AMERICAN MIDSTREAM PARTNERS, LP, 10-K filed on 4/16/2013
Annual Report
Document and Entity Information (USD $)
In Thousands, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Jun. 30, 2012
Mar. 12, 2013
Limited Partner Common Units
Mar. 12, 2013
Limited Partner Subordinated Units
Entity Registrant Name
American Midstream Partners, LP 
 
 
 
Entity Central Index Key
0001513965 
 
 
 
Document Type
10-K 
 
 
 
Document Period End Date
Dec. 31, 2012 
 
 
 
Amendment Flag
false 
 
 
 
Document Fiscal Year Focus
2012 
 
 
 
Document Fiscal Period Focus
FY 
 
 
 
Current Fiscal Year End Date
--12-31 
 
 
 
Entity Well-known Seasoned Issuer
No 
 
 
 
Entity Voluntary Filers
No 
 
 
 
Entity Current Reporting Status
Yes 
 
 
 
Entity Filer Category
Non-accelerated Filer 
 
 
 
Entity Public Float
 
$ 0 
 
 
Entity Common Stock, Shares Outstanding
 
 
4,645,453 
4,526,066 
Consolidated Balance Sheets (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Current assets
 
 
Cash and cash equivalents
$ 576 
$ 871 
Accounts receivable
1,958 
1,218 
Unbilled revenue
21,512 
19,745 
Risk management assets
969 
0 
Other current assets
3,226 
3,323 
Total current assets
28,241 
25,157 
Property, plant and equipment, net
223,819 
170,231 
Other assets, net
4,636 
3,707 
Total assets
256,696 
199,095 
Current liabilities
 
 
Accounts payable
5,527 
837 
Accrued gas purchases
17,034 
14,715 
Risk management liabilities
0 
179 
Accrued expenses and other current liabilities
9,619 
7,086 
Total current liabilities
32,180 
22,817 
Other liabilities
8,628 
8,612 
Long-term debt
128,285 
66,270 
Total liabilities
169,093 
97,699 
Commitments and contingencies (see Note 16)
   
   
Partners’ capital and noncontrolling interest
 
 
General partner interest (185 and 185 thousand units issued and outstanding as of December 31, 2012 and 2011, respectively)
548 
1,091 
Limited partner interest (9,165 and 9,087 thousand units issued and outstanding as of December 31, 2012 and 2011, respectively)
79,266 
99,890 
Accumulated other comprehensive income
351 
415 
Total partners’ capital
80,165 
101,396 
Noncontrolling interest
7,438 
0 
Total equity
87,603 
101,396 
Total liabilities and equity
$ 256,696 
$ 199,095 
Consolidated Balance Sheets (Parenthetical)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Statement of Financial Position [Abstract]
 
 
General partner interest, units issued
185 
185 
General partner interest units, outstanding
185 
185 
Limited partners, units issued
9,165 
9,087 
Limited partner common units, outstanding
9,165 
9,087 
Consolidated Statements of Operations (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Income Statement [Abstract]
 
 
 
Revenue
$ 209,594 
$ 248,282 
$ 212,248 
Realized gain (loss) on early termination of commodity derivatives
0 1
(2,998)1
0 1
Unrealized gain (loss) on commodity derivatives
992 
(541)
(308)
Total revenue
210,586 2
244,743 2
211,940 
Operating expenses:
 
 
 
Purchases of natural gas, NGLs and condensate
155,667 
202,403 
173,821 
Direct operating expenses
18,202 
12,856 
12,187 
Selling, general and administrative expenses
14,309 
10,794 
7,120 
Advisory services agreement termination fee
0 
2,500 
0 
Transaction expenses
0 
282 
303 
Equity compensation expense
1,783 
3,357 
1,734 
Depreciation and accretion expense
21,414 
20,705 
20,013 
Total operating expenses
211,375 
252,897 
215,178 
Gain (loss) on acquisition of assets
0 
565 
0 
Gain (loss) on involuntary conversion of property, plant and equipment
(1,021)
0 
0 
Gain (loss) on sale of assets, net
128 
399 
0 
Operating income (loss)
(1,682)2
(7,190)2
(3,238)
Other income (expenses):
 
 
 
Interest expense
(4,570)
(4,508)
(5,406)
Net income (loss)
(6,252)2
(11,698)
(8,644)
Net income (loss) attributable to noncontrolling interests
256 2
0 
0 
Net income (loss) attributable to the Partnership
(6,508)2
(11,698)2
(8,644)
General partner's interest in net income (loss)
(129)2
(233)2
(173)
Limited partners’ interest in net income (loss)
$ (6,379)2
$ (11,465)2
$ (8,471)
Limited partners’ net income (loss) per unit (basic and diluted)
(0.70)2
(1.64)2
(1.66)
Weighted average number of units used in computation of limited partners’ net income (loss) per unit (basic and diluted)
9,113 3 4
6,997 3 4
5,099 3 4
[2] During the fourth quarter, we identified revenues in the amount of $0.3 million associated with proceeds received in connection with COMA reimbursable projects that were incorrectly recognized in the first quarter of 2012 that should have been recognized ratably during each of the succeeding quarters of 2012 for approximately $0.1 million per quarter. In addition, we recorded in the first quarter of 2012 and for the year ended December 31, 2012 out-of-period adjustments amounting to $0.1 million for the correction of immaterial errors associated with additional depreciation expense and selling, general and administrative expense. Based upon our evaluation of relevant factors, we concluded that these errors were not material to any previously issued and current consolidated financial statements.(b)For a definition of gross margin and a reconciliation to its mostly directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 19, "Reporting Segments".
Consolidated Statements of Comprehensive Income (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Statement of Other Comprehensive Income [Abstract]
 
 
 
