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As filed with the Securities and Exchange Commission on May 12, 2011

 Registration No. 333-173191

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

 
 
Amendment No. 1
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 MAY 12, 2011

PRELIMINARY PROSPECTUS

 
           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     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          common units to cover over-allotments.
 
We intend to apply to list our common units on The NASDAQ Stock Market under the symbol “           .”

 
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 our unitholders.	
 		
 	• 	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	

 
 
          , 2011

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[Inside Front Cover Art to Come]

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 	 	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	 	 	32	 	
Tax Risks to Common Unitholders	 	 	40	 	
Use of Proceeds	 	 	45	 	
Capitalization	 	 	47	 	
Dilution	 	 	48	 	
Our Cash Distribution Policy and Restrictions on Distributions	 	 	49	 	
General	 	 	49	 	
Our Minimum Quarterly Distribution	 	 	50	 	
Unaudited Historical As Adjusted Available Cash for the Year Ended December 31, 2010 and the Twelve Months Ended March 31, 2011	 	 	52	 	
Estimated Adjusted EBITDA for the Twelve Months Ending June 30, 2012	 	 	54	 	
Statement of Estimated Adjusted EBITDA	 	 	56	 	
Assumptions and Considerations	 	 	58	 	
Provisions of our Partnership Agreement Relating to Cash Distributions	 	 	64	 	
Distributions of Available Cash	 	 	64	 	
Operating Surplus and Capital Surplus	 	 	65	 	
Capital Expenditures	 	 	67	 	
Subordination Period	 	 	68	 	
Distributions of Available Cash from Operating Surplus during the Subordination Period	 	 	70	 	
Distributions of Available Cash from Operating Surplus after the Subordination Period	 	 	70	 	
General Partner Interest and Incentive Distribution Rights	 	 	70	 	
Percentage Allocations of Available Cash from Operating Surplus	 	 	71	 	
General Partner’s Right to Reset Incentive Distribution Levels	 	 	71	 	
Distributions from Capital Surplus	 	 	74	 	
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels	 	 	75	 	
Distributions of Cash Upon Liquidation	 	 	75	 	
Selected Historical Financial and Operating Data	 	 	78	 	
Non-GAAP Financial Measures	 	 	80	 	
Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	 	82	 	
Overview	 	 	82	 	
Our Operations	 	 	82	 	
How We Evaluate Our Operations	 	 	84	 	
Items Affecting the Comparability of Our Financial Results	 	 	86	 	
General Trends and Outlook	 	 	87	 	

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 	 	Page	
 		
Results of Operations — Combined Overview	 	 	88	 	
Segment Results	 	 	92	 	
Liquidity and Capital Resources	 	 	97	 	
Quantitative and Qualitative Disclosures about Market Risk	 	 	103	 	
Impact of Seasonality	 	 	104	 	
Critical Accounting Policies and Estimates	 	 	105	 	
Industry Overview	 	 	108	 	
General	 	 	108	 	
Midstream Services	 	 	108	 	
Typical Midstream Contractual Arrangements	 	 	109	 	
U.S. Natural Gas Fundamentals	 	 	110	 	
Business	 	 	112	 	
Overview	 	 	112	 	
Business Strategies	 	 	113	 	
Competitive Strengths	 	 	114	 	
Our Sponsor	 	 	115	 	
Our Assets	 	 	116	 	
Gathering and Processing Segment	 	 	117	 	
Transmission Segment	 	 	124	 	
Competition	 	 	129	 	
Safety and Maintenance	 	 	129	 	
Regulation of Operations	 	 	130	 	
Environmental Matters	 	 	135	 	
Title to Properties and Rights-of-Way	 	 	139	 	
Employees	 	 	139	 	
Legal Proceedings	 	 	139	 	
Management	 	 	140	 	
Compensation Discussion and Analysis	 	 	142	 	
Summary Compensation Table for 2010	 	 	150	 	
Grants of Plan-Based Awards for 2010	 	 	150	 	
Outstanding Equity-Based Awards at December 31, 2010	 	 	151	 	
Units Vested in 2010	 	 	152	 	
Long-Term Incentive Plan	 	 	152	 	
Potential Payments Upon Termination or Change in Control	 	 	153	 	
Compensation of Directors	 	 	154	 	
Director Compensation Table for 2010	 	 	155	 	
Compensation Practices as they Relate to Risk Management	 	 	155	 	
Security Ownership of Certain Beneficial Owners and Management	 	 	156	 	
Certain Relationships and Related Party Transactions	 	 	158	 	
Distributions and Payments to our General Partner and its Affiliates	 	 	158	 	
Ownership Interests of Certain Executive Officers and Directors of Our General Partner	 	 	159	 	
Agreements with Affiliates	 	 	159	 	
Procedures for Review, Approval and Ratification of Related-Person Transactions	 	 	160	 	
Conflicts Of Interest and Fiduciary Duties	 	 	162	 	
Conflicts of Interest	 	 	162	 	
Fiduciary Duties	 	 	167	 	
Description of the Common Units	 	 	170	 	
The Units	 	 	170	 	
Transfer Agent and Registrar	 	 	170	 	
Transfer of Common Units	 	 	170	 	
The Partnership Agreement	 	 	172	 	
Organization and Duration	 	 	172	 	

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 	 	Page	
 		
Purpose	 	 	172	 	
Cash Distributions	 	 	172	 	
Capital Contributions	 	 	172	 	
Voting Rights	 	 	173	 	
Limited Liability	 	 	174	 	
Issuance of Additional Securities	 	 	175	 	
Amendment of Our Partnership Agreement	 	 	175	 	
Merger, Sale or Other Disposition of Assets	 	 	177	 	
Termination and Dissolution	 	 	178	 	
Liquidation and Distribution of Proceeds	 	 	178	 	
Withdrawal or Removal of Our General Partner	 	 	178	 	
Transfer of General Partner Interest	 	 	180	 	
Transfer of Ownership Interests in Our General Partner	 	 	180	 	
Transfer of Incentive Distribution Rights	 	 	180	 	
Change of Management Provisions	 	 	180	 	
Limited Call Right	 	 	181	 	
Meetings; Voting	 	 	181	 	
Status as Limited Partner	 	 	182	 	
Non-Citizen Assignees; Redemption	 	 	182	 	
Non-Taxpaying Assignees; Redemption	 	 	182	 	
Indemnification	 	 	183	 	
Reimbursement of Expenses	 	 	183	 	
Books and Reports	 	 	183	 	
Right to Inspect Our Books and Records	 	 	184	 	
Registration Rights	 	 	184	 	
Units Eligible for Future Sale	 	 	185	 	
Material Federal Income Tax Consequences	 	 	186	 	
Partnership Status	 	 	186	 	
Limited Partner Status	 	 	188	 	
Tax Consequences of Unit Ownership	 	 	188	 	
Tax Treatment of Operations	 	 	194	 	
Disposition of Common Units	 	 	195	 	
Uniformity of Units	 	 	197	 	
Tax-Exempt Organizations and Other Investors	 	 	198	 	
Administrative Matters	 	 	199	 	
Recent Legislative Developments	 	 	201	 	
State, Local, Foreign and Other Tax Considerations	 	 	201	 	
Investment in American Midstream Partners, LP by Employee Benefit Plans	 	 	202	 	
Underwriting	 	 	204	 	
Offering Price Determination	 	 	206	 	
Notice to Prospective Investors in the European Economic Area	 	 	206	 	
Notice to Prospective Investors in the Dubai International Financial Centre	 	 	206	 	
Notice to Prospective Investors in the United Kingdom	 	 	207	 	
Notice to Prospective Investors in Germany	 	 	207	 	
Notice to Prospective Investors in the Netherlands	 	 	208	 	
Notice to Prospective Investors in Switzerland	 	 	208	 	
Validity of the Common Units	 	 	209	 	
Experts	 	 	209	 	
Where You Can Find More Information	 	 	209	 	
Forward-Looking Statements	 	 	209	 	
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-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 $      per common unit (the mid-point of the price range set forth on the cover page of this prospectus), (2) unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised, and (3) that the unit split referred to in “Recapitalization Transactions and Partnership Structure” has occurred. You should read “Risk Factors” beginning on page 13 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 under 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% of our general partner. Robert B. Hellman, 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% of the ownership interests in our general partner and will hold     % of our common units and     % of our subordinated units, or an aggregate of     % 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 split into          general partner units, resulting in the ownership by our general partner of an aggregate of           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 split into           common units, resulting in their ownership of an aggregate of           common units, representing an aggregate     % limited partner interest in us;	
 		
