintain and operate, at its sole cost, risk and expense, such check measuring equipment as desired, provided that such equipment shall be so installed as not to interfere with the operation of BAMAGAS measuring equipment at or near a Point of Receipt or Point of Delivery.	
 		
 	b.	 	Right To Be Present: BAMAGAS and CES shall have the right to have representatives present at the time of any installing, reading, cleaning, changing, repairing, inspecting, testing, calibrating, or adjusting done in connection with the other’s measuring equipment used in measuring or checking the measurement of deliveries of Natural Gas under this Agreement. The records from such measuring equipment shall remain the property of their owner, but upon request each will submit to the other its records and charts, together with calculations therefrom, for the inspection and verification, subject to return within thirty (30) Days after receipt thereof.	
 		
 	c.	 	Care Required: All installations of measuring equipment applying to or affecting deliveries of Natural Gas shall be made in accordance with standard industry practices and such manner as to permit accurate determination of the quantity of Natural Gas delivered and ready verification of the accuracy of measurement. Care shall be exercised by both Parties in the installation, maintenance and operation of pressure regulating equipment so as to prevent any inaccuracy in the determination of the quantity of Natural Gas delivered under this Agreement.	
 		
 	d.	 	Calibration and Test of Meters: The accuracy of BAMAGAS measuring equipment shall be verified by BAMAGAS at reasonable intervals, and, if requested, in the presence of representatives of CES, but BAMAGAS shall not be required to verify the accuracy of such equipment more frequently than once in any thirty (30) day period. In the event either Party shall notify the other that it desires a special test of any measuring equipment, the Parties shall cooperate to secure a prompt verification of the accuracy of such equipment. The expense of any such special test, if called for by CES, shall be borne by CES if the measuring equipment tested is found not to be in error or to be in error not more than two percent (2%).	

 	(i)	 	If, upon test, any measuring equipment, including recording calorimeters, is found to be in error by not more than two percent (2%), previous recordings of such equipment shall be considered accurate in computing deliveries of Natural Gas, but such equipment shall be adjusted at once to record accurately.	
 		
 	(ii)	 	If, upon test, any measuring equipment shall be found to be inaccurate by an amount exceeding two percent. (2%) at a recording corresponding to the average hourly rate of flow for the period since the last preceding test, then any previous recordings of such equipment shall be corrected to zero error for any period which is known definitely but in case the period is not known or agreed upon, such correction shall be for a period extending over one-half (1/2) of the time elapsed since the date of the last test, not exceeding a correction period of sixteen (16) Days.	

 	e.	 	Correction of Metering Errors — Failure of Meters: In the event a meter is out of service, or registering; inaccurately, the quantity of Natural Gas delivered hereunder shall be adjusted for purposes of calculating CES’ monthly bill according to the following procedures:	

 	(i)	 	by using the registration of any check meter or meters, if installed and accurately registering; or	
 		
 	(ii)	 	in the absence of (i), by correcting the error if the percentage is ascertainable by calibration; tests or mathematical calculation; or	
 		
 	(iii)	 	in the absence of both (i) and (ii), by estimating the quantity of delivery by utilizing a mathematical computation of subtracting accurately recording delivery meters from the receipt meters for the appropriate time period; or	
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 	(iv)	 	in the absence of (i), (ii) and (iii), by estimating the quantity of delivery by deliveries during periods under similar conditions when the meter was registering accurately.	

 	f.	 	Preservation of Metering Records: BAMAGAS and CES shall each preserve for a period of at least one (1) year all test data, charts and other similar records.	
ARTICLE VI
CHARGES TO BE PAID BY CES
     6.1 Transportation Charges. In consideration of BAMAGAS agreement to make the capacity of the Pipeline up to the Firm Transportation Quantity available to CES for transportation of CES’ Gas on a Firm basis during the Initial Term, CES shall pay to BAMAGAS on a monthly basis during the Initial Term, commencing as of the First Delivery Date (whether or not CES commences the shipping of Gas on such date or any later date and whether or not on any Day CES causes any Gas, up to the Firm Transportation Quantity, to be scheduled for delivery or be delivered) a fixed demand charge (the “Initial Term Demand Charge”) equal to the product of (a) seven cents ($0.07) per MMBtu of Gas (the “Initial Term Transportation Rate”) times (b) 100,000 MMBtu of Gas and times (c) the number of Days in such Month. BAMAGAS shall not charge the Initial Term Transportation Rate for the actual quantities of CES’ Gas collectively received each Day at the Points of Receipt during the Initial Term as long as those quantities are not in excess of the Firm Transportation Quantity. In the event that BAMAGAS transports Gas for CES in excess of the Firm Transportation Quantity to the Points of Receipt on any Day during the Initial Term, CES shall pay BAMAGAS for all MMBtu of Gas delivered in excess of the Firm Transportation Quantity per Day an amount equal to (a) the Initial Term Transportation Rate times (b) all MMBtu of Gas in excess of the Firm Transportation Quantity per Day.
     In consideration of BAMAGAS’ agreement to make the capacity of the Pipeline up to the Firm Transportation Quantity available to CES for the transportation of CES’ Gas on a Firm basis during each Renewal Term, CES shall pay to BAMAGAS on a Monthly basis during each Renewal Term commencing as of the first Day of such Renewal Term (and whether or not on any Day CES causes any Gas up to the Firm Transportation Quantity to be scheduled for delivery or be delivered), a fixed demand charge (the “Renewal Term Demand Charge”) equal to the product: of (a) four cents ($0.04) per MMBtu of Gas (the “Renewal Term Transportation Rate”) times (b) 100,000 MMBtu, and times (c) the number of Days in such Month. BAMAGAS shall not charge the Renewal Term Transportation Rate for the actual quantities of Gas collectively received each Day at the Point(s) of Receipt during any Renewal Term as long as those quantities are not in excess of the Firm Transportation Quantity. In the event that BAMAGAS transports for CES Gas in excess of the Firm Transportation Quantity to the Points of Receipt on any Day during a Renewal Term, CES shall pay BAMAGAS for all MMBtu of Gas delivered in excess of the Firm Transportation Quantity per Day an amount equal to (a) the Renewal Term Transportation Rate times (b) all MMBtu of Gas in excess of the Firm Transportation Quantity per Day.
     In the event CES delivers or causes to be delivered or tendered Gas quantities from the Point(s) of Receipt to the Point(s) of Delivery in excess of the Firm Transportation Quantity on any given Day to be transported hereunder during the Initial Term or any Renewal Term, such daily quantities in excess of the Firm Transportation Quantity may be interrupted or curtailed by BAMAGAS and BAMAGAS shall not be in breach of this Agreement. No event of Force Majeure, Applicable Law or an Excusable Event shall relieve CES of the obligation to pay the full amount of the Initial Term Demand Charge and the Renewal Term Demand Charge, as applicable, each Month during the Term of this Agreement, except as otherwise expressly provided in Section 11.2. CES shall have no right to make up the difference, if any, between the actual quantities of Gas transported on any given Day during the Initial Term or any Renewal Term and the Firm Transportation Quantity, nor shall CES be entitled to any credit or allowance for any such differences. The Parties shall settle Imbalances in accordance with the provisions of the operational balancing agreement attached as Exhibit 8.
     6.2 Taxes. In addition to any other payments due hereunder, CES shall be liable to reimburse BAMAGAS for all taxes, including but not limited to sales (wholesale or retail), transaction, occupation, privilege, license, franchise, service, production, severance, gathering, transmission, gross receipts, export or excise, or other exaction, (but not including income, excess profits, capital stock, state franchise or
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general property taxes) hereafter levied, assessed or fixed by any Governmental Authority (and whether any such tax is currently collected), measured by, in respect of or applicable to the Natural Gas to be received, transported or delivered by BAMAGAS under this Agreement and to the extent actually paid by BAMAGAS. All such taxes shall be separately stated and identified on invoices issued by BAMAGAS hereunder. In the event any taxes, assessments, impositions, or other charges are imposed by any Governmental Authority on the receipt, transportation or delivery of Natural Gas hereunder that are not in effect as of the date hereof (“New Taxes”), such New Taxes shall be allocated prorata between CES and BAMAGAS based upon the respective use (including reserved capacity for firm transportation) of the capacity of the Pipeline by CES and all other parties during each tax period applicable to such New Taxes.
     6.3 Other Charges. CES shall promptly reimburse BAMAGAS for any surcharges and all other costs charged to or levied upon BAMAGAS by Natural Gas producers, suppliers, transporters or regulatory agencies related to the receipt, transportation or delivery of Natural Gas under this Agreement, provided that such charges are not caused by actions or omissions of BAMAGAS in material breach of an obligation to CES under this Agreement.
     6.4 Price Reduction. In the event that at any time during the Term hereof, BAMAGAS contracts with any other shipper (“Third Party Transportation Contract”), for any level of transportation service of Gas on the Pipeline at a rate more favorable than the rate then being charged CES hereunder for any level of transportation service (“Favorable Rate”), and the transported Gas is used by the shipper or any Affiliate of it for a Competing Use, BAMAGAS shall credit to the transportation charges under this Agreement, during the term of the Third Party Transportation Contract, a sum equal to the positive difference, if any, between the Favorable Rate and CES’ rate for that quantity of CES’ Gas, up to (but not exceeding) the daily quantity transported on the Pipeline at the Favorable Rate; provided, however, that CES shall pay the Initial Term Demand Charge, the Renewal Term Demand Charge, the Initial Term Transportation Rate and the Renewal Term Transportation Rate subject to offset by the credits provided for hereunder. The foregoing credits shall not be applicable if there is a price readjustment pursuant to the provisions of Article XV.
     Similarly, if BAMAGAS, Enbridge or any Affiliate of either of them enters into any Natural Gas sales agreements for delivery of Gas off of the Pipeline with any third party, (“Third Party Sales Contract”) used by such third party or any Affiliate of it for a Competing Use, and the net effect of the sale is that the transportation service of Gas on the Pipeline is at a rate more favorable than the rate charged CES hereunder for the same level of transportation service (“Beneficial Rate”), and if the transported Gas is used by the third party purchaser or any Affiliate of it for a Competing Use, BAMAGAS shall credit to the transportation charges under this Agreement during the term of the Third Party Sales Contract a sum equal to the difference between the Beneficial Rate and CES’ rate for that quantity of CES’ Gas, up to (but not exceeding) the daily quantity sold off of the Pipeline to the third party purchaser at the Beneficial Rate; provided, however that CES shall pay the Initial Term Demand Charge, the Renewal Term Demand Charge, the Initial Term Transportation Rate or the Renewal Term Transportation Rate subject to offset by the credits provided for hereunder. For the purposes hereof, “Competing Use” shall mean Natural Gas that is utilized for the purpose of the generation of electricity and/or steam delivered by the Pipeline and/or BAMAGAS Lateral(s). CES shall have the right at all reasonable times to examine records and relevant data to the extent necessary to verify the accuracy of any supporting information regarding Favorable and Beneficial Rates.
ARTICLE VII
BILLING AND PAYMENTS
     7.1 Billing Dates. On or about the fifth (5th) Business Day of each Month, BAMAGAS shall issue (by facsimile or other means) to CES an invoice setting forth the quantity of Gas received and delivered for CES’ account during the preceding Month, any lost or unaccounted for Gas based on the calculations of electronic flow measurement equipment and all applicable fees and charges due in accordance with Article VI hereof.
     7.2 Payment Date. Payment by CES shall be made to BAMAGAS, at its address designated herein, in immediately available funds, on or before the Day that is thirty (30) Days after receipt of any invoice from BAMAGAS hereunder. If CES, in good faith, disputes any portion of any such invoice or
 13 

 

billing by BAMAGAS, CES shall nonetheless pay any undisputed portion of such invoice within the prescribed time frame. Wire transfers of payment shall be made to such accounts or accounts as BAMAGAS may designate in writing to CES.
     7.3 Right to Examination. Each of BAMAGAS and CES shall have the right to examine at any reasonable time, upon not less than five (5) Business Days written notice to the other, the books, records and charts of the other to the extent necessary to verify the accuracy of any invoice, charge or computation made under or pursuant to the provisions of this Agreement. Each Party shall retain all such records for a period of two (2) years after the creation thereof.
     7.4 Adjustment of Errors in Billing. If it shall be found that at any time or times CES has been overcharged or undercharged in any form whatsoever under the provisions of this Agreement, and CES shall have actually paid the bill containing such overcharge or undercharge, then, within thirty (30) Days after the final determination thereof, BAMAGAS shall refund the amount of any such overcharge or CES shall pay the amount of any such undercharge with interest thereon at a rate per annum equal to the prime rate of interest published in the Wall Street Journal, from the time such overcharge or undercharge was paid to the date of refund or payment, as the case may be.
     7.5 Interest on Past Due Payments. Interest on any past due payment hereunder shall accrue at a rate per annum equal to the prime rate of interest published in the Wall Street Journal, plus two percent (2%), from the due date until the date of payment, but in no event in excess of the maximum legal rate of interest.
ARTICLE VIII
POSSESSION OF NATURAL GAS
     BAMAGAS shall be deemed to be in control and possession of the Natural Gas being transported hereunder from the time it is received at the upstream flange of a receipt meter at a Point of Receipt until it shall have been delivered to the downstream flange of a delivery meter at a Point of Delivery. As between the Parties hereto, CES shall be deemed to be in control and possession of such Natural Gas before it is received by BAMAGAS as described in the prior sentence at a Point of Receipt and after it has been delivered to CES as described in the prior sentence at a Point of Delivery. Possession of and risk of loss of Gas received by BAMAGAS at the Points(s) of Receipt shall pass from BAMAGAS to CES at the Point(s) of Delivery.
ARTICLE IX
REPRESENTATIONS AND WARRANTIES AND COVENANTS
     9.1 Warranty of Title CES warrants that it will have, at the time of delivery of Gas at a Point of Receipt for transportation hereunder, good title to and/or the full right and authority to deliver such Gas to BAMAGAS for transportation hereunder. Subject only to the accuracy of CES’ foregoing warranty, BAMAGAS warrants that it will at the time of delivery of the Gas transported hereunder have the full right and authority to deliver such Gas to CES. BAMAGAS further warrants that such Gas will be free and clear of all liens, encumbrances or claims created by or through BAMAGAS.
     9.2 Warranty Regarding Intrastate Pipeline. Subject only to any changes in Applicable Law subsequent to the date of this Agreement which affects the status or determination of status of interstate and intrastate pipelines and of regulation by Governmental Authorities. BAMAGAS represents and warrants that the Pipeline will qualify as an intrastate pipeline upon completion hereof and that this Agreement shall not then be subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) or any successor thereto. BAMAGAS further represents and warrants that it will not take any affirmative act which would cause the Pipeline to be classified as an interstate pipeline or otherwise be subject to the jurisdiction of FERC or any successor thereto under or pursuant to the Applicable Law currently in effect as of the date of this Agreement.
     9.3 Corporate Representations and Warranties. Each Party hereby represents and warrants to the other Party that, as of the date hereof:
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 	a.	 	Such Party is duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization, is in good standing and is qualified to do business in the State of Alabama and in all other jurisdictions in which the nature of the business conducted by it makes such qualification necessary and where failure to so qualify would have a material adverse effect on its financial condition, operations, prospects or business.	
 		
 	b.	 	Such Party is not in violation of any applicable law promulgated or judgment entered by any Governmental Authority which violation(s), individually or in the aggregate, would adversely affect its performance of any obligations under this Agreement. There are no legal or arbitration proceedings or any proceeding by or before any governmental or regulatory authority or agency now pending or (to its best knowledge) threatened against it which, if adversely determined, could have a material adverse effect upon its financial condition, operations, prospects or business, as a whole, or its ability to perform under this Agreement.	
 		
 	c.	 	Except for such Governmental Approvals to be obtained by BAMAGAS for the construction and operation of the Pipeline and Governmental Approvals to be obtained by CES with respect to the Decatur Energy Center, such Party is the holder of all permits, licenses or other authorizations required to permit it to operate or conduct its business now and as contemplated by this Agreement, and, no authorization, consent or approval of, notice to or filing with any other Person is required for the execution, delivery or performance by such Party of this Agreement.	
 		
 	d.	 	The execution, delivery and performance by such Party of this Agreement, the compliance with the terms and provisions hereof, and the carrying out of the transactions contemplated hereby, does not conflict or will not conflict with or result in a breach or violation of any of the terms, conditions or provisions of the charter documents, as amended, or bylaws, as amended, of such Party or any order, writ, injunction, judgment or decree of any court or Governmental Authority against such Party or by which it or any of its properties is bound, or any loan agreement, indenture, mortgage, note, resolution, bond, or contract or other agreement or instrument to which such Party is a party or by which it or any of its properties is bound, or constitutes or will constitute a default thereunder or will result in the imposition of any lien upon any of its properties.	
 		
 	e.	 	Such Party has all necessary power and authority to execute, deliver and perform this Agreement and its obligations hereunder; the execution, delivery and performance of this Agreement have been duly authorized by all necessary action on its part; it has duly and validly executed and delivered this Agreement; and the Agreement constitutes a legal, valid and binding obligation of such Party, enforceable against such Party in accordance with the terms hereof, except as the enforceability thereof may be limited by bankruptcy, insolvency, reorganization or moratorium or other similar laws relating to the enforcement of creditors’ rights generally and by general equitable principles.	
     9.4 BAMAGAS covenants. BAMAGAS hereby covenants that during the Term of this Agreement, without the prior written consent of CES:

 	a.	 	It shall not engage in any business other than the development, construction of up to a thirty inch (30") pipeline during the initial construction period, operation, and maintenance (including repair or replacement) of the Pipeline and the BAMAGAS Lateral(s) and the sale, delivery and transportation of Natural Gas thereon (collectively, the “BAMAGAS Activities”);	
 		
 	b.	 	It shall not incur, create, assume or otherwise become liable for any indebtedness other than indebtedness associated with the BAMAGAS Activities;	
 		
 	c.	 	It shall not create, incur, assume or suffer to exist on any of its property any lien, encumbrance, security interest, mortgage, pledge, hypothecation or assignment other than	
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 	 	 	such a lien or other interest arising out of indebtedness associated with the BAMAGAS Activities;	
 		
 	d.	 	It shall preserve and maintain its existence as a corporation and its qualification and good standing in the State of Alabama;	
 		
 	e.	 	It shall pay or cause to be paid, when due and payable, all taxes, charges, levies and assessments and other charges required to be paid by it or levied against the Pipeline and the BAMAGAS Lateral(s), except for taxes contested in good faith and with respect to which proper reserves have been established;	
 		
 	f.	 	It shall maintain all Governmental Approvals required for the ownership and operation of the Pipeline and the BAMAGAS Lateral(s) and for the conduct of its business;	
 		
 	g.	 	It shall maintain appropriate liability insurance on the Pipeline and the BAMAGAS Lateral(s).	
ARTICLE X
INDEMNIFICATION
     10.1 BAMAGAS INDEMNITY. BAMAGAS SHALL PROTECT, DEFEND, INDEMNIFY, AND HOLD HARMLESS THE SHIPPER GROUP FROM AND AGAINST ALL SUITS, ACTIONS, DEBTS, ACCOUNTS, DAMAGES, COSTS, LOSSES AND EXPENSES, INCLUDING, WITHOUT LIMITATION, INJURY TO OR DEATH OF PERSONS AND DAMAGE TO OR DESTRUCTION OF PROPERTY, ARISING FROM ANY ACT OR OMISSION OR ACCIDENT IN CONNECTION WITH (A) BAMAGAS’ CONTROL OR POSSESSION OF THE GAS IN THE PIPELINE OR THE BAMAGAS LATERALS, AND (B) BAMAGAS’ CONSTRUCTION, OWNERSHIP OR OPERATION OF THE PIPELINE AND THE BAMAGAS LATERALS.
     10.2 CES INDEMNITY. CES AGREES TO PROTECT, DEFEND, INDEMNIFY AND HOLD HARMLESS THE BAMAGAS GROUP FROM ALL SUITS, ACTIONS, DEBTS, ACCOUNTS, DAMAGES, COSTS, LOSSES AND EXPENSES, INCLUDING, WITHOUT LIMITATION, INJURY TO OR DEATH OF PERSONS AND DESTRUCTION OF PROPERTY ARISING FROM ANY ACT OR OMISSION OR ACCIDENT IN CONNECTION WITH (A) THE SHIPPER GROUP’S OR THEIR AGENT’S OWNERSHIP, POSSESSION OR CONTROL OF THE GAS PRIOR TO ITS DELIVERY INTO THE PIPELINE OR THE BAMAGAS LATERALS AND AFTER REDELIVERY AT THE POINTS OF DELIVERY OR SECONDARY POINTS OF DELIVERY, AND (B) THE SHIPPER GROUP’S CONSTRUCTION, OWNERSHIP AND OPERATION OF THE DECATUR ENERGY CENTER.
     10.3 Scope. For the purposes of this indemnity:

 	a.	 	The agreement to “defend” includes the responsibility to pay the costs and expenses of defense (including reasonable attorneys’ fees) of the person entitled to indemnity;	
 		
 	b.	 	“Shipper Group” means CES, its officers, directors, subsidiaries, affiliates, members, partners, successors and assigns. “BAMAGAS Group” means BAMAGAS, its officers, directors, subsidiaries, affiliates, members, partners, successors and assigns;	
     10.4 Notice and Opportunity to Defend. Any person claiming indemnification hereunder (an “Indemnitee” must give prompt and timely notice to the Party against which it is claiming indemnity hereunder (the “Indemnitor”) and shall have the right to participate fully in the defense at its sole expense if the Indemnitor undertakes to provide the actual defense. The Indemnitor shall determine within thirty (30) Days after the receipt of such notice whether it will pay the costs and expenses of the Indemnitee’s defense or undertake to provide the actual defense. If the Indemnitor elects to undertake the actual defense, then the Indemnitee shall give the Indemnitor the opportunity to direct the defense of such claim through counsel of its own choosing; provided, however, that (i) if there are differing interests which require separate counsel for the Indemnitee, then the Indemnitee shall defend the claim with separate counsel
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selected or approved by the Indemnitor, and the Indemnitor shall pay the costs and expenses of the Indemnitee’s separate defense; and (ii) the Indemnitee shall nonetheless have the right to participate, solely as an observer, through counsel or otherwise, in meetings and proceedings with adverse parties.
ARTICLE XI
FORCE MAJEURE
     11.1 Force Majeure Defined. Except as expressly provided in this Section 11.1, neither BAMAGAS nor CES shall be required to perform any act required by this Agreement, other than the making of payment of monies due hereunder (including, without limitation, the Initial Term Demand Charge and the Renewal Term Demand Charge), during such period as such Party is unable to perform in whole or in part due to Force Majeure. The term “Force Majeure” as used in this Agreement shall mean any acts of God, strikes, lockouts, embargoes, acts of the public enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, storms, floods, washouts, arrests and restraints of rulers and peoples, civil disturbances, explosions, breakage or failure of or accident to machinery and equipment or lines of pipe caused by events or actions beyond the affected Party’s reasonable control, unanticipated repairs to or replacements of equipment, machinery, lines of pipe, pumps, compressors, valves, gauges, and metering equipment, line freeze-ups, the binding order of any court or Governmental Authority which has been resisted in good faith by all reasonable legal means, and any other cause, of the kind herein enumerated , not within the control of the Party claiming suspension and which by the exercise of due diligence such Party is unable to prevent or overcome. A failure to settle or prevent any strike or other controversy with employees or with anyone purporting or seeking to represent employees shall not be considered to be a matter within the control of the Party claiming suspension; however, in the event of a Force Majeure due to a strike or similar labor dispute, CES shall have the right to utilize its own employees or contract workers to operate the Pipeline during such event; provided, however, that BAMAGAS shall not be liable under this Agreement or otherwise for the acts or omissions of CES’ employees or its contractors in connection with their operation of the Pipeline and/or the BAMAGAS Lateral(s), nor shall BAMAGAS be held in breach of any covenant or other obligation to CES under this Agreement by reason of any acts or omissions of CES’ employees or its contractors in connection with their operation of the Pipeline and/or the BAMAGAS Lateral(s). Except as provided in the immediately preceding sentence, such operation of the Pipeline by CES’ employees or its contractors shall not impair any rights that CES may have under this Agreement. Routine maintenance which will result in the curtailment or interruption of transportation of Gas to the Point(s) of Delivery if scheduled by mutual consent of the Parties, which consent shall not be unreasonably withheld by the affected Party, shall be deemed to operate as a Force Majeure event except for the payment of the Initial Term Demand Charge or the Renewal Term Demand Charge. Causes or contingencies affecting the performance of this Agreement by either Party if deemed to be Force Majeure within the meaning of this Agreement, however, shall not relieve the affected Party of its obligation to perform in the event of such Party’s failure to use due diligence to remedy the situation and remove the cause in an adequate manner and with all reasonable dispatch, nor shall such causes or contingencies relieve either Party of its obligation to perform unless such Party gives notice and full particulars of the same in writing to the other Party as soon as practicable after the initial occurrence relied on. Except as expressly provided in this Section 11.1 or elsewhere in this Agreement, neither Party shall be liable to the other for damages, direct or indirect, immediate or remote, by reason of, caused by or arising out of the obligation or obligations of either Party when such suspension results from an event of Force Majeure.
     11.2 Effect of Force Majeure. In the event that BAMAGAS is unable to transport Gas or CES is unable to receive Gas hereunder as the result of an event of Force Majeure, a period of time equal to the duration of such inability (the “Extension Period”) shall be added to the Initial Term if occurring during the Initial Term) or the Renewal Term (if occurring during the Renewal Term), as applicable, and during such extended period the Transportation Rate for all quantities of Gas transported each Day up to, but not in excess of, the Firm Transportation Quantity shall be zero cents ($0.00), except as otherwise provided in this Section 11.2. In the event that as the result of an event of Force Majeure the Decatur Energy Center is substantially damaged or destroyed and CES decides not to rebuild such facility, CES shall have the right to terminate this Agreement and to have no prospective obligations under this Agreement to BAMAGAS except as provided in the next sentence. In the event of termination of this Agreement in accordance with the foregoing, CES shall pay BAMAGAS the relevant Termination Value as determined in accordance with Exhibit 4. CES shall have the right during the continuance of any event of Force Majeure that affects
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its ability to receive Gas hereunder to sell its capacity on the Pipeline to a third party, other than a then existing customer of BAMAGAS, Enbridge or any Affiliate of either of them, unless BAMAGAS elects to delay the payment of the Initial Term Demand Charge or the Renewal Term Demand Charge which would otherwise be due BAMAGAS during the period of the Force Majeure for payment during any Extension Period.
ARTICLE XII
EVENTS OF DEFAULT
     12.1 Definition. An “Event of Default” under this Agreement shall be deemed to exist with respect to a Party upon the occurrence of any one or more of the following events:

 	a.	 	Failure by a Party to timely make payment of any amount due to the other Party under this Agreement (other than an amount subject to a good faith dispute), which failure continues for a period of twenty (20) Days after receipt of written notice of such nonpayment;	
 		
 	b.	 	Failure or refusal of BAMAGAS to submit and/or to diligently pursue a Cure Plan as provided in Article II, Section 2.3 (whether or not such Cure Plan is successful) after CES delivers to BAMAGAS written notice of BAMAGAS’ failure to meet any Milestone upon the expiration of the Completion Period provided for in the Milestone Schedule or any extension period agreed to in writing by CES.	
 		
 	c.	 	Curtailment or interruption, other than by reason of Pressure Variance, at any time subsequent to sixty (60) Days following BAMAGAS’ initial deliveries on the Pipeline of transportation by BAMAGAS to a Primary Point of Delivery for more than fifteen (15) minutes of the greater of 3,000 MMBtus or five percent (5%) or more of those Gas quantities which are required at any given time, not to exceed the Firm Transportation Quantity, for the operational requirement of the Decatur Energy Center, other than by reason of express written consent of CES, Force Majeure, Applicable Law, an Excusable Event, or as otherwise permitted under this Agreement (an “Unexcused Curtailment”), on more than three (3) occasions on separate Days in any consecutive four (4) year period or on more than eight (8) occasions on separate Days in the aggregate over any consecutive twenty (20) year period; provided, however, an Unexcused Curtailment shall be conclusively deemed not to have occurred unless written notice thereof, together with the known facts surrounding such curtailment or interruption, is given in writing by CES to BAMAGAS within ten (10) Days following such curtailment or interruption. BAMAGAS shall have the right to deliver to the Point(s) of Delivery those quantities of Gas which would otherwise be curtailed or interrupted under this provision via any of the Pipeline, the BAMAGAS Lateral(s), the MIT Lateral or any other pipeline, and if delivered by any such means to the Point(s) of Delivery, no curtailment or interruption shall be deemed to have occurred.	
 		
 	d.	 	Failure by a Party hereunder subsequent to the completion of both the Pipeline and the BAMAGAS Lateral(s) to substantially perform any other material obligation under this Agreement (i) which is not separately listed in this Section 12.1, and (ii) for which no exclusive remedy is provided for elsewhere in this Agreement, within twelve (12) months after a Party’s receipt of written notice from the other Party that a material obligation has not been performed.	
 		
 	e.	 	If by order of a court of competent jurisdiction, a receiver or liquidator or trustee of a Party or of any of the property of a Party shall be appointed, and such receiver or liquidator or trustee shall not have been discharged within a period of ninety (90) Days; or if by decree of such a court, a Party shall be adjudicated bankrupt or insolvent or any substantial part of the property of such Party shall have been sequestered, and such decree shall have continued undischarged and unstayed for a period of ninety (90) Days after the entry thereof; or if a petition to declare bankruptcy or to reorganize a Party pursuant to any of the provisions of the federal Bankruptcy Code, as it now exists or as it may hereafter be amended, or pursuant to any other similar state statute applicable to such Party, as now or hereafter in effect, shall be filed against such Party and shall not be dismissed within ninety (90) Days after such filing; or	
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 	f.	 	If a Party shall file a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law or shall consent to the filing of any bankruptcy or reorganization petition against it under any similar law; or, without limitation of the generality of the foregoing, if a Party shall file a petition or answer or consent seeking relief or assisting in seeking relief in a proceeding under any of the provisions of the federal Bankruptcy Code, as it now exists or as it may hereafter be amended, or pursuant to any other similar state statute applicable to such Party, as now or hereafter in effect, or an answer admitting the material allegations of a petition filed against it in such a proceeding; or if a Party shall make an assignment for the benefit of its creditors; or if a Party shall admit in writing its inability to pay its debts generally as they become due; or if a Party shall consent to the appointment of a receiver or receivers, or trustee or trustees, or liquidator or, liquidators of it or of all or any part of its property.	
     12.2 Right of Termination for Default. Upon the occurrence and during the continuation of an Event of Default, the Party not in default shall have the right to terminate this Agreement upon written notice to the other Party (the “Notice”) if the default is not cured or remedied within the thirty (30) day period following the other Party’s receipt of such written notice (the “Notice Period”); provided, however, if the Party claimed to be in default disputes at any time prior to the expiration of the Notice Period that an Event of Default occurred, then the dispute shall be arbitrated under the provisions of Sections 16.3, 16.4 and 16.5. Failure by the Party alleged to be in default to dispute the occurrence or continuance of an Event of Default after Notice has been received and within the Notice Period shall operate to waive any rights the Party alleged to be in default may have to dispute same. Any measures taken by the Party alleged to be in default shall not in any way prejudice such Party’s dispute as to the occurrence of an Event of Default noticed by the other Party, whether such measures are taken before or after notice of the Event of Default is given. Furthermore, no evidence taken at any time to remedy any Event of Default (whether or not notice is given to the Party claimed to be in default) shall be admissible by the Party alleging the Event of Default in any arbitration proceeding or other legal proceeding between the Parties.
     12.3 CES Purchase Rights. In the event of termination of this Agreement by CES following a BAMAGAS Event of Default and BAMAGAS’ failure to timely cure or remedy such Event of Default, or in the event that CES desires a Renewal Term but BAMAGAS does not, as provided in Article III, or if CES terminates this Agreement under Section 12.2, CES shall, subject to the purchase rights of CES under the Natural Gas Transportation Agreement for the Morgan Energy Center, have the right to purchase the Pipeline and the BAMAGAS Lateral(s), subject to the right of BAMAGAS to transport Gas on the Pipeline and the BAMAGAS Laterals to Morgan Energy Center pursuant to the Natural Gas Transportation Agreement for the Morgan Energy Center and the transportation rights of BAMAGAS and/or any marketing Affiliate(s) of BAMAGAS or Enbridge on the Pipeline and the BAMAGAS Lateral(s) as set forth on Exhibit 11 (collectively, the “Transportation Rights”), for a price (the “Purchase Price”) equal to the amount (the “Termination Value”) as determined in accordance with Exhibit 4. Concurrent with payment of the Purchase Price, BAMAGAS shall execute and deliver to CES such instruments of transfer as are reasonably requested by CES subject to the Transportation Rights and those certain covenants, use restrictions and other obligations specified in Exhibit 9 (the “Use Restrictions”), and CES shall execute and deliver to BAMAGAS such instruments binding the Pipeline and the BAMAGAS Lateral(s) to such Transportation Rights and Use Restrictions as are reasonably requested by BAMAGAS; provided, however, that no representations shall be required to be provided by BAMAGAS other than representations that BAMAGAS has the right, power and authority to convey the Pipeline and the BAMAGAS Lateral(s) and that they are assigned free and clear of all liens and/or any other claims and liabilities. At CES’ request, upon execution of this Agreement, BAMAGAS shall grant to CES a first priority security interest (which shall be of equal priority with the first priority security interest concurrently granted by BAMAGAS to CES pursuant to the Natural Gas Transportation Agreement for the Morgan Energy Center) in the Pipeline and/or the BAMAGAS Lateral(s) to secure CES’ purchase rights under this Section 12.3.
     12.4 Remedies Not Exclusive. Except as otherwise expressly provided to the contrary herein, the rights and remedies herein provided in case of an Event of Default shall not be exclusive but shall, to the extent permitted by law, be cumulative and in addition to all other rights and remedies existing at law, in equity or otherwise (including the right to specific performance), except those rights and remedies which
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have been waived or relinquished hereunder by the Parties pursuant to the provisions hereof. No delay or omission of a Party to exercise any right or remedy occurring upon any Event of Default shall impair any such right or remedy or constitute a waiver of such default or an acquiescence therein. Every right and remedy given by this Agreement or by law to a Party may be exercised from time to time, and as often as may be deemed expedient, by such Party. A Party shall have the obligation to mitigate any damages it incurs as a result of the other Party’s breach.
     12.5 Limitation of Liability. EXCEPT AS OTHERWISE SPECIFICALLY PROVIDED HEREIN, IN NO EVENT SHALL ANY PARTY BE LIABLE TO ANY OTHER PARTY FOR INDIRECT. SPECIAL, INCIDENTAL, CONTINGENT OR CONSEQUENTIAL DAMAGES, WHETHER SUCH DAMAGES ARISE IN CONTRACT, TORT, STRICT LIABILITY OR OTHERWISE, LENDER OR IN CONNECTION WITH THIS AGREEMENT, AND ANY DAMAGES SHALL BE LIMITED TO COMPENSATORY DAMAGES.
     12.6 Non-Recourse. The obligations of the Parties under this Agreement are intended to be recourse only to the assets of the Parties, and neither the partners thereof nor any shareholder, officer, director, employee or agent of the Parties or any partners or Affiliates of such Party shall have any personal responsibility or liability for any breach in performance or observance of the covenants, representations, or obligations thereunder. The provisions of this Section 12.6 shall not limit any of the obligations of Calpine Corporation under the absolute and unconditional guaranty of payment to be provided to BAMAGAS with respect to all obligations of CES hereunder, as provided under Section 18.1 (the “Calpine Corporation Guaranty”).
ARTICLE XIII
TRANSFER AND ASSIGNMENT
     13.1 Assignment. This Agreement shall be binding upon and inure to the benefit of the Parties hereto and their respective successors and permitted assigns. No assignment or transfer permitted hereunder shall relieve the assigning Party of its respective obligations under this Agreement unless the other Party agrees to such release; provided, however, that in the event of an assignment by CES to an Affiliate (and provided that the Calpine Corporation Guaranty remains in effect), CES shall be released from its obligations hereunder. This Agreement, including any of the rights or obligations hereunder, may not be assigned or transferred without the prior written consent of the other Party, which consent shall not be unreasonably withheld, conditioned or delayed. Notwithstanding the foregoing (but subject to Section 13.2 below), any Party may, without the need for consent from the other Party (and without relieving itself from liability hereunder), (a) transfer or assign this Agreement to an Affiliate of such Party (provided that in the case of BAMAGAS, the assignment to such Affiliate will not jeopardize the status of the Pipeline or the BAMAGAS Laterals) as non-FERC jurisdictional assets), or (b) transfer or assign this Agreement to any Person succeeding to all or substantially all of the assets of such Party. In the event that DEC sells the Decatur Energy Center to a third party (a “Second Owner”), BAMAGAS agrees that if requested by CES it will enter into a new agreement with the Second Owner on the same terms and conditions as this Agreement. Upon the sale of the Decatur Energy Center, BAMAGAS shall release Calpine from all of its prospective obligations under the Calpine Corporation Guaranty provided that the successor owner has substantially the same or better creditworthiness as Calpine and executes and delivers a guaranty to BAMAGAS with respect to the Decatur Energy Center substantially in the same form and content as the Calpine Corporation Guaranty. In addition, CES and BAMAGAS each shall have the right without the consent of the other Party to assign this Agreement as collateral security for loans made, in the case of DEC, with respect to the construction of the Decatur Energy Center or, in the case of BAMAGAS, with respect to the construction of the Pipeline and the BAMAGAS Lateral(s). Each of CES and BAMAGAS agree to provide reasonable cooperation to
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the other Party with respect to obtaining such financing, including the execution of written consents to assignment reasonably requested by such lenders.
     13.2 Right of First Refusal. In the event that BAMAGAS receives a bona fide offer from a third party (including an Affiliate of BAMAGAS) for the purchase of the Pipeline and/or the BAMAGAS Lateral(s) and/or BAMAGAS (“Third Party Offer”) and BAMAGAS intends to accept such offer, prior to accepting such offer it must notify CES of the offer (the “Offer Notice”), which Offer Notice shall set forth the purchase price and all of the other terms offered by the third party. Subject to the same right of first refusal of CES pursuant to the Natural Gas Transportation Contract for the Morgan Energy Center, CES shall have thirty (30) Days (the “Exercise Period”) from the date of the Offer Notice within which to elect to purchase all (and not less than all of the property covered by the Offer Notice) for the same purchase price and upon the same other terms (including the closing date) set forth in the Offer Notice. If the Third Party Offer includes assets other than the Pipeline and the BAMAGAS Lateral(s), BAMAGAS shall notify CES of the offer price for the Pipeline and the BAMAGAS Lateral(s) in order for CES to exercise its right of first refusal exclusively in connection with those assets. In the event that CES elects to purchase the Pipeline and the BAMAGAS Lateral(s), it shall notify BAMAGAS in writing within the Exercise Period; provided, however, if the Third Party Offer is conditioned upon the ability to purchase the Pipeline and the BAMAGAS Lateral(s) with other assets or BAMAGAS with other assets and/or another entity and CES elects to purchase the Pipeline and the BAMAGAS Lateral(s), then BAMAGAS, at its option, may rescind the Offer Notice, in which event BAMAGAS shall not sell the Pipeline and/or the BAMAGAS Lateral(s) or BAMAGAS, as applicable, to either CES or the third party pursuant to the Third Party Offer. If a Third Party Offer encompasses both the Pipeline and the BAMAGAS Lateral(s), CES may only exercise its right of first refusal as specified herein in connection with both assets or it shall be deemed to have waived its rights. In the event CES does not give such a notice to BAMAGAS or does not respond within the Exercise Period, BAMAGAS shall be free to accept the offer of the third party for the same purchase price and on the same terms set forth in the Offer Notice. In the event the terms of the transaction with the third party change after CES has declined to exercise its right of first refusal, BAMAGAS must provide a new Offer Notice to CES. In the event that CES decides to purchase on the terms set forth in an Offer Notice, it shall notify BAMAGAS in writing prior to the end of the Exercise Period and the sale to CES shall be closed within thirty (30) Days thereof. Upon a sale to CES hereunder, this Agreement shall automatically terminate as to all prospective obligations. Upon a sale to a third party hereunder, the third party as a successor in interest to BAMAGAS shall be bound by this Agreement, which shall remain in effect under the terms of Article III.
ARTICLE XIV
REGULATION
     Each Party shall, in the course of its undertakings hereunder and as a part thereof, endeavor to obtain all required Governmental Approvals and shall comply otherwise with all applicable federal, state and local laws and regulations thereof. CES shall cooperate with BAMAGAS and, if requested by BAMAGAS, shall provide reasonable assistance to BAMAGAS in connection with BAMAGAS’ actions to obtain such Governmental Approvals. Each Party waives any right to contest or to seek to amend the rates provided for herein before any Governmental Authority.
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ARTICLE XVI
DISPUTE RESOLUTION; GOVERNING LAW
     16.1 Procedure. In the event a dispute arises between BAMAGAS and CES regarding this Agreement or the transaction covered hereby, including, without limitation, (a) the application or interpretation of this Agreement, (b) whether or not an Unexcused Curtailment has occurred, (c) whether or not an Event of Default has occurred or continued without having been cured or remedied, and (d) the actions or measures which may be taken to cure or otherwise remedy an Event of Default, the Parties agree to use the procedures in this Article XVI to resolve any such disputes.
     16.2 Initial Resolution Attempts. Either Party may initiate dispute resolution procedures by sending written notice to the other Party specifically stating the complaining Party’s claim and requesting dispute resolution in accordance with this Article XVI. The receiving Party shall reply with the designation of a person authorized to settle the dispute and shall list two (2) alternative dates (both of which must be within ten (10) Business Days after receipt of the complaint) for meeting at a mutually agreeable location. If the matter has not been resolved within ten (10) Days of such meeting, each Party shall refer the dispute to a senior executive of its organization who shall meet at a mutually agreeable location within fourteen (14) Days to resolve the dispute.
     16.3. Arbitration. If the matter has not been resolved within fourteen (14) Days of the meeting of the senior executives, the Parties shall submit the dispute to arbitration under the terms and conditions set forth herein. Any dispute or need of interpretation arising out of this Agreement or which is disputed shall be submitted to binding arbitration by one arbitrator with knowledge of and over five years of professional experience in connection with similar transactions who has not previously been employed by either Party, and does not have a direct or indirect interest in either Party or the subject matter of the arbitration. Such arbitrator shall either be as mutually agreed by the Parties within ten (10) Days after written notice from either Party requesting arbitration, or failing agreement, shall be selected under the expedited rules of the American Arbitration Association (the “AAA”). The rules of the AAA shall apply to the extent not inconsistent with the rules herein specified. Either Party may initiate arbitration by written notice to the other Party and the arbitration shall be conducted according to the following: (a) the arbitration hearing shall commence no later than thirty (30) Days of the selection of the arbitrator, (b) not later than seven (7) Days prior to the hearing date set by the arbitrator each Party shall submit a brief detailing its factual and legal position and a final offer for the settlement of the dispute, including a dollar amount, if applicable, (c) the hearing shall be conducted on a confidential basis without continuance or adjournment, (d) the Parties shall divide equally the cost of the arbitrator and the hearing and each Party shall be responsible for its own expenses and those of its counsel and representatives and (e) evidence concerning any offer made or the details of any negotiation prior to arbitration and the cost to the Parties of their representatives and counsel shall not be permissible. The arbitrator shall include in his report/award a list of findings, with supporting evidentiary references, upon which he has relied in making his decision. The award rendered by the arbitrator shall be final and binding upon the Parties and judgment upon the award rendered by the arbitrator may be entered by any court having jurisdiction thereof. The place of arbitration shall be Houston, Texas. Each Party understands that this Agreement contains an agreement to arbitrate with respect to any dispute. After signing this Agreement, each Party understands that it will not be able to bring a lawsuit concerning any dispute that may arise that is covered by this arbitration provision. Instead, each Party agrees to submit any such dispute to an impartial arbitrator. Any monetary award of the arbitrator may be enforced by the Party in whose favor such monetary award is made in any court of competent jurisdiction.
     16.4. General Rules and Provisions. Notwithstanding anything to the contrary contained herein, and regardless of any procedures or rules of the AAA, it is expressly agreed that the following shall apply and control over any other provision in this Article XVI.

 	a.	 	The arbitrator shall have no authority to award punitive damages or attorneys’ fees.	
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 	b.	 	The fees and expenses of the mediator and arbitrator shall be shared equally by the Parties, and each Party shall bear its own costs and expenses.	
 		
 	c.	 	The Parties may, by written agreement signed by both Parties, alter any time deadline, location(s) for meeting(s), or procedure outlined in this Article XVI or in the AAA rules.	
 		
 	d.	 	Time is of the essence for purposes of the provisions of this Article XVI .	
 		
 	e.	 	Either Party may seek a restraining order, temporary injunction, or other provisional judicial relief if the Party in its sole judgment believes that such action is necessary to avoid irreparable injury or to preserve the status quo. The Parties will continue to participate in good faith in the procedures despite any request for provisional relief.	
 		
 	f.	 	The arbitrator shall have no authority, power or right to alter, change, amend, modify, waive, add to or delete from any of the provisions of this Agreement, and any award rendered by the arbitrator shall be consistent with the terms and conditions of this Agreement.	
     16.5. Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Texas, exclusive of any conflict of laws provisions thereof that would refer jurisdiction to the laws of another state.
ARTICLE XVII
NOTICES
     17.1 Writing. Any notice, demand, offer or other written instrument required or permitted to be given pursuant to this Agreement shall be in writing signed by the Party giving such notice, demand or offer, and shall be sent by telefax (confirmed by a mailed or courier copy received within five (5) Days), then by hand delivery, overnight courier, telegram or registered or certified mail, return receipt requested, to the other Party at such address as set forth below.
If delivered to BAMAGAS:
BAMAGAS Company
1100 Louisiana, Suite 2900
Houston, Texas 77002
Attn: President
Tel.: (713) 650-8900
Fax: (713) 653-6711
With a copy to:
Enbridge (U.S.) Inc.
1100 Louisiana, Suite 2900
Houston, Texas 77001
Attn: President
Tel.: (713) 650-8900
Fax: (713) 653-6711
If delivered to CES:
Calpine Energy Services, L.P.
700 Louisiana, Suite 2700
Houston, Texas 77002
Attention: Jeff Rawls, Vice President — Producer Services
Tel.: (713) 830-8636
Fax: (713) 830-8712
 23 

 

With a copy to:
Calpine Corporation
50 West San Fernando Street
San Jose, California 95113
Attention: General Counsel
Tel.: (408) 995-5115
Fax: (408) 975-4648
     Each Party shall have the right to change the place to which notice shall be sent or delivered or to specify one additional address to which copies of notices may be sent, in either case by similar notice sent or delivered in like manner to the other Party.
     17.2 Timing of Receipt. Without limiting any other means by which a Party may be able to prove that a notice has been received by the other Party, a notice shall be deemed to be duly received:

 	a.	 	If delivered by hand, overnight courier or telegram, on the date when received at the address of the recipient;	
 		
 	b.	 	If sent by registered or certified mail, on the date of the return receipt; or	
 		
 	c.	 	If sent by telefax, upon receipt by the sender of acknowledgment or transmission report generated by the machine from which the telefax was sent indicating that the telefax was sent in its entirety and received at the recipient’s telefax number.	
ARTICLE XVIII
MISCELLANEOUS
     18.1 Financial Responsibility. Within two (2) Business Days following execution hereof BAMAGAS shall furnish to CES an absolute and unconditional guaranty from Enbridge (U.S.) Inc. to CES (which guaranty will terminate prospectively upon CES’ exercise of its purchase rights under Section 12.3 or a sale of the Pipeline to an unaffiliated third party after compliance with the provisions of Section 13.2) in the form and content of Exhibit 5. Contemporaneously with the execution and delivery of this Agreement, CES shall furnish to BAMAGAS an absolute, unconditional guaranty from Calpine to BAMAGAS in the form and content of Exhibit 6 (the “Calpine Corporation Guaranty”).
     18.2 Captions. Captions of the Articles and Sections of this Agreement are for convenience and reference only, and the words contained therein shall in no way be held to explain, modify, amplify, or aid in the interpretation, construction or meaning of the provisions of this Agreement.
     18.3 Non Disclosure. Any information disclosed by a Party that is described herein or that is marked or identified as confidential or proprietary will be treated as confidential information and shall not be used or disclosed by the receiving Party (other than to its Affiliates) without the prior consent of the disclosing Party, except when required to be disclosed by Applicable Law or in connection with regulatory filings. In addition, no Party shall disclose any of the terms of this Agreement (other than to its Affiliates, its lenders or potential lenders, and any other parties now or hereafter owning an equity interest in the Pipeline, the BAMAGAS Lateral(s), the Decatur Energy Center, or any of the Parties to this Agreement) without the prior written consent of the other Party. The foregoing notwithstanding, the steam hosts for Decatur Energy Center shall have the right to review BAMAGAS’ invoices to CES for transportation service.
     Confidential information does not include information that: (i) is or becomes a part of the public domain through no fault of the receiving Party and without breach of this Agreement or other confidentiality agreement; (ii) is received from a third party in good faith where such third party is not obligated to a Party to keep such information confidential; (iii) was in the receiving Party’s possession prior to receipt from the other Party; or (iv) was independently developed by the receiving Party without reference to any such confidential information. To the extent that either Party is required by (i) an applicable federal or state securities law, order, rule or regulation; or (ii) an applicable federal or state law,
 24 

 

order, rule or regulation relating to obtaining necessary or desirable permits; to make disclosure of such information or of the terms of the transactions contemplated and the transactions themselves, then such Party shall be permitted to make only those disclosures as are reasonably necessary to be compliant with such applicable law, order, rule or regulation and shall furnish a copy of such disclosure to the other Party as far in advance of such disclosure as is reasonably practicable.
     18.4 Press Releases and Public Announcements. The Parties may issue press releases upon the execution of this Agreement, provided that each Party shall submit to the other Party a copy of its intended press release not less than two (2) Business Days prior to the time of release, for such other Party’s approval. Any Party may make any public disclosure it believes in good faith is required by applicable law or any listing or trading agreement concerning its publicly traded securities (in which case the disclosing Party will use its reasonable best efforts to advise the other Party before making the disclosure).
     18.5 Amendments. No change, amendment or modification of this Agreement, and no further agreement to be made pursuant to this Agreement, shall be valid or binding upon the Parties unless such change, amendment or modification shall be in writing and duly executed by both Parties.
     18.6 Severability. The invalidity of one or more phrases, sentences, clauses or Sections contained in this Agreement shall not affect the validity of the remaining portions of this Agreement so long as the material purposes of this Agreement can be determined and effectuated.
     18.7 Entire Agreement. This Agreement sets forth all of the promises, agreements, conditions and understandings between the Parties relating to the subject matter hereof and supersedes any and all negotiations, other agreements and representations made prior to the date hereof with respect to the same subject matter.
     18.8 No Waiver. Any failure of either Party to enforce any of the provisions of this Agreement or to require compliance with any of its terms at any time during the pendency of this Agreement, shall in no way affect the validity of this Agreement, or any part hereof, and shall not be deemed a waiver of the right of such Party thereafter to enforce any and each such provision. Any consent or approval given pursuant to this Agreement shall be limited to its express terms and shall not otherwise increase the obligations of the Party giving such consent or approval or otherwise reduce the obligations of the Party receiving such consent or approval.
     18.9 Further Assurances. Each Party agrees to execute and deliver all further instruments and documents, and take any further action that may be reasonably necessary, to effectuate the purposes and intent of this Agreement.
     18.10 Counterparts. This Agreement may be executed in counterparts, each of which shall be deemed to be an original and both of which together shall be deemed to constitute one and the same agreement.
     18.11 Exhibits, Attachments and Schedules. All references in the Agreement to Exhibits, Attachments and Schedules shall be deemed to be references to the Exhibits, Attachments and Schedules attached hereto as the same may be amended and supplemented pursuant to the terms of this Agreement or otherwise by mutual written agreement of the Parties.
 25 

 

     IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date first hereinabove written.
BAMAGAS Company

By:	 	/s/ I.J. Berthelot II

Name: I.J. Berthelot II	 	 	
 	 	Title: Vice President	 	 	
CALPINE ENERGY SERVICES, L.P.
By Its General Partner,
CPN Energy Services GP, Inc.

By:	 	/s/ Diana Knox
 
Name: Diana Knox	 	 	
 	 	Title: Sr. Vice President	 	 	
 26 

 

EXHIBIT 1
MILESTONE SCHEDULE
MIDCOAST PIPELINE MILESTONE SCHEDULE
 	 	 	 	 	 	 	 	 	
 	 	Notice To Proceed	 	Completion Period	
MILESTONES	 	(expected date)	 	(days)	
Public Announcement	 	 	 	 	 	 	 	 	
Project Schedule	 	 	 	 	 	 	 	 	
Provide to Calpine a Proposed Schedule	 	 	6/25/00	 	 	 	30	 	
Lateral Capacity Determination	 	 	6/25/00	 	 	 	30	 	
Route Selection	 	 	 	 	 	 	 	 	
Route Selection and Surveying	 	 	6/25/00	 	 	 	100	 	
Drafting and Mapping	 	 	6/25/00	 	 	 	125	 	
 	 	 	 	 	 	 	 	 	
Easement and RDW Acquisition:	 	 	 	 	 	 	 	 	
50% of Easements and Rights of Way Obtained (includes Midcoast or subsidiary’s owned rights that are assignable)	 	 	6/25/00	 	 	 	75	 	
90% of Easements and Rights of Way Obtained	 	 	6/25/00	 	 	 	170	 	
100% of Easements and Rights of Way Obtained (Condemnations may not be complete)	 	 	6/25/00	 	 	 	270	 	
Regulatory:	 	 	 	 	 	 	 	 	
Permits and CCN Application Submitted	 	 	7/25/00	 	 	 	60	 	
Regulatory (Environmental) Approvals unless a full environmental impact study is required.	 	 	7/25/00	 	 	 	120	 	
CCN Approval	 	 	7/25/00	 	 	 	120	 	
All Regulatory Approvals	 	 	7/25/00	 	 	 	301	 	
Engineering:	 	 	 	 	 	 	 	 	
Preliminary Engineering	 	 	7/25/00	 	 	 	30	 	
Engineering — Detailed Design	 	 	8/25/00	 	 	 	90	 	
 	 	 	 	 	 	 	 	 	
Development and Construction of BAMAGAS Lateral for DEC #1 :	 	 	 	 	 	 	 	 	

 

 	 	 	 	 	 	 	 	 	
 	 	Notice To Proceed	 	Completion Period	
MILESTONES	 	(expected date)	 	(days)	
Easements and Rights of Way Procured	 	 	6/25/00	 	 	 	270	 	
Regulatory Approvals (if needed)	 	 	7/25/00	 	 	 	200	 	
Engineering	 	 	8/25/00	 	 	 	90	 	
Pipe and Equipment for Lateral Ordered	 	 	8/25/01	 	 	 	60	 	
Construction of Lateral	 	 	9/1/01	 	 	 	45	 	
Lateral Testing	 	 	10//01	 	 	 	15	 	
Lateral Operational	 	 	11/1/01	 	 	 	0	 	
 	 	 	 	 	 	 	 	 	
Development and Construction of BAMAGAS Lateral for DEC #2:	 	 	 	 	 	 	 	 	
Easements and Rights of Way Procured	 	 	6/25/00	 	 	 	270	 	
Regulatory Approvals (if needed)	 	 	7/25/00	 	 	 	200	 	
Engineering	 	 	8/25/00	 	 	 	90	 	
Pipe and Equipment for Lateral Ordered	 	 	8/25/01	 	 	 	60	 	
Construction of Lateral	 	 	9/1/01	 	 	 	45	 	
Lateral Testing	 	 	10/2501	 	 	 	15	 	
Lateral Operational	 	 	11/1/01	 	 	 	0	 	
 	 	 	 	 	 	 	 	 	
Construction of Main Line:	 	 	 	 	 	 	 	 	
Pipe and Equipment PO Placed	 	 	4/1/01	 	 	 	30	 	
Construction Contract Awarded	 	 	5/1/01	 	 	 	30	 	
Gas Pipeline Construction	 	 	6/1/01	 	 	 	180	 	
Construction Complete	 	 	12/1/01	 	 	 	0	 	
Gas Pipeline Testing	 	 	12/1/01	 	 	 	30	 	
Gas Pipeline Operable:	 	 	 	 	 	 	 	 	
Gas Pipeline Operational	 	 	1/1/02	 	 	 	0	 	

 

EXHIBIT 2
GAS QUALITY SPECIFICATIONS

1.	 	Natural or Artificial Gas:	
 		
 	 	The gas received or delivered by the Pipeline shall be a combustible gas consisting wholly of, or a mixture of:	

 	(A)	 	Natural gas of the quality and composition produced in its natural state except that the pipeline may extract or permit the extraction of any of the constituents thereof except methane.	
 		
 	(B)	 	Gas generated by vaporization of Liquefied Natural Gas (LNG).	
 		
 	(C)	 	Manufactured, reformed, or mixed gas consisting essentially of hydrocarbons of the quality and character produced by nature in the petroleum, oil and gas fields with physical properties such that when the artificial pipeline gas is commingled with natural gas, the two become indistinguishable.	

2.	 	Total Heating Value:	

 	(A)	 	No gas delivered hereunder shall have a total heating value at the Point of Receipt either below Nine Hundred Sixty Seven (967) or above one thousand one hundred (1100) Btu per cubic foot of dry gas at a temperature of sixty degrees (60°) Fahrenheit and under a pressure of 14.73 psia.	
 		
 	(B)	 	The total heating value shall be determined by gas chromatographic analysis using AGA 3-1990 factors or any revision thereof, or by other methods mutually agreed upon by Customer and Pipeline.	
 		
 	(C)	 	The average total heating value of the gas shall be determined for any billing period by method or methods mutually agreed upon by Customer and Pipeline.	

3.	 	Composition:	

 	(A)	 	Solids:	
 		
 	 	 	The gas shall be commercially free, under continuous gas flow conditions, from objectionable odors, solid matter, dust, gums, and gum-forming constituents which might interfere with its merchantability or cause injury to or interference with proper operations of the pipelines, compressor stations, meters, regulators or other appliances through which it flows.	

(B)	 	Oxygen:	
 		
 	 	The gas shall not have an uncombined oxygen content in excess of two-tenths (0.2) of one percent (1%) by volume, and both parties shall make every reasonable effort to keep the gas free from oxygen.	
 		
(C)	 	Carbon Dioxide and Nitrogen:	

 

 	 	The gas shall not contain more than four percent (4%) by volume, of a combined total of carbon dioxide and nitrogen; it being understood, however, that the total carbon dioxide content shall not exceed three percent (3%) by volume.	
 		
(D)	 	Liquids:	
 		
 	 	The gas shall be free of water and hydrocarbons in liquid form at the temperature and pressure at which the gas is received and delivered.	
 		
(B)	 	Hydrogen Sulfide:	
 		
 	 	The gas shall not contain more than one-quarter (0.25) grain (4 ppm) of hydrogen sulfide per one-hundred (100) cubic feet.	
 		
(F)	 	Total Sulphur:	
 		
 	 	The gas shall not contain more than ten (10) grains of total sulphur, excluding any mercaptan sulphur, per one-hundred (100) cubic feet.	
 		
(G)	 	Temperature:	
 		
 	 	The gas shall not have a temperature of more than one-hundred twenty degrees (120°) Fahrenheit.	
 		
(H)	 	Water Vapor:	
 		
 	 	The gas shall not contain in excess of seven (7) pounds of water vapor per million cubic feet.	
 		
(I)	 	Liquefiable Hydrocarbons:	
 		
 	 	The gas shall not contain more than two-tenths (0.2) gallon per thousand cubic feet, of those certain liquefiable hydrocarbons commonly referred to as natural gasoline, as determined by gas chromatographic analysis.	
 		
(J)	 	Microbiological Agents:	
The gas shall not contain, either in the gas or in any liquids with the gas, any microbiological organism, active bacteria or bacterial agent capable of contributing to or causing corrosion and/or operational and/or other problems.
Microbiological organisms, bacteria or bacterial agents include, but are not limited to, sulfate reducing bacteria (SRB) and acid producing bacteria (APB). Tests for bacteria or bacterial agents shall be conducted on samples taken from the meter run or the appurtenant piping using American Petroleum Institute (API) test method API-RP38 or any other test method acceptable to Pipeline and Customer which is currently available or may become available at any time.
This Exhibit may be amended from time to time by mutual consent of the parties, such consent not to be unreasonably withheld to conform to stricter requirements imposed by either the upstream suppliers or transporters at the point(s) of receipt.

 

EXHIBIT 3
POINTS OF RECEIPT/DELIVERY
Points of Receipt
The proposed interconnection between the BAMAGAS Pipeline and Tennessee Gas Pipeline Company located in or near Section 2, Township 4 South, Range 13 West, of Colbert County, Alabama.
The proposed interconnection between the BAMAGAS Pipeline and Texas Eastern Transmission Company located in or near Section 8, Township 4 South, Range 12 West, of Colbert County, Alabama.
The proposed interconnection between the BAMAGAS Pipeline and Midcoast Interstate Transmission Company located at a mutually agreeable location in Morgan County, Alabama.
Points of Delivery
The proposed interconnection between the BAMAGAS Pipeline and Decatur Energy Center located either in or near Section 4, Township 5 South, Range 5 West or Section 11, Township 5 South, Range 5 West, of Morgan County, Alabama (as designated pursuant to the Natural Gas Pipeline Construction and Transportation Agreement). More specifically, the Point of Delivery shall be the southeast corner of the property described in Attachment 1.

 

Attachment 1
A tract of land containing 20.00 acres more or less and being situated in Section 11, Township 5 South, Range 5 West, Morgan County, Alabama, being more particularly described as follows:
Commencing at the Southwest corner of said Section 11, thence along the South boundary of said Section, South 89 degrees 05 minutes 15 seconds East for 1767.06 feet; thence leaving said boundary, North 00 degrees 54 minutes 45 seconds East for 4247.37 feet; thence North 89 degrees 57 minutes 35 seconds East for 1818.13 feet to a capped rebar situated at the POINT OF BEGINNING of the herein described tract; thence continue North 89 degrees 57 minutes 35 seconds East for 567.84 feet to a capped rebar; thence South 00 degrees 03 minutes 14 seconds East for 345.00 feet to a capped rebar; thence North 89 degrees 57 minutes 35 seconds for 390.00 feet; thence South 00 degrees 03 minutes 14 seconds East for 704.02 feet to a capped rebar; thence South 89 degrees 57 minutes 35 seconds West for 959.67 feet to a capped rebar; thence North 00 degrees 02 minutes 45 seconds East for 1049.02 feet back to the point of beginning. Said tract is subject to any existing easements and rights of way. All capped rebars are 1/2” capped rebars stamped (MST CA-0334-LS).

 

EXHIBIT 4
PIPELINE TERMINATION VALUE
 	 	 	 	 	
YEAR OF	 	 	
TERMINATION OF	 	 	
CONSTRUCTION AND	 	 	
TRANSPORTATION	 	TERMINATION VALUE DECATUR ENERGY	
AGREEMENT	 	CENTER	
1	 	$	33,500,000	 	
2	 	$	32,755,556	 	
3	 	$	32,011,111	 	
4	 	$	31,266,667	 	
5	 	$	30,522,222	 	
6	 	$	29,777,778	 	
7	 	$	29,033,333	 	
8	 	$	28,288,889	 	
9	 	$	27,544,444	 	
10	 	$	26,800,000	 	
11	 	$	26,055,556	 	
12	 	$	25,311,111	 	
13	 	$	24,566,667	 	
14	 	$	23,822,222	 	
15	 	$	23,077,778	 	
16	 	$	22,333,333	 	
17	 	$	21,588,889	 	
18	 	$	20,844,444	 	
19	 	$	20,100,000	 	
20	 	$	19,355,556	 	
21	 	$	18,611,111	 	
22	 	$	17,866,667	 	
23	 	$	17,122,222	 	
24	 	$	16,377,778	 	
25	 	$	15,633,333	 	
26	 	$	14,888,889	 	
27	 	$	14,144,444	 	
28	 	$	13,400,000	 	
29	 	$	12,655,556	 	
30	 	$	11,911,111	 	
31	 	$	11,166,667	 	
32	 	$	10,422,222	 	
33	 	$	9,677,778	 	
34	 	$	8,933,333	 	
35	 	$	8,188,889	 	
36	 	$	7,444,444	 	
37	 	$	6,700,000	 	
38	 	$	5,955,556	 	
39	 	$	5,211,111	 	
40	 	$	4,466,667	 	
41	 	$	3,722,222	 	
42	 	$	2,977,778	 	
43	 	$	2,233,333	 	
44	 	$	1,488,889	 	
45	 	$	744,444	 	
Year 1 begins on the “First Delivery Date” and ends 364 days later (365 days if February of that year contains 29 days).
Year 2, (and/or subsequent years(s)) begin on the ending date of year 1 (and/or subsequent years(s)) and ends 364 days later (365 days later if February of that year contains 29 days).