Net income (loss)
$ (6,252)1
$ (11,698)
$ (8,644)
Unrealized gain (loss) on post retirement benefit plan assets and liabilities
(64)
359 
10 
Comprehensive income (loss)
(6,316)
(11,339)
(8,634)
Less: Comprehensive income (loss) attributable to noncontrolling interests
256 1
0 
0 
Comprehensive income attributable to Partnership
$ (6,572)
$ (11,339)
$ (8,634)
[1] During the fourth quarter, we identified revenues in the amount of $0.3 million associated with proceeds received in connection with COMA reimbursable projects that were incorrectly recognized in the first quarter of 2012 that should have been recognized ratably during each of the succeeding quarters of 2012 for approximately $0.1 million per quarter. In addition, we recorded in the first quarter of 2012 and for the year ended December 31, 2012 out-of-period adjustments amounting to $0.1 million for the correction of immaterial errors associated with additional depreciation expense and selling, general and administrative expense. Based upon our evaluation of relevant factors, we concluded that these errors were not material to any previously issued and current consolidated financial statements.(b)For a definition of gross margin and a reconciliation to its mostly directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 19, "Reporting Segments".
Consolidated Statements of Changes in Partners' Capital and Noncontrolling Interest (USD $)
Total
USD ($)
Limited Partner Common Units
Limited Partner Subordinated Units
Limited Partner Interest
USD ($)
General Partner Units
General Partner Interest
USD ($)
Accumulated Other Comprehensive Income
USD ($)
Total Partners Capital
USD ($)
Noncontrolling Interest
USD ($)
Beginning Balance at Dec. 31, 2009
 
 
 
$ 91,148,000 
 
$ 2,010,000 
$ 46,000 
$ 93,204,000 
$ 0 
Balance, shares at Dec. 31, 2009
 
4,756,000 
0 
 
97,000 
 
 
 
 
Net income (loss)
(8,644,000)
 
 
(8,471,000)
 
(173,000)
0 
(8,644,000)
0 
Unitholder contributions, shares
 
571,000 
0 
 
12,000 
 
 
 
 
Unit holder contributions
 
 
 
11,760,000 
 
240,000 
0 
12,000,000 
0 
Issuance of common units to public, net of offering costs
0 
 
 
 
 
 
 
 
 
Unit holder distributions
 
 
 
(11,545,000)
 
(234,000)
0 
(11,779,000)
0 
Net distributions to noncontrolling owners
0 
 
 
 
 
 
 
 
 
LTIP vesting, shares
 
44,000 
0 
 
0 
 
 
 
 
LTIP vesting
 
 
 
903,000 
 
(903,000)
0 
0 
0 
Tax netting repurchase, shares
 
(8,000)
0 
 
0 
 
 
 
 
Tax netting repurchase
 
 
 
(171,000)
 
0 
0 
(171,000)
0 
Unit based compensation, shares
43,809,000 
 
 
 
 
 
 
 
 
Unit based compensation
 
 
 
0 
 
1,184,000 
0 
1,184,000 
0 
Other comprehensive income (loss)
0 
 
 
 
 
0 
10,000 
10,000 
0 
Ending Balance at Dec. 31, 2010
 
 
 
83,624,000 
 
2,124,000 
56,000 
85,804,000 
0 
Balance, shares at Dec. 31, 2010
 
5,363,000 
0 
 
109,000 
 
 
 
 
Net income (loss)
(11,698,000)1
 
 
(11,465,000)
 
(233,000)
0 
(11,698,000)
0 
Recapitalization, shares
 
(4,602,000)
4,526,000 
 
76,000 
 
 
 
 
Recapitalization
0 
 
 
 
 
0 
0 
0 
0 
Issuance of common units to public, net of offering costs, shares
 
3,750,000 
0 
 
0 
 
 
 
 
Issuance of common units to public, net of offering costs
69,085,000 
 
 
69,085,000 
 
0 
0 
69,085,000 
0 
Unit holder distributions
 
 
 
(42,682,000)
 
(864,000)
0 
(43,546,000)
0 
Net distributions to noncontrolling owners
0 
 
 
 
 
 
 
 
 
LTIP vesting, shares
 
62,000 
0 
 
0 
 
 
 
 
LTIP vesting
 
 
 
1,286,000 
 
(1,286,000)
0 
0 
0 
Tax netting repurchase, shares
 
(12,000)
0 
 
0 
 
 
 
 
Tax netting repurchase
(215,000)
 
 
 
 
0 
0 
(215,000)
 
Unit based compensation, shares
62,418,000 
 
 
 
 
 
 
 
 
Unit based compensation
 
 
 
257,000 
 
1,350,000 
0 
1,607,000 
0 
Other comprehensive income (loss)
 
 
 
0 
 
0 
359,000 
359,000 
0 
Ending Balance at Dec. 31, 2011
101,396,000 
 
 
99,890,000 
 
1,091,000 
415,000 
101,396,000 
0 
Balance, shares at Dec. 31, 2011
 
4,561,000 
4,526,000 
 
185,000 
 
 
 
 
Acquisition of noncontrolling interest
0 
 
 
 
 
0 
0 
0 
7,407,000 
Net income (loss)
(6,508,000)1
 
 
(6,379,000)
 
(129,000)
0 
(6,508,000)
256,000 
Unitholder contributions, shares
76,019 
 
 
 
 
 
 
 
 
Unit holder contributions
 
 
 
0 
 
13,000 
0 
13,000 
0 
Issuance of common units to public, net of offering costs
0 
 
 
 
 
 
 
 
 
Unit holder distributions
 
 
 
(15,748,000)
 
(322,000)
0 
(16,070,000)
0 
Net distributions to noncontrolling owners
(256,000)1
 
 
0 
 
0 
0 
0 
(225,000)
LTIP vesting, shares
 
98,000 
0 
 
0 
 
 
 
 
LTIP vesting
 
 
 
1,888,000 
 
(1,888,000)
0 
0 
0 
Tax netting repurchase, shares
 
(20,000)
0 
 
0 
 
 
 
 
Tax netting repurchase
 
 
 
(385,000)
 
0 
0 
(385,000)
0 
Unit based compensation, shares
98,000,000 
0 
0 
 
0 
 
 
 
 
Unit based compensation
 
 
 
0 
 
1,783,000 
0 
1,783,000 
0 
Other comprehensive income (loss)
 
 
 
0 
 
0 
(64,000)
(64,000)
0 
Ending Balance at Dec. 31, 2012
$ 80,165,000 
 
 
$ 79,266,000 
 
$ 548,000 
$ 351,000 
$ 80,165,000 
$ 7,438,000 
Balance, shares at Dec. 31, 2012
 
4,639,000 
4,526,000 
 
185,000 
 
 
 