 	• 	each outstanding phantom unit granted to participants in our LTIP will automatically split into           phantom units, resulting in their holding an aggregate of          phantom units;	
 		
 	• 	each common unit held by AIM Midstream Holdings will automatically split into          common units, resulting in the ownership by AIM Midstream Holdings of an aggregate of     common units, representing an aggregate     % limited partner interest in us; and	
 		
 	• 	the common units held by AIM Midstream Holdings will automatically convert into     common units and           subordinated units.	

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

			
 	• 	we will issue           common units to the public in this offering;	
 		
 	• 	AIM Midstream Holdings will contribute           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           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	 	 	 	%	
AIM Midstream Holdings Units:	 	 	 	 	
Common Units	 	 	 	%	
Subordinated Units	 	 	 	%	
LTIP Participants Common Units	 	 	 	%	
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, 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% of the ownership interests in our general partner and will hold     % of our common units and 100% of our subordinated units, or an aggregate of     % 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.
 
Our general partner owns           general partner units representing a 2.0% general partner interest in us, which entitles 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 $      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.               .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. 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

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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		          common units.	
 		
		          common units, if the underwriters exercise in full their option to purchase additional common units.	
 		
Units outstanding after this offering		          common units and          subordinated units, each representing a 49.0% limited partner interest in us. Our general partner will own          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 $      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;	

 
			
		• pay offering expenses of approximately $      million;	

 
			
		• terminate, in exchange for a payment of approximately $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 $      million to AIM Midstream Holdings for reimbursement of capital expenditures funded by the initial investment by AIM Midstream Holdings in us.	

			
		We will use the proceeds from borrowings of approximately $      million under our new credit facility to (i) distribute approximately $      million to AIM Midstream Holdings and (ii) pay fees and expenses relating to our new credit facility of approximately $      .	
 		
		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 $      per unit ($      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 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	

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		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 $      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 $     ; and	
 		
		•  third , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $     .	
 		
		If cash distributions to our unitholders exceed $      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 ($      per unit per quarter, or $      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 $      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.	
 		
Conversion of subordinated units		The subordination period will end on the first business day after we have earned and paid at least (i) $      (the minimum quarterly distribution on an annualized basis) on each outstanding common and subordinated unit, as well as the corresponding distribution on	

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		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) $     (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     % 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	
 		
		• 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	

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		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 $      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 NASDAQ Stock Market under the symbol ‘‘          .”	

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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	)	
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(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	 	
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)(4)	 	 	 	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)(5)	 	 	 	12.5	 	 	 	 	11.7	 	 	 	 	11.4	 	 	 	 	9.9	 	 	 	11.1	 	 	 	15.2	 	
Gross NGL production (Mgal/d)(5)	 	 	 	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 $0.4 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)		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.”	

 
			
(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.”	

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

 
			
(5)		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 $      per unit per quarter, or $      per unit on an annualized basis, we will require available cash of approximately $      million per quarter, or $      million per year, based on the number of common and subordinated units 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 $      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     % 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     % 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 53.7% 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 July 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 liquidity. The derivative instruments we utilize for these hedges are based on posted market prices, which may be lower than the actual

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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 16% and 12%, respectively, of our segment gross margin for the year ended December 31, 2010 and approximately 16% and 20%, 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 41%, 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

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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.
 
Our elective processing arrangements are month-to-month, and the loss of these arrangements 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 are generated by processing natural gas under our percent-of-proceeds arrangements with Enterprise Products Partners L.P. at its Toca plant. We refer to these arrangements as our elective processing arrangements. During the year ended December 31, 2010, 7% and 18% 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 elective processing arrangements 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 the 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 transmission pipelines located where a leak or rupture could harm “high consequence areas,” including high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive

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to environmental damage from a pipeline release and commercially navigable waterways, 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;	
 		
 	• 	mistaken assumptions about the overall costs of equity or debt;	

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 	• 	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.
 
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

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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 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

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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.
 
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.

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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 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,

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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 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

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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 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

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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 is likely to be considered in the current session of Congress, either independently or in conjunction with the reauthorization of the Pipeline Safety Act. 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 Pipeline and Hazardous Materials Safety Administration’s announced intention to strengthen its rules. Such legislative and regulatory changes could have a material effect on our operations through more stringent and comprehensive safety regulations and higher penalties for the violation of those regulations.
 
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

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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.
 
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

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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 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.

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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.

 
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 AIM Midstream Holdings’ 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.	

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 	• 	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 $      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.	
 		
 	• 	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.

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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           publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional common units. In addition, AIM Midstream Holdings will own           common and           subordinated units, representing an aggregate     % 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;	
 		
 	• 	future sales of our common units; and	
 		
 	• 	other factors described in these “Risk Factors.”	

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

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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 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;	

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 	• 	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 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.

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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 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     % 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

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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.
 
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 $      per common unit.
 
The estimated initial public offering price of $      per common unit (the midpoint of the range set forth on the cover of this prospectus) exceeds our net tangible book value of $      per unit. Based on the estimated initial public offering price of $      per common unit, you will incur immediate and substantial dilution of $      per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. 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.	

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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           common units and           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     % of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), AIM Midstream Holdings will own approximately     % 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

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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 NASDAQ Stock Market LLC, or the NASDAQ, 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 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.
 
If we are deemed to be an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.
 
Our initial assets will consist of our ownership interests in our operating subsidiaries. If a sufficient amount of our other assets are deemed to be “investment securities,” within the meaning of the Investment Company Act of 1940, or the Investment Company Act, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or contract rights so as to fall outside of the definition of investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property from or to our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business.
 
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.

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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 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

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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.
 
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

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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 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

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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.
 