 

EXHIBIT 5
GUARANTY
          This GUARANTY dated as of June 28, 2000, is made by Enbridge ( U.S. ), Inc. (“Enbridge”), a                 corporation for the benefit of Calpine Energy Services, L.P. ( “CES” )
           WHEREAS, BAMAGAS Company (“BAMAGAS”), a Delaware corporation, and CES , a Delaware limited partnership, have entered into that certain “Natural Gas Pipeline Construction and Transportation Agreement” dated as of June 28, 2000, and that certain Natural Gas Pipeline Transportation Agreement of even date (collectively “Agreements”);
           WHEREAS, pursuant to Section 18.1 of the Agreements, BAMAGAS agreed to furnish CES an absolute, unconditional guaranty from Enbridge to CES of BAMAGAS’ payment obligations to CES under the Agreement;
          NOW, THEREFORE, in consideration of the foregoing and for good and sufficient consideration in hand received by Enbridge, Enbridge agrees as follows:
          1. Guaranty . Enbridge irrevocably and unconditionally guarantees to CES the prompt and complete payment when due, by acceleration or otherwise of all amounts payable or becoming payable by BAMAGAS to CES and the payment of all present and future liabilities of all kinds of BAMAGAS to CES under or pursuant to the Agreements, including, without limitation, damages suffered by CES by reason of BAMAGAS’ breach of any of its representations, warranties, indemnities, covenants and other obligations to CES under the Agreement and any amendments thereto (collectively the “Obligations”) . This is a guaranty of payment and not of collection. If BAMAGAS fails to pay or perform any of the Obligations, for any reason, Enbridge will pay or cause to be paid such Obligations directly for CES’ benefit promptly upon CES’ demand therefor and without CES having to make prior demand on BAMAGAS. This Guaranty is a primary obligation of Enbridge and all payments hereunder shall be made without reduction, whether by offset, payment in escrow, or otherwise, except to the extent of any defenses to payment or performance which BAMAGAS may have under the Agreement. Notwithstanding anything to the contrary herein, this Guaranty shall continue to be effective or reinstated, as the case may be, if at any time payment of the Obligations, or any part thereof, is rescinded or must otherwise be returned by CES upon the insolvency, bankruptcy or reorganization of BAMAGAS or otherwise, all as though the payment of such Obligations had not been made.
          2. Enbridge’s Obligations . Subject to paragraph 3 below, Enbridge’s obligations under this Guaranty are absolute and unconditional, shall remain in force until all Obligations have been paid and performed and shall not be released or discharged for any reason whatsoever prior to such payment and performance, including without limitation:
(i) the extension of time for payment or performance of any Obligation or the amendment, extension or renewal of the Agreements or any Obligation, except that any such extension, amendment or renewal shall not enlarge Enbridge’s obligations under this Guaranty and Enbridge shall have the benefit of any such extension, amendment or renewal to the same extent as BAMAGAS (e.g., if BAMAGAS’ time for payment of an Obligation has been extended, Enbridge shall have no obligation under this Guaranty to make payment of such Obligation until such time as BAMAGAS is required under the extension to make payment);
(ii) any delay or failure by CES to enforce or exercise any right or remedy under the Agreement, or waiver by CES of any such right or remedy;
(iii) the release or discharge of BAMAGAS from the performance or observance of any Obligations by operation of law or otherwise, but only if and to the extent BAMAGAS would otherwise have incurred such Obligations in the absence of such release or discharge;
(iv) any transfer, assignment or mortgaging by CES of any interest in the Agreements or this Guaranty;

 

(v) the voluntary or involuntary liquidation, dissolution, sale or other disposition of all or substantially all the assets and liabilities, or the voluntary or involuntary receivership, insolvency, bankruptcy, assignment for the benefit of creditors, reorganization or other similar proceeding affecting BAMAGAS, or the disaffirmance of the Agreements in any such proceeding; or
(vi) any merger, consolidation or other reorganization to which BAMAGAS, Enbridge or any related entity is a party, or any direct or indirect sale or disposition of Enbridge’s or Enbridge’s assets or Enbridge’s direct or indirect ownership interest in CES .
          Furthermore, Enbridge’s obligations under this Guaranty to CES shall not be limited or impaired in any respect by reason of CES having recourse only to certain assets of BAMAGAS in connection with BAMAGAS’ obligations to CES under the Agreement.
          3. Assignment . Enbridge may not assign this Guaranty or its obligations thereunder except as expressly provided in Section 13.1 of the Agreements.
          4. Waivers by Enbridge . Enbridge waives notice of the acceptance of this Guaranty, demand or presentment for payment to BAMAGAS or the making of any protest, notice of the amount of the Obligations outstanding at any time, notice of nonpayment or failure to perform on the part of BAMAGAS, notice of any amendment, modification or waiver of or under the Agreements, and all other notices or demands not specifically required hereunder.
          5. Representations and Warranties . Enbridge hereby represents and warrants that (i) it has all necessary and appropriate powers and authority to execute and perform under this Guaranty (ii) that such Guaranty constitutes its legal, valid and binding obligations enforceable against it in accordance with its terms (except as enforceability may be limited by bankruptcy, insolvency, moratorium and other similar laws affecting enforcement of creditors’ rights in general and general principles of equity), and (iii) it expects to derive benefits from each and every extension of credit to BAMAGAS.
          6. Miscellaneous . No provision of this Guaranty may be amended or waived except by a written instrument executed by Enbridge and CES. This Guaranty shall not be deemed to benefit any person except BAMAGAS and CES . This Guaranty shall inure to the benefit of CES and its successors and assigns. This Guaranty shall be governed by the laws of the State of Texas (excluding any choice of laws rules which would require the application of the law of another jurisdiction).
          7. Attorneys’ Fees . Enbridge agrees to pay all attorneys’ fees, court costs and other expenses of collection paid or incurred by CES in enforcing Enbridge’s obligations to CES under this Agreement.
          IN WITNESS WHEREOF, Enbridge has executed this Guaranty as of the date first above written.

ENBRIDGE (U.S.), INC.	 	 	
 	 	 	 	 	
By:	 	 	 	 	
 	 	 	 	 	
Name:	 	 	 	 	
 	 	 	 	 	
Title:	 	 	 	 	
 	 	 	 	 	
Date:	 	 	 	 	

 

EXHIBIT 6
GUARANTY
          This GUARANTY dated as of June 28, 2000, is made by Calpine Corporation (“Calpine”), a Delaware corporation for the benefit of BAMAGAS Company (“BAMAGAS”).
           WHEREAS, BAMAGAS, a Delaware corporation, and Calpine Energy Services, L.P. ( “CES” ), a Delaware limited partnership, have entered into that certain “Natural Gas Pipeline Transportation Agreement” dated as of June 28, 2000, and that certain Natural Gas Pipeline Construction and Transportation Agreement of even date (collectively “Agreements”);
           WHEREAS, pursuant to Section 18.1 of the Agreements, CES agreed to furnish BAMAGAS an absolute, unconditional guaranty from Calpine to BAMAGAS of CES’ payment obligations to BAMAGAS under the Agreement;
          NOW, THEREFORE, in consideration of the foregoing and for good and sufficient consideration in hand received by Calpine, Calpine agrees as follows:
          1. Guaranty . Calpine irrevocably and unconditionally guarantees to BAMAGAS the prompt and complete payment when due, by acceleration or otherwise, of all amounts payable or becoming payable by CES to BAMAGAS and the payment of all present and future liabilities of all kinds of CES to BAMAGAS under or pursuant to the Agreement, including, without limitation, damages suffered by BAMAGAS by reason of CES’ breach of any of its representations, warranties, indemnities, covenants and other obligations to BAMAGAS under the Agreement and any amendments thereto (collectively the “Obligations”) . This is a guaranty of payment and not of collection. If CES fails to pay or perform any of the Obligations, for any reason, Calpine will pay or cause to be paid such Obligations directly for BAMAGAS’ benefit promptly upon BAMAGAS’ demand therefor and without BAMAGAS having to make prior demand on CES . This Guaranty is a primary obligation of Calpine and all payments hereunder shall be made without reduction, whether by offset, payment in escrow, or otherwise, except to the extent of any defenses to payment or performance which CES may have under the Agreement. Notwithstanding anything to the contrary herein, this Guaranty shall continue to be effective or reinstated, as the case may be, if at any time payment of the Obligations, or any part thereof, is rescinded or must otherwise be returned by BAMAGAS upon the insolvency, bankruptcy or reorganization of CES or otherwise, all as though the payment of such Obligations had not been made.
          2. Calpine’s Obligations . Subject to paragraph 3 below, Calpine’s obligations under this Guaranty are absolute and unconditional, shall remain in force until all Obligations have been paid and performed and shall not be released or discharged for any reason whatsoever prior to such payment and performance, including without limitation:
(i) the extension of time for payment or performance of any Obligation or the amendment, extension or renewal of the Agreements or any Obligation, except that any such extension, amendment or renewal shall not enlarge Calpine’s obligations under this Guaranty and Calpine shall have the benefit of any such extension, amendment or renewal to the same extent as CES (e.g., if CES’ time for payment of an Obligation has been extended, Calpine shall have no obligation under this Guaranty to make payment of such Obligation until such time as CES is required under the extension to make payment);
(ii) any delay or failure by BAMAGAS to enforce or exercise any right or remedy under the Agreement, or waiver by BAMAGAS of any such right or remedy;
(iii) the release or discharge of CES from the performance or observance of any Obligations by operation of law or otherwise, but only if and to the extent CES would otherwise have incurred such Obligations in the absence of such release or discharge;
(iv) any transfer, assignment or mortgaging by BAMAGAS of any interest in the Agreements or this Guaranty;

 

(v) the voluntary or involuntary liquidation, dissolution, sale or other disposition of all or substantially all the assets and liabilities, or the voluntary or involuntary receivership, insolvency, bankruptcy, assignment for the benefit of creditors, reorganization or other similar proceeding affecting CES , or the disaffirmance of the Agreements in any such proceeding; or
(vi) any merger, consolidation or other reorganization to which CES, Calpine or any related entity is a party, or any direct or indirect sale or disposition of Calpine’s or CES’ assets or Calpine’s direct or indirect ownership interest in CES .
          Furthermore, Calpine’s obligations under this Guaranty to BAMAGAS shall not be limited or impaired in any respect by reason of BAMAGAS having recourse only to certain assets of CES in connection with CES’ obligations to BAMAGAS under the Agreement.
          3. Assignment . Calpine may not assign this Guaranty or its obligations thereunder except as expressly provided in Section 13.1 of the Agreements.
          4. Waivers by Calpine . Calpine waives notice of the acceptance of this Guaranty, demand or presentment for payment to CES or the making of any protest, notice of the amount of the Obligations outstanding at any time, notice of nonpayment or failure to perform on the part of CES , notice of any amendment, modification or waiver of or under the Agreement, and all other notices or demands not specifically required hereunder.
          5. Representations and Warranties . Calpine hereby represents and warrants that (i) it has all necessary and appropriate powers and authority to execute and perform under this Guaranty (ii) that such Guaranty constitutes its legal, valid and binding obligations enforceable against it in accordance with its terms (except as enforceability may be limited by bankruptcy, insolvency, moratorium and other similar laws affecting enforcement of creditors’ rights in general and general principles of equity), and (iii) it expects to derive benefits from each and every extension of credit to CES .
          6. Miscellaneous . No provision of this Guaranty may be amended or waived except by a written instrument executed by Calpine and BAMAGAS. This Guaranty shall not be deemed to benefit any person except CES and BAMAGAS. This Guaranty shall inure to the benefit of BAMAGAS and its successors and assigns. This Guaranty shall be governed by the laws of the State of Texas (excluding any choice of laws rules which would require the application of the law of another jurisdiction).
          7. Attorneys’ Fees . Calpine agrees to pay all attorneys’ fees, court costs and other expenses of collection paid or incurred by BAMAGAS in enforcing Calpine’s obligations to BAMAGAS under this Agreement.
          IN WITNESS WHEREOF, Calpine has executed this Guaranty as of the date first above written.

CALPINE CORPORATION	 	 	
 	 	 	 	 	
By:	 	 	 	 	
Name:	 	 	 	 	
Title:	 	 	 	 	
Date:	 	 	 	 	

 

EXHIBIT 7
PROPERTY RIGHTS ASSIGNABLE TO BAMAGAS
None. CES will supplement this Exhibit over the term of the Agreement upon acquisition or assignment of any property rights.

 

EXHIBIT 8
OPERATIONAL BALANCING AGREEMENT
BETWEEN
BAMAGAS COMPANY
AND
CALPINE ENERGY SERVICES, L.P.
          This Operational Balancing Agreement (this “Agreement”) is entered into as of the                      between BAMAGAS Company, a Delaware corporation (“BAMAGAS”), and Calpine Energy Services, L.P. a Delaware limited partnership (“CES”) (individually a “Party” or collectively “Parties”).
          WHEREAS, BAMAGAS, and CES entered into that certain Natural Gas Pipeline Construction and Transportation Agreement dated June 28, 2000 (“Construction and Transportation Agreement”), under which BAMAGAS will construct, own, operate and maintain a new intrastate pipeline and related facilities (whether existing or new) in the State of Alabama (“Pipeline”) and will transport on a firm basis on the Pipeline, certain quantities of natural gas (“Gas”) to the Decatur Energy Center (as said term is defined in the Construction and Transportation Agreement);
          WHEREAS, the Pipeline interconnects at the Interconnection Point(s) specified on Attachment 2 attached hereto;
          WHEREAS, pursuant to the Construction and Transportation Agreement, CES will cause Gas to be delivered to BAMAGAS at the Interconnection Point(s) for transportation and redelivery by BAMAGAS at the Decatur Energy Center;
          WHEREAS, from time to time, the quantities of Gas actually delivered to BAMAGAS at the Interconnection Point(s) will be either greater than or less than the quantities of Gas nominated, confirmed and scheduled by the Parties, resulting in inadvertent over — or underdeliveries of CES’ scheduled quantities;
          WHEREAS, the Parties desire to provide for the elimination of such over — and under — deliveries by adjusting deliveries and receipts of Gas at the Interconnection Point(s);
          NOW, THEREFORE the Parties agree that such over — or underdeliveries of Gas at the Interconnection Point(s) shall be eliminated in the following manner:
ARTICLE I
CORRECTION OF OPERATIONAL IMBALANCES

1.1	 	Operational Imbalance(s) — The Parties intend that the MMBtu of Gas actually delivered and received each day at each Interconnection Point will equal the confirmed scheduled nominations of the Parties to be delivered or received therefrom. Any variance between the actual physical flow of Gas at an Interconnection Point each day and the confirmed scheduled nominations of receipts and deliveries for that Interconnection Point for such day is an “Operational Imbalance”, which Operational Imbalance is the responsibility of the Parties to eliminate pursuant to this Agreement.	

 

1.2	 	Corrections During the Month — BAMAGAS shall provide to CES on a daily basis electronically or in writing the estimated daily metered Gas quantities, or actual daily metered Gas quantities, if applicable, for purposes of adjustments to determine the estimated or actual Operational Imbalance at each Interconnection Point, as applicable. BAMAGAS shall also make available to CES the monthly Operational Imbalance at each delivery or receipt meter. Subject to CES’ available capacity on the Pipeline (CES’ available capacity being the difference between actual deliveries for the account of CES and the Firm Transportation Quantity as said term is defined in the Natural Gas Pipeline Construction and Transportation Agreement), CES may correct the Operational Imbalance in kind by nominating make up Gas quantities on any day during the same month in which the Operational Imbalance occurs in accordance with BAMAGAS’ nomination deadline procedures.	
 		
1.3	 	Corrections in Subsequent Periods — The cumulative Operational Imbalance at each Interconnection Point each month will be determined and communicated by BAMAGAS to CES electronically or in writing as soon as possible, but no later than the first business day after the last day of each month. To the extent that BAMAGAS has the right to balance in kind pursuant to the respective operational balancing agreements it enters into with CES’ upstream suppliers or transporters, as identified on Exhibit 3 to the Natural Gas Pipeline Construction and Transportation Agreement (collectively, the “BAMAGAS Balancing Agreements”), CES shall have the right to balance in kind the cumulative Operational Imbalance(s) during the month subsequent to the month in which the Operational Imbalance(s) were created (“Subsequent Month”) by nominating additional Gas quantities in accordance with the procedures of the applicable BAMAGAS Balancing Agreements. To the extent BAMAGAS does not have the right to balance in kind under any of the BAMAGAS Balancing Agreements any or all of the cumulative Operational Imbalance at each Interconnection Point during any given month or, if BAMAGAS has such right but CES fails to correct the monthly Operational Imbalance on or before the last day of the Subsequent Month, then BAMAGAS shall be entitled to cash out the remaining Operational Imbalance quantities for the same price and on the same terms and provisions as provided in the applicable BAMAGAS Balancing Agreements; it being the express intent of the Parties that BAMAGAS shall at all times be kept whole by CES and CES with respect to any differences in the price or method of balancing Operational Imbalances at each Interconnection Point each month between this Agreement and the applicable BAMAGAS Balancing Agreement(s) then in effect. Measurement of Gas under this Agreement shall be made in accordance with the applicable provisions in the FERC Gas Tariffs of the interstate pipelines interconnecting with BAMAGAS at the respective Interconnection Point(s).	
 		
1.4	 	BAMAGAS shall endeavor to negotiate the terms and provisions of the BAMAGAS Balancing Agreements so that balancing may be had by BAMAGAS in kind during the month subsequent to the month in which the imbalances were created; however, if BAMAGAS is unable to negotiate such terms and provisions, but CES is able to do so, then BAMAGAS, at its election, may utilize those operation balancing agreement(s) of CES with CES’ upstream suppliers or transporters containing such provisions.	
 		
1.5	 	In the event that a capacity constraint occurs on BAMAGAS’ Pipeline which results in curtailment of Gas quantities at an Interconnection Point, BAMAGAS shall determine the reallocation of Gas quantities to shippers on the Pipeline in accordance with Section 2.8 of the Construction and Transportation Agreement.	

 

ARTICLE II
TERM

 	 	Duration of Agreement — This Agreement shall be effective from the date hereof and shall remain in effect until such time as the Natural Gas Pipeline Construction and Transportation Agreement between BAMAGAS and CES terminates.	
ARTICLE III
MISCELLANEOUS

3.1	 	Disputes - If a dispute arises as a result of the provisions of this Agreement, the Parties will enter into good faith negotiations to resolve the dispute and amend this Agreement, if appropriate. If the Parties are unable to resolve such problems as a result of such negotiations the dispute shall be submitted to arbitration in accordance with Article XVI of the Construction and Transportation Agreement.	
 		
3.2	 	Governing Bodies — This Agreement shall be subject to all applicable laws, Federal or State and to all applicable rules and regulations of any duly authorized Federal, State or other government agency having jurisdiction over the transactions described herein. The interpretation and performance of this Agreement shall be in accordance with and controlled by the laws of the State of Texas, without regard to principles of conflicts of law.	
 		
3.3	 	Waivers — No waiver by either Party of any one or more defaults by the other in the performance of this Agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character.	
 		
3.4	 	Notices — Any notice under this Agreement shall be in writing and mailed to the post office address of the party intended to receive the same, as follows:	
NOTICES:
BAMAGAS Company
1100 Louisiana, Suite 2900
Houston, Texas 77002
Attn: President
Tel.: (713) 650-8900
Fax: (713) 653-6711
Calpine Energy Services, L.P.
700 Louisiana, Suite 2700
Houston, Texas 77002
Attention: Jeff Rawls
Vice President — Producer Services
Tel.: (713) 830-8636
Fax: (713) 830-8712

 	 	With regard to operational matters, the Parties shall have the right to designate different personnel or locations to receive notices.	
 		
3.5	 	Conflicts — If there is any conflict or discrepancy between this Agreement and a BAMAGAS Balancing Agreement with regard to allocations at any Interconnection Point, the terms of the applicable BAMAGAS Balancing Agreement shall govern and control.	

 

The Parties’ signature below will evidence their agreement to this Operational Balancing Agreement.

 	 	BAMAGAS COMPANY	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	 	 	 	
 	 	 	 	 	 	 	
 	 	Title:	 	 	 	 	
 	 	 	 	 	 	 	
 	 	Date:	 	 	 	 	

 	 	CALPINE ENERGY SERVICES, L.P.	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	 	 	 	
 	 	 	 	 	 	 	
 	 	Title:	 	 	 	 	
 	 	 	 	 	 	 	
 	 	Date:	 	 	 	 	

 

ATTACHMENT 2
BAMAGAS COMPANY
AND
CALPINE ENERGY SERVICES, L.P.
Interconnection Point(s) between                                 and                                 .
Meter Name(s)

 

EXHIBIT 9
USE RESTRICTIONS
          The Pipeline and the BAMAGAS Lateral(s), including, without limitation, the rights-of-way and easements pertaining thereto, which may be acquired by CES, its successors or assigns, pursuant to the exercise of CES’ purchase rights under Section 13.2 of the Natural Gas Construction and Transportation Agreement to which this Exhibit 9 is attached and made a part thereof (the “Agreement”), shall be assigned and conveyed to CES, its successors or assigns, limited to the following uses (the “Use Restrictions”), and CES represents, warrants and covenants, on behalf of itself and its successors and assigns, to BAMAGAS, Enbridge (in consideration for Enbridge’s guaranty of the performance of BAMAGAS’ obligations to CES under this Agreement), and the Affiliates of both of them, that the Pipeline and the BAMAGAS Lateral(s), including, without limitation, the rights-of-way and easements pertaining thereto, shall not be utilized in violation of the Use Restrictions, to-wit: for the transportation of Gas to the Decatur Energy Center and to any other parties except for transportation to then existing shippers or Gas end users with which the Affiliated Transportation Parties have entered into either transportation service agreements on the Pipeline and/or the BAMAGAS Lateral(s) or Gas sales agreements utilizing transportation service, in whole or in part, on the Pipeline and/or the BAMAGAS Lateral(s), until such time as the transportation rights of the Affiliated Transportation Parties on the Pipeline and the BAMAGAS Lateral(s) expire, as set forth in Exhibit 11 of this Agreement. The foregoing notwithstanding, if (i) CES exercises its step in rights under Section 2.3 of the Agreement and completes construction of the Pipeline and the BAMAGAS Lateral(s), and/or (ii) BAMAGAS elects not to reimburse CES for the expenses incurred by CES in the exercise of its step in rights under Section 2.3 of the Agreement and elects not to complete the construction of the Pipeline and the BAMAGAS Lateral(s), and/or (iii) an Event of Default occurs under Section 12.1 (b) and CES, it successors or assigns exercise their purchase rights under Section 13.2 of the Agreement, and/or (iv) CES, its successors or assigns, exercise their right of first refusal under Section 13.2 of the Agreement, then in any such event CES, its successors or assigns, shall not be subject to any Use Restrictions and have the right to use the Pipeline, the BAMAGAS Lateral(s) and associated rights of way and easements for any purpose.
          The foregoing covenants of CES shall be deemed covenants running with the Pipeline and BAMAGAS Lateral(s), including, without limitation, the rights-of-way and easements pertaining thereto, and shall be binding upon each subsequent owner of the Pipeline and/or the BAMAGAS Lateral(s), or any interest therein. Any entity which shall succeed by purchase, merger or consolidation to CES, or CES’ rights under the Agreement, shall be bound by the foregoing representations, warranties and covenants of CES.

 

EXHIBIT 10
HYDRAULIC MODEL
Part I — Pipeline Flow Schematic for Decatur Energy Center (“DEC”) only.
Part II — Receipt and Delivery Pressures vs. Volume Trend Plot for DEC only.
Part III — Receipt and Delivery Pressures vs. Volume Trend Plot for DEC only.
Part IV — Receipt and Delivery Pressures vs. Volume Trend Plot for DEC only.
Part V — Receipt and Delivery Volumes and Timing for Part II, Part III, and Part IV.
Part VI — Pipeline Flow Schematic for DEC and Morgan Energy Center (“MEC”).
Part VII — Receipt and Delivery Pressures vs. Volumes Trend Plot for DEC and MEC.
Part VIII — Receipt and Delivery Pressures vs. Volume Trend Plot for DEC and MEC.
Part IX — Receipt and Delivery Pressures vs. Volume Trend Plot for DEC and MEC.
Part X — Receipt and Delivery Volumes and Timing for Part VI, Part VII, and Part VIII.
The model that was used is a transient gas network analysis package developed by LICENERGY, Inc. (LIC). This company is now a part of ENERGY SOLUTIONS INTERNATIONAL. This software is capable of performing two types of simulations — steady state and transient. The present version of the software is called Pipeline Studio Version 2.0, capable of running in Windows 95, 98, NT and also Windows 2000.

 

Tenn Barton Moub Max Fiovv Flow 138 MMSCFD Pres 675 psig- Mode Max Flow Flow 0 MMSCFD Pres 658.441 psig amoco Pres 550.363 psig Flow 0 MMSCFD Mode Max Flow I CV 1500 Dn Pres 671.838 psig — Up Pres 675 psig GasEq Coleibrook Len 5.6 miles Dia 19.25 in Eft 0.92 Pipe000l Len 8.6 miles Dia 19.25 in PipeUU04 Len 34.5 miles Dia 19.438 in Pipe0002 Pipe0003 Len 3.3 miles I Dia 19 25 in I Solilia Pres 540.843 psig Flow 138 MMSCFD Mode Max Flow COLEBROOK 20”: PIPELINE... 675 PSIG @ TGP — 500 PSIG SOLUTIA EFF .92 ROUGH FACTOR .0007	
Exhibit 11 - Part I
Pipeline Flow Schematic for Decatur Energy Center (“DEC”) Only.

 

RAMPA&S-PLUS-2: Pressure (TENN_BARTON) RAMPA&S-PLUS-2: Pressure (SOLITIA) RAMPA&S-PLUS-2: Flow (TENN_BARTON) RAMPA&S-PLUS-2: Flow (SOLITIA)	
Exhibit 11 - Part II
Receipt and Delivery Pressures vs. Volume Trend Plot for DEC    only.

 

Exhibit 11 - Part III
Receipt and Delivery Pressures vs. Volume Trend Plot for DEC    only.

 

RAMPA&S-2: Pressure (TENN_BARTON) RAMPA&S-PLUS-2. Pressure (SOLITIA) RAMPA&S-PLUS-2: Row (TENN_BARTON) RAMPA&S-PLUS-2 Flow (SOLITIA) i	
Exhibit 11 - Part IV
Receipt and Delivery Pressures vs. Volume Trend Plot for DEC    only.

 
EXHIBIT 11 - PART V
Decator Energy Center

COLEBROOK-675PSIG/500PSIG - 20" P/L

RECIEPT VOLUMES VS DELIVERY VOLUMES USED IN EXHIBIT 11 PART II. III. & IV
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	EXHIBIT 11 PART II	 	EXHIBIT 11 PART III	 	EXHIBIT 11 PART IV	
Device Type	 	Supply	 	Delivery	 	Supply	 	Delivery	 	Supply	 	Delivery	
Name	 	Tenn Barton	 	Solutia	 	Tenn Barton	 	Solutia	 	Tenn Barton	 	Solutia	
Setpoint	 	Flow Maximum	 	Flow Maximum	 	Flow Maximum	 	Flow Maximum	 	Flow Maximum	 	Flow Maximum	
Units	 	MMCFD	 	MMCFD	 	MMCFD	 	MMCFD	 	MMCFD	 	MMCFD	
Initial Flow Hour	 	 	138	 	 	 	138	 	 	 	120	 	 	 	31	 	 	 	138	 	 	 	138	 	
1	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	0	 	
2	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	0	 	
3	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	0	 	
4	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	0	 	
5	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	0	 	
6	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	0	 	
7	 	 	138	 	 	 	138	 	 	 	75	 	 	 	100	 	 	 	138	 	 	 	138	 	
8	 	 	138	 	 	 	133	 	 	 	110	 	 	 	124	 	 	 	138	 	 	 	138	 	
9	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
10	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
11	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
12	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
13	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
14	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
15	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
16	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
17	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
18	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
19	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
20	 	 	138	 	 	 	138	 	 	 	88	 	 	 	100	 	 	 	138	 	 	 	138	 	
21	 	 	138	 	 	 	138	 	 	 	60	 	 	 	75	 	 	 	138	 	 	 	138	 	
22	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
23	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
24	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
25	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
26	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
27	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
28	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
29	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
30	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
31	 	 	138	 	 	 	138	 	 	 	75	 	 	 	100	 	 	 	138	 	 	 	138	 	
32	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
33	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
34	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
35	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
36	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
37	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	0	 	
38	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	0	 	
39	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	0	 	
40	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	0	 	
41	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	0	 	
42	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	0	 	
43	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	0	 	
44	 	 	138	 	 	 	138	 	 	 	88	 	 	 	100	 	 	 	138	 	 	 	0	 	
45	 	 	138	 	 	 	138	 	 	 	80	 	 	 	75	 	 	 	138	 	 	 	138	 	
46	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
47	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
48	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
49	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
50	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
51	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
52	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
53	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
54	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
55	 	 	138	 	 	 	138	 	 	 	75	 	 	 	100	 	 	 	138	 	 	 	138	 	
56	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
57	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
58	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	133	 	 	 	138	 	
59	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
60	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	

 

Tenn Barton Made Max Flow Flow 276 MMSCFD Pres G7G pbry TET Mode Max Flow Flow 0 MMSCFD Pres 648.54 psig Amoco Pres 535 435 psig Flow 0 MMSCFD Mode Max Flow CV 1500 Do Pies 662.174 psig Up Pres 675 psig GasEq Colsbrook Lan 5.6 miles Dia25.l26in EIT0.92 PipeOOO1 Pipe0004 Pipe0002 Pipe0003 Len 8.6 miles Len 34.5 miles Len 3.3 miles Dia 25.12 in Dia 25.25 in Dia 25.126 In Solllia Pres 525.592 psig Flow 276 MMSCFD Mode Max Flow COLEBROOK 26”: PIPELINE... 675 PSIG @ TOP — 500 PSIG SOLUTIA EFF .92 ROUGH FACTOR .0007	
Exhibit 11 - Part VI
Pipeline Flow Schematic for DEC and MEC

 

RAWPA&S-PLUS-2: Pressure (TENN_BARTON) RAMPMS-PLUS-Z Presstre fSOLITIA) RAMPA8.S-PLUS-2: Flow (TENN_BARTON) RAMPA&S-PLUS-2- riow (SOI ITIA)	
Part VII
Receipt and Delivery Pressures vs. Volumes Trend Plot for DEC and MEC

 

Exhibit 11 - Part VIII
Receipt and Delivery Pressures vs. Volume Trend Plot for DEC and MEC

 

Exhibit 11 - Part IX
Receipt and Delivery Pressures vs. Volume Trend Plot for DEC and MEC

 
EXHIBIT 11 - PART X
Decatur Energy Center & Morgan ENERGY Center
COLEBROOK-675PSIG/500PSIG - 26" P/L
RECIEPT VOLUMES VS DELIVERY VOLUMES USED IN EXHIBIT 11 PART VII. VIII. & IX
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	EXHIBIT 11 PART VII	 	 	EXHIBIT 11 PART VIII	 	 	EXHIBIT 11 PART IX	 	 	 	 	
Device Type	 	Supply	 	 	Delivery	 	 	Supply	 	 	Delivery	 	 	Supply	 	 	Delivery	 	 	Delivery	 	
Name	 	Tenn Barton	 	 	Solutia	 	 	Tann Barton	 	 	Solutia	 	 	Tann Barton	 	 	Solutia	 	 	Amoco	 	
Setpoint	 	Flow Maximum	 	 	Flow Maximum	 	 	Flow Maximum	 	 	Flow Maximum	 	 	Flow Maximum	 	 	Flow Maximum	 	 	Flow Maximum	 	
Units	 	MMCFD	 	 	MMCFD	 	 	MMCFD	 	 	MMCFD	 	 	MMCFD	 	 	MMCFD	 	 	MMCFD	 	
Initial Flow Hour	 	 	276	 	 	 	276	 	 	 	240	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
1	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	0	 	 	 	0	 	
2	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	0	 	 	 	0	 	
3	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	0	 	 	 	0	 	
4	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	0	 	 	 	0	 	
5	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	0	 	 	 	0	 	
6	 	 	276	 	 	 	276	 	 	 	90	 	 	 	92	 	 	 	278	 	 	 	0	 	 	 	0	 	
7	 	 	276	 	 	 	276	 	 	 	236	 	 	 	200	 	 	 	278	 	 	 	140	 	 	 	138	 	
8	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
9	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
10	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
11	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
12	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
16	 	 	276	 	 	 	276	 	 	 	226	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
14	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
15	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
13	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
17	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
18	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
19	 	 	276	 	 	 	276	 	 	 	236	 	 	 	243	 	 	 	278	 	 	 	140	 	 	 	138	 	
20	 	 	276	 	 	 	276	 	 	 	175	 	 	 	200	 	 	 	278	 	 	 	140	 	 	 	138	 	
21	 	 	276	 	 	 	276	 	 	 	160	 	 	 	160	 	 	 	278	 	 	 	140	 	 	 	138	 	
22	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
23	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
24	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
25	 	 	276	 	 	 	276	 	 	 	30	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
26	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
27	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
28	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
29	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
30	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
31	 	 	276	 	 	 	276	 	 	 	200	 	 	 	200	 	 	 	278	 	 	 	140	 	 	 	138	 	
32	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
33	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
34	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
35	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
36	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
37	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	0	 	 	 	0	 	
38	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	0	 	 	 	0	 	
39	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	0	 	 	 	0	 	
40	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	0	 	 	 	0	 	
41	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	0	 	 	 	0	 	
42	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	0	 	 	 	0	 	
43	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	0	 	 	 	0	 	
44	 	 	276	 	 	 	276	 	 	 	175	 	 	 	200	 	 	 	278	 	 	 	0	 	 	 	0	 	
45	 	 	276	 	 	 	276	 	 	 	150	 	 	 	150	 	 	 	278	 	 	 	140	 	 	 	138	 	
46	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
47	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
48	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
49	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
50	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
51	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
52	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
53	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
54	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
55	 	 	276	 	 	 	276	 	 	 	236	 	 	 	200	 	 	 	278	 	 	 	140	 	 	 	138	 	
56	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
57	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
58	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
59	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
60	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	

 

EXHIBIT 11
TRANSPORTATION RIGHTS
          Following any acquisition of the Pipeline and/or the BAMAGAS Lateral(s) by CES, its successors or assigns, pursuant to any of the provisions of the Natural Gas Pipeline Construction and Transportation Agreement to which this Exhibit 11 is attached and made a part thereof, BAMAGAS and the marketing Affiliates of both BAMAGAS and Enbridge (collectively, the “Affiliated Transportation Parties”) shall have the right to transport on the Pipeline and the BAMAGAS Lateral(s), on a firm basis as to all pipeline capacity in excess of the Firm Transportation Quantity, Gas quantities under transportation agreements then in effect between (i) BAMAGAS and any of the other Affiliated Transportation Parties, (ii) BAMAGAS and any third parties, and (iii) any of the Affiliated Transportation Parties and any third parties, for and during the term of each such agreement, not to exceed, however, the lesser of a period of ten (10) years from the date of acquisition of the Pipeline and the BAMAGAS Lateral(s) by CES or a period of five (5) years following the expiration of the Initial Term, if acquired during the Initial Term, or a period of five (5) years from the date of acquisition of the Pipeline and the BAMAGAS Lateral(s) by CES, if acquired during any Renewal Term. BAMAGAS, its successors and assigns, shall pay CES, its successors and assigns, for such transportation a prorata percentage of the operation and maintenance expenses related to the operation of the Pipeline and the BAMAGAS Lateral(s) based upon the annual Gas throughput of the Affiliated Transportation Parties as compared to the total annual Gas throughput of all parties shipping on the Pipeline and the BAMAGAS Lateral(s).

Exhibit 10.17
FIRST AMENDMENT
to
NATURAL GAS PIPELINE CONSTRUCTION
AND TRANSPORTATION AGREEMENT
Dated as of June 28, 2000
between
BAMAGAS COMPANY
and
CALPINE ENERGY SERVICES, L.P.
     This FIRST AMENDMENT to the NATURAL GAS PIPELINE CONSTRUCTION AND TRANSPORTATION AGREEMENT (“Amendment”) is entered into on this 1st day of September, 2001, between BAMAGAS Company and Calpine Energy Services, L.P. (collectively the “Parties” and/or individually a “Party”).
     WHEREAS, the Parties desire to modify the Natural Gas Pipeline Construction and Transportation Agreement dated as of June 28, 2000, between BAMAGAS Company and Calpine Energy Services, L.P. (“Agreement”);
     NOW, THEREFORE, in consideration of the premises and the mutual covenants and promises herein contained, the Parties agree as follows:
1. The definition of “Morgan Energy Center Transportation Agreement” in Article I of the Agreement is hereby added as follows:
“Morgan Energy Center Transportation Agreement” shall mean that certain Natural Gas Pipeline Transportation Agreement, between BAMAGAS Company and Calpine Energy Services, L.P. dated as of June 28, 2000.
2. The definition of “ROW” in Article I of the Agreement is hereby deleted and replaced with the following definition:
“ROW” shall mean all rights-of-way, land use rights, sites and easements acquired and/or utilized by BAMAGAS for the purpose of the Pipeline and the BAMAGAS Lateral(s) and their interconnections with (a) the Primary Point(s) of Delivery and (b) the Primary Point(s) of Delivery (as identified in the Morgan Energy Center Transportation Agreement).
3. The definition of “Pipeline” in Article I of the Agreement is hereby deleted and replaced with the following definition:
 1 of 3 

 

“Pipeline” shall mean a contiguous, new pipeline and related facilities (whether existing or new) for the transmission of Natural Gas, including all of the necessary pipe, fittings, valves, measuring equipment and regulators to be constructed or acquired, owned and operated by BAMAGAS beginning at Tennessee Gas Pipeline Company’s 500 leg near Barton in Colbert County, Alabama, and ending at: (a) the Primary Point(s) of Delivery as described in Exhibit 3 and (b) the Primary Point(s) of Delivery (as identified in the Morgan Energy Center Transportation Agreement), including the pipeline interconnections between Tennessee Gas Pipeline Company and BAMAGAS, Texas Eastern Transmission Company and BAMAGAS, and Midcoast Interstate Transmission Company and BAMAGAS, respectively.
4. The definition of “Point(s) of Delivery” in Exhibit 3 of the Agreement is hereby deleted and replaced with the following definition:
“Point(s) of Delivery” shall mean the proposed interconnection between the BAMAGAS Pipeline and the upstream side of the most easterly 16” valve located inside the gas metering station located in the southeast quarter of the southeast quarter of Section 11, Township 5 South Range 5 West, Morgan County, Alabama, and/or the Secondary Point(s) of Delivery.
5. The definition of “Primary Point(s) of Delivery” in Article I of the Agreement is hereby deleted and replaced with the following definition:
“Primary Point(s) of Delivery” shall mean the point of interconnection between the BAMAGAS Pipeline and the upstream side of the most easterly 16” valve located inside the gas metering station located in the southeast quarter of the southeast quarter of Section 11, Township 5 South Range 5 West, Morgan County, Alabama.
6. The definition of “BAMAGAS Lateral(s)” in Article I of the Agreement is hereby deleted and replaced with the following definition:
“BAMAGAS Lateral(s)” shall mean the non FERC jurisdictional pipeline(s) to be constructed by BAMAGAS for the purpose of transporting Natural Gas from the pipeline facilities of Midcoast Interstate Transmission Company to (a) the Primary Point(s) of Delivery and (b) the Primary Point(s) of Delivery (as defined in the Morgan Energy Center Transportation Agreement), which pipeline(s) shall be used for the testing of the Decatur Energy Center and for Gas transportation service during time periods that the Pipeline is unavailable to transport the Firm Transportation Quantity as provided for herein.
7. Except as provided in numbered paragraphs 1 - 6 above, there are no other changes to the Agreement under which this Amendment is issued and the Agreement remains in full force and effect. To the extent of any inconsistency between this Amendment and the Agreement, the Agreement shall govern, except to the extent explicitly modified by this Amendment.
 2 of 3 

 

     IN WITNESS WHEREOF, the Parties have caused this Amendment to be executed in their respective names by duly authorized officers in duplicate originals on the day and year first entered above.

CALPINE ENERGY SERVICES, L.P.	 	BAMAGAS COMPANY	
 	 	 	 	 	 	 	 	 	 	 	
By:	 	/s/ Diana Knox 	 	 	 	By:	 	/s/ I.J. Berthelot 	 	 	
 	 	 	 	 	 	 	 	 	 	 	
Name: Diana Knox	 	 	 	Name: I.J. “Chip” Berthelot	 	 	
 	 	 	 	 	 	 	 	 	 	 	
Title:   Sr. Vice President	 	 	 	Title:   Vice President Commercial Activity	 	 	
 3 of 3 

Exhibit 10.18
NATURAL GAS PIPELINE
TRANSPORTATION AGREEMENT
BETWEEN
BAMAGAS COMPANY
AND
CALPINE ENERGY SERVICES, L.P.

 

TABLE OF CONTENTS

ARTICLE I DEFINITIONS	 	 	1	 	
 	 	 	 	 	
ARTICLE II CONSTRUCTION AND OPERATION OF PIPELINE; TRANSPORTATION AND DELIVERIES	 	 	5	 	
 	 	 	 	 	
Section 2.1 Development of Pipeline	 	 	5	 	
Section 2.2 Construction of Pipeline	 	 	5	 	
Section 2.3 Milestone Schedule	 	 	5	 	
Section 2.4 Notice to Proceed	 	 	5	 	
Section 2.5 BAMAGAS Lateral(s)	 	 	5	 	
Section 2.6 Operation of Pipeline	 	 	6	 	
Section 2.7 Transportation and Delivery	 	 	6	 	
Section 2.8 Curtailment	 	 	6	 	
Section 2.9 Scheduling Gas Flow	 	 	7	 	
Section 2.10 Imbalance Charges	 	 	7	 	
Section 2.11 Gas Delivery Rates	 	 	7	 	
 	 	 	 	 	
ARTICLE III TERM OF AGREEMENT	 	 	8	 	
 	 	 	 	 	
ARTICLE IV QUALITY AND PRESSURE	 	 	8	 	
 	 	 	 	 	
Section 4.1 Quality	 	 	8	 	
Section 4.2 Pressure	 	 	8	 	
 	 	 	 	 	
ARTICLE V MEASUREMENTS AND MEASURING EQUIPMENT	 	 	9	 	
 	 	 	 	 	
Section 5.1 Transportation Units	 	 	9	 	
Section 5.2 Measuring Station	 	 	9	 	
 	 	 	 	 	
ARTICLE VI CHARGES TO BE PAID BY DEC	 	 	10	 	
 	 	 	 	 	
Section 6.1 Transportation Charges	 	 	10	 	
Section 6.2 Taxes	 	 	11	 	
Section 6.3 Other Charges	 	 	11	 	
Section 6.4 Price Reduction	 	 	11	 	
 	 	 	 	 	
ARTICLE VII BILLING AND PAYMENTS	 	 	12	 	
 	 	 	 	 	
Section 7.1 Billing Dates	 	 	12	 	
Section 7.2 Payment Date	 	 	12	 	
Section 7.3 Right of Examination	 	 	12	 	
Section 7.4 Adjustment of Errors in Billing	 	 	12	 	
Section 7.5 Interest on Past Due Payments	 	 	12	 	
 	 	 	 	 	
ARTICLE VIII POSSESSION OF NATURAL GAS	 	 	12	 	
 	 	 	 	 	
ARTICLE IX REPRESENTATIONS AND WARRANTIES AND COVENANTS	 	 	13	 	
 	 	 	 	 	
Section 9.1 Warranty of Title	 	 	13	 	
Section 9.2 Warranty Regarding Intrastate Pipeline	 	 	13	 	
Section 9.3 Corporate Representations and Warranties	 	 	13	 	
Section 9.4 BAMAGAS Covenants	 	 	14	 	
 ii 

 

 	 	 	 	 	
		
ARTICLE X INDEMNIFICATION	 	 	14	 	
 	 	 	 	 	
Section 10.1 BAMAGAS Indemnity	 	 	14	 	
Section 10.2 CES Indemnity	 	 	15	 	
Section 10.3 Scope	 	 	15	 	
Section 10.4 Notice and Opportunity to Defend	 	 	15	 	
 	 	 	 	 	
ARTICLE XI FORCE MAJEURE	 	 	15	 	
 	 	 	 	 	
Section 11.1 Force Majeure Defined	 	 	15	 	
Section 11.2 Effect of Force Majeure	 	 	16	 	
 	 	 	 	 	
ARTICLE XII EVENTS OF DEFAULT	 	 	16	 	
 	 	 	 	 	
Section 12.1 Definition	 	 	16	 	
Section 12.2 Right of Termination for Default	 	 	17	 	
Section 12.3 CES Purchase Rights	 	 	17	 	
Section 12.4 Remedies Not Exclusive	 	 	18	 	
Section 12.5 Limitation of Liability	 	 	18	 	
Section 12.6 Non-Recourse	 	 	18	 	
 	 	 	 	 	
ARTICLE XIII TRANSFER AND ASSIGNMENT	 	 	18	 	
 	 	 	 	 	
Section 13.1 Assignment	 	 	18	 	
Section 13.2 Right of First Refusal	 	 	19	 	
 	 	 	 	 	
ARTICLE XIV REGULATION	 	 	20	 	
 	 	 	 	 	
ARTICLE XV DECATUR ENERGY CENTER	 	 	20	 	
 	 	 	 	 	
ARTICLE XVI DISPUTE RESOLUTION; GOVERNING LAW	 	 	20	 	
 	 	 	 	 	
Section 16.1 Procedure	 	 	20	 	
Section 16.2 Initial Resolution Attempts	 	 	20	 	
Section 16.3 Arbitration	 	 	20	 	
Section 16.4 General Rules and Provisions	 	 	21	 	
Section 16.5 Governing Law	 	 	21	 	
 	 	 	 	 	
ARTICLE XVII NOTICES	 	 	21	 	
 	 	 	 	 	
Section 17.1 Writing	 	 	21	 	
Section 17.2 Timing of Receipt	 	 	22	 	
 	 	 	 	 	
ARTICLE XVIII MISCELLANEOUS	 	 	22	 	
 	 	 	 	 	
Section 18.1 Financial Responsibility	 	 	22	 	
Section 18.2 Captions	 	 	23	 	
Section 18.3 Non Disclosure	 	 	23	 	
Section 18.4 Press Release	 	 	23	 	
Section 18.5 Amendments	 	 	23	 	
Section 18.6 Severability	 	 	23	 	
Section 18.7 Entire Agreement	 	 	23	 	
Section 18.8 No Waiver	 	 	23	 	
Section 18.9 Further Assurances	 	 	24	 	
Section 18.10 Counterparts	 	 	24	 	
Section 18.11 Exhibits, Attachments and Schedules	 	 	24	 	
 iii 

 

EXHIBIT 1
MILESTONE SCHEDULE
EXHIBIT 2
GAS SPECIFICATIONS
EXHIBIT 3
POINTS OF DELIVERY/RECEIPT
EXHIBIT 4
PIPELINE TERMINNATION VALUE
EXHIBIT 5
MIDCOAST GUARANTEE
EXHIBIT 6
CES GUARANTY
EXHIBIT 7
PROPERTY RIGHTS ASSIGNABLE TO BAMAGAS
EXHIBIT 8
OPERATIONAL BALANCING AGREEMENT
EXHIBIT 9
USE RESTRICTIONS
EXHIBIT 10
HYDRAULIC MODEL
EXHIBIT 11
TRANSPORTATION RIGHTS
 iv 

 

NATURAL GAS PIPELINE TRANSPORTATION AGREEMENT
(MORGAN ENERGY CENTER)

     This Natural Gas Pipeline Transportation Agreement for the Morgan Energy Center (this “Agreement”) entered into effective as of the 28th day of June, 2000 (“Effective Date”) by and between BAMAGAS Company, a Delaware corporation (together with its successors and permitted assigns, “BAMAGAS”), and Calpine Energy Services, L.P. (“CES”), a Delaware limited partnership (together with its successors and permitted assigns, “CES”). BAMAGAS, CES may also be referred to herein individually as “Party” or jointly as “Parties.”

Recitals
     WHEREAS, Morgan Energy Center, LLC (together with its successors and permitted assigns, “MEC”) is constructing a power generation facility in Morgan County, Alabama (“Morgan Energy Center”, as more fully described below) and an affiliate of it, Decatur Energy Center, LLC, a Delaware limited liability company (together with its successors and permitted assigns, “DEC”), is constructing another power generation facility in Morgan County, Alabama (“Decatur Energy Center”); and
     WHEREAS, MEC and CES have agreed that CES will provide fuel management services for natural gas to be used at the Morgan Energy Center; and
     WHEREAS, contemporaneously with the execution of this Agreement by the Parties, BAMAGAS is entering into a Natural Gas Pipeline Construction and Transportation Agreement with CES to construct, own, operate and maintain a new intrastate pipeline and related facilities (whether existing or new) to be located wholly within the State of Alabama (the “Pipeline”, as more fully described below) to receive and transport on a firm basis natural gas; and
     WHEREAS, upon BAMAGAS construction of the Pipeline, BAMAGAS is willing to receive and transport on a firm basis natural gas for the Morgan Energy Center, and to make available Equivalent Quantities of natural gas at the Point(s) of Delivery and CES desires for BAMAGAS to do so;
     NOW, THEREFORE, in consideration of the premises and of the mutual agreements herein contained, the Parties hereto agree as follows:
ARTICLE I
DEFINITIONS
     Except where the context expressly states another meaning the following terms when used in this Agreement and in the Exhibits to this Agreement shall be construed to have the following meanings:
     “AAA” shall have the meaning set forth in Section 16.3.
     “Affiliate” shall mean any Person that directly or indirectly Controls or is Controlled by or is under common Control with, the Person in question. “Person” means an individual, partnership, limited partnership, corporation, limited liability company, association, trust, unincorporated organization, or a government authority or agency or political subdivision thereof. “Control” means the possession, directly or indirectly, through one or more intermediaries, of either of the following: (a) (i) in the case of a corporation, 50% or more of the outstanding voting securities thereof; (ii) in the case of a limited liability company, partnership, limited partnership or venture, the right to 50% or more of the distributions therefrom (including liquidating distributions); (iii) in the case of a trust or estate, 50% or more of the beneficial interest therein; or (iv) in the case of any other entity, 50% or more of the economic or beneficial interest therein; or (b) in the case of any entity, the power or authority, through the ownership of voting securities, by contract or otherwise, to direct the management, activities or policies of the entity.

 

     “Affiliated Transportation Parties” shall have the meaning set forth in Exhibit 11.
     “Agreement” shall have the meaning set forth in the opening paragraph.
     “Applicable Law” shall mean any federal, state, local or other constitution, charter, act, statute, law, ordinance, code, rule, regulation or order or other legislative or administrative action of the United States of America or the State of Alabama, or any agency, department, authority, political subdivision or other instrumentality or either of them, or a final decree, judgment or order of a court applicable to the Pipeline, the Lateral(s), the Morgan Energy Center, the Parties or this Agreement.
     “BAMAGAS” shall have the meaning set forth in the opening paragraph hereof.
     “BAMAGAS Activities” shall have the meaning set forth in Section 9.4(a).
     “BAMAGAS Group” shall have the meaning set forth in Section 10.3(b).
     “BAMAGAS Lateral(s)” shall mean the non FERC jurisdictional pipeline(s) to be constructed by BAMAGAS for the purpose of transporting Natural Gas from the pipeline facilities of Midcoast Interstate Transmission, Inc. to the Primary Point(s) of Delivery and the points of delivery specified under the Natural Gas Construction and Transportation Agreement for Decatur Energy Center, which pipeline(s) shall be used for the testing of the Morgan Energy Center and for Gas transportation service during time periods that the Pipeline is unavailable to transport the Firm Transportation Quantity as provided for herein.
     “Beneficial Rate(s)” shall have the meaning set forth in Section 6.4.
     “British Thermal Unit” or “Btu” shall mean the amount of heat required to raise the temperature of one (1) pound of water from fifty-nine (59) degrees Fahrenheit to sixty (60) degrees Fahrenheit at a constant pressure of 14.73 psia.
     “Business Day” shall mean any Day that is not a Saturday, Sunday or day on which banks are permitted or required to be closed in Houston, Texas.
     “Calpine” shall mean Calpine Corporation, a Delaware corporation, together with its successors and assigns.
     “Calpine Corporation Guaranty” shall mean the guaranty furnished by Calpine pursuant to Section 18.1.
     “Competing Use” shall have the meaning set forth in Section 6.4.
     “CCT” or “Central Clock Time” shall mean Central Standard Time except when Daylight Savings Time is in effect, when it shall mean one hour in advance of Central Standard Time.
     “CES” shall have the meaning set forth in the opening paragraph hereof.
     “Day” shall mean a period beginning at 9:00 a.m. CCT on one calendar day and ending at 9:00 a.m. CCT on the next succeeding calendar day. The date of a Day shall be that of its beginning.
     “DEC” shall have the meaning set forth in the first paragraph of the “Recitals” hereof.
     “Decatur Energy Center” shall mean a power generation facility to be constructed in Morgan County, Alabama by DEC.
     “Effective Date” shall have the meaning set forth in the opening paragraph.
     “Enbridge” shall mean Enbridge (U.S.) Inc.
 2 

 

     “Equivalent Quantity(ies)” shall mean a thermally equivalent quantity of Natural Gas (i.e., an equal number of MMBtu), as received by BAMAGAS at the Point(s) of Receipt less the quantity of Natural Gas lost and unaccounted for in the transmission of such Natural Gas. For purposes of determining the Equivalent Quantity: Natural Gas lost and unaccounted for after receipt by BAMAGAS shall not exceed 1.5%, in each case of the total quantity (in MMBtu) received by BAMAGAS at the Point(s) of Receipt in any given Month. BAMAGAS shall provide any quantities of Natural Gas lost and unaccounted for in excess of 1.5%, at no cost to CES, to ensure delivery of the Equivalent Quantity to CES at the Point(s) of Delivery.
     “Event of Default” shall mean any of the events or circumstances set forth in Section 12.1.
     “Excusable Events” shall have the meaning set forth in Section 2.8.
     “Existing Shippers” shall have the meaning set for in Section 6.4.
     “Extension Period” shall have the meaning set forth in Section 11.2.
     “Exercise Period” shall have the meaning set forth in Section 13.2.
     “Favorable Rate(s)” shall have the meaning set forth in Section 6.4.
     “FERC” shall have the meaning set forth in Section 9.2.
     “Firm” or “Firm Transportation” shall mean that the receipt, delivery and transportation of Natural Gas shall not be subject to interruption or curtailment, other than by reason of express written consent of CES, Force Majeure, Applicable Law or an Excusable Event, or as otherwise provided in this Agreement.
     “Firm Transportation Quantity” shall mean 138,000 MMBtu of Natural Gas per Day.
     “First Delivery Date” shall mean February 1, 2002.
     “Force Majeure” shall have the meaning set forth in Section 11.1.
     “Gas” or “Natural Gas” shall mean the effluent vapor stream in its natural state produced from wells, including all hydrocarbon and nonhydrocarbon constituents, if any, and including casinghead Gas produced with crude oil and residue Gas resulting from the processing of Gas well or casinghead Gas.
     “Governmental Approvals” shall mean all permits, licenses or other authorizations required to be obtained with respect to the construction, ownership and operation of the Pipeline and the BAMAGAS Lateral(s).
     “Governmental Authority” shall mean any federal, state or local governmental entity, authority or agency, court, tribunal, regulatory commission or other body, whether legislative, judicial or executive, having authority over this Agreement or the Parties hereto.
     “Hydraulic Model” shall mean the hydraulic simulation model described in Exhibit 10.
     “Imbalance(s)” shall mean the difference between scheduled and actual receipt quantities of Natural Gas at Point(s) of Receipt.
     “Indemnitee” shall have the meaning set forth in Section 10.4.
     “Indemnitor” shall have the meaning set forth in Section 10.4.
     “Initial Term” shall have the meaning set forth in Article III.
     “Initial Term Demand Charge” shall have the meaning set forth in Section 6.1.
 3 

 

     “Initial Term Transportation Rate” shall have the meaning set forth in Section 6.1.
     “MEC” shall have the meaning set forth in the first paragraph of the Recitals hereof.
     “MEC’s Lateral Supply Cost” shall have the meaning set forth in Section 4.1.
     “MEC’s Pipeline Supply Cost” shall have the meaning set forth in Section 4.1.
     “MIT Lateral” shall mean the existing lateral pipeline that ties into the Midcoast Interstate Transmission Company 8” and 12” systems that currently deliver Natural Gas directly into Amoco.
     “MMBtu” or ‘Dekatherm” or “dth” shall mean one million (1,000,000) Btu.
     “Month” shall mean a period beginning at 9:00 a.m. CCT on the first day of the calendar month and ending at 9:00 a.m. CCT on the first day of the next succeeding calendar month.
     “Morgan Energy Center” shall have the meaning set forth in the first paragraph of the “Recitals” hereof.
     “New Taxes” shall have the meaning set forth in Section 6.2.
     “Notice” shall have the meaning set forth in Section 12.2.
     “Notice Period” shall have the meaning set forth in Section 12.2.
     “Offer Notice” shall have the meaning set forth in Section 12.2.
     “Party” or “Parties” shall have the meaning set forth in the opening paragraph hereof.
     “Pipeline” shall mean a contiguous, new pipeline and related facilities (whether existing or new) for the transmission of Natural Gas, including all of the necessary pipe, fittings, valves, measuring equipment and regulators to be constructed or acquired, owned and operated by BAMAGAS beginning at Tennessee Gas Pipeline Company’s 500 leg near Barton in Colbert County, Alabama, and ending at the Primary Point(s) of Delivery as described in Exhibit 3, including the pipeline interconnections between Tennessee Gas Pipeline Company and BAMAGAS, Texas Eastern Transmission Company and BAMAGAS, and Midcoast Interstate Transmission Company and BAMAGAS, respectively.
     “Point(s) of Delivery” shall mean any or all of the Primary Point(s) of Delivery and Secondary Point(s) of Delivery.
     “Point(s) of Receipt” shall mean the point(s) of interconnection between the Pipeline and CES’ upstream suppliers or transporters, as identified on Exhibit 3, and such other point(s) of interconnection, if any, which BAMAGAS and CES shall mutually agree upon to be made between the Pipeline and other pipelines or which may be unilaterally added or deleted by CES provided that no additional facilities are required to be added by BAMAGAS to the Pipeline at BAMAGAS expense.
     “Pressure Variance” shall have the meaning set forth in Section 4.2.
     “Pressure Variance Event” shall have the meaning set forth in Section 4.2.
     “Primary Point(s) of Delivery” shall mean the point of interconnection between the Pipeline and/or the BAMAGAS Lateral(s) and the facilities, for delivery of Natural Gas to the Morgan Energy Center as identified on Exhibit 3.
     “Procurement Deadline” shall have the meaning set forth in Article XV.
 4 

 

     “Purchase Price” shall have the meaning set forth in Section 12.3.
     “Renewal Term” shall have the meaning set forth in Article III.
     “Renewal Term Demand Charge” shall have the meaning set forth in Section 6.1.
     “Renewal Term Transportation Rate” shall have the meaning set forth in Section 6.1.
     “ROW” shall mean all rights-of-way, land use rights, sites and easements acquired and/or utilized by BAMAGAS for the purpose of the Pipeline and the BAMAGAS Lateral(s) and their interconnections with Morgan Energy Center.
     “Secondary Point(s) of Delivery” shall mean the point(s) of interconnection between the Pipeline and the pipelines of CES’ upstream suppliers or transporters, as identified on Exhibit 3, and such other point(s) of interconnection, if any, which BAMAGAS and CES shall mutually agree upon to be made between the Pipeline and other interstate pipelines or which may be unilaterally added by CES for redelivery of Natural Gas to interstate pipelines provided that no additional facilities are required to be added by BAMAGAS to the Pipeline at BAMAGAS’ expense.
     “Second Owner” shall have the meaning set forth in Section 13.1.
     “Shipper Group” shall have the meaning set forth in Section 10.3.b.
     “Supply Notice” shall have the meaning set forth in Section 2.8.
     “Term” shall mean the Initial Term and any Renewal Term(s).
     “Termination Value” shall have the meaning set within Section 12.3.
     “Third Party Transportation Contract” shall have the meaning set forth in Section 6.4.
     “Third Party Offer” shall have the meaning set forth in Section 13.2.
     “Third Party Sales Contract” shall have the meaning set forth in Section 6.4.
     “Transportation Capacity” shall mean the design capacity of the Pipeline as determined in accordance with the Hydraulic Model.
     “Transportation Rights” shall have the meaning set forth in Section 12.3.
     “Unexcused Curtailment” shall have the meaning set forth in Section 12.1.c.
     “Use Restrictions” shall have the meaning set forth in Section 12.3.
ARTICLE II
TRANSPORTATION AND DELIVERIES
     2.1 OMITTED.
     2.2 OMITTED.
     2.3 OMITTED.
     2.4 OMITTED.
     2.5 OMITTED.
 5 

 

     2.6 Operation of Pipeline. During the Term hereof, BAMAGAS shall operate and maintain the Pipeline and the BAMAGAS Lateral(s) in a prudent manner and in accordance with all applicable Governmental Approvals. Except in cases when prior scheduling is not reasonable, any maintenance (including but not limited to repair and replacement) of the Pipeline and/or the BAMAGAS Lateral(s) that causes or is likely to cause curtailment of transportation on the Pipeline and/or the BAMAGAS Lateral(s) shall be conducted by BAMAGAS only after prior scheduling with CES.
     2.7 Transportation and Delivery. From the First Delivery Date until the end of the Term, BAMAGAS agrees: (a) on a Firm basis, to accept and receive collectively at the Point(s) of Receipt such quantities of Natural Gas as CES or its agent delivers or makes available for delivery into the Pipeline or the BAMAGAS Lateral(s) each Day up to an amount that will enable BAMAGAS to deliver the Equivalent Quantity of the Firm Transportation Quantity during each Day at the specified Point of Delivery and (b) on an interruptible basis, and subject to interruption, curtailment and available pipeline capacity, to accept and receive collectively at the Point(s) of Receipt such quantities of Natural Gas in excess of the Firm Transportation Quantity which CES or its agent delivers or makes available for delivery into the Pipeline or the BAMAGAS Lateral(s) each Day. BAMAGAS shall have the right to transport and deliver Equivalent Quantities of the Gas to the Point(s) of Delivery via the Pipeline, the BAMAGAS Lateral(s), the MIT Lateral or any other available pipeline, and if transported and delivered by any such means or any combination thereof, BAMAGAS shall be deemed to be in compliance with this Agreement. The Point of Delivery shall be a Primary Point of Delivery unless a Secondary Point of Delivery is specified by CES to BAMAGAS upon not less than one (1) hour prior notice to BAMAGAS. By written notice to BAMAGAS, CES shall have the right to add or delete Point(s) of Receipt and Secondary Point(s) of Delivery from time to time at no incremental cost to CES, subject to the availability of Firm Capacity and provided that the addition of a Point of Receipt (which may be located on an intrastate or interstate pipeline) or Secondary Point of Delivery (which shall be limited to interstate pipelines) does not require BAMAGAS to add any facilities to the Pipeline or the BAMAGAS Lateral(s) at BAMAGAS’ expense. Each such notice shall be deemed to amend Exhibit 3 of this Agreement. CES shall have the right to resell any or all of the quantities of Gas received by it at Point(s) of Delivery; provided, however (a) CES shall endeavor to purchase only those quantities of Gas necessary for internal uses at the Morgan Energy Center and (b) CES covenants and shall cause MEC not to resell any Gas transported on the Pipeline other than at the Secondary Point(s) of Delivery.
     2.8 Curtailment. All quantities of Natural Gas delivered by or for the account of CES to BAMAGAS at the Point(s) of Receipt each Day, up to the Firm Transportation Quantity, shall be transported and delivered each Day, by BAMAGAS to the Points of Delivery without curtailment or interruption, except for curtailments or interruptions by reason of the express consent of CES, Force Majeure, Applicable Law, or any of the following events: (i) failure on any Day by CES to deliver or cause to be delivered at the Point(s) of Receipt sufficient Gas quantities to enable BAMAGAS to redeliver Equivalent Quantities at the Point(s) of Delivery; (ii) failure by CES to transport and redeliver the Equivalent Quantities at a pressure sufficient for BAMAGAS to deliver the Gas quantities at the Point(s) of Delivery at a pressure of no less than 500 psig; (iii) failure by CES to deliver Gas quantities at the Point(s) of Receipt that meet the quality specifications set forth in Exhibit 2; and (iv) failure by CES to deliver Gas quantities at the Point(s) of Receipt at a rate of flow that will enable BAMAGAS to comply with the requirements of the Hydraulic Model for delivery of Gas at the Point(s) of Delivery. (The events described in the preceding sentence under (i), (ii), (iii) and (iv) shall be collectively referred to in this Agreement as “Excusable Events”). In the event a Force Majeure event or any other event other than an Excusable Event(s) causes BAMAGAS to curtail or interrupt transportation service on the Pipeline, BAMAGAS shall deliver, as directed by CES the Equivalent Quantity delivered by or for the account of CES into the Pipeline, up to the Firm Transportation Quantity, to the Point(s) of Delivery prior to making deliveries pursuant to BAMAGAS obligations under any other firm or interruptible transportation contracts with third parties and/or BAMAGAS and/or its affiliated companies transporting Natural Gas on the Pipeline. BAMAGAS warrants that it shall include in any transportation agreement it may enter into with its Affiliates and/or third parties a covenant that states that the transportation rights on the Pipeline and/or the BAMAGAS Lateral(s) shall be subject to interruption or curtailment prior to interruption or curtailment of all quantities up to the Firm Transportation Quantity for CES regardless of the level of service retained by such parties. BAMAGAS shall not enter into transportation contracts for itself or its Affiliates’ account and/or with any third parties that have as a matter of law or regulation, a right to a higher priority of service than CES other than with respect to quantities of Natural Gas that can be transported on the Pipeline in excess of the Firm Transportation Quantity, and shall not enter into transportation contracts for itself or its
 6 

 