 
[1] During the fourth quarter, we identified revenues in the amount of $0.3 million associated with proceeds received in connection with COMA reimbursable projects that were incorrectly recognized in the first quarter of 2012 that should have been recognized ratably during each of the succeeding quarters of 2012 for approximately $0.1 million per quarter. In addition, we recorded in the first quarter of 2012 and for the year ended December 31, 2012 out-of-period adjustments amounting to $0.1 million for the correction of immaterial errors associated with additional depreciation expense and selling, general and administrative expense. Based upon our evaluation of relevant factors, we concluded that these errors were not material to any previously issued and current consolidated financial statements.(b)For a definition of gross margin and a reconciliation to its mostly directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 19, "Reporting Segments".
Consolidated Statements of Cash Flows (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Statement of Cash Flows [Abstract]
 
 
 
Net income (loss)
$ (6,252)1
$ (11,698)
$ (8,644)
Adjustments to reconcile net income (loss) to net cash provided (used) in operating activities:
 
 
 
Depreciation and accretion expense
21,414 
20,705 
20,013 
Amortization of deferred financing costs
716 
1,262 
807 
Unrealized (gain) loss on commodity derivatives
(992)
849 
385 
Unit based compensation
1,783 
1,607 
1,185 
OPEB plan net periodic (benefit) cost
(88)
(82)
   
(Gain) loss on acquisition of assets
0 
(565)
0 
(Gain) loss on involuntary conversion of property, plant and equipment
1,021 
0 
0 
(Gain) loss on sale of assets, net
(128)
(399)
0 
Changes in operating assets and liabilities, net of effects of assets acquired and liabilities:
 
 
 
Accounts receivable
(740)
(562)
791 
Unbilled revenue
2,768 
2,449 
(3,865)
Risk management assets and liabilities
(156)
(670)
(308)
Other current assets
984 
(1,800)
0 
Other assets, net
(57)
(54)
(104)
Accounts payable
1,197 
(218)
(954)
Accrued gas purchases
(1,711)
(3,991)
3,825 
Accrued expenses and other current liabilities
(943)
4,410 
268 
Other liabilities
(468)
(811)
392 
Net cash provided (used) in operating activities
18,348 
10,432 
13,791 
Cash flows from investing activities
 
 
 
Cost of acquisition, net of cash acquired
(51,377)
(35,500)
0 
Additions to property, plant and equipment
(11,705)
(6,369)
(10,268)
Proceeds from disposals of property, plant and equipment
128 
125 
   
Insurance proceeds from involuntary conversion of property, plant and equipment
527 
0 
0 
Net cash provided (used) in investing activities
(62,427)
(41,744)
(10,268)
Cash flows from financing activities
 
 
 
Unit holder contributions
13 
   
12,000 
Unit holder distributions
(16,070)
(43,546)
(11,779)
Net distributions to noncontrolling interest owners
(225)
0 
0 
Proceeds upon issuance of common units to public, net of offering costs
0 
69,085 
0 
LTIP tax netting unit repurchase
(385)
(215)
0 
Payment on other loan
0 
(615)
(1,000)
Payments for deferred debt issuance costs
(1,564)
(2,489)
0 
Borrowings on other loan
0 
0 
800 
Payments on long-term debt
(59,230)
(120,670)
(31,130)
Borrowings on long-term debt
121,245 
130,570 
26,500 
Net cash provided (used) in financing activities
43,784 
32,120 
(4,609)
Net increase (decrease) in cash and cash equivalents
(295)
808 
(1,086)
Cash and cash equivalents
 
 
 
Beginning of period
871 
63 
1,149 
End of period
576 
871 
63 
Supplemental cash flow information
 
 
 
Interest payments
3,185 
3,349 
4,523 
Supplemental non-cash information
 
 
 
Increase (decrease) in accrued property, plant and equipment
6,968 
75 
0 
Receivable for reimbursable construction in progress projects
$ 141 
$ 872 
$ 6,058 
[1] During the fourth quarter, we identified revenues in the amount of $0.3 million associated with proceeds received in connection with COMA reimbursable projects that were incorrectly recognized in the first quarter of 2012 that should have been recognized ratably during each of the succeeding quarters of 2012 for approximately $0.1 million per quarter. In addition, we recorded in the first quarter of 2012 and for the year ended December 31, 2012 out-of-period adjustments amounting to $0.1 million for the correction of immaterial errors associated with additional depreciation expense and selling, general and administrative expense. Based upon our evaluation of relevant factors, we concluded that these errors were not material to any previously issued and current consolidated financial statements.(b)For a definition of gross margin and a reconciliation to its mostly directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 19, "Reporting Segments".
Organization and Basis of Presentation
Organization and Basis of Presentation
Organization and Basis of Presentation
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, fractionating, marketing and transportation services primarily 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.
Our interstate natural gas pipeline assets transport natural gas through the Federal Energy Regulatory Commission (“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 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.
ArcLight Transactions
On April 15, 2013, the Partnership, our general partner and AIM Midstream Holdings, LLC, an affiliate of American Infrastructure MLP Fund, entered into agreements (the "ArcLight Transactions") with High Point Infrastructure Partners, LLC, an affiliate of ArcLight Capital Partners, LLC (“High Point”), pursuant to which High Point (i) acquired 90% of our general partner and all of our subordinated units from AIM Midstream Holdings and (ii) contributed certain midstream assets and $15.0 million in cash to us in exchange for 5,142,857 convertible preferred units (the “Series A Preferred Units”) issued by the Partnership.  As a result of these transactions, which were also consummated on April 15, 2013, High Point acquired both control of our general partner and a majority of our outstanding limited partnership interests.  The midstream assets contributed by High Point consist of approximately 700 miles of natural gas and liquids pipeline assets located in southeast Louisiana and the shallow water and deep shelf Gulf of Mexico. These midstream assets gather natural gas from both onshore and offshore producing regions around southeast Louisiana. The onshore footprint is Plaquemines and St. Bernard's Parish, LA. The offshore footprint consists of the following federal Gulf of Mexico zones: Mississippi Canyon, Viosca Knoll, West Delta, Main Pass, South Pass and Breton Sound. Natural gas is collected at more than 75 receipt points that connect to hundreds of wells targeting various geological zones in water depths up to 1,000 feet, with an emphasis on oil and liquids-rich reservoirs. The High Point midstream assets are comprised of FERC-regulated transmission assets and non-jurisdictional gathering assets, both of which accept natural gas from well production and interconnected pipeline systems. High Point delivers the natural gas to the Toca Gas Processing Plant, operated by Enterprise, where the products are processed and the residue gas sent to an unaffiliated interstate system owned by Kinder Morgan. See Note 23 - Subsequent Events for further information.