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 $      million (based upon the mid-point of the price range set forth on the cover page of this prospectus), 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 $      million;	

			
 	• 	terminate, in exchange for a payment of approximately $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 $      million to AIM Midstream Holdings for reimbursement of capital expenditures funded by the initial investment by AIM Midstream Holdings 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 $      under that credit facility. We will use the proceeds from that borrowing to (i) fund a distribution of approximately $      to AIM Midstream Holdings and (ii) pay fees and expenses of approximately $      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	 	$	     	 	 	Repayment of outstanding balance under existing credit facility	 	$	 	 	
Borrowings under new credit facility	 	$	 	 	 	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	 	$	 	 	
 	 	 	 	 	 	Offering expenses payable by us	 	$		 	
 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	 	 	 	Total	 	$		 	

 
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 May 6, 2011, we had approximately $60.2 million of indebtedness outstanding under our existing credit facility. This indebtedness had a weighted average interest rate of 7.4% as of May 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.

Our estimates assume an initial public offering price of $      per common unit (based upon the mid-point of the price range set forth on the cover page of this prospectus) 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 $      million. Any increase or decrease in the initial public offering price will result in a corresponding adjustment to the distribution to AIM Midstream Holdings from the net proceeds of this offering.

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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 $      million from the issuance and sale of           common units to the public at an assumed initial offering price of $      (based upon the mid-point of the price range set forth on the cover page of this prospectus) 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 $           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	 	 	$	     	 	
 	 	 	 	 	 	 	 	 	
Long-Term Debt:	 	 	 	 	 	 	 	 	
Existing credit facility(2)	 	$	56,500	 	 	$	 	 	
New credit facility(3)(4)	 	 	—	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Total long-term debt (including current maturities)	 	$	56,500	 	 	$	 	 	
 	 	 	 	 	 	 	 	 	
Partners’ Capital:	 	 	 	 	 	 	 	 	
Limited partners	 	 	 	 	 	 	 	 	
Common unitholders — public	 	$	—	 	 	$	 	 	
Common unitholders — LTIP participants	 	 	735	 	 	 	 	 	
Common unitholders — AIM Midstream Holdings	 	 	76,176	 	 	 	 	 	
Subordinated unitholders — AIM Midstream Holdings	 	 	—	 	 	 	 	 	
General partner	 	 	1,998	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Total partners’ capital(5)	 	$	78,909	 	 	$		 	
 	 	 	 	 	 	 	 	 	
Total capitalization	 	$	135,409	 	 	$	 	 	

 

			
(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 May 6, 2011, we had $60.2 million of borrowings outstanding under our existing credit facility. This amount does not include $0.6 million of letters of credit that were outstanding under our existing credit facility as of that date.	

 
			
(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     %.	

			
(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 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 $      million, or $      per unit. Net tangible book value excludes $      million of net intangible assets. 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	 	 	 	 	 	$	     	 	
Net tangible book value per unit before the offering(1)	 	$	     	 	 	 	 	 	
Increase in net tangible book value per unit attributable to purchasers in the offering	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Less: Pro forma net tangible book value per unit after the offering(2)	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Immediate dilution in tangible net book value per common unit to purchasers in the offering(3)	 	 	 	 	 	$	 	 	

 

			
(1)		Determined by dividing the number of units (          common units,          subordinated units and           general partner units) held by our general partner and its affiliates, including AIM Midstream Holdings, into the net tangible book value of our assets.	
 		
(2)		Determined by dividing the total number of units to be outstanding after this offering (          common units,          subordinated units and           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 $      and $      , respectively.	
 
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)	 	 	     	 	 	 	     	%	 	$	     	 	 	 		%	
Purchasers in the offering	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	 	 	 	 	100.0	%	 	$	 	 	 	 	100.0	%	

 

			
(1)		The units acquired by our general partner and its affiliates, including AIM Midstream Holdings, consist of           common units,          subordinated units and           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, or not opposed to, 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     % of our outstanding common units and all of our outstanding subordinated units, or     % 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 $      per unit per quarter, or $      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          , 2011. This equates to an aggregate cash distribution of $      million per quarter, or $      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          , 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 $      per unit per quarter ($      per unit on an annualized basis).

 	 	Number of	 	 	 	 	
 	 	Units	 	 	Minimum Quarterly Distributions	 	
 	 	 	 	 	One Quarter	 	 	Annualized	 	
 		
Public Common Units	 	 	 	 	 	$	     	 	 	$	     	 	
AIM Midstream Holdings Units:	 	 	 	 	 	 	 	 	 	 	 	 	
Common Units	 	 	 	 	 	 	 	 	 	 	 	 	
Subordinated Units	 	 	 	 	 	 	 	 	 	 	 	 	
LTIP Participants Common Units	 	 	 	 	 	 	 	 	 	 	 	 	
General Partner Interest	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	       	 	 	$	 	 	 	$	 	 	

 
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 $      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 $           (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 for each quarter in that four-quarter period and the corresponding distribution on our general partner’s 2.0% interest. 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 $      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 NASDAQ; 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)	 	 	 	 	 	 	 	 	
Distributions to public common unitholders(6)	 	 	 	 	 	 	 	 	
Distributions to AIM Midstream Holdings, our general partner and LTIP participants(6)	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Total Distributions	 	$	 	 	 	$	 	 	
 	 	 	 	 	 	 	 	 	
Excess (Shortfall)	 	$	 	 	 	$	 	 	
 	 	 	 	 	 	 	 	 	
Percent of minimum quarterly distributions payable to common unitholders	 	 	 	%	 	 		%	
Percent of minimum quarterly distributions payable to subordinated unitholders	 	 	 	%	 	 		%	

 

 
			
(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 NASDAQ; 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% general partner interest, (ii) we have issued           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 $      per unit per quarter ($      per unit on an annualized basis), as well as the corresponding distribution on our 2.0% general partner interest.	

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 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

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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 $      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 $      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	 	$	295,469	 	
Purchases of natural gas, NGLs and condensate	 	 	251,083	 	
 	 	 	 	 	
Gross margin(1)	 	$	44,386	 	
Operating expenses:	 	 	 	 	
Direct operating expenses	 	 	14,404	 	
Selling, general and administrative expenses(2)	 	 	10,837	 	
Depreciation expense	 	 	20,247	 	
 	 	 	 	 	
Total operating expenses	 	$	45,488	 	
 	 	 	 	 	
Operating income (loss)	 	 	(1,102	)	
Interest expense	 	 	1,526	 	
 	 	 	 	 	
Net income (loss)	 	$	(2,628	)	
Adjustments to reconcile net income to estimated adjusted EBITDA:	 	 	 	 	
Add:	 	 	 	 	
Interest expense	 	 	1,526	 	
Non-cash compensation expense related to our LTIP	 	 	1,600	 	
Depreciation expense	 	 	20,247	 	
 	 	 	 	 	
Estimated adjusted EBITDA(1)	 	$	20,745	 	
Adjustments to reconcile estimated adjusted EBITDA to estimated cash available for distribution:	 	 	 	 	
Less:	 	 	 	 	
Cash interest expense	 	 	979	 	
Estimated maintenance capital expenditures	 	 	3,000	 	
Non-recurring deferred maintenance capital expenditures during forecast period	 	 	2,200	 	
Expansion capital expenditures	 	 	4,955	 	
Add:	 	 	 	 	
Non-cash items(3)	 	 	5	 	
Borrowings to fund expansion capital expenditures	 	 	4,955	 	
Cash from offering proceeds reserved to fund non-recurring deferred maintenance capital expenditures	 	 	2,200	 	
 	 	 	 	 	