Affiliates’ account and/or with any third parties for an equivalent priority of service, if the quantities of Gas under those contracts, in addition to the Firm Transportation Quantity hereunder, will exceed the Transportation Capacity of the Pipeline in accordance with the Hydraulic Model. In the event that BAMAGAS curtails or interrupts transportation service on the Pipeline due to reasons other than express written consent of CES, Force Majeure, Applicable Law or an Excusable Event, CES shall have the right to transport Gas on the BAMAGAS Lateral(s) at no cost to CES, provided that CES has made and continues to make all payments to BAMAGAS required under Article VI of this Agreement. If the cost to CES for the delivery of Gas supplies from its upstream transporters or suppliers to the BAMAGAS Lateral point(s) of receipt is greater than the cost CES would have incurred for the delivery of such Gas to the Pipeline Point(s) of Receipt, BAMAGAS shall pay CES such excess cost, if such curtailment or interruption is due to cause(s) other than express written consent of CES, Force Majeure, Applicable Law or an Excusable Event; provided however BAMAGAS or its designee shall have the right (but not the obligation) to provide alternate Gas supplies to CES (at CES’ cost) no later than thirty (30) minutes after notice by telephone from CES in connection with an event of curtailment (“Supply Notice”) at a cost equal to that which CES would otherwise pay to its upstream transporters or suppliers for delivery to the BAMAGAS Lateral(s) during all such periods. If, after receipt of the Supply Notice, BAMAGAS or its designee fails or declines to supply the Gas quantities curtailed or interrupted, CES has the right to enter into alternate supply agreements with third parties provided such agreements do not exceed a term of twenty-four (24) hours. BAMAGAS or its designee shall have a continuing right to provide Gas supplies to CES for the price hereinbefore specified during any period of continuation of such curtailment or interruption beyond such twenty-four (24) hour period and, to that end, BAMAGAS and CES shall fully cooperate with each other.
     2.9 Scheduling Gas Flow. At least two (2) Days prior to the beginning of each Month, CES shall furnish BAMAGAS with a schedule showing the estimated quantities of Natural Gas each Day during such Month it desires BAMAGAS to receive, transport and deliver during such Month to each Point of Delivery with the quantities specified for each of the Points of Receipt and each of the Points of Delivery. CES shall use reasonable efforts to inform BAMAGAS promptly and confirm in writing all changes in the quantity of Natural Gas, which it desires BAMAGAS to transport hereunder from the quantity of Natural Gas then being transported by BAMAGAS hereunder. All such schedules are provided by CES to BAMAGAS for planning purposes, and CES shall have the right to alter without prior notice the quantities to be furnished at a Point of Receipt or a Point of Delivery at any time, up to the Firm Transportation Quantity. Notwithstanding the immediately preceding sentence, CES shall use reasonable efforts to notify BAMAGAS by telephone or other timely means of any known or anticipated swings in previously scheduled quantities of Gas.
     2.10 Imbalance Charges. CES shall have the right but not the obligation to enter into balancing service agreements with upstream pipelines and suppliers as are necessary to provide for balancing of the quantities of Natural Gas received at the Point(s) of Receipt. All Imbalance charges and any other payments due in accordance with such agreements or otherwise for CES’ Gas shall be the responsibility of and shall be paid by CES unless an Imbalance is caused by BAMAGAS, in which case BAMAGAS shall be liable for any such Imbalance charges. BAMAGAS and CES shall endeavor to keep Imbalances to a minimum and shall make adjustments in receipts and deliveries as promptly as is consistent with their operating conditions in order to balance any excess or deficiency so shown. The provisions of this Section 2.10 shall survive the termination of this Agreement until such time as complete balancing can be attained. BAMAGAS and CES shall enter into an operational balancing agreement in a form substantially similar to Exhibit 8, which will govern the rights and obligations of each Party regarding Imbalances.
     2.11 Gas Delivery Rates. CES shall have the right to deliver or cause to be delivered to BAMAGAS for transportation hereunder any quantities of Gas from zero to the Firm Transportation Quantity and shall not be required to cause such deliveries to be maintained at a uniform or dairy rate of flow. Nothing in this Agreement shall prevent BAMAGAS from taking such action as it deems necessary to adjust such hourly and daily rates of flow to meet operating constraints or capacity limitations as determined in accordance with the Hydraulic Model referenced in Exhibit 10 and to protect the operational integrity of the Pipeline. BAMAGAS shall maintain the linepack (i.e., the total amount of Gas contained in the Pipeline) on the Pipeline at all times during the Term of this Agreement at the quantities required by the Hydraulic Model except by reason of express written consent of CES, Force Majeure, Applicable Law, or an Excusable Event.
 7 

 

ARTICLE III
TERM OF AGREEMENT
     The Term of this Agreement shall commence on the Effective Date and, unless earlier terminated in accordance herewith, shall remain in full force and effect until the expiration of twenty (20) years from the First Delivery Date (the “Initial Term”) and shall thereafter continue in full force and effect for consecutive periods of one (1) year each (each, a “Renewal Term”) unless CES gives written notice of termination of this Agreement to BAMAGAS at least ninety (90) Days prior to the end of the Initial Term or the then current Renewal Term. Provided, however, BAMAGAS shall have the right, exercisable within thirty (30) Days of the beginning of each Renewal Term, to terminate this Agreement as of the expiration of the Initial Term or the then Renewal Term, as applicable, by written notice delivered to CES, in which case CES or its designee shall have the right to purchase the Pipeline and/or the BAMAGAS Lateral(s) in accordance with the terms of Section 12.3.
ARTICLE IV
QUALITY AND PRESSURE
     4.1 Quality. CES shall endeavor to ensure that all Natural Gas delivered by it or for its account to BAMAGAS hereunder shall meet the quality specifications set forth in Exhibit 2 to this Agreement. The Parties agree that Exhibit 2 sets forth the quality specifications required by transporters immediately upstream from the Pipeline and that Exhibit 2 will be amended from time to time as necessary to reflect any changes to those requirements. All Natural Gas delivered by BAMAGAS at the Points of Delivery shall be at least of the same quality as that received by BAMAGAS for CES’ account at the Point(s) of Receipt. BAMAGAS shall perform chromatograph analyses of all Natural Gas delivered hereunder and shall furnish such analyses to CES on a “real-time” basis (i.e., through a direct communication link to the Morgan Energy Center). In the event that either Party receives nonconforming Gas from or on behalf of the other Party, it shall promptly notify the other Party of such nonconformance and shall not be required to accept such nonconforming Gas. In the event that BAMAGAS delivers nonconforming Gas to CES that is rejected by CES and such nonconformance was not caused by CES’ upstream suppliers, CES shall have the right, until such time as BAMAGAS causes the Gas in the Pipeline to meet the quality specifications set forth in Exhibit 2, to transport Gas on the BAMAGAS Lateral(s) at no cost to CES for all quantities per Day up to the Firm Transportation Quantity (provided that CES shall continue to pay to BAMAGAS the Initial Term Demand Charge or the Renewal Term Demand Charge, as applicable), but shall pay for all quantities per Day in excess of the Firm Transportation Quantity at the rates specified in Section 6.1 hereof. If the third party cost to CES for the delivery of Gas from its upstream transporters or suppliers to the BAMAGAS Lateral point(s) of receipt (“CES’ Lateral Supply Cost”) is greater than the third party cost CES would have incurred for the delivery of such Gas to the Pipeline Point(s) of Receipt (“CES’ Pipeline Supply Cost”), BAMAGAS shall reimburse CES for the positive difference between CES’ Lateral Supply Cost and CES’ Pipeline Supply Cost; provided, however, if BAMAGAS notifies CES that it is able to provide or cause to be provided (and does so provide or cause to provide if timely authorized by CES) Gas to CES (at CES’ expense) at the BAMAGAS Lateral points or receipt at a cost which is less than that incurred or to be incurred by CES from its upstream Gas suppliers, then BAMAGAS shall reimburse CES only for the positive difference, if any, between CES’ Lateral Supply Cost and CES’ Pipeline Supply Cost. CES shall reimburse BAMAGAS for all its costs incurred in connection with the purging of nonconforming Gas delivered by or for the account of CES into the Pipeline or the BAMAGAS Lateral(s) or in otherwise causing such nonconforming Gas to meet the quality specifications set forth in Exhibit 2 provided such non conformance was caused by CES or its upstream Gas suppliers. The Parties agree that BAMAGAS has no obligation to odorize CES’ Natural Gas received by BAMAGAS at the Point(s) of Receipt, unless BAMAGAS is required to do so pursuant to Applicable Law.
     4.2 Pressure. BAMAGAS shall deliver Natural Gas to CES at prevailing line pressure as it may vary from time to time. CES will endeavor to have the Gas delivered by the upstream transporters at the Point(s) of Receipt at a pressure equal to or greater than 675 psig. If the Gas is delivered by the upstream transporters at the Point(s) of Receipt at a pressure equal to or greater than 675 psig, then the variance between the pressure at the Point(s) of Receipt and the Point(s) of Delivery (the “Pressure Variance”) shall be such that the pressure at the Point(s) of Delivery is not less than 500 psig. If the Gas is delivered by the upstream transporters at the Point(s) of Receipt at a pressure of less than 675 psig, then the Pressure
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Variance shall not exceed that provided for in accordance with the Hydraulic Model. Other than by reason of the express written consent of CES, Force Majeure, Applicable Law, or an Excusable Event, if the Pressure Variance exceeds that allowed under the following provisions of this Section 4.2 on more than three (3) occasions for a duration of one (1) hour or more after notice thereof has been received by BAMAGAS (“Pressure Variance Event”), BAMAGAS shall be required to remedy the problem by adding compression and/or performing other pipeline improvements. If BAMAGAS is successful in remedying the problem as determined by both Parties in accordance with the requirements of the Hydraulic Model, then no Pressure Variance Event shall be deemed to have occurred.
ARTICLE V
MEASUREMENTS AND MEASURING EQUIPMENT
     5.1 Transportation Units. The transportation unit of the Natural Gas received and delivered by BAMAGAS hereunder shall be one (1) MMBtu.
     5.2 Measuring Station. BAMAGAS or the appropriate upstream transporter will install, own and operate, at the Point(s) of Receipt and the Point(s) of Delivery, a measuring station properly equipped with meters and other necessary measuring equipment by which the quantity of Natural Gas delivered under this Agreement shall be measured. Orifice meters or other AGA approved measurement devices, which include turbine or ultrasonic meters, shall be installed, operated and equipped with electronic flow measurement equipment in accordance with the latest applicable Measurement Committee Report of the American Gas Association. Nothing hereinabove shall preclude BAMAGAS or CES, at such Party’s sole cost, risk and expense, from installing, owning, operating and maintaining measuring equipment at or near the Point(s) of Receipt or Point(s) of Delivery to measure Natural Gas delivered under this Agreement. Each BAMAGAS and CES agree to grant each other a right to enter onto such Party’s property for the purpose of installing, reading and maintaining measuring equipment as provided for herein.

 	a.	 	Check Measuring Equipment: CES may install, own, maintain and operate, at its sole cost, risk and expense, such check measuring equipment as desired, provided that such equipment shall be so installed as not to interfere with the operation of BAMAGAS measuring equipment at or near a Point of Receipt or Point of Delivery.	
 		
 	b.	 	Right To Be Present: BAMAGAS and CES shall have the right to have representatives present at the time of any installing, reading, cleaning, changing, repairing, inspecting, testing, calibrating, or adjusting done in connection with the other’s measuring equipment used in measuring or checking the measurement of deliveries of Natural Gas under this Agreement. The records from such measuring equipment shall remain the property of their owner, but upon request each will submit to the other its records and charts, together with calculations therefrom, for the inspection and verification, subject to return within thirty (30) Days after receipt thereof.	
 		
 	c.	 	Care Required: All installations of measuring equipment applying to or affecting deliveries of Natural Gas shall be made in accordance with standard industry practices and such manner as to permit accurate determination of the quantity of Natural Gas delivered and ready verification of the accuracy of measurement. Care shall be exercised by both Parties in the installation, maintenance and operation of pressure regulating equipment so as to prevent any inaccuracy in the determination of the quantity of Natural Gas delivered under this Agreement.	
 		
 	d.	 	Calibration and Test of Meters: The accuracy of BAMAGAS measuring equipment shall be verified by BAMAGAS at reasonable intervals, and, if requested, in the presence of representatives of CES, but BAMAGAS shall not be required to verify the accuracy of such equipment more frequently than once in any thirty (30) day period. In the event either Party shall notify the other that it desires a special test of any measuring equipment, the Parties shall cooperate to secure a prompt verification of the accuracy of such equipment. The expense of any such special test, if called for by CES, shall be borne by CES if the measuring equipment tested is found not to be in error or to be in error not more than two percent (2%).	
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 	(i)	 	If, upon test, any measuring equipment, including recording calorimeters, is found to be in error by not more than two percent (2%), previous recordings of such equipment shall be considered accurate in computing deliveries of Natural Gas, but such equipment shall be adjusted at once to record accurately.	
 		
 	(ii)	 	If, upon test, any measuring equipment shall be found to be inaccurate by an amount exceeding two percent (2%) at a recording corresponding to the average hourly rate of flow for the period since the last preceding test, then any previous recordings of such equipment shall be corrected to zero error for any period which is known definitely but in case the period is not known or agreed upon, such correction shall be for a period extending over one-half (1/2) of the time elapsed since the date of the last test, not exceeding a correction period of sixteen (16) Days.	

 	e.	 	Correction of Metering Errors — Failure of Meters: In the event a meter is out of service, or registering inaccurately, the quantity of Natural Gas delivered hereunder shall be adjusted for purposes of calculating CES’ monthly bill according to the following procedures:	

 	(i)	 	by using the registration of any check meter or meters, if installed and accurately registering; or	
 		
 	(ii)	 	in the absence of (i), by correcting the error if the percentage is ascertainable by calibration; tests or mathematical calculation; or	
 		
 	(iii)	 	in the absence of both (i) and (ii), by estimating the quantity of delivery by utilizing a mathematical computation of subtracting accurately recording delivery meters from the receipt meters for the appropriate time period; or	
 		
 	(iv)	 	in the absence of (i), (ii) and (iii), by estimating the quantity of delivery by deliveries during periods under similar conditions when the meter was registering accurately.	

 	f.	 	Preservation of Metering Records: BAMAGAS and CES shall each preserve for a period of at least one (1) year all test data, charts and other similar records.	
ARTICLE VI
CHARGES TO BE PAID BY CES
     6.1 Transportation Charges. In consideration of BAMAGAS’ agreement to make the capacity of the Pipeline up to the Firm Transportation Quantity available to CES for transportation of CES’ Gas on a Firm basis during the Initial Term, CES shall pay to BAMAGAS on a monthly basis during the Initial Term, commencing as of the First Delivery Date (whether or not CES commences the shipping of Gas on such date or any later date and whether or not on any Day CES causes any Gas, up to the Firm Transportation Quantity, to be scheduled for delivery or be delivered) a fixed demand charge (the “Initial Term Demand Charge”) equal to the product of (a) seven cents ($0.07) per MMBtu of Gas (the “Initial Term Transportation Rate”) times (b) 100,000 MMBtu of Gas and times (c) the number of Days in such Month. BAMAGAS shall not charge the Initial Term Transportation Rate for the actual quantities of CES’ Gas collectively received each Day at the Points of Receipt during the Initial Term as long as those quantities are not in excess of the Firm Transportation Quantity. In the event that BAMAGAS transports Gas for CES in excess of the Firm Transportation Quantity to the Points of Receipt on any Day during the Initial Term, CES shall pay BAMAGAS for all MMBtu of Gas delivered in excess of the Firm Transportation Quantity per Day an amount equal to (a) the Initial Term Transportation Rate times (b) all MMBtu of Gas in excess of the Firm Transportation Quantity per Day.
     In consideration of BAMAGAS’ agreement to make the capacity of the Pipeline up to the Firm Transportation Quantity available to CES for the transportation of CES’ Gas on a Firm basis during each Renewal Term, CES shall pay to BAMAGAS on a Monthly basis during each Renewal Term commencing as of the first Day of such Renewal Term (and whether or not on any Day CES causes any Gas up to the Firm Transportation Quantity to be scheduled for delivery or be delivered), a fixed demand charge (the “Renewal Term Demand Charge”) equal to the product of (a) four cents ($0.04) per MMBtu of Gas (the
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“Renewal Term Transportation Rate”) times (b) 100,000 MMBtu, and times (c) the number of Days in such Month. BAMAGAS shall not charge the Renewal Term Transportation Rate for the actual quantities of Gas collectively received each Day at the Point(s) of Receipt during any Renewal Term as long as those quantities are not in excess of the Firm Transportation Quantity. In the event that BAMAGAS transports for CES Gas in excess of the Firm Transportation Quantity to the Points of Receipt on any Day during a Renewal Term, CES shall pay BAMAGAS for all MMBtu of Gas delivered in excess of the Firm Transportation Quantity per Day an amount equal to (a) the Renewal Term Transportation Rate times (b) all MMBtu of Gas in excess of the Firm Transportation Quantity per Day.
     In the event CES delivers or causes to be delivered or tendered Gas quantities from the Point(s) of Receipt to the Point(s) of Delivery in excess of the Firm Transportation Quantity on any given Day to be transported hereunder during the Initial Term or any Renewal Term, such daily quantities in excess of the Firm Transportation Quantity may be interrupted or curtailed by BAMAGAS and BAMAGAS shall not be in breach of this Agreement. No event of Force Majeure, Applicable Law or an Excusable Event shall relieve CES of the obligation to pay the full amount of the Initial Term Demand Charge and the Renewal Term Demand Charge, as applicable, each Month during the Term of this Agreement, except as otherwise expressly provided in Section 11.2. CES shall have no right to make up the difference, if any, between the actual quantities of Gas transported on any given Day during the Initial Term or any Renewal Term and the Firm Transportation Quantity, nor shall CES be entitled to any credit or allowance for any such differences. The Parties shall settle Imbalances in accordance with the provisions of the operational balancing agreement attached as Exhibit 8.
     6.2 Taxes. In addition to any other payments due hereunder, CES shall be liable to reimburse BAMAGAS for all taxes, including but not limited to sales (wholesale or retail), transaction, occupation, privilege, license, franchise, service, production, severance, gathering, transmission, gross receipts, export or excise, or other exaction, (but not including income, excess profits, capital stock, state franchise or general property taxes) hereafter levied, assessed or fixed by any Governmental Authority (and whether any such tax is currently collected), measured by, in respect of or applicable to the Natural Gas to be received, transported or delivered by BAMAGAS under this Agreement and to the extent actually paid by BAMAGAS. All such taxes shall be separately stated and identified on invoices issued by BAMAGAS hereunder. In the event any taxes, assessments, impositions, or other charges are imposed by any Governmental Authority on the receipt, transportation or delivery of Natural Gas hereunder that are not in effect as of the date hereof (“New Taxes”), such New Taxes shall be allocated pro rata between CES and BAMAGAS based upon the respective use (including reserved capacity for firm transportation) of the capacity of the Pipeline by CES and all other parties during each tax period applicable to such New Taxes.
     6.3 Other Charges. CES shall promptly reimburse BAMAGAS for any surcharges and all other costs charged to or levied upon BAMAGAS by Natural Gas producers, suppliers, transporters or regulatory agencies related to the receipt, transportation or delivery of Natural Gas under this Agreement, provided that such charges are not caused by actions or omissions of BAMAGAS in material breach of an obligation to CES under this Agreement.
     6.4 Price Reduction. In the event that at any time during the Term hereof, BAMAGAS contracts with any other shipper (“Third Party Transportation Contract”), for any level of transportation service of Gas on the Pipeline at a rate more favorable than the rate then being charged CES hereunder for any level of transportation service (“Favorable Rate”), and the transported Gas is used by the shipper or any Affiliate of it for a Competing Use, BAMAGAS shall credit to the transportation charges under this Agreement, during the term of the Third Party Transportation Contract, a sum equal to the positive difference, if any, between the Favorable Rate and CES’ rate for that quantity of CES’ Gas, up to (but not exceeding) the daily quantity transported on the Pipeline at the Favorable Rate; provided, however, that CES shall pay the Initial Term Demand Charge, the Renewal Term Demand Charge, the Initial Term Transportation Rate and the Renewal Term Transportation Rate subject to offset by the credits provided for hereunder. The foregoing credits shall not be applicable if there is a price readjustment pursuant to the provisions of the second to the last paragraph of Article XV. This obligation of BAMAGAS shall apply to any Favorable Rate in any transportation service agreement entered into between BAMAGAS and Existing Shippers after the execution of this Agreement.
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     Similarly, if BAMAGAS, Enbridge or any Affiliate of either of them enters into any Natural Gas sales agreements for delivery of Gas off of the Pipeline with any third party, (“Third Party Sales Contract”) used by such third party or any Affiliate of it for a Competing Use, and the net effect of the sale is that the transportation service of Gas on the Pipeline is at a rate more favorable than the rate charged CES hereunder for the same level of transportation service (“Beneficial Rate”), and if the transported Gas is used by the third party purchaser or any Affiliate of it for a Competing Use, BAMAGAS shall credit to the transportation charges under this Agreement during the term of the Third Party Sales Contract a sum equal to the difference between the Beneficial Rate and CES’ rate for that quantity of CES’ Gas, up to (but not exceeding) the daily quantity sold off of the Pipeline to the third party purchaser at the Beneficial Rate; provided, however that CES shall pay the Initial Term Demand Charge, the Renewal Term Demand Charge, the Initial Term Transportation Rate or the Renewal Term Transportation Rate subject to offset by the credits provided for hereunder. For the purposes hereof, “Competing Use” shall mean Natural Gas that is utilized for the purpose of the generation of electricity and/or steam delivered by the Pipeline and/or BAMAGAS Lateral(s). CES shall have the right at all reasonable times to examine records and relevant data to the extent necessary to verify the accuracy of any supporting information regarding Favorable and Beneficial Rates.
ARTICLE VII
BILLING AND PAYMENTS
     7.1 Billing Dates. On or about the fifth (5th) Business Day of each Month, BAMAGAS shall issue (by facsimile or other means) to CES an invoice setting forth the quantity of Gas received and delivered for CES’ account during the preceding Month, any lost or unaccounted for Gas based on the calculations of electronic flow measurement equipment and all applicable fees and charges due in accordance with Article VI hereof.
     7.2 Payment Date. Payment by CES shall be made to BAMAGAS, at its address designated herein, in immediately available funds, on or before the Day that is thirty (30) Days after receipt of any invoice from BAMAGAS hereunder. If CES, in good faith, disputes any portion of any such invoice or billing by BAMAGAS, CES shall nonetheless pay any undisputed portion of such invoice within the prescribed time frame. Wire transfers of payment shall be made to such accounts or accounts as BAMAGAS may designate in writing to CES.
     7.3 Right to Examination. Each of BAMAGAS and CES shall have the right to examine at any reasonable time, upon not less than five (5) Business Days written notice to the other, the books, records and charts of the other to the extent necessary to verify the accuracy of any invoice, charge or computation made under or pursuant to the provisions of this Agreement. Each Party shall retain all such records for a period of two (2) years after the creation thereof.
     7.4 Adjustment of Errors in Billing. If it shall be found that at any time or times CES has been overcharged or undercharged in any form whatsoever under the provisions of this Agreement, and CES shall have actually paid the bill containing such overcharge or undercharge, then, within thirty (30) Days after the final determination thereof BAMAGAS shall refund the amount of any such overcharge or CES shall pay the amount of any such undercharge with interest thereon at a rate per annum equal to the prime rate of interest published in the Wall Street Journal, from the time such overcharge or undercharge was paid to the date of refund or payment, as the case may be.
     7.5 Interest on Past Due Payments. Interest on any past due payment hereunder shall accrue at a rate per annum equal to the prime rate of interest published in the Wall Street Journal, plus two percent (2%), from the due date until the date of payment, but in no event in excess of the maximum legal rate of interest.
ARTICLE VIII
POSSESSION OF NATURAL GAS
     BAMAGAS shall be deemed to be in control and possession of the Natural Gas being transported hereunder from the time it is received at the upstream flange of a receipt meter at a Point of Receipt until it shall have been delivered to the downstream flange of a delivery meter at a Point of Delivery. As between
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the Parties hereto, CES shall be deemed to be in control and possession of such Natural Gas before it is received by BAMAGAS as described in the prior sentence at a Point of Receipt and after it has been delivered to CES as described in the prior sentence at a Point of Delivery. Possession of and risk of loss of Gas received by BAMAGAS at the Points(s) of Receipt shall pass from BAMAGAS to CES at the Point(s) of Delivery.
ARTICLE IX
REPRESENTATIONS AND WARRANTIES AND COVENANTS
     9.1 Warranty of Title. CES warrants that it will have, at the time of delivery of Gas at a Point of Receipt for transportation hereunder, good title to and/or the full right and authority to deliver such Gas to BAMAGAS for transportation hereunder. Subject only to the accuracy of CES’ foregoing warranty, BAMAGAS warrants that it will at the time of delivery of the Gas transported hereunder have the full right and authority to deliver such Gas to CES. BAMAGAS further warrants that such Gas will be free and clear of all liens, encumbrances or claims created by or through BAMAGAS.
     9.2 Warranty Regarding Intrastate Pipeline. Subject only to any changes in Applicable Law subsequent to the date of this Agreement which affects the status or determination of status of interstate and intrastate pipelines and of regulation by Governmental Authorities, BAMAGAS represents and warrants that the Pipeline will qualify as an intrastate pipeline upon completion hereof and that this Agreement shall not then be subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) or any successor thereto. BAMAGAS further represents and warrants that it will not take any affirmative act which would cause the Pipeline to be classified as an interstate pipeline or otherwise be subject to the jurisdiction of FERC or any successor thereto under or pursuant to the Applicable Law currently in effect as of the date of this Agreement.
     9.3 Corporate Representations and Warranties. Each Party hereby represents and warrants to the other Party that, as of the date hereof:

 	a.	 	Such Party is duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization, is in good standing and is qualified to do business in the State of Alabama and in all other jurisdictions in which the nature of the business conducted by it makes such qualification necessary and where failure to so qualify would have a material adverse effect on its financial condition, operations, prospects or business.	
 		
 	b.	 	Such Party is not in violation of any applicable law promulgated or judgment entered by any Governmental Authority which violation(s), individually or in the aggregate, would adversely affect its performance of any obligations under this Agreement. There are no legal or arbitration proceedings or any proceeding by or before any governmental or regulatory authority or agency now pending or (to its best knowledge) threatened against it which, if adversely determined, could have a material adverse effect upon its financial condition, operations, prospects or business, as a whole, or its ability to perform under this Agreement.	
 		
 	c.	 	Except for such Governmental Approvals to be obtained by BAMAGAS for the construction and operation of the Pipeline and Governmental Approvals to be obtained by CES with respect to the Morgan Energy Center, such Party is the holder of all permits, licenses or other authorizations required to permit it to operate or conduct its business now and as contemplated by this Agreement, and, no authorization, consent or approval of, notice to or filing with any other Person is required for the execution, delivery or performance by such Party of this Agreement.	
 		
 	d.	 	The execution, delivery and performance by such Party of this Agreement, the compliance with the terms and provisions hereof, and the carrying out of the transactions contemplated hereby, does not conflict or will not conflict with or result in a breach or violation of any of the terms, conditions or provisions of the charter documents, as amended, or bylaws, as	
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 	 	 	amended, of such Party or any order, writ, injunction, judgment or decree of any court or Governmental Authority against such Party or by which it or any of its properties is bound, or any loan agreement, indenture, mortgage, note, resolution, bond, or contract or other agreement or instrument to which such Party is a party or by which it or any of its properties is bound, or constitutes or will constitute a default thereunder or will result in the imposition of any lien upon any of its properties.	
 		
 	e.	 	Such Party has all necessary power and authority to execute, deliver and perform this Agreement and its obligations hereunder; the execution, delivery and performance of this Agreement have been duly authorized by all necessary action on its part; it has duly and validly executed and delivered this Agreement; and the Agreement constitutes a legal, valid and binding obligation of such Party, enforceable against such Party in accordance with the terms hereof, except as the enforceability thereof may be limited by bankruptcy, insolvency, reorganization or moratorium or other similar laws relating to the enforcement of creditors’ rights generally and by general equitable principles.	
     9.4 BAMAGAS covenants. BAMAGAS hereby covenants that during the Term of this Agreement, without the prior written consent of CES:

 	a.	 	It shall not engage in any business other than the development, construction of up to a thirty inch (30”) pipeline during the initial construction period, operation, and maintenance (including repair or replacement) of the Pipeline and the BAMAGAS Lateral(s) and the sale, delivery and transportation of Natural Gas thereon (collectively, the “BAMAGAS Activities”);	
 		
 	b.	 	It shall not incur, create, assume or otherwise become liable for any indebtedness other than indebtedness associated with the BAMAGAS Activities;	
 		
 	c.	 	It shall not create, incur, assume or suffer to exist on any of its property any lien, encumbrance, security interest, mortgage, pledge, hypothecation or assignment other than such a lien or other interest arising out of indebtedness associated with the BAMAGAS Activities;	
 		
 	d.	 	It shall preserve and maintain its existence as a corporation and its qualification and good standing in the State of Alabama;	
 		
 	e.	 	It shall pay or cause to be paid, when due and payable, all taxes, charges, levies and assessments and other charges required to be paid by it or levied against the Pipeline and the BAMAGAS Lateral(s), except for taxes contested in good faith and with respect to which proper reserves have been established;	
 		
 	f.	 	It shall maintain all Governmental Approvals required for the ownership and operation of the Pipeline and the BAMAGAS Lateral(s) and for the conduct of its business;	
 		
 	g.	 	It shall maintain appropriate liability insurance on the Pipeline and the BAMAGAS Lateral(s).	
ARTICLE X
INDEMNIFICATION
     10.1 BAMAGAS INDEMNITY. BAMAGAS SHALL PROTECT, DEFEND, INDEMNIFY, AND HOLD HARMLESS THE SHIPPER GROUP FROM AND AGAINST ALL SUITS, ACTIONS, DEBTS, ACCOUNTS, DAMAGES, COSTS, LOSSES AND EXPENSES, INCLUDING, WITHOUT LIMITATION, INJURY TO OR DEATH OF PERSONS AND DAMAGE TO OR DESTRUCTION OF PROPERTY, ARISING FROM ANY ACT OR OMISSION OR ACCIDENT IN CONNECTION WITH (A) BAMAGAS’ CONTROL OR POSSESSION OF THE GAS IN THE PIPELINE OR THE BAMAGAS LATERALS, AND (B) BAMAGAS’ CONSTRUCTION, OWNERSHIP OR OPERATION OF THE PIPELINE AND THE BAMAGAS LATERALS.
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     10.2 CES INDEMNITY. CES AGREES TO PROTECT, DEFEND, INDEMNIFY AND HOLD HARMLESS THE BAMAGAS GROUP FROM ALL SUITS, ACTIONS, DEBTS, ACCOUNTS, DAMAGES, COSTS, LOSSES AND EXPENSES, INCLUDING, WITHOUT LIMITATION, INJURY TO OR DEATH OF PERSONS AND DESTRUCTION OF PROPERTY ARISING FROM ANY ACT OR OMISSION OR ACCIDENT IN CONNECTION WITH (A) THE SHIPPER GROUP’S OR THEIR AGENT’S OWNERSHIP, POSSESSION OR CONTROL OF THE GAS PRIOR TO ITS DELIVERY INTO THE PIPELINE OR THE BAMAGAS LATERALS AND AFTER REDELIVERY AT THE POINTS OF DELIVERY OR SECONDARY POINTS OF DELIVERY, AND (B) THE SHIPPER GROUP’S CONSTRUCTION, OWNERSHIP AND OPERATION OF THE MORGAN ENERGY CENTER.
     10.3 Scope. For the purposes of this indemnity:

 	a.	 	The agreement to “defend” includes the responsibility to pay the costs and expenses of defense (including reasonable attorneys’ fees) of the person entitled to indemnity;	
 		
 	b.	 	“Shipper Group” means CES, its officers, directors, subsidiaries, affiliates, members, partners, successors and assigns. “BAMAGAS Group” means BAMAGAS, its officers, directors, subsidiaries, affiliates, members, partners, successors and assigns;	
     10.4 Notice and Opportunity to Defend. Any person claiming indemnification hereunder (an “Indemnitee”) must give prompt and timely notice to the Party against which it is claiming indemnity hereunder (the “Indemnitor”) and shall have the right to participate fully in the defense at its sole expense if the Indemnitor undertakes to provide the actual defense. The Indemnitor shall determine within thirty (30) Days after the receipt of such notice whether it will pay the costs and expenses of the Indemnitee’s defense or undertake to provide the actual defense. If the Indemnitor elects to undertake the actual defense, then the Indemnitee shall give the Indemnitor the opportunity to direct the defense of such claim through counsel of its own choosing; provided, however, that (i) if there are differing interests which require separate counsel for the Indemnitee, then the Indemnitee shall defend the claim with separate counsel selected or approved by the Indemnitor, and the Indemnitor shall pay the costs and expenses of the Indemnitee’s separate defense; and (ii) the Indemnitee shall nonetheless have the right to participate, solely as an observer, through counsel or otherwise, in meetings and proceedings with adverse parties.
ARTICLE XI
FORCE MAJEURE
     11.1 Force Majeure Defined. Except as expressly provided in this Section 11.1, neither BAMAGAS nor CES shall be required to perform any act required by this Agreement, other than the making of payment of monies due hereunder (including, without limitation, the Initial Term Demand Charge and the Renewal Term Demand Charge), during such period as such Party is unable to perform in whole or in part due to Force Majeure. The term “Force Majeure” as used in this Agreement shall mean any acts of God, strikes, lockouts, embargoes, acts of the public enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, storms, floods, washouts, arrests and restraints of rulers and peoples, civil disturbances, explosions, breakage or failure of or accident to machinery and equipment or lines of pipe caused by events or actions beyond the affected Party’s reasonable control, unanticipated repairs to or replacements of equipment, machinery, lines of pipe, pumps, compressors, valves, gauges, and metering equipment, line freeze-ups, the binding order of any court or Governmental Authority which has been resisted in good faith by all reasonable legal means, and any other cause, of the kind herein enumerated, not within the control of the Party claiming suspension and which by the exercise of due diligence such Party is unable to prevent or overcome. A failure to settle or prevent any strike or other controversy with employees or with anyone purporting or seeking to represent employees shall not be considered to be a matter within the control of the Party claiming suspension; however, in the event of a Force Majeure due to a strike or similar labor dispute, CES shall have the right to utilize its own employees or contract workers to operate the Pipeline during such event; provided, however, that BAMAGAS shall not be liable under this Agreement or otherwise for the acts or omissions of CES’ employees or its contractors in connection with their operation of the Pipeline and/or the BAMAGAS Lateral(s), nor shall BAMAGAS be held in breach of any covenant or other obligation to CES under this Agreement by reason
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of any acts or omissions of CES’ employees or its contractors in connection with their operation of the Pipeline and/or the BAMAGAS Lateral(s). Except as provided in the immediately preceding sentence, such operation of the Pipeline by CES’ employees or its contractors shall not impair any rights that CES may have under this Agreement. Routine maintenance which will result in the curtailment or interruption of transportation of Gas to the Point(s) of Delivery if scheduled by mutual consent of the Parties, which consent shall not be unreasonably withheld by the affected Party, shall be deemed to operate as a Force Majeure event except for the payment of the Initial Term Demand Charge or the Renewal Term Demand Charge. Causes or contingencies affecting the performance of this Agreement by either Party if deemed to be Force Majeure within the meaning of this Agreement, however, shall not relieve the affected Party of its obligation to perform in the event of such Party’s failure to use due diligence to remedy the situation and remove the cause in an adequate manner and with all reasonable dispatch, nor shall such causes or contingencies relieve either Party of its obligation to perform unless such Party gives notice and full particulars of the same in writing to the other Party as soon as practicable after the initial occurrence relied on. Except as expressly provided in this Section 11.1 or elsewhere in this Agreement, neither Party shall be liable to the other for damages, direct or indirect, immediate or remote, by reason of, caused by or arising out of the obligation or obligations of either Party when such suspension results from an event of Force Majeure.
     11.2 Effect of Force Majeure. In the event that BAMAGAS is unable to transport Gas or CES is unable to receive Gas hereunder as the result of an event of Force Majeure, a period of time equal to the duration of such inability (the “Extension Period”) shall be added to the Initial Term if occurring during the Initial Term) or the Renewal Term (if occurring during the Renewal Term), as applicable, and during such extended period the Transportation Rate for all quantities of Gas transported each Day up to, but not in excess of, the Firm Transportation Quantity shall be zero cents ($0.00), except as otherwise provided in this Section 11.2. In the event that as the result of an event of Force Majeure the Morgan Energy Center is substantially damaged or destroyed and CES decides not to rebuild such facility, CES shall have the right to terminate this Agreement and to have no prospective obligations under this Agreement to BAMAGAS except as provided in the next sentence. In the event of termination of this Agreement in accordance with the foregoing, CES shall pay BAMAGAS the relevant Termination Value as determined in accordance with Exhibit 4. CES shall have the right during the continuance of any event of Force Majeure that affects its ability to receive Gas hereunder to sell its capacity on the Pipeline to a third party, other than a then existing customer of BAMAGAS, Enbridge or any Affiliate of either of them, unless BAMAGAS elects to delay the payment of the Initial Term Demand Charge or the Renewal Term Demand Charge which would otherwise be due BAMAGAS during the period of the Force Majeure for payment during any Extension Period.
ARTICLE XII
EVENTS OF DEFAULT
     12.1 Definition. An “Event of Default” under this Agreement shall be deemed to exist with respect to a Party upon the occurrence of any one or more of the following events:

 	a.	 	Failure by a Party to timely make payment of any amount due to the other Party under this Agreement (other than an amount subject to a good faith dispute), which failure continues for a period of twenty (20) Days after receipt of written notice of such nonpayment;	
 		
 	b.	 	Curtailment or interruption, other than by reason of Pressure Variance, at any time subsequent to sixty (60) Days following BAMAGAS’ initial deliveries on the Pipeline of transportation by BAMAGAS to a Primary Point of Delivery for more than fifteen (15) minutes of the greater of 3,000 MMBtus or five percent (5%) or more of those Gas quantities which are required at any given time, not to exceed the Firm Transportation Quantity, for the operational requirement of the Morgan Energy Centers, other than by reason of express written consent of CES, Force Majeure, Applicable Law, an Excusable Event, or as otherwise permitted under this Agreement (an “Unexcused Curtailment”), on more than three (3) occasions on separate Days in any consecutive four (4) year period or on more than eight (8) occasions on separate Days in the aggregate over any consecutive twenty (20) year period; provided, however, an Unexcused Curtailment shall be conclusively deemed not to	
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 	 	 	have occurred unless written notice thereof, together with the known facts surrounding such curtailment or interruption, is given in writing by CES to BAMAGAS within ten (10) Days following such curtailment or interruption. BAMAGAS shall have the right to deliver to the Point(s) of Delivery those quantities of Gas which would otherwise be curtailed or interrupted under this provision via any of the Pipeline, the BAMAGAS Lateral(s), the MIT Lateral or any other pipeline, and if delivered by any such means to the Point(s) of Delivery, no curtailment or interruption shall be deemed to have occurred.	
 		
 	c.	 	Failure by a Party hereunder subsequent to the completion of both the Pipeline and the BAMAGAS Lateral(s) to substantially perform any other material obligation under this Agreement (i) which is not separately listed in this Section 12.1, and (ii) for which no exclusive remedy is provided for elsewhere in this Agreement, within twelve (12) months after a Party’s receipt of written notice from the other Party that a material obligation has not been performed.	
 		
 	d.	 	If by order of a court of competent jurisdiction, a receiver or liquidator or trustee of a Party or of any of the property of a Party shall be appointed, and such receiver or liquidator or trustee shall not have been discharged within a period of ninety (90) Days; or if by decree of such a court, a Party shall be adjudicated bankrupt or insolvent or any substantial part of the property of such Party shall have been sequestered, and such decree shall have continued undischarged and unstayed for a period of ninety (90) Days after the entry thereof; or if a petition to declare bankruptcy or to reorganize a Party pursuant to any of the provisions of the federal Bankruptcy Code, as it now exists or as it may hereafter be amended, or pursuant to any other similar state statute applicable to such Party, as now or hereafter in effect, shall be filed against such Party and shall not be dismissed within ninety (90) Days after such filing; or	
 		
 	e.	 	If a Party shall file a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law or shall consent to the filing of any bankruptcy or reorganization petition against it under any similar law; or, without limitation of the generality of the foregoing, if a Party shall file a petition or answer or consent seeking relief or assisting in seeking relief in a proceeding under any of the provisions of the federal Bankruptcy Code, as it now exists or as it may hereafter be amended, or pursuant to any other similar state statute applicable to such Party, as now or hereafter in effect, or an answer admitting the material allegations of a petition filed against it in such a proceeding; or if a Party shall make an assignment for the benefit of its creditors; or if a Party shall admit in writing its inability to pay its debts generally as they become due; or if a Party shall consent to the appointment of a receiver or receivers, or trustee or trustees, or liquidator or, liquidators of it or of all or any part of its property.	
     12.2 Right of Termination for Default. Upon the occurrence and during the continuation of an Event of Default, the Party not in default shall have the right to terminate this Agreement upon written notice to the other Party (the “Notice”) if the default is not cured or remedied within the thirty (30) day period following the other Party’s receipt of such written notice (the “Notice Period”); provided, however, if the Party claimed to be in default disputes at any time prior to the expiration of the Notice Period that an Event of Default occurred, then the dispute shall be arbitrated under the provisions of Sections 16.3, 16.4 and 16.5. Failure by the Party alleged to be in default to dispute the occurrence or continuance of an Event of Default after Notice has been received and within the Notice Period shall operate to waive any rights the Party alleged to be in default may have to dispute same. Any measures taken by the Party alleged to be in default shall not in any way prejudice such Party’s dispute as to the occurrence of an Event of Default noticed by the other Party, whether such measures are taken before or after notice of the Event of Default is given. Furthermore, no evidence taken at any time to remedy any Event of Default (whether or not notice is given to the Party claimed to be in default) shall be admissible by the Party alleging the Event of Default in any arbitration proceeding or other legal proceeding between the Parties.
     12.3 CES Purchase Rights. In the event of termination of this Agreement by CES following a BAMAGAS Event of Default and BAMAGAS’ failure to timely cure or remedy such Event of Default, or in the event that CES desires a Renewal Term but BAMAGAS does not, as provided in Article III, or if CES terminates this Agreement under Section 12.2, CES shall, subject to the purchase rights of CES under
 17 

 

the Natural Gas Construction and Transportation Agreement for the Decatur Energy Center, have the right to purchase the Pipeline and the BAMAGAS Lateral(s), subject to the right of BAMAGAS to transport Gas on the Pipeline and the BAMAGAS Laterals to Morgan Energy Center pursuant to the Natural Gas Construction and Transportation Agreement for the Decatur Energy Center and the transportation rights of BAMAGAS and/or any marketing Affiliate(s) of BAMAGAS or Enbridge on the Pipeline and the BAMAGAS Lateral(s) as set forth on Exhibit 11 (collectively, the “Transportation Rights”), for a price (the “Purchase Price”) equal to the amount (the “Termination Value”) as determined in accordance with Exhibit 4. Concurrent with payment of the Purchase Price, BAMAGAS shall execute and deliver to CES such instruments of transfer as are reasonably requested by CES subject to the Transportation Rights and those certain covenants, use restrictions and other obligations specified in Exhibit 9 (the “Use Restrictions”), and CES shall execute and deliver to BAMAGAS such instruments binding the Pipeline and the BAMAGAS Lateral(s) to such Transportation Rights and Use Restrictions as are reasonably requested by BAMAGAS; provided, however, that no representations shall be required to be provided by BAMAGAS other than representations that BAMAGAS has the right, power and authority to convey the Pipeline and the BAMAGAS Lateral(s) and that they are assigned free and clear of all liens and/or any other claims and liabilities. At CES’ request, upon execution of this Agreement, BAMAGAS shall grant to CES a first priority security interest (which shall be of equal priority with the first priority security interest also granted by BAMAGAS to CES pursuant to the Natural Gas Construction and Transportation Agreement for the Decatur Energy Center) in the Pipeline and/or the BAMAGAS Lateral(s) to secure CES’ purchase rights under this Section 12.3.
     12.4 Remedies Not Exclusive. Except as otherwise expressly provided to the contrary herein, the rights and remedies herein provided in case of an Event of Default shall not be exclusive but shall, to the extent permitted by law, be cumulative and in addition to all other rights and remedies existing at law, in equity or otherwise (including the right to specific performance), except those rights and remedies which have been waived or relinquished hereunder by the Parties pursuant to the provisions hereof. No delay or omission of a Party to exercise any right or remedy occurring upon any Event of Default shall impair any such right or remedy or constitute a waiver of such default or an acquiescence therein. Every right and remedy given by this Agreement or by law to a Party may be exercised from time to time, and as often as may be deemed expedient, by such Party. A Party shall have the obligation to mitigate any damages it incurs as a result of the other Party’s breach.
     12.5 Limitation of Liability. EXCEPT AS OTHERWISE SPECIFICALLY PROVIDED HEREIN, IN NO EVENT SHALL ANY PARTY BE LIABLE TO ANY OTHER PARTY FOR INDIRECT, SPECIAL, INCIDENTAL, CONTINGENT OR CONSEQUENTIAL DAMAGES, WHETHER SUCH DAMAGES ARISE IN CONTRACT, TORT, STRICT LIABILITY OR OTHERWISE, UNDER OR IN CONNECTION WITH THIS AGREEMENT, AND ANY DAMAGES SHALL BE LIMITED TO COMPENSATORY DAMAGES.
     12.6 Non-Recourse. The obligations of the Parties under this Agreement are intended to be recourse only to the assets of the Parties, and neither the partners thereof nor any shareholder, officer, director, employee or agent of the Parties or any partners or Affiliates of such Party shall have any personal responsibility or liability for any breach in performance or observance of the covenants, representations, or obligations thereunder. The provisions of this Section 12.6 shall not limit any of the obligations of Calpine Corporation under the absolute and unconditional guaranty of payment to be provided to BAMAGAS with respect to all obligations of CES hereunder, as provided under Section 18.1 (the “Calpine Corporation Guaranty”).
ARTICLE XIII
TRANSFER AND ASSIGNMENT
     13.1 Assignment. This Agreement shall be binding upon and inure to the benefit of the Parties hereto and their respective successors and permitted assigns. No assignment or transfer permitted hereunder shall relieve the assigning Party of its respective obligations under this Agreement unless the other Party agrees to such release; provided, however, that in the event of an assignment by CES to an Affiliate (and provided that the Calpine Corporation Guaranty remains in effect), CES shall be released
 18 

 

from its obligations hereunder. This Agreement, including any of the rights or obligations hereunder, may not be assigned or transferred without the prior written consent of the other Party, which consent shall not be unreasonably withheld, conditioned or delayed. Notwithstanding the foregoing (but subject to Section 13.2 below), any Party may, without the need for consent from the other Party (and without relieving itself from liability hereunder), (a) transfer or assign this Agreement to an Affiliate of such Party (provided that in the case of BAMAGAS, the assignment to such Affiliate will not jeopardize the status of the Pipeline or the BAMAGAS Lateral(s) as non-FERC jurisdictional assets), or (b) transfer or assign this Agreement to any Person succeeding to all or substantially all of the assets of such Party. In the event that MEC sells the Morgan Energy Center to a third party (a “Second Owner”), BAMAGAS agrees that if requested by MEC it will enter into a new agreement with the Second Owner on the same terms and conditions as this Agreement. Upon the sale of the Morgan Energy Center, BAMAGAS shall release Calpine from all of its prospective obligations under the Calpine Corporation Guaranty provided that the successor owner has substantially the same or better creditworthiness as Calpine and executes and delivers a guaranty to BAMAGAS with respect to the Morgan Energy Center substantially in the same form and content as the Calpine Corporation Guaranty. In addition, CES and BAMAGAS each shall have the right without the consent of the other Party to assign this Agreement as collateral security for loans made, in the case of CES, with respect to the construction of the Morgan Energy Center or, in the case of BAMAGAS, with respect to the construction of the Pipeline and the BAMAGAS Lateral(s). Each of MEC and BAMAGAS agree to provide reasonable cooperation to the other Party with respect to obtaining such financing, including the execution of written consents to assignment reasonably requested by such lenders.
     13.2 Right of First Refusal. In the event that BAMAGAS receives a bona fide offer from a third party (including an Affiliate of BAMAGAS) for the purchase of the Pipeline and/or the BAMAGAS Lateral(s) and/or BAMAGAS (“Third Party Offer”) and BAMAGAS intends to accept such offer, prior to accepting such offer it must notify CES of the offer (the “Offer Notice”), which Offer Notice shall set forth the purchase price and all of the other terms offered by the third party. Subject to the same first refusal rights of CES pursuant to the Natural Gas Construction and Transportation Contract for the Morgan Energy Center, CES shall have thirty (30) Days (the “Exercise Period”) from the date of the Offer Notice within which to elect to purchase all (and not less than all of the property covered by the Offer Notice) for the same purchase price and upon the same other terms (including the closing date) set forth in the Offer Notice. If the Third Party Offer includes assets other than the Pipeline and the BAMAGAS Lateral(s), BAMAGAS shall notify CES of the offer price for the Pipeline and the BAMAGAS Lateral(s) in order for CES to exercise its right of first refusal exclusively in connection with those assets. In the event that CES elects to purchase the Pipeline and the BAMAGAS Lateral(s), it shall notify BAMAGAS in writing within the Exercise Period; provided, however, if the Third Party Offer is conditioned upon the ability to purchase the Pipeline and the BAMAGAS Lateral(s) with other assets or BAMAGAS with other assets and/or another entity and CES elects to purchase the Pipeline and the BAMAGAS Lateral(s), then BAMAGAS, at its option, may rescind the Offer Notice, in which event BAMAGAS shall not sell the Pipeline and/or the BAMAGAS Lateral(s) or BAMAGAS, as applicable, to either CES or the third party pursuant to the Third Party Offer. If a Third Party Offer encompasses both the Pipeline and the BAMAGAS Lateral(s), CES may only exercise its right of first refusal as specified herein in connection with both assets or it shall be deemed to have waived its rights. In the event CES does not give such a notice to BAMAGAS or does not respond within the Exercise Period, BAMAGAS shall be free to accept the offer of the third party for the same purchase price and on the same terms set forth in the Offer Notice. In the event the terms of the transaction with the third party change after CES has declined to exercise its right of first refusal, BAMAGAS must provide a new Offer Notice to CES. In the event that CES decides to purchase on the terms set forth in an Offer Notice, it shall notify BAMAGAS in writing prior to the end of the Exercise Period and the sale to CES shall be closed within thirty (30) Days thereof. Upon a sale to CES hereunder, this Agreement shall automatically terminate as to all prospective obligations. Upon a sale to a third party hereunder, the third party as a successor in interest to BAMAGAS shall be bound by this Agreement, which shall remain in effect under the terms of Article III.
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ARTICLE XIV
REGULATION
     Each Party shall, in the course of its undertakings hereunder and as a part thereof, endeavor to obtain all required Governmental Approvals and shall comply otherwise with all applicable federal, state and local laws and regulations thereof. CES shall cooperate with BAMAGAS and, if requested by BAMAGAS, shall provide reasonable assistance to BAMAGAS in connection with BAMAGAS’ actions to obtain such Governmental Approvals. Each Party waives any right to contest or to seek to amend the rates provided for herein before any Governmental Authority.
ARTICLE XVI
DISPUTE RESOLUTION; GOVERNING LAW
     16.1 Procedure. In the event a dispute arises between BAMAGAS and CES regarding this Agreement or the transaction covered hereby, including, without limitation, (a) the application or interpretation of this Agreement, (b) whether or not an Unexcused Curtailment has occurred, (c) whether or not an Event of Default has occurred or continued without having been cured or remedied, and (d) the actions or measures which may be taken to cure or otherwise remedy an Event of Default, the Parties agree to use the procedures in this Article XVI to resolve any such disputes.
     16.2 Initial Resolution Attempts. Either Party may initiate dispute resolution procedures by sending written notice to the other Party specifically stating the complaining Party’s claim and requesting dispute resolution in accordance with this Article XVI. The receiving Party shall reply with the designation of a person authorized to settle the dispute and shall list two (2) alternative dates (both of which must be within ten (10) Business Days after receipt of the complaint) for meeting at a mutually agreeable location. If the matter has not been resolved within ten (10) Days of such meeting, each Party shall refer the dispute to a senior executive of its organization who shall meet at a mutually agreeable location within fourteen (14) Days to resolve the dispute.
     16.3. Arbitration. If the matter has not been resolved within fourteen (14) Days of the meeting of the senior executives, the Parties shall submit the dispute to arbitration under the terms and conditions set forth herein. Any dispute or need of interpretation arising out of this Agreement or which is disputed shall be submitted to binding arbitration by one arbitrator with knowledge of and over five years of professional experience in connection with similar transactions who has not previously been employed by either Party, and does not have a direct or indirect interest in either Party or the subject matter of the arbitration. Such arbitrator shall either be as mutually agreed by the Parties within ten (10) Days after written notice from either Party requesting arbitration, or failing agreement, shall be selected under the expedited rules of the American Arbitration Association (the “AAA”). The rules of the AAA shall apply to the extent not inconsistent with the rules herein specified. Either Party may initiate arbitration by written notice to the
 20 

 

other Party and the arbitration shall be conducted according to the following: (a) the arbitration hearing shall commence no later than thirty (30) Days of the selection of the arbitrator, (b) not later than seven (7) Days prior to the hearing date set by the arbitrator each Party shall submit a brief detailing its factual and legal position and a final offer for the settlement of the dispute, including a dollar amount, if applicable, (c) the hearing shall be conducted on a confidential basis without continuance or adjournment, (d) the Parties shall divide equally the cost of the arbitrator and the hearing and each Party shall be responsible for its own expenses and those of its counsel and representatives and (e) evidence concerning any offer made or the details of any negotiation prior to arbitration and the cost to the Parties of their representatives and counsel shall not be permissible. The arbitrator shall include in his report/award a list of findings, with supporting evidentiary references, upon which he has relied in making his decision. The award rendered by the arbitrator shall be final and binding upon the Parties, and judgment upon the award rendered by the arbitrator may be entered by any court having jurisdiction thereof. The place of arbitration shall be Houston, Texas. Each Party understands that this Agreement contains an agreement to arbitrate with respect to any dispute. After signing this Agreement, each Party understands that it will not be able to bring a lawsuit concerning any dispute that may arise that is covered by this arbitration provision. Instead, each Party agrees to submit any such dispute to an impartial arbitrator. Any monetary award of the arbitrator may be enforced by the Party in whose favor such monetary award is made in any court of competent jurisdiction.
     16.4. General Rules and Provisions. Notwithstanding anything to the contrary contained herein, and regardless of any procedures or rules of the AAA, it is expressly agreed that the following shall apply and control over any other provision in this Article XVI.

 	a.	 	The arbitrator shall have no authority to award punitive damages or attorneys’ fees.	
 		
 	b.	 	The fees and expenses of the mediator and arbitrator shall be shared equally by the Parties, and each Party shall bear its own costs and expenses.	
 		
 	c.	 	The Parties may, by written agreement signed by both Parties, alter any time deadline, location(s) for meeting(s), or procedure outlined in this Article XVI or in the AAA rules.	
 		
 	d.	 	Time is of the essence for purposes of the provisions of this Article XVI.	
 		
 	e.	 	Either Party may seek a restraining order, temporary injunction, or other provisional judicial relief if the Party in its sole judgment believes that such action is necessary to avoid irreparable injury or to preserve the status quo. The Parties will continue to participate in good faith in the procedures despite any request for provisional relief.	
 		
 	f.	 	The arbitrator shall have no authority, power or right to alter, change, amend, modify, waive, add to or delete from any of the provisions of this Agreement, and any award rendered by the arbitrator shall be consistent with the terms and conditions of this Agreement.	
     16.5. Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Texas, exclusive of any conflict of laws provisions thereof that would refer jurisdiction to the laws of another state.
ARTICLE XVII
NOTICES
     17.1 Writing. Any notice, demand, offer or other written instrument required or permitted to be given pursuant to this Agreement shall be in writing signed by the Party giving such notice, demand or offer, and shall be sent by telefax (confirmed by a mailed or courier copy received within five (5) Days), then by hand delivery, overnight courier, telegram or registered or certified mail, return receipt requested, to the other Party at such address as set forth below.
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If delivered to BAMAGAS:
BAMAGAS Company
1100 Louisiana, Suite 2900
Houston, Texas 77002
Attn: President
Tel.: (713) 650-8900
Fax: (713) 653-6711
With a copy to:
Enbridge (U.S.) Inc.
1100 Louisiana, Suite 2900
Houston, Texas 77001
Attn: President
Tel.: (713) 650-8900
Fax: (713) 653-6711
If delivered to CES:
Calpine Energy Services, L.P.
700 Louisiana, Suite 2700
Houston, Texas 77002
Attention: Jeff Rawls, Vice President — Producer Services
Tel.: (713) 830-8636
Fax: (713) 830-8712
With a copy to:
Calpine Corporation
50 West San Fernando Street
San Jose, California 95113
Attention: General Counsel
Tel.: (408) 995-5115
Fax: (408) 975-4648
     Each Party shall have the right to change the place to which notice shall be sent or delivered or to specify one additional address to which copies of notices may be sent, in either case by similar notice sent or delivered in like manner to the other Party.
     17.2 Timing of Receipt. Without limiting any other means by which a Party may be able to prove that a notice has been received by the other Party, a notice shall be deemed to be duly received:

 	a.	 	If delivered by hand, overnight courier or telegram, on the date when received at the address of the recipient;	
 		
 	b.	 	If sent by registered or certified mail, on the date of the return receipt; or	
 		
 	c.	 	If sent by telefax, upon receipt by the sender of acknowledgment or transmission report generated by the machine from which the telefax was sent indicating that the telefax was sent in its entirety and received at the recipient’s telefax number.	
ARTICLE XVIII
MISCELLANEOUS
     18.1 Financial Responsibility. Within two (2) Business Days following execution hereof BAMAGAS shall furnish to CES an absolute and unconditional guaranty from Enbridge (U.S.) Inc. to CES (which guaranty will terminate prospectively upon CES’ exercise of its purchase rights under Section 12.3
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or a sale of the Pipeline to an unaffiliated third party after compliance with the provisions of Section 13.2) in the form and content of Exhibit 5. Contemporaneously with the execution and delivery of this Agreement, CES shall furnish to BAMAGAS an absolute, unconditional guaranty from Calpine to BAMAGAS in the form and content of Exhibit 6 (the “Calpine Corporation Guaranty”).
     18.2 Captions. Captions of the Articles and Sections of this Agreement are for convenience and reference only, and the words contained therein shall in no way be held to explain, modify, amplify, or aid in the interpretation, construction or meaning of the provisions of this Agreement.
     18.3 Non Disclosure. Any information disclosed by a Party that is described herein or that is marked or identified as confidential or proprietary will be treated as confidential information and shall not be used or disclosed by the receiving Party (other than to its Affiliates) without the prior consent of the disclosing Party, except when required to be disclosed by Applicable Law or in connection with regulatory filings. In addition, no Party shall disclose any of the terms of this Agreement (other than to its Affiliates, its lenders or potential lenders, and any other parties now or hereafter owning an equity interest in the Pipeline, the BAMAGAS Lateral(s), the Morgan Energy Center, or any of the Parties to this Agreement) without the prior written consent of the other Party. The foregoing notwithstanding, the steam hosts for Morgan Energy Center shall have the right to review BAMAGAS’ invoices to CES for transportation service.
     Confidential information does not include information that: (i) is or becomes a part of the public domain through no fault of the receiving Party and without breach of this Agreement or other confidentiality agreement; (ii) is received from a third party in good faith where such third party is not obligated to a Party to keep such information confidential; (iii) was in the receiving Party’s possession prior to receipt from the other Party; or (iv) was independently developed by the receiving Party without reference to any such confidential information. To the extent that either Party is required by (i) an applicable federal or state securities law, order, rule or regulation; or (ii) an applicable federal or state law, order, rule or regulation relating to obtaining necessary or desirable permits; to make disclosure of such information or of the terms of the transactions contemplated and the transactions themselves, then such Party shall be permitted to make only those disclosures as are reasonably necessary to be compliant with such applicable law, order, rule or regulation and shall furnish a copy of such disclosure to the other Party as far in advance of such disclosure as is reasonably practicable.
     18.4 Press Releases and Public Announcements. The Parties may issue press releases upon the execution of this Agreement, provided that each Party shall submit to the other Party a copy of its intended press release not less than two (2) Business Days prior to the time of release, for such other Party’s approval. Any Party may make any public disclosure it believes in good faith is required by applicable law or any listing or trading agreement concerning its publicly traded securities (in which case the disclosing Party will use its reasonable best efforts to advise the other Party before making the disclosure).
     18.5 Amendments. No change, amendment or modification of this Agreement, and no further agreement to be made pursuant to this Agreement, shall be valid or binding upon the Parties unless such change, amendment or modification shall be in writing and duly executed by both Parties.
     18.6 Severability. The invalidity of one or more phrases, sentences, clauses or Sections contained in this Agreement shall not affect the validity of the remaining portions of this Agreement so long as the material purposes of this Agreement can be determined and effectuated.
     18.7 Entire Agreement. This Agreement sets forth all of the promises, agreements, conditions and understandings between the Parties relating to the subject matter hereof and supersedes any and all negotiations, other agreements and representations made prior to the date hereof with respect to the same subject matter.
     18.8 No Waiver. Any failure of either Party to enforce any of the provisions of this Agreement or to require compliance with any of its terms at any time during the pendency of this Agreement, shall in no way affect the validity of this Agreement, or any part hereof, and shall not be deemed a waiver of the right of such Party thereafter to enforce any and each such provision. Any consent or approval given pursuant to this Agreement shall be limited to its express terms and shall not otherwise
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increase the obligations of the Party giving such consent or approval or otherwise reduce the obligations of the Party receiving such consent or approval.
     18.9 Further Assurances. Each Party agrees to execute and deliver all further instruments and documents, and take any further action that may be reasonably necessary, to effectuate the purposes and intent of this Agreement.
     18.10 Counterparts. This Agreement may be executed in counterparts, each of which shall be deemed to be an original and both of which together shall be deemed to constitute one and the same agreement.
     18.11 Exhibits, Attachments and Schedules. All references in the Agreement to Exhibits, Attachments and Schedules shall be deemed to be references to the Exhibits, Attachments and Schedules attached hereto as the same may be amended and supplemented pursuant to the terms of this Agreement or otherwise by mutual written agreement of the Parties.
     IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date first hereinabove written.
BAMAGAS Company

By:	 	/s/ I.J. Berthelot II	 	 	
 	 	Name: I.J. Berthelot II	 	 	
 	 	Title: Vice President	 	 	

CALPINE ENERGY SERVICES, L.P.	 	 	
By Its General Partner,	 	 	
CPN Energy Services GP, Inc.	 	 	
 	 	 	 	 	
By:	 	/s/ Diana Knox
 	 	 	
 	 	Name: Diana Knox	 	 	
 	 	Title: Sr. Vice President	 	 	
 24 

 

EXHIBIT 1
Omitted

 

EXHIBIT 2
GAS QUALITY SPECIFICATIONS

1.	 	Natural or Artificial Gas:	
 		
 	 	The gas received or delivered by the Pipeline shall be a combustible gas consisting wholly of, or a mixture of:	

 	(A)	 	Natural gas of the quality and composition produced in its natural state except that the pipeline may extract or permit the extraction of any of the constituents thereof except methane.	
 		
 	(B)	 	Gas generated by vaporization of Liquefied Natural Gas (LNG).	
 		
 	(C)	 	Manufactured, reformed, or mixed gas consisting essentially of hydrocarbons of the quality and character produced by nature in the petroleum, oil and gas fields with physical properties such that when the artificial pipeline gas is commingled with natural gas, the two become indistinguishable.	

2.	 	Total Heating Value:	

 	(A)	 	No gas delivered hereunder shall have a total heating value at the Point of Receipt either below Nine Hundred Sixty Seven (967) or above one thousand one hundred (1100) Btu per cubic foot of dry gas at a temperature of sixty degrees (60°) Fahrenheit and under a pressure of 14.73 psia.	
 		
 	(B)	 	The total heating value shall be determined by gas chromatographic analysis using AGA 3-1990 factors or any revision thereof, or by other methods mutually agreed upon by Customer and Pipeline.	
 		
 	(C)	 	The average total heating value of the gas shall be determined for any billing period by method or methods mutually agreed upon by Customer and Pipeline.	

3.	 	Composition:	

 	(A)	 	Solids:	
 		
 	 	 	The gas shall be commercially free, under continuous gas flow conditions, from objectionable odors, solid matter, dust, gums, and gum-forming constituents which might interfere with its merchantability or cause injury to or interference with proper operations of the pipelines, compressor stations, meters, regulators or other appliances through which it flows.	
 		
 	(B)	 	Oxygen:	
 		
 	 	 	The gas shall not have an uncombined oxygen content in excess of two-tenths (0.2) of one percent (1%) by volume, and both parties shall make every reasonable effort to keep the gas free from oxygen.	
 		
 	(C)	 	Carbon Dioxide and Nitrogen:	

 

 	 	 	The gas shall not contain more than four percent (4%) by volume, of a combined total of carbon dioxide and nitrogen; it being understood, however, that the total carbon dioxide content shall not exceed three percent (3%) by volume.	
 		
 	(D)	 	Liquids:	
 		
 	 	 	The gas shall be free of water and hydrocarbons in liquid form at the temperature and pressure at which the gas is received and delivered.	
 		
 	(E)	 	Hydrogen Sulfide:	
 		
 	 	 	The gas shall not contain more than one-quarter (0.25) grain (4 ppm) of hydrogen sulfide per one-hundred (100) cubic feet.	
 		
 	(F)	 	Total Sulphur:	
 		
 	 	 	The gas shall not contain more than ten (10) grains of total sulphur, excluding any mercaptan sulphur, per one-hundred (100) cubic feet.	
 		
 	(G)	 	Temperature:	
 		
 	 	 	The gas shall not have a temperature of more than one-hundred twenty degrees (120°) Fahrenheit.	
 		
 	(H)	 	Water Vapor:	
 		
 	 	 	The gas shall not contain in excess of seven (7) pounds of water vapor per million cubic feet.	
 		