We depend on our June 2012 amended credit facility for future capital needs and may use it to fund a portion of cash distributions to unitholders, as necessary, depending on the level of our operating cashflow. The Partnership believes that the consummation of the ArcLight Transactions will allow it to maintain compliance with the Consolidated Total Leverage to EBTIDA ratio in the Fourth Amendment to our June 2012 amended credit agreement ("Fourth Amendment") for a period of at least the next twelve months from the date of the Annual Report on Form 10-K. However, no assurances can be given that the ArcLight Transactions will achieve the necessary ratios or that the contributed business can yield the necessary cash flows. If the foregoing does not occur and we are not able to generate sufficient cash flows from operations to maintain compliance with the financial covenants in the Fourth Amendment and we are not able enter into an agreement to refinance or obtain covenant default waivers the debt could become due and payable upon acceleration by the lenders in our banking group and other agreements with cross-default provisions could become due. In addition, failure to comply with any of the covenants under our Fourth Amendment could adversely affect our ability to fund ongoing operations and growth capital requirements as well as our ability to pay distributions to our unitholders. See Note 22 - Liquidity for further information.
Basis of presentation
The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2012 and 2011, and results of operations, comprehensive income, changes in partners' capital and noncontrolling interest, and cash flows for the years ended December 31, 2012, 2011 and 2010.
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 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. We have made reclassifications to amounts reported in prior period consolidated financial statements to conform with current year presentation. These reclassifications did not have an impact on net income for the period previously reported.
The results of operations for acquisitions accounted for as business combinations have been included in the consolidated financial statements since their respective acquisition dates (see Note 2).
Consolidation policy
Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold an undivided interest in the Burns Point gas processing facility in which we are responsible for our proportionate share of the costs and expenses of the facility. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of this undivided interest. In July 2012, the Partnership acquired a 87.4% undivided interest in the Chatom Processing and Fractionation facility (the "Chatom system"). Our consolidated financial statements reflect the accounts of the Chatom system since acquisition, and the interests in the Chatom system held by non-affiliated working interest owners are reflected as noncontrolling interests in the Partnership's consolidated financial statements.
Use of estimates
When preparing financial statements in conformity with GAAP, 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 (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 regulations by FERC. 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 be recorded under GAAP for our regulated entities. As of December 31, 2012 and 2011, we had no such material regulatory assets or liabilities.
 
Revenue recognition and the estimation of revenues and cost of purchases
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, natural gas liquids ("NGLs") or condensates that are purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating or transportation, we record those fees separately in revenues. We have the following arrangements:

Fee-based
Under these arrangements, we generally are paid a fixed fee for gathering and transporting natural gas. Fee-based revenues, which are included in sales of natural gas, NGLs and condensate, are recorded when services have been provided, and collectability of the revenue is reasonably assured.
Percent-of-proceeds, or POP
Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas and NGLs at market prices. Where we provide processing services at the processing plants that we own, or obtain processing service for our own account under our own elective processing arrangements we typically retain and sell a percentage of the residue natural gas and resulting NGLs. We recognize percent-of-proceeds contract revenue, which is included in sales of natural gas, NGLs and condensate, when the natural gas, NGLs or condensate is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.
Fixed-margin
Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. We recognize revenue from fixed-margin contracts, which is included in sales of natural gas, NGLs and condensate, when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred and collectability of the revenue is reasonably assured.
Firm transportation
Under arrangements to provide firm transportation service, 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 they utilize the capacity. In most cases, the shipper also pays a variable use charge with respect to quantities actually transported by us. Firm transportation revenue is recorded when products are delivered, services have been provided and collectability of the revenue is reasonably assured.
 
Interruptible transportation
Under arrangements to provide interruptible transportation service, we are only obligated to transport natural gas nominated by the shipper to the extent we have available capacity. For this service the shipper pays no reservation charge but pays a variable use charge for quantities actually shipped. Interruptible transportation revenue is recorded when products are delivered, services have been provided and collectability of revenue is reasonably assured.
Interest in the Burns Point Plant
We account for our interest in the Burns Point Plant using the proportionate consolidation method. Under this method, we include in our consolidated statement of operations our value of plant revenues taken in-kind and plant expenses reimbursed to the operator.
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. As of December 31, 2012 and 2011, the Partnership recorded no allowances for losses on accounts receivable.
Inventory
Inventory includes NGL product inventory. The Partnership records all product inventories at the lower of cost or market (“LCM”), which is determined on a weighted average basis and included within Other current assets on the consolidated balance sheets.
Operational balancing agreements and natural gas imbalances
To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through future receipt or delivery of natural gas. Natural gas imbalances are recorded as gas imbalances and classified within other current assets or other current liabilities on our consolidated balance sheets based on the market value.
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 assets.
The Partnership calculated the fair value of net assets acquired from Quantum Resources Management, LLC in July 2012 with the assistance of an independent third party valuation firm. These valuations were performed primarily using a discounted cash flow model that included certain market assumptions related to future throughput discount rates. We created the projections and reviewed the calculations, assumptions and valuation methodology used to determine the fair value of the assets acquired. We determined the final fair values to assign to the assets and liabilities in determining the purchase price allocation and had sole responsibility for those items in the financial statements.
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 business, 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 years ended December 31, 2012, 2011 and 2010.
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 tax expense results from the enactment of state income tax laws by the State of Texas that apply to entities organized as partnerships and is included in selling, general and administrative expenses in the consolidated statements of operations. The Texas margin tax is computed on our modified gross margin and was not significant for each of the years ended December 31, 2012, 2011 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 requirement 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 from the remediation of existing environmental contamination caused by past operations that do not benefit future period 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 regulation 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 cost or new information. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record 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 in more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.
We have legal obligations requiring us to decommission our offshore pipeline systems at retirement. In certain rate jurisdictions, we are permitted to include annual charges for removal costs in the regulated cost of service rates we charge our customers. Additionally, legal obligations exist for a minority of our offshore 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 of 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 exist 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 amount 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 sheet 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 or trading purposes.
The price assumptions we use to value our derivative financial instruments can affect net income for each period. We use published market price information where available, or quotations from over-the-counter, or OTC, market makers to find executable bids and offers. The valuations also reflect the potential impact of 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 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.
Comprehensive income (loss)
The Partnership’s other comprehensive income (loss) is comprised of adjustments to other post-retirement plan assets and liabilities. See Note 16, "Post-Employment Benefits".
 