Estimated Cash Available for Distribution	 	$	16,771	 	
 	 	 	 	 	
Estimated Annual Cash Distributions	 	 	 	 	
Distributions per unit(4)	 	 	 	 	
Distributions on public common units(4)	 	 	 	 	
Distributions on common units held by AIM Midstream Holdings(4)	 	 	 	 	
Distributions on subordinated units held by AIM Midstream Holdings(4)	 	 	 	 	
Distributions to our general partner(4)	 	 	 	 	
Distributions on common units held by LTIP participants(4)	 	 	 	 	
Total Estimated Annual Distributions	 	$		 	
 	 	 	 	 	
Excess Cash Available for Distributions	 	$		 	
 	 	 	 	 	
Minimum Estimated Adjusted EBITDA	 	$		 	
 	 	 	 	 	
Percent of minimum quarterly distributions payable to common unitholders	 	 	 	%	
Percent of minimum quarterly distributions payable to subordinated unitholders	 	 	 	%	

 

			
(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 NASDAQ, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees and director and officer insurance expenses.	
 		
(3)		Represents estimated non-cash costs associated with our commodity price hedging program and non-cash revenue from our construction, operating and maintenance agreements.	
 		
(4)		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 $      per unit on an annualized basis, as well as the corresponding distribution on our 2.0% general partner interest.	

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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 $4.87 per Mcf, $1.34 per gallon and $2.39 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 February 2, 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 88% 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 $1.5 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 $0.2 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 $0.3 million increase in cash available for distribution. A decrease in forecasted cash flow of greater than $      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 $295.5 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 $251.1 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, $165.0 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 $30.8 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	 	 	$	9.5	 	
Fixed-margin	 	 	4.9	 	 	 	4.8	 	 	 	3.9	 	
Percent-of-proceeds — fee-based	 	 	0.9	 	 	 	1.7	 	 	 	3.2	 	
Percent-of-proceeds — equity	 	 	12.3	 	 	 	13.1	 	 	 	14.2	(1)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	24.6	 	 	$	26.7	 	 	$	30.8	 	

 

 
			
(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 252.8 MMcf/d of natural gas and process an average of 54.4 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	 	 	 	155.6	 	
Fixed-margin	 	 	65.2	 	 	 	63.4	 	 	 	51.9	 	
Percent-of-proceeds — owned plants	 	 	9.9	 	 	 	10.9	 	 	 	17.2	 	
Incremental interconnect volumes(1)	 	 	1.8	 	 	 	6.9	 	 	 	28.1	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total throughput volumes	 	 	175.6	 	 	 	195.1	 	 	 	252.8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Processing Plant Inlet Volumes (MMcf/d):	 	 	 	 	 	 	 	 	 	 	 	 	
Owned plants	 	 	9.9	 	 	 	10.9	 	 	 	17.2	 	
Elective processing arrangements(2)	 	 	26.9	 	 	 	31.8	 	 	 	37.2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total processing inlet volumes	 	 	36.8	 	 	 	42.7	 	 	 	54.4	 	

 

			
(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 9.2 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 $0.17/Mcf and $0.21/Mcf for our fee-based and fixed-margin gathering activities, respectively, and an average fee of $0.50/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)	 	 	51.9	 	 	$	97.9	 	 	$	94.0	 	
Percent-of-proceeds arrangements at owned plants(1):	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas (MMcf/d)	 	 	7.1	 	 	 	12.4	 	 	 	9.7	 	
NGLs (Mgal/d)	 	 	56.4	 	 	 	24.5	 	 	 	18.7	 	
Condensate (Mgal/d)	 	 	6.5	 	 	 	5.5	 	 	 	4.3	 	
Elective processing arrangements(2):	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas (MMcf/d, net)	 	 	24.5	 	 	 	46.4	 	 	 	53.4	 	
NGLs (Mgal/d, net)	 	 	26.5	 	 	 	12.0	 	 	 	—	 	
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 $13.6 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	 	 	 	2.1	 	
Fixed-margin	 	 	0.7	 	 	 	0.9	 	 	 	0.5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	13.5	 	 	$	14.0	 	 	$	13.6	 	

 
Transportation Volumes.   We estimate that we will transport 351.5 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 61.1 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 $0.09/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 $0.08/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 $71.5 million of revenue related to natural gas sales and $71.0 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 $10.2 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 $5.0 million. These expenditures are comprised of four expansion capital projects that we believe we will pursue during the forecast period. We expect that these projects will add over $2.0 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;	

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 	• 	the construction of a new skid-mounted processing plant on the Alabama Processing system in order to serve additional new production at a cost of approximately $1.3 million 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 $3.2 million that we expect to complete in the first quarter of 2012.	
 
Financing

We estimate that interest expense will be approximately $1.5 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 $      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 $21.5 million.	

			
 	• 	We will have average outstanding borrowings of $25.7 million, including borrowings to finance our estimated expansion capital expenditures of $5.0 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 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; and	
 		
 	• 	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 $      per unit, or $      on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including

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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:

 	• 	$      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 $      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 in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities, (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and

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sales or other dispositions of assets as part of ordinary course 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 to our general partner, 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; or	
 		
 	• 	non-pro rata purchases of any class of our units made with the proceeds of an interim capital transaction.	
 
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 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. 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 $      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 $     (the annualized minimum quarterly distribution) 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 $      (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 $      (150.0% of the annualized minimum quarterly distribution) 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) $      (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 $ per unit, 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	
 		
 	• 	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.	

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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.
 
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	

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 	• 	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 $      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 $      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 $      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	 	 	 	 	 	  $	       	 	 	 	98.0	%	 	 	2.0	%	
First Target Distribution	 	 	 	 	 	up to $	       	 	 	 	98.0	%	 	 	2.0	%	
Second Target Distribution	 	above $	 	 	 	up to $	       	 	 	 	85.0	%	 	 	15.0	%	
Third Target Distribution	 	above $	 	 	 	up to $	       	 	 	 	75.0	%	 	 	25.0	%	
Thereafter	 	 	 	 	 	above $	       	 	 	 	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 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

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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 $     .

 	 	 	 	 	 	 	 	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	 	 	 	 	 	     $	     	 	 	 	98.0	%	 	 	2.0	%	 	 	—	 	 	 	 	 	
First Target Distribution	 	 	 	 	 	up to $	     	 	 	 	98.0	%	 	 	2.0	%	 	 	—	 	 	 	 	 	
Second Target Distribution	 	above $	 	 	 	up to $	     	 	 	 	85.0	%	 	 	2.0	%	 	 	13.0	%	 	 	 	 	
Third Target Distribution	 	above $	 	 	 	up to $	     	 	 	 	75.0	%	 	 	2.0	%	 	 	23.0	%	 	 	 	 	
Thereafter	 	 	 	 	 	above $	     	 	 	 	50.0	%	 	 	2.0	%	 	 	48.0	%	 	 	 	 	

 
			
(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           common units outstanding, our general partner has maintained its 2.0% general partner interest and the average distribution to each common unit would be $      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	 	 	 	 	 	     $	  	 	 	$	 	 	 	$	 	 	 	$	 	 	 	$	 	 	 	$	 	 	
First Target Distribution	 	 	 	 	 	up to $	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Second Target Distribution	 	above $	 	 	 	up to $	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Third Target Distribution	 	above $	 	 	 	up to $	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Thereafter	 	 	 	 	 	above $	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	$	     	 	 	$	     	 	 	$	     	 	 	$	     	 	 	$	     	 	

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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 common units outstanding, our general partner’s 2.0% interest has been maintained, and the average distribution to each common unit would be $     . 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 $      , 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 $      .