 	(I)	 	Liquefiable Hydrocarbons:	
 		
 	 	 	The gas shall not contain more than two-tenths (0.2) gallon per thousand cubic feet, of those certain liquefiable hydrocarbons commonly referred to as natural gasoline, as determined by gas chromatographic analysis.	
 		
 	(J)	 	Microbiological Agents:	
 		
 	 	 	     The gas shall not contain, either in the gas or in any liquids with the gas, any microbiological organism, active bacteria or bacterial agent capable of contributing to or causing corrosion and/or operational and/or other problems.	
 		
 	 	 	     Microbiological organisms, bacteria or bacterial agents include, but are not limited to, sulfate reducing bacteria (SRB) and acid producing bacteria (APB). Tests for bacteria or bacterial agents shall be conducted on samples taken from the meter run or the appurtenant piping using American Petroleum Institute (API) test method API-RP38 or any other test method acceptable to Pipeline and Customer which is currently available or may become available at any time.	
This Exhibit may be amended from time to time by mutual consent of the parties, such consent not to be unreasonably withheld to conform to stricter requirements imposed by either the upstream suppliers or transporters at the point(s) of receipt.

 

EXHIBIT 3
POINTS OF RECEIPT/DELIVERY
Points of Receipt
The proposed interconnection between the BAMAGAS Pipeline and Tennessee Gas Pipeline Company located in or near Section 2, Township 4 South, Range 13 West, of Colbert County, Alabama.
The proposed interconnection between the BAMAGAS Pipeline and Texas Eastern Transmission Company located in or near Section 8, Township 4 South, Range 12 West, of Colbert County, Alabama.
The proposed interconnection between the BAMAGAS Pipeline and Midcoast Interstate Transmission Company located at a mutually agreeable location in Morgan County, Alabama.
Points of Delivery
The proposed interconnection between the BAMAGAS Pipeline and Morgan Energy Center located either in or near Section 4, Township 5 South, Range 5 West or Section 11, Township 5 South, Range 5 West, of Morgan County, Alabama (as designated pursuant to the Natural Gas Pipeline Transportation Agreement). More specifically, near the corner of 10 th Street and Red Hat Road.

 

EXHIBIT 4
PIPELINE TERMINATION VALUE
 	 	 	 	 	
YEAR OF	 	 	
TERMINATION OF	 	 	
CONSTRUCTION AND	 	 	
TRANSPORTATION	 	TERMINATION VALUE MORGAN	
AGREEMENT	 	ENERGY CENTER	
1	 	$	33,500,000	 	
2	 	$	32,755,556	 	
3	 	$	32,011,111	 	
4	 	$	31,266,667	 	
5	 	$	30,522,222	 	
6	 	$	29,777,778	 	
7	 	$	29,033,333	 	
8	 	$	28,288,889	 	
9	 	$	27,544,444	 	
10	 	$	26,800,000	 	
11	 	$	26,055,556	 	
12	 	$	25,311,111	 	
13	 	$	24,566,667	 	
14	 	$	23,822,222	 	
15	 	$	23,077,778	 	
16	 	$	22,333,333	 	
17	 	$	21,588,889	 	
18	 	$	20,844,444	 	
19	 	$	20,100,000	 	
20	 	$	19,355,556	 	
21	 	$	18,611,111	 	
22	 	$	17,866,667	 	
23	 	$	17,122,222	 	
24	 	$	16,377,778	 	
25	 	$	15,633,333	 	
26	 	$	14,888,889	 	
27	 	$	14,144,444	 	
28	 	$	13,400,000	 	
29	 	$	12,655,556	 	
30	 	$	11,911,111	 	
31	 	$	11,166,667	 	
32	 	$	10,422,222	 	
33	 	$	9,677,778	 	
34	 	$	8,933,333	 	
35	 	$	8,188,889	 	
36	 	$	7,444,444	 	
37	 	$	6,700,000	 	
38	 	$	5,955,556	 	
39	 	$	5,211,111	 	
40	 	$	4,466,667	 	
41	 	$	3,722,222	 	
42	 	$	2,977,778	 	
43	 	$	2,233,333	 	
44	 	$	1,488,889	 	
45	 	$	744,444	 	
Year 1 begins on the “First Delivery Date” and ends 364 days later (365 days if February of that year contains 29 days).
Year 2, (and/or subsequent years(s)) begin on the ending date of year 1 (and/or subsequent years(s)) and ends 364 days later (365 days later if February of that year contains 29 days).

 

EXHIBIT 5
GUARANTY
     This GUARANTY dated as of June 28, 2000, is made by Enbridge ( U.S. ), Inc. (“Enbridge”), a _______ corporation for the benefit of Calpine Energy Services, L.P. (“ CES ”)
      WHEREAS, BAMAGAS Company (“BAMAGAS”), a Delaware corporation, and CES , a Delaware limited partnership have entered into that certain “Natural Gas Pipeline Construction Agreement” dated as of June 28, 2000 and that certain Natural Gas Pipeline Construction and Transportation Agreements of even date (collectively “Agreements”);
      WHEREAS, pursuant to Section 18.1 of the Agreements, BAMAGAS agreed to furnish CES an absolute, unconditional guaranty from Enbridge to CES of BAMAGAS ’s payment obligations to CES under the Agreements;
     NOW, THEREFORE, in consideration of the foregoing and for good and sufficient consideration in hand received by Enbridge, Enbridge agrees as follows:
     1.  Guaranty . Enbridge irrevocably and unconditionally guarantees to CES the prompt and complete payment when due, by acceleration or otherwise, of all amounts payable or becoming payable by BAMAGAS to CES and the payment of all present and future liabilities of all kinds of BAMAGAS to CES under or pursuant to the Agreements, including, without limitation, damages suffered by CES by reason of BAMAGAS’ breach of any of its representations, warranties, indemnities, covenants and other obligations to CES under the Agreement and any amendments thereto (collectively the “Obligations”) . This is a guaranty of payment and not of collection. If BAMAGAS fails to pay or perform any of the Obligations, for any reason, Enbridge will pay or cause to be paid such Obligations directly for CES ’ benefit promptly upon CES ’ demand therefor and without CES having to make prior demand on BAMAGAS. This Guaranty is a primary obligation of Enbridge and all payments hereunder shall be made without reduction, whether by offset, payment in escrow, or otherwise, except to the extent of any defenses to payment or performance which BAMAGAS may have under the Agreement. Notwithstanding anything to the contrary herein, this Guaranty shall continue to be effective or reinstated, as the case may be, if at any time payment of the Obligations, or any part thereof, is rescinded or must otherwise be returned by CES upon the insolvency, bankruptcy or reorganization of BAMAGAS or otherwise, all as though the payment of such Obligations had not been made.
     2.  Enbridge’s Obligations . Subject to paragraph 3 below, Enbridge’s obligations under this Guaranty are absolute and unconditional, shall remain in force until all Obligations have been paid and performed and shall not be released or discharged for any reason whatsoever prior to such payment and performance, including without limitation:
     (i) the extension of time for payment or performance of any Obligation or the amendment, extension or renewal of the Agreements or any Obligation, except that any such extension, amendment or renewal shall not enlarge Enbridge’s obligations under this Guaranty and Enbridge shall have the benefit of any such extension, amendment or renewal to the same extent as BAMAGAS (e.g., if BAMAGAS’ time for payment of an Obligation has been extended, Enbridge shall have no obligation under this Guaranty to make payment of such Obligation until such time as BAMAGAS is required under the extension to make payment);
          (ii) any delay or failure by CES to enforce or exercise any right or remedy under the Agreement, or waiver by CES of any such right or remedy;
          (iii) the release or discharge of BAMAGAS from the performance or observance of any Obligations by operation of law or otherwise, but only if and to the extent BAMAGAS would otherwise have incurred such Obligations in the absence of such release or discharge;
          (iv) any transfer, assignment or mortgaging by CES of any interest in the Agreements or this Guaranty;

 

          (v) the voluntary or involuntary liquidation, dissolution, sale or other disposition of all or substantially all the assets and liabilities, or the voluntary or involuntary receivership, insolvency, bankruptcy, assignment for the benefit of creditors, reorganization or other similar proceeding affecting BAMAGAS, or the disaffirmance of the Agreements in any such proceeding; or
          (vi) any merger, consolidation or other reorganization to which BAMAGAS, Enbridge or any related entity is a party, or any direct or indirect sale or disposition of Enbridge’s or Enbridge’s assets or Enbridge’s direct or indirect ownership interest in CES .
     Furthermore, Enbridge’s obligations under this Guaranty to CES shall not be limited or impaired in any respect by reason of CES having recourse only to certain assets of BAMAGAS in connection with BAMAGAS’ obligations to CES under the Agreement.
     3.  Assignment . Enbridge may not assign this Guaranty or its obligations thereunder except as expressly provided in Section 13.1 of the Agreements.
     4.  Waivers by Enbridge. Enbridge waives notice of the acceptance of this Guaranty, demand or presentment for payment to BAMAGAS or the making of any protest, notice of the amount of the Obligations outstanding at any time, notice of nonpayment or failure to perform on the part of BAMAGAS, notice of any amendment, modification or waiver of or under the Agreements, and all other notices or demands not specifically required hereunder.
     5.  Representations and Warranties. Enbridge hereby represents and warrants that (i) it has all necessary and appropriate powers and authority to execute and perform under this Guaranty, (ii) that such Guaranty constitutes its legal, valid and binding obligations enforceable against it in accordance with its terms (except as enforceability may be limited by bankruptcy, insolvency, moratorium and other similar laws affecting enforcement of creditors’ rights in general and general principles of equity), and (iii) it expects to derive benefits from each and every extension of credit to BAMAGAS.
     6.  Miscellaneous . No provision of this Guaranty may be amended or waived except by a written instrument executed by Enbridge and CES. This Guaranty shall not be deemed to benefit any person except BAMAGAS and CES. This Guaranty shall inure to the benefit of CES and its successors and assigns. This Guaranty shall be governed by the laws of the State of Texas (excluding any choice of laws rules which would require the application of the law of another jurisdiction).
     7.  Attorneys’ Fees . Enbridge agrees to pay all attorneys’ fees, court costs and other expenses of collection paid or incurred by CES in enforcing Enbridge’s obligations to CES under this Agreement.
     IN WITNESS WHEREOF, Enbridge has executed this Guaranty as of the date first above written.

ENBRIDGE (U.S.) INC.	 	 	
 	 	 	 	 	
By:	 	 	 	 	
Name:	 	 	 	 	
Title:	 	 	 	 	
Date:	 	 	 	 	

 

EXHIBIT 6
GUARANTY
     This GUARANTY dated as of June 28, 2000, is made by Calpine Corporation (“Calpine”), a Delaware corporation for the benefit of BAMAGAS Company (“BAMAGAS”).
      WHEREAS, BAMAGAS, a Delaware corporation, Calpine Energy Services, L.P. (“ CES ”), a Delaware limited partnership, have entered into that certain “Natural Gas Pipeline Transportation Agreement” dated as of June 28, 2000, and that certain Natural Gas Pipeline Construction and Transportation Agreement of even date (collectively “Agreements”);
      WHEREAS, pursuant to Section 18.1 of the Agreements, CES agreed to furnish BAMAGAS an absolute, unconditional guaranty from Calpine to BAMAGAS of CES’ payment obligations to BAMAGAS under the Agreements;
     NOW, THEREFORE, in consideration of the foregoing and for good and sufficient consideration in hand received by Calpine, Calpine agrees as follows:
     1.  Guaranty . Calpine irrevocably and unconditionally guarantees to BAMAGAS the prompt and complete payment when due, by acceleration or otherwise, of all amounts payable or becoming payable by CES to BAMAGAS and the payment of all present and future liabilities of all kinds of CES to BAMAGAS under or pursuant to the Agreement, including, without limitation, damages suffered by BAMAGAS by reason of CES ’ breach of any of its representations, warranties, indemnities, covenants and other obligations to BAMAGAS under the Agreement and any amendments thereto (collectively the “Obligations”) . This is a guaranty of payment and not of collection. If CES fails to pay or perform any of the Obligations, for any reason, Calpine will pay or cause to be paid such Obligations directly for BAMAGAS’ benefit promptly upon BAMAGAS’ demand therefor and without BAMAGAS having to make prior demand on CES . This Guaranty is a primary obligation of Calpine and all payments hereunder shall be made without reduction, whether by offset, payment in escrow, or otherwise, except to the extent of any defenses to payment or performance which CES may have under the Agreement. Notwithstanding anything to the contrary herein, this Guaranty shall continue to be effective or reinstated, as the case may be, if at any time payment of the Obligations, or any part thereof, is rescinded or must otherwise be returned by BAMAGAS upon the insolvency, bankruptcy or reorganization of CES or otherwise, all as though the payment of such Obligations had not been made.
     2.  Calpine’s Obligations . Subject to paragraph 3 below, Calpine’s obligations under this Guaranty are absolute and unconditional, shall remain in force until all Obligations have been paid and performed and shall not be released or discharged for any reason whatsoever prior to such payment and performance, including without limitation:
     (i) the extension of time for payment or performance of any Obligation or the amendment, extension or renewal of the Agreements or any Obligation, except that any such extension, amendment or renewal shall not enlarge Calpine’s obligations under this Guaranty and Calpine shall have the benefit of any such extension, amendment or renewal to the same extent as CES (e.g., if CES ’ time for payment of an Obligation has been extended, Calpine shall have no obligation under this Guaranty to make payment of such Obligation until such time as CES is required under the extension to make payment);
     (ii) any delay or failure by BAMAGAS to enforce or exercise any right or remedy under the Agreement, or waiver by BAMAGAS of any such right or remedy;
     (iii) the release or discharge of CES from the performance or observance of any Obligations by operation of law or otherwise, but only if and to the extent CES would otherwise have incurred such Obligations in the absence of such release or discharge;
     (iv) any transfer, assignment or mortgaging by BAMAGAS of any interest in the Agreements or this Guaranty;

 

     (v) the voluntary or involuntary liquidation, dissolution, sale or other disposition of all or substantially all the assets and liabilities, or the voluntary or involuntary receivership, insolvency, bankruptcy, assignment for the benefit of creditors, reorganization or other similar proceeding affecting CES , or the disaffirmance of the Agreements in any such proceeding; or
     (vi) any merger, consolidation or other reorganization to which CES , Calpine or any related entity is a party, or any direct or indirect sale or disposition of Calpine’s or CES’s assets or Calpine’s direct or indirect ownership interest in CES .
     Furthermore, Calpine’s obligations under this Guaranty to BAMAGAS shall not be limited or impaired in any respect by reason of BAMAGAS having recourse only to certain assets of CES in connection with CES ’ obligations to BAMAGAS under the Agreement.
     3.  Assignment . Calpine may not assign this Guaranty or its obligations thereunder except as expressly provided in Section 13.1 of the Agreements.
     4.  Waivers by Calpine . Calpine waives notice of the acceptance of this Guaranty, demand or presentment for payment to CES or the making of any protest, notice of the amount of the Obligations outstanding at any time, notice of nonpayment or failure to perform on the part of CES , notice of any amendment, modification or waiver of or under the Agreement, and all other notices or demands not specifically required hereunder.
     5.  Representations and Warranties . Calpine hereby represents and warrants that (i) it has all necessary and appropriate powers and authority to execute and perform under this Guaranty, (ii) that such Guaranty constitutes its legal, valid and binding obligations enforceable against it in accordance with its terms (except as enforceability may be limited by bankruptcy, insolvency, moratorium and other similar laws affecting enforcement of creditors’ rights in general and general principles of equity), and (iii) it expects to derive benefits from each and every extension of credit to CES or CES.
     6.  Miscellaneous . No provision of this Guaranty may be amended or waived except by a written instrument executed by Calpine and BAMAGAS. This Guaranty shall not be deemed to benefit any person except CES and BAMAGAS. This Guaranty shall inure to the benefit of BAMAGAS and its successors and assigns. This Guaranty shall be governed by the laws of the State of Texas (excluding any choice of laws rules which would require the application of the law of another jurisdiction).
     7.  Attorneys’ Fees . Calpine agrees to pay all attorneys’ fees, court costs and other expenses of collection paid or incurred by BAMAGAS in enforcing Calpine’s obligations to BAMAGAS under this Agreement.
     IN WITNESS WHEREOF, Calpine has executed this Guaranty as of the date first above written.

CALPINE CORPORATION	 	 	
 	 	 	 	 	
By:	 	 	 	 	
Name:	 	 	 	 	
Title:	 	 	 	 	
Date:	 	 	 	 	

 

EXHIBIT 7
PROPERTY RIGHTS ASSIGNABLE TO BAMAGAS
None. CES will supplement this Exhibit over the term of the Agreement upon acquisition or assignment of any property rights.

 

EXHIBIT 8
OPERATIONAL BALANCING AGREEMENT
BETWEEN
BAMAGAS COMPANY

AND
CALPINE ENERGY SERVICES, L.P.
     This Operational Balancing Agreement (this “Agreement”) is entered into as of the ________________ between BAMAGAS Company a Delaware corporation (“BAMAGAS”), and Calpine Energy Services, L.P. a Delaware limited partnership (“CES”) (individually a “Party” or collectively “Parties”).
     WHEREAS, BAMAGAS CES entered into that certain Natural Gas Pipeline Transportation Agreement dated June 28, 2000, (“Transportation Agreement”), under which BAMAGAS will construct, own, operate and maintain a new intrastate pipeline and related facilities (whether existing or new) in the State of Alabama (“Pipeline”) and will transport on a firm basis on the Pipeline, certain quantities of natural gas (“Gas”) to the Morgan Energy Center (as said term is defined in the Transportation Agreement);
     WHEREAS, the Pipeline interconnects at the Interconnection Point(s) specified on Attachment 2 attached hereto;
     WHEREAS, pursuant to the Natural Gas Pipeline Transportation Agreement CES, will cause Gas to be delivered to BAMAGAS at the Interconnection Point(s) for transportation and redelivery by BAMAGAS at the Morgan Energy Center;
     WHEREAS, from time to time, the quantities of Gas actually delivered to BAMAGAS at the Interconnection Point(s) will be either greater than or less than the quantities of Gas nominated, confirmed and scheduled by the Parties, resulting in inadvertent over - or underdeliveries of CES’ scheduled quantities;
     WHEREAS, the Parties desire to provide for the elimination of such over - and under - deliveries by adjusting deliveries and receipts of Gas at the Interconnection Point(s);
     NOW, THEREFORE the Parties agree that such over - or underdeliveries of Gas at the Interconnection Point(s) shall be eliminated in the following manner:
ARTICLE I
CORRECTION OF OPERATIONAL IMBALANCES

1.1	 	Operational Imbalance(s) - The Parties intend that the MMBtu of Gas actually delivered and received each day at each Interconnection Point will equal the confirmed scheduled nominations of the Parties to be delivered or received therefrom. Any variance between the actual physical flow of Gas at an Interconnection Point each day and the confirmed scheduled nominations of receipts and deliveries for that Interconnection Point for such day is an “Operational Imbalance”, which Operational Imbalance is the responsibility of the Parties to eliminate pursuant to this Agreement.	

 

1.2	 	Corrections During the Month - BAMAGAS shall provide to CES on a daily basis electronically or in writing the estimated daily metered Gas quantities, or actual daily metered Gas quantities, if applicable, for purposes of adjustments to determine the estimated or actual Operational Imbalance at each Interconnection Point, as applicable. BAMAGAS shall also make available to CES the monthly Operational Imbalance at each delivery or receipt meter. Subject to CES’ available capacity on the Pipeline (CES’ available capacity being the difference between actual deliveries for the account of CES and the Firm Transportation Quantity as said term is defined in the Natural Gas Pipeline Transportation Agreement), CES may correct the Operational Imbalance in kind by nominating make up Gas quantities on any day during the same month in which the Operational Imbalance occurs in accordance with BAMAGAS’ nomination deadline procedures.	
 		
1.3	 	Corrections in Subsequent Periods — The cumulative Operational Imbalance at each Interconnection Point each month will be determined and communicated by BAMAGAS to CES electronically or in writing as soon as possible, but no later than the first business day after the last day of each month. To the extent that BAMAGAS has the right to balance in kind pursuant to the respective operational balancing agreements it enters into with CES’ upstream suppliers or transporters, as identified on Exhibit 3 to the Natural Gas Pipeline Transportation Agreement (collectively, the “BAMAGAS Balancing Agreements”), CES shall have the right to balance in kind the cumulative Operational Imbalance(s) during the month subsequent to the month in which the Operational Imbalance(s) were created (“Subsequent Month”) by nominating additional Gas quantities in accordance with the procedures of the applicable BAMAGAS Balancing Agreements. To the extent BAMAGAS does not have the right to balance in kind under any of the BAMAGAS Balancing Agreements any or all of the cumulative Operational Imbalance at each Interconnection Point during any given month or, if BAMAGAS has such right but CES fails to correct the monthly Operational Imbalance on or before the last day of the Subsequent Month, then BAMAGAS shall be entitled to cash out the remaining Operational Imbalance quantities for the same price and on the same terms and provisions as provided in the applicable BAMAGAS Balancing Agreements; it being the express intent of the Parties that BAMAGAS shall at all times be kept whole by CES and CES with respect to any differences in the price or method of balancing Operational Imbalances at each Interconnection Point each month between this Agreement and the applicable BAMAGAS Balancing Agreement(s) then in effect. Measurement of Gas under this Agreement shall be made in accordance with the applicable provisions in the FERC Gas Tariffs of the interstate pipelines interconnecting with BAMAGAS at the respective Interconnection Point(s).	
 		
1.4	 	BAMAGAS shall endeavor to negotiate the terms and provisions of the BAMAGAS Balancing Agreements so that balancing may be had by BAMAGAS in kind during the month subsequent to the month in which the imbalances were created; however, if BAMAGAS is unable to negotiate such terms and provisions, but CES is able to do so, then BAMAGAS, at its election, may utilize those operation balancing agreement(s) of CES with CES’ upstream suppliers or transporters containing such provisions.	
 		
1.5	 	In the event that a capacity constraint occurs on BAMAGAS’ Pipeline which results in curtailment of Gas quantities at an Interconnection Point, BAMAGAS shall determine the reallocation of Gas quantities to shippers on the Pipeline in accordance with Section 2.8 of the Transportation Agreement.	

 

ARTICLE II
TERM

 	 	Duration of Agreement - This Agreement shall be effective from the date hereof and shall remain in effect until such time as the Natural Gas Pipeline Transportation Agreement between BAMAGAS and CES terminates.	
ARTICLE III
MISCELLANEOUS

3.1	 	Disputes - If a dispute arise as a result of the provisions of this Agreement, the Parties will enter into good faith negotiations to resolve the dispute and amend this Agreement, if appropriate. If the Parties are unable to resolve such problems as a result of such negotiations the dispute shall be submitted to arbitration in accordance with Article XVII of the Transportation Agreement.	
 		
3.2	 	Governing Bodies - This Agreement shall be subject to all applicable laws, Federal or State and to all applicable rules and regulations of any duly authorized Federal, State or other government agency having jurisdiction over the transactions described herein. The interpretation and performance of this Agreement shall be in accordance with and controlled by the laws of the State of Texas, without regard to principles of conflicts of law.	
 		
3.3	 	Waivers - No waiver by either Party of any one or more defaults by the other in the performance of this Agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character.	
 		
3.4	 	Notices - Any notice under this Agreement shall be in writing and mailed to the post office address of the party intended to receive the same, as follows:	
NOTICES:
BAMAGAS Company
1100 Louisiana, Suite 2900
Houston, Texas 77002
Attn: President
Tel.: (713) 650-8900
Fax: (713) 653-6711
Calpine Energy Services, L.P.
700 Louisiana, Suite 2700
Houston, Texas 77002
Attention: Jeff Rawls, Vice President – Producer
Services
Tel.: (713) 830-8636
Fax: (713) 830-8712

 	 	With regard to operational matters, the Parties shall have the right to designate different personnel or locations to receive notices.	
 		
3.5	 	Conflicts - If there is any conflict or discrepancy between this Agreement and a BAMAGAS Balancing Agreement with regard to allocations at any Interconnection Point, the terms of the applicable BAMAGAS Balancing Agreement shall govern and control.	

 

The Parties’ signature below will evidence their agreement to this Operational Balancing Agreement.

 	 	BAMAGAS COMPANY	
 	 	 	 	 	
 	 	By:	 	 	

 	 	 	 	 	
 	 	Title:	 	 	

 	 	 	 	 	
 	 	Date:	 	 	

 	 	 	 	 	
 	 	CALPINE ENERGY SERVICES, L.P.	
 	 	 	 	 	
 	 	By:	 	 	

 	 	 	 	 	
 	 	Title:	 	 	

 	 	 	 	 	
 	 	Date:	 	 	

   

 

ATTACHMENT 2
BAMAGAS COMPANY
AND
CALPINE ENERGY SERVICES, L.P.
Interconnection Point(s) between                                          and                                   .
Meter Name(s)

 

EXHIBIT 9
USE RESTRICTIONS
     The Pipeline and the BAMAGAS Lateral(s), including, without limitation, the rights-of-way and easements pertaining thereto, which may be acquired by CES, its successors or assigns, pursuant to the exercise of CES’ purchase rights under Section 13.2 of the Natural Gas Transportation Agreement to which this Exhibit 9 is attached and made a part thereof (the “Agreement”), shall be assigned and conveyed to CES, its successors or assigns, limited to the following uses (the “Use Restrictions”), and CES represents, warrants and covenants, on behalf of itself and its successors and assigns, to BAMAGAS, Enbridge (in consideration for Enbridge’s guaranty of the performance of BAMAGAS’ obligations to CES under this Agreement), and the Affiliates of both of them, that the Pipeline and the BAMAGAS Lateral(s), including, without limitation, the rights-of-way and easements pertaining thereto, shall not be utilized in violation of the Use Restrictions, to-wit: for the transportation of Gas to the Morgan Energy Center and to any other parties except for transportation to then existing shippers or Gas end users with which the Affiliated Transportation Parties have entered into either transportation service agreements on the Pipeline and/or the BAMAGAS Lateral(s) or Gas sales agreements utilizing transportation service, in whole or in part, on the Pipeline and/or the BAMAGAS Lateral(s), until such time as the transportation rights of the Affiliated Transportation Parties on the Pipeline and the BAMAGAS Lateral(s) expire, as set forth in Exhibit 11 of this Agreement. The foregoing notwithstanding, if (i) CES exercises its step in rights under Section 2.3 of the Natural Gas Pipeline Construction and Transportation Agreement and completes construction of the Pipeline and the BAMAGAS Lateral(s), and/or (ii) BAMAGAS elects not to reimburse CES for the expenses incurred by CES in the exercise of its step in rights under Section 2.3 of the Natural Gas Pipeline Construction and Transportation Agreement and elects not to complete the construction of the Pipeline and the BAMAGAS Lateral(s), and/or (iii) an Event of Default occurs under Section 12.1 under the Natural Gas Pipeline Construction and Transportation Agreement (b) and CES, it successors or assigns exercise their purchase rights under Section 13.2 of the Agreement, and/or (iv) CES, its successors or assigns, exercise their right of first refusal under Section 13.2 of the Agreement, then in any such event CES, its successors or assigns, shall not be subject to any Use Restrictions and have the right to use the Pipeline, the BAMAGAS Lateral(s) and associated rights of way and easements for any purpose.
     The foregoing covenants of CES shall be deemed covenants running with the Pipeline and BAMAGAS Lateral(s), including, without limitation, the rights-of-way and easements pertaining thereto, and shall be binding upon each subsequent owner of the Pipeline and/or the BAMAGAS Lateral(s), or any interest therein. Any entity which shall succeed by purchase, merger or consolidation to CES, or CES’ rights under the Agreement, shall be bound by the foregoing representations, warranties and covenants of CES.

 

EXHIBIT 10
HYDRAULIC MODEL
Part I — Pipeline Flow Schematic for Decatur Energy Center (“DEC”) only.
Part II — Receipt and Delivery Pressures vs. Volume Trend Plot for DEC only.
Part III — Receipt and Delivery Pressures vs. Volume Trend Plot for DEC only.
Part IV — Receipt and Delivery Pressures vs. Volume Trend Plot for DEC only.
Part V — Receipt and Delivery Volumes and Timing for Part II, Part III, and Part IV.
Part VI — Pipeline Flow Schematic for DEC1 and Morgan Energy Center (“MEC”).
Part VII — Receipt and Delivery Pressures vs. Volumes Trend Plot for DEC and MEC.
Part VIII — Receipt and Delivery Pressures vs. Volume Trend Plot for DEC and MEC.
Part IX — Receipt and Delivery Pressures vs. Volume Trend Plot for DEC and MEC.
Part X — Receipt and Delivery Volumes and Timing for Part VI, Part VII, and Part VIII.
The model that was used is a transient gas network analysis package developed by LICENERGY, Inc. (LIC). This company is now a part of ENERGY SOLUTIONS INTERNATIONAL. This software is capable of performing two types of simulations — steady state and transient. The present version of the software is called Pipeline Studio Version 2.0, capable of running in Windows 95, 98, NT and also Windows 2000.

 

Exhibit 11 - Part I
Pipeline Flow Schematic for Decatur Energy Center (“DEC”) Only.

 

Exhibit 11 - Part II
Receipt and Delivery Pressures vs. Volume Trend Plot for DEC only.

 

Exhibit 11 - Part III
Receipt and Delivery Pressures vs. Volume Trend Plot for DEC only.

 

Exhibit 11 - Part IV
Receipt and Delivery Pressures vs. Volume Trend Plot for DEC only.

 
EXHIBIT 11 - PART V

Decator Energy Center
COLEBROOK-675PSIG/500PSIG - 20' P/L
RECIEPT VOLUMES VS DELIVERY VOLUMES USED IN
EXHIBIT 11 PART II. III. & IV

Device Type	 	EXHIBIT 11 PART II	 	 	EXHIBIT 11 PART III	 	 	EXHIBIT 11 PART IV	 	
Name	 	Supply	 	 	Delivery	 	 	Supply	 	 	Delivery	 	 	Supply	 	 	Delivery	 	
Setpoint	 	Tenn Barton	 	 	Solutia	 	 	Tenn Barton	 	 	Solutia	 	 	Tenn Barton	 	 	Solutia	 	
Units	 	Flow Maximum	 	 	Flow Maximum	 	 	Flow Maximum	 	 	Flow Maximum	 	 	Flow Maximum	 	 	Flow Maximum	 	
Initial	 	MMCFD	 	 	MMCFD	 	 	MMCFD	 	 	MMCFD	 	 	MMCFD	 	 	MMCFD	 	
Flow Hour	 	 	138	 	 	 	138	 	 	 	120	 	 	 	31	 	 	 	138	 	 	 	138	 	
1	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	0	 	
2	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	0	 	
3	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	0	 	
4	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	0	 	
5	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	0	 	
6	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	0	 	
7	 	 	138	 	 	 	138	 	 	 	75	 	 	 	100	 	 	 	138	 	 	 	138	 	
8	 	 	138	 	 	 	138	 	 	 	110	 	 	 	124	 	 	 	138	 	 	 	138	 	
9	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
10	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
11	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
12	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
13	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
14	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
15	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
16	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
17	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
18	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
19	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
20	 	 	138	 	 	 	138	 	 	 	88	 	 	 	100	 	 	 	138	 	 	 	138	 	
21	 	 	138	 	 	 	138	 	 	 	60	 	 	 	75	 	 	 	138	 	 	 	138	 	
22	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
23	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
24	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
25	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
26	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
27	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
28	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
29	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
30	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
31	 	 	138	 	 	 	138	 	 	 	75	 	 	 	100	 	 	 	138	 	 	 	138	 	
32	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
33	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
34	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
35	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
36	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
37	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	0	 	
38	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	0	 	
39	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	0	 	
40	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	0	 	
41	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	0	 	
42	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	0	 	
43	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	0	 	
44	 	 	138	 	 	 	138	 	 	 	88	 	 	 	100	 	 	 	138	 	 	 	0	 	
45	 	 	138	 	 	 	138	 	 	 	60	 	 	 	75	 	 	 	138	 	 	 	138	 	
46	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
47	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
48	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
49	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
50	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
51	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
52	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
53	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
54	 	 	138	 	 	 	138	 	 	 	45	 	 	 	31	 	 	 	138	 	 	 	138	 	
55	 	 	138	 	 	 	138	 	 	 	75	 	 	 	100	 	 	 	138	 	 	 	138	 	
56	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
57	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
58	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
59	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	
60	 	 	138	 	 	 	138	 	 	 	118	 	 	 	124	 	 	 	138	 	 	 	138	 	

 

Exhibit 11 - Part VI
Pipeline Flow Schematic for DEC and MEC

 

Part VII
Receipt and Delivery Pressures vs. Volumes Trend Plot for DEC and MEC

 

Exhibit 11 - Part VIII
Receipt and Delivery Pressures vs. Volume Trend Plot for DEC and MEC

 

Exhibit 11 - Part IX
Receipt and Delivery Pressures vs. Volume Trend Plot for DEC and MEC

 
EXHIBIT 11 - PART X
Decatur Energy Center & Morgan ENERGY Center
COLEBROOK-675PSIG/500PSIG — 26" P/L
RECIEPT VOLUMES VS DELIVERY VOLUMES USED IN EXHIBIT 11 PART VII. VIII. & IX
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	EXHIBIT 11 PART VII	 	 	EXHIBIT 11 PART VIII	 	 	EXHIBIT 11 PART IX	 	 	 	 	
 		
Device Type	 	 	 	 	 	 	 	 	 	 	 	 	
Name	 	Supply	 	 	Delivery	 	 	Supply	 	 	Delivery	 	 	Supply	 	 	Delivery	 	 	Delivery	 	
Setpoint	 	Tenn Barton	 	 	Solutia	 	 	Tenn Barton	 	 	Solutia	 	 	Tenn Barton	 	 	Solutia	 	 	Amoco	 	
Units	 	Flow Maximum	 	 	Flow Maximum	 	 	Flow Maximum	 	 	Flow Maximum	 	 	Flow Maximum	 	 	Flow Maximum	 	 	Flow Maximum	 	
Initial	 	MMCFD	 	 	MMCFD	 	 	MMCFD	 	 	MMCFD	 	 	MMCFD	 	 	MMCFD	 	 	MMCFD	 	
Flow Hour	 	 	276	 	 	 	276	 	 	 	240	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
1	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	0	 	 	 	0	 	
2	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	0	 	 	 	0	 	
3	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	0	 	 	 	0	 	
4	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	0	 	 	 	0	 	
5	 	 	276	 	 	 	276	 	 	 	90	 	 	 	92	 	 	 	278	 	 	 	0	 	 	 	0	 	
6	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	0	 	 	 	0	 	
7	 	 	276	 	 	 	276	 	 	 	236	 	 	 	200	 	 	 	278	 	 	 	140	 	 	 	138	 	
8	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
9	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
10	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
11	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
12	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
13	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
14	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
15	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
16	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
17	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
18	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
19	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
20	 	 	276	 	 	 	276	 	 	 	175	 	 	 	200	 	 	 	278	 	 	 	140	 	 	 	138	 	
21	 	 	276	 	 	 	276	 	 	 	150	 	 	 	150	 	 	 	278	 	 	 	140	 	 	 	138	 	
22	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
23	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
24	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
25	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
26	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
27	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
28	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
29	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
30	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
31	 	 	276	 	 	 	276	 	 	 	200	 	 	 	200	 	 	 	278	 	 	 	140	 	 	 	138	 	
32	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
33	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
34	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
35	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
36	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
37	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	0	 	 	 	0	 	
38	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	0	 	 	 	0	 	
39	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	0	 	 	 	0	 	
40	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	0	 	 	 	0	 	
41	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	0	 	 	 	0	 	
42	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	0	 	 	 	0	 	
43	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	0	 	 	 	0	 	
44	 	 	276	 	 	 	276	 	 	 	175	 	 	 	200	 	 	 	278	 	 	 	0	 	 	 	0	 	
45	 	 	276	 	 	 	276	 	 	 	150	 	 	 	150	 	 	 	278	 	 	 	140	 	 	 	138	 	
46	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
47	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
48	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
49	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
50	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
51	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
52	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
53	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
54	 	 	276	 	 	 	276	 	 	 	90	 	 	 	62	 	 	 	278	 	 	 	140	 	 	 	138	 	
55	 	 	276	 	 	 	276	 	 	 	200	 	 	 	200	 	 	 	278	 	 	 	140	 	 	 	138	 	
56	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
57	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
58	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
59	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	
60	 	 	276	 	 	 	276	 	 	 	236	 	 	 	248	 	 	 	278	 	 	 	140	 	 	 	138	 	

 

EXHIBIT 11

TRANSPORTATION RIGHTS
     Following any acquisition of the Pipeline and/or the BAMAGAS Lateral(s) by CES, its successors or assigns, pursuant to any of the provisions of the Natural Gas Pipeline Transportation Agreement to which this Exhibit 11 is attached and made a part thereof, BAMAGAS and the marketing Affiliates of both BAMAGAS and Enbridge (collectively, the “Affiliated Transportation Parties”) shall have the right to transport on the Pipeline and the BAMAGAS Lateral(s), on a firm basis as to all pipeline capacity in excess of the Firm Transportation Quantity, Gas quantities under transportation agreements then in effect between (i) BAMAGAS and any of the other Affiliated Transportation Parties, (ii) BAMAGAS and any third parties, and (iii) any of the Affiliated Transportation Parties and any third parties, for and during the term of each such agreement, not to exceed, however, the lesser of a period of ten (10) years from the date of acquisition of the Pipeline and the BAMAGAS Lateral(s) by CES or a period of five (5) years following the expiration of the Initial Term, if acquired during the Initial Term, or a period of five (5) years from the date of acquisition of the Pipeline and the BAMAGAS Lateral(s) by CES, if acquired during any Renewal Term. BAMAGAS, its successors and assigns, shall pay CES, its successors and assigns, for such transportation a prorata percentage of the operation and maintenance expenses related to the operation of the Pipeline and the BAMAGAS Lateral(s) based upon the annual Gas throughput of the Affiliated Transportation Parties as compared to the total annual Gas throughput of all parties shipping on the Pipeline and the BAMAGAS Lateral(s).

Exhibit 10.19
FIRST AMENDMENT
to
NATURAL GAS PIPELINE TRANSPORTATION AGREEMENT
Dated as of June 28, 2000
between
BAMAGAS COMPANY
and
CALPINE ENERGY SERVICES, L.P.
     This FIRST AMENDMENT to the NATURAL GAS PIPELINE TRANSPORTATION AGREEMENT (“Amendment”) is entered into on this 1st day of September, 2001, between BAMAGAS Company and Calpine Energy Services, L.P. (collectively the “Parties” and/or individually a “Party”).
     WHEREAS, the Parties desire to modify the Natural Gas Pipeline Transportation Agreement dated as of June 28, 2000, between BAMAGAS Company and Calpine Energy Services, L.P. (“Agreement”):
     NOW, THEREFORE, in consideration of the premises and the mutual covenants and promises herein contained, the Parties agree as follows:
1. The definition of “Point(s) of Delivery” in Exhibit 3 of the Agreement is hereby deleted and replaced with the following definition:
“Point(s) of Delivery” shall mean the proposed interconnection between the BAMAGAS Pipeline and the upstream side of the most northerly 16” valve located inside a one hundred by one hundred foot gas metering station located in the southwest quarter of the northwest quarter and the northwest quarter of the southwest quarter of Section 4, Township 5 South Range 5 West, Morgan County, Alabama.
2. The definition of “Primary Point(s) of Delivery” in Article I of the Agreement is hereby deleted and replaced with the following definition:
“Primary Point(s) of Delivery” shall mean the point of interconnection between the BAMAGAS Pipeline and the upstream side of the most northerly 16” valve located inside a one hundred by one hundred foot gas metering station located in the southwest quarter of the northwest quarter and the northwest quarter of the southwest quarter of Section 4, Township 5 South Range 5 West, Morgan County, Alabama.
3. The definition of “ROW” in Article I of the Agreement is hereby deleted.
 1 of 2 

 

4. The definition of “BAMAGAS Lateral(s)” in Article I of the Agreement is hereby deleted and replaced with the following definition:
“BAMAGAS Lateral(s)” shall mean the non FERC jurisdictional pipeline(s) to be constructed by BAMAGAS for the purpose of transporting Natural Gas from the pipeline facilities of Midcoast Interstate Transmission Company to the (a) Primary Point(s) of Delivery and (b) the Primary Point(s) of Delivery (as defined in the Decatur Energy Center Construction and Transportation Agreement), which pipeline(s) shall be used for the testing of the Morgan Energy Center and for Gas transportation service during time periods that the Pipeline is unavailable to transport the Firm Transportation Quantity as provided for herein.
5. Except as provided in numbered paragraphs 1-4 above, there are no other changes to the Agreement under which this Amendment is issued and the Agreement remains in full force and effect. To the extent of any inconsistency between this Amendment and the Agreement, the Agreement shall govern, except to the extent explicitly modified by this Amendment.
     IN WITNESS WHEREOF, the Parties have caused this Amendment to be executed in their respective names by duly authorized officers in duplicate originals on the day and year first entered above.

CALPINE ENERGY SERVICES, L.P.	 	 	 	BAMAGAS COMPANY	 	 	
 	 	 	 	 	 	 	 	 	 	 	
By:	 	/s/ Diana Knox 	 	 	 	By:	 	/s/ I.J. Berthelot	 	 	
Name:	 	 
Diana Knox	 	 	 	Name:	 	 
I.J. “Chip” Berthelot	 	 	
Title:	 	Sr. Vice President	 	 	 	Title:	 	Vice President Commercial Activity	 	 	
 2 of 2 

Exhibit 10.20
FT CONTRACT NO. 6066
     THIS AGREEMENT is made and entered into as of the 1st day of May 1, 2003 by and between ENBRIDGE PIPELINES (ALATENN) , L.L.C., hereinafter referred to as “Transporter” and CITY OF HUNTSVILLE , a municipal corporation, d/b/a HUNTSVILLE UTILITIES, hereinafter referred to as “Shipper.” Transporter and shipper shall collectively be referred to herein as the “Parties.”
W I T N E S S E T H:
     That in consideration of the premises and of the mutual covenants and agreements herein contained, Transporter and Shipper agree as follows:
ARTICLE I
DEFINITIONS

1.1	 	TRANSPORTATION QUANTITY — shall mean the Maximum Daily Quantity (“MDQ”) of gas which Transporter agrees to receive and transport, subject to Article II herein, for the account of Shipper hereunder, which on each day shall be 15,281 dekatherms. Any limitations of the quantities to be received from each Point of Receipt and/or delivered to each Point of Delivery shall be as specified on Exhibit(s) A and B attached hereto.	
 		
1.2	 	EQUIVALENT QUANTITY — shall mean that the quantities of gas delivered hereunder at the Point(s) of Delivery shall be the thermal equivalent of the quantities of gas received at the Point(s) of Receipt for transportation less, the Fuel and Losses Quantity associated with this transportation service in accordance with Section 6 of Rate Schedule FT.	
ARTICLE II
TRANSPORTATION SERVICE

 	 	Transporter agrees to accept and receive daily on a firm basis, at the Point(s) of Receipt from Shipper or for Shipper’s account such quantity of gas as Shipper makes available up to the MDQ, excluding fuel and losses, as specified in Section 1.1 and to transport and deliver to or for the account of Shipper to the Point(s) of Delivery an equivalent quantity of gas; provided, that Transporter, at its option, may agree to receive, transport and deliver quantities	
 1 

 

of gas in excess of the amounts specified in Section 1.1, subject to the limitations and conditions specified in Section 2 of Rate Schedule FT.
ARTICLE III
PRIMARY POINT(S) OF RECEIPT AND DELIVERY

3.1	 	The Primary Point(s) of Receipt and Delivery shall be those points specified on Exhibit(s) A and B attached hereto.	
 		
3.2	 	Shipper may supplement Primary Point(s) of Receipt and/or Point(s) of Delivery provided by this Contract by submitting to Transporter a Customer Nomination Form. Such request form, after having been fully processed and accepted by Transporter, shall be deemed to have the full force and effect of a written Contract and shall qualify as a supplementary written consent pursuant to Paragraph 17.3 of this Contract. Priority of transportation service to such additional Points of Receipt and/or Delivery shall be determined pursuant to Section 3 of the General Terms and Conditions of Transporter’s FERC Gas Tariff. Shipper may nominate Secondary Point(s) of Receipt and/or Delivery within Shipper’s MDQ by submitting to Transporter a revised Customer Nomination Form.	
ARTICLE IV
FACILITIES
     All facilities are in place to render the service provided for in this Contract.
ARTICLE V
RECEIPT AND DELIVERY PRESSURES
     Shipper shall deliver or cause to be delivered to Transporter the gas to be transported hereunder at pressures sufficient to deliver such gas into Transporter’s system at the Point(s) of Receipt. Transporter shall deliver the gas to be transported hereunder to or for the account of Shipper at the pressures existing in Transporter’s system at the Point(s) of Delivery.
ARTICLE VI
QUALITY SPECIFICATIONS AND STANDARDS FOR MEASUREMENT
     For all gas received, transported and delivered hereunder the parties agree to the Quality Specifications and Standards for Measurement as specified in the General Terms and Conditions of Transporter’s FERC Gas Tariff Second Revised Volume No. 1. To the extent that no new measurement facilities are installed to provide service hereunder, measurement operations will continue in the
 2 

 

manner in which they have previously been handled. In the event that such facilities are not operated by Transporter then responsibility for operations shall be deemed to be Shipper’s. Any exceptions to this Article shall be specified on Exhibits(s) N/A attached hereto.
ARTICLE VII
RATES AND CHARGES FOR GAS TRANSPORTATION

7.1	 	TRANSPORTATION RATES — Commencing with the date of execution the compensation to be paid by Shipper to Transporter for the transportation service provided herein, including system fuel and losses, shall be in accordance with Transporter’s Rate Schedule FT and the General Terms and Conditions of Transporter’s FERC Gas Tariff.	
 		
7.2	 	NEW FACILITIES CHARGE — N/A	
 		
7.3	 	INCIDENTAL CHARGES — Shipper agrees to reimburse Transporter for any filing or similar fees and taxes, which have not been previously paid by shipper, which Transporter incurs in rendering service hereunder.	
 		
7.4	 	OTHER CHARGES — Shipper agrees to pay, if applicable, other charges as listed in Section 5.4, 5.5, 5.6, 5.7 and 5.8 of Rate Schedule FT.	
 		
7.5	 	CHANGES IN RATES AND CHARGES — Transporter shall have the unilateral right to file and make effective changes in the rates and charges stated in this Article, the rates and charges applicable to service pursuant to Transporter’s Rate Schedule FT, the Rate Schedule pursuant to which this service is rendered and/or any provisions of the General Terms and Conditions in Transporter’s FERC Gas Tariff applicable to this service. Without prejudice to Shipper’s right to contest such changes, Shipper agrees to pay the effective rates and charges for service rendered pursuant to this Contract.	
ARTICLE VIII
BILLINGS AND PAYMENT
     Transporter shall bill and Shipper shall pay all rates and charges in accordance with Section 5 and 6, respectively, of the General Terms and Conditions of Transporter’s FERC Gas Tariff.
 3 

 

ARTICLE IX *
TAXES
     Shipper agrees to pay the amount of any tax and/or any increase of any additional tax (as tax and additional tax is defined in the next sentence hereof) which Transporter shall be required to pay. The term “tax” and “additional tax” shall mean collectively any sales (wholesale or retail), transactions, occupation, privilege license or franchise, service, production, severance, gathering, transmission, export or excise tax, assessment, fee, gross receipts or other exaction, whether of the kind herein enumerated, or otherwise (not including income, excess profits, capital stock, state franchise or general property taxes) hereafter levied, accessed or fixed by the United States or any state or other governmental authority, measured by, in respect of or applicable to the natural gas to be delivered by Transporter to Shipper under this Contract, and which Transporter may be liable for in any month either directly or indirectly through any obligation of Transporter to reimburse others.

*	 	This provision presently applies to the Alabama Utility Gross Receipts Tax. Taxes collected pursuant to this Article shall not be included in Transporter’s FERC cost of service used for the design of jurisdictional rates.	
X
GENERAL TERMS AND CONDITIONS
     This Contract shall be subject to the provisions of Transporter’s Rate Schedule FT and to the General Terms and Conditions of Transporter’s FERC Gas Tariff incorporated therein, as the same may be changed or superseded from time to time in accordance with the rules and regulations of the FERC, which Rate Schedule and General Terms and Conditions are incorporated herein by reference and made a part hereof for all purposes.
ARTICLE XI
REGULATION
     This Contract shall be subject to all applicable and lawful governmental statutes, orders, rules and regulations and is contingent upon the receipt and continuation of all necessary regulatory approvals or authorizations upon terms acceptable to Transporter. This Contract shall be void and of no force and effect if any necessary regulatory approval is not so obtained or continued. All parties hereto shall cooperate to obtain or continue all necessary approvals or authorizations, but no party shall be liable to any other party for failure to obtain or continue such approvals or authorizations.
 4 

 

ARTICLE XII
RESPONSIBILITY DURING TRANSPORTATION
     Except as herein specified, the responsibility for gas during transportation shall be as stated in the General Terms and Conditions of Transporter’s FERC Gas Tariff.
ARTICLE XIII
WARRANTIES
     In addition to the warranties set forth in Section 9 of the General Terms and Conditions of Transporter’s FERC Gas Tariff, Shipper warrants the following:

13.1	 	Shipper warrants that all upstream and downstream transportation arrangements are in place, or will be in place as of the requested effective date of service, and that it has advised the upstream and downstream transporters of the Receipt and Delivery Point(s) under this Contract and any quantity limitations for each point as specified on Exhibits(5) A and B attached hereto. Shipper agrees to indemnify and hold Transporter harmless for refusal to transport gas hereunder in the event any upstream or downstream transporter fails to receive or deliver gas as contemplated by this Contract.	
 		
13.2	 	If transportation hereunder is pursuant to Subpart B of Part 284 of the FERC’s Regulations, Shipper warrants that the service provided hereunder is on behalf of an intrastate pipeline or a local distribution company within the meaning of Section 311(a)(1) of the Natural Gas Policy Act of 1978.	
 		
13.3	 	Shipper agrees to indemnify and hold Transporter harmless from all suits, actions, debts, accounts, damages, costs, losses and expenses (including reasonable attorneys fees) arising from or out of breach of any warranty, express or implied, by Shipper herein.	
 		
13.4	 	Transporter shall not be obligated to provide or continue service hereunder in the event of any breach of warranty.	
 5 

 

ARTICLE XIII
TERM

14.1	 	The term of this Contract shall commence May 1, 2003 and shall continue in full force and effect until April 30, 2008 (the “Primary Term”). Providing the Primary Term is one year or more and Shipper is paying Transporter’s Maximum FT transportation rate, then Shipper shall have a one-time, unilateral right, exercisable by written notice to Transporter at any time not less than twelve months before the end of the Primary Term, to extend the term of this Contract for a period of not less than one (1) year, nor more than fifteen (15) years which shall begin on the first day immediately following the expiration of the Primary Term and shall end on the date specified by Shipper in such notice (“the Rollover Term”). Providing Shipper is paying Transporter’s Maximum FT transportation rate, the term of this Contract shall continue after the Primary Term or the Rollover Term, as the case may be, for successive periods of one (1) year each (the “Renewal Terms”), unless terminated as of the end of any such Primary Term, Rollover Term or Renewal Term by written notice given by either party to the other not less than twelve (12) months prior to the end of any such term; provided; however, that no such notice shall have the effect of terminating this Contract at the end of the Primary Term if Buyer has given notice extending the term of this Contract for a Rollover Term. If the FERC or other governmental body having jurisdiction over the service rendered pursuant to the Contract authorizes abandonment of such service, this Contract shall terminate on the abandonment date permitted by the FERC or such other governmental body.	
 		
14.2	 	Any portions of this Contract necessary to correct or cash-out imbalances under this Contract as required by the General Terms and Conditions of Transporter’s FERC Gas Tariff, shall survive the other parts of this Contract until such time as such balancing has been accomplished.	
 		
14.3	 	This Contract will terminate automatically in the event Shipper fails to pay all of the amount of any bill for service rendered by Transporter hereunder in accord with the terms and conditions of Section 6 of the General Terms and Conditions of Transporter’s FERC Gas Tariff.	
 6 

 

ARTICLE XV
NOTICE
     Except as otherwise provided in the General Terms and Conditions applicable to this Contract, any notice under this Contract shall be in writing and mailed to the post office address of the party intended to receive the same, as follows:
ENBRIDGE PIPELINES (ALATENN) L.L.C..
1100 Louisiana — Suite 3300
Houston, Texas 77002
ATTENTION: Contract Administration
Facsimile: 713-821-2119

          Shipper:	 	CITY OF HUNTSVILLE	
 	 	 	
          Notices:	 	P.O. Box 2048
Huntsville, AL. 35804
Attention: Jimmie Butler, Gas Manager	
 	 	 	
          Billing:	 	P.O. Box 2048
Huntsville, AL. 35804
Attention: Tim McKee, CFO	
or to such other address as either Party shall designate by formal written notice to the other.
ARTICLE XVI
ASSIGNMENTS

16.1	 	Either Party may assign or pledge this Contract and all rights and obligations hereunder under the provisions of any mortgagee, deed of trust, indenture, or other instrument which it has executed or may execute hereafter as security for indebtedness. Either Party may, without relieving itself of its obligations under this Contract, assign any of its rights hereunder to a company with which it is affiliated, otherwise Shipper shall not assign this Contract or any of its rights hereunder, except in accord with Section 3 of the General Terms and Conditions of Transporter’s FERC Gas Tariff, unless it shall first have obtained the written consent of Transporter.	
 		
16.2	 	Any person which shall succeed by purchase, merger, or consolidation to the properties, substantially as an entirety, of either party hereto shall be entitled to the right and shall be subject to the obligations of its predecessor in interest under this Contract.	
 7 

 

ARTICLE XVII
MISCELLANEOUS

17.1	 	This Contract shall be interpreted under the laws of the State of Alabama.	
 		
17.2	 	If any provision of this Contract is declared null and void, or voidable, by a court of competent jurisdiction, then that provision will be considered severable upon consent of Transporter and the Shipper; and if the severability option is exercised, the remaining provisions of the Contract shall remain in full force and effect.	
 		
17.3	 	No modification of or supplement to the terms and provisions hereof shall be or become effective, except by the execution of supplementary written consent.	
 		
17.4	 	Exhibit(s) A and B attached hereto is/are incorporated herein by reference and made a part hereof for all purposes.	
     IN WITNESS WHEREOF, the parties hereto have caused this Contract to be duly executed in several counterparts as of the date first hereinabove written.

Transporter:	 	 	 	Shipper:	 	 	
ENBRIDGE PIPELINES (ALATENN), L.L.C.	 	 	 	CITY OF HUNTSVILLE	 	 	
 	 	 	 	 	 	 	 	 	 	 	
By:	 	/s/ Terrance L. McGill 	 	 	 	By:	 	/s/ Henry O’Quinn 	 	 	
Name:	 	 
Terrance L. McGill  	 	 	 	Name:	 	 
Henry O’Quinn   	 	 	

 	 	 	
Title:	 	Vice President	 	 	 	Title:	 	Assistant General Manager	 	 	
 		
Date:	 	5-27-03	 	 	 	Date:	 	4-17-20/03	 	 	
 	 	 	 	 	 	Name:	 	/s/ Jimmie L. Butler 	 	 	
 	 	 	 	 	 	
Title:	 	Jimmie L. Butler
MGR. - Gas Dept.	 	 	
 		
 	 	 	 	 	 	Date:	 	4/17/03	 	 	
 8 

 

EXHIBIT “A”
TO FIRM GAS TRANSPORTATION CONTRACT
DATED MAY 1, 2003
BETWEEN
ENBRIDGE PIPELINES (ALATENN) L.L.C.
AND
CITY OF HUNTSVILLE
CONTRACT NO. 6066
PRIMARY POINT(S) OF RECEIPT
 	 	 	 	 	
METER NO.	 	DESCRIPTION	 	VOLUME	
10160	 	Barton-TGP, Colbert County, AL	 	15,281	
Shipper may use as a secondary receipt point any other receipt point on either mainline segment on Transporter’s system.

 
EXHIBIT “B”
TO FIRM GAS TRANSPORTATION CONTRACT
DATED MAY 1, 2003
BETWEEN
ENBRIDGE PIPELINES (ALATENN), L.L.C.
AND
CITY OF HUNTSVILLE
CONTRACT NO. 6066
PRIMARY POINT(S) OF DELIVERY
 	 	 	 	 	
METER NO.	 	DESCRIPTION	 	VOLUME	
10740	 	Huntsville #2 Delivery	 	  2,281	
 	 	 	 	 	
10780	 	Huntsville #1 Delivery	 	13,000	

Exhibit 10.21
FTS Contract No. 71657
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE FTS)
This Agreement (“Agreement”) is made and entered into this 1 st day of September, 2008, by and between Enbridge Pipelines (Midla) L.L.C., a Delaware Corporation (herein called “Pipeline”), and Enbridge Marketing (US), LP herein called “Customer” whether one or more persons).
In consideration of the premises and of the mutual covenants herein contained, the parties do agree as follows:
ARTICLE I
SCOPE OF AGREEMENT

1.1	 	Subject to the terms, conditions and limitations hereof and of Pipeline’s Rate Schedule FTS, Pipeline agrees to receive from or for Customer for transportation on a firm basis quantities of natural gas up to the Maximum Daily Quantity (MDQ) tendered by Customer on any day at the Point(s) of Receipt; provided, however, Customer shall not tender at any Point of Receipt on any day a quantity of natural gas in excess of the applicable MDQ set forth on Exhibit A for each such Point of Receipt or Customer’s nomination, if less than the MDQ, or in any year, a cumulative quantity of natural gas in excess of the Maximum Annual Quantity (MAQ) inclusive of the applicable Fuel Reimbursement Quantities. For purposes of this Agreement, the MDQ and MAQ shall be as follows:	
Maximum Daily Quantity
							
January	 	 	34,100	 	 	MMBtu	
February	 	 	34,100	 	 	MMBtu	
March	 	 	34,100	 	 	MMBtu	
April	 	 	13,000	 	 	MMBtu	
May	 	 	7,700	 	 	MMBtu	
June	 	 	7,700	 	 	MMBtu	
July	 	 	7,700	 	 	MMBtu	
August	 	 	7,700	 	 	MMBtu	
September	 	 	7,700	 	 	MMBtu	
October	 	 	13,000	 	 	MMBtu	
November	 	 	34,100	 	 	MMBtu	
December	 	 	34,100	 	 	MMBtu	

1.2	 	Subject to the terms, conditions and limitations hereof and of Pipeline’s Rate Schedule FTS, Pipeline agrees to transport and deliver to or for Customer at the Point(s) of Delivery and Customer agrees to accept or cause acceptance of delivery of the quantities of natural gas received by Pipeline on any day pursuant to Paragraph 1.1 above, less the applicable Fuel Reimbursement Quantities; provided, however, Pipeline shall not be obligated to deliver at any Point of Delivery on any day a quantity of natural gas in excess of the applicable MDQ set forth on Exhibit B for each such Point of Delivery or Customer’s nomination, if less than the MDQ.	

 

FTS Contract No. 71657

1.3	 	To the extent permitted by Pipeline’s FERC Gas Tariff, Fifth Revised Volume No. 1 (hereinafter the “Tariff”), and FERC orders and regulations, Pipeline shall have the right to interrupt service under this Agreement if at any time Customer fails to materially comply with any provision of this Agreement.	
ARTICLE II
TERM OF AGREEMENT

2.1	 	This Agreement shall become effective as of the date first set forth hereinabove written and shall continue through August 31, 2013 (the “Primary Term”). Thereafter, this Agreement shall continue for successive terms of twelve (12) months each (the “Renewal Term”) unless either party gives ninety (90) days written notice to the other party prior to the end of the Primary Term or any twelve (12) month Renewal Term thereafter.	
 		
2.2	 	Termination of this Agreement shall not affect or cancel the obligations, claims, and liabilities then owing by either party to the other.	
 		
2.3	 	Pipeline’s or Customer’s right to terminate this Agreement upon expiration of the Primary Term hereof shall be subject to the pregranted abandonment provision of Section 7 of the General Terms and Conditions of the Tariff.	
ARTICLE III
RATE SCHEDULE

3.1	 	Customer shall pay Pipeline each month for service provided under this Agreement the maximum rates and such other charges as are specified in the Tariff for Rate Schedule FTS, including but not limited to the Annual Charge Adjustment (ACA), the Fuel Reimbursement Charge, Electronic Bulletin Board charges, and penalties.	
 		
3.2	 	Pursuant to Rate Schedule FTS of the Tariff, Pipeline may agree from time to time to collect a rate lower than the maximum rate set forth in the Tariff. Such a discounted rate shall be set forth in Exhibit D or in a separate written agreement.	
 		
3.3	 	The rates and charges provided for under Rate Schedule FTS shall be subject to increase or decrease pursuant to any order issued by the Federal Energy Regulatory Commission in any proceeding initiated by Pipeline or applicable to the services performed hereunder. Customer agrees that Pipeline shall, without any further agreement by Customer, have the right to change from time to time, all or any part of this Agreement, as well as all or any part of Rate Schedule FTS, or the General Terms and Conditions thereof, including without limitation the right to change the rates and charges in effect hereunder, pursuant to Section 4 (d) of the Natural Gas Act as may be deemed necessary by Pipeline, in its reasonable judgment, to assure just and reasonable service and rates under the Natural Gas Act. Nothing contained herein shall prejudice the rights of Customer to contest at any time the changes made pursuant to this Paragraph 3.3, including the right to	

 

FTS Contract No. 71657
contest the transportation rates or charges for the services provided under this Agreement, from time to time, in any subsequent proceeding.
ARTICLE IV
POINT(S) OF RECEIPT AND DELIVERY

4.1	 	Natural gas to be received by Pipeline from or for Customer hereunder shall be delivered at the outlet side of the measuring station(s) at the Point(s) of Receipt set forth in Exhibit A of this Agreement, with the Maximum Daily Quantity and the pressure obligation indicated for each such Point of Receipt.	
 		
4.2	 	Natural gas to be delivered by Pipeline to or for Customer hereunder shall be delivered at the outlet side of the measuring station(s) at the Point(s) of Delivery set forth in Exhibit B of this Agreement, with the Maximum Daily Quantity and the pressure obligation indicated for each such Point of Delivery.	
ARTICLE V
CONDITIONS OF SERVICE

5.1	 	This Agreement and all terms and provisions contained or incorporated herein are subject to Rate Schedule FTS and the General Terms and Conditions of the Tariff on file with the Federal Energy Regulatory Commission, or other duly constituted authorities having jurisdiction, and as the same may be legally amended or superseded, which rate schedule and General Terms and Conditions are incorporated by reference and made a part of this Agreement. Capitalized terms herein shall have the meaning assigned to such terms in the Tariff. In the event of conflict between this Agreement and Pipeline’s Tariff, the Tariff shall control.	
 		
5.2	 	For service hereunder which is subject to 18 C.F.R Section 284.101 (Section 311 transportation), Customer must execute Exhibit C and the affidavits attached thereto, all of which are hereby incorporated by reference and made a part of this Agreement.	
 		
5.3	 	The parties hereto agree that neither party shall be liable to the other for any special, indirect, or consequential damages (including business interruptions) arising out of or in any manner related to this Agreement.	
ARTICLE VI
NOTICES
Except as herein otherwise provided or as provided in the General Terms and Conditions of the Tariff, any notice, request, demand, statement, bill or payment provided for in this Agreement, or any notice which any party may desire to give to the other, shall be in writing and shall be considered as duly delivered when received by registered, certified, or first class mail, or overnight delivery service (Federal Express, UPS, or U.S. Postal Service) at the address of the parties as follows:

 

FTS Contract No. 71657

 	 	(a) Pipeline:	 	ENBRIDGE PIPELINES (MIDLA) L.L.C.	
 	 	 	 	Attn: Contract Administration	
 	 	 	 	1100 Louisiana, Suite 3300	
 	 	 	 	Houston, Texas 77002	
 	 	 	 	 	
 	 	 	 	Telephone No. (713) 821-2000	
 	 	 	 	Facsimile No. (713) 821-3313	
 	 	 	 	 	
 	 	(b) Customer:	 	Enbridge Marketing (US), LP	
 	 	 	 	Attention: Mr. Robert Hall	
 	 	 	 	1100 Louisiana, Suite 3600	
 	 	 	 	Houston, Texas 77002	
or such other address as either party shall subsequently designate by formal written notice.
ARTICLE VII
MISCELLANEOUS

7.1	 	This Agreement constitutes the entire agreement between the parties and no modification, waiver, representation or agreement, oral or otherwise, shall affect the subject matter hereof unless and until such modification, waiver, representation or agreement is reduced to writing and executed by authorized representatives of the parties. No waiver by either Customer or Pipeline of the performance of any of the provisions of this Agreement by the other or the failure to exercise the rights granted to either Customer or Pipeline herein s shall operate or be construed as an implied or express waiver of any future performance by the other party, or right of Customer or Pipeline herein, whether of a like or of a different character.	
 		
7.2	 	This Agreement shall be binding upon and inure to the benefit of the successors and assigns of each of the parties hereto.	
 		
7.3	 	The interpretation and performance of this Agreement shall be in accordance with the laws of the State of Texas, excluding conflicts of law principles that would require the application of the laws of a different jurisdiction.	
 		
7.4	 	As this Firm Transportation Agreement relates to Capacity Release, the Replacement Shipper grants to Midla its permission and approval to notify the Releasing Shipper (even when such Releasing Shipper is an Energy Affiliate of Midla) of certain credit-related information specified under Section 4.12(c) of the General Terms and Conditions of Midla’s FERC Gas Tariff.	
 		
7.5	 	When this Agreement becomes effective, it shall supersede the following agreements between the parties hereto:	

 	 	 	Dated	 	N/A	

 	 	 	Dated	 	N/A	

 

FTS Contract No. 71657
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed by their respective agents thereunto duly authorized, the day and year first above written.