Unit-based employee compensation
We award unit-based compensation to management, non-management 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 equity compensation expense over the requisite service period of each award. See Note 15, "Long-Term Incentive Plan".
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 use various assumptions and methods in estimating the fair values of our financial instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of our various credit facilities approximate fair value, because the interest rates on these facilities are variable.
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 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities;
•
Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets that are either directly or indirectly observable; and
•
Level 3 – Inputs are unobservable and considered significant to fair value measurement.
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 extinguishment include any associated unamortized debt issue costs.
Noncontrolling interest

Noncontrolling interest represents the noncontrolling interest holders' proportionate share of the equity of the Chatom system.  Noncontrolling interest is adjusted for the noncontrolling interest holders' proportionate share of the earnings or losses.  Management reports noncontrolling interest in the Chatom system in the financial statements pursuant to paragraph ASC No. 810-10-65-1.  The 12.6% noncontrolling interest is held by non-affiliated working interest owners.
Limited partners’ net income (loss) per unit
We compute limited partners’ net income (loss) per unit by dividing our limited partners’ interest in net income (loss) by the weighted average number of units outstanding during the period. The overall computation, presentation and disclosure of our limited partners’ net income (loss) per unit are made in accordance with the FASB Accounting Standards Codification (ASC) Topic 260 “Earnings per Share”.
Acquisitions
Acquisitions
Acquisitions
Chatom Gathering, Processing and Fractionation Plant
Effective July 1, 2012, we acquired an 87.4% undivided interest in the Chatom system from affiliates of Quantum Resources Management, LLC. The acquisition fair value consideration of $51.4 million includes a credit associated with the cash flow the Chatom system generated between January 1, 2012, and the effective date of July 1, 2012.  The consideration paid by the Partnership consisted of cash, which was funded under borrowings under our revolving credit facility.
The Chatom system is located in Washington County, Alabama, approximately 15 miles from our Bazor Ridge processing plant in Wayne County, Mississippi, and consists of a 25 MMcf/d refrigeration processing plant, a 1,900 Bbl/d fractionation unit, a 160 long-ton per day sulfur recovery unit, and a 29 mile gas gathering system. We believe the fractionating services provide flexibility to the Partnership's product and service offerings.

The following table presents the fair value of consideration transferred to acquire the Chatom system and the amounts of identified assets acquired and liabilities assumed at the acquisition date, as well as the fair value of the 12.6% noncontrolling interest in the Chatom system at the acquisition date:
 
 
 
(in thousands)
Cash consideration:
 
 
$
51,377

Recognized amounts of identifiable assets acquired and liabilities assumed:
 
Unbilled revenue
 
 
$
4,535

Property, plant and equipment
58,279

Asset retirement cost
452

Accounts payable
 
 
(399
)
Accrued gas purchases
(3,631
)
Asset retirement obligations
(452
)
Noncontrolling interest
(7,407
)
Total identifiable net assets:
$
51,377



The fair value of the property, plant and equipment and noncontrolling interests were estimated by applying a combination of the market and income approaches. This fair value measurements are based on significant inputs not observable in the market and thus represents a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimates are based on i) an assumed cost of capital of 9.25%, ii) an assumed terminal value based on the present value of estimated EBITDA, iii) an inflationary cost increase of 2.5%, iv) forward market prices as of July 2012 for natural gas and crude oil, iv) a Federal tax rate of 35% and a state tax rate of 6.5%, and v) an increase in processed and fractionated volumes in 2013, declining thereafter. Working capital was estimated using net realizable value. Accrued revenue was deemed to be fully collectible at July 1, 2012.

Subsequent to the acquisition, our 87.4% undivided interest in the Chatom system contributed $25.2 million of revenue and $2.0 million of net income attributable to the Partnership, which are included in the consolidated statement of operations for the year ended December 31, 2012, respectively.

The following table presents unaudited pro forma consolidated information of the Partnership, adjusted for the acquisition of the Chatom system, as if the acquisition had occurred on January 1, 2011:
 
Year Ended
 
December 31,
 
2012
 
2011
 
(unaudited, in thousands)
Revenue
$
246,342

 
$
296,387

Net income (loss)
$
(4,319
)
 
$
(10,411
)
Limited partners’ net income (loss) per unit
$
(0.49
)
 
$
(1.53
)


These amounts have been calculated after applying the Partnership's accounting policies and adjusting the results to reflect i) additional depreciation and amortization that would have been charged assuming fair value adjustments to property, plant and equipment, and ii) recording pro forma interest expense on debt that would have been incurred to acquire the Chatom system as of January 1, 2012 and 2011, respectively. The unaudited pro forma adjustments are based on available information and certain assumptions we believe are reasonable.

Burns Point Plant Interest
On December 1, 2011, we acquired a 50% undivided interest (“Interest”) in the Burns Point Plant (“Plant”) from Marathon Oil Company (“Seller”) for total cash consideration of $35.5 million. No liabilities of the Seller were assumed. The purchase was effective November 1, 2011 (“Effective Date”) with our assumption of insurable risks, operating liabilities and entitlement to in-kind revenues as of that date. The remaining 50% undivided interest is owned by the Plant operator, Enterprise Gas Processing, LLC (“Operator”). The Plant, which is an unincorporated venture, is governed by a construction and operating agreement (“Agreement”).
The Plant is located in St. Mary Parish, Louisiana, and processes raw natural gas using a cryogenic expander. The Plant inlet volumes are sourced from offshore natural gas production via our Quivira system, Gulf South pipelines and onshore from individual producers near the plant. The Partnership’s Quivira system currently supplies approximately 85% of the inlet volume to the Plant. The residue gas is transported, via pipeline to Gulf South and Tennessee Gas Pipeline and the Y-grade liquid is transported via pipeline to K/D/S Promix, LLC (“Promix”), an Enterprise-operated fractionator. The current capacity of the Plant is 165 MMcf/d. The acquisition complemented our existing assets given the location of the Plant in comparison to the Quivira system and is included in our gathering and processing segment.
The Plant is not a legal entity but rather an asset that is jointly owned by the Operator and us. We acquired an interest in the asset group and do not hold an interest in a legal entity. Each of the owners in the asset group is proportionately liable for the liabilities. Outside of the rights and responsibilities of the Operator, we and the Operator have equal rights and obligations to the assets. Significant non-capital and maintenance capital expenditures, plant expansions and significant plant dispositions require the approval of both owners.
Under the terms of the Agreement, the Operator is required to provide monthly production allocation and expense statements to us and is not required to prepare and provide to us balance sheet information or stand-alone financial statements. Historically, balance sheet and stand-alone financial statements for the Plant have not been prepared and are, therefore, not available.
We reviewed the governance structure of the Plant and applied the concepts discussed in ASC-810-10-45, Other Presentation Matters. We determined that while the facility is an unincorporated joint venture, the asset group is jointly controlled with the Operator.
We reviewed the requirements for the application of the equity method of accounting, given the joint control attribute of the Plant, and because complete Plant financial statements are not, nor expected to be, available from the Operator, we have elected to account for our Interest using the proportionate consolidation method. Our interest in the Plant is recorded in property, plant and equipment, net on the consolidated balance sheet and will be depreciated over 40 years. Under this method, we include in our consolidated statement of operations the value of our Plant revenues taken in-kind and the Plant expenses reimbursed to the Operator.
The following table presents the fair value of consideration transferred to acquire our Interest in the Plant and the amounts of identified assets acquired and liabilities assumed at the acquisition date:
 