 	 	 	 	 	 	 	 	 	 	 	Cash Distribution to General Partner	 	 	 	 	
 	 	 	 	 	Cash	 	 	After Reset	 	 	 	 	
 	 	 	 	 	Distributions to	 	 	2.0%	 	 	 	 	 	 	 	 	 	 	
 	 	Quarterly	 	 	Common	 	 	General	 	 	Incentive	 	 	 	 	 	 	 	
 	 	Distribution per	 	 	Unitholders	 	 	Partner	 	 	Distribution	 	 	 	 	 	Total	 	
 	 	Unit After Reset	 	 	After Reset	 	 	Interest	 	 	Rights	 	 	Total	 	 	Distributions	 	
 		
Minimum Quarterly Distribution	 	 	 	 	 	     $	  	 	 	$	 	 	 	$	 	 	 	$	 	 	 	$	 	 	 	$	 	 	
First Target Distribution	 	 	 	 	 	up to $	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Second Target Distribution	 	above $	 	 	 	up to $	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Third Target Distribution	 	above $	 	 	 	up to $	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Thereafter	 	 	 	 	 	above $	  	 	 	$	     	 	 	$	     	 	 	$	     	 	 	$	     	 	 	$	     	 	

 
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	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
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(2)	 	 	$	14,880	 	 	 	$	11,981	 	 	 	$	21,956	 	 	 	$	11,021	 	 	 	$	3,450	 	 	 	$	18,263	 	 	$	5,197	 	 	$	6,914	 	
Gross margin(3)	 	 	 	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)(4)	 	 	 	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)(5)	 	 	 	 	 	 	 	 	 	 	 	 	 	12.5	 	 	 	 	11.7	 	 	 	 	11.4	 	 	 	 	9.9	 	 	 	11.1	 	 	 	15.2	 	
Gross NGL production (Mgal/d)(5)	 	 	 	 	 	 	 	 	 	 	 	 	 	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 0.4 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	

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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.”	

 
			
(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.”	

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

 
			
(5)		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 under 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, under 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 under 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 $0.4 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 NASDAQ; 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 $0.4 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)	 	 	 	 	 	 	 	 	 	 	 	 	$	4.71	 	 	 	$	4.61	 	 	$	5.04	 	 	$	3.99	 	
NGLs ($/gal)	 	 	 	 	 	 	 	 	 	 	 	 	$	1.05	 	 	 	$	1.08	 	 	$	1.13	 	 	$	1.18	 	
Condensate ($/gal)	 	 	 	 	 	 	 	 	 	 	 	 	$	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.

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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 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

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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 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 NYMEX daily settlement price of natural gas in 2010 was $4.39/MMBtu, compared to $4.43/MMBtu and $3.99/MMBtu for the 2009 Successor Period and the 2009 Predecessor Period, respectively. The average NYMEX daily settlement price in 2010 of WTI crude oil, to which NGL prices are generally positively correlated, was $79.52/Bbl, compared to $74.28/Bbl and $58.94/Bbl 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.

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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 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 NYMEX daily settlement price of natural gas was $5.02/MMBtu and $3.99/MMBtu for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $8.90/MMBtu in 2008. The average NYMEX daily settlement price of WTI crude oil, to which NGL prices are generally positively correlated, was $76.30/Bbl and $58.94/Bbl for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $99.65/Bbl 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

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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 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.

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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.	

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

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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 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.	

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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 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 $      per unit, which equates to an aggregate distribution of $      million per quarter, or $      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 $      million revolving credit facility. The new credit facility will mature in          , and borrowings

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will bear interest, at a variable rate per annum equal to the lesser of 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 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 41%, 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 16% and 12%, respectively, of our segment gross margin for the year ended December 31, 2010 and 16% and 20%, 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 $      million, which will be used, together with the net proceeds of this offering, to make a distribution to AIM Midstream Holdings as described in “Use of Proceeds.” We expect the initial interest rate under our new credit facility to be     %.	
 
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 our 2011 hedge transactions, we executed swap and put contracts settled against ethane, propane, butane and natural gasoline market prices. Pursuant to our 2011 hedge transactions, we have hedged approximately 86% of our expected exposure to NGL prices in 2011, and approximately 49% in 2012.
 
In June 2010, prior to our entry into our 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 March 31, 2011:

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Notional	 	 	Weighted Average Price	 	Fair Market Value	 	
 	 	 	 	Volumes	 	 	($/gal)	 	December 31,	 	 	March 31,	 	
Commodity	 	Period	 	(gal/d)	 	 	We Receive	 	 	We Pay	 	2010	 	 	2011	 	
 		
Ethane	 	Feb 2011-Jul 2012	 	 	7,300	 	 	$	0.47	 	 	OPIS avg	 	 	N/A	 	 	$	(418,474	)	
Propane	 	Feb 2011-Jul 2012	 	 	7,050	 	 	$	1.17	 	 	OPIS avg	 	 	N/A	 	 	$	(749,639	)	
Iso-Butane	 	Feb 2011-Jul 2012	 	 	2,510	 	 	$	1.57	 	 	OPIS avg	 	 	N/A	 	 	$	(389,020	)	
Normal Butane	 	Feb 2011-Jul 2012	 	 	3,000	 	 	$	1.59	 	 	OPIS avg	 	 	N/A	 	 	$	(422,769	)	
Natural Gasoline	 	Feb 2011-Jul 2012	 	 	5,500	 	 	$	2.08	 	 	OPIS avg	 	 	N/A	 	 	$	(1,098,925	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	 	 	25,360	 	 	$	1.26	 	 	 	 	 	N/A	 	 	$	(3,078,827	)	

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

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Notional	 	 	Floor Strike	 	 	Fair Market Value	 	
 	 	 	 	Volumes	 	 	Price	 	 	December 31,	 	 	March 31,	 	
Commodity	 	Period	 	(gal/d)	 	 	($/gal)	 	 	2010	 	 	2011	 	
 		
NGL basket(1)	 	Feb 2011-Jul 2012	 	 	9,800	 	 	$	1.29	 	 	 	N/A	 	 	$	173,870	 	
NGL basket(2)	 	Jul 2010-Jun 2011	 	 	13,212	 	 	$	1.03	 	 	$	—	 	 	$	2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	 	 	23,012	 	 	$	1.14	 	 	$	—	 	 	$	173,872	 	

 

			
(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 value of the grants issued were calculated based on a discounted cash flow, or DCF, model. 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 2009 and 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. Therefore, we maintained the $10.00 valuation throughout 2009 and 2010. During 2011, the fair value of the grants issued was calculated by our general partner based on several valuation models, including: a DCF model, a comparable company multiple analysis and a comparable 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 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 valuations were done on a contemporaneous basis.