ATTEST: /s/ Angela H. Byrd
 	 	ENBRIDGE PIPELINES (MIDLA) L.L.C.

By:	 	Angela H. Byrd 	 	By:	 	/s/ Stephen L. Merritt 	

 	 	Contract Administrator	 	Stephen L. Merritt
Vice President 	
 	 	 	
(Printed Name)                                  (Title) 	 	(Printed Name)                                                     (Title) 	
 	 	 	 	 	 	 	
 	 	 	 	CUSTOMER	
 		
ATTEST:

By:	 	/s/ Bob Hall 	 	By:	 	/s/ Janet Loy 	

Bob Hall 	 	Janet Loy
President 	
 	 	 	
(Printed Name)                                                        (Title)	 	(Printed Name)                                                               (Title) 	

 

FTS Contract No. 71657
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE FTS)
EXHIBIT A
To the Agreement under Rate Schedule FTS between Enbridge Pipelines (Midla) L.L.C. (Pipeline) and Enbridge Marketing (US), LP (Customer) concerning Point(s) of Receipt.
Point(s) of Receipt
     Dated: September 1, 2008
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Maximum Receipt		
Primary Point	 	Maximum Daily	 	Pressure		
Of Receipt	 	Receipt Obligation	 	(psig)		
7049 (Desaird)	 	Jan-March	 	 	16,100	 	 	195		
 	 	April	 	 	10,000	 	 	 		
 	 	May-Sept	 	 	7,000	 	 	 		
 	 	Oct	 	 	10,000	 	 	 		
 	 	Nov-Dec	 	 	16,100	 	 	 		
 	 	 	 	 	 	 	 	 	 	 		
8092 (Transco Ethel)	 	Jan-March	 	 	13,000	 	 	800		
 	 	April	 	 	2,000	 	 	 		
 	 	May-Sept	 	 	500	 	 	 		
 	 	Oct	 	 	2,000	 	 	 		
 	 	Nov-Dec	 	 	13,000	 	 	 		
 	 	 	 	 	 	 	 	 	 	 		
8085 (Gulf South Scotland)	 	Jan-March	 	 	5,000	 	 	800		
 	 	April	 	 	1,000	 	 	 		
 	 	May-Sept	 	 	200	 	 	 		
 	 	Oct	 	 	1,000	 	 	 		
 	 	Nov-Dec	 	 	5,000	 	 	 		

Secondary Point of	 	Maximum Daily Receipt	 	Maximum Receipt	
Receipt	 	Obligation	 	Pressure	
 	 	 	 	 	
ALL	 	N/A	 	Midla’s maximum	
 	 	 	 	allowable operating	
 	 	 	 	pressure at point	

Signed for Identification	 	 	 	 	
 	 	 	 	 	
Enbridge Pipelines (Midla) L.L.C.:	 	/s/ Stephen L. Merritt 	 	 	
 	 	 	 	 	
Customer:	 	/s/ Janet Loy 	 	 	
 	 	 	 	 	
Supersedes Exhibit A Dated:	 	N/A	 	 	

 

FTS Contract No. 71657
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE FTS)
EXHIBIT B
To the Agreement under Rate Schedule FTS between Enbridge Pipelines (Midla) L.L.C. (Pipeline) and Enbridge Marketing (US), LP (Customer) concerning Point(s) of Delivery.
Point(s) of Delivery
     Dated: September 1, 2008
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Maximum Delivery		
Primary Point of	 	Maximum Daily	 	 	Pressure		
Delivery	 	Delivery Obligation	 	 	(psig)		
8011 (Domestic #1)	 	Jan-March	 	 	22,000	 	 	150		
 	 	April	 	 	8,000	 	 	 		
 	 	May-Sept	 	 	5,000	 	 	 		
 	 	Oct	 	 	8,000	 	 	 		
 	 	Nov-Dec	 	 	22,000	 	 	 		
 	 	 	 	 	 	 	 	 	 	 		
8019 (Domestic #2)	 	Jan-March	 	 	10,000	 	 	150		
 	 	April	 	 	4,000	 	 	 		
 	 	May-Sept	 	 	2,000	 	 	 		
 	 	Oct	 	 	4,000	 	 	 		
 	 	Nov-Dec	 	 	10,000	 	 	 		
 	 	 	 	 	 	 	 	 	 	 		
8010 (Harding Field)	 	Jan-March	 	 	1,400	 	 	150		
 	 	April	 	 	700	 	 	 		
 	 	May-Sept	 	 	500	 	 	 		
 	 	Oct	 	 	700	 	 	 		
 	 	Nov-Dec	 	 	1,400	 	 	 		
 	 	 	 	 	 	 	 	 	 	 		
8029 (Alsen Community)	 	Jan-March	 	 	700	 	 	150		
 	 	April	 	 	300	 	 	 		
 	 	May-Sept	 	 	200	 	 	 		
 	 	Oct	 	 	300	 	 	 		
 	 	Nov-Dec	 	 	700	 	 	 		

Secondary Point of	 	Maximum Daily Delivery	 	Maximum Delivery	
Delivery	 	Obligation	 	Pressure	
 	 	 	 	 	
ALL	 	N/A	 	Midla’s maximum	
 	 	 	 	allowable operating	
 	 	 	 	pressure at point	

Signed for Identification	 	 	 	 	
 	 	 	 	 	
Enbridge Pipelines (Midla) L.L.C.:	 	/s/ Stephen L. Merritt 	 	 	
 	 	 	 	 	
Customer:	 	/s/ Janet Loy 	 	 	
 	 	 	 	 	
Supersedes Exhibit B Dated:	 	N/A	 	 	

 

FTS Contract No. 71657
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE FTS)
EXHIBIT C
To the Agreement under Rate Schedule FTS between Enbridge Pipelines (Midla) L.L.C. (Pipeline) and Enbridge Marketing (US), LP (Customer) concerning “on behalf of” entity(ies).
“On Behalf of” Entity(ies)
     Dated: N/A

Name	 	Type	

 		

 		

Customer warrants that the transportation by Pipeline hereunder will be “on behalf of” the above listed entity(ies) and in full compliance with Section 311 of the Natural Gas Policy Act of 1978 (NGPA) and FERC Order No. 525 et seq. Customer shall indemnify and hold Pipeline harmless from any and all liability arising from any acts and omissions or material representations of Customer in connection with or related to Pipeline’s service under Section 311 of the NGPA. Customer shall not cause gas to be delivered to Pipeline for transportation “on behalf of” any other entity until such time as this Exhibit C has been amended to reflect the addition of such entity.

Signed for Identification	 	 	 	 	
 	 	 	 	 	
Enbridge Pipelines (Midla) L.L.C.:	 	/s/ Stephen L. Merritt 	 	 	
 	 	 	 	 	
Customer:	 	/s/ Janet Loy 	 	 	
 	 	 	 	 	
Supersedes Exhibit C Dated:	 	N/A	 	 	

 

FTS Contract No. 71657
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE FTS)
EXHIBIT D
To the Agreement under Rate Schedule FTS between Enbridge Pipelines (Midla) L.L.C. (Pipeline) and Enbridge Marketing (US), LP (Customer) concerning discount information.
Discount Information
Dated: September 1, 2008
Discounted Transportation Rate: $2.00 — Discount applies only to reservation rate. All other rates and charges apply as specified in the tariff.
Discounted Rate Effective:        From: September 1, 2008        To: August 31, 2013

 	o	Evergreen:	o	Year-to-Year	
 	 	 	o	Month-to-Month	
Condition for Discounted Transportation Rate (check applicable condition(s)):

 	þ	 	Discounted Transportation Rate applicable to specified quantities under Shipper’s Service Contract(s):	

January	 	 	34,100	 	 	MMBtu	
February	 	 	34,100	 	 	MMBtu	
March	 	 	34,100	 	 	MMBtu	
April	 	 	13,000	 	 	MMBtu	
May	 	 	7,700	 	 	MMBtu	
June	 	 	7,700	 	 	MMBtu	
July	 	 	7,700	 	 	MMBtu	
August	 	 	7,700	 	 	MMBtu	
September	 	 	7,700	 	 	MMBtu	
October	 	 	13,000	 	 	MMBtu	
November	 	 	34,100	 	 	MMBtu	
December	 	 	34,100	 	 	MMBtu	

 	o	 	Discounted Transportation Rate applicable to specified quantities above or below a certain level or all quantities if quantities exceed a certain level:	
Discounted Transportation Rate applicable to                     
MMBtu above/below                      MMBtu
or

 	o	 	Discounted Transportation Rate applicable in a specified relationship to quantities actually transported:	
Adjustment in Transportation Rate:                     
(based on                      MMBtu actually transported)

 

FTS Contract No. 71657

 	o	 	Discounted Transportation Rate applicable to specified quantities during specified periods of time or during specified periods of the year:	
                     MMBtu for the following time period(s):

 	o	 	Discounted Transportation Rate applicable to specified quantities at specific Point(s) of Receipt or Point(s) of Delivery or other geographical locations:	
Point(s) of Receipt:                     
Point(s) of Delivery:                     
Other geographical locations:                     

 	o	 	Discounted Transportation Rate applicable to production reserves committed or dedicated by Shipper:	
Production Reserves:                      Field

 	o	 	Discounted Transportation Rate based on published index prices for specific Point(s) of Receipt and/or Point(s) of Delivery or other agreed-upon published pricing reference points (based upon the differential between published prices or arrived at by formula):	

 	 	Index Price(s):	 	 	 	 	

                     Differential between Index Prices
or
                     Formula:                     
In no event shall the discounted rate established as set forth above exceed the otherwise applicable maximum lawful rate.

Signed for Identification	 	 	 	 	
 	 	 	 	 	
Enbridge Pipelines (Midla) L.L.C.:	 	/s/ Stephen L. Merritt 	 	 	
 	 	 	 	 	
Customer:	 	/s/ Janet Loy 	 	 	
 	 	 	 	 	
Supersedes Exhibit D Dated:	 	N/A	 	 	

Exhibit 10.22
FTS Contract No. 71658
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE FTS)
This Agreement (“Agreement”) is made and entered into this 1 st day of September, 2008, by and between Enbridge Pipelines (Midla) L.L.C., a Delaware Corporation (herein called “Pipeline”), and Enbridge Marketing (US), LP herein called “Customer” whether one or more persons).
In consideration of the premises and of the mutual covenants herein contained, the parties do agree as follows:
ARTICLE I
SCOPE OF AGREEMENT

1.1	 	Subject to the terms, conditions and limitations hereof and of Pipeline’s Rate Schedule FTS, Pipeline agrees to receive from or for Customer for transportation on a firm basis quantities of natural gas up to the Maximum Daily Quantity (MDQ) tendered by Customer on any day at the Point(s) of Receipt; provided, however, Customer shall not tender at any Point of Receipt on any day a quantity of natural gas in excess of the applicable MDQ set forth on Exhibit A for each such Point of Receipt or Customer’s nomination, if less than the MDQ, or in any year, a cumulative quantity of natural gas in excess of the Maximum Annual Quantity (MAQ) inclusive of the applicable Fuel Reimbursement Quantities. For purposes of this Agreement, the MDQ and MAQ shall be as follows:	
 	 	 	 	 	 	 	
Maximum Daily Quantity	 	 	 	 	 	 	
January	 	 	20,000	 	 	MMBtu	
February	 	 	20,000	 	 	MMBtu	
March	 	 	20,000	 	 	MMBtu	
April	 	 	12,000	 	 	MMBtu	
May	 	 	7,700	 	 	MMBtu	
June	 	 	7,700	 	 	MMBtu	
July	 	 	7,700	 	 	MMBtu	
August	 	 	7,700	 	 	MMBtu	
September	 	 	7,700	 	 	MMBtu	
October	 	 	12,000	 	 	MMBtu	
November	 	 	20,000	 	 	MMBtu	
December	 	 	20,000	 	 	MMBtu	

1.2	 	Subject to the terms, conditions and limitations hereof and of Pipeline’s Rate Schedule FTS, Pipeline agrees to transport and deliver to or for Customer at the Point(s) of Delivery and Customer agrees to accept or cause acceptance of delivery of the quantities of natural gas received by Pipeline on any day pursuant to Paragraph 1.1 above, less the applicable Fuel Reimbursement Quantities; provided, however, Pipeline shall not be obligated to deliver at any Point of Delivery on any day a quantity of natural gas in excess of the applicable MDQ set forth on Exhibit B for each such Point of Delivery or Customer’s nomination, if less than the MDQ.	

 

FTS Contract No. 71658

1.3	 	To the extent permitted by Pipeline’s FERC Gas Tariff, Fifth Revised Volume No. 1 (hereinafter the “Tariff”), and FERC orders and regulations, Pipeline shall have the right to interrupt service under this Agreement if at any time Customer fails to materially comply with any provision of this Agreement.	
ARTICLE II
TERM OF AGREEMENT

2.1	 	This Agreement shall become effective as of the date first set forth hereinabove written and shall continue through August 31, 2013 (the “Primary Term”). Thereafter, this Agreement shall continue for successive terms of twelve (12) months each (the “Renewal Term”) unless either party gives ninety (90) days written notice to the other party prior to the end of the Primary Term or any twelve (12) month Renewal Term thereafter.	
 		
2.2	 	Termination of this Agreement shall not affect or cancel the obligations, claims, and liabilities then owing by either party to the other.	
 		
2.3	 	Pipeline’s or Customer’s right to terminate this Agreement upon expiration of the Primary Term hereof shall be subject to the pregranted abandonment provision of Section 7 of the General Terms and Conditions of the Tariff.	
ARTICLE III
RATE SCHEDULE

3.1	 	Customer shall pay Pipeline each month for service provided under this Agreement the maximum rates and such other charges as are specified in the Tariff for Rate Schedule FTS, including but not limited to the Annual Charge Adjustment (ACA), the Fuel Reimbursement Charge, Electronic Bulletin Board charges, and penalties.	
 		
3.2	 	Pursuant to Rate Schedule FTS of the Tariff, Pipeline may agree from time to time to collect a rate lower than the maximum rate set forth in the Tariff. Such a discounted rate shall be set forth in Exhibit D or in a separate written agreement.	
 		
3.3	 	The rates and charges provided for under Rate Schedule FTS shall be subject to increase or decrease pursuant to any order issued by the Federal Energy Regulatory Commission in any proceeding initiated by Pipeline or applicable to the services performed hereunder. Customer agrees that Pipeline shall, without any further agreement by Customer, have the right to change from time to time, all or any part of this Agreement, as well as all or any part of Rate Schedule FTS, or the General Terms and Conditions thereof, including without limitation the right to change the rates and charges in effect hereunder, pursuant to Section 4(d) of the Natural Gas Act as may be deemed necessary by Pipeline, in its reasonable judgment, to assure just and reasonable service and rates under the Natural Gas Act. Nothing contained herein shall prejudice the rights of Customer to contest at any time the changes made pursuant to this Paragraph 3.3, including the right to	

 

FTS Contract No. 71658
contest the transportation rates or charges for the services provided under this Agreement, from time to time, in any subsequent proceeding.
ARTICLE IV
POINT(S) OF RECEIPT AND DELIVERY

4.1	 	Natural gas to be received by Pipeline from or for Customer hereunder shall be delivered at the outlet side of the measuring station(s) at the Point(s) of Receipt set forth in Exhibit A of this Agreement, with the Maximum Daily Quantity and the pressure obligation indicated for each such Point of Receipt.	
 		
4.2	 	Natural gas to be delivered by Pipeline to or for Customer hereunder shall be delivered at the outlet side of the measuring station(s) at the Point(s) of Delivery set forth in Exhibit B of this Agreement, with the Maximum Daily Quantity and the pressure obligation indicated for each such Point of Delivery.	
ARTICLE V
CONDITIONS OF SERVICE

5.1	 	This Agreement and all terms and provisions contained or incorporated herein are subject to Rate Schedule FTS and the General Terms and Conditions of the Tariff on file with the Federal Energy Regulatory Commission, or other duly constituted authorities having jurisdiction, and as the same may be legally amended or superseded, which rate schedule and General Terms and Conditions are incorporated by reference and made a part of this Agreement. Capitalized terms herein shall have the meaning assigned to such terms in the Tariff. In the event of conflict between this Agreement and Pipeline’s Tariff, the Tariff shall control.	
 		
5.2	 	For service hereunder which is subject to 18 C.F.R Section 284.101 (Section 311 transportation), Customer must execute Exhibit C and the affidavits attached thereto, all of which are hereby incorporated by reference and made a part of this Agreement.	
 		
5.3	 	The parties hereto agree that neither party shall be liable to the other for any special, indirect, or consequential damages (including business interruptions) arising out of or in any manner related to this Agreement.	
ARTICLE VI
NOTICES
Except as herein otherwise provided or as provided in the General Terms and Conditions of the Tariff, any notice, request, demand, statement, bill or payment provided for in this Agreement, or any notice which any party may desire to give to the other, shall be in writing and shall be considered as duly delivered when received by registered, certified, or first class mail, or overnight delivery service (Federal Express, UPS, or U.S. Postal Service) at the address of the parties as follows:

 

FTS Contract No. 71658

(a) Pipeline:	 	ENBRIDGE PIPELINES (MIDLA) L.L.C.	
 	 	Attn: Contract Administration	
 	 	1100 Louisiana, Suite 3300	
 	 	Houston, Texas 77002	
 	 	 	
 	 	Telephone No. (713) 821-2000	
 	 	Facsimile No. (713) 821-3313	
 	 	 	
(b) Customer:	 	Enbridge Marketing (US), LP	
 	 	Attention: Mr. Robert Hall	
 	 	1100 Louisiana, Suite 3600	
 	 	Houston, Texas 77002	
or such other address as either party shall subsequently designate by formal written notice.
ARTICLE VII
MISCELLANEOUS

7.1	 	This Agreement constitutes the entire agreement between the parties and no modification, waiver, representation or agreement, oral or otherwise, shall affect the subject matter hereof unless and until such modification, waiver, representation or agreement is reduced to writing and executed by authorized representatives of the parties. No waiver by either Customer or Pipeline of the performance of any of the provisions of this Agreement by the other or the failure to exercise the rights granted to either Customer or Pipeline herein s shall operate or be construed as an implied or express waiver of any future performance by the other party, or right of Customer or Pipeline herein, whether of a like or of a different character.	
 		
7.2	 	This Agreement shall be binding upon and inure to the benefit of the successors and assigns of each of the parties hereto.	
 		
7.3	 	The interpretation and performance of this Agreement shall be in accordance with the laws of the State of Texas, excluding conflicts of law principles that would require the application of the laws of a different jurisdiction.	
 		
7.4	 	As this Firm Transportation Agreement relates to Capacity Release, the Replacement Shipper grants to Midla its permission and approval to notify the Releasing Shipper (even when such Releasing Shipper is an Energy Affiliate of Midla) of certain credit-related information specified under Section 4.12(c) of the General Terms and Conditions of Midla’s FERC Gas Tariff.	
 		
7.5	 	When this Agreement becomes effective, it shall supersede the following agreements between the parties hereto:	

 	 	Dated	 	N/A	
 		
 	 	Dated	 	N/A	

 

FTS Contract No. 71658
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed by their respective agents thereunto duly authorized, the day and year first above written.
ENBRIDGE PIPELINES (MIDLA) L.L.C.

ATTEST:	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
By:	 	/s/ Angela H. Byrd	 	 	 	By:	 	/s/ Stephen L. Merritt	
 	 	 	 	 	 	 	 	 	
Angela H. Byrd         Contract Administrator	 	 	 	Stephen L. Merritt                            Vice President	
(Printed Name)         (Title)	 	 	 	(Printed Name)                                             (Title)	
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	CUSTOMER	
 	 	 	 	 	 	 	 	 	
ATTEST:

By:	 	/s/ Bob Hall	 	 	 	By:	 	/s/ Janet Loy	
 	 	 	 	 	 	 	 	 	
Bob Hall	 	 	 	Janet Loy                                                         President	
(Printed Name)                                     (Title)	 	 	 	(Printed Name)                                                      (Title)	

 

FTS Contract No. 71658
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE FTS)
EXHIBIT A
To the Agreement under Rate Schedule FTS between Enbridge Pipelines (Midla) L.L.C. (Pipeline) and Enbridge Marketing (US), LP (Customer) concerning Point(s) of Receipt.
Point(s) of Receipt
          Dated: September 1, 2008
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Maximum Receipt	
primary point	 	 	Maximum Daily	 	Pressure	
Of Receipt	 	 	Receipt Obligation	 	(psig)	
178 (Oak Hill)	 	Jan-March	 	 	500	 	 	 	350	 	
 	 	April	 	 	250	 	 	 	 	 	
 	 	May-Sept	 	 	175	 	 	 	 	 	
 	 	Oct	 	 	250	 	 	 	 	 	
 	 	Nov-Dec	 	 	500	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
179 (Siegan Lane)	 	Jan-March	 	 	8,300	 	 	 	800	 	
 	 	April	 	 	4,150	 	 	 	 	 	
 	 	May-Sept	 	 	2,950	 	 	 	 	 	
 	 	Oct	 	 	4,150	 	 	 	 	 	
 	 	Nov-Dec	 	 	8,300	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
180 (Hammond Hwy)	 	Jan-March	 	 	7,500	 	 	 	800	 	
 	 	April	 	 	3,750	 	 	 	 	 	
 	 	May-Sept	 	 	2,625	 	 	 	 	 	
 	 	Oct	 	 	3,750	 	 	 	 	 	
 	 	Nov-Dec	 	 	7,500	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
181 (Highland Rd)	 	Jan-March	 	 	3,700	 	 	 	800	 	
 	 	April	 	 	1,850	 	 	 	 	 	
 	 	May-Sept	 	 	1,295	 	 	 	 	 	
 	 	Oct	 	 	1,850	 	 	 	 	 	
 	 	Nov-Dec	 	 	3,700	 	 	 	 	 	
 		
Secondary Point of	 	Maximum Daily Receipt	 	Maximum Receipt	
Receipt	 	Obligation	 	Pressure	
 		
ALL	 	N/A	 	Midla’s maximum
allowable operating
pressure at point	

Signed for Identification	 	 	
 	 	 	
Enbridge Pipelines (Midla) L.L.C.:	 	/s/ Stephen L. Merritt	
 	 	 	
Customer:	 	/s/ Janet Loy	
 	 	 	
Supersedes Exhibit A Dated:	 	N/A	

 

FTS Contract No. 71658
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE FTS)
EXHIBIT B
To the Agreement under Rate Schedule FTS between Enbridge Pipelines (Midla) L.L.C. (Pipeline) and Enbridge Marketing (US), LP (Customer) concerning Point(s) of Delivery.
Point(s) of Delivery
          Dated: September 1, 2008
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Maximum Delivery	
Primary Point	 	 	Maximum Daily	 	Pressure	
Of Delivery	 	 	Delivery Obligation	 	(psig)	
8030 (Oak Hill)	 	Jan-March	 	 	500	 	 	 	100	 	
 	 	April	 	 	250	 	 	 	 	 	
 	 	May-Sept	 	 	175	 	 	 	 	 	
 	 	Oct	 	 	250	 	 	 	 	 	
 	 	Nov-Dec	 	 	500	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
8021 (Siegan Lane)	 	Jan-March	 	 	8,300	 	 	 	100	 	
 	 	April	 	 	4,150	 	 	 	 	 	
 	 	May-Sept	 	 	2,950	 	 	 	 	 	
 	 	Oct	 	 	4,150	 	 	 	 	 	
 	 	Nov-Dec	 	 	8,300	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
8073 (Hammond Hwy)	 	Jan-March	 	 	7,500	 	 	 	150	 	
 	 	April	 	 	3,750	 	 	 	 	 	
 	 	May-Sept	 	 	2,625	 	 	 	 	 	
 	 	Oct	 	 	3,750	 	 	 	 	 	
 	 	Nov-Dec	 	 	7,500	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
8056 (Highland Rd)	 	Jan-March	 	 	3,700	 	 	 	100	 	
 	 	April	 	 	1,850	 	 	 	 	 	
 	 	May-Sept	 	 	1,295	 	 	 	 	 	
 	 	Oct	 	 	1,850	 	 	 	 	 	
 	 	Nov-Dec	 	 	3,700	 	 	 	 	 	
 		
Secondary Point of	 	Maximum Daily Delivery	 	Maximum Delivery	
Delivery	 	Obligation	 	Pressure	
 		
ALL	 	N/A	 	Midla’s maximum
allowable operating
pressure at point	

Signed for Identification	 	 	
 	 	 	
Enbridge Pipelines (Midla) L.L.C.:	 	/s/ Stephen L. Merritt	
 	 	 	
Customer:	 	/s/ Janet Loy	
 	 	 	
Supersedes Exhibit A Dated:	 	N/A	

 

FTS Contract No. 71658
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE FTS)
EXHIBIT C
To the Agreement under Rate Schedule FTS between Enbridge Pipelines (Midla) L.L.C. (Pipeline) and Enbridge Marketing (US), LP (Customer) concerning “on behalf of” entity(ies).
“On Behalf of” Entity(ies)
          Dated: N/A

Name	 	Type	

 		

 		

Customer warrants that the transportation by Pipeline hereunder will be “on behalf of” the above listed entity(ies) and in full compliance with Section 311 of the Natural Gas Policy Act of 1978 (NGPA) and FERC Order No. 525 et seq. Customer shall indemnify and hold Pipeline harmless from any and all liability arising from any acts and omissions or material representations of Customer in connection with or related to Pipeline’s service under Section 311 of the NGPA. Customer shall not cause gas to be delivered to Pipeline for transportation “on behalf of” any other entity until such time as this Exhibit C has been amended to reflect the addition of such entity.

Signed for Identification	 	 	
 	 	 	
Enbridge Pipelines (Midla) L.L.C.:	 	/s/ Stephen L. Merritt	
 	 	 	
Customer:	 	/s/ Janet Loy	
 	 	 	
Supersedes Exhibit C Dated:	 	N/A	

 

FTS Contract No. 71658
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE FTS)
EXHIBIT D
To the Agreement under Rate Schedule FTS between Enbridge Pipelines (Midla) L.L.C. (Pipeline) and Enbridge Marketing (US), LP (Customer) concerning discount information.
Discount Information
Dated: September 1, 2008
Discounted Transportation Rate: $2.00 — Discount applies only to reservation rate. All other rate and charges apply as specified in the tariff.
 	 	 	 	 	
Discounted Rate Effective:	 	From: September 1, 2008	 	To: August 31, 2013	

___ Evergreen:	 	___ Year-to-Year	
 	 	___ Month-to-Month	
Condition for Discounted Transportation Rate (check applicable condition(s)):

 	þ	 	Discounted Transportation Rate applicable to specified quantities under Shipper’s Service Contract(s):	

January	 	 	20,000	 	 	MMBtu	
February	 	 	20,000	 	 	MMBtu	
March	 	 	20,000	 	 	MMBtu	
April	 	 	12,000	 	 	MMBtu	
May	 	 	7,700	 	 	MMBtu	
June	 	 	7,700	 	 	MMBtu	
July	 	 	7,700	 	 	MMBtu	
August	 	 	7,700	 	 	MMBtu	
September	 	 	7,700	 	 	MMBtu	
October	 	 	12,000	 	 	MMBtu	
November	 	 	20,000	 	 	MMBtu	
December	 	 	20,000	 	 	MMBtu	

 	o	 	Discounted Transportation Rate applicable to specified quantities above or below a certain level or all quantities if quantities exceed a certain level:	
Discounted Transportation Rate applicable to                     
MMBtu above/below                      MMBtu
or

 	o	 	Discounted Transportation Rate applicable in a specified relationship to quantities actually transported:	

 

FTS Contract No. 71658
Adjustment in Transportation Rate:                     
(based on                      MMBtu actually transported)

 	o	 	Discounted Transportation Rate applicable to specified quantities during specified periods of time or during specified periods of the year:	
                     MMBtu for the following time period(s):

 	o	 	Discounted Transportation Rate applicable to specified quantities at specific Point(s) of Receipt or Point(s) of Delivery or other geographical locations:	
Point(s) of Receipt:                     
Point(s) of Delivery:                     
Other geographical locations:                     

 	o	 	Discounted Transportation Rate applicable to production reserves committed or dedicated by Shipper:	
Production Reserves:                      Field

 	o	 	Discounted Transportation Rate based on published index prices for specific Point(s) of Receipt and/or Point(s) of Delivery or other agreed-upon published pricing reference points (based upon the differential between published prices or arrived at by formula):	
Index Price(s):                                          
   _________________
____ Differential between Index Prices
or
____ Formula:                                          
In no event shall the discounted rate established as set forth above exceed the otherwise applicable maximum lawful rate.

Signed for Identification	 	 	
 	 	 	
Enbridge Pipelines (Midla) L.L.C.:	 	/s/ Stephen L. Merritt	
 	 	 	
Customer:	 	/s/ Janet Loy	
 	 	 	
Supersedes Exhibit D Dated:	 	N/A	

Exhibit 10.23
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
BETWEEN
AMERICAN MIDSTREAM, LLC
(PLANT SUPPLIER)
AND
ENTERPRISE GAS PROCESSING, LLC
(PROCESSOR)
JULY 1, 2010

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GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
TABLE OF CONTENTS
 	 	 	 	 	
ARTICLES	 	PAGE NUMBER	
Article I — Definitions	 	 	2	 	
 		
Article II — Exhibits	 	 	6	 	
 		
Article III — Capacity of Plant	 	 	6	 	
 		
Article IV — Delivery and Redelivery of Plant Supplier’s Gas	 	 	7	 	
 		
Article V — Allocation of Products	 	 	9	 	
 		
Article VI — Consideration Due Plant Supplier	 	 	14	 	
 		
Article VII — Plant Volume Reduction and Bypassed Gas	 	 	14	 	
 		
Article VIII — Term	 	 	17	 	
 		
Article IX — Payment of Royalty and Taxes	 	 	18	 	
 		
Article X — Laws, Regulations and Force Majeure	 	 	18	 	
 		
Article XI — Notices	 	 	19	 	
 		
Article XII — Indemnification	 	 	20	 	
 		
Article XIII — Miscellaneous	 	 	21	 	
EXHIBITS
“A” — Example Calculation — Product Allocation Procedure

“B” — Example Calculation — Plant Volume Reduction

“C” — Fractionation Fee

“D” — Product Index Bases

“E” — “Plant Supplier’s Fields for Processing”

“F” — Settlement Instructions
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GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
     THIS GAS PROCESSING AGREEMENT (the “Agreement”), is made and entered into this 1st day of July 2010 (the “Effective Date”), by and between AMERICAN MIDSTREAM, LLC (“Plant Supplier”) and ENTERPRISE GAS PROCESSING, LLC, (“Processor”).
R E C I T A L S
     A. WHEREAS, Processor has constructed the Toca Gas Processing Plant on a tract of land in Sections 54 and 55, T-14-S, R-4-E, St. Bernard Parish, Louisiana (herein called the “Toca Plant” or “Plant”), and operates said Plant for the purpose of extracting Liquid Hydrocarbons, as hereinafter defined, from certain gas delivered to the Plant from the pipeline system of Southern Natural Gas Company (herein called “Southern’s Lines”); and
     B. WHEREAS, the Toca Plant Owners have heretofore individually entered into an agreement with Enterprise Products Operating LLC, by and through its predecessor in interest, Shell Oil Company, as Owner of the Norco Fractionation Plant, entitled “Hydrocarbon Fractionation Agreement” (herein called “Fractionation Agreement”), whereby the Toca Plant Operator will deliver for the account of Plant Owners Raw Make, as hereinafter defined, recovered at the Toca Plant to Fractionator for transportation to the Norco Fractionation Plant and for fractionation into commercial Products; and
     C. WHEREAS, Plant Supplier owns or holds the gas processing rights to gas produced from the lands and leases as set out on Exhibit “E”, attached hereto and incorporated herein by reference, and has the right to extract or have extracted the Liquid Hydrocarbons from such gas, which gas will be transported through Southern’s Lines to the Plant for Plant Supplier’s account; and
     D. WHEREAS, Processor and Plant Supplier desire hereby to provide the terms and conditions under which such gas will be delivered from Southern’s Lines to the Plant pursuant to the Transportation Agreement, as hereinafter defined, for processing for Plant Supplier’s account and

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the Liquid Hydrocarbons in such gas will be sold to Processor at the Plant Delivery Point for a consideration to Plant Supplier consisting of a share of Products, all as hereinafter more fully set forth;
     NOW, THEREFORE, in consideration of the premises and of the mutual covenants and agreements herein provided, the parties hereto agree as follows:
ARTICLE I — DEFINITIONS
     1.1 Definitions . The following definitions of terms shall apply for all purposes of this agreement, including the preambles and exhibits, unless the context otherwise clearly requires.
     1.1.1 The term “gas” shall mean all vaporized hydrocarbons and vaporized concomitant materials, whether produced with oil or from gas or gas condensate wells.
     1.1.2 A “cubic foot of gas” shall mean the volume of gas contained in one cubic foot of space at a standard pressure base and a standard temperature base. The standard pressure base shall be 15.025 pounds per square inch absolute, and the standard temperature base shall be 60 degrees Fahrenheit. Whenever the conditions of pressure and temperature differ from the above standard, conversion of the volume from these conditions to the standard conditions shall be made in accordance with the Ideal Gas Laws, corrected for deviation by the methods set forth in the American Gas Association Measurement Committee Report No. 3 dated April 1955, as said report may be amended from time to time. The terms “MCF” and “MMCF” shall relate, respectively, the 1,000 cubic feet of gas and 1,000,000 cubic feet of gas.
     1.1.3 “Bypassed Gas” shall mean gas which has been delivered to Plant Owners at the Plant Delivery Point, but which has been returned to Southern at the Plant Redelivery Point without having been processed.
     1.1.4 “Committed Gas” shall mean the gas produced by a Plant Owner which has been committed to and made available for processing in the Toca Plant by virtue of such Plant Owner’s ownership of capacity in the Plant under the provisions of the Construction and Operating Agreement.

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     1.1.5 “Construction and Operating Agreement” shall mean that certain agreement entitled “Agreement for the Construction and Operation of the Toca Gas Processing Plant, St. Bernard Parish, Louisiana”, entered into effective as of July 1, 1970 by Plant Owners to provide for the construction, ownership and operation of the Toca Plant.
     1.1.6 “Determined Plant Capacity” shall mean the gas handling capacity of the Plant at design recovery levels, which currently is deemed to be 1030.0 MMCF/D, but the Plant gas handling capacity and/or liquid recovery levels shall be subject to revision from time to time by Plant Owners to reflect Plant capacity; provided that in any such adjustment the gas handling capacity shall never be adjusted below 1030.0 MMCF/D, nor shall it be determined to be greater, at normal recovery levels of 90 percent propane, than 80 percent of the maximum gas handling capacity of the Plant at a delivery pressure of 800 psia and with a Plant pressure loss not to exceed 35 psi.
     1.1.7 “Field Delivery Point” shall mean any point at which gas being transported in Southern’s Lines and subject to processing in the Plant is initially measured for the purpose of delivery for sale or for transportation.
     1.1.8 “Fractionator” shall mean Enterprise Products Operating LLC in its capacity as owner and operator of the Norco Fractionation Plant and related pipelines and facilities.
     1.1.9 “ Fractionation Expense ” shall mean the fractionation expense calculated per the terms and conditions of Exhibit “C.”
     1.1.10 “Gallon” shall mean a standard U.S. liquid gallon of 231 cubic inches when said liquid has a temperature of 60 degrees Fahrenheit and is at a pressure sufficient for liquification.
     1.1.11 “Gas Transporter” shall mean the party or parties who transport the gas produced from the respective Exhibit “E” field or fields from time to time.
     1.1.12 “ Gross Receipts ” shall mean the monthly revenue calculated from the value of the individual Products (expressed in cents per gallon) multiplied by the volume of the Products allocated to the Plant Supplier. The value of each individual Product shall be based on the pricing

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basis set forth under Exhibit “D”, as such pricing basis may change from time to time as provided in Exhibit C.
     1.1.13 “ Inert Constituents ” shall mean non-hydrocarbon constituents contained in Gas, including, without limitation, carbon dioxide, water vapor, ozone, nitrous oxide, and mercury, but, for the avoidance of doubt, expressly excluding NGLs.
     1.1.14 “ Liquid Hydrocarbons ”, sometimes herein used to refer to liquefiable hydrocarbons present in the gas stream and sometimes herein used to refer to hydrocarbons in a liquid state after extraction by the Plant from the gas stream, shall in either case mean natural gasoline (iso-pentanes plus heavier hydrocarbons), butanes, propane and ethane.
     1.1.15 “ Net Proceeds ” shall mean the Gross Receipts obtained from the sale of the share of Products to which Plant Supplier is entitled under this Agreement when Plant Operator under the terms of this Agreement is authorized to make such sale, less the following costs and expenses: (a) excise, sales, use, severance, gathering, processing, fuel use, or other similar taxes (reference Article IX.3) imposed by any taxing authority having or asserting jurisdiction over the production, sale or use of the Products and which tax Processor is obligated to pay; (b) actual tank car expense if the Product is shipped in tank cars, and rail transportation and/or other rail carrier costs if incurred by Processor; (c) actual other transportation costs if incurred by Processor, and (d) the Fractionation Expense.
     1.1.16 “Plant Delivery Point” shall mean the point on Southern’s Lines at which gas is delivered by Southern to Plant Owners for processing in the Plant.
     1.1.17 “Plant Operator” shall mean Enterprise Products Operating LLC or any successor to Enterprise Products Operating LLC selected by Toca Plant Owners to operate the Plant.
     1.1.18 “Plant Redelivery Point” shall mean the point on Southern’s Lines at which Residue Gas is returned by Plant Owners to Southern.
     1.1.19 “Plant Supplier” shall mean any Plant Supplier, including Plant Supplier hereunder, whose gas is being transported through Southern’s Lines and who has entered into a Gas

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Processing Agreement or a Products Purchase Agreement with Plant Operator to have gas processed in the Plant. Such term shall also apply to a Plant Owner with respect to Committed Gas made available by it for processing in the Plant in excess of 125 percent of such Owner’s capacity in the Plant, which excess, as provided in the Construction and Operating Agreement, is considered to be under a Products Purchase Agreement.
     1.1.20 “Products” shall mean the commercial products fractionated from the Raw Make by Fractionator at the Norco Fractionation Plant pursuant to the terms of the Fractionation Agreement, including, but not limited to, natural gasoline, butanes, propane and ethane (including such methane allowable in commercial ethane), and shall include any Liquid Hydrocarbons recovered by the inlet scrubber at the Plant for which the preferred disposition is at the Plant rather than being combined with the Raw Make.
     1.1.21 “Raw Make” shall mean the combined stream of Liquid Hydrocarbons and concomitant materials recovered from gas processed in the Plant and shall include any liquefied hydrocarbons recovered by the Plant inlet scrubber if combined with the Raw Make.
     1.1.22 “Residue Gas” shall mean the stream of gas returned to Southern at the Plant Redelivery Point after the gas received from Southern has been processed in the Plant for the recovery of Liquid Hydrocarbons and shall include any Bypassed Gas commingled with such processed gas.
     1.1.23 “Southern’s Lines” shall mean that portion of Southern’s gas pipeline system upstream of the Plant Delivery Point, plus any present or future extensions or loops thereof, which is transporting unprocessed gas for processing at the Plant site.
     1.1.24 “Toca Plant Owners” or “Plant Owners” shall mean the parties who own the Toca Plant, whether presently or in the future.
     1.1.25 “Transportation Agreement” shall mean the applicable agreement in place from time to time between Southern and Plant Supplier or Gas Transporter which covers the transportation of the gas to the Plant to be processed hereunder.

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ARTICLE II — EXHIBITS
     2.1 Exhibits . The following exhibits are attached to and made a part of this agreement:
     2.1.1 Exhibit “A” , which is an example calculation illustrating the procedure for allocating Products to Plant Owners and Plant Suppliers.
     2.1.2 Exhibit “B” , which is an example calculation illustrating the procedure for calculating and allocating Plant Volume Reduction.
     2.1.3 Exhibit “C” , which is description of the procedure for calculating the Fractionation Expense.
     2.1.4 Exhibit “D” , which lists the Product prices.
     2.1.5 Exhibit “E” , which lists the Field Delivery Point(s) from which gas to be processed hereunder is produced. Exhibit “D” may be amended to add additional Field Delivery Points from time to time upon mutual agreement of Processor and Plant Supplier.
     2.1.6 Exhibit “F” , which lists the Plant Supplier’s accounts payable address for checks or bank instructions for wire transfer, federal tax identification number, and invoice and plant statement addresses, all of which provide the settlement instructions for the transactions hereunder. Exhibit “E” may be amended by Plant Supplier from time to time.
ARTICLE III — CAPACITY OF PLANT
     3.1 Plant Design . The Toca Plant is designed to extract approximately 50 percent of the ethane and over 90 percent of the propane, together with essentially all of the butanes and heavier liquefiable hydrocarbons contained in the gas at a gas flow rate of 1030 MMCF per day, with gas handling facilities designed to handle 1030 MMCF per day at a delivery pressure of 800 psia and with a Plant pressure loss not to exceed 35 psi. The pressure base for the foregoing design specifications is 14.73 pounds per square inch absolute at a temperature base of 60 degrees Fahrenheit; however, a pressure base of 15.025 pounds psia shall be used in connection with any

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adjustment of the Determined Plant Capacity and for determining the Plant capacity which is owned and/or utilized by Plant Owners.
     3.2 Capacity Not Warranted . Plant Supplier hereby specifically recognizes that the foregoing representations regarding the processing capacity of the Toca Plant are merely advisory and do not constitute a warranty by or obligation of Processor as to capacity. Plant Supplier further recognizes that the Determined Plant Capacity may change from time to time as the result of operating experience or performance tests or alterations made to the Plant by Plant Owners.
ARTICLE IV — DELIVERY AND REDELIVERY OF PLANT SUPPLIER’S GAS
     4.1 Gas to be Delivered by Plant Supplier . Commencing as of the Effective Date, Plant Supplier shall deliver to Processor at the Plant Delivery Point for processing hereunder all of Plant Supplier’s gas delivered to the Field Delivery Point(s) listed on Exhibit “E”, less and except Plant Supplier’s pro rata share of the gas which is used by Southern for compressor fuel, incidental sales of gas for drilling purposes and other routine and normal uses as may be necessary to the maintenance of leases or operation of Southern’s Lines and also any gas lost in the normal operation of Southern’s Lines upstream of the Plant Delivery Point, including, but not limited to, gas lost in pipeline blowdown for repairs or tie-ins, cleaning and purging and in pipeline scrubber operations. Such deliveries of gas shall be continued hereunder during the term hereof. The rights granted herein by Plant Supplier to Processor are exclusive, and Liquid Hydrocarbons shall not be stripped in the field or elsewhere from Plant Supplier’s gas subject hereto prior to delivery at the Toca Plant other than by usual field separation methods which may include adiabatic expansion utilizing the natural pressures available from the wells, but shall exclude facilities designed to recover Liquid Hydrocarbons including but not limited to solid bed absorption, lean oil absorption, turbo-expander or mechanical refrigeration principles. In no event shall Processor be liable to Plant Supplier if Southern fails for any reason to deliver Plant Supplier’s gas to the Plant for processing as above provided.

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     4.2 When Plant Supplier’s Gas is to be Bypassed . During periods when the Plant is shut down because of mechanical failure, force majeure or necessary maintenance or repairs, all of Plant Supplier’s gas being transported through Southern’s Lines shall be Bypassed Gas. When the Plant is partially shut down for any of the above-mentioned reasons, or if the Plant lacks sufficient capacity to handle all gas available for processing from Southern’s Lines, Plant Supplier’s gas shall be processed only on a space available basis, and to the extent that gas handling capacity in the Plant, for any reason, is not available for such gas, such gas shall be preferentially bypassed along with the gas of any other Plant Suppliers which is made available for processing in the Plant. All of such gas bypassed preferentially will be determined monthly on an average daily basis and will be prorated to all Plant Suppliers under their respective agreements in the ratio that the average daily volume of gas made available by each during the month bears to the total average daily volumes made available by all such Plant Suppliers during the month; provided that, if any continuous period of complete shutdown of the Plant shall equal or exceed twelve (12) hours’ duration, the time of each such shutdown [determined to the nearest increment of six (6) hours] and the measured (or estimated, in the absence of measurement) volumes of gas bypassed during such determined period of shutdown shall be excluded in determining the average volume of Plant Suppliers’ gas considered to have been bypassed during the affected month for purposes hereof.
     4.3 Redelivery of Plant Supplier’s Gas to Southern’s Lines . After processing Plant Supplier’s gas delivered hereunder to the Plant, Processor shall redeliver the Residue Gas to Southern’s Lines at the Plant Redelivery Point. The Residue Gas prior to being commingled with any Bypassed Gas shall have a total or gross heating value of not less than one thousand (1,000) BTU’s per cubic foot (gross heating value saturated with water vapor) and shall otherwise comply with the quality specifications enumerated in the contract heretofore executed by Plant Owners and Southern; provided that the combined gas stream delivered by Southern at the Plant Delivery Point meets such specifications.
     4.4 Production Estimates . Effective as of the date of this Agreement, Processor requires from Plant Supplier five (5) days prior to the start of each month gas composition analyses

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and monthly volume forecast, i.e. monthly wellhead production estimates, daily pipeline nomination volume, or other delivery point information for any Gas that may be delivered into Southern’s Lines, for each Field Delivery Point (expressed in MCF per day).
ARTICLE V — ALLOCATION OF PRODUCTS
     5.1 General . Products fractionated from the Raw Make recovered from gas processed in the Plant shall be allocated to the source of each Plant Owner’s Committed Gas and each Plant Supplier’s gas in accordance with the procedure set forth in the following sections of this Article V, which procedure is illustrated by the example calculation set forth in Exhibit “A” hereto. As shown on said Exhibit, separate calculations shall be made for each Product. For the purposes of such allocations, Plant Supplier under this Agreement shall be allocated Products on the same basis as Products are allocated to Plant Owners. Processor will respond promptly to inquiries from Plant Supplier regarding daily operating rates and daily production rates at the Plant.
     5.2 “ Plant Supplier’s Inert Constituents ” Plant Supplier shall retain title to all Inert Constituents in the Natural Gas delivered by Plant Supplier under this Agreement (collectively, whether removed from the Natural Gas or not, “ Plant Supplier’s Inert Constituents ”), including but not limited to, carbon dioxide (CO2). To the extent that Processor removes Plant Supplier’s Inert Constituents from such Natural Gas and Plant Supplier has not made arrangements to utilize, market or dispose of Plant Supplier’s Inert Constituents, Processor may, but is not required to, dispose of some or all of Plant Supplier’s Inert Constituents by venting or other methods. If (i) venting Plant Supplier’s Inert Constituents is ever prohibited or disallowed for any reason or is deemed by Processor to be uneconomic, or (ii) additional costs are required to vent, dispose of or handle Plant Supplier’s Inert Constituents due to new rules, regulations or other laws, then Plant Supplier shall promptly (i) make alternate arrangements to utilize, market and/or dispose of Plant Supplier’s Inert Constituents at Plant Supplier’s sole cost and expense, (ii) notify Processor in writing and in reasonable detail of such alternate arrangements, and (iii) reimburse Processor for any costs incurred by Processor for delivering Plant Supplier’s Inert Constituents for such

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utilization, marketing and/or disposal. If Plant Supplier fails to comply with Plant Supplier’s obligations under the immediately preceding sentence, Processor shall be entitled, without further notice to Plant Supplier, to make arrangements for utilization, marketing and/or disposal of some or all of Plant Supplier’s Inert Constituents for Plant Supplier’s account and at Plant Supplier’s sole cost and expense; and Plant Supplier shall promptly reimburse Processor upon demand for any costs and expenses incurred by Processor in connection with such arrangements by Processor. PLANT SUPPLIER HEREBY RELEASES, INDEMNIFIES, DEFENDS AND HOLDS HARMLESS PROCESSOR AND PROCESSOR’S DIRECTORS, OFFICERS, EMPLOYEES, AGENTS, AND CONTRACTORS FROM AND AGAINST ANY AND ALL CLAIMS, DEMANDS, DAMAGES, LIABILITIES, EXPENSES, ACTIONS, CAUSES OF ACTION, LIABILITIES, LOSSES, TAXES, PENALTIES AND FEES ARISING OUT OF OR IN ANY WAY RELATING TO (I) ANY OR ALL OF PLANT SUPPLIER’S INERT CONSTITUENTS, INCLUDING, WITHOUT LIMITATION, THE UTILIZATION, MARKETING OR DISPOSAL THEREOF, AND/OR (II) ANY PERSONAL INJURY, DEATH, PROPERTY DAMAGE, ENVIRONMENTAL DAMAGE, POLLUTION, OR CONTAMINATION ARISING OUT OF OR RELATING TO ANY OR ALL OF PLANT SUPPLIER’S INERT CONSTITUENTS.
     If any Taxes (as defined in Section 9.2), fees or other impositions are ever imposed on Plant Supplier’s Inert Constituents and/or the utilization, marketing or disposal thereof, Plant Supplier shall promptly pay such Taxes. If such Taxes must be paid by Processor, Plant Supplier shall promptly reimburse Processor for any and all such Taxes paid by Processor with respect to any or all of Plant Supplier’s Inert Constituents. If Processor is required by applicable law to pay such Taxes on any or all of Plant Supplier’s Inert Constituents and it is unlawful for Plant Supplier to make such reimbursement to Processor for such Taxes, Plant Supplier and Processor shall promptly negotiate and execute an amendment to this Agreement which restores to Processor the same economic bargain as would have resulted if Plant Supplier, rather than Processor, had paid all Taxes on Plant Supplier’s Inert Constituents; and if Plant Supplier is unable or unwilling to

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promptly enter into such an amendment reasonably acceptable to Processor, Processor shall have the option, exercisable in Processor’s sole discretion, to terminate this Agreement by written notice to Plant Supplier.
     5.3 Basic Allocation Data . The volumes of gas which shall be credited as having been processed in the Plant shall be the sum of all volumes of gas delivered to Southern at the various Field Delivery Points, less the volumes deducted pursuant to Section 5.5 hereof. Representative determinations for Liquid Hydrocarbons content of the gas shall be made of the gas streams at each Field Delivery Point by Plant Operator quarterly or more often if found necessary, by chromatographic analysis or by some other acceptable method for testing gas for Liquid Hydrocarbons content. Plant Operator shall give Plant Supplier reasonable advance notice of tests to determine Liquid Hydrocarbons content of the gas at the Field Delivery Point(s) for Plant Supplier’s account so that Plant Supplier may witness such tests if desired. Plant Supplier agrees that the gas stream(s) made available for these tests shall be representative of the stream(s) normally delivered at the Field Delivery Point(s) for Plant Supplier’s account and will be at as near average delivery conditions and volumes as possible at the time. Plant Operator or Plant Supplier may request a retest if dissatisfied with the results of a particular test. If the request for a retest is made by Plant Supplier and the Liquid Hydrocarbons content of the previous test is confirmed within ten percent (10%), the expense of the retest shall be borne by Plant Supplier.
     5.4 Allocation of Products to the Respective Field Delivery Points . Such aforesaid volumes of gas which are credited as having been processed and the theoretical Liquid Hydrocarbons content of such gas at the respective Field Delivery Points shall be used as the basis for allocating each Product fractionated from the Raw Make to such Field Delivery Points by the method illustrated in Exhibit “A”. Such method contemplates that the volume of theoretical Liquid Hydrocarbons (separately for each Product) for each such Field Delivery Point will be calculated by multiplying the volume of gas credited as having been processed from such Field Delivery Point by the theoretical Liquid Hydrocarbons content (separately as to each Product) at each such Field Delivery Point. The total of each such Product fractionated from the Raw Make will, in turn, be

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allocated to such respective Field Delivery Points in the ratio that the volume of theoretical Product calculated for each Field Delivery Point bears to the sum of the volumes of such theoretical Product calculated for all such Field Delivery Points. Any Liquid Hydrocarbons recovered by the Plant inlet scrubber for which the preferred disposition is at the Plant rather than being combined with the Raw Make, shall be allocated to the Field Delivery Points in the same proportions as natural gasoline Product is allocated.
     5.5 Field Volume Statements and Sub-Allocations at Field Delivery Points . As soon as practicable, but no later than the twentieth (20th) day of each month, Plant Supplier shall furnish, or cause to be furnished, to Plant Operator a gas purchase statement by Gas Transporter or such other statement as Plant Operator may reasonably require, to show the volume of gas delivered during the preceding month from each of the Field Delivery Points for Plant Supplier’s account. Additionally, by the twentieth (20th) day of each such month, but only when gas owned by more than one Plant Supplier (including for Plant Supplier’s account) has been delivered through a single Field Delivery Point, Plant Supplier, if so situated, shall furnish or cause the operator of the Field Delivery Point to furnish to Plant Operator written instructions on sub-allocating the gas delivered through said Field Delivery Point and Products attributable thereto for such preceding month. Plant Operator shall be entitled to rely on the information thus furnished or caused to be furnished in sub-allocating the Products recovered and allocated to the particular Field Delivery Point.
     5.6 Pipeline Uses and Losses . From the quantities of gas measured at the respective Field Delivery Points as provided above, there shall be deducted any gas which may be lost, used or sold by Southern at any place on Southern’s Lines between such Field Delivery Points and the Plant Delivery Point, as more specifically set forth in Section 4.1 above. It is agreed that the volumes of such gas and the nature of each disposition, as reported by Southern to Plant Operator, shall be subtracted by Plant Operator from the quantities of gas measured at the Field Delivery Points. In making settlements hereunder, Plant Operator shall be entitled to rely upon the accuracy of such information as reported to it by Southern, but Plant Operator shall footnote settlement data supplied to the affected Plant Suppliers, noting the allocable amount of gas lost, used or sold by Southern. It

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is understood that the aforesaid volumes of gas lost, used or sold by Southern at any place on Southern’s Lines shall be allocated to all Field Delivery Points serving Southern’s Lines (including those Field Delivery Points serving the Lines from which gas will be processed in plants other than the Toca Plant) in the ratio which the volume of gas measured at each such Field Delivery Point during a month bears to the total volume of gas measured at all Field Delivery Points serving Southern’s Lines during the month.
     5.7 Product Allocation Statements . By the end of the month in which the information referred to in the preceding two sections is received, Plant Operator shall furnish a statement to all Plant Owners and Plant Suppliers accounting for the volume of gas delivered from each Field Delivery Point for the preceding month together with the amount of each individual Product allocated to said gas.
     5.8 Measurement of Field Volumes . All gas delivered at a Field Delivery Point shall be measured by a suitable orifice meter or meters of standard make furnished, installed, operated and kept in repair by the owners of the equipment at the point where delivery is made to Southern’s Lines which shall be the same meter or meters used under the provisions of each Plant Owner’s or Plant Supplier’s individual gas purchase contract with Gas Transporter. The volumes measured by said meter or meters shall be used for purposes of settlement under this agreement. The computation of all gas volumes measured by orifice meters shall be based on the latest orifice factors published by the American Gas Association corrected to a base pressure of 15.025 pounds per square inch absolute and at a base temperature of sixty degrees Fahrenheit (60°F), and the measurement procedures, technical requirements and standards for all such meters shall be as set out in each Owner’s or Plant Supplier’s gas purchase contract with its respective Gas Transporter. Plant Supplier agrees that the Plant Operator shall have the right to witness all tests of the meters and other equipment employed to measure volumes of gas delivered to Gas Transporter, and upon request, Plant Supplier shall give Plant Operator reasonable advance notice of all such tests.

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ARTICLE VI — CONSIDERATION DUE PLANT SUPPLIER

     6.1 Plant Supplier’s Consideration . Plant Supplier shall receive as full settlement hereunder each month eighty-four percent (84%) of the Net Proceeds attributable to such Gas for such month, as allocated to Plant Supplier’s Gas under Article VI hereof, less the Plant Share. Processor shall be entitled to sixteen percent (16%) of the Net Proceeds attributable to such Gas for such month (“Processor’s Proceeds”).

     Notwithstanding the foregoing, in no event shall the value of the Processor’s Proceeds be less than the value of $0.15 per MCF multiplied by the MCF of the Plant Supplier’s Gas at the Field Delivery Point.

ARTICLE VII — PLANT VOLUME REDUCTION AND BYPASSED GAS
     7.1 General . It is recognized that there will be a reduction in gas volumes, herein called “Plant Volume Reduction”, between the quantity of gas delivered by Southern for processing in the Plant and the volume of Residue Gas returned to Southern’s Lines because of (a) extraction of Raw Make, herein called the “shrinkage portion”, and (b) Plant fuel used, flared gas or other uses or losses incident to or occasioned by processing.
     7.2 Calculation of Plant Volume Reduction . The Plant Volume Reduction for the entire Plant shall be accounted for on a monthly basis and shall be calculated as follows:
     7.2.1 Shrinkage Portion . The vapor volume equivalent of each liquid component of the Raw Make shall be determined by multiplying the liquid volume of such component by the applicable vapor equivalent factor set forth in the schedule below. The total shrinkage portion of the Plant Volume Reduction will be equal to the sum of all such conversion computations made for each component of the Raw Make. Until revised by Plant Owners and Gas Transporters, the vapor equivalent factors set forth in the schedule below shall be used for all such conversion calculations:

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 	 	VAPOR EQUIVALENT	 	HEAT EQUIVALENT	
COMPONENTS	 	FACTOR (CF/GAL)	 	FACTOR (MMBTU/GAL)	
Carbon Dioxide	 	 	57.8528	 	 	 	0.000000	 	
Methane	 	 	57.8431	 	 	 	0.059729	 	
Ethane	 	 	36.6672	 	 	 	0.066338	 	
Propane	 	 	35.5942	 	 	 	0.091563	 	
Iso-Butane	 	 	29.9662	 	 	 	0.099629	 	
N-Butane	 	 	31.1047	 	 	 	0.103740	 	
Iso-Pentane	 	 	26.8137	 	 	 	0.109679	 	
N-Pentane	 	 	27.0524	 	 	 	0.110869	 	
Hexane	 	 	23.8466	 	 	 	0.115952	 	
Heptanes Plus*	 	 	 	 	 	 	 	 	
Taken from Gas Processors Association (“GPA”) Publication 2145-09. Vapor Equivalent factors are in cubic feet per gallon on the Ideal Gas Basis corrected from 14.696 psia to 15.025 psia. Such factors shall be modified from time to time to conform with any amendment or revision of the above table adopted by the GPA. Heat Equivalent factors are in MMBTU per Gallon. Such factors shall be modified from time to time to conform with any amendment or revision of the above table adopted by the GPA.

*	 	The Gas/liquid ratio for heptanes plus shall be determined from time to time as may be necessary to be representative of such components.	
The total shrinkage portion of the Plant Volume Reduction will be determined from measurement by positive displacement liquid meter and monthly composite sampling and analysis of the Raw Make.
     7.2.2 Determination of Losses . Plant fuel, flared gas and other uses or losses incident to processing: The volume of gas which is attributable to such uses or losses shall be as determined by the measurement with meters of each such use occurring in the Plant as may be necessary to determine accurately the total volume of gas so used, such meters to be installed and operated as mutually agreed by Plant Owners and Southern.
     7.2.3 Plant Volume Reduction Determination . All Plant Volume Reduction attributable to any other Plant use, loss or operation shall be determined by a method mutually agreeable to Plant Owners and Southern. It is understood that Plant Owners and Southern may agree on some other method of determining Plant Volume Reduction in order to remove any

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inequities which may be found to exist, and it is agreed that any such other method adopted shall be applicable to this agreement.
     7.3 Sharing of Plant Volume Reduction Among Plant Owners and Plant Suppliers . That portion of Plant Volume Reduction resulting from Plant fuel shall be the volume measured by orifice meters. The metered fuel volume shall be allocated to the respective Field Delivery Points of Plant Owners and Plant Suppliers on the following basis: One-half (1/2) in the same ratio that the sum of the gallons of propane and heavier Products (calculated separately for each Product) allocated to each Field Delivery Point bears to the sum of the gallons of propane and heavier Products (calculated separately for each Product) allocated to all Field Delivery Points, and one-half (1/2) in the ratio that the volume of gas processed from each such Field Delivery Point bears to the total volume of gas processed in the Plant. That portion of the Plant Volume Reduction remaining, after subtracting the metered fuel volume, shall be allocated to the respective Field Delivery Points of Plant Owners and Plant Suppliers in the same ratio that the sum of the vapor equivalent of all Products (calculated separately for each Product) allocated to each Field Delivery Point bears to the sum of the vapor equivalent of all Products (calculated separately for each Product) allocated to all Field Delivery Points to the Plant.
     7.4 Accounting to Gas Transporter for Plant Volume Reduction . Plant Supplier shall bear and shall account to Gas Transporter for the full amount of Plant Volume Reduction allocated to the gas credited as having been processed from the Field Delivery Points for Plant Supplier’s account monthly on such basis as may be provided in the applicable contract between Plant Supplier and Southern, or between the Gas Transporter and Southern, it being expressly understood that Plant Owners have no responsibility for any portion of such Plant Volume Reduction allocated pursuant hereto to the Field Delivery Points for Plant Supplier’s account. Plant Operator shall, by the end of the month in which it receives the accounting data required to be furnished by Plant Supplier under Section 5.5 and such additional accounting data as may be required from Plant Owners, other Suppliers and Southern, furnish Plant Supplier and other interested parties a statement setting forth:

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     7.4.1 The total quantity of Plant Volume Reduction; and
     7.4.2 Each Plant Owner’s and Plant Supplier’s proportionate share of the total Plant Volume Reduction; and
     7.4.3 An allocation of the Plant Volume Reduction applicable to each Field Delivery Point serving the Plant, and a sub-allocation as to gas which is owned by more than one Plant Supplier (including for Plant Supplier’s account) to show the amount of Plant Volume Reduction attributable to each Owner of the gas delivered at such Field Delivery Point.
The results set forth in such statement each month shall constitute the quantity of Plant Volume Reduction to be allocated to each Plant Owner and Plant Supplier for the preceding month, and it is understood that Gas Transporter may rely on such statements in effecting settlement with Plant Supplier for Plant Supplier’s share of Plant Volume Reduction. Plant Operator shall furnish the foregoing parties with an allocation statement based on estimated Plant Volume Reduction covering the first month of Plant operation. Plant Operator’s statement shall also report the volume of gas bypassed at the Plant during the preceding month and allocation thereof to Plant Owners and/or Plant Suppliers, including Plant Supplier.
     7.5 Determination of Bypassed Gas . Plant Owners shall install an orifice meter on the Plant bypass line for the purpose of measuring gas bypassed as herein provided, such meter to be installed, operated and measurement made thereby in conformity with the requirements agreed upon by Plant Owners and Southern.
     7.6 Sample Calculation of Plant Volume Reduction Allocation Procedure . The procedure for calculating and allocating Plant Volume Reduction in accordance with the provisions of this Article VII is illustrated by Exhibit “B” hereto.
ARTICLE VIII — TERM
     8.1 Term . This agreement shall apply to the gas described in Section 4.1 as of the Effective Date and shall remain in effect until terminated, effective at the end of any month, by

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either Processor or Plant Supplier on at least sixty (60) days prior written notice to the other party. This agreement shall also terminate upon the discontinuance of plant operations by Plant Owners based on their determination, in their sole discretion, that further plant operations would be unprofitable on at least thirty (30) day’s advanced written notice to the Plant Supplier.
ARTICLE IX — PAYMENT OF ROYALTY AND TAXES
     9.1 Royalty and Other Burdens on Production . Plant Supplier shall be solely responsible for accounting to or paying to the lessors, royalty owners and the owners, if any, of oil payments, overriding royalties, or other interests in production, under the lease or leases in the field or fields covered hereunder for their share, if any, of the Products or the proceeds derived therefrom attributable to the gas processed for Plant Supplier’s account hereunder.
     9.2 Severance and Other Taxes . Processor shall not be liable for the payment of any monies due hereunder to the lessors, royalty owners and the owners, if any, of oil payments or overriding royalties, under the lease or leases in the field or fields covered hereunder. Processor shall not be liable for any severance, gathering or equivalent Taxes due on the production, severance and handling of the Gas delivered by Plant Supplier for processing hereunder and the severance or similar Taxes due on Plant Supplier’s share of products hereunder where the same are taken in kind. Plant Supplier shall pay or cause to be paid any and all excise, sales, use, severance, gathering, processing, fuel use, or other similar Taxes or obligations due on the sale, use, production, severance, processing, transportation or handling of Plant Supplier’s Gas and condensate delivered to Processor hereunder or on Residue Gas, Products, or Raw Make extracted therefrom (or the proceeds attributable thereto, as the case may be), except for any Taxes assessed on the disposition of Processor’s share of such Residue Gas, Products, or Raw Make, if any, extracted from Plant Supplier’s Gas or condensate.
ARTICLE X — LAWS, REGULATIONS AND FORCE MAJEURE

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     10.1 Agreement Subject to Laws . This agreement shall be subject to all valid and applicable laws, orders, rules and regulations made by duly constituted governmental authorities.
     10.2 Force Majeure . Performance, other than to make payments due, under this agreement by the parties hereto, shall be excused in the event such performance is prevented by war, strikes, fires, floods, tornadoes, lightning, explosions, acts of God or of the public enemy, acts of governmental authorities, Federal or State regulations, inability or delay in obtaining servitudes, easements or permits, or material, and other happenings beyond the control of such parties, whether similar or dissimilar to the matters herein specifically enumerated; provided, however, that prompt written or telegraphic notice has been given by the party who is claiming to have been excused from performance by any of such causes to the other party and that performance shall be resumed within a reasonable time after such cause has been removed; and provided further, that no party hereto shall be required against its will to adjust any labor dispute.
ARTICLE XI — NOTICES
     All notices, settlement instructions or demands required or provided for herein shall be in writing and shall be considered as duly delivered when delivered by courier, facsimile, electronic mail, or mailed by prepaid registered or certified mail, addressed to the party to whom such notice is given as follows:

PLANT SUPPLIER :	 	Notices:	
 	 	 	
If by mail, facsimile or courier:	 	American Midstream, LLC	
 	 	Attn: Mary Ann Gonzales	
 	 	8300 FM 1960 West	
 	 	Houston TX 77070	
 	 	Phone: (281) 955-4815	
 	 	Facsimile: (281) 955-4855	
If by electronic mail:	 	Email: mgonzales@americanmidstream.com	

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PROCESSOR :	 	Notices:	
 	 	 	
If by mail:	 	Enterprise Gas Processing, LLC	
 	 	Attn: GOM Gas Processing Contract Administration	
 	 	P.O. Box 4324	
 	 	Houston, Texas 77210-4324	
 	 	Phone: (713) 381-4081	
 	 	Facsimile: (713) 381-4365	
 	 	 	
If by courier:	 	Enterprise Gas Processing, LLC	
 	 	Attn: GOM Gas Processing Contract Administration	
 	 	1100 Louisiana, Suite 1500	
 	 	Houston, Texas 77002	
 	 	Phone: (713) 381-4081	
 	 	 	
If by electronic mail:	 	GOMgasprocessing@eprod.com	
or to such other address as either party shall designate by like written notice to the other party. Routine communications, including statements, computations and allocations, may be transmitted by ordinary mail or electronic mail.
ARTICLE XII — INDEMNIFICATION
     Processor and Plant Supplier shall indemnify, defend and hold the other harmless from claims, demands and causes of action of every type and character arising out of the performance of this agreement which are asserted against the indemnitee by any person (including, without limitation, Processor’s and Plant Supplier’s employees) for personal injury, death, loss of or damage to property where such injury, death or loss of or damage to property is due to the sole negligence or sole willful misconduct of the indemnitor. Where personal injury, death, or loss of or damage to property is the result of joint negligence or willful misconduct of Processor and Plant Supplier, the indemnitor’s duty of indemnification shall be in the same proportion that the indemnitor’s negligent acts or omissions or willful misconduct contributed thereto. If Processor or Plant Supplier is strictly liable under law, the indemnitor’s duty of indemnification shall be in the same proportion that the indemnitor’s negligent acts or omissions contributed to the personal injury, illness, death, or losses of or damage to property for which the indemnitor is strictly liable.