(in thousands)
Cash consideration:
$
35,500

Recognized amounts of identifiable assets acquired and liabilities assumed:
 
Property, plant and equipment
$
36,065

Liabilities assumed
—

Total identifiable net assets:
$
36,065

Bargain purchase (gain)
(565
)
 
$
35,500



 Fair value of the assets calculated under the market participant approach was in excess of cash consideration paid resulting in a $0.6 million bargain purchase gain.

The following table presents unaudited pro forma consolidated information of the Partnership, adjusted for the acquisition of the Interest in the Plant, as if the acquisition had occurred on January 1, 2010:

 
Year Ended
 
December 31,
 
2011
 
2010
 
(unaudited, in thousands)
Revenue
$
249,908

 
$
216,585

Net income (loss)
$
(11,741
)
 
$
(8,844
)
Limited partners’ net income (loss) per unit
$
(1.65
)
 
$
(1.70
)


These amounts have been calculated after applying the Partnership's accounting policies and adjusting the results to reflect i)additional depreciation and amortization that would have been charged assuming fair value adjustments to property, plant and equipment, ii) recording pro forma interest expense on debt that would have been incurred to acquire our interest in the Plant, and iii) elimination of the bargain purchase gain as of January 1, 2011 and 2010, respectively. The unaudited pro forma adjustments are based on available information and certain assumptions we believe are reasonable.
The unaudited pro forma consolidated financial information is for informational purposes only and is not intended to represent or be indicative of the consolidated results of operations or financial position that we would have reported had these acquisitions been completed on the date indicated and should not be taken as representative of its future consolidated results of operations or financial position. Further, the unaudited pro forma consolidated statement of operations is not indicative of the operations going forward because it necessarily excludes various operating expenses.
Concentration of Credit Risk and Trade Accounts Receivable
Concentration of Credit Risk and Trade Accounts Receivable
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 as 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; however, for the years ended December 31, 2012, 2011 and 2010, no allowances on or write-offs of accounts receivable were recorded.
The following table summarizes the percentage of revenue earned from those customers that exceed 10% or greater of the Partnership's consolidated revenue in the consolidated statement of operations for the each of the periods presented below:
 
For the year ended December 31,
 
2012
 
2011
 
2010
Customer A
30
%
 
41
%
 
25
%
Customer B
14
%
 
18
%
 
30
%
Customer C
13
%
 
15
%
 
11
%
Other
43
%
 
26
%
 
34
%
Total
100
%
 
100
%
 
100
%
Other Current Assets
Other Current Assets
Other Current Assets
 
 
 
December 31,
 
 
2012
 
2011
 
 
(in thousands)
Other receivables
 
$
452

 
$
663

Construction, operating and maintenance agreement (“COMA”)
 
—

 
623

Prepaid insurance—current portion
 
458

 
567

Other prepaid amounts
 
451

 
508

Gas imbalances receivable
 
932

 
852

NGL inventory
 
931

 
96

Other current assets
 
2

 
14

 
 
$
3,226

 
$
3,323


For the years ended December 31, 2012 and 2011, we recorded no lower-of-cost-or-market write-downs on our NGL inventory.
Derivatives
Derivatives
Derivatives
Commodity derivatives
To minimize the effect of commodity prices and maintain our cash flow and the economics of our development plans, we enter into commodity hedge contracts from time to time. The terms of the 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 mitigate the effect of commodity price downturns while allowing us to participate in some commodity price upside. Management regularly monitors the commodity markets and financial commitments to determine if, when, and at what level commodity hedging is appropriate in accordance with policies that are established by the board of directors of our general partner. Currently, the commodity derivatives are in the form of swaps, puts and collars. As of December 31, 2012, the aggregate notional volume of our commodity derivatives was 15.1 million gallons.
We enter into commodity contracts with multiple counterparties. We may be required to post collateral with our counterparties in connection with our derivative positions. As of December 31, 2012, we have not posted collateral with our counterparties. The counterparties are not required to post collateral with us in connection with their derivative positions. Netting agreements are in place with our counterparties that permit us to offset our commodity derivative asset and liability positions.
In June 2011, the Board of Directors of our general partner determined that we would gain operational and strategic flexibility from canceling our then-existing NGL swap contracts and entering into new NGL swap contracts with an existing counterparty that extended through the end of 2012. During 2012, we entered into additional commodity contracts with existing counterparties to hedge our 2012 and 2013 exposure to commodity prices.
Interest rate derivatives
The Partnership may utilize interest rate caps to protect against changes in interest rates on its floating rate debt. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates, the Partnership entered into interest rate caps that mitigate the risk of increases in interest rates. For the year ended December 31, 2011, we had interest rate caps with a notional amount of up to $25.0 million that effectively fix the base rate on that portion of our debt, with a fixed maximum rate of 4%, which expired during the fourth quarter of 2011. As of December 31, 2012 and 2011, we held no interest rate derivatives.
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 fair value of the derivatives recorded in the consolidated 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 non-cash earnings volatility due to changes in the underlying commodity price indices or interest rates.
As of December 31, 2012 and 2011, the fair value associated with our commodity derivative instruments were recorded in our consolidated balance sheets, under the captions as follows:
 