 
We estimate the IPO price to differ significantly from the fair value of limited partner/common units used to determine the grant date fair value of phantom units. This change is due to the following internal and external factors:

 
			
 	• 	operational achievements completed in the fourth quarter of 2010, including the completion of the Winchester Lateral on our Bazor Ridge system and the TGP Interconnect on our Lafitte system;	

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 	• 	a general recovery in the unit prices of public master limited partnerships; and	

 
			
 	• 	our strong performance in the first quarter of 2011.	

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 July 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 July 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, under 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

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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.

 
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;	
 		
 	• 	the construction of a new skid-mounted processing plant on the Alabama Processing system in order to serve additional new production at a cost of approximately $1.3 million 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 $3.2 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.	

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 	• 	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 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 86% and 49%, 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	

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 		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 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% of our general partner. Robert B. Hellman, 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% of the ownership interests in our general partner and will hold     % of our common units and     % of our subordinated units, or an aggregate of     % 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 through 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 53.7%, 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 an elective processing arrangement we have at the Toca plant. 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

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approximately 60 MMcf/d. 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 for processing natural gas we purchase at the Lafitte/TGP interconnect. We refer to these Toca contracts with Enterprise as our “elective processing arrangements.”

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Please read “Risk Factors — Risks Related to Our Business — Our elective processing arrangements are month-to-month, and the loss of these arrangements 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.
 
We have 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. 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 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

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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 41%, 29% and 10% of its revenue from ConocoPhillips, EMUS and Dow Hydrocarbons and Resources, respectively, and 16% and 17% 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 16% and 20% 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	%	 	 	25	%	 	 	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

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generating facilities supply the Tennessee Valley Authority, or the TVA, with electricity under long-term contractual arrangements between Calpine Corporation and the TVA.

 
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

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nine receipt and 19 delivery points. Due to the numerous interstate pipeline connections and growing supply 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% and 30% of its gross margin from

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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 Pipeline and Hazardous Materials Safety Administration, or PHMSA, of the Department of Transportation, or the DOT, 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, areas unusually sensitive to environmental damage and commercially navigable waterways. 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 is likely to be considered 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.
 
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 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

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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;	
 		
 	• 	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.

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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.
 
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

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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 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

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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 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

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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 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

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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 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

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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.
 
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

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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 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,

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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.
 
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

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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.
 
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 NASDAQ 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 NASDAQ requirements, and a compensation committee of the board of directors, or the Compensation Committee.
 
Even though most companies listed on the NASDAQ are required to have a majority of independent directors serving on the board of directors of the listed company, the NASDAQ 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 and Edward O. Diffendal will serve as the initial members of the Audit Committee. Mr. Moore serves as the chairman of the Audit Committee. In compliance with the rules of the NASDAQ, 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 and L. Kent Moore serve as the members of the Compensation Committee. Robert B. Hellman serves as the chairman of the Compensation Committee.
 
Robert B. Hellman and Matthew P. Carbone serve as the members of the Compliance Committee. Robert B. Hellman 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	 	 	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	

 
Robert B. Hellman 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. Mr. Moore is currently a director of Foothills Energy Ventures, LLC. From 2006 through 2009, Mr. Moore also served as chairman of the board of Foothills. 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.

 
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

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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, 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.
 
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

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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.
 
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

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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.	
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.	

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Element	 	Characteristics	 	Purpose	
 		
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. 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 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
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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.
 
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 employment agreements, are set forth in the table below. Please refer to “— Employment Agreements with Named Executive Officers” below for a description of these 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.
 
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.

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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.	
 
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.
 
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

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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.
 
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 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 “— Employment Agreements with Named Executive Officers.”

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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	 	$	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	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

 

 
			
(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.	
 
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. Each of the employment agreements has an initial term of two years. These employment agreements are each

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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.

 	 	2010 Base	 	 	2010 Target	 	
Name	 	Salary	 	 	Bonus	 	
 		
Brian F. Bierbach	 	$	235,000	 	 	$	65,000	 	
Marty W. Patterson	 	$	190,000	 	 	$	35,000	 	
John J. Connor	 	$	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.
 
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	 	 	$	     	 	
Sandra M. Flower	 	 	51,579	 	 	$	     	 	
Marty W. Patterson	 	 	58,026	 	 	$	     	 	
John J. Connor	 	 	58,026	 	 	$	     	 	
William B. Mathews	 	 	25,789	 	 	$	     	 	

 
			
(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 we assumed was $     , the mid-point of the range of the initial public offering price set forth on the cover page of this prospectus, multiplied by the number of unvested phantom units.	

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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	 	 	$	       	 	
Marty W. Patterson	 	 	19,342	 	 	$	 	 	
John J. Connor	 	 	19,342	 	 	$		 	

 
			
(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 we have assumed was $ , the mid-point of the range of the initial public offering price set forth on the cover page of this prospectus, 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 March 29, 2011, 424,157 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 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.

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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 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.

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The following table shows the value of the severance benefits and other benefits (1) under the employment agreements for the named executive officers who have 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	 	$	 	 	 	 	None	 	 	 	None	 	
Sandra M. Flower	 	Accelerated vesting of phantom	 	$	 	 	 	 	None	 	 	 	None	 	
 	 	units per award agreement	 	 	 	 	 	 	 	 	 	 	 	 	
Marty W. Patterson	 	Lump sum payment per employment agreement	 	 	None	 	 	$	190,000	 	 	$	190,000	 	
 	 	Accelerated vesting of phantom units per award agreement	 	$	 	 	 	 	None	 	 	 	None	 	
John J. Connor	 	Lump sum payment per employment agreement	 	 	None	 	 	$	185,000	 	 	$	185,000	 	
 	 	Accelerated vesting of phantom units per award agreement	 	$	 	 	 	 	None	 	 	 	None	 	
William B. Mathews	 	Accelerated vesting of phantom units per award agreement	 	$	 	 	 	 	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 $      , the mid-point of the range of the initial public offering price set forth on the cover page of this prospectus, multiplied by the number of phantom units that would have vested.	
 
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;	

 
			
 	• 	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.	

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We do not anticipate that Messrs. Moore or Page will participate in the annual phantom unit grant going forward 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.
 
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.	