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ARTICLE XIII — MISCELLANEOUS
     13.1 Access to Plant Supplier’s Premises . Processor shall have the right of access insofar as Plant Supplier has the right to grant such access to the Field Delivery Point(s) for Plant Supplier’s accounts for all purposes necessary for the fulfillment of this agreement.
     13.2 Separate Agreement . If the gas which is subject to processing hereunder is delivered from more than one Field Delivery Point, this agreement shall be considered a separate agreement as to each such Field Delivery Point and a separate accounting shall be made hereunder for the gas received from each such Point.
     13.3 Inspection of Records . Each party hereto shall have the right at all reasonable times during business hours to examine the books, records, charts, meters, measuring equipment and other pertinent matter or data of the other party relating to this agreement and to witness the tests of the other party to the extent necessary to verify the accuracy of any statement, charge, computation or demand under or pursuant to any of the provisions hereof. If any such examination shall reveal, or if either party shall otherwise discover, any error or inaccuracy in its own or the other party’s statements, payments, calculations or determinations, then proper adjustment and correction thereof shall be made as promptly as practicable thereafter; provided that, no adjustment of any statement, billing or payment shall be made after the lapse of two (2) years from the rendition thereof.
     13.4 Headings and Subheadings . Except when comprising a part of a sentence, the headings and subheadings used in this instrument are provided for reference purposes only and shall not be construed to interpret or amend any part of the text hereof.
     13.5 Successors and Assigns Bound . This agreement shall extend to and be binding upon the parties hereto, their respective successors and assigns, and shall follow and run with the title to the leases in the field or fields covered hereby, and the rights of either party may be assigned or conveyed in whole or in part, but all such assignments and conveyances shall be subject to this agreement. No transfer or succession to the interest of any party herein shall affect or bind the non-transferring party until the non-transferring party shall have been furnished at its address given

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above with the original recorded instrument or a certified copy of the recorded instrument under which the transfer or succession takes place.
     13.6 Conflicts. To the extent of any conflict between any portion of the written text of this Agreement or any Exhibit and any of the example(s) contained in this Agreement or any Exhibit hereto, the example(s) shall control.
     13.7 Media or Press Releases . No party shall issue a media or press release regarding the matters which are the subject of this Agreement unless such party has obtained the prior written consent of the other parties, except where such release is deemed in good faith by the releasing party to be required by applicable laws or applicable rules or regulations of any governmental body or stock exchange. However, any party that fails to object to a media or press release within seventy-two (72) hours following proper notice of the proposed media or press release will be deemed to have consented to such media or press release. The parties shall use reasonable efforts to unanimously agree upon the timing and content of releases to the news media concerning operations covered by this Agreement. However, in the event the parties cannot unanimously agree upon either the timing and/or content of the news release within seventy-two (72) hours of receipt of such proposed news release, then any party shall be allowed to issue its own release without the approval of the other parties.
[ Signatures are on the next page. ]

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      IN WITNESS WHEREOF , this Agreement is executed by the parties hereto on the date first above written.

		
 	 	PLANT SUPPLIER :	 	 	
 	 	 	 	 	 	 	
 	 	AMERICAN MIDSTREAM, LLC	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Brian Bierbach	 	 	
 	 	Name:	 	 
Brian Bierbach	 	 	
 	 	Title:	 	 
President	 	 	
 	 	 	 	 	 	 	
 	 	PROCESSOR :	 	 	
 	 	 	 	 	 	 	
 	 	ENTERPRISE GAS PROCESSING, LLC	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ William S. Goloway 	 	 	
 	 	 	 	 
William S. Goloway	 	 	
 	 	 	 	Regional Director	 	 	

 	 	 	
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EXHIBIT “A”
TO GAS PROCESSING CONTRACT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
EXAMPLE CALCULATION
PROCUT ALLOCATION PROCEDURE

I.	 	CALCULATION OF TOTAL PLANT PRODUCTS	

SUMMARY OF RAW MAKE PRODUCTION
 	 	 	 	 	
COMPONENT	 	GALLONS	 	
CO2	 	 	200,000	 	
 	 	 	 	 	
C1	 	 	200,000	 	
C2	 	 	9,000,000	 	
C3	 	 	5,000,000	 	
IC4	 	 	1,400,000	 	
NC4	 	 	1,700,000	 	
IC5	 	 	800,000	 	
NC5	 	 	600,000	 	
C6	 	 	850,000	 	
C7+	 	 	900,000	 	
 	 	 	 	
Subtotal          	 	 	20,650,000	 	
Scrubber          	 	 	100,000	 	
 	 	 	 	
Total          	 	 	20,750,000	 	
PLANT PRODUCTS
 	 	 	 	 	
PRODUCT	 	GALLONS	 	
Ethane	 	 	9,086,913	 	
 	 	 	 	 	
Propane	 	 	5,000,000	 	
Iso-Butane	 	 	1,400,000	 	
Normal Butane	 	 	1,700,000	 	
Natural Gasoline	 	 	3,150,000	 	
Scrubber	 	 	100,000	 	

Total          	 	 	20,436,913	 	
The ethane product contains:

(1)	 	The total ethane component	
 		
(3)	 	All methane up to a maximum of 1.5 mol% of the total ethane product            (0.009657 x C2 Gals)	

II.	 	ALLOCATION OF GASLINE TO FIELD DELIVERY POINTS	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	GALLONS	 	 	 	 	 	 	
FIELD DELIVERY	 	GAS CREDITED AS	 	FIELD C5+	 	THEORETICALLY	 	 	 	 	 	ALLOCATED	
POINT	 	PROCESSED IN MCF	 	GPM	 	AVAILABLE	 	FRACTION DUE	 	GALLONS	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
A	 	 	4,000,000	 	 	 	0.15	 	 	 	600,000	 	 	 	0.181	 	 	 	569,277	 	
B	 	 	10,000,000	 	 	 	0.20	 	 	 	2,000,000	 	 	 	0.602	 	 	 	1,897,590	 	
C	 	 	2,400,000	 	 	 	0.30	 	 	 	720,000	 	 	 	0.217	 	 	 	683,133	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	16,400,000	 	 	 	 	 	 	 	3,320,000	 	 	 	 	 	 	 	3,150,000	 	
The other Products are allocated in the same manner except that other Producers may receive no ethane.
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EXHIBIT “B”
PLANT THERMAL REDUCTION
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
EXAMPLE CALCULATION

I.	 	TOTAL PLANT THERMAL REDUCTION (SEE EXHBITI “A”)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	VAPOR/HEAT EQUIVALENT	 	TOTAL	 	 	
SUMMARY OF RAW MAKE PRODUCTION	 	FACTORS	 	SHRINKAGE	 	PLANT FUEL	
COMPONENT	 	GALLONS	 	CF/GAL	 	MMBTU/GAL	 	MCF	 	MMBTU	 	MMBTU	 	MCF	
CO2	 	 	200,000	 	 	 	57.8528	 	 	 	0.000000	 	 	 	11,571	 	 	 	—	 	 	 	 	 	 	 	 	 	
C1	 	 	200,000	 	 	 	57.8431	 	 	 	0.059729	 	 	 	11,569	 	 	 	11,946	 	 	 	 	 	 	 	 	 	
C2	 	 	9,000,000	 	 	 	36.6672	 	 	 	0.066338	 	 	 	330,105	 	 	 	597,045	 	 	 	 	 	 	 	 	 	
C3	 	 	5,000,000	 	 	 	35.5942	 	 	 	0.091563	 	 	 	177,971	 	 	 	457,813	 	 	 	 	 	 	 	 	 	
IC4	 	 	1,400,000	 	 	 	29.9662	 	 	 	0.099629	 	 	 	41,953	 	 	 	139,480	 	 	 	 	 	 	 	 	 	
NC4	 	 	1,700,000	 	 	 	31.1047	 	 	 	0.103740	 	 	 	52,878	 	 	 	176,359	 	 	 	 	 	 	 	 	 	
IC5	 	 	800,000	 	 	 	26.8137	 	 	 	0.109679	 	 	 	21,451	 	 	 	87,743	 	 	 	 	 	 	 	 	 	
NC5	 	 	600,000	 	 	 	27.0524	 	 	 	0.110869	 	 	 	16,231	 	 	 	66,521	 	 	 	 	 	 	 	 	 	
C6	 	 	850,000	 	 	 	23.8466	 	 	 	0.115952	 	 	 	20,270	 	 	 	98,559	 	 	 	 	 	 	 	 	 	
C7+	 	 	900,000	 	 	 	 	 	 	 	 	 	 	 	21,354	 	 	 	121,977	 	 	 	 	 	 	 	 	 	
Scrubber	 	 	100,000	 	 	 	 	 	 	 	 	 	 	 	2,372	 	 	 	14,906	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	20,750,000	 	 	 	 	 	 	 	 	 	 	 	707,624	 	 	 	1,769,349	 	 	 	280,000	 	 	 	293,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1.046	 	

II.	 	DETERMINATION OF HEAT FACTORS FOR ETHANE AND NATURAL GASOLINE	

A.	 	Ethane Product Heat Factor	 	=	 	Total MMBTU for C1 & C2
Total MCF for CO2, C1 & C2	
 	 	 	 	 	 	 	
 	 	 	 	=	 	(   11,946 + 597,045   )
(11,571 + 11,569 + 330,105)	
 	 	 	 	 	 	 	
 	 	 	 	=	 	1.7245 MMBTU/MCF	
 	 	 	 	 	 	 	
B.	 	Gasoline Product Heat Factor
     (scrubber heat factor calculated
     in similar manner)	 	=	 	Total MMBTU for IC5, NC5, C6 & C7+
Total MCF for IC5, NC5, C6 & C7+	
 	 	 	 	=	 	(   87,743 + 66,521 + 98,559 + 121,977   )
(   21,451 + 16,231 + 20,270 + 21,354   )	
 	 	 	 	 	 	 	
 	 	 	 	=	 	4.7260 MMBTU/MCF	
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EXHIBIT “B” (continued)

III.	 	ALLOCATION OF PLANT THERMAL REDUCTION OTO DELIVERY POINT “A”	

 	A.	 	SHRINKAGE PORTION	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	VAPOR	 	HEAT	 	TOTAL	
 	 	ALLOCATED	 	FACTORS	 	FACTORS	 	SHRINKAGE	
PRODUCT	 	GALLONS	 	MCF/GAL	 	MMBTU/MCF	 	MMBTU	
Ethane	 	 	1,000,000	 	 	 	0.03886	 	 	 	1.7245	 	 	 	67,018	 	
Propane	 	 	500,000	 	 	 	0.03559	 	 	 	2.5724	 	 	 	45,781	 	
Iso-Butane	 	 	100,000	 	 	 	0.02997	 	 	 	3.3247	 	 	 	9,963	 	
Normal Butane	 	 	100,000	 	 	 	0.03111	 	 	 	3.3352	 	 	 	10,374	 	
Gasoline	 	 	403,846	 	 	 	0.02518	 	 	 	4.7260	 	 	 	48,051	 	
Scrubber	 	 	12,821	 	 	 	0.02372	 	 	 	5.0195	 	 	 	1,527	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	2,116,667	 	 	 	 	 	 	 	 	 	 	 	182,714	 	

    B.	 	FUEL PORTION	 	 	 	 	
 	 	 	 	 	 	 	 	 	
 	 	1.	 	Half allocated on gas volume	 	=	 	50% x 4,000,000 / 16,400,000 x 293,000 MMBTU	
 	 	 	 	 	 	=	 	35,732 MMBTU	
 	 	 	 	 	 	 	 	 	
 	 	2.	 	Half allocated on C3+ Products	 	=	 	50% x 1,103,846 / 11,250,000 x 293,000 MMBTU	
 	 	 	 	 	 	=	 	14,475 MMBTU	
 	 	 	 	 	 	 	 	 	
 	 	3.	 	Total Fuel Allocation	 	=	 	50,106 MMBTU	
 	 	 	 	 	 	 	 	 	
    C.	 	FLARE & OTHER LOSSES PORTION	 	 	 	2,000 MMBTU	
 	 	 	 	 	 	 	 	 	
 	 	 	 	Allocated based on Shrinkage	 	=	 	182,714 / 1,769,349 x 2,000	
 	 	 	 	 	 	=	 	207 MMBTU	
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EXHIBIT “C”
TO
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
FRACTIONATION FEE
Beginning on the effective date of this Agreement, and on the first day of each month thereafter with respect to fuel gas, the Fractionation Fee shall be calculated based on the following formula (expressed in cents/Gallon):

		
(W)(1.20)	 	+	 	(2.40) =	 	Fractionation Fee	
 	 	 	 	 	 	 	
$4.00/MMBTU	 	 	 	 	 	¢/Gallon	

     With respect to the formula above, the following definition shall apply:
W = The settlement price in dollars per MMBtu, for the Henry Hub index (“Index”), as published in Inside F.E.R.C.’s Gas Market Report (“ IFERC ”), in effect for the month in which the Gas is being processed (e.g. IFERC price published on/near last day of February for March gas flows).

Notwithstanding anything to the contrary herein, in no event shall the adjustments permitted by the formula appearing above in this Agreement reduce the Fractionation Fee below 3.60 cents ($0.0360) per gallon (the “Fractionation Fee Floor”). In the event that the computation of the Fractionation Fee, as herein provided, results in an amount that is less than the 3.60 cents ($0.0360) per gallon, then the Parties acknowledge and agree that the Fractionation Fee shall be 3.60 cents ($0.0360) per gallon. In the event that anything in this Agreement conflicts or otherwise restricts the application of the Fractionation Fee Floor, the Fractionation Fee Floor shall fully apply and control.

 	 	 	
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EXHIBIT “D”
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
PRODUCT INDEX BASES

Product	 	Pricing Basis	
Ethane	 	OPIS monthly average (of daily high and low) price for Napoleonville ethane, less $0.005/gallon.	
 	 	 	
Propane	 	OPIS monthly average (of daily high and low) price for Napoleonville propane, less $0.0125/gallon.	
 	 	 	
Isobutane	 	OPIS monthly average (of daily high and low) price for Napoleonville isobutane, less $0.005/gallon.	
 	 	 	
Normal Butane	 	OPIS monthly average (of daily high and low) price for Napoleonville normal butane, less $0.0125/gallon.	
 	 	 	
Natural Gasoline	 	OPIS monthly average (of daily high and low) price for Napoleonville natural gasoline, less $0.005/gallon.	

NOTE: The above basis pricing reflects the Toca gas plant’s existing agreement for sale by the plant of natural gas liquids fob the Norco Fractionator Plant. The pricing basis herein may change from time-to-time, and upon notification of such change to Plant Supplier, the new pricing basis will become effective for the month following the month of such notification.

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EXHIBIT “E”
TO
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
PLANT SUPPLIER’S FIELDS FOR PROCESSING
FIELDS FOR WHICH PLANT SUPPLIER HOLDS PROCESSING RIGHTS TO GAS PRODUCED
THEREFROM AND WHICH IS TO BE PROCESSED HEREUNDER:

Delivery Point	 	Southern Meter Number	
 	 	 	
Creole Receiving Station	 	039500	

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EXHIBIT “F”
TO
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
SETTLEMENT INSTRUCTIONS
American Midstream, LLC (“Plant Supplier”)
Payments to Plant Supplier (wire) :
Comerica Bank
ABA: # 111000753
Account No.: 1881319493
For credit to: American Midstream, LLC
Federal Tax ID # 27-0855925
Plant Supplier’s Invoices/Statement Address:
American Midstream, LLC
Attn: Peter McNamara
8300 FM 1960 West
Houston TX 77070
Phone: (281) 955-4709
Fax: (281) 955-4855
Email Address: Peter McNamara PMcnamara@americanmidstream.com
COPY TO :
 American Midstream, LLC Attn: Kristy
Karm and Denise Tubb
1614 15 th Street, Suite 300
Denver CO 80202
Fax: (720) 457-6040
Email Addresses: Kristy Karm       KKarm@americanmidstream.com
                             Denise Tubb       DTubb@americanmidstream.com

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Exhibit 10.24
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
BETWEEN
AMERICAN MIDSTREAM, LLC
(PLANT SUPPLIER)
AND
ENTERPRISE GAS PROCESSING, LLC
(PROCESSOR)
NOVEMBER 1, 2010

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PRODUCTS PURCHASE AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
TABLE OF CONTENTS
 	 	 	 	 	
ARTICLES	 	PAGE NUMBER	 	
Article I — Definitions	 	 	2	 	
 	 	 	 	 	
Article II — Exhibits	 	 	6	 	
 	 	 	 	 	
Article III — Capacity of Plant	 	 	6	 	
 	 	 	 	 	
Article IV — Delivery and Redelivery of Plant Supplier’s Gas	 	 	7	 	
 	 	 	 	 	
Article V — Allocation of Products	 	 	9	 	
 	 	 	 	 	
Article VI — Consideration Due Plant Supplier	 	 	14	 	
 	 	 	 	 	
Article VII — Plant Volume Reduction and Bypassed Gas	 	 	14	 	
 	 	 	 	 	
Article VIII — Term	 	 	17	 	
 	 	 	 	 	
Article IX — Payment of Royalty and Taxes	 	 	18	 	
 	 	 	 	 	
Article X — Laws, Regulations and Force Majeure	 	 	18	 	
 	 	 	 	 	
Article XI — Notices	 	 	19	 	
 	 	 	 	 	
Article XII — Indemnification	 	 	20	 	
 	 	 	 	 	
Article XIII — Miscellaneous	 	 	20	 	
EXHIBITS
“A” — Example Calculation — Product Allocation Procedure
“B” — Example Calculation — Plant Volume Reduction
“C” — Fractionation Fee
“D” — Product Index Bases
“E” — Plant Supplier’s Field Delivery Point(s) for Processing
“F” — Settlement Instructions
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GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST . BERNARD PARISH , LOUISIANA
     THIS GAS PROCESSING AGREEMENT (the “Agreement”) is made and entered into this 1st day of November 2010 (the “Effective Date”), by and between AMERICAN MIDSTREAM, LLC (“Plant Supplier”) and ENTERPRISE GAS PROCESSING, LLC, (“Processor”).
R E C I T A L S
     A. WHEREAS, Processor has constructed the Toca Gas Processing Plant on a tract of land in Sections 54 and 55, T-14-S, R-4-E, St. Bernard Parish, Louisiana (herein called the “Toca Plant” or “Plant”), and operates said Plant for the purpose of extracting Liquid Hydrocarbons, as hereinafter defined, from certain gas delivered to the Plant from the pipeline system of Southern Natural Gas Company (herein called “Southern’s Lines”); and
     B. WHEREAS, the Toca Plant Owners have heretofore individually entered into an agreement with Enterprise Products Operating LLC, by and through its predecessor in interest, Shell Oil Company, as Owner of the Norco Fractionation Plant, entitled “Hydrocarbon Fractionation Agreement” (herein called “Fractionation Agreement”), whereby the Toca Plant Operator will deliver for the account of Plant Owners Raw Make, as hereinafter defined, recovered at the Toca Plant to Fractionator for transportation to the Norco Fractionation Plant and for fractionation into commercial Products; and
     C. WHEREAS, Plant Supplier owns or holds the gas processing rights to gas delivered to Field Delivery Point(s) listed on Exhibit “E”, attached hereto and incorporated herein by reference, and has the right to extract or have extracted the Liquid Hydrocarbons from such gas, which gas will be transported through Southern’s Lines to the Plant for Plant Supplier’s account; and
     D. WHEREAS, Processor and Plant Supplier desire hereby to provide the terms and conditions under which such gas will be delivered from Southern’s Lines to the Plant pursuant to the Transportation Agreement, as hereinafter defined, for processing for Plant Supplier’s account and

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the Liquid Hydrocarbons in such gas will be sold to Processor at the Plant Delivery Point for a consideration to Plant Supplier consisting of a share of Products, all as hereinafter more fully set forth;
     NOW, THEREFORE, in consideration of the premises and of the mutual covenants and agreements herein provided, the parties hereto agree as follows:
ARTICLE I — DEFINITIONS
     1.1 Definitions . The following definitions of terms shall apply for all purposes of this agreement, including the preambles and exhibits, unless the context otherwise clearly requires.
     1.1.1 The term “gas” shall mean all vaporized hydrocarbons and vaporized concomitant materials, whether produced with oil or from gas or gas condensate wells.
     1.1.2 A “cubic foot of gas” shall mean the volume of gas contained in one cubic foot of space at a standard pressure base and a standard temperature base. The standard pressure base shall be 15.025 pounds per square inch absolute, and the standard temperature base shall be 60 degrees Fahrenheit. Whenever the conditions of pressure and temperature differ from the above standard, conversion of the volume from these conditions to the standard conditions shall be made in accordance with the Ideal Gas Laws, corrected for deviation by the methods set forth in the American Gas Association Measurement Committee Report No. 3 dated April 1955, as said report may be amended from time to time. The terms “MCF” and “MMCF” shall relate, respectively, the 1,000 cubic feet of gas and 1,000,000 cubic feet of gas.
     1.1.3 “Bypassed Gas” shall mean gas which has been delivered to Plant Owners at the Plant Delivery Point, but which has been returned to Southern at the Plant Redelivery Point without having been processed.
     1.1.4 “Committed Gas” shall mean the gas produced by a Plant Owner which has been committed to and made available for processing in the Toca Plant by virtue of such Plant Owner’s ownership of capacity in the Plant under the provisions of the Construction and Operating Agreement.

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     1.1.5 “Construction and Operating Agreement” shall mean that certain agreement entitled “Agreement for the Construction and Operation of the Toca Gas Processing Plant, St. Bernard Parish, Louisiana”, entered into effective as of July 1, 1970 by Plant Owners to provide for the construction, ownership and operation of the Toca Plant.
     1.1.6 “Determined Plant Capacity” shall mean the gas handling capacity of the Plant at design recovery levels, which currently is deemed to be 1030.0 MMCF/D, but the Plant gas handling capacity and/or liquid recovery levels shall be subject to revision from time to time by Plant Owners to reflect Plant capacity; provided that in any such adjustment the gas handling capacity shall never be adjusted below 1030.0 MMCF/D, nor shall it be determined to be greater, at normal recovery levels of 90 percent propane, than 80 percent of the maximum gas handling capacity of the Plant at a delivery pressure of 800 psia and with a Plant pressure loss not to exceed 35 psi.
     1.1.7 “Field Delivery Point” shall mean any point at which gas being transported in Southern’s Lines and subject to processing in the Plant is initially measured for the purpose of delivery for sale or for transportation.
     1.1.8 “Fractionator” shall mean Enterprise Products Operating LLC in its capacity as owner and operator of the Norco Fractionation Plant and related pipelines and facilities.
     1.1.9 “ Fractionation Expense ” shall mean the fractionation expense calculated per the terms and conditions of Exhibit “C.”
     1.1.10 “Gallon” shall mean a standard U.S. liquid gallon of 231 cubic inches when said liquid has a temperature of 60 degrees Fahrenheit and is at a pressure sufficient for liquification.
     1.1.11 “Gas Transporter” shall mean the party or parties who transport the gas delivered from the respective Exhibit “E” Field Delivery Point(s) from time to time.
     1.1.12 “ Gross Receipts ” shall mean the monthly revenue calculated from the value of the individual Products (expressed in cents per gallon) multiplied by the volume of the Products allocated to the Plant Supplier. The value of each individual Product shall be based on the pricing

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basis set forth under Exhibit “D”, as such pricing basis may change from time to time as provided in Exhibit C.
     1.1.13 “ Inert Constituents ” shall mean non-hydrocarbon constituents contained in Gas, including, without limitation, carbon dioxide, water vapor, ozone, nitrous oxide, and mercury, but, for the avoidance of doubt, expressly excluding NGLs.
     1.1.14 “ Liquid Hydrocarbons ”, sometimes herein used to refer to liquefiable hydrocarbons present in the gas stream and sometimes herein used to refer to hydrocarbons in a liquid state after extraction by the Plant from the gas stream, shall in either case mean natural gasoline (iso-pentanes plus heavier hydrocarbons), butanes, propane and ethane.
     1.1.15 “ Net Proceeds ” shall mean the Gross Receipts obtained from the sale of the share of Products to which Plant Supplier is entitled under this Agreement when Plant Operator under the terms of this Agreement is authorized to make such sale, less the following costs and expenses: (a) excise, sales, use, severance, gathering, processing, fuel use, or other similar taxes (reference Article IX.3) imposed by any taxing authority having or asserting jurisdiction over the production, sale or use of the Products and which tax Processor is obligated to pay; (b) actual tank car expense if the Product is shipped in tank cars, and rail transportation and/or other rail carrier costs if incurred by Processor; (c) actual other transportation costs if incurred by Processor, and (d) the Fractionation Expense.
     1.1.16 “Plant Delivery Point” shall mean the point on Southern’s Lines at which gas is delivered by Southern to Plant Owners for processing in the Plant.
     1.1.17 “Plant Operator” shall mean Enterprise Products Operating LLC or any successor to Enterprise Products Operating LLC selected by Toca Plant Owners to operate the Plant.
     1.1.18 “Plant Redelivery Point” shall mean the point on Southern’s Lines at which Residue Gas is returned by Plant Owners to Southern.
     1.1.19 “Third Party Supplier” shall mean any Plant Supplier, including Plant Supplier hereunder, whose gas is being transported through Southern’s Lines and who has entered

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into a Gas Processing Agreement or a Products Purchase Agreement with Plant Operator to have gas processed in the Plant. Such term shall also apply to a Plant Owner with respect to Committed Gas made available by it for processing in the Plant in excess of 125 percent of such Owner’s capacity in the Plant, which excess, as provided in the Construction and Operating Agreement, is considered to be under a Products Purchase Agreement.
     1.1.20 “Products” shall mean the commercial products fractionated from the Raw Make by Fractionator at the Norco Fractionation Plant pursuant to the terms of the Fractionation Agreement, including, but not limited to, natural gasoline, butanes, propane and ethane (including such methane allowable in commercial ethane), and shall include any Liquid Hydrocarbons recovered by the inlet scrubber at the Plant for which the preferred disposition is at the Plant rather than being combined with the Raw Make.
     1.1.21 “Raw Make” shall mean the combined stream of Liquid Hydrocarbons and concomitant materials recovered from gas processed in the Plant and shall include any liquefied hydrocarbons recovered by the Plant inlet scrubber if combined with the Raw Make.
     1.1.22 “Residue Gas” shall mean the stream of gas returned to Southern at the Plant Redelivery Point after the gas received from Southern has been processed in the Plant for the recovery of Liquid Hydrocarbons and shall include any Bypassed Gas commingled with such processed gas.
     1.1.23 “Southern’s Lines” shall mean that portion of Southern’s gas pipeline system upstream of the Plant Delivery Point, plus any present or future extensions or loops thereof, which is transporting unprocessed gas for processing at the Plant site.
     1.1.24 “Toca Plant Owners” or “Plant Owners” shall mean the parties who own the Toca Plant, whether presently or in the future.
     1.1.25 “Transportation Agreement” shall mean the applicable agreement in place from time to time between Southern and Plant Supplier or Gas Transporter which covers the transportation of the gas to the Plant to be processed hereunder.

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ARTICLE II — EXHIBITS
     2.1 Exhibits . The following exhibits are attached to and made a part of this agreement:
     2.1.1 Exhibit “A” , which is an example calculation illustrating the procedure for allocating Products to Plant Owners and Third Party Suppliers.
     2.1.2 Exhibit “B” , which is an example calculation illustrating the procedure for calculating and allocating Plant Volume Reduction.
     2.1.3 Exhibit “C” , which is description of the procedure for calculating the Fractionation Expense.
     2.1.4 Exhibit “D” , which lists the Product prices.
     2.1.5 Exhibit “E” , which lists the Field Delivery Point(s) from which gas to be processed hereunder is produced. Exhibit “E” may be amended to add additional Field Delivery Points from time to time upon mutual agreement of Processor and Plant Supplier.
     2.1.6 Exhibit “F” , which lists the Plant Supplier’s accounts payable address for checks or bank instructions for wire transfer, federal tax identification number, and invoice and plant statement addresses, all of which provide the settlement instructions for the transactions hereunder. Exhibit “F” may be amended by Plant Supplier from time to time.
ARTICLE III — CAPACITY OF PLANT
     3.1 Plant Design . The Toca Plant is designed to extract approximately 50 percent of the ethane and over 90 percent of the propane, together with essentially all of the butanes and heavier liquefiable hydrocarbons contained in the gas at a gas flow rate of 1030 MMCF per day, with gas handling facilities designed to handle 1030 MMCF per day at a delivery pressure of 800 psia and with a Plant pressure loss not to exceed 35 psi. The pressure base for the foregoing design specifications is 14.73 pounds per square inch absolute at a temperature base of 60 degrees Fahrenheit; however, a pressure base of 15.025 pounds psia shall be used in connection with any

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adjustment of the Determined Plant Capacity and for determining the Plant capacity which is owned and/or utilized by Plant Owners.
     3.2 Capacity Not Warranted . Plant Supplier hereby specifically recognizes that the foregoing representations regarding the processing capacity of the Toca Plant are merely advisory and do not constitute a warranty by or obligation of Processor as to capacity. Plant Supplier further recognizes that the Determined Plant Capacity may change from time to time as the result of operating experience or performance tests or alterations made to the Plant by Plant Owners.
ARTICLE IV — DELIVERY AND REDELIVERY OF PLANT SUPPLIER’S GAS
     4.1 Gas to be Delivered by Plant Supplier . Commencing as of the Effective Date, Plant Supplier shall deliver to Processor at the Plant Delivery Point for processing hereunder all of Plant Supplier’s gas delivered to the Field Delivery Point(s) listed on Exhibit “E”, less and except Plant Supplier’s pro rata share of the gas which is used by Southern for compressor fuel, incidental sales of gas for drilling purposes and other routine and normal uses as may be necessary to the maintenance of leases or operation of Southern’s Lines and also any gas lost in the normal operation of Southern’s Lines upstream of the Plant Delivery Point, including, but not limited to, gas lost in pipeline blowdown for repairs or tie-ins, cleaning and purging and in pipeline scrubber operations. Such deliveries of gas shall be continued hereunder during the term hereof. The rights granted herein by Plant Supplier to Processor are exclusive, and Liquid Hydrocarbons shall not be stripped in the field or elsewhere from Plant Supplier’s gas subject hereto prior to delivery at the Toca Plant other than by usual field separation methods which may include adiabatic expansion utilizing the natural pressures available from the wells, but shall exclude facilities designed to recover Liquid Hydrocarbons including but not limited to solid bed absorption, lean oil absorption, turbo-expander or mechanical refrigeration principles. In no event shall Processor be liable to Plant Supplier if Southern fails for any reason to deliver Plant Supplier’s gas to the Plant for processing as above provided.

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     4.2 When Plant Supplier’s Gas is to be Bypassed . During periods when the Plant is shut down because of mechanical failure, force majeure or necessary maintenance or repairs, all of Plant Supplier’s gas being transported through Southern’s Lines shall be Bypassed Gas. When the Plant is partially shut down for any of the above-mentioned reasons, or if the Plant lacks sufficient capacity to handle all gas available for processing from Southern’s Lines, Plant Supplier’s gas shall be processed only on a space available basis, and to the extent that gas handling capacity in the Plant, for any reason, is not available for such gas, such gas shall be preferentially bypassed along with the gas of any other Third Party Suppliers which is made available for processing in the Plant. All of such gas bypassed preferentially will be determined monthly on an average daily basis and will be prorated to all Third Party Suppliers under their respective agreements in the ratio that the average daily volume of gas made available by each during the month bears to the total average daily volumes made available by all such Third Party Suppliers during the month; provided that, if any continuous period of complete shutdown of the Plant shall equal or exceed twelve (12) hours’ duration, the time of each such shutdown [determined to the nearest increment of six (6) hours] and the measured (or estimated, in the absence of measurement) volumes of gas bypassed during such determined period of shutdown shall be excluded in determining the average volume of Third Party Suppliers’ gas considered to have been bypassed during the affected month for purposes hereof.
     4.3 Redelivery of Plant Supplier’s Gas to Southern’s Lines . After processing Plant Supplier’s gas delivered hereunder to the Plant, Processor shall redeliver the Residue Gas to Southern’s Lines at the Plant Redelivery Point. The Residue Gas prior to being commingled with any Bypassed Gas shall have a total or gross heating value of not less than one thousand (1,000) BTU’s per cubic foot (gross heating value saturated with water vapor) and shall otherwise comply with the quality specifications enumerated in the contract heretofore executed by Plant Owners and Southern; provided that the combined gas stream delivered by Southern at the Plant Delivery Point meets such specifications.
     4.4 Production Estimates . Effective as of the date of this Agreement, Processor requires from Plant Supplier five (5) days prior to the start of each month gas composition analyses

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and monthly volume forecast, i.e. monthly wellhead production estimates, daily pipeline nomination volume, or other delivery point information for any Gas that may be delivered into Southern’s Lines, for each Field Delivery Point (expressed in MCF per day).
ARTICLE V — ALLOCATION OF PRODUCTS
     5.1 General . Products fractionated from the Raw Make recovered from gas processed in the Plant shall be allocated to the source of each Plant Owner’s Committed Gas and each Third Party Supplier’s gas in accordance with the procedure set forth in the following sections of this Article V, which procedure is illustrated by the example calculation set forth in Exhibit “A” hereto. As shown on said Exhibit, separate calculations shall be made for each Product. For the purposes of such allocations, Plant Supplier under this Agreement shall be allocated Products on the same basis as Products are allocated to Plant Owners. Processor will respond promptly to inquiries from Plant Supplier regarding daily operating rates and daily production rates at the Plant.
     5.2 “ Plant Supplier’s Inert Constituents ” Plant Supplier shall retain title to all Inert Constituents in the Natural Gas delivered by Plant Supplier under this Agreement (collectively, whether removed from the Natural Gas or not, “Plant Supplier’s Inert Constituents ”), including but not limited to, carbon dioxide (CO2). To the extent that Processor removes Plant Supplier’s Inert Constituents from such Natural Gas and Plant Supplier has not made arrangements to utilize, market or dispose of Plant Supplier’s Inert Constituents, Processor may, but is not required to, dispose of some or all of Plant Supplier’s Inert Constituents by venting or other methods. If (i) venting Plant Supplier’s Inert Constituents is ever prohibited or disallowed for any reason or is deemed by Processor to be uneconomic, or (ii) additional costs are required to vent, dispose of or handle Plant Supplier’s Inert Constituents due to new rules, regulations or other laws, then Plant Supplier shall promptly (i) make alternate arrangements to utilize, market and/or dispose of Plant Supplier’s Inert Constituents at Plant Supplier’s sole cost and expense, (ii) notify Processor in writing and in reasonable detail of such alternate arrangements, and (iii) reimburse Processor for any costs incurred by Processor for delivering Plant Supplier’s Inert Constituents for such utilization,

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marketing and/or disposal. If Plant Supplier fails to comply with Plant Supplier’s obligations under the immediately preceding sentence, Processor shall be entitled, without further notice to Plant Supplier, to make arrangements for utilization, marketing and/or disposal of some or all of Plant Supplier’s Inert Constituents for Plant Supplier’s account and at Plant Supplier’s sole cost and expense; and Plant Supplier shall promptly reimburse Processor upon demand for any costs and expenses incurred by Processor in connection with such arrangements by Processor. PLANT SUPPLIER HEREBY RELEASES, INDEMNIFIES, DEFENDS AND HOLDS HARMLESS PROCESSOR AND PROCESSOR’S DIRECTORS, OFFICERS, EMPLOYEES, AGENTS, AND CONTRACTORS FROM AND AGAINST ANY AND ALL CLAIMS, DEMANDS, DAMAGES, LIABILITIES, EXPENSES, ACTIONS, CAUSES OF ACTION, LIABILITIES, LOSSES, TAXES, PENALTIES AND FEES ARISING OUT OF OR IN ANY WAY RELATING TO (I) ANY OR ALL OF PLANT SUPPLIER’S INERT CONSTITUENTS, INCLUDING, WITHOUT LIMITATION, THE UTILIZATION, MARKETING OR DISPOSAL THEREOF, AND/OR (II) ANY PERSONAL INJURY, DEATH, PROPERTY DAMAGE, ENVIRONMENTAL DAMAGE, POLLUTION, OR CONTAMINATION ARISING OUT OF OR RELATING TO ANY OR ALL OF PLANT SUPPLIER’S INERT CONSTITUENTS.
     If any Taxes (as defined in Section 9.2), fees or other impositions are ever imposed on Plant Supplier’s Inert Constituents and/or the utilization, marketing or disposal thereof, Plant Supplier shall promptly pay such Taxes. If such Taxes must be paid by Processor, Plant Supplier shall promptly reimburse Processor for any and all such Taxes paid by Processor with respect to any or all of Plant Supplier’s Inert Constituents. If Processor is required by applicable law to pay such Taxes on any or all of Plant Supplier’s Inert Constituents and it is unlawful for Plant Supplier to make such reimbursement to Processor for such Taxes, Plant Supplier and Processor shall promptly negotiate and execute an amendment to this Agreement which restores to Processor the same economic bargain as would have resulted if Plant Supplier, rather than Processor, had paid all Taxes on Plant Supplier’s Inert Constituents; and if Plant Supplier is unable or unwilling to promptly enter

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into such an amendment reasonably acceptable to Processor, Processor shall have the option, exercisable in Processor’s sole discretion, to terminate this Agreement by written notice to Plant Supplier.
     5.3 Basic Allocation Data. The volumes of gas which shall be credited as having been processed in the Plant shall be the sum of all volumes of gas delivered to Southern at the various Field Delivery Points, less the volumes deducted pursuant to Section 5.5 hereof. Representative determinations for Liquid Hydrocarbons content of the gas shall be made of the gas streams at each Field Delivery Point by Plant Operator quarterly or more often if found necessary, by chromatographic analysis or by some other acceptable method for testing gas for Liquid Hydrocarbons content. Plant Operator shall give Plant Supplier reasonable advance notice of tests to determine Liquid Hydrocarbons content of the gas at the Field Delivery Point(s) for Plant Supplier’s account so that Plant Supplier may witness such tests if desired. Plant Supplier agrees that the gas stream(s) made available for these tests shall be representative of the stream(s) normally delivered at the Field Delivery Point(s) for Plant Supplier’s account and will be at as near average delivery conditions and volumes as possible at the time. Plant Operator or Plant Supplier may request a retest if dissatisfied with the results of a particular test. If the request for a retest is made by Plant Supplier and the Liquid Hydrocarbons content of the previous test is confirmed within ten percent (10%), the expense of the retest shall be borne by Plant Supplier.
     5.4 Allocation of Products to the Respective Field Delivery Points. Such aforesaid volumes of gas which are credited as having been processed and the theoretical Liquid Hydrocarbons content of such gas at the respective Field Delivery Points shall be used as the basis for allocating each Product fractionated from the Raw Make to such Field Delivery Points by the method illustrated in Exhibit “A”. Such method contemplates that the volume of theoretical Liquid Hydrocarbons (separately for each Product) for each such Field Delivery Point will be calculated by multiplying the volume of gas credited as having been processed from such Field Delivery Point by the theoretical Liquid Hydrocarbons content (separately as to each Product) at each such Field Delivery Point. The total of each such Product fractionated from the Raw Make will, in turn, be

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allocated to such respective Field Delivery Points in the ratio that the volume of theoretical Product calculated for each Field Delivery Point bears to the sum of the volumes of such theoretical Product calculated for all such Field Delivery Points. Any Liquid Hydrocarbons recovered by the Plant inlet scrubber for which the preferred disposition is at the Plant rather than being combined with the Raw Make, shall be allocated to the Field Delivery Points in the same proportions as natural gasoline Product is allocated.
     5.5 Field Volume Statements and Sub-Allocations at Field Delivery Points. As soon as practicable, but no later than the twentieth (20th) day of each month, Plant Supplier shall furnish, or cause to be furnished, to Plant Operator a gas purchase statement by Gas Transporter or such other statement as Plant Operator may reasonably require, to show the volume of gas delivered during the preceding month from each of the Field Delivery Points for Plant Supplier’s account. Additionally, by the twentieth (20th) day of each such month, but only when gas owned by more than one Plant Supplier (including for Plant Supplier’s account) has been delivered through a single Field Delivery Point, Plant Supplier, if so situated, shall furnish or cause the operator of the Field Delivery Point to furnish to Plant Operator written instructions on sub-allocating the gas delivered through said Field Delivery Point and Products attributable thereto for such preceding month. Plant Operator shall be entitled to rely on the information thus furnished or caused to be furnished in sub-allocating the Products recovered and allocated to the particular Field Delivery Point.
     5.6 Pipeline Uses and Losses. From the quantities of gas measured at the respective Field Delivery Points as provided above, there shall be deducted any gas which may be lost, used or sold by Southern at any place on Southern’s Lines between such Field Delivery Points and the Plant Delivery Point, as more specifically set forth in Section 4.1 above. It is agreed that the volumes of such gas and the nature of each disposition, as reported by Southern to Plant Operator, shall be subtracted by Plant Operator from the quantities of gas measured at the Field Delivery Points. In making settlements hereunder, Plant Operator shall be entitled to rely upon the accuracy of such information as reported to it by Southern, but Plant Operator shall footnote settlement data supplied

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to the affected Plant Suppliers, noting the allocable amount of gas lost, used or sold by Southern. It is understood that the aforesaid volumes of gas lost, used or sold by Southern at any place on Southern’s Lines shall be allocated to all Field Delivery Points serving Southern’s Lines (including those Field Delivery Points serving the Lines from which gas will be processed in plants other than the Toca Plant) in the ratio which the volume of gas measured at each such Field Delivery Point during a month bears to the total volume of gas measured at all Field Delivery Points serving Southern’s Lines during the month.
     5.7 Product Allocation Statements. By the end of the month in which the information referred to in the preceding two sections is received, Plant Operator shall furnish a statement to all Plant Owners and Third Party Suppliers accounting for the volume of gas delivered from each Field Delivery Point for the preceding month together with the amount of each individual Product allocated to said gas.
     5.8 Measurement of Field Volumes. All gas delivered at a Field Delivery Point shall be measured by a suitable orifice meter or meters of standard make furnished, installed, operated and kept in repair by the owners of the equipment at the point where delivery is made to Southern’s Lines which shall be the same meter or meters used under the provisions of each Plant Owner’s or Third Party Supplier’s individual gas purchase contract with Gas Transporter. The volumes measured by said meter or meters shall be used for purposes of settlement under this agreement. The computation of all gas volumes measured by orifice meters shall be based on the latest orifice factors published by the American Gas Association corrected to a base pressure of 15.025 pounds per square inch absolute and at a base temperature of sixty degrees Fahrenheit (60°F), and the measurement procedures, technical requirements and standards for all such meters shall be as set out in each Owner’s or Plant Supplier’s gas transportation contract. Plant Supplier agrees that the Plant Operator shall have the right to witness all tests of the meters and other equipment employed to measure volumes of gas delivered to Gas Transporter, and upon request, Plant Supplier shall give Plant Operator reasonable advance notice of all such tests.

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ARTICLE VI — CONSIDERATION DUE PLANT SUPPLIER

     6.1 Plant Supplier’s Consideration. Plant Supplier shall receive as full settlement hereunder each month ninety percent (90%) of the Net Proceeds attributable to such Gas for such month, as allocated to Plant Supplier’s Gas under Article VI hereof, less the Plant Share. Processor shall be entitled to ten percent (10%) of the Net Proceeds attributable to such Gas for such month (“Processor’s Proceeds”).

     Notwithstanding the foregoing, in no event shall the value of the Processor’s Proceeds be less than the value of $0.10 per MCF multiplied by the MCF of the Plant Supplier’s Gas at the Field Delivery Point.

ARTICLE VII — PLANT VOLUME REDUCTION AND BYPASSED GAS
     7.1 General . It is recognized that there will be a reduction in gas volumes, herein called “Plant Volume Reduction”, between the quantity of gas delivered by Southern for processing in the Plant and the volume of Residue Gas returned to Southern’s Lines because of (a) extraction of Raw Make, herein called the “shrinkage portion”, and (b) Plant fuel used, flared gas or other uses or losses incident to or occasioned by processing.
     7.2 Calculation of Plant Volume Reduction . The Plant Volume Reduction for the entire Plant shall be accounted for on a monthly basis and shall be calculated as follows:
     7.2.1 Shrinkage Portion. The vapor volume equivalent of each liquid component of the Raw Make shall be determined by multiplying the liquid volume of such component by the applicable vapor equivalent factor set forth in the schedule below. The total shrinkage portion of the Plant Volume Reduction will be equal to the sum of all such conversion computations made for each component of the Raw Make. Until revised by Plant Owners and Gas Transporters, the vapor equivalent factors set forth in the schedule below shall be used for all such conversion calculations:

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 	 	VAPOR EQUIVALENT	 	HEAT EQUIVALENT	
COMPONENTS	 	FACTOR (CF/GAL)	 	FACTOR (MMBTU/GAL)	
Carbon Dioxide	 	 	57.8528	 	 	 	0.000000	 	
Methane	 	 	57.8431	 	 	 	0.059729	 	
Ethane	 	 	36.6672	 	 	 	0.066338	 	
Propane	 	 	35.5942	 	 	 	0.091563	 	
Iso-Butane	 	 	29.9662	 	 	 	0.099629	 	
N-Butane	 	 	31.1047	 	 	 	0.103740	 	
Iso-Pentane	 	 	26.8137	 	 	 	0.109679	 	
N-Pentane	 	 	27.0524	 	 	 	0.110869	 	
Hexane	 	 	23.8466	 	 	 	0.115952	 	
Heptanes Plus*	 	 	 	 	 	 	 	 	
Taken from Gas Processors Association (“GPA”) Publication 2145-09. Vapor Equivalent factors are in cubic feet per gallon on the Ideal Gas Basis corrected from 14.696 psia to 15.025 psia. Such factors shall be modified from time to time to conform with any amendment or revision of the above table adopted by the GPA. Heat Equivalent factors are in MMBTU per Gallon. Such factors shall be modified from time to time to conform with any amendment or revision of the above table adopted by the GPA.
The Gas/liquid ratio for heptanes plus shall be determined from time to time as may be necessary to be representative of such components.
The total shrinkage portion of the Plant Volume Reduction will be determined from measurement by positive displacement liquid meter and monthly composite sampling and analysis of the Raw Make.
     7.2.2 Determination of Losses . Plant fuel, flared gas and other uses or losses incident to processing: The volume of gas which is attributable to such uses or losses shall be as determined by the measurement with meters of each such use occurring in the Plant as may be necessary to determine accurately the total volume of gas so used, such meters to be installed and operated as mutually agreed by Plant Owners and Southern.
     7.2.3 Plant Volume Reduction Determination. All Plant Volume Reduction attributable to any other Plant use, loss or operation shall be determined by a method mutually agreeable to Plant Owners and Southern. It is understood that Plant Owners and Southern may agree on some other method of determining Plant Volume Reduction in order to remove any inequities which may be found to exist, and it is agreed that any such other method adopted shall be applicable to this agreement.

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     7.3 Sharing of Plant Volume Reduction Among Plant Owners and Third Party Suppliers. That portion of Plant Volume Reduction resulting from Plant fuel shall be the volume measured by orifice meters. The metered fuel volume shall be allocated to the respective Field Delivery Points of Plant Owners and Third Party Suppliers on the following basis: One-half (1/2) in the same ratio that the sum of the gallons of propane and heavier Products (calculated separately for each Product) allocated to each Field Delivery Point bears to the sum of the gallons of propane and heavier Products (calculated separately for each Product) allocated to all Field Delivery Points, and one-half (1/2) in the ratio that the volume of gas processed from each such Field Delivery Point bears to the total volume of gas processed in the Plant. That portion of the Plant Volume Reduction remaining, after subtracting the metered fuel volume, shall be allocated to the respective Field Delivery Points of Plant Owners and Third Party Suppliers in the same ratio that the sum of the vapor equivalent of all Products (calculated separately for each Product) allocated to each Field Delivery Point bears to the sum of the vapor equivalent of all Products (calculated separately for each Product) allocated to all Field Delivery Points to the Plant.
     7.4 Accounting to Gas Transporter for Plant Volume Reduction. Plant Supplier shall bear and shall account to Gas Transporter for the full amount of Plant Volume Reduction allocated to the gas credited as having been processed from the Field Delivery Points for Plant Supplier’s account monthly on such basis as may be provided in the applicable contract between Plant Supplier and Southern, or between the Gas Transporter and Southern, it being expressly understood that Plant Owners have no responsibility for any portion of such Plant Volume Reduction allocated pursuant hereto to the Field Delivery Points for Plant Supplier’s account. Plant Operator shall, by the end of the month in which it receives the accounting data required to be furnished by Plant Supplier under Section 5.5 and such additional accounting data as may be required from Plant Owners, other Suppliers and Southern, furnish Plant Supplier and other interested parties a statement setting forth:
     7.4.1 The total quantity of Plant Volume Reduction; and

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7.4.2 Each Plant Owner’s and Third Party Supplier’s proportionate share of the total Plant Volume Reduction; and
7.4.3 An allocation of the Plant Volume Reduction applicable to each Field Delivery Point serving the Plant, and a sub-allocation as to gas which is owned by more than one Plant Supplier (including for Plant Supplier’s account) to show the amount of Plant Volume Reduction attributable to each Owner of the gas delivered at such Field Delivery Point.
The results set forth in such statement each month shall constitute the quantity of Plant Volume Reduction to be allocated to each Plant Owner and Third Party Supplier for the preceding month, and it is understood that Gas Transporter may rely on such statements in effecting settlement with Plant Supplier for Plant Supplier’s share of Plant Volume Reduction. Plant Operator shall furnish the foregoing parties with an allocation statement based on estimated Plant Volume Reduction covering the first month of Plant operation. Plant Operator’s statement shall also report the volume of gas bypassed at the Plant during the preceding month and allocation thereof to Plant Owners and/or Third Party Suppliers, including Plant Supplier.
     7.5 Determination of Bypassed Gas . Plant Owners shall install an orifice meter on the Plant bypass line for the purpose of measuring gas bypassed as herein provided, such meter to be installed, operated and measurement made thereby in conformity with the requirements agreed upon by Plant Owners and Southern.
     7.6 Sample Calculation of Plant Volume Reduction Allocation Procedure . The procedure for calculating and allocating Plant Volume Reduction in accordance with the provisions of this Article VII is illustrated by Exhibit “B” hereto.
ARTICLE VIII — TERM
     8.1 Term . This agreement shall apply to the gas described in Section 4.1 as of the November 1, 2010 and shall remain in full force and effect until February 28, 2011.

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ARTICLE IX — PAYMENT OF ROYALTY AND TAXES
     9.1 Royalty and Other Burdens on Production . Plant Supplier shall be solely responsible for accounting to or paying to the lessors, royalty owners and the owners, if any, of oil payments, overriding royalties, or other interests in production, under the lease or leases in the field or fields covered hereunder for their share, if any, of the Products or the proceeds derived therefrom attributable to the gas processed for Plant Supplier’s account hereunder.
     9.2 Severance and Other Taxes . Processor shall not be liable for the payment of any monies due hereunder to the lessors, royalty owners and the owners, if any, of oil payments or overriding royalties, under the lease or leases in the field or fields covered hereunder. Processor shall not be liable for any severance, gathering or equivalent Taxes due on the production, severance and handling of the Gas delivered by Plant Supplier for processing hereunder and the severance or similar Taxes due on Plant Supplier’s share of products hereunder where the same are taken in kind. Plant Supplier shall pay or cause to be paid any and all excise, sales, use, severance, gathering, processing, fuel use, or other similar Taxes or obligations due on the sale, use, production, severance, processing, transportation or handling of Plant Supplier’s Gas and condensate delivered to Processor hereunder or on Residue Gas, Products, or Raw Make extracted therefrom (or the proceeds attributable thereto, as the case may be), except for any Taxes assessed on the disposition of Processor’s share of such Residue Gas, Products, or Raw Make, if any, extracted from Plant Supplier’s Gas or condensate.
ARTICLE X — LAWS, REGULATIONS AND FORCE MAJEURE
     10.1 Agreement Subject to Laws . This agreement shall be subject to all valid and applicable laws, orders, rules and regulations made by duly constituted governmental authorities.
     10.2 Force Majeure . Performance, other than to make payments due, under this agreement by the parties hereto, shall be excused in the event such performance is prevented by war, strikes, fires, floods, tornadoes, lightning, explosions, acts of God or of the public enemy, acts of governmental authorities, Federal or State regulations, inability or delay in obtaining servitudes,

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easements or permits, or material, and other happenings beyond the control of such parties, whether similar or dissimilar to the matters herein specifically enumerated; provided, however, that prompt written or telegraphic notice has been given by the party who is claiming to have been excused from performance by any of such causes to the other party and that performance shall be resumed within a reasonable time after such cause has been removed; and provided further, that no party hereto shall be required against its will to adjust any labor dispute.
ARTICLE XI — NOTICES
     All notices, settlement instructions or demands required or provided for herein shall be in writing and shall be considered as duly delivered when delivered by courier, facsimile or mailed by prepaid registered or certified mail, addressed to the party to whom such notice is given as follows:

PLANT SUPPLIER:	 	Notices :	
 	 	 	
If by mail, courier or facsimile:	 	American Midstream, LLC
Attn: Gas Contracts
8300 FM 1960 West, Suite 225
Houston, TX 77070
Phone: 281-955-4800
Fax: 281-955-4855	
 	 	 	
If by electronic mail:	 	Email: bpieri@americanmidstream.com	
 	 	 	
PROCESSOR:	 	Notices :	
 	 	 	
If by mail or facsimile:	 	Enterprise Gas Processing, LLC
Attn: GOM Gas Processing Contract Administration
P.O. Box 4324
Houston, Texas 77210-4324
Telephone: (713) 381-4081
Facsimile: (713) 381-4365	
 	 	 	
If by courier:	 	Enterprise Gas Processing, LLC
Attn: GOM Gas Processing Contract Administration
1100 Louisiana, Suite 1500
Houston, Texas 77002
Telephone: (713) 381-4081	
 	 	 	
If by electronic mail:	 	GOMgasprocessing@eprod.com	

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or to such other address as either party shall designate by like written notice to the other party. Routine communications, including statements, computations and allocations, may be transmitted by ordinary mail or electronic mail.
ARTICLE XII — INDEMNIFICATION
     Processor and Plant Supplier shall indemnify, defend and hold the other harmless from claims, demands and causes of action of every type and character arising out of the performance of this agreement which are asserted against the indemnitee by any person (including, without limitation, Processor’s and Plant Supplier’s employees) for personal injury, death, loss of or damage to property where such injury, death or loss of or damage to property is due to the sole negligence or sole willful misconduct of the indemnitor. Where personal injury, death, or loss of or damage to property is the result of joint negligence or willful misconduct of Processor and Plant Supplier, the indemnitor’s duty of indemnification shall be in the same proportion that the indemnitor’s negligent acts or omissions or willful misconduct contributed thereto. If Processor or Plant Supplier is strictly liable under law, the indemnitor’s duty of indemnification shall be in the same proportion that the indemnitor’s negligent acts or omissions contributed to the personal injury, illness, death, or losses of or damage to property for which the indemnitor is strictly liable.
ARTICLE XIII — MISCELLANEOUS
     13.1 Access to Plant Supplier’s Premises . Processor shall have the right of access insofar as Plant Supplier has the right to grant such access to the Field Delivery Point(s) for Plant Supplier’s accounts for all purposes necessary for the fulfillment of this agreement.
     13.2 Separate Agreement . If the gas which is subject to processing hereunder is delivered from more than one Field Delivery Point, this agreement shall be considered a separate

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agreement as to each such Field Delivery Point and a separate accounting shall be made hereunder for the gas received from each such Point.
     13.3 Inspection of Records . Each party hereto shall have the right at all reasonable times during business hours to examine the books, records, charts, meters, measuring equipment and other pertinent matter or data of the other party relating to this agreement and to witness the tests of the other party to the extent necessary to verify the accuracy of any statement, charge, computation or demand under or pursuant to any of the provisions hereof. If any such examination shall reveal, or if either party shall otherwise discover, any error or inaccuracy in its own or the other party’s statements, payments, calculations or determinations, then proper adjustment and correction thereof shall be made as promptly as practicable thereafter; provided that, no adjustment of any statement, billing or payment shall be made after the lapse of two (2) years from the rendition thereof.
     13.4 Headings and Subheadings . Except when comprising a part of a sentence, the headings and subheadings used in this instrument are provided for reference purposes only and shall not be construed to interpret or amend any part of the text hereof.
     13.5 Successors and Assigns Bound . This agreement shall extend to and be binding upon the parties hereto, their respective successors and assigns, and shall follow and run with the title to the leases in the field or fields covered hereby, and the rights of either party may be assigned or conveyed in whole or in part, but all such assignments and conveyances shall be subject to this agreement. No transfer or succession to the interest of any party herein shall affect or bind the non-transferring party until the non-transferring party shall have been furnished at its address given above with the original recorded instrument or a certified copy of the recorded instrument under which the transfer or succession takes place.
     13.6 Conflicts. To the extent of any conflict between any portion of the written text of this Agreement or any Exhibit and any of the example(s) contained in this Agreement or any Exhibit hereto, the example(s) shall control.

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     13.7 Media or Press Releases . No party shall issue a media or press release regarding the matters which are the subject of this Agreement unless such party has obtained the prior written consent of the other parties, except where such release is deemed in good faith by the releasing party to be required by applicable laws or applicable rules or regulations of any governmental body or stock exchange. However, any party that fails to object to a media or press release within seventy-two (72) hours following proper notice of the proposed media or press release will be deemed to have consented to such media or press release. The parties shall use reasonable efforts to unanimously agree upon the timing and content of releases to the news media concerning operations covered by this Agreement. However, in the event the parties cannot unanimously agree upon either the timing and/or content of the news release within seventy-two (72) hours of receipt of such proposed news release, then any party shall be allowed to issue its own release without the approval of the other parties.
[Signatures are on the next page.]

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           IN WITNESS WHEREOF , this Agreement is executed by the parties hereto on the date first above written.
 	 	 	 	 	
 	PLANT SUPPLIER :

AMERICAN MIDSTREAM (LOUISIANA INTRASTATE), LLC
 	 	
 	By:  	/s/ Brian Bierbach  	 	
 	 	Brian Bierbach 	 	
 	 	President & CEO 	 	
 	
 	PROCESSOR :

ENTERPRISE GAS PROCESSING, LLC
 	 	
 	By:  	/s/ William S. Goloway  	 	
 	 	William S. Goloway 	 	
 	 	Regional Director 	 	

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EXHIBIT “A”
TO GAS PROCESSING CONTRACT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
EXAMPLE CALCULATION
PROCUT ALLOCATION PROCEDURE

I.	 	CALCULATION OF TOTAL PLANT PRODUCTS	

SUMMARY OF RAW MAKE PRODUCTION
 	 	 	 	 	
COMPONENT	 	GALLONS	 	
CO2	 	 	200,000	 	
 	 	 	 	 	
C1	 	 	200,000	 	
C2	 	 	9,000,000	 	
C3	 	 	5,000,000	 	
IC4	 	 	1,400,000	 	
NC4	 	 	1,700,000	 	
IC5	 	 	800,000	 	
NC5	 	 	600,000	 	
C6	 	 	850,000	 	
C7+	 	 	900,000	 	
 	 	 	 	
Subtotal          	 	 	20,650,000	 	
Scrubber          	 	 	100,000	 	
 	 	 	 	
Total          	 	 	20,750,000	 	
PLANT PRODUCTS
 	 	 	 	 	
PRODUCT	 	GALLONS	 	
Ethane	 	 	9,086,913	 	
 	 	 	 	 	
Propane	 	 	5,000,000	 	
Iso-Butane	 	 	1,400,000	 	
Normal Butane	 	 	1,700,000	 	
Natural Gasoline	 	 	3,150,000	 	
Scrubber	 	 	100,000	 	

Total          	 	 	20,436,913	 	
The ethane product contains:

(1)	 	The total ethane component	
 		
(3)	 	All methane up to a maximum of 1.5 mol% of the total ethane product            (0.009657 x C2 Gals)	

II.	 	ALLOCATION OF GASLINE TO FIELD DELIVERY POINTS	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	GALLONS	 	 	 	 	 	 	
FIELD DELIVERY	 	GAS CREDITED AS	 	FIELD C5+	 	THEORETICALLY	 	 	 	 	 	ALLOCATED	
POINT	 	PROCESSED IN MCF	 	GPM	 	AVAILABLE	 	FRACTION DUE	 	GALLONS	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
A	 	 	4,000,000	 	 	 	0.15	 	 	 	600,000	 	 	 	0.181	 	 	 	569,277	 	
B	 	 	10,000,000	 	 	 	0.20	 	 	 	2,000,000	 	 	 	0.602	 	 	 	1,897,590	 	
C	 	 	2,400,000	 	 	 	0.30	 	 	 	720,000	 	 	 	0.217	 	 	 	683,133	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	16,400,000	 	 	 	 	 	 	 	3,320,000	 	 	 	 	 	 	 	3,150,000	 	
The other Products are allocated in the same manner except that other Producers may receive no ethane.
 Page 1 

 

EXHIBIT “B”
PLANT THERMAL REDUCTION
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
EXAMPLE CALCULATION

I.	 	TOTAL PLANT THERMAL REDUCTION (SEE EXHBITI “A”)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	VAPOR/HEAT EQUIVALENT	 	TOTAL	 	 	
SUMMARY OF RAW MAKE PRODUCTION	 	FACTORS	 	SHRINKAGE	 	PLANT FUEL	
COMPONENT	 	GALLONS	 	CF/GAL	 	MMBTU/GAL	 	MCF	 	MMBTU	 	MMBTU	 	MCF	
CO2	 	 	200,000	 	 	 	57.8528	 	 	 	0.000000	 	 	 	11,571	 	 	 	—	 	 	 	 	 	 	 	 	 	
C1	 	 	200,000	 	 	 	57.8431	 	 	 	0.059729	 	 	 	11,569	 	 	 	11,946	 	 	 	 	 	 	 	 	 	
C2	 	 	9,000,000	 	 	 	36.6672	 	 	 	0.066338	 	 	 	330,105	 	 	 	597,045	 	 	 	 	 	 	 	 	 	
C3	 	 	5,000,000	 	 	 	35.5942	 	 	 	0.091563	 	 	 	177,971	 	 	 	457,813	 	 	 	 	 	 	 	 	 	
IC4	 	 	1,400,000	 	 	 	29.9662	 	 	 	0.099629	 	 	 	41,953	 	 	 	139,480	 	 	 	 	 	 	 	 	 	
NC4	 	 	1,700,000	 	 	 	31.1047	 	 	 	0.103740	 	 	 	52,878	 	 	 	176,359	 	 	 	 	 	 	 	 	 	
IC5	 	 	800,000	 	 	 	26.8137	 	 	 	0.109679	 	 	 	21,451	 	 	 	87,743	 	 	 	 	 	 	 	 	 	
NC5	 	 	600,000	 	 	 	27.0524	 	 	 	0.110869	 	 	 	16,231	 	 	 	66,521	 	 	 	 	 	 	 	 	 	
C6	 	 	850,000	 	 	 	23.8466	 	 	 	0.115952	 	 	 	20,270	 	 	 	98,559	 	 	 	 	 	 	 	 	 	
C7+	 	 	900,000	 	 	 	 	 	 	 	 	 	 	 	21,354	 	 	 	121,977	 	 	 	 	 	 	 	 	 	
Scrubber	 	 	100,000	 	 	 	 	 	 	 	 	 	 	 	2,372	 	 	 	14,906	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	20,750,000	 	 	 	 	 	 	 	 	 	 	 	707,624	 	 	 	1,769,349	 	 	 	280,000	 	 	 	293,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1.046	 	

II.	 	DETERMINATION OF HEAT FACTORS FOR ETHANE AND NATURAL GASOLINE	

A.	 	Ethane Product Heat Factor	 	=	 	Total MMBTU for C1 & C2
Total MCF for CO2, C1 & C2	
 	 	 	 	 	 	 	
 	 	 	 	=	 	(   11,946 + 597,045   )
(11,571 + 11,569 + 330,105)	
 	 	 	 	 	 	 	
 	 	 	 	=	 	1.7245 MMBTU/MCF	
 	 	 	 	 	 	 	
B.	 	Gasoline Product Heat Factor
     (scrubber heat factor calculated
     in similar manner)	 	=	 	Total MMBTU for IC5, NC5, C6 & C7+
Total MCF for IC5, NC5, C6 & C7+	
 	 	 	 	=	 	(   87,743 + 66,521 + 98,559 + 121,977   )
(   21,451 + 16,231 + 20,270 + 21,354   )	
 	 	 	 	 	 	 	
 	 	 	 	=	 	4.7260 MMBTU/MCF	
 Page 2 

 

EXHIBIT “B” (continued)

III.	 	ALLOCATION OF PLANT THERMAL REDUCTION OTO DELIVERY POINT “A”	

 	A.	 	SHRINKAGE PORTION	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	VAPOR	 	HEAT	 	TOTAL	
 	 	ALLOCATED	 	FACTORS	 	FACTORS	 	SHRINKAGE	
PRODUCT	 	GALLONS	 	MCF/GAL	 	MMBTU/MCF	 	MMBTU	
Ethane	 	 	1,000,000	 	 	 	0.03886	 	 	 	1.7245	 	 	 	67,018	 	
Propane	 	 	500,000	 	 	 	0.03559	 	 	 	2.5724	 	 	 	45,781	 	
Iso-Butane	 	 	100,000	 	 	 	0.02997	 	 	 	3.3247	 	 	 	9,963	 	
Normal Butane	 	 	100,000	 	 	 	0.03111	 	 	 	3.3352	 	 	 	10,374	 	
Gasoline	 	 	403,846	 	 	 	0.02518	 	 	 	4.7260	 	 	 	48,051	 	
Scrubber	 	 	12,821	 	 	 	0.02372	 	 	 	5.0195	 	 	 	1,527	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	2,116,667	 	 	 	 	 	 	 	 	 	 	 	182,714	 	

    B.	 	FUEL PORTION	 	 	 	 	
 	 	 	 	 	 	 	 	 	
 	 	1.	 	Half allocated on gas volume	 	=	 	50% x 4,000,000 / 16,400,000 x 293,000 MMBTU	
 	 	 	 	 	 	=	 	35,732 MMBTU	
 	 	 	 	 	 	 	 	 	
 	 	2.	 	Half allocated on C3+ Products	 	=	 	50% x 1,103,846 / 11,250,000 x 293,000 MMBTU	
 	 	 	 	 	 	=	 	14,475 MMBTU	
 	 	 	 	 	 	 	 	 	
 	 	3.	 	Total Fuel Allocation	 	=	 	50,106 MMBTU	
 	 	 	 	 	 	 	 	 	
    C.	 	FLARE & OTHER LOSSES PORTION	 	 	 	2,000 MMBTU	
 	 	 	 	 	 	 	 	 	
 	 	 	 	Allocated based on Shrinkage	 	=	 	182,714 / 1,769,349 x 2,000	
 	 	 	 	 	 	=	 	207 MMBTU	
 Page 3 

 

EXHIBIT “C”
TO
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
FRACTIONATION FEE
Beginning on the effective date of this Agreement, and on the first day of each month thereafter with respect to fuel gas, the Fractionation Fee shall be calculated based on the following formula (expressed in cents/Gallon):

		
 	 	 (W)1.20   	+	2.40      =	 	Fractionation Fee	
 	 	$4.00/MMBTU	 	 	 	¢/Gallon	

     With respect to the formula above, the following definition shall apply:
W = The settlement price in dollars per MMBtu, for the Henry Hub index (“Index”), as published in Inside F.E.R.C. ’s Gas Market Report (“IFERC”), in effect for the month in which the Gas is being processed (e.g. IFERC price published on/near last day of February for March gas flows).