(in thousands)
 
Gross Derivative Assets
 
Gross Derivative Liabilities
Balance Sheet Classification
 
December 31, 2012
 
December 31, 2011
 
December 31, 2012
 
December 31, 2011
 
 
 
 
 
 
 
 
 
Risk management assets
 
$
1,889

 
$
—

 
$
(920
)
 
$
—

Risk management assets - long term
 
—

 
—

 
—

 
—

Total
 
$
1,889

 
$
—

 
$
(920
)
 
$
—

 
 
 
 
 
 
 
 
 
Risk management liabilities
 
$
—

 
$
456

 
$
—

 
$
(635
)
Risk management liabilities - long term
 
—

 
—

 
—

 
—

Total
 
$
—

 
$
456

 
$
—

 
$
(635
)

For the years ended December 31, 2012, 2011 and 2010, the realized and unrealized gains (losses) associated with our commodity and interest rate derivative instruments were recorded in our consolidated statements of operations, under the captions as follows:
 
(in thousands)
 
Gain (loss) on derivatives
Statement of Operations Classification
 
Realized
 
Unrealized
2012
 

Revenue
 
$
2,408

 
$
—

Unrealized gain (loss) on commodity derivatives
 
—

 
992

Total
 
$
2,408

 
$
992

2011
 

 

Revenue
 
$
(1,911
)
 
$
—

Realized gain (loss) on early termination of commodity derivatives
 
(2,998
)
 
—

Unrealized gain (loss) on commodity derivatives
 
—

 
(541
)
Total
 
$
(4,909
)
 
$
(541
)
2010
 
 
 
 
Revenue
 
$
—

 
$
—

Unrealized gain (loss) on commodity derivatives
 
—

 
(308
)
Interest expense
 
—

 
(77
)
Total
 
$
—

 
$
(385
)
Fair Value Measurement
Fair Value Measurement
Fair Value Measurement
The authoritative guidance for fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers include:
•
Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities;
•
Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets that are either directly or indirectly observable; and
•
Level 3 – Inputs are unobservable and considered significant to fair value measurement.
A financial instrument’s categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy.
We believe the carrying amount of cash and cash equivalents approximates fair value because of the short-term maturity of these instruments would be classified as Level 1 under the fair value hierarchy.
The recorded value of the amounts outstanding under the credit facility approximates its fair value, as interest rates are variable, based on prevailing market rates and the short-term nature of borrowings and repayments under the credit facility. Our existing revolving credit facility would be classified as Level 1 under the fair value hierarchy.
The fair value of all derivatives instruments is estimated using a market valuation methodology based upon forward commodity price curves, volatility curves as well as other relevant economic measures, if necessary. Discount factors may be utilized to extrapolate a forecast of future cash flows associated with long dated transactions or illiquid market points. The inputs are obtained from independent pricing services, and we have made no adjustments to the obtained prices.
We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivatives contracts held. We will recognize transfers between levels at the end of the reporting period for which the transfer has occurred. We recognized transfers out of Level 3 into Level 2 as a result of changes in tenure and market points of certain contracts in the amount of $1.0 million for the year ended December 31, 2012. There were no such transfers for years ended December 31, 2011.
Fair Value of Financial Instruments
The following table sets forth by level within the fair value hierarchy, our net derivative assets (liabilities) that were measured at fair value on a recurring basis as of December 31, 2012 and 2011:
 
 
Carrying
Amount
 
Estimated Fair Value
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
 
(in thousands)
 
 
Commodity derivative asset (liability), net
 
 
 
 
 
 
 
 
 
December 31, 2012
$
969

 
$
—

 
$
969

 
$
—

 
$
969

December 31, 2011
$
(179
)
 
$
—

 
$
—

 
$
(179
)
 
$
(179
)

Changes in Level 3 Fair Value Measurements
The table below includes a roll forward of the balance sheet amounts (including the change in fair value) for financial instruments classified 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). Contracts classified as Level 3 are valued using internally developed price inputs and curves constructed as a result of the long dated nature of the transactions or the illiquidity of the market points. Contracts classified as Level 2 are valued using inputs and curves that are supported and available from public markets to the extent that the markets or the relevant settlement periods are liquid:
 
 
Year Ended
 
December 31,
 
2012
 
2011
 
(in thousands)
Fair value asset (liability), beginning of period
$
(179
)
 
$
—

Realized gain (loss) on early termination of commodity derivatives
—

 
(2,998
)
Realized gain (loss) on expiration of commodity put contract
—

 
(308
)
Unrealized gain (loss) on commodity derivatives
992

 
(541
)
Purchases
156

 
670

Settlements
—

 
2,998

Transfers out of Level 3 (a)
(969
)
 
—

Fair value asset (liability), end of period
$
—

 
$
(179
)
(a)Amounts transferred out are reflected at fair value as of the end of the period

Also included in revenue were $2.4 million, $(1.6) million, and zero in realized gains (losses) for the years ended December 31, 2012, 2011, and 2010, respectively, representing our commodity derivative settlements.
Property, Plant and Equipment, Net
Property, Plant and Equipment, Net
Property, Plant and Equipment, Net
Property, plant and equipment, net, as of December 31, 2012 and 2011 were as follows:
 
 
 
 
 
December 31,
 
 
Useful Life
 
2012
 
2011
 
 
 
 
(in thousands)
Land
 
 
 
$
2,254

 
$
41

Construction in progress
 
 
 
5,053

 
3,380

Buildings and improvements
 
4 to 40
 
1,432

 
1,490

Processing and treating plants
 
8 to 40
 
98,106

 
49,396

Pipelines
 
5 to 40
 
163,447

 
146,788

Compressors
 
4 to 20
 
8,957

 
7,437

Equipment
 
8 to 20
 
4,785

 
1,198

Computer software
 
5
 
1,950

 
1,500

Total property, plant and equipment
 
 
 
285,984

 
211,230

Accumulated depreciation
 
 
 
(62,165
)
 
(40,999
)
Property, plant and equipment, net
 
 
 
$
223,819

 
$
170,231


Of the gross property, plant and equipment balances at December 31, 2012 and 2011, $26.1 million and $24.0 million, respectively, were related to AlaTenn and Midla, our FERC-regulated interstate assets.
Insurance proceeds

We pay premiums to our insurance carrier which provides us with property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our operations. While we believe we maintain adequate insurance coverage on our behalf, insurance may not fully cover every type of damage, interruption or other loss that might occur. If we were to incur a significant loss for which we were not fully insured, it could have a material impact on our financial position, results of operations and cash flows. In addition, there may be timing differences between amounts we accrue related to property damage expense, amounts we are required to pay in connection with a loss and amounts we subsequently receive from insurance carriers as reimbursements. Any event that materially interrupts the revenues generated by our consolidated operations, or other losses that require us to make material expenditures not reimbursed by insurance, could reduce our ability to pay distributions to our unitholders and, accordingly, adversely affect the market price of our common units.