			
(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, 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          , 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           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)	 	 	     	 	 	 	     	%	 	 	     	 	 	 	     	%	 	 	     	%	
AIM Midstream Holdings, LLC(2)	 	 	 	 	 	 		%	 	 	 	 	 	 		%	 	 		%	
Robert B. Hellman(2)	 	 	 	 	 	 		%	 	 	 	 	 	 		%	 	 		%	
Brian F. Bierbach(3)	 	 	 	 	 	 		%	 	 	 	 	 	 		%	 	 		%	
Matthew P. Carbone(2)	 	 	 	 	 	 		%	 	 	 	 	 	 		%	 	 		%	
Edward O. Diffendal(2)	 	 	 	 	 	 		%	 	 	 	 	 	 		%	 	 		%	
David L. Page(2)	 	 	 	 	 	 		%	 	 	 	 	 	 		%	 	 		%	
L. Kent Moore(3)	 	 	 	 	 	 		%	 	 	 	 	 	 		%	 	 		%	
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)	 	 	 	 	 	 		%	 	 	 	 	 	 		%	 	 		%	

 

			
* 		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           common units and          subordinated units held by AIM Midstream Holdings. AIM Universal Holdings, LLC’s members consist of Robert B. Hellman 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          common units and           subordinated units, representing a combined     % limited partner interest in us (or           common units and           subordinated units, representing a combined     % 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           common units and          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 $      million on its 2.0% general partner interest and AIM Midstream Holdings would receive an annual distribution of approximately $      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, 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 $      per quarter, after the closing of our initial public offering. Upon the closing of this offering, AIM Midstream Holdings will own          common units and           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.
 
Investors’ Rights Agreement
 
On October 30, 2009, AIM Midstream Holdings, AIM Midstream, LLC, American Infrastructure MLP Fund, L.P., American Infrastructure MLP Private Equity Fund, L.P. and American Infrastructure MLP Associates Fund, L.P., or the AIM Parties, and Stockwell Fund II, L.P., or Stockwell, entered into an investors’ rights agreement pursuant to which Stockwell received tag-along rights to sell its limited liability company interests in AIM Midstream Holdings in the event the AIM Parties desire to sell, contract to sell, pledge, transfer, exchange or otherwise dispose of an aggregate of more than 50% of their limited liability company interests in AIM Midstream Holdings to a non-affiliated third party.
 
In addition, the investors’ rights agreement gives Stockwell a limited preemptive right to acquire limited liability company interests in AIM Midstream Holdings at any time AIM Midstream Holdings offers to sell such interests to any AIM Party. In such event, AIM Midstream Holdings is required to offer to sell to Stockwell a prescribed number of limited liability company interests prior to any issuance to the AIM Parties, and Stockwell is entitled to purchase such interests on the same terms and conditions as they are offered to the AIM Party.
 
The rights described above will terminate upon the closing of this offering.
 
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.

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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 $      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 general partner in connection with resetting the target distribution levels related to our general partner’s

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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.	
 		
		Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a	

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		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.
 
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

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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
 
           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.	
 
Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

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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 November 4, 2019 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	 	Except for transfers to an affiliate or to another person as part of our general partner’s merger or consolidation, sale of all or substantially all of its assets or the sale of all of the ownership interests in such holder, the approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to June 30, 2021. Please read “— Transfer of 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
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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 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.

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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.	
 
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     % 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 year 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;	
 		
 	• 	an amendment that our general partner determines to be necessary or appropriate in connection with the authorization of issuance of additional partnership securities or rights to acquire partnership securities;	
 		
 	• 	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.	

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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;	
 		
 	• 	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.

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If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or 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 conversion, 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 conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.
 
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 November 4, 2019, 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

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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 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     % 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.

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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	
 		
 	• 	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 Incentive Distribution Rights
 
Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interest in the holder or the sale of all or substantially all of the holder’s assets to that entity without the prior approval of the unitholders. Prior to June 30, 2021, other transfers of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after June 30, 2021, the incentive distribution rights will be freely transferable.
 
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.
 
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	

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 	• 	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.
 
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

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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
 
If we are or become subject to federal, state, or local laws or regulations that, in the determination of our general partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest based on the nationality, citizenship or other related status of any limited partner or assignee, our general partner may request any limited partner or assignee to furnish to the general partner an executed citizenship certification or such other information about his nationality, citizenship or related status. If a limited partner fails to furnish such citizenship certification or other requested information about his nationality, citizenship or other related status within 30 days after a request for such citizenship certification or other requested information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.
 
Furthermore, we have the right to redeem all of the common and subordinated units of any holder that our general partner concludes is not an eligible citizen or fails to furnish the information requested by our general partner. The redemption price in the event of such redemption for each unit held by such unitholder will be the lesser of (i) the current market price (the date of determination of which shall be the date fixed for redemption) and (ii) the price paid for each such unit by the unitholder. The redemption price will be paid, as determined by our general partner, in cash or by delivery of a promissory note. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.
 
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 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.	

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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.
 
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.

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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 partner;	
 		
 	• 	a copy of our federal, state and local income tax returns;	
 		
 	• 	true and full information as to the amount of cash, and a description and statement of the net agreed value of any other capital contribution by each partner and that each partner has agreed to contribute in the future, and the date on which each became a partner;	
 		
 	• 	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           common units and           subordinated units (or           common units and           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;
 
(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

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(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	 	 	          	 	 	
 	 	 	 	 		
Total	 	 	 	 	 	

 
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           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 Nasdaq Global Market under the symbol ‘‘     .”

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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     % 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 $.
 
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 Nasdaq Global Market, 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.
 
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.

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 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

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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 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.

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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.          .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-19	 	
Consolidated Balance Sheets	 	 	F-20	 	
Consolidated Statements of Operations	 	 	F-21	 	
Consolidated Statements of Changes in Partners’ Capital	 	 	F-22	 	
Consolidated Statements of Cash Flows	 	 	F-23	 	
Notes to Consolidated Financial Statements	 	 	F-24	 	
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-49	 	
Combined Balance Sheets	 	 	F-50	 	
Combined Statements of Operations	 	 	F-51	 	
Combined Statements of Group Equity	 	 	F-52	 	
Combined Statements of Cash Flows	 	 	F-53	 	
Notes to Combined Financial Statements	 	 	F-54	 	

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

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

 
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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Table of Contents

 
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.

 
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

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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)

 
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.

 
		
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

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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)

 
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, 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

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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)

 
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 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	 	

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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)

 
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).

 	 	 	 	 	 	 	 	 	
 	 	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	 	

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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)

 
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.

 
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.

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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 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 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.

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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)

 
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.

 
		
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).

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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)

 
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.

 
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	 	

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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)

 
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.

 
		
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.

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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 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	)	

 

 	 	 	 	 	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.

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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)

 
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.

 
		
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.

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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)

 
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(1)	 	 	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(1)	 	 	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	)	

 

 
			
(1)		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.	

 
		
14.  	Subsequent Events	

 
The Partnership has evaluated subsequent events through May 13, 2011:

 
On May 4, 2011, the Board of Directors of our general partner approved a distribution in the amount of $3.8 million, consisting of $3.6 million to the limited partners and $0.1 million to the general partner and $0.1 million in DER payments.

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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

F-19

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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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

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.
 
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 at market prices. Where we provide processing services at the processing plants that we own, or obtain

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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)
 
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.
 
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.
 
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.
 
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.
 
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.

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

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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)
 
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 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;	

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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)

			
 	• 	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 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

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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)
 
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 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.

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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 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.
 
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	

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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)

 		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, 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,

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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)
 
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
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

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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 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.
 
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.

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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)

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 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

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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)
 
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).

 	 	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	 	 	$	—	 	

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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)

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.
 
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.

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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)

 	 	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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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)
 
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(1)	 	 	76.7	%	 	 	70.7	%	
Cash and short-term assets(2)	 	 	23.3	%	 	 	29.3	%	
 	 	 	 	 	 	 	 	 	
Total	 	 	100.0	%	 	 	100.0	%	

 
			
(1)		United States government securities, municipal corporate bonds and notes and as set backed securities.	
 		