Notwithstanding anything to the contrary herein, in no event shall the adjustments permitted by the formula appearing above in this Agreement reduce the Fractionation Fee below 3.60 cents ($0.0360) per gallon (the “Fractionation Fee Floor”). In the event that the computation of the Fractionation Fee, as herein provided, results in an amount that is less than the 3.60 cents ($0.0360) per gallon, then the Parties acknowledge and agree that the Fractionation Fee shall be 3.60 cents ($0.0360) per gallon. In the event that anything in this Agreement conflicts or otherwise restricts the application of the Fractionation Fee Floor, the Fractionation Fee Floor shall fully apply and control.

 	 	 	
American Midstream, LLC	 	Execution Copy	
L1214	 	 	
 2 

 

EXHIBIT “D”
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
PRODUCT INDEX BASES

Product	 	Pricing Basis	
Ethane	 	OPIS monthly average (of daily high and low) price for Napoleonville ethane, less $0.005/gallon.	
 	 	 	
Propane	 	OPIS monthly average (of daily high and low) price for Napoleonville propane, less $0.0125/gallon.	
 	 	 	
Isobutane	 	OPIS monthly average (of daily high and low) price for Napoleonville isobutane, less $0.005/gallon.	
 	 	 	
Normal Butane	 	OPIS monthly average (of daily high and low) price for Napoleonville normal butane, less $0.0125/gallon.	
 	 	 	
Natural Gasoline	 	OPIS monthly average (of daily high and low) price for Napoleonville natural gasoline, less $0.005/gallon.	

NOTE: The above basis pricing reflects the Toca gas plant’s existing agreement for sale by the plant of natural gas liquids fob the Norco Fractionator Plant. The pricing basis herein may change from time-to-time, and upon notification of such change to Plant Supplier, the new pricing basis will become effective for the month following the month of such notification.

American Midstream, LLC	 	Execution Copy	
L1214	 	 	
 3 

 

EXHIBIT “E”
TO
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
PLANT SUPPLIER’S FIELD DELIVERY POINT(S) FOR PROCESSING
THE PORTION OF GAS THAT IS DELIVERED TO PROCESSOR AT THE FOLLOWING FIELD DELIVERY POINT FROM A NEW INTERRCONNECT BETWEEN PLANT SUPPLIER’S GLORIA PIPELINE AND TENNESSEE PIPELINE. SUB-ALLOCATION OF THIS GAS WILL BE BASED ON MCF AND THEORETICAL NGL GALLONS RECEIVED BY PROCESSOR DIRECTLY FROM TENNESSEE PIPELINE. PLANT SUPPLIER HOLDS PROCESSING RIGHTS TO GAS DELIVERED THEREFROM AND WHICH IS TO BE PROCESSED HEREUNDER:
 	 	 	 	 	
Southern Delivery Point	 	Southern Meter Number	
Creole Receiving Station	 	 	039500	 	

American Midstream, LLC	 	Execution Copy	
L1214	 	 	
 4 

 

EXHIBIT “F”
TO
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
SETTLEMENT INSTRUCTIONS
     American Midstream, LLC (“Plant Supplier”)
Payments to Plant Supplier (wire) :
Comerica Bank
910 Louisiana, Suite 410
Houston, Texas 77210
ABA: 111000753
Account Number: 1881319493
Beneficiary account — American Midstream LLC
Plant Supplier’s Statement Address:
American Midstream, LLC
Attn: Gas Contracts
8300 FM 1960 West, Suite 225
Houston, TX 77070
Phone:     281-955-4800
Fax:         281-955-4855
If by electronic mail: Email: bpieri@americanmidstream.com

American Midstream, LLC	 	Execution Copy	
L1214	 	 	
 5 

Exhibit 10.25
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
BETWEEN
AMERICAN MIDSTREAM (LOUISIANA INTRASTATE), LLC
(PLANT SUPPLIER)
AND
ENTERPRISE GAS PROCESSING, LLC
(PROCESSOR)
APRIL 1, 2011

American Midstream (Louisiana Intrastate), LLC
L1234	 	Execution Copy	

 

PRODUCTS PURCHASE AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
TABLE OF CONTENTS
 	 	 	 	 	
ARTICLES	 	PAGE NUMBER	
 	 	 	 	 	
Article I — Definitions	 	 	2	 	
 	 	 	 	 	
Article II — Exhibits	 	 	6	 	
 	 	 	 	 	
Article III — Capacity of Plant	 	 	6	 	
 	 	 	 	 	
Article IV — Delivery and Redelivery of Plant Supplier’s Gas	 	 	7	 	
 	 	 	 	 	
Article V — Allocation of Products	 	 	9	 	
 	 	 	 	 	
Article VI — Consideration Due Plant Supplier	 	 	14	 	
 	 	 	 	 	
Article VII — Plant Volume Reduction and Bypassed Gas	 	 	14	 	
 	 	 	 	 	
Article VIII — Term	 	 	17	 	
 	 	 	 	 	
Article IX — Payment of Royalty and Taxes	 	 	18	 	
 	 	 	 	 	
Article X — Laws, Regulations and Force Majeure	 	 	18	 	
 	 	 	 	 	
Article XI — Notices	 	 	19	 	
 	 	 	 	 	
Article XII — Indemnification	 	 	20	 	
 	 	 	 	 	
Article XIII — Miscellaneous	 	 	20	 	
EXHIBITS
“A” — Example Calculation — Product Allocation Procedure (Omitted)
“B” — Example Calculation — Plant Volume Reduction (Omitted)
“C” — Fractionation Fee
“D” — Product Index Bases
“E” — Plant Supplier’s Field Delivery Point(s) for Processing
“F” — Settlement Instructions
 2 

 

GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
          THIS GAS PROCESSING AGREEMENT (the “Agreement”) is made and entered into this 1st day of April, 2011 (the “Effective Date”), by and between AMERICAN MIDSTREAM (LOUISIANA INTRASTATE), LLC (“Plant Supplier”) and ENTERPRISE GAS PROCESSING, LLC, (“Processor”).
RECITALS
          A. WHEREAS, Processor has constructed the Toca Gas Processing Plant on a tract of land in Sections 54 and 55, T-14-S, R-4-E, St. Bernard Parish, Louisiana (herein called the “Toca Plant” or “Plant”), and operates said Plant for the purpose of extracting Liquid Hydrocarbons, as hereinafter defined, from certain gas delivered to the Plant from the pipeline system of Southern Natural Gas Company (herein called “Southern’s Lines”); and
          B. WHEREAS, the Toca Plant Owners have heretofore individually entered into an agreement with Enterprise Products Operating LLC, by and through its predecessor in interest, Shell Oil Company, as Owner of the Norco Fractionation Plant, entitled “Hydrocarbon Fractionation Agreement” (herein called “Fractionation Agreement”), whereby the Toca Plant Operator will deliver for the account of Plant Owners Raw Make, as hereinafter defined, recovered at the Toca Plant to Fractionator for transportation to the Norco Fractionation Plant and for fractionation into commercial Products; and
          C. WHEREAS, Plant Supplier owns or holds the gas processing rights to gas delivered to Field Delivery Point(s) listed on Exhibit “E”, attached hereto and incorporated herein by reference, and has the right to extract or have extracted the Liquid Hydrocarbons from such gas, which gas will be transported through Southern’s Lines to the Plant for Plant Supplier’s account; and
          D. WHEREAS, Processor and Plant Supplier desire hereby to provide the terms and conditions under which such gas will be delivered from Southern’s Lines to the Plant pursuant to the Transportation Agreement, as hereinafter defined, for processing for Plant Supplier’s account and

American Midstream (Louisiana Intrastate), LLC
L1234	 	1	 	Execution Copy	

 

the Liquid Hydrocarbons in such gas will be sold to Processor at the Plant Delivery Point for a consideration to Plant Supplier consisting of a share of Products, all as hereinafter more fully set forth;
          NOW, THEREFORE, in consideration of the premises and of the mutual covenants and agreements herein provided, the parties hereto agree as follows:
ARTICLE I — DEFINITIONS
          1.1 Definitions. The following definitions of terms shall apply for all purposes of this agreement, including the preambles and exhibits, unless the context otherwise clearly requires.
          1.1.1 The term “gas” shall mean all vaporized hydrocarbons and vaporized concomitant materials, whether produced with oil or from gas or gas condensate wells.
          1.1.2 A “cubic foot of gas ” shall mean the volume of gas contained in one cubic foot of space at a standard pressure base and a standard temperature base. The standard pressure base shall be 15.025 pounds per square inch absolute, and the standard temperature base shall be 60 degrees Fahrenheit. Whenever the conditions of pressure and temperature differ from the above standard, conversion of the volume from these conditions to the standard conditions shall be made in accordance with the Ideal Gas Laws, corrected for deviation by the methods set forth in the American Gas Association Measurement Committee Report No. 3 dated April 1955, as said report may be amended from time to time. The terms “MCF” and “MMCF” shall relate, respectively, the 1,000 cubic feet of gas and 1,000,000 cubic feet of gas.
          1.1.3 “Bypassed Gas” shall mean gas which has been delivered to Plant Owners at the Plant Delivery Point, but which has been returned to Southern at the Plant Redelivery Point without having been processed.
          1.1.4 “Committed Gas” shall mean the gas produced by a Plant Owner which has been committed to and made available for processing in the Toca Plant by virtue of such Plant Owner’s ownership of capacity in the Plant under the provisions of the Construction and Operating Agreement.

American Midstream (Louisiana Intrastate), LLC
L1234	 	2	 	Execution Copy	

 

          1.1.5 “Construction and Operating Agreement” shall mean that certain agreement entitled “Agreement for the Construction and Operation of the Toca Gas Processing Plant, St. Bernard Parish, Louisiana”, entered into effective as of July 1, 1970 by Plant Owners to provide for the construction, ownership and operation of the Toca Plant.
          1.1.6 “Determined Plant Capacity” shall mean the gas handling capacity of the Plant at design recovery levels, which currently is deemed to be 1030.0 MMCF/D, but the Plant gas handling capacity and/or liquid recovery levels shall be subject to revision from time to time by Plant Owners to reflect Plant capacity; provided that in any such adjustment the gas handling capacity shall never be adjusted below 1030.0 MMCF/D, nor shall it be determined to be greater, at normal recovery levels of 90 percent propane, than 80 percent of the maximum gas handling capacity of the Plant at a delivery pressure of 800 psia and with a Plant pressure loss not to exceed 35 psi.
          1.1.7 “Field Delivery Point” shall mean any point at which gas being transported in Southern’s Lines and subject to processing in the Plant is initially measured for the purpose of delivery for sale or for transportation.
          1.1.8 “Fractionator” shall mean Enterprise Products Operating LLC in its capacity as owner and operator of the Norco Fractionation Plant and related pipelines and facilities.
          1.1.9 “Fractionation Expense” shall mean the fractionation expense calculated per the terms and conditions of Exhibit “C.”
          1.1.10 “Gallon” shall mean a standard U.S. liquid gallon of 231 cubic inches when said liquid has a temperature of 60 degrees Fahrenheit and is at a pressure sufficient for liquification.
          1.1.11 “Gas Transporter” shall mean the party or parties who transport the gas delivered from the respective Exhibit “E” Field Delivery Point(s) from time to time.
          1.1.12 “Gross Receipts” shall mean the monthly revenue calculated from the value of the individual Products (expressed in cents per gallon) multiplied by the volume of the Products allocated to the Plant Supplier. The value of each individual Product shall be based on the pricing

American Midstream (Louisiana Intrastate), LLC
L1234	 	3	 	Execution Copy	

 

basis set forth under Exhibit “D”, as such pricing basis may change from time to time as provided in Exhibit C.
          1.1.13 “Inert Constituents” shall mean non-hydrocarbon constituents contained in Gas, including, without limitation, carbon dioxide, water vapor, ozone, nitrous oxide, and mercury, but, for the avoidance of doubt, expressly excluding NGLs.
          1.1.14 “Liquid Hydrocarbons” , sometimes herein used to refer to liquefiable hydrocarbons present in the gas stream and sometimes herein used to refer to hydrocarbons in a liquid state after extraction by the Plant from the gas stream, shall in either case mean natural gasoline (iso-pentanes plus heavier hydrocarbons), butanes, propane and ethane.
          1.1.15 “ Net Proceeds ” shall mean the Gross Receipts obtained from the sale of the share of Products to which Plant Supplier is entitled under this Agreement when Plant Operator under the terms of this Agreement is authorized to make such sale, less the following costs and expenses: (a) excise, sales, use, severance, gathering, processing, fuel use, or other similar taxes (reference Article IX.3) imposed by any taxing authority having or asserting jurisdiction over the production, sale or use of the Products and which tax Processor is obligated to pay; (b) actual tank car expense if the Product is shipped in tank cars, and rail transportation and/or other rail carrier costs if incurred by Processor; (c) actual other transportation costs if incurred by Processor, and (d) the Fractionation Expense.
          1.1.16 “Plant Delivery Point” shall mean the point on Southern’s Lines at which gas is delivered by Southern to Plant Owners for processing in the Plant.
          1.1.17 “Plant Operator” shall mean Enterprise Products Operating LLC or any successor to Enterprise Products Operating LLC selected by Toca Plant Owners to operate the Plant.
          1.1.18 “Plant Redelivery Point” shall mean the point on Southern’s Lines at which Residue Gas is returned by Plant Owners to Southern.
          1.1.19 “Third Party Supplier” shall mean any Plant Supplier, including Plant Supplier hereunder, whose gas is being transported through Southern’s Lines and who has entered into a Gas Processing Agreement or a Products Purchase Agreement with Plant Operator to have gas

American Midstream (Louisiana Intrastate), LLC
L1234	 	4	 	Execution Copy	

 

processed in the Plant. Such term shall also apply to a Plant Owner with respect to Committed Gas made available by it for processing in the Plant in excess of 125 percent of such Owner’s capacity in the Plant, which excess, as provided in the Construction and Operating Agreement, is considered to be under a Products Purchase Agreement.
          1.1.20 “Products” shall mean the commercial products fractionated from the Raw Make by Fractionator at the Norco Fractionation Plant pursuant to the terms of the Fractionation Agreement, including, but not limited to, natural gasoline, butanes, propane and ethane (including such methane allowable in commercial ethane), and shall include any Liquid Hydrocarbons recovered by the inlet scrubber at the Plant for which the preferred disposition is at the Plant rather than being combined with the Raw Make.
          1.1.21 “Raw Make” shall mean the combined stream of Liquid Hydrocarbons and concomitant materials recovered from gas processed in the Plant and shall include any liquefied hydrocarbons recovered by the Plant inlet scrubber if combined with the Raw Make.
          1.1.22 “Residue Gas” shall mean the stream of gas returned to Southern at the Plant Redelivery Point after the gas received from Southern has been processed in the Plant for the recovery of Liquid Hydrocarbons and shall include any Bypassed Gas commingled with such processed gas.
          1.1.23 “Southern’s Lines” shall mean that portion of Southern’s gas pipeline system upstream of the Plant Delivery Point, plus any present or future extensions or loops thereof, which is transporting unprocessed gas for processing at the Plant site.
          1.1.24 “Toca Plant Owners” or “Plant Owners” shall mean the parties who own the Toca Plant, whether presently or in the future.
          1.1.25 “Transportation Agreement” shall mean the applicable agreement in place from time to time between Southern and Plant Supplier or Gas Transporter which covers the transportation of the gas to the Plant to be processed hereunder.

American Midstream (Louisiana Intrastate), LLC
L1234	 	5	 	Execution Copy	

 

ARTICLE II — EXHIBITS
          2.1 Exhibits. The following exhibits are attached to and made a part of this agreement:
          2.1.1 Exhibit “A” , which is an example calculation illustrating the procedure for allocating Products to Plant Owners and Third Party Suppliers.
          2.1.2 Exhibit “B” , which is an example calculation illustrating the procedure for calculating and allocating Plant Volume Reduction.
          2.1.3 Exhibit “C” , which is description of the procedure for calculating the Fractionation Expense.
          2.1.4 Exhibit “D” , which lists the Product prices.
          2.1.5 Exhibit “E” , which lists the Field Delivery Point(s) from which gas to be processed hereunder is produced. Exhibit “E” may be amended to add additional Field Delivery Points from time to time upon mutual agreement of Processor and Plant Supplier.
          2.1.6 Exhibit “F” , which lists the Plant Supplier’s accounts payable address for checks or bank instructions for wire transfer, federal tax identification number, and invoice and plant statement addresses, all of which provide the settlement instructions for the transactions hereunder. Exhibit “F” may be amended by Plant Supplier from time to time.
ARTICLE III — CAPACITY OF PLANT
          3.1 Plant Design. The Toca Plant is designed to extract approximately 50 percent of the ethane and over 90 percent of the propane, together with essentially all of the butanes and heavier liquefiable hydrocarbons contained in the gas at a gas flow rate of 1030 MMCF per day, with gas handling facilities designed to handle 1030 MMCF per day at a delivery pressure of 800 psia and with a Plant pressure loss not to exceed 35 psi. The pressure base for the foregoing design specifications is 14.73 pounds per square inch absolute at a temperature base of 60 degrees Fahrenheit; however, a pressure base of 15.025 pounds psia shall be used in connection with any

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adjustment of the Determined Plant Capacity and for determining the Plant capacity which is owned and/or utilized by Plant Owners.
          3.2 Capacity Not Warranted. Plant Supplier hereby specifically recognizes that the foregoing representations regarding the processing capacity of the Toca Plant are merely advisory and do not constitute a warranty by or obligation of Processor as to capacity. Plant Supplier further recognizes that the Determined Plant Capacity may change from time to time as the result of operating experience or performance tests or alterations made to the Plant by Plant Owners.
ARTICLE IV — DELIVERY AND REDELIVERY OF PLANT SUPPLIER’S GAS
          4.1 Gas to be Delivered by Plant Supplier. Commencing as of the Effective Date, Plant Supplier shall deliver to Processor at the Plant Delivery Point for processing hereunder all of Plant Supplier’s gas delivered to the Field Delivery Point(s) listed on Exhibit “E”, less and except Plant Supplier’s pro rata share of the gas which is used by Southern for compressor fuel, incidental sales of gas for drilling purposes and other routine and normal uses as may be necessary to the maintenance of leases or operation of Southern’s Lines and also any gas lost in the normal operation of Southern’s Lines upstream of the Plant Delivery Point, including, but not limited to, gas lost in pipeline blowdown for repairs or tie-ins, cleaning and purging and in pipeline scrubber operations. Such deliveries of gas shall be continued hereunder during the term hereof. The rights granted herein by Plant Supplier to Processor are exclusive, and Liquid Hydrocarbons shall not be stripped in the field or elsewhere from Plant Supplier’s gas subject hereto prior to delivery at the Toca Plant other than by usual field separation methods which may include adiabatic expansion utilizing the natural pressures available from the wells, but shall exclude facilities designed to recover Liquid Hydrocarbons including but not limited to solid bed absorption, lean oil absorption, turbo-expander or mechanical refrigeration principles. In no event shall Processor be liable to Plant Supplier if Southern fails for any reason to deliver Plant Supplier’s gas to the Plant for processing as above provided.

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          4.2 When Plant Supplier’s Gas is to be Bypassed. During periods when the Plant is shut down because of mechanical failure, force majeure or necessary maintenance or repairs, all of Plant Supplier’s gas being transported through Southern’s Lines shall be Bypassed Gas. When the Plant is partially shut down for any of the above-mentioned reasons, or if the Plant lacks sufficient capacity to handle all gas available for processing from Southern’s Lines, Plant Supplier’s gas shall be processed only on a space available basis, and to the extent that gas handling capacity in the Plant, for any reason, is not available for such gas, such gas shall be preferentially bypassed along with the gas of any other Third Party Suppliers which is made available for processing in the Plant. All of such gas bypassed preferentially will be determined monthly on an average daily basis and will be prorated to all Third Party Suppliers under their respective agreements in the ratio that the average daily volume of gas made available by each during the month bears to the total average daily volumes made available by all such Third Party Suppliers during the month; provided that, if any continuous period of complete shutdown of the Plant shall equal or exceed twelve (12) hours’ duration, the time of each such shutdown [determined to the nearest increment of six (6) hours] and the measured (or estimated, in the absence of measurement) volumes of gas bypassed during such determined period of shutdown shall be excluded in determining the average volume of Third Party Suppliers’ gas considered to have been bypassed during the affected month for purposes hereof.
          4.3 Redelivery of Plant Supplier’s Gas to Southern’s Lines. After processing Plant Supplier’s gas delivered hereunder to the Plant, Processor shall redeliver the Residue Gas to Southern’s Lines at the Plant Redelivery Point. The Residue Gas prior to being commingled with any Bypassed Gas shall have a total or gross heating value of not less than one thousand (1,000) BTU’s per cubic foot (gross heating value saturated with water vapor) and shall otherwise comply with the quality specifications enumerated in the contract heretofore executed by Plant Owners and Southern; provided that the combined gas stream delivered by Southern at the Plant Delivery Point meets such specifications.
          4.4 Production Estimates. Effective as of the date of this Agreement, Processor requires from Plant Supplier five (5) days prior to the start of each month gas composition analyses

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and monthly volume forecast, i.e. monthly wellhead production estimates, daily pipeline nomination volume, or other delivery point information for any Gas that may be delivered into Southern’s Lines, for each Field Delivery Point (expressed in MCF per day).
ARTICLE V — ALLOCATION OF PRODUCTS
          5.1 General. Products fractionated from the Raw Make recovered from gas processed in the Plant shall be allocated to the source of each Plant Owner’s Committed Gas and each Third Party Supplier’s gas in accordance with the procedure set forth in the following sections of this Article V, which procedure is illustrated by the example calculation set forth in Exhibit “A” hereto. As shown on said Exhibit, separate calculations shall be made for each Product. For the purposes of such allocations, Plant Supplier under this Agreement shall be allocated Products on the same basis as Products are allocated to Plant Owners. Processor will respond promptly to inquiries from Plant Supplier regarding daily operating rates and daily production rates at the Plant.
          5.2 “Plant Supplier’s Inert Constituents” Plant Supplier shall retain title to all Inert Constituents in the Natural Gas delivered by Plant Supplier under this Agreement (collectively, whether removed from the Natural Gas or not, “Plant Supplier’s Inert Constituent s”), including but not limited to, carbon dioxide (CO2). To the extent that Processor removes Plant Supplier’s Inert Constituents from such Natural Gas and Plant Supplier has not made arrangements to utilize, market or dispose of Plant Supplier’s Inert Constituents, Processor may, but is not required to, dispose of some or all of Plant Supplier’s Inert Constituents by venting or other methods. If (i) venting Plant Supplier’s Inert Constituents is ever prohibited or disallowed for any reason or is deemed by Processor to be uneconomic, or (ii) additional costs are required to vent, dispose of or handle Plant Supplier’s Inert Constituents due to new rules, regulations or other laws, then Plant Supplier shall promptly (i) make alternate arrangements to utilize, market and/or dispose of Plant Supplier’s Inert Constituents at Plant Supplier’s sole cost and expense, (ii) notify Processor in writing and in reasonable detail of such alternate arrangements, and (iii) reimburse Processor for any costs incurred by Processor for delivering Plant Supplier’s Inert Constituents for such utilization, marketing and/or

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disposal. If Plant Supplier fails to comply with Plant Supplier’s obligations under the immediately preceding sentence, Processor shall be entitled, without further notice to Plant Supplier, to make arrangements for utilization, marketing and/or disposal of some or all of Plant Supplier’s Inert Constituents for Plant Supplier’s account and at Plant Supplier’s sole cost and expense; and Plant Supplier shall promptly reimburse Processor upon demand for any costs and expenses incurred by Processor in connection with such arrangements by Processor. PLANT SUPPLIER HEREBY RELEASES, INDEMNIFIES, DEFENDS AND HOLDS HARMLESS PROCESSOR AND PROCESSOR’S DIRECTORS, OFFICERS, EMPLOYEES, AGENTS, AND CONTRACTORS FROM AND AGAINST ANY AND ALL CLAIMS, DEMANDS, DAMAGES, LIABILITIES, EXPENSES, ACTIONS, CAUSES OF ACTION, LIABILITIES, LOSSES, TAXES, PENALTIES AND FEES ARISING OUT OF OR IN ANY WAY RELATING TO (I) ANY OR ALL OF PLANT SUPPLIER’S INERT CONSTITUENTS, INCLUDING, WITHOUT LIMITATION, THE UTILIZATION, MARKETING OR DISPOSAL THEREOF, AND/OR (II) ANY PERSONAL INJURY, DEATH, PROPERTY DAMAGE, ENVIRONMENTAL DAMAGE, POLLUTION, OR CONTAMINATION ARISING OUT OF OR RELATING TO ANY OR ALL OF PLANT SUPPLIER’S INERT CONSTITUENTS.
          If any Taxes (as defined in Section 9.2), fees or other impositions are ever imposed on Plant Supplier’s Inert Constituents and/or the utilization, marketing or disposal thereof, Plant Supplier shall promptly pay such Taxes. If such Taxes must be paid by Processor, Plant Supplier shall promptly reimburse Processor for any and all such Taxes paid by Processor with respect to any or all of Plant Supplier’s Inert Constituents. If Processor is required by applicable law to pay such Taxes on any or all of Plant Supplier’s Inert Constituents and it is unlawful for Plant Supplier to make such reimbursement to Processor for such Taxes, Plant Supplier and Processor shall promptly negotiate and execute an amendment to this Agreement which restores to Processor the same economic bargain as would have resulted if Plant Supplier, rather than Processor, had paid all Taxes on Plant Supplier’s Inert Constituents; and if Plant Supplier is unable or unwilling to promptly enter

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into such an amendment reasonably acceptable to Processor, Processor shall have the option, exercisable in Processor’s sole discretion, to terminate this Agreement by written notice to Plant Supplier.
          5.3 Basic Allocation Data. The volumes of gas which shall be credited as having been processed in the Plant shall be the sum of all volumes of gas delivered to Southern at the various Field Delivery Points, less the volumes deducted pursuant to Section 5.5 hereof. Representative determinations for Liquid Hydrocarbons content of the gas shall be made of the gas streams at each Field Delivery Point by Plant Operator quarterly or more often if found necessary, by chromatographic analysis or by some other acceptable method for testing gas for Liquid Hydrocarbons content. Plant Operator shall give Plant Supplier reasonable advance notice of tests to determine Liquid Hydrocarbons content of the gas at the Field Delivery Point(s) for Plant Supplier’s account so that Plant Supplier may witness such tests if desired. Plant Supplier agrees that the gas stream(s) made available for these tests shall be representative of the stream(s) normally delivered at the Field Delivery Point(s) for Plant Supplier’s account and will be at as near average delivery conditions and volumes as possible at the time. Plant Operator or Plant Supplier may request a retest if dissatisfied with the results of a particular test. If the request for a retest is made by Plant Supplier and the Liquid Hydrocarbons content of the previous test is confirmed within ten percent (10%), the expense of the retest shall be borne by Plant Supplier.
          5.4 Allocation of Products to the Respective Field Delivery Points . Such aforesaid volumes of gas which are credited as having been processed and the theoretical Liquid Hydrocarbons content of such gas at the respective Field Delivery Points shall be used as the basis for allocating each Product fractionated from the Raw Make to such Field Delivery Points by the method illustrated in Exhibit “A”. Such method contemplates that the volume of theoretical Liquid Hydrocarbons (separately for each Product) for each such Field Delivery Point will be calculated by multiplying the volume of gas credited as having been processed from such Field Delivery Point by the theoretical Liquid Hydrocarbons content (separately as to each Product) at each such Field Delivery Point. The total of each such Product fractionated from the Raw Make will, in turn, be

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allocated to such respective Field Delivery Points in the ratio that the volume of theoretical Product calculated for each Field Delivery Point bears to the sum of the volumes of such theoretical Product calculated for all such Field Delivery Points. Any Liquid Hydrocarbons recovered by the Plant inlet scrubber for which the preferred disposition is at the Plant rather than being combined with the Raw Make, shall be allocated to the Field Delivery Points in the same proportions as natural gasoline Product is allocated.
          5.5 Field Volume Statements and Sub-Allocations at Field Delivery Points. As soon as practicable, but no later than the twentieth (20th) day of each month, Plant Supplier shall furnish, or cause to be furnished, to Plant Operator a gas purchase statement by Gas Transporter or such other statement as Plant Operator may reasonably require, to show the volume of gas delivered during the preceding month from each of the Field Delivery Points for Plant Supplier’s account. Additionally, by the twentieth (20th) day of each such month, but only when gas owned by more than one Plant Supplier (including for Plant Supplier’s account) has been delivered through a single Field Delivery Point, Plant Supplier, if so situated, shall furnish or cause the operator of the Field Delivery Point to furnish to Plant Operator written instructions on sub-allocating the gas delivered through said Field Delivery Point and Products attributable thereto for such preceding month. Plant Operator shall be entitled to rely on the information thus furnished or caused to be furnished in sub-allocating the Products recovered and allocated to the particular Field Delivery Point.
          5.6 Pipeline Uses and Losses. From the quantities of gas measured at the respective Field Delivery Points as provided above, there shall be deducted any gas which may be lost, used or sold by Southern at any place on Southern’s Lines between such Field Delivery Points and the Plant Delivery Point, as more specifically set forth in Section 4.1 above. It is agreed that the volumes of such gas and the nature of each disposition, as reported by Southern to Plant Operator, shall be subtracted by Plant Operator from the quantities of gas measured at the Field Delivery Points. In making settlements hereunder, Plant Operator shall be entitled to rely upon the accuracy of such information as reported to it by Southern, but Plant Operator shall footnote settlement data supplied

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to the affected Plant Suppliers, noting the allocable amount of gas lost, used or sold by Southern. It is understood that the aforesaid volumes of gas lost, used or sold by Southern at any place on Southern’s Lines shall be allocated to all Field Delivery Points serving Southern’s Lines (including those Field Delivery Points serving the Lines from which gas will be processed in plants other than the Toca Plant) in the ratio which the volume of gas measured at each such Field Delivery Point during a month bears to the total volume of gas measured at all Field Delivery Points serving Southern’s Lines during the month.
          5.7 Product Allocation Statements. By the end of the month in which the information referred to in the preceding two sections is received, Plant Operator shall furnish a statement to all Plant Owners and Third Party Suppliers accounting for the volume of gas delivered from each Field Delivery Point for the preceding month together with the amount of each individual Product allocated to said gas.
          5.8 Measurement of Field Volumes. All gas delivered at a Field Delivery Point shall be measured by a suitable orifice meter or meters of standard make furnished, installed, operated and kept in repair by the owners of the equipment at the point where delivery is made to Southern’s Lines which shall be the same meter or meters used under the provisions of each Plant Owner’s or Third Party Supplier’s individual gas purchase contract with Gas Transporter. The volumes measured by said meter or meters shall be used for purposes of settlement under this agreement. The computation of all gas volumes measured by orifice meters shall be based on the latest orifice factors published by the American Gas Association corrected to a base pressure of 15.025 pounds per square inch absolute and at a base temperature of sixty degrees Fahrenheit (60°F), and the measurement procedures, technical requirements and standards for all such meters shall be as set out in each Owner’s or Plant Supplier’s gas transportation contract. Plant Supplier agrees that the Plant Operator shall have the right to witness all tests of the meters and other equipment employed to measure volumes of gas delivered to Gas Transporter, and upon request, Plant Supplier shall give Plant Operator reasonable advance notice of all such tests.

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ARTICLE VI — CONSIDERATION DUE PLANT SUPPLIER
          6.1 Plant Supplier’s Consideration . Plant Supplier shall receive as full settlement hereunder each month ninety percent (90%) of the Net Proceeds attributable to such Gas for such month, as allocated to Plant Supplier’s Gas under Article VI hereof, less the Plant Share. Processor shall be entitled to ten percent (10%) of the Net Proceeds attributable to such Gas for such month (“Processor’s Proceeds”).
          Notwithstanding the foregoing, in no event shall the value of the Processor’s Proceeds be less than the value of $0.10 per MCF multiplied by the MCF of the Plant Supplier’s Gas at the Field Delivery Point.
ARTICLE VII — PLANT VOLUME REDUCTION AND BYPASSED GAS
          7.1 General . It is recognized that there will be a reduction in gas volumes, herein called “Plant Volume Reduction”, between the quantity of gas delivered by Southern for processing in the Plant and the volume of Residue Gas returned to Southern’s Lines because of (a) extraction of Raw Make, herein called the “shrinkage portion”, and (b) Plant fuel used, flared gas or other uses or losses incident to or occasioned by processing.
          7.2 Calculation of Plant Volume Reduction . The Plant Volume Reduction for the entire Plant shall be accounted for on a monthly basis and shall be calculated as follows:
          7.2.1 Shrinkage Portion . The vapor volume equivalent of each liquid component of the Raw Make shall be determined by multiplying the liquid volume of such component by the applicable vapor equivalent factor set forth in the schedule below. The total shrinkage portion of the Plant Volume Reduction will be equal to the sum of all such conversion computations made for each component of the Raw Make. Until revised by Plant Owners and Gas Transporters, the vapor equivalent factors set forth in the schedule below shall be used for all such conversion calculations:

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 	 	VAPOR EQUIVALENT	 	HEAT EQUIVALENT	
COMPONENTS	 	FACTOR (CF/GAL)	 	FACTOR (MMBTU/GAL)	
Carbon Dioxide	 	 	57.8528	 	 	 	0.000000	 	
Methane	 	 	57.8431	 	 	 	0.059729	 	
Ethane	 	 	36.6672	 	 	 	0.066338	 	
Propane	 	 	35.5942	 	 	 	0.091563	 	
Iso-Butane	 	 	29.9662	 	 	 	0.099629	 	
N-Butane	 	 	31.1047	 	 	 	0.103740	 	
Iso-Pentane	 	 	26.8137	 	 	 	0.109679	 	
N-Pentane	 	 	27.0524	 	 	 	0.110869	 	
Hexane	 	 	23.8466	 	 	 	0.115952	 	
Heptanes Plus*	 	 	 	 	 	 	 	 	
Taken from Gas Processors Association (“GPA”) Publication 2145-09. Vapor Equivalent factors are in cubic feet per gallon on the Ideal Gas Basis corrected from 14.696 psia to 15.025 psia. Such factors shall be modified from time to time to conform with any amendment or revision of the above table adopted by the GPA. Heat Equivalent factors are in MMBTU per Gallon. Such factors shall be modified from time to time to conform with any amendment or revision of the above table adopted by the GPA.
The Gas/liquid ratio for heptanes plus shall be determined from time to time as may be necessary to be representative of such components.
The total shrinkage portion of the Plant Volume Reduction will be determined from measurement by positive displacement liquid meter and monthly composite sampling and analysis of the Raw Make.
          7.2.2 Determination of Losses . Plant fuel, flared gas and other uses or losses incident to processing: The volume of gas which is attributable to such uses or losses shall be as determined by the measurement with meters of each such use occurring in the Plant as may be necessary to determine accurately the total volume of gas so used, such meters to be installed and operated as mutually agreed by Plant Owners and Southern.
          7.2.3 Plant Volume Reduction Determination . All Plant Volume Reduction attributable to any other Plant use, loss or operation shall be determined by a method mutually agreeable to Plant Owners and Southern. It is understood that Plant Owners and Southern may agree on some other method of determining Plant Volume Reduction in order to remove any

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inequities which may be found to exist, and it is agreed that any such other method adopted shall be applicable to this agreement.
          7.3 Sharing of Plant Volume Reduction Among Plant Owners and Third Party Suppliers . That portion of Plant Volume Reduction resulting from Plant fuel shall be the volume measured by orifice meters. The metered fuel volume shall be allocated to the respective Field Delivery Points of Plant Owners and Third Party Suppliers on the following basis: One-half (1/2) in the same ratio that the sum of the gallons of propane and heavier Products (calculated separately for each Product) allocated to each Field Delivery Point bears to the sum of the gallons of propane and heavier Products (calculated separately for each Product) allocated to all Field Delivery Points, and one-half (1/2) in the ratio that the volume of gas processed from each such Field Delivery Point bears to the total volume of gas processed in the Plant. That portion of the Plant Volume Reduction remaining, after subtracting the metered fuel volume, shall be allocated to the respective Field Delivery Points of Plant Owners and Third Party Suppliers in the same ratio that the sum of the vapor equivalent of all Products (calculated separately for each Product) allocated to each Field Delivery Point bears to the sum of the vapor equivalent of all Products (calculated separately for each Product) allocated to all Field Delivery Points to the Plant.
          7.4 Accounting to Gas Transporter for Plant Volume Reduction . Plant Supplier shall bear and shall account to Gas Transporter for the full amount of Plant Volume Reduction allocated to the gas credited as having been processed from the Field Delivery Points for Plant Supplier’s account monthly on such basis as may be provided in the applicable contract between Plant Supplier and Southern, or between the Gas Transporter and Southern, it being expressly understood that Plant Owners have no responsibility for any portion of such Plant Volume Reduction allocated pursuant hereto to the Field Delivery Points for Plant Supplier’s account. Plant Operator shall, by the end of the month in which it receives the accounting data required to be furnished by Plant Supplier under Section 5.5 and such additional accounting data as may be required from Plant Owners, other Suppliers and Southern, furnish Plant Supplier and other interested parties a statement setting forth:
7.4.1 The total quantity of Plant Volume Reduction; and

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7.4.2 Each Plant Owner’s and Third Party Supplier’s proportionate share of the total Plant Volume Reduction; and
7.4.3 An allocation of the Plant Volume Reduction applicable to each Field Delivery Point serving the Plant, and a sub-allocation as to gas which is owned by more than one Plant Supplier (including for Plant Supplier’s account) to show the amount of Plant Volume Reduction attributable to each Owner of the gas delivered at such Field Delivery Point.
The results set forth in such statement each month shall constitute the quantity of Plant Volume Reduction to be allocated to each Plant Owner and Third Party Supplier for the preceding month, and it is understood that Gas Transporter may rely on such statements in effecting settlement with Plant Supplier for Plant Supplier’s share of Plant Volume Reduction. Plant Operator shall furnish the foregoing parties with an allocation statement based on estimated Plant Volume Reduction covering the first month of Plant operation. Plant Operator’s statement shall also report the volume of gas bypassed at the Plant during the preceding month and allocation thereof to Plant Owners and/or Third Party Suppliers, including Plant Supplier.
          7.5 Determination of Bypassed Gas . Plant Owners shall install an orifice meter on the Plant bypass line for the purpose of measuring gas bypassed as herein provided, such meter to be installed, operated and measurement made thereby in conformity with the requirements agreed upon by Plant Owners and Southern.
          7.6 Sample Calculation of Plant Volume Reduction Allocation Procedure . The procedure for calculating and allocating Plant Volume Reduction in accordance with the provisions of this Article VII is illustrated by Exhibit “B” hereto.
ARTICLE VIII — TERM
          8.1 Term . This agreement shall apply to the gas described in Section 4.1 as of the June 30, 2011 and shall remain in full force and effect until April 30, 2011.

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ARTICLE IX — PAYMENT OF ROYALTY AND TAXES
          9.1 Royalty and Other Burdens on Production . Plant Supplier shall be solely responsible for accounting to or paying to the lessors, royalty owners and the owners, if any, of oil payments, overriding royalties, or other interests in production, under the lease or leases in the field or fields covered hereunder for their share, if any, of the Products or the proceeds derived therefrom attributable to the gas processed for Plant Supplier’s account hereunder.
          9.2 Severance and Other Taxes . Processor shall not be liable for the payment of any monies due hereunder to the lessors, royalty owners and the owners, if any, of oil payments or overriding royalties, under the lease or leases in the field or fields covered hereunder. Processor shall not be liable for any severance, gathering or equivalent Taxes due on the production, severance and handling of the Gas delivered by Plant Supplier for processing hereunder and the severance or similar Taxes due on Plant Supplier’s share of products hereunder where the same are taken in kind. Plant Supplier shall pay or cause to be paid any and all excise, sales, use, severance, gathering, processing, fuel use, or other similar Taxes or obligations due on the sale, use, production, severance, processing, transportation or handling of Plant Supplier’s Gas and condensate delivered to Processor hereunder or on Residue Gas, Products, or Raw Make extracted therefrom (or the proceeds attributable thereto, as the case may be), except for any Taxes assessed on the disposition of Processor’s share of such Residue Gas, Products, or Raw Make, if any, extracted from Plant Supplier’s Gas or condensate.
ARTICLE X — LAWS, REGULATIONS AND FORCE MAJEURE
          10.1 Agreement Subject to Laws . This agreement shall be subject to all valid and applicable laws, orders, rules and regulations made by duly constituted governmental authorities.
          10.2 Force Majeure . Performance, other than to make payments due, under this agreement by the parties hereto, shall be excused in the event such performance is prevented by war, strikes, fires, floods, tornadoes, lightning, explosions, acts of God or of the public enemy, acts of governmental authorities, Federal or State regulations, inability or delay in obtaining servitudes,

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 	 	easements or permits, or material, and other happenings beyond the control of such parties, whether similar or dissimilar to the matters herein specifically enumerated; provided, however, that prompt written or telegraphic notice has been given by the party who is claiming to have been excused from performance by any of such causes to the other party and that performance shall be resumed within a reasonable time after such cause has been removed; and provided further, that no party hereto shall be required against its will to adjust any labor dispute.	
ARTICLE XI — NOTICES
          All notices, settlement instructions or demands required or provided for herein shall be in writing and shall be considered as duly delivered when delivered by courier, facsimile or mailed by prepaid registered or certified mail, addressed to the party to whom such notice is given as follows:

PLANT SUPPLIER:	 	Notices :	
 	 	 	
If by mail, courier or facsimile:	 	American Midstream (Louisiana Intrastate), LLC	
 	 	Attn: Gas Contracts	
 	 	8300 FM 1960 West, Suite 225	
 	 	Houston, TX 77070	
 	 	Phone: 281-955-4800	
 	 	Fax: 281-955-4855	
 	 	 	
If by electronic mail:	 	Email: bpieri@americanmidstream.com	
 	 	 	
PROCESSOR:	 	Notices :	
 	 	 	
If by mail or facsimile:	 	Enterprise Gas Processing, LLC	
 	 	Attn: GOM Gas Processing Contract Administration	
 	 	P.O. Box 4324	
 	 	Houston, Texas 77210-4324	
 	 	Telephone: (713) 381-1539	
 	 	Facsimile: (713) 381-4365	
 	 	 	
If by courier:	 	Enterprise Gas Processing, LLC	
 	 	Attn: GOM Gas Processing Contract Administration	
 	 	1100 Louisiana, Suite 1500	

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 	 	Houston, Texas 77002	
 	 	Telephone: (713) 381-1539	
 	 	 	
     If by electronic mail:	 	GOMgasprocessing@eprod.com	
or to such other address as either party shall designate by like written notice to the other party. Routine communications, including statements, computations and allocations, may be transmitted by ordinary mail or electronic mail.
ARTICLE XII — INDEMNIFICATION

     Processor and Plant Supplier shall indemnify, defend and hold the other harmless from claims, demands and causes of action of every type and character arising out of the performance of this agreement which are asserted against the indemnitee by any person (including, without limitation, Processor’s and Plant Supplier’s employees) for personal injury, death, loss of or damage to property where such injury, death or loss of or damage to property is due to the sole negligence or sole willful misconduct of the indemnitor. Where personal injury, death, or loss of or damage to property is the result of joint negligence or willful misconduct of Processor and Plant Supplier, the indemnitor’s duty of indemnification shall be in the same proportion that the indemnitor’s negligent acts or omissions or willful misconduct contributed thereto. If Processor or Plant Supplier is strictly liable under law, the indemnitor’s duty of indemnification shall be in the same proportion that the indemnitor’s negligent acts or omissions contributed to the personal injury, illness, death, or losses of or damage to property for which the indemnitor is strictly liable.	
ARTICLE XIII — MISCELLANEOUS
          13.1 Access to Plant Supplier’s Premises . Processor shall have the right of access insofar as Plant Supplier has the right to grant such access to the Field Delivery Point(s) for Plant Supplier’s accounts for all purposes necessary for the fulfillment of this agreement.
          13.2 Separate Agreement . If the gas which is subject to processing hereunder is delivered from more than one Field Delivery Point, this agreement shall be considered a separate

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agreement as to each such Field Delivery Point and a separate accounting shall be made hereunder for the gas received from each such Point.
          13.3 Inspection of Records. Each party hereto shall have the right at all reasonable times during business hours to examine the books, records, charts, meters, measuring equipment and other pertinent matter or data of the other party relating to this agreement and to witness the tests of the other party to the extent necessary to verify the accuracy of any statement, charge, computation or demand under or pursuant to any of the provisions hereof. If any such examination shall reveal, or if either party shall otherwise discover, any error or inaccuracy in its own or the other party’s statements, payments, calculations or determinations, then proper adjustment and correction thereof shall be made as promptly as practicable thereafter; provided that, no adjustment of any statement, billing or payment shall be made after the lapse of two (2) years from the rendition thereof.
          13.4 Headings and Subheadings. Except when comprising a part of a sentence, the headings and subheadings used in this instrument are provided for reference purposes only and shall not be construed to interpret or amend any part of the text hereof.
          13.5 Successors and Assigns Bound. This agreement shall extend to and be binding upon the parties hereto, their respective successors and assigns, and shall follow and run with the title to the leases in the field or fields covered hereby, and the rights of either party may be assigned or conveyed in whole or in part, but all such assignments and conveyances shall be subject to this agreement. No transfer or succession to the interest of any party herein shall affect or bind the non-transferring party until the non-transferring party shall have been furnished at its address given above with the original recorded instrument or a certified copy of the recorded instrument under which the transfer or succession takes place.
          13.6 Conflicts. To the extent of any conflict between any portion of the written text of this Agreement or any Exhibit and any of the example(s) contained in this Agreement or any Exhibit hereto, the example(s) shall control.
          13.7 Media or Press Releases. No party shall issue a media or press release regarding the matters which are the subject of this Agreement unless such party has obtained the prior written

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consent of the other parties, except where such release is deemed in good faith by the releasing party to be required by applicable laws or applicable rules or regulations of any governmental body or stock exchange. However, any party that fails to object to a media or press release within seventy-two (72) hours following proper notice of the proposed media or press release will be deemed to have consented to such media or press release. The parties shall use reasonable efforts to unanimously agree upon the timing and content of releases to the news media concerning operations covered by this Agreement. However, in the event the parties cannot unanimously agree upon either the timing and/or content of the news release within seventy-two (72) hours of receipt of such proposed news release, then any party shall be allowed to issue its own release without the approval of the other parties.
[ Signatures are on the next page. ]

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           IN WITNESS WHEREOF, this Agreement is executed by the parties hereto on the date first above written.

PLANT SUPPLIER:

AMERICAN MIDSTREAM (LOUISIANA INTRASTATE), LLC
 	 	
 	By:  	/s/ Marty Patterson  	 	
 	 	Marty Patterson 	 	
 	 	SR UP 	 	
 	
 	PROCESSOR:

ENTERPRISE GAS PROCESSING, LLC
 	 	
 	By:  	/s/ William S. Goloway  	 	
 	 	William S. Goloway 	 	
 	 	Regional Director 	 	

		
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EXHIBIT “C”
TO
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
FRACTIONATION FEE
Beginning on the effective date of this Agreement, and on the first day of each month thereafter with respect to fuel gas, the Fractionation Fee shall be calculated based on the following formula (expressed in cents/Gallon):

 	 	(W)(1.20)
 
$4.00/MMBTU	 	+ 2.40 = 	 	Fractionation Fee
¢/Gallon	
     With respect to the formula above, the following definition shall apply:
W = The settlement price in dollars per MMBtu, for the Henry Hub index (“Index”), as published in Inside F.E.R. C.’s Gas Market Report (“IFERC”) , in effect for the month in which the Gas is being processed (e.g. IFERC price published on/near last day of February for March gas flows).
Notwithstanding anything to the contrary herein, in no event shall the adjustments permitted by the formula appearing above in this Agreement reduce the Fractionation Fee below 3.60 cents ($0.0360) per gallon (the “Fractionation Fee Floor”). In the event that the computation of the Fractionation Fee, as herein provided, results in an amount that is less than the 3.60 cents ($0.0360) per gallon, then the Parties acknowledge and agree that the Fractionation Fee shall be 3.60 cents ($0.0360) per gallon. In the event that anything in this Agreement conflicts or otherwise restricts the application of the Fractionation Fee Floor, the Fractionation Fee Floor shall fully apply and control.

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EXHIBIT “D”
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
PRODUCT INDEX BASES
 	 	 	
Product	 	Pricing Basis	
Ethane	 	OPIS monthly average (of daily high and low) price for Napoleonville ethane, less $0.005/gallon.	
 	 	 	
Propane	 	OPIS monthly average (of daily high and low) price for Napoleonville propane, less $0.0125/gallon.	
 	 	 	
Isobutane	 	OPIS monthly average (of daily high and low) price for Napoleonville isobutane, less $0.005/gallon.	
 	 	 	
Normal Butane	 	OPIS monthly average (of daily high and low) price for Napoleonville normal butane, less $0.0125/gallon.	
 	 	 	
Natural Gasoline	 	OPIS monthly average (of daily high and low) price for Napoleonville natural gasoline, less $0.005/gallon.	
NOTE: The above basis pricing reflects the Toca gas plant’s existing agreement for sale by the plant of natural gas liquids fob the Norco Fractionator Plant. The pricing basis herein may change from time-to-time, and upon notification of such change to Plant Supplier, the new pricing basis will become effective for the month following the month of such notification.

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EXHIBIT “E”
TO
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
PLANT SUPPLIER’S FIELD DELIVERY POINT(S) FOR PROCESSING
THE PORTION OF GAS THAT IS DELIVERED TO PROCESSOR AT THE FOLLOWING FIELD DELIVERY POINT FROM A NEW INTERRCONNECT BETWEEN PLANT SUPPLIER’S GLORIA PIPELINE AND TENNESSEE PIPELINE. SUB-ALLOCATION OF THIS GAS WILL BE BASED ON MCF AND THEORETICAL NGL GALLONS RECEIVED BY PROCESSOR DIRECTLY FROM TENNESSEE PIPELINE. PLANT SUPPLIER HOLDS PROCESSING RIGHTS TO GAS DELIVERED THEREFROM AND WHICH IS TO BE PROCESSED HEREUNDER:

 	 	Southern Delivery Point	 	 	 	Southern Meter Number	
 	 	 	 	 	 	 	 	 	
 	 	Creole Receiving Station	 	 	 	 	039500	 	

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EXHIBIT “F”
TO
GAS PROCESSING AGREEMENT
TOCA GAS PROCESSING PLANT
ST. BERNARD PARISH, LOUISIANA
SETTLEMENT INSTRUCTIONS
American Midstream (Louisiana Intrastate), LLC (“Plant Supplier”)
Payments to Plant Supplier (wire):
 Comerica Bank
 910 Louisiana, Suite 410
 Houston, Texas 77210
 ABA: 111000753
 Account Number: 1881319493
 Beneficiary account — American Midstream (Louisiana Intrastate), LLC
Plant Supplier’s Statement Address:
American Midstream (Louisiana Intrastate), LLC
Attn: Gas Contracts
8300 FM 1960 West, Suite 225
Houston, TX 77070
Phone: 281-955-4800
Fax: 281-955-4855
If by electronic mail: Email: bpieri@americanmidstream.com

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Exhibit 10.26
EMPLOYMENT AGREEMENT
     THIS EMPLOYMENT AGREEMENT (“Agreement”) is made by and between American Midstream GP, LLC, a Delaware limited liability company (“Company”), and Sandra M. Flower (“Executive”).
W I T N E S S E T H:
     WHEREAS, Executive is currently employed by Company, which is the general partner of American Midstream Partners, LP (“American Midstream LP”); and
     WHEREAS, in connection with the initial public offering of the common units of American Midstream LP, Company and Executive desire to enter into this Agreement to provide the terms and conditions of Executive’s employment with the Company from and after the Effective Date;
     NOW, THEREFORE, for and in consideration of the mutual promises, covenants and obligations contained herein, Company and Executive agree as follows:
ARTICLE 1: EMPLOYMENT AND DUTIES
     1.1 Employment; Effective Date . Effective as of, and contingent upon, the closing of the initial public offering of the common units of American Midstream LP (the “Effective Date”), and continuing for the period of time set forth in Article 2 of this Agreement, Executive’s employment by Company shall be subject to the terms and conditions of this Agreement.
     1.2 Positions . Company shall employ Executive in the position of Vice President of Finance reporting to the President and Chief Executive Officer of the Company, or in such other positions as the parties mutually may agree.
     1.3 Duties and Services . Executive agrees to serve in the position referred to in paragraph 1.2 and to perform diligently and to the best of his or her abilities the duties and services appertaining to such office, as well as such additional duties and services appropriate to such office which the parties mutually may agree upon from time to time. Executive’s employment shall also be subject to the policies maintained and established by Company that are of general applicability to Company’s executive employees, as such policies may be amended from time to time, provided that in the event of any inconsistency between such policies and any term of this Agreement, this Agreement shall control.
     1.4 Other Interests . Executive agrees, during the period of his or her employment by Company, to devote substantially all of his or her primary business time, energy and best efforts to the business and affairs of Company and its affiliates and not to engage, directly or indirectly, in any other business or businesses, whether or not similar to that of Company, except with the consent of the Board.