Involuntary conversions result from the loss of an asset because of some unforeseen event (e.g., destruction due to hurricanes). Some of these events are insurable, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. During the year ended December 31, 2012, we collected $0.5 million of nonrefundable cash proceeds from our insurance carrier that we recognized as an offset to property, plant and equipment write-downs of $1.5 million due to property damage under the caption Gain (loss) on involuntary conversion of property, plant and equipment. These proceeds relate to property damage claims we made in connection with the named windstorm Hurricane Isaac in September of 2012. To the extent that additional non-refundable insurance proceeds related to this incident are received, we expect to record gains equal to such proceeds.
Asset Retirement Obligation
Asset Retirement Obligation
Asset Retirement Obligation
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 then 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 years ended December 31, 2012 and 2011, we recognized $0.5 million and $0.9 million, respectively, of ARO which is included in other liabilities for specific assets that we intend to retire for operational purposes.
We recorded accretion expense, which is included in depreciation expense, in our consolidated statements of operations of less than $0.1 million, $1.4 million, and $1.2 million for the years ended December 31, 2012, 2011, and 2010, respectively.
 
No assets were legally restricted for purposes of settling our ARO liabilities during the years ended December 31, 2012 and 2011. The following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for years ended December 31, 2012 and 2011, respectively:

 
Year Ended
 
December 31,
 
2012
 
2011
 
(in thousands)
Balance at beginning of period
$
8,093

 
$
7,249

Additions
452

 
872

Reductions
—

 
(920
)
Expenditures
(258
)
 
(501
)
Accretion expense
32

 
1,393

Balance at end of period
$
8,319

 
$
8,093



In August 2011, we sold an abandoned portion of pipe for which we had recorded an ARO. As a result of this sale, we are no longer responsible for the costs of abandonment on this pipe and have reduced our ARO during 2011 by $0.5 million. In December 2011, we completed the abandonment of the West Cameron Pipeline at a cost of $0.5 million. Upon the completion of this project we reduced our ARO by $0.4 million.
Other Assets, Net
Other Assets, Net
Other Assets, Net
Other assets, net, were as follows:
 
 
 
December 31,
 
 
2012
 
2011
 
 
(in thousands)
Deferred financing costs
 
$
3,394

 
$
2,545

Other post retirement benefit plan assets, net
 
1,080

 
966

Prepaid amounts—long term
 
97

 
139

Security deposits
 
65

 
57

Other
 
—

 
—

 
 
$
4,636

 
$
3,707


Deferred financing costs
During the years ended December 31, 2012 and 2011, deferred financing costs related to the term-loan portion of our credit facility were amortized using the effective interest rate over the term of the term credit facility, which was retired on August 1, 2011. 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 years ended December 31, 2012 and 2011, we recorded deferred financing costs of $0.7 million and $1.3 million, respectively.
Accrued Expenses and Other Current Liabilities
Accounts Expenses and Other Current Liabilities
Accrued Expenses and Other Current Liabilities
Accrued expenses and other current liabilities were as follows:
 
 
 
December 31,
 
 
2012
 
2011
 
 
(in thousands)
Deferred revenue—short term
 
$
288

 
$
2,314

Accrued salaries
 
944

 
1,542

Accrued expenses
 
6,519

 
953

Construction operating and maintenance agreement deposits
 
30

 
710

Gas imbalances payable
 
971

 
1,200

Contract obligations—short term
 
—

 
240

Accrued interest payable
 
724

 
123

Other
 
143

 
4

 
 
$
9,619

 
$
7,086

Other Liabilities
Other Liabilities
Other Liabilities
Other liabilities were as follows: 
 
 
December 31,
 
 
2012
 
2011
 
 
(in thousands)
Deferred revenue—long term
 
$
245

 
$
351

Asset retirement obligations
 
8,319

 
8,093

Contract obligations—long term
 
—

 
88

Other deferred expenses
 
64

 
80

 
 
$
8,628

 
$
8,612

Long-Term Debt
Long-Term Debt
Long-Term Debt
On August 1, 2011, we executed a $100 million revolving credit facility, with a $50 million accordion feature which, if exercised, would increase the total commitment under the facility to $150 million.
On June 27, 2012, we amended our credit facility to increase the commitments from an aggregate principal amount of $100 million to an aggregate principal amount of $200 million, evidenced by a credit agreement with Bank of America, N.A., as Administrative Agent, Collateral Agent and L/C Issuer; Comerica Bank and Citicorp North America, Inc., as Co-Syndication Agents; BBVA Compass, as Documentation Agent; and the other financial institutions party thereto. The credit facility also provides for a $50 million dollar accordion feature. If the accordion feature were to be fully exercised, the total commitment under the existing facility would be $250 million.
The amended credit facility provides for a maximum borrowing equal to the lesser of (i) $200 million or (ii) 4.50 times adjusted consolidated EBITDA. Prior to the Third Amendment described below, we could elect to have loans under the new credit facility bear interest either at a Eurodollar-based rate plus a margin ranging from 2.25% to 3.50% depending on our total leverage ratio then in effect, or a base rate which is a fluctuating rate per annum equal to the highest of (a) the Federal Funds Rate plus 1/2 of 1%, (b) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its “prime rate”, or (c) the Eurodollar Rate plus 1.00% plus a margin ranging from 1.25% to 2.50% depending on the total leverage ratio then in effect. We also paid a commitment fee of 0.50% per annum on the undrawn portion of the revolving loan. For the years ended December 31, 2012, 2011 and 2010, the weighted average interest rate on borrowings under our credit facilities was approximately 4.09%, 6.71%, and 7.48%, respectively.
Our obligations under the credit facility are secured by a first mortgage in favor of the lenders in our real property. Advances made under the credit facility are guaranteed