(2)		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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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(1)	 	 	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(1)	 	 	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	)	

 
			
(1)		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(1)	 	 	77.0%	 	 	 	77.0%	 	
Cash and short-term assets(2)	 	 	23.0%	 	 	 	23.0%	 	
 	 	 	 	 	 	 	 	 	
 	 	 	100.0%	 	 	 	100.0%	 	

 

			
(1)		United States government securities, corporate bonds and notes and asset-backed securities.	
 		
(2)		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

 To be provided by amendment.

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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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           Common Units
 
American Midstream Partners, LP
 
Common Units
Representing Limited Partner Interests

 

 
PRELIMINARY PROSPECTUS
 
          , 2011

 
 
Citi
 
BofA Merrill Lynch

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.

Table of Contents
PART II
 
INFORMATION NOT REQUIRED IN 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 NASDAQ listing fee, the amounts set forth below are estimates.

SEC registration fee	 	$	8,708	 	
FINRA filing fee	 	 	8,000	 	
NASDAQ listing fee	 	 	*	 	
Printing and engraving expenses	 	 	*	 	
Fees and expenses of legal counsel	 	 	*	 	
Accounting fees and expenses	 	 	*	 	
Transfer agent and registrar fees	 	 	*	 	
Miscellaneous	 	 	*	 	
 	 	 	 	 	
Total	 	 	*	 	

 

			
*		To be filed by amendment.	

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);	

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 	• 	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;	
 		
 	• 	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 Statement Schedules.	
 
The following documents are filed as exhibits to this registration statement:

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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	
 	3	.4**	 	Certificate of Formation of American Midstream GP, LLC	
 	3	.5**	 	Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC	
 	3	.6*	 	Form of Second Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC	
 	5	.1*	 	Opinion of Andrews Kurth LLP as to the legality of the securities being registered	
 	8	.1*	 	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*	 	Advisory Services Agreement, dated as of October 2, 2009, by and between American Midstream, LLC, American Infrastructure MLP Management, L.L.C., American Infrastructure MLP PE Management, L.L.C. and American Infrastructure MLP Associates Management, L.L.C.	
 	10	.5*	 	Investors’ Rights Agreement, dated as of October 30, 2009, by and among AIM Midstream Holdings, LLC AIM Midstream LLC, American Infrastructure MLP Fund, L.P., American Infrastructure MLP Private Equity Fund, L.P., American Infrastructure MLP Associates Fund and Stockwell Fund II, L.P.	
 	10	.6*	 	Employment Agreement, dated November 2, 2009, by and between American Midstream GP, LLC and Brian Bierbach.	
 	10	.7*	 	Employment Agreement, dated November 2, 2009, by and between American Midstream GP, LLC and Marty W. Patterson.	
 	10	.8*	 	Employment Agreement, dated November 2, 2009, by and between American Midstream GP, LLC and John J. Connor.	
 	10	.9*	 	Amended and Restated American Midstream GP, LLC Long-Term Incentive Plan	
 	10	.10*	 	Form of Phantom Unit Grant under American Midstream GP, LLC Long-Term Incentive Plan.	
 	10	.11*	 	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	.12*	 	Gas Processing Agreement, dated July 1, 2010, by and between American Midstream, LLC and Enterprise Gas Processing, LLC.	

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Number	 	Description	
 		
 	10	.13*	 	Gas Processing Agreement, dated November 1, 2010, by and between American Midstream, LLC and Enterprise Gas Processing, LLC.	
 	21	.1**	 	List of Subsidiaries of American Midstream Partners, LP	
 	23	.1	 	Consent of PricewaterhouseCoopers LLP	
 	23	.2	 	Consent of PricewaterhouseCoopers LLP	
 	23	.3*	 	Consent of Andrews Kurth LLP (contained in Exhibit 5.1)	
 	23	.4*	 	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.	

		
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 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.

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(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.

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SIGNATURES

Pursuant 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 May 12, 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	

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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	 	May 12, 2011	
 	 	 	 	 	
*

Sandra M. Flower	 	Vice President of Finance
(Principal Financial Officer and Principal Accounting Officer)	 	May 12, 2011	
 	 	 	 	 	
*

Robert B. Hellman	 	Director	 	May 12, 2011	
 	 	 	 	 	
*

Matthew P. Carbone	 	Director	 	May 12, 2011	
 	 	 	 	 	
*

Edward O. Diffendal	 	Director	 	May 12, 2011	
 	 	 	 	 	
*

L. Kent Moore	 	Director	 	May 12, 2011	
 	 	 	 	 	
*

David L. Page	 	Director	 	May 12, 2011	
 	 	 	 	 	 	 	
*By	 	/s/   Brian F. Bierbach

Brian F. Bierbach
Attorney-in-Fact	 	 	 	 	

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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	
 	3	.4**	 	Certificate of Formation of American Midstream GP, LLC	
 	3	.5**	 	Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC	
 	3	.6*	 	Form of Second Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC	
 	5	.1*	 	Opinion of Andrews Kurth LLP as to the legality of the securities being registered	
 	8	.1*	 	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*	 	Advisory Services Agreement, dated as of October 2, 2009, by and between American Midstream, LLC, American Infrastructure MLP Management, L.L.C., American Infrastructure MLP PE Management, L.L.C. and American Infrastructure MLP Associates Management, L.L.C.	
 	10	.5*	 	Investors’ Rights Agreement, dated as of October 30, 2009, by and among AIM Midstream Holdings, LLC AIM Midstream LLC, American Infrastructure MLP Fund, L.P., American Infrastructure MLP Private Equity Fund, L.P., American Infrastructure MLP Associates Fund and Stockwell Fund II, L.P.	
 	10	.6*	 	Employment Agreement, dated November 2, 2009, by and between American Midstream GP, LLC and Brian Bierbach.	
 	10	.7*	 	Employment Agreement, dated November 2, 2009, by and between American Midstream GP, LLC and Marty W. Patterson.	
 	10	.8*	 	Employment Agreement, dated November 2, 2009, by and between American Midstream GP, LLC and John J. Connor.	
 	10	.9*	 	Amended and Restated American Midstream GP, LLC Long-Term Incentive Plan	
 	10	.10*	 	Form of Phantom Unit Grant under American Midstream GP, LLC Long-Term Incentive Plan.	
 	10	.11*	 	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	.12*	 	Gas Processing Agreement, dated July 1, 2010, by and between American Midstream, LLC and Enterprise Gas Processing, LLC.	
 	10	.13*	 	Gas Processing Agreement, dated November 1, 2010, by and between American Midstream, LLC and Enterprise Gas Processing, LLC.	

Table of Contents

 	 	 	 	 	
Number	 	Description	
 		
 	21	.1**	 	List of Subsidiaries of American Midstream Partners, LP	
 	23	.1	 	Consent of PricewaterhouseCoopers LLP	
 	23	.2	 	Consent of PricewaterhouseCoopers LLP	
 	23	.3*	 	Consent of Andrews Kurth LLP (contained in Exhibit 5.1)	
 	23	.4*	 	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.	

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
May 12, 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
May 12, 2011