 

     1.5 Duty of Loyalty . Executive acknowledges and agrees that Executive owes a fiduciary duty of loyalty to act at all times in the best interests of Company. In keeping with such duty, Executive shall make full disclosure to Company of all business opportunities pertaining to Company’s business and shall not appropriate for Executive’s own benefit business opportunities concerning Company’s business.
ARTICLE 2: TERM AND TERMINATION OF EMPLOYMENT
     2.1 Term . Unless sooner terminated pursuant to other provisions hereof, Company agrees to continue to employ Executive for the period beginning on the Effective Date and ending on the second anniversary of the Effective Date (the “Initial Expiration Date”); provided, however, that beginning on the Initial Expiration Date, and on each anniversary of the Initial Expiration Date thereafter, if this Agreement has not been terminated pursuant to paragraph 2.2 or 2.3, then the term of this Agreement shall automatically be extended for an additional one-year period, unless on or before the date that is 90 days prior to the first day of any such extension period, either party shall give written notice to the other that no such automatic extension shall occur.
     2.2 Company’s Right to Terminate . Notwithstanding the provisions of paragraph 2.1, Company shall have the right to terminate Executive’s employment under this Agreement for any of the following reasons:
     (i) upon Executive’s death;
     (ii) upon Executive’s disability, which shall mean Executive’s becoming incapacitated by accident, sickness, or other circumstances which renders him or her mentally or physically incapable of performing the duties and services required of him or her hereunder for 90 or more days (whether or not consecutive) out of any consecutive 180-day period;
     (iii) for “Cause,” which shall mean Executive has (A) engaged in gross negligence, gross incompetence or willful misconduct in the performance of the duties required of him or her hereunder; (B) refused without proper reason to perform the duties and responsibilities required of him or her hereunder; (C) willfully engaged in conduct that is materially injurious to Company or its affiliates (monetarily or otherwise); (D) committed an act of fraud, embezzlement or willful breach of fiduciary duty to Company or an affiliate (including the unauthorized disclosure of confidential or proprietary material information of Company or an affiliate) or (E) been convicted of (or pleaded no contest to) a crime involving fraud, dishonesty or moral turpitude or any felony; or
     (iv) at any time for any other reason, or for no reason whatsoever, in the sole discretion of the Board.
     2.3 Executive’s Right to Terminate . Notwithstanding the provisions of paragraph 2.1, Executive shall have the right to terminate his or her employment under this Agreement for any of the following reasons:
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     (i) for “Good Reason,” which shall mean, in connection with or based upon a nonconsensual (A) material diminution in Executive’s responsibilities, duties or authority; (B) material diminution in Executive’s base compensation; (C) assignment of Executive to a principal office located beyond a 50-mile radius of Executive’s then current work place, or (D) material breach by Company of any material provision of this Agreement; or
     (ii) at any time for any other reason, or for no reason whatsoever, in the sole discretion of Executive.
     2.4 Notice of Termination . If Company desires to terminate Executive’s employment hereunder at any time prior to expiration of the term of employment as provided in paragraph 2.1, it shall do so by giving a 30-day written notice to Executive that it has elected to terminate Executive’s employment hereunder and stating the effective date and reason for such termination, provided that no such action shall alter or amend any other provisions hereof or rights arising hereunder. If Executive desires to terminate his or her employment hereunder at any time prior to expiration of the term of employment as provided in paragraph 2.1, he or she shall do so by giving a 30-day written notice to Company that he or she has elected to terminate his or her employment hereunder and stating the effective date and reason for such termination, provided that no such action shall alter or amend any other provisions hereof or rights arising hereunder. In the case of any notice by Executive of his or her intent to terminate his or her employment hereunder for Good Reason, Executive shall provide Company with notice of the existence of the condition(s) constituting the Good Reason within 60 days after Executive has actual knowledge of the initial existence of such condition(s) and Company shall have 30 days following Executive’s provision of such notice to remedy such condition(s). If Company remedies the condition(s) constituting the Good Reason within such 30 day period, then Executive’s employment hereunder shall continue and his or her notice of termination shall become void and of no further effect. If Company does not remedy the condition(s) constituting the Good Reason within such 30 day period, Executive’s employment with Company shall terminate on the date that is 31 days following the date of Executive’s notice of termination and Executive shall be entitled to receive the payments and benefits described in paragraph 4.3, if applicable. The notice, remedy rights and termination timing provisions applicable under this paragraph 2.4 in the case of Executive’s election to terminate his or her employment for Good Reason are referred to collectively as the “Good Reason Termination Procedure.”
     2.5 Deemed Resignations . Any termination of Executive’s employment shall constitute an automatic resignation of Executive as an officer of Company and each affiliate of Company, an automatic resignation of Executive from the Board and from the board of directors or similar governing body of any affiliate of Company, and an automatic resignation from the board of directors or similar governing body of any corporation, limited liability company or other entity in which Company or any affiliate holds an equity interest and with respect to which board or similar governing body Executive serves as Company’s or such affiliate’s designee or other representative.
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ARTICLE 3: COMPENSATION AND BENEFITS
     3.1 Base Salary . During the period of this Agreement, Executive shall receive an annual base salary of $175,000. Executive’s annual base salary shall be reviewed by the Compensation Committee of the Board (“Compensation Committee”) on an annual basis, and, in the sole discretion of the Compensation Committee, such annual base salary may be increased, but not decreased (except for a decrease that is consistent with reductions taken generally by other executives of Company), effective as of any date determined by the Compensation Committee. Executive’s annual base salary shall be paid in equal installments in accordance with Company’s standard policy regarding payment of compensation to executives, but no less frequently than monthly.
     3.2 Bonus Opportunity . During the period of this Agreement, Executive shall be provided with the opportunity to earn and receive an annual incentive performance bonus payable in cash in an amount equal to $100,000 (pro-rated for any period of less than 12 months), 20 percent of which shall be conditioned and determined on the attainment of personal performance goals and 80 percent of which shall be conditioned and determined on the attainment of organizational performance goals, in each case as set by, and based on performance criteria established by, the Compensation Committee. The Compensation Committee shall notify Executive of the bonus opportunity by no later than the end of the first 90 days of each annual performance period and shall, at that time, set and communicate to Executive the personal and organizational performance goals on which the bonus (and each component thereof) shall be conditioned and the criteria on which the attainment of such goals and the resulting bonus, if any, shall be determined. All determinations with respect to the bonus hereunder shall be made by the Compensation Committee and its determinations shall be final and binding.
     3.3 Incentive Compensation . Executive shall be eligible to receive awards under the Company’s Long Term Incentive Plan, as determined by the Compensation Committee.
     3.4 Other Perquisites . During his or her employment hereunder, Executive shall be afforded the following benefits as incidences of his or her employment:
     (i) Business and Entertainment Expenses — Subject to Company’s standard policies and procedures with respect to expense reimbursement as applied to its executive employees generally, Company shall reimburse Executive for, or pay on behalf of Executive, reasonable and appropriate expenses incurred by Executive for business related purposes, including dues and fees to industry and professional organizations and costs of entertainment and business development.
     (ii) Vacation — During his or her employment hereunder, Executive shall be entitled to four weeks of paid vacation each calendar year (pro-rated for the calendar year containing the Effective Date) and to all holidays provided to executives of Company generally.
     (iii) Other Company Benefits — Executive and, to the extent applicable, Executive’s spouse, dependents and beneficiaries, shall be allowed to participate in, and in accordance with the terms of, all benefits, plans and programs, including
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improvements or modifications of the same, which are now, or may hereafter be, available to other executive employees of Company. Such benefits, plans and programs shall include, without limitation, any profit sharing plan, thrift plan, health insurance or health care plan, life insurance, disability insurance, pension plan, supplemental retirement plan, vacation and sick leave plan, and the like which may be maintained by Company. Company shall not, however, by reason of this paragraph be obligated to institute, maintain, or refrain from changing, amending, or discontinuing, any such benefit plan or program, so long as such changes are similarly applicable to executive employees generally.
ARTICLE 4: EFFECT OF TERMINATION ON COMPENSATION
     4.1 Payment of Accrued Obligations . Upon termination of Executive’s employment hereunder for any reason and by any means, Executive shall be entitled to, and shall be paid, any annual base salary that is accrued and unpaid as of the date of such termination, which shall be paid on the next regularly scheduled pay day for the payment of Executive’s annual base salary, and any expense reimbursement payable in accordance with paragraph 3.4(i) for reimbursable expenses incurred by Executive prior to the date of such termination, which shall be paid at the time and in the manner provided by Company’s reimbursement policy and in accordance with this Agreement. Other than the foregoing amounts and any Severance Pay pursuant to paragraph 4.3, all compensation and benefits to Executive hereunder shall terminate contemporaneously with the termination of Executive’s employment. Any other benefits to which Executive shall be entitled shall be governed by the plan, policy or agreement providing for such benefits and applicable law.
     4.2 Other Terminations . If Executive’s employment hereunder shall terminate at any time (including, but not limited to, upon or following a change of control of the Company), (i) upon expiration of the term provided in paragraph 2.1 hereof because either party has provided the notice contemplated in such paragraph (except as provided in Section 5.6 hereof), (ii) by Executive for Good Reason and in accordance with the Good Reason Termination Procedure or (iii) by Company other than in any event or circumstance described in paragraph 2.2(i), 2.2(ii), or 2.2(iii), then, subject to paragraph 4.4, Company shall pay Executive an amount equal one times the sum of Executive’s annual base salary at the rate in effect under paragraph 3.1 on the date of such termination, plus one times the amount, if any, paid to Executive under paragraph 3.2 for the calendar year ending immediately prior to the date of such termination of Executive’s employment (the “Severance Amount”), which shall be paid as provided in paragraph 4.3.
     4.3 Severance Payments . Subject to paragraph 4.4 below, the Severance Amount, if any shall be due, shall be divided into amounts (each, a “Severance Payment”) to be paid in installments. The amount of each Severance Payment shall be equal to the Severance Amount divided by the number of regular pay days scheduled (in accordance with Company’s regular payroll practices) to occur between the date of Executive’s termination of employment (“Termination Date”) and the first anniversary of the Termination Date (“Scheduled Paydays”). If any Severance Amount would otherwise be owed under this Agreement, but the requirements of paragraph 4.4 are not satisfied, then no Severance Amount and no amount in lieu of the Severance Amount, shall be owed or paid. If the requirements of paragraph 4.4 are satisfied, then, subject to paragraph 7.14(iv), a portion of the Severance Amount equal to the product of
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one Severance Payment and the number of Scheduled Paydays during the 60-day period beginning on the Termination Date shall be paid in a lump sum amount on the 60 th day following the Termination Date, and the remainder of the Severance Amount shall be paid in regular installments, each one equal to the amount of one Severance Payment, with the first such payment being due on due on the Scheduled Payday immediately following the 60 th day after the Termination Date, with like payments on each Scheduled Payday thereafter until the remaining Severance Amount is paid in full.
     4.4 Release and Full Settlement . Anything to the contrary herein notwithstanding, as a condition to the receipt of any portion of the Severance Amount, Executive shall execute a release, in the form established by the Board, releasing the Board, Company, and Company’s parent corporation, subsidiaries, affiliates, and their respective shareholders, partners, officers, directors, employees, attorneys and agents from any and all claims and from any and all causes of action of any kind or character including, but not limited to, all claims or causes of action arising out of Executive’s employment with Company or its affiliates or the termination of such employment, but excluding all claims to vested benefits and payments Executive may have under any compensation or benefit plan, program or arrangement, including this Agreement. Executive shall provide such release to Company no later than 50 days after the Termination Date and, as a condition to Company’s obligation to pay all or any portion of the Severance Amount, Executive shall not revoke such release. The performance of Company’s obligations hereunder shall constitute full settlement of all such claims and causes of action.
     4.5 No Duty to Mitigate Losses . Executive shall have no duty to find new employment following the termination of his or her employment under circumstances which require Company to pay any amount to Executive pursuant to this Article 4. Any salary or remuneration received by Executive from a third party for the providing of personal services (whether by employment or by functioning as an independent contractor) following the termination of his or her employment under circumstances pursuant to which this Article 4 apply shall not reduce Company’s obligation to make a payment to Executive (or the amount of such payment) pursuant to the terms of this Article 4.
     4.6 Liquidated Damages . In light of the difficulties in estimating the damages for an early termination of Executive’s employment under this Agreement, Company and Executive hereby agree that the payments and benefits, if any, to be received by Executive pursuant to this Article 4 shall be received by Executive as liquidated damages.
     4.7 Other Benefits . This Agreement governs the rights and obligations of Executive and Company with respect to Executive’s base salary, bonus and certain perquisites of employment. Except as expressly provided herein, Executive’s rights and obligations both during the term of his or her employment and thereafter with respect to his or her ownership rights in Company and American Midstream LP, and other benefits under the plans and programs maintained by Company shall be governed by the terms (which are not, and are not required to be, affected, altered or amended) of the separate agreements, plans and the other documents and instruments governing such matters.
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ARTICLE 5: PROTECTION OF CONFIDENTIAL INFORMATION
     5.1 Disclosure to and Property of Company . All information, designs, ideas, concepts, improvements, product developments, discoveries and inventions, whether patentable or not, that are conceived, made, developed or acquired by Executive, individually or in conjunction with others, during the period of Executive’s employment by Company (whether during business hours or otherwise and whether on Company’s premises or otherwise) that relate to Company’s (or any of its affiliates’) business, trade secrets, products or services (including, without limitation, all such information relating to corporate opportunities, product specification, compositions, manufacturing and distribution methods and processes, research, financial and sales data, pricing terms, evaluations, opinions, interpretations, acquisitions prospects, the identity of customers or their requirements, the identity of key contacts within the customer’s organizations or within the organization of acquisition prospects, marketing and merchandising techniques, business plans, computer software or programs, computer software and database technologies, prospective names and marks) (collectively, “Confidential Information”) shall be disclosed to Company and are and shall be the sole and exclusive property of Company (or its affiliates). Moreover, all documents, videotapes, written presentations, brochures, drawings, memoranda, notes, records, files, correspondence, manuals, models, specifications, computer programs, E-mail, voice mail, electronic databases, maps, drawings, architectural renditions, models and all other writings or materials of any type embodying any of such information, ideas, concepts, improvements, discoveries, inventions and other similar forms of expression (collectively, “Work Product”) are and shall be the sole and exclusive property of Company (or its affiliates). Upon Executive’s termination of employment with Company, for any reason, Executive promptly shall deliver such Confidential Information and Work Product, and all copies thereof, to Company.
     5.2 Disclosure to Executive . In reliance upon Executive’s representations and agreements in this Agreement, Company has and will disclose to Executive, and will place Executive in a position to have access to and to develop, Confidential Information and Work Product of Company (or its affiliates); and/or has and will entrust Executive with business opportunities of Company (or its affiliates); and/or has and will place Executive in a position to develop business good will on behalf of Company (or its affiliates). Executive agrees to preserve and protect the confidentiality of all Confidential Information or Work Product of Company (or its affiliates).
     5.3 No Unauthorized Use or Disclosure . Executive agrees that he or she will not, at any time during or after Executive’s employment by Company, make any unauthorized disclosure of, and will prevent the removal from Company premises of, Confidential Information or Work Product of Company (or its affiliates), or make any use thereof, except in the carrying out of Executive’s responsibilities during the course of Executive’s employment with Company. Executive shall use commercially reasonable efforts to cause all persons or entities to whom any Confidential Information shall be disclosed by him or her hereunder to observe the terms and conditions set forth herein as though each such person or entity was bound hereby. Executive shall have no obligation hereunder to keep confidential any Confidential Information if and to the extent disclosure thereof is specifically required by law; provided, however, that in the event disclosure is required by applicable law, Executive shall provide Company with prompt notice of such requirement prior to making any such disclosure, so that Company may seek an appropriate
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protective order or otherwise contest such disclosure. At the request of Company at any time, Executive agrees to deliver to Company all Confidential Information that he or she may possess or control. Executive agrees that all Confidential Information of Company (whether now or hereafter existing) conceived, discovered or made by him or her during the period of Executive’s employment by Company exclusively belongs to Company (and not to Executive), and Executive will promptly disclose such Confidential Information to Company and perform all actions reasonably requested by Company to establish and confirm such exclusive ownership. Affiliates of Company shall be third party beneficiaries of Executive’s obligations under this Article 5. As a result of Executive’s employment by Company, Executive may also from time to time have access to, or knowledge of, Confidential Information or Work Product of third parties, such as customers, suppliers, partners, joint venturers, and the like, of Company and its affiliates. Executive also agrees to preserve and protect the confidentiality of such third party Confidential Information and Work Product to the same extent, and on the same basis, as Company’s Confidential Information and Work Product.
     5.4 Ownership by Company . If, during Executive’s employment by Company, Executive creates any work of authorship fixed in any tangible medium of expression that is the subject matter of copyright (such as videotapes, written presentations, or acquisitions, computer programs, E-mail, voice mail, electronic databases, drawings, maps, architectural renditions, models, manuals, brochures, or the like) relating to Company’s business, products, or services, whether such work is created solely by Executive or jointly with others (whether during business hours or otherwise and whether on Company’s premises or otherwise), including any Work Product, Company shall be deemed the author of such work if the work is prepared by Executive in the scope of Executive’s employment; or, if the work is not prepared by Executive within the scope of Executive’s employment but is specially ordered by Company as a contribution to a collective work, as a part of a motion picture or other audiovisual work, as a translation, as a supplementary work, as a compilation, or as an instructional text, then the work shall be considered to be work made for hire and Company shall be the author of the work. If such work is neither prepared by Executive within the scope of Executive’s employment nor a work specially ordered that is deemed to be a work made for hire, then Executive hereby agrees to assign, and by these presents does assign, to Company all of Executive’s worldwide right, title, and interest in and to such work and all rights of copyright therein.
     5.5 Assistance by Executive . During the period of Executive’s employment by Company and thereafter, Executive shall assist Company and its nominee, at any time, in the protection of Company’s (or its affiliates’) worldwide right, title and interest in and to Work Product and the execution of all formal assignment documents requested by Company or its nominee and the execution of all lawful oaths and applications for patents and registration of copyright in the United States and foreign countries.
     5.6 Non-Competition Obligations . Both as part of the consideration for the compensation and benefits to be paid to Executive hereunder; and to protect the trade secrets and Confidential Information of Company and its affiliates that have been or will in the future be disclosed or entrusted to Executive, the business good will of Company and its affiliates that has been and will in the future be developed in Executive, and the business opportunities that have been and will in the future be disclosed or entrusted to Executive by Company and its affiliates; Executive agrees that during the period that Executive is employed by Company and for 12
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months after the date of the termination of Executive’s employment with the Company for any reason, Executive shall not, directly or indirectly for Executive or for others, in the geographic areas and markets where Company conducts any business during Executive’s employment with the Company (as identified on Schedule A attached hereto, and amended by the Company from time to time), as well as any other geographic area or market where Company is conducting any business as of the date of termination of the employment relationship:

 	(i)	 	engage in the business of acquiring, developing, improving, managing, providing services with respect to, operating and disposing of mid-stream energy projects, including pipelines, treatment and processing facilities and gas storage fields or any other business that is competitive with the business conducted by Company;	
 		
 	(ii)	 	render any advice or services to, or otherwise assist, any other person, association, or entity who is engaged, directly or indirectly, with any business that is competitive with the business conducted by Company;	
 		
 	(iii)	 	induce any employee of Company or its affiliates to terminate his or her employment with Company or its affiliates, or hire or assist in the hiring of any such employee by any person, association, or entity not affiliated with Company; or	
 		
 	(iv)	 	request or cause any customer of Company or its affiliates to terminate any business relationship with Company or its affiliates.	
Executive understands that the foregoing restrictions may limit Executive’s ability to engage in certain businesses anywhere in the world during the period provided for above, but acknowledges and represents that the restrictions are both reasonable and necessary to protect Company’s legitimate business interests, and that Executive will receive sufficiently high remuneration and other benefits under this Agreement to compensate for and to justify such restrictions. Notwithstanding the foregoing, in the event that the Executive’s employment is terminated upon expiration of the initial or extended term pursuant to Section 2.1 hereof because either party has provided the notice contemplated in such paragraph, the Board may, in its discretion, release the Executive from the covenants contained in this Section 5.6; provided, however, that in such case, the Executive shall not receive the Severance Amount provided in Section 4.2 hereof.
     5.7 Enforcement and Remedies . Executive acknowledges and agrees that money damages would not be sufficient remedy for any breach of this Article 5 by Executive, and Company or its affiliates shall be entitled to enforce the provisions of this Article 5 by terminating payments then owing to Executive under this Agreement or otherwise, by specific performance and injunctive relief as remedies for such breach or any threatened breach. Such remedies shall not be deemed the exclusive remedies for a breach of this Article 5, but shall be in addition to all remedies available at law or in equity, including, without limitation, the recovery of damages from Executive and Executive’s agents involved in such breach and remedies available to Company pursuant to other agreements with Executive.
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     5.8 Reformation . It is expressly understood and agreed that Company and Executive consider the restrictions contained in this Article 5 to be reasonable and necessary to protect the proprietary information of Company and its affiliates. Nevertheless, if any of the aforesaid restrictions are found by a court having jurisdiction to be unreasonable, or overly broad as to geographic area or time, or otherwise unenforceable, the parties intend for the restrictions therein set forth to be modified by such courts so as to be reasonable and enforceable and, as so modified by the court, to be fully enforced.
ARTICLE 6: NONDISPARAGEMENT
     Executive shall refrain, both during the employment relationship and after the employment relationship terminates, from publishing any oral or written statements about Company, its affiliates, or any of such entities’ officers, employees, agents or representatives that (i) are slanderous, libelous, or defamatory; (ii) disclose private or confidential information about Company, its affiliates, or any of such entities’ business affairs, officers, employees, agents, or representatives; (iii) constitute an intrusion into the seclusion or private lives of the officers, employees, agents, or representatives of Company or its affiliates; (iv) give rise to unreasonable publicity about the private lives of the officers, employees, agents, or representatives of Company or its affiliates; (v) place Company, its affiliates, or any of such entities’ officers, employees, agents, or representatives in a false light before the public; or (vi) constitute a misappropriation of the name or likeness of Company, its affiliates, or any of such entities’ officers, employees, agents, or representatives. A violation or threatened violation of this prohibition may be enjoined by the courts. The rights afforded Company and its affiliates under this provision are in addition to any and all rights and remedies otherwise afforded by law.
     Company agrees that, both during Executive’s employment relationship and after the employment relationship terminates, Company, its affiliates, and such entities’ officers, employees, agents or representatives shall refrain from publishing any oral or written statements about Executive that (i) are slanderous, libelous, or defamatory; (ii) disclose private or confidential information about Executive; (iii) that constitute an intrusion into the seclusion or private life of Executive; (iv) give rise to unreasonable publicity about the private life of Executive; (v) place Executive in a false light before the public; or (vi) constitute a misappropriation of the name or likeness of Executive. A violation or threatened violation of this prohibition may be enjoined by the courts. The rights afforded Executive under this provision are in addition to any and all rights and remedies otherwise afforded by law.
     The nondisparagement obligations of this Article 6 shall not apply to communications with law enforcement or required testimony under law or court process.
ARTICLE 7: MISCELLANEOUS
     7.1 Notices . For purposes of this Agreement, notices and all other communications provided for herein shall be in writing and shall be deemed to have been duly given when personally delivered or when mailed by United States registered or certified mail, return receipt requested, postage prepaid, addressed as follows:
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If to Company to:	 	American Midstream GP, LLC	
 	 	1614 15th Street	
 	 	Suite 300	
 	 	Denver, CO 80202	
 	 	Attention: Chairman of the Board	
 	 	 	
with a copy to:	 	American Infrastructure MLP Fund, L.P.	
 	 	950 Tower Lane	
 	 	Suite 800	
 	 	Foster City, CA 94404	
 	 	Attention: Ed Diffendal and Robert B. Hellman, Jr.	
 	 	 	
If to Executive to:	 	Sandra M. Flower	
 	 	10066 Wyecliff Drive	
 	 	Highlands Ranch, CO 80216	
or to such other address as either party may furnish to the other in writing in accordance herewith, except that notices or changes of address shall be effective only upon receipt.
     7.2 Applicable Law . This Agreement is entered into under, and shall be governed for all purposes by, the laws of the State of Delaware.
     7.3 No Waiver . No failure by either party hereto at any time to give notice of any breach by the other party of, or to require compliance with, any condition or provision of this Agreement shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.
     7.4 Severability . If a court of competent jurisdiction determines that any provision of this Agreement is invalid or unenforceable, then the invalidity or unenforceability of that provision shall not affect the validity or enforceability of any other provision of this Agreement, and all other provisions shall remain in full force and effect.
     7.5 Counterparts . This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same Agreement.
     7.6 Withholding of Taxes and Other Employee Deductions . Company may withhold from any benefits and payments made pursuant to this Agreement or otherwise all federal, state, city and other taxes as may be required pursuant to any law or governmental regulation or ruling and all other normal employee deductions made with respect to Company’s employees generally.
     7.7 Headings . The paragraph headings have been inserted for purposes of convenience and shall not be used for interpretive purposes.
     7.8 Gender and Plurals . Wherever the context so requires, the masculine gender includes the feminine or neuter, and the singular number includes the plural and conversely.
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     7.9 Affiliate . As used in this Agreement, the term “affiliate” shall mean any entity which owns or controls, is owned or controlled by, or is under common ownership or control with, Company.
     7.10 Term . This Agreement has a term co-extensive with the term of employment provided in Article 2. Termination shall not affect any right or obligation of any party which is accrued or vested prior to such termination. The provisions of paragraphs 2.4 and 2.5 and Articles 4, 5, 6, and 7 shall survive any termination of this Agreement.
     7.11 Entire Agreement . Except as provided in (i) the written benefit plans and programs referenced in paragraph 3.4(iii) (and any agreements between Company and Executive that have been executed under such plans and programs) and paragraph 4.7 and (ii) any signed written agreement contemporaneously or hereafter executed by Company and Executive, this Agreement constitutes the entire agreement of the parties with regard to the subject matter hereof, and contains all the covenants, promises, representations, warranties and agreements between the parties with respect to employment of Executive by Company. Without limiting the scope of the preceding sentence, all understandings and agreements preceding the date of execution of this Agreement and relating to the subject matter hereof (other than (A) under the agreements described in clause (i) of the preceding sentence; (B) as provided herein or (C) under the agreements forming and/or operating Company and American Midstream, LP or any investor rights agreement related thereto) are hereby null and void and of no further force and effect. Any modification of this Agreement will be effective only if it is in writing and signed by the party to be charged.
     7.12 Legal Expenses . If Executive incurs legal costs and expenses (including reasonable attorneys’ fees) in any contest relating to rights under this Agreement and prevails in such contest, Company shall reimburse Executive for his or her reasonable legal costs and expenses (including reasonable attorneys’ fees) incurred with respect to such contest.
     7.13 Liability Insurance . Company shall maintain a directors’ and officers’ insurance liability policy throughout the term of this Agreement and shall provide Executive with coverage under such policy on terms not less favorable than provided to other Company directors and officers.
     7.14 Compliance with Section 409A of the Code .
     (i) All references in this Agreement to the termination of Executive’s employment with Company shall mean and shall be deemed to occur if and when a termination of employment that constitutes a “separation from service” within the meaning of Section 409A(a)(2)(A)(i) of the Internal Revenue Code of 1986, as amended (the “Code”), and applicable administrative guidance issued thereunder has occurred.
     (ii) To the extent that any reimbursement or benefit in kind hereunder constituted deferred compensation under Section 409A of the Code, such reimbursement or benefit shall be administered consistently with the following additional requirements as set forth in Treas. Reg. §1.409A-3(i)(1)(iv): (1) Executive’s eligibility for or receipt of benefits or reimbursements in one calendar year will not affect Executive’s eligibility for
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or the amount of benefits or reimbursements in any other calendar year, (2) any reimbursement of eligible expenses will be made on or before the last day of the year following the year in which the expense was incurred, (3) Executive’s right to benefits or reimbursement is not subject to liquidation or exchange for another benefit, and (4) the right to reimbursement of expenses incurred or to the provision of benefits in kind shall terminate ten (10) years from Executive’s termination of employment, if not before.
     (iii) Executive’s right to installment payments, if any, hereunder, shall be treated as the right to receive a series of separate and distinct individual payments for purposes of Section 409A of the Code.
     (iv) Notwithstanding any provision in this Agreement to the contrary, if Executive is a “specified employee” (within the meaning of Section 409A(a)(2)(B)(i) of the Code, and applicable administrative guidance thereunder and determined in accordance with any method selected by Company that is permitted under the regulations issued under Section 409A of the Code), and any amount paid or benefit provided under this Agreement to or on behalf of Executive would be subject to additional taxes under Section 409A of the Code because the timing of such payment is not delayed as provided in Section 409A(a)(2)(B)(i) of the Code and the regulations thereunder, then any such payment or benefit that Executive would otherwise be entitled to during the first six months following the date of Executive’s separation from service (within the meaning of Section 409A(a)(2)(A)(i) of the Code and applicable administrative guidance thereunder) shall be accumulated and paid or provided, as applicable, on the date that is six months plus one day after Executive’s separation from service (or if such date does not fall on a business day of Company, the next following business day of Company), or such earlier date upon which such amount can be paid or provided under Section 409A of the Code without being subject to such additional taxes and interest; provided, however, that Executive shall be entitled to receive the maximum amount permissible under Section 409A of the Code and the applicable administrative guidance thereunder during the six-month period following his or her separation from service that will not result in the imposition of any additional tax or penalties on such amount.
     (v) To the extent that Section 409A of the Code is applicable to this Agreement, the provisions of this Agreement shall be interpreted as necessary to comply with such section and the applicable administrative guidance issued thereunder.
     7.15 Arbitration .
     (i) Company and Executive agree to submit to final and binding arbitration any and all disputes or disagreements concerning the interpretation or application of this Agreement, the termination of this Agreement, or any other aspect of Executive’s employment relationship with Company. Any such dispute or disagreement will be resolved by arbitration in accordance with the National Rules for the Resolution of Employment Disputes of the American Arbitration Association (the “AAA Rules”) before a single arbitrator. Arbitration will take place in Delaware, unless the parties mutually agree to a different location. Company and Executive agree that the decision of the arbitrator will be final and binding on both parties. Any court having jurisdiction may
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enter a judgment upon the award rendered by the arbitrator. The costs of the proceedings shall be borne equally by the parties unless the arbitrator orders otherwise.
     (ii) Notwithstanding the provisions of paragraph 7.15(i), (a) Company may, if it so chooses, bring an action in any court of competent jurisdiction for injunctive relief to enforce Executive’s obligations under Articles 5 or 6 hereof, pending a decision by the arbitrator in accordance with paragraph 7.15(i), and (b) Executive may, if he or she so chooses, bring an action in any court of competent jurisdiction for temporary or preliminary injunctive relief to enforce Company’s obligations under Article 6 hereof, pending a decision by the arbitrator in accordance with paragraph 7.15(i).
     7.16 Provisions Regarding Effective Date . As indicated in this Agreement, this Agreement is effective as of the Effective Date, and accordingly in connection therewith the parties agree that the following shall apply:
     (i) This Agreement shall from and after its execution by the parties be an agreement binding upon and enforceable by both Company and Executive subject to the application of the provisions hereof generally being effective as of the Effective Date.
     (ii) In the event that the employment of Executive by Company terminates at any time prior to the Effective Date, this Agreement shall be null and void and of no force and effect.
     (iii) In the event that the Effective Date does not occur on or before July 31, 2011, this Agreement shall be null and void and of no force and effect.
Signature page follows.
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      IN WITNESS WHEREOF , the parties hereto have executed this Agreement on the 8th day of June, 2011, to be effective as of the Effective Date.
 	 	 	 	 	
 	American Midstream GP, LLC
 	 	
 	By:  	/s/ Robert B. Hellman, Jr. 	 	
 	 	Robert B. Hellman, Jr., 	 	
 	 	Chairman, Compensation Committee 	 	
 	
 	“EXECUTIVE”
 	 	
 	 	/s/ Sandra M. Flower  	 	
 	 	Sandra M. Flower 	 	

Signature Page to Employment Agreement

 

SCHEDULE A
NONCOMPETITION GEOGRAPHIC AREAS AND SCOPE
Every State of the United States in which the Company does business on the Executive’s date of termination.
All customers of the Company on the Executive’s date of termination.

Exhibit 10.27
EMPLOYMENT AGREEMENT
     THIS EMPLOYMENT AGREEMENT (“Agreement”) is made by and between American Midstream GP, LLC, a Delaware limited liability company (“Company”), and William B. Mathews (“Executive”).
W I T N E S S E T H:
     WHEREAS, Executive is currently employed by Company, which is the general partner of American Midstream Partners, LP (“American Midstream LP”); and
     WHEREAS, in connection with the initial public offering of the common units of American Midstream LP, Company and Executive desire to enter into this Agreement to provide the terms and conditions of Executive’s employment with the Company from and after the Effective Date;
     NOW, THEREFORE, for and in consideration of the mutual promises, covenants and obligations contained herein, Company and Executive agree as follows:
ARTICLE 1: EMPLOYMENT AND DUTIES
     1.1 Employment; Effective Date . Effective as of, and contingent upon, the closing of the initial public offering of the common units of American Midstream LP (the “Effective Date”), and continuing for the period of time set forth in Article 2 of this Agreement, Executive’s employment by Company shall be subject to the terms and conditions of this Agreement.
     1.2 Positions . Company shall employ Executive in the position of Secretary, General Counsel and Vice President of Legal Affairs reporting to the President and Chief Executive Officer of the Company, or in such other positions as the parties mutually may agree.
     1.3 Duties and Services . Executive agrees to serve in the position referred to in paragraph 1.2 and to perform diligently and to the best of his or her abilities the duties and services appertaining to such office, as well as such additional duties and services appropriate to such office which the parties mutually may agree upon from time to time. Executive’s employment shall also be subject to the policies maintained and established by Company that are of general applicability to Company’s executive employees, as such policies may be amended from time to time, provided that in the event of any inconsistency between such policies and any term of this Agreement, this Agreement shall control.
     1.4 Other Interests . Executive agrees, during the period of his or her employment by Company, to devote substantially all of his or her primary business time, energy and best efforts to the business and affairs of Company and its affiliates and not to engage, directly or indirectly, in any other business or businesses, whether or not similar to that of Company, except with the consent of the Board.

 

     1.5 Duty of Loyalty . Executive acknowledges and agrees that Executive owes a fiduciary duty of loyalty to act at all times in the best interests of Company. In keeping with such duty, Executive shall make full disclosure to Company of all business opportunities pertaining to Company’s business and shall not appropriate for Executive’s own benefit business opportunities concerning Company’s business.
ARTICLE 2: TERM AND TERMINATION OF EMPLOYMENT
     2.1 Term . Unless sooner terminated pursuant to other provisions hereof, Company agrees to continue to employ Executive for the period beginning on the Effective Date and ending on the second anniversary of the Effective Date (the “Initial Expiration Date”); provided, however, that beginning on the Initial Expiration Date, and on each anniversary of the Initial Expiration Date thereafter, if this Agreement has not been terminated pursuant to paragraph 2.2 or 2.3, then the term of this Agreement shall automatically be extended for an additional one-year period, unless on or before the date that is 90 days prior to the first day of any such extension period, either party shall give written notice to the other that no such automatic extension shall occur.
     2.2 Company’s Right to Terminate . Notwithstanding the provisions of paragraph 2.1, Company shall have the right to terminate Executive’s employment under this Agreement for any of the following reasons:
     (i) upon Executive’s death;
     (ii) upon Executive’s disability, which shall mean Executive’s becoming incapacitated by accident, sickness, or other circumstances which renders him or her mentally or physically incapable of performing the duties and services required of him or her hereunder for 90 or more days (whether or not consecutive) out of any consecutive 180-day period;
     (iii) for “Cause,” which shall mean Executive has (A) engaged in gross negligence, gross incompetence or willful misconduct in the performance of the duties required of him or her hereunder; (B) refused without proper reason to perform the duties and responsibilities required of him or her hereunder; (C) willfully engaged in conduct that is materially injurious to Company or its affiliates (monetarily or otherwise); (D) committed an act of fraud, embezzlement or willful breach of fiduciary duty to Company or an affiliate (including the unauthorized disclosure of confidential or proprietary material information of Company or an affiliate) or (E) been convicted of (or pleaded no contest to) a crime involving fraud, dishonesty or moral turpitude or any felony; or
     (iv) at any time for any other reason, or for no reason whatsoever, in the sole discretion of the Board.
     2.3 Executive’s Right to Terminate . Notwithstanding the provisions of paragraph 2.1, Executive shall have the right to terminate his or her employment under this Agreement for any of the following reasons:
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     (i) for “Good Reason,” which shall mean, in connection with or based upon a nonconsensual (A) material diminution in Executive’s responsibilities, duties or authority; (B) material diminution in Executive’s base compensation; (C) assignment of Executive to a principal office located beyond a 50-mile radius of Executive’s then current work place, or (D) material breach by Company of any material provision of this Agreement; or
     (ii) at any time for any other reason, or for no reason whatsoever, in the sole discretion of Executive.
     2.4 Notice of Termination . If Company desires to terminate Executive’s employment hereunder at any time prior to expiration of the term of employment as provided in paragraph 2.1, it shall do so by giving a 30-day written notice to Executive that it has elected to terminate Executive’s employment hereunder and stating the effective date and reason for such termination, provided that no such action shall alter or amend any other provisions hereof or rights arising hereunder. If Executive desires to terminate his or her employment hereunder at any time prior to expiration of the term of employment as provided in paragraph 2.1, he or she shall do so by giving a 30-day written notice to Company that he or she has elected to terminate his or her employment hereunder and stating the effective date and reason for such termination, provided that no such action shall alter or amend any other provisions hereof or rights arising hereunder. In the case of any notice by Executive of his or her intent to terminate his or her employment hereunder for Good Reason, Executive shall provide Company with notice of the existence of the condition(s) constituting the Good Reason within 60 days after Executive has actual knowledge of the initial existence of such condition(s) and Company shall have 30 days following Executive’s provision of such notice to remedy such condition(s). If Company remedies the condition(s) constituting the Good Reason within such 30 day period, then Executive’s employment hereunder shall continue and his or her notice of termination shall become void and of no further effect. If Company does not remedy the condition(s) constituting the Good Reason within such 30 day period, Executive’s employment with Company shall terminate on the date that is 31 days following the date of Executive’s notice of termination and Executive shall be entitled to receive the payments and benefits described in paragraph 4.3, if applicable. The notice, remedy rights and termination timing provisions applicable under this paragraph 2.4 in the case of Executive’s election to terminate his or her employment for Good Reason are referred to collectively as the “Good Reason Termination Procedure.”
     2.5 Deemed Resignations . Any termination of Executive’s employment shall constitute an automatic resignation of Executive as an officer of Company and each affiliate of Company, an automatic resignation of Executive from the Board and from the board of directors or similar governing body of any affiliate of Company, and an automatic resignation from the board of directors or similar governing body of any corporation, limited liability company or other entity in which Company or any affiliate holds an equity interest and with respect to which board or similar governing body Executive serves as Company’s or such affiliate’s designee or other representative.
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ARTICLE 3: COMPENSATION AND BENEFITS
     3.1 Base Salary . During the period of this Agreement, Executive shall receive an annual base salary of $215,000. Executive’s annual base salary shall be reviewed by the Compensation Committee of the Board (“Compensation Committee”) on an annual basis, and, in the sole discretion of the Compensation Committee, such annual base salary may be increased, but not decreased (except for a decrease that is consistent with reductions taken generally by other executives of Company), effective as of any date determined by the Compensation Committee. Executive’s annual base salary shall be paid in equal installments in accordance with Company’s standard policy regarding payment of compensation to executives, but no less frequently than monthly.
     3.2 Bonus Opportunity . During the period of this Agreement, Executive shall be provided with the opportunity to earn and receive an annual incentive performance bonus payable in cash in an amount equal to $100,000 (pro-rated for any period of less than 12 months), 20 percent of which shall be conditioned and determined on the attainment of personal performance goals and 80 percent of which shall be conditioned and determined on the attainment of organizational performance goals, in each case as set by, and based on performance criteria established by, the Compensation Committee. The Compensation Committee shall notify Executive of the bonus opportunity by no later than the end of the first 90 days of each annual performance period and shall, at that time, set and communicate to Executive the personal and organizational performance goals on which the bonus (and each component thereof) shall be conditioned and the criteria on which the attainment of such goals and the resulting bonus, if any, shall be determined. All determinations with respect to the bonus hereunder shall be made by the Compensation Committee and its determinations shall be final and binding.
     3.3 Incentive Compensation . Executive shall be eligible to receive awards under the Company’s Long Term Incentive Plan, as determined by the Compensation Committee.
     3.4 Other Perquisites . During his or her employment hereunder, Executive shall be afforded the following benefits as incidences of his or her employment:
     (i) Business and Entertainment Expenses — Subject to Company’s standard policies and procedures with respect to expense reimbursement as applied to its executive employees generally, Company shall reimburse Executive for, or pay on behalf of Executive, reasonable and appropriate expenses incurred by Executive for business related purposes, including dues and fees to industry and professional organizations and costs of entertainment and business development.
     (ii) Vacation — During his or her employment hereunder, Executive shall be entitled to four weeks of paid vacation each calendar year (pro-rated for the calendar year containing the Effective Date) and to all holidays provided to executives of Company generally.
     (iii) Other Company Benefits — Executive and, to the extent applicable, Executive’s spouse, dependents and beneficiaries, shall be allowed to participate in, and in accordance with the terms of, all benefits, plans and programs, including
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improvements or modifications of the same, which are now, or may hereafter be, available to other executive employees of Company. Such benefits, plans and programs shall include, without limitation, any profit sharing plan, thrift plan, health insurance or health care plan, life insurance, disability insurance, pension plan, supplemental retirement plan, vacation and sick leave plan, and the like which may be maintained by Company. Company shall not, however, by reason of this paragraph be obligated to institute, maintain, or refrain from changing, amending, or discontinuing, any such benefit plan or program, so long as such changes are similarly applicable to executive employees generally.
ARTICLE 4: EFFECT OF TERMINATION ON COMPENSATION
     4.1 Payment of Accrued Obligations . Upon termination of Executive’s employment hereunder for any reason and by any means, Executive shall be entitled to, and shall be paid, any annual base salary that is accrued and unpaid as of the date of such termination, which shall be paid on the next regularly scheduled pay day for the payment of Executive’s annual base salary, and any expense reimbursement payable in accordance with paragraph 3.4(i) for reimbursable expenses incurred by Executive prior to the date of such termination, which shall be paid at the time and in the manner provided by Company’s reimbursement policy and in accordance with this Agreement. Other than the foregoing amounts and any Severance Pay pursuant to paragraph 4.3, all compensation and benefits to Executive hereunder shall terminate contemporaneously with the termination of Executive’s employment. Any other benefits to which Executive shall be entitled shall be governed by the plan, policy or agreement providing for such benefits and applicable law.
     4.2 Other Terminations . If Executive’s employment hereunder shall terminate at any time (including, but not limited to, upon or following a change of control of the Company), (i) upon expiration of the term provided in paragraph 2.1 hereof because either party has provided the notice contemplated in such paragraph (except as provided in Section 5.6 hereof), (ii) by Executive for Good Reason and in accordance with the Good Reason Termination Procedure or (iii) by Company other than in any event or circumstance described in paragraph 2.2(i), 2.2(ii), or 2.2(iii), then, subject to paragraph 4.4, Company shall pay Executive an amount equal one times the sum of Executive’s annual base salary at the rate in effect under paragraph 3.1 on the date of such termination, plus one times the amount, if any, paid to Executive under paragraph 3.2 for the calendar year ending immediately prior to the date of such termination of Executive’s employment (the “Severance Amount”), which shall be paid as provided in paragraph 4.3.
     4.3 Severance Payments . Subject to paragraph 4.4 below, the Severance Amount, if any shall be due, shall be divided into amounts (each, a “Severance Payment”) to be paid in installments. The amount of each Severance Payment shall be equal to the Severance Amount divided by the number of regular pay days scheduled (in accordance with Company’s regular payroll practices) to occur between the date of Executive’s termination of employment (“Termination Date”) and the first anniversary of the Termination Date (“Scheduled Paydays”). If any Severance Amount would otherwise be owed under this Agreement, but the requirements of paragraph 4.4 are not satisfied, then no Severance Amount and no amount in lieu of the Severance Amount, shall be owed or paid. If the requirements of paragraph 4.4 are satisfied, then, subject to paragraph 7.14(iv), a portion of the Severance Amount equal to the product of
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one Severance Payment and the number of Scheduled Paydays during the 60-day period beginning on the Termination Date shall be paid in a lump sum amount on the 60 th day following the Termination Date, and the remainder of the Severance Amount shall be paid in regular installments, each one equal to the amount of one Severance Payment, with the first such payment being due on due on the Scheduled Payday immediately following the 60 th day after the Termination Date, with like payments on each Scheduled Payday thereafter until the remaining Severance Amount is paid in full.
     4.4 Release and Full Settlement . Anything to the contrary herein notwithstanding, as a condition to the receipt of any portion of the Severance Amount, Executive shall execute a release, in the form established by the Board, releasing the Board, Company, and Company’s parent corporation, subsidiaries, affiliates, and their respective shareholders, partners, officers, directors, employees, attorneys and agents from any and all claims and from any and all causes of action of any kind or character including, but not limited to, all claims or causes of action arising out of Executive’s employment with Company or its affiliates or the termination of such employment, but excluding all claims to vested benefits and payments Executive may have under any compensation or benefit plan, program or arrangement, including this Agreement. Executive shall provide such release to Company no later than 50 days after the Termination Date and, as a condition to Company’s obligation to pay all or any portion of the Severance Amount, Executive shall not revoke such release. The performance of Company’s obligations hereunder shall constitute full settlement of all such claims and causes of action.
     4.5 No Duty to Mitigate Losses . Executive shall have no duty to find new employment following the termination of his or her employment under circumstances which require Company to pay any amount to Executive pursuant to this Article 4. Any salary or remuneration received by Executive from a third party for the providing of personal services (whether by employment or by functioning as an independent contractor) following the termination of his or her employment under circumstances pursuant to which this Article 4 apply shall not reduce Company’s obligation to make a payment to Executive (or the amount of such payment) pursuant to the terms of this Article 4.
     4.6 Liquidated Damages . In light of the difficulties in estimating the damages for an early termination of Executive’s employment under this Agreement, Company and Executive hereby agree that the payments and benefits, if any, to be received by Executive pursuant to this Article 4 shall be received by Executive as liquidated damages.
     4.7 Other Benefits . This Agreement governs the rights and obligations of Executive and Company with respect to Executive’s base salary, bonus and certain perquisites of employment. Except as expressly provided herein, Executive’s rights and obligations both during the term of his or her employment and thereafter with respect to his or her ownership rights in Company and American Midstream LP, and other benefits under the plans and programs maintained by Company shall be governed by the terms (which are not, and are not required to be, affected, altered or amended) of the separate agreements, plans and the other documents and instruments governing such matters.
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ARTICLE 5: PROTECTION OF CONFIDENTIAL INFORMATION
     5.1 Disclosure to and Property of Company . All information, designs, ideas, concepts, improvements, product developments, discoveries and inventions, whether patentable or not, that are conceived, made, developed or acquired by Executive, individually or in conjunction with others, during the period of Executive’s employment by Company (whether during business hours or otherwise and whether on Company’s premises or otherwise) that relate to Company’s (or any of its affiliates’) business, trade secrets, products or services (including, without limitation, all such information relating to corporate opportunities, product specification, compositions, manufacturing and distribution methods and processes, research, financial and sales data, pricing terms, evaluations, opinions, interpretations, acquisitions prospects, the identity of customers or their requirements, the identity of key contacts within the customer’s organizations or within the organization of acquisition prospects, marketing and merchandising techniques, business plans, computer software or programs, computer software and database technologies, prospective names and marks) (collectively, “Confidential Information”) shall be disclosed to Company and are and shall be the sole and exclusive property of Company (or its affiliates). Moreover, all documents, videotapes, written presentations, brochures, drawings, memoranda, notes, records, files, correspondence, manuals, models, specifications, computer programs, E-mail, voice mail, electronic databases, maps, drawings, architectural renditions, models and all other writings or materials of any type embodying any of such information, ideas, concepts, improvements, discoveries, inventions and other similar forms of expression (collectively, “Work Product”) are and shall be the sole and exclusive property of Company (or its affiliates). Upon Executive’s termination of employment with Company, for any reason, Executive promptly shall deliver such Confidential Information and Work Product, and all copies thereof, to Company.
     5.2 Disclosure to Executive . In reliance upon Executive’s representations and agreements in this Agreement, Company has and will disclose to Executive, and will place Executive in a position to have access to and to develop, Confidential Information and Work Product of Company (or its affiliates); and/or has and will entrust Executive with business opportunities of Company (or its affiliates); and/or has and will place Executive in a position to develop business good will on behalf of Company (or its affiliates). Executive agrees to preserve and protect the confidentiality of all Confidential Information or Work Product of Company (or its affiliates).
     5.3 No Unauthorized Use or Disclosure . Executive agrees that he or she will not, at any time during or after Executive’s employment by Company, make any unauthorized disclosure of, and will prevent the removal from Company premises of, Confidential Information or Work Product of Company (or its affiliates), or make any use thereof, except in the carrying out of Executive’s responsibilities during the course of Executive’s employment with Company. Executive shall use commercially reasonable efforts to cause all persons or entities to whom any Confidential Information shall be disclosed by him or her hereunder to observe the terms and conditions set forth herein as though each such person or entity was bound hereby. Executive shall have no obligation hereunder to keep confidential any Confidential Information if and to the extent disclosure thereof is specifically required by law; provided, however, that in the event disclosure is required by applicable law, Executive shall provide Company with prompt notice of such requirement prior to making any such disclosure, so that Company may seek an appropriate
 7 

 

protective order or otherwise contest such disclosure. At the request of Company at any time, Executive agrees to deliver to Company all Confidential Information that he or she may possess or control. Executive agrees that all Confidential Information of Company (whether now or hereafter existing) conceived, discovered or made by him or her during the period of Executive’s employment by Company exclusively belongs to Company (and not to Executive), and Executive will promptly disclose such Confidential Information to Company and perform all actions reasonably requested by Company to establish and confirm such exclusive ownership. Affiliates of Company shall be third party beneficiaries of Executive’s obligations under this Article 5. As a result of Executive’s employment by Company, Executive may also from time to time have access to, or knowledge of, Confidential Information or Work Product of third parties, such as customers, suppliers, partners, joint venturers, and the like, of Company and its affiliates. Executive also agrees to preserve and protect the confidentiality of such third party Confidential Information and Work Product to the same extent, and on the same basis, as Company’s Confidential Information and Work Product.
     5.4 Ownership by Company . If, during Executive’s employment by Company, Executive creates any work of authorship fixed in any tangible medium of expression that is the subject matter of copyright (such as videotapes, written presentations, or acquisitions, computer programs, E-mail, voice mail, electronic databases, drawings, maps, architectural renditions, models, manuals, brochures, or the like) relating to Company’s business, products, or services, whether such work is created solely by Executive or jointly with others (whether during business hours or otherwise and whether on Company’s premises or otherwise), including any Work Product, Company shall be deemed the author of such work if the work is prepared by Executive in the scope of Executive’s employment; or, if the work is not prepared by Executive within the scope of Executive’s employment but is specially ordered by Company as a contribution to a collective work, as a part of a motion picture or other audiovisual work, as a translation, as a supplementary work, as a compilation, or as an instructional text, then the work shall be considered to be work made for hire and Company shall be the author of the work. If such work is neither prepared by Executive within the scope of Executive’s employment nor a work specially ordered that is deemed to be a work made for hire, then Executive hereby agrees to assign, and by these presents does assign, to Company all of Executive’s worldwide right, title, and interest in and to such work and all rights of copyright therein.
     5.5 Assistance by Executive . During the period of Executive’s employment by Company and thereafter, Executive shall assist Company and its nominee, at any time, in the protection of Company’s (or its affiliates’) worldwide right, title and interest in and to Work Product and the execution of all formal assignment documents requested by Company or its nominee and the execution of all lawful oaths and applications for patents and registration of copyright in the United States and foreign countries.
     5.6 Non-Competition Obligations . Both as part of the consideration for the compensation and benefits to be paid to Executive hereunder; and to protect the trade secrets and Confidential Information of Company and its affiliates that have been or will in the future be disclosed or entrusted to Executive, the business good will of Company and its affiliates that has been and will in the future be developed in Executive, and the business opportunities that have been and will in the future be disclosed or entrusted to Executive by Company and its affiliates; Executive agrees that during the period that Executive is employed by Company and for 12
 8 

 

months after the date of the termination of Executive’s employment with the Company for any reason, Executive shall not, directly or indirectly for Executive or for others, in the geographic areas and markets where Company conducts any business during Executive’s employment with the Company (as identified on Schedule A attached hereto, and amended by the Company from time to time), as well as any other geographic area or market where Company is conducting any business as of the date of termination of the employment relationship:

 	(i)	 	engage in the business of acquiring, developing, improving, managing, providing services with respect to, operating and disposing of mid-stream energy projects, including pipelines, treatment and processing facilities and gas storage fields or any other business that is competitive with the business conducted by Company;	
 		
 	(ii)	 	render any advice or services to, or otherwise assist, any other person, association, or entity who is engaged, directly or indirectly, with any business that is competitive with the business conducted by Company;	
 		
 	(iii)	 	induce any employee of Company or its affiliates to terminate his or her employment with Company or its affiliates, or hire or assist in the hiring of any such employee by any person, association, or entity not affiliated with Company; or	
 		
 	(iv)	 	request or cause any customer of Company or its affiliates to terminate any business relationship with Company or its affiliates.	
Executive understands that the foregoing restrictions may limit Executive’s ability to engage in certain businesses anywhere in the world during the period provided for above, but acknowledges and represents that the restrictions are both reasonable and necessary to protect Company’s legitimate business interests, and that Executive will receive sufficiently high remuneration and other benefits under this Agreement to compensate for and to justify such restrictions. Notwithstanding the foregoing, in the event that the Executive’s employment is terminated upon expiration of the initial or extended term pursuant to Section 2.1 hereof because either party has provided the notice contemplated in such paragraph, the Board may, in its discretion, release the Executive from the covenants contained in this Section 5.6; provided, however, that in such case, the Executive shall not receive the Severance Amount provided in Section 4.2 hereof.
     5.7 Enforcement and Remedies . Executive acknowledges and agrees that money damages would not be sufficient remedy for any breach of this Article 5 by Executive, and Company or its affiliates shall be entitled to enforce the provisions of this Article 5 by terminating payments then owing to Executive under this Agreement or otherwise, by specific performance and injunctive relief as remedies for such breach or any threatened breach. Such remedies shall not be deemed the exclusive remedies for a breach of this Article 5, but shall be in addition to all remedies available at law or in equity, including, without limitation, the recovery of damages from Executive and Executive’s agents involved in such breach and remedies available to Company pursuant to other agreements with Executive.
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     5.8 Reformation . It is expressly understood and agreed that Company and Executive consider the restrictions contained in this Article 5 to be reasonable and necessary to protect the proprietary information of Company and its affiliates. Nevertheless, if any of the aforesaid restrictions are found by a court having jurisdiction to be unreasonable, or overly broad as to geographic area or time, or otherwise unenforceable, the parties intend for the restrictions therein set forth to be modified by such courts so as to be reasonable and enforceable and, as so modified by the court, to be fully enforced.
ARTICLE 6: NONDISPARAGEMENT
     Executive shall refrain, both during the employment relationship and after the employment relationship terminates, from publishing any oral or written statements about Company, its affiliates, or any of such entities’ officers, employees, agents or representatives that (i) are slanderous, libelous, or defamatory; (ii) disclose private or confidential information about Company, its affiliates, or any of such entities’ business affairs, officers, employees, agents, or representatives; (iii) constitute an intrusion into the seclusion or private lives of the officers, employees, agents, or representatives of Company or its affiliates; (iv) give rise to unreasonable publicity about the private lives of the officers, employees, agents, or representatives of Company or its affiliates; (v) place Company, its affiliates, or any of such entities’ officers, employees, agents, or representatives in a false light before the public; or (vi) constitute a misappropriation of the name or likeness of Company, its affiliates, or any of such entities’ officers, employees, agents, or representatives. A violation or threatened violation of this prohibition may be enjoined by the courts. The rights afforded Company and its affiliates under this provision are in addition to any and all rights and remedies otherwise afforded by law.
     Company agrees that, both during Executive’s employment relationship and after the employment relationship terminates, Company, its affiliates, and such entities’ officers, employees, agents or representatives shall refrain from publishing any oral or written statements about Executive that (i) are slanderous, libelous, or defamatory; (ii) disclose private or confidential information about Executive; (iii) that constitute an intrusion into the seclusion or private life of Executive; (iv) give rise to unreasonable publicity about the private life of Executive; (v) place Executive in a false light before the public; or (vi) constitute a misappropriation of the name or likeness of Executive. A violation or threatened violation of this prohibition may be enjoined by the courts. The rights afforded Executive under this provision are in addition to any and all rights and remedies otherwise afforded by law.
     The nondisparagement obligations of this Article 6 shall not apply to communications with law enforcement or required testimony under law or court process.
ARTICLE 7: MISCELLANEOUS
     7.1 Notices . For purposes of this Agreement, notices and all other communications provided for herein shall be in writing and shall be deemed to have been duly given when personally delivered or when mailed by United States registered or certified mail, return receipt requested, postage prepaid, addressed as follows:
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 	 	If to Company to:	 	American Midstream GP, LLC	
 	 	 	 	1614 15th Street	
 	 	 	 	Suite 300 	
 	 	 	 	Denver, CO 80202 	
 	 	 	 	Attention: Chairman of the Board	
 	 	 	 	 	
 	 	with a copy to:	 	American Infrastructure MLP Fund, L.P.	
 	 	 	 	950 Tower Lane	
 	 	 	 	Suite 800 	
 	 	 	 	Foster City, CA 94404 	
 	 	 	 	Attention: Ed Diffendal and Robert B. Hellman, Jr.	
 	 	 	 	 	
 	 	If to Executive to:	 	William B. Mathews	
 	 	 	 	255 Gaylord Street	
 	 	 	 	Denver, CO 80206 	
or to such other address as either party may furnish to the other in writing in accordance herewith, except that notices or changes of address shall be effective only upon receipt.
     7.2 Applicable Law . This Agreement is entered into under, and shall be governed for all purposes by, the laws of the State of Delaware.
     7.3 No Waiver . No failure by either party hereto at any time to give notice of any breach by the other party of, or to require compliance with, any condition or provision of this Agreement shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.
     7.4 Severability . If a court of competent jurisdiction determines that any provision of this Agreement is invalid or unenforceable, then the invalidity or unenforceability of that provision shall not affect the validity or enforceability of any other provision of this Agreement, and all other provisions shall remain in full force and effect.
     7.5 Counterparts . This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same Agreement.
     7.6 Withholding of Taxes and Other Employee Deductions . Company may withhold from any benefits and payments made pursuant to this Agreement or otherwise all federal, state, city and other taxes as may be required pursuant to any law or governmental regulation or ruling and all other normal employee deductions made with respect to Company’s employees generally.
     7.7 Headings . The paragraph headings have been inserted for purposes of convenience and shall not be used for interpretive purposes.
     7.8 Gender and Plurals . Wherever the context so requires, the masculine gender includes the feminine or neuter, and the singular number includes the plural and conversely.
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     7.9 Affiliate . As used in this Agreement, the term “affiliate” shall mean any entity which owns or controls, is owned or controlled by, or is under common ownership or control with, Company.
     7.10 Term . This Agreement has a term co-extensive with the term of employment provided in Article 2. Termination shall not affect any right or obligation of any party which is accrued or vested prior to such termination. The provisions of paragraphs 2.4 and 2.5 and Articles 4, 5, 6, and 7 shall survive any termination of this Agreement.
     7.11 Entire Agreement . Except as provided in (i) the written benefit plans and programs referenced in paragraph 3.4(iii) (and any agreements between Company and Executive that have been executed under such plans and programs) and paragraph 4.7 and (ii) any signed written agreement contemporaneously or hereafter executed by Company and Executive, this Agreement constitutes the entire agreement of the parties with regard to the subject matter hereof, and contains all the covenants, promises, representations, warranties and agreements between the parties with respect to employment of Executive by Company. Without limiting the scope of the preceding sentence, all understandings and agreements preceding the date of execution of this Agreement and relating to the subject matter hereof (other than (A) under the agreements described in clause (i) of the preceding sentence; (B) as provided herein or (C) under the agreements forming and/or operating Company and American Midstream, LP or any investor rights agreement related thereto) are hereby null and void and of no further force and effect. Any modification of this Agreement will be effective only if it is in writing and signed by the party to be charged.
     7.12 Legal Expenses . If Executive incurs legal costs and expenses (including reasonable attorneys’ fees) in any contest relating to rights under this Agreement and prevails in such contest, Company shall reimburse Executive for his or her reasonable legal costs and expenses (including reasonable attorneys’ fees) incurred with respect to such contest.
     7.13 Liability Insurance . Company shall maintain a directors’ and officers’ insurance liability policy throughout the term of this Agreement and shall provide Executive with coverage under such policy on terms not less favorable than provided to other Company directors and officers.
     7.14 Compliance with Section 409A of the Code .
     (i) All references in this Agreement to the termination of Executive’s employment with Company shall mean and shall be deemed to occur if and when a termination of employment that constitutes a “separation from service” within the meaning of Section 409A(a)(2)(A)(i) of the Internal Revenue Code of 1986, as amended (the “Code”), and applicable administrative guidance issued thereunder has occurred.
     (ii) To the extent that any reimbursement or benefit in kind hereunder constituted deferred compensation under Section 409A of the Code, such reimbursement or benefit shall be administered consistently with the following additional requirements as set forth in Treas. Reg. §1.409A-3(i)(1)(iv): (1) Executive’s eligibility for or receipt of benefits or reimbursements in one calendar year will not affect Executive’s eligibility for
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or the amount of benefits or reimbursements in any other calendar year, (2) any reimbursement of eligible expenses will be made on or before the last day of the year following the year in which the expense was incurred, (3) Executive’s right to benefits or reimbursement is not subject to liquidation or exchange for another benefit, and (4) the right to reimbursement of expenses incurred or to the provision of benefits in kind shall terminate ten (10) years from Executive’s termination of employment, if not before.
     (iii) Executive’s right to installment payments, if any, hereunder, shall be treated as the right to receive a series of separate and distinct individual payments for purposes of Section 409A of the Code.
     (iv) Notwithstanding any provision in this Agreement to the contrary, if Executive is a “specified employee” (within the meaning of Section 409A(a)(2)(B)(i) of the Code, and applicable administrative guidance thereunder and determined in accordance with any method selected by Company that is permitted under the regulations issued under Section 409A of the Code), and any amount paid or benefit provided under this Agreement to or on behalf of Executive would be subject to additional taxes under Section 409A of the Code because the timing of such payment is not delayed as provided in Section 409A(a)(2)(B)(i) of the Code and the regulations thereunder, then any such payment or benefit that Executive would otherwise be entitled to during the first six months following the date of Executive’s separation from service (within the meaning of Section 409A(a)(2)(A)(i) of the Code and applicable administrative guidance thereunder) shall be accumulated and paid or provided, as applicable, on the date that is six months plus one day after Executive’s separation from service (or if such date does not fall on a business day of Company, the next following business day of Company), or such earlier date upon which such amount can be paid or provided under Section 409A of the Code without being subject to such additional taxes and interest; provided, however, that Executive shall be entitled to receive the maximum amount permissible under Section 409A of the Code and the applicable administrative guidance thereunder during the six-month period following his or her separation from service that will not result in the imposition of any additional tax or penalties on such amount.
     (v) To the extent that Section 409A of the Code is applicable to this Agreement, the provisions of this Agreement shall be interpreted as necessary to comply with such section and the applicable administrative guidance issued thereunder.
     7.15 Arbitration .
     (i) Company and Executive agree to submit to final and binding arbitration any and all disputes or disagreements concerning the interpretation or application of this Agreement, the termination of this Agreement, or any other aspect of Executive’s employment relationship with Company. Any such dispute or disagreement will be resolved by arbitration in accordance with the National Rules for the Resolution of Employment Disputes of the American Arbitration Association (the “AAA Rules”) before a single arbitrator. Arbitration will take place in Delaware, unless the parties mutually agree to a different location. Company and Executive agree that the decision of the arbitrator will be final and binding on both parties. Any court having jurisdiction may
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enter a judgment upon the award rendered by the arbitrator. The costs of the proceedings shall be borne equally by the parties unless the arbitrator orders otherwise.
     (ii) Notwithstanding the provisions of paragraph 7.15(i), (a) Company may, if it so chooses, bring an action in any court of competent jurisdiction for injunctive relief to enforce Executive’s obligations under Articles 5 or 6 hereof, pending a decision by the arbitrator in accordance with paragraph 7.15(i), and (b) Executive may, if he or she so chooses, bring an action in any court of competent jurisdiction for temporary or preliminary injunctive relief to enforce Company’s obligations under Article 6 hereof, pending a decision by the arbitrator in accordance with paragraph 7.15(i).
     7.16 Provisions Regarding Effective Date . As indicated in this Agreement, this Agreement is effective as of the Effective Date, and accordingly in connection therewith the parties agree that the following shall apply:
     (i) This Agreement shall from and after its execution by the parties be an agreement binding upon and enforceable by both Company and Executive subject to the application of the provisions hereof generally being effective as of the Effective Date.
     (ii) In the event that the employment of Executive by Company terminates at any time prior to the Effective Date, this Agreement shall be null and void and of no force and effect.
     (iii) In the event that the Effective Date does not occur on or before July 31, 2011, this Agreement shall be null and void and of no force and effect.
Signature page follows.
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      IN WITNESS WHEREOF , the parties hereto have executed this Agreement on the 9th day of June, 2011, to be effective as of the Effective Date.

 	 	American Midstream GP, LLC	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Robert B. Hellman, Jr. 	 	 	
 	 	 	 	 
Robert B. Hellman, Jr.,	 	 	
 	 	 	 	Chairman, Compensation Committee	 	 	
 	 	 	 	 	 	 	
 	 	“EXECUTIVE”	 	 	
 	 	 	 	 	 	 	
 	 	 	 	/s/ William B. Mathews 	 	 	
 	 	 	 	 	 	 	
 	 	 	 	William B. Mathews	 	 	
Signature Page to Employment Agreement

 

SCHEDULE A
NONCOMPETITION GEOGRAPHIC AREAS AND SCOPE
Every State of the United States in which the Company does business on the Executive’s date of termination.
All customers of the Company on the Executive’s date of termination.

Exhibit 10.28
AMERICAN MIDSTREAM GP, LLC
AMENDMENT OF GRANT OF PHANTOM UNITS UNDER THE AMERICAN
MIDSTREAM PARTNERS, LP LONG-TERM INCENTIVE PLAN
     This Amendment of Grant of Phantom Units Under the American Midstream Partners, LP Long-Term Incentive Plan (“Amendment”) is entered into between American Midstream GP, LLC (the “Company”) and                      (“Grantee”) and is effective as of the date set forth on the signature page hereto.
      WHEREAS , the Company awarded to Grantee a grant of                      Phantom Units pursuant to the American Midstream Partners, LP Long-Term Incentive Plan (the “Plan”), as evidenced by that Award Agreement dated                                           (the “Award Agreement”, a copy of which is attached hereto as “ Exhibit A” ); and
      WHEREAS , Section 7(b) of the Plan reserves to the Committee the power and authority to amend, with the consent of the Participant in certain cases, any outstanding Award; and
      WHEREAS , the Company and Grantee now desire to amend the Award to Grantee represented by the Award Agreement (the “Award”) to a eliminate the DERs, if any, associated with the Award and to provide for the acceleration of vesting of the unvested Phantom Units under the Award in certain cases relating to a Change of Control of the Company.
      NOW THEREFORE , in consideration of the mutual terms, conditions, and covenants set forth herein, the ongoing employment relationship and compensation to be paid and received in connection therewith, and the payment by the Company to Grantee of an amount determined as if the outstanding unvested Phantom Units were Units in the Partnership for purposes of participating in any distributions of cash as a result of the initial public offering to occur on or about June 30, 2011 (the “Special Payment”), the Company and Grantee agree as follows:

1.	 	Certain Terms . Capitalized terms used, but not defined, herein shall have the meanings assigned to them under the Award Agreement.	
 		
2.	 	Elimination of DERs . Contingent upon receipt of the Special Payment, the Grantee hereby unconditionally and irrevocably relinquishes, waives, forfeits and disclaims any and all DERs, and the Award Agreement shall hereby be amended to remove all references to DERs, if any.	
 		
3.	 	Provision on Other Terminations . Paragraph 3(b) of the Award Agreement shall be redesignated Paragraph 3(c) and shall be amended to read as follows:	

 	“(c)	 	Other Terminations . Except as provided in Paragraph 3(b) above, if your employment with the Company terminates for any reason other than as provided in Paragraph 3(a) above, all unvested Phantom Units then held by you automatically shall be forfeited without payment upon such termination.”	
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4.	 	Effect of Change of Control on Vesting . New Paragraph 3(b) shall be added to the Award Agreement to read as follows:	

 	“(b)	 	Change of Control . Without altering the effect of Paragraph 3(a) above:	

 	(i)	 	In the event of a Change of Control of the Partnership in connection with which the surviving or acquiring entity does not assume and continue the unvested Phantom Units under the Award on the terms and conditions not less favorable than those provided under the Plan and the Award Agreement immediately prior to such Change in Control, the unvested Phantom Units under the Award not previously forfeited shall vest as of the closing date of such Change of Control.	
 		
 	(ii)	 	In the event of a Change of Control of the Partnership to which Paragraph 3(b)(i) above does not apply and in connection with which the unitholders of the Partnership sell or exchange their interests in the Partnership for consideration comprised entirely of cash or a combination of cash and equity interests in the surviving or acquiring entity, then a portion of the then-unvested Phantom Units under the Award not previously forfeited equal to the percentage of all the consideration to such unitholders represented by cash shall vest as of the closing date of such Change of Control.	
 		
 	(iii)	 	In the event of a Change of Control of the Partnership in connection with which some or all of the unvested Phantom Units are not vested pursuant to Paragraph 3(b)(i) or 3(b)(ii) above, if Grantee’s employment with the Company is terminated other than for Cause within one year after the closing date of such Change of Control of the Partnership, or if Grantee is not offered or does not accept employment with the successor or survivor or acquiring entity, any Phantom Units that are then unvested and not previously forfeited shall become fully vested as of the date of such termination of employment. For this purpose, ‘Cause’ shall have the meaning given it in the employment agreement between the Company and Grantee as of the time of such termination, if any, and if no such agreement exists or no such definition is provided thereunder, ‘Cause’ shall mean Grantee has (A) engaged in gross negligence, gross incompetence or willful misconduct in the performance of the duties required of him or her hereunder; (B) refused without proper reason to perform the duties and responsibilities required of him or her hereunder; (C) willfully engaged in conduct that is materially injurious to Company or its affiliates (monetarily or otherwise); (D) committed an act of fraud, embezzlement or willful breach of fiduciary duty to Company or an affiliate (including the unauthorized disclosure of confidential or proprietary material information of Company or an affiliate) or (E) been convicted of (or pleaded no contest to) a crime involving fraud, dishonesty or moral turpitude or any felony.”	
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5.	 	Settlement of Vested Phantom Units . Paragraph 4 of the Award Agreement shall be amended to read in its entirety as follows:	

 	“4.	 	Payment . If vesting of a Phantom Unit shall occur pursuant to Paragraph 2 or 3(a), above, then as soon as administratively practicable after the vesting of such Phantom Unit, but not later than seven days thereafter, you shall be paid a lump sum payment in cash equal to the Fair Market Value of one Unit as of the vesting date in settlement of such Phantom Unit. If vesting of a Phantom Unit shall occur pursuant to Paragraph 3(b), above, then in settlement of such vested Phantom Unit you shall be paid a sum of cash equal to the Fair Market Value of one Unit as of such vesting date, which sum shall be paid in equal installments divided among the remainder (and paid on or as soon as administratively practicable after, but not later than seven days after each) of the first four anniversaries of the Grant Date. Notwithstanding the foregoing, however, the Committee may, in its sole discretion, direct that payment be made to you in the form of one Unit (in lieu of cash) for each vested Phantom Unit. Prior to the consummation of any initial public offering of Units by the Partnership, if the Committee determines, in its sole discretion, to deliver Units in settlement of a vested Phantom Unit(s), you may be required to execute, as a condition of delivery of such Units, a Unitholder’s agreement in a form approved by the Committee (the “Unitholder’s Agreement”). Such Unitholder’s Agreement may contain (i) restrictions on your transfer and sale of such Units, (ii) obligations for you to sell such Units in connection with a sale of interests in the Partnership by the Company, AIM Midstream Holdings, LLC or their respective Affiliates and (iii) such other restrictions and obligations as the Committee determines, in its sole discretion, to impose, all of which will be applicable prior to the consummation of any initial public offering of Units by the Partnership. If you fail to execute such Unitholder’s Agreement within the deadline established by the Committee therefor, the vested Phantom Unit as to which such Unitholder’s Agreement was required will be cancelled without payment of any consideration therefor.”	
Signature Page Follows
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      IN WITNESS WHEREOF , the parties hereto have executed this Agreement on, and to be effective as of, the                      day of                      , 2011.

 	 	American Midstream GP, LLC	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	 	 	 	
 	 	 	 	 
Robert B. Hellman, Jr.,	 	 	
 	 	 	 	Chairman, Compensation Committee	 	 	
 	 	 	 	 	 	 	
 	 	“GRANTEE”	 	 	

 	 			[Name]	 	 	
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EXHIBIT A
[ATTACH GRANT OF PHANTOM UNITS]
 5 

Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the use in this Registration Statement on Form S-1/A of American Midstream Partners, LP of our report dated March 30, 2011 relating to the financial statements of American Midstream Partners, LP, which appears in such Registration Statement. We also consent to the reference to us under the heading “Experts” in such Registration Statement.
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
June 9, 2011

Exhibit 23.2
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the use in this Registration Statement on Form S-1/A of American Midstream Partners, LP (Predecessor) of our report dated March 30, 2011 relating to the financial statements of American Midstream Partners, LP (Predecessor) which appears in such Registration Statement. We also consent to the references to us under the heading “Experts” in such Registration Statement.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
June 9, 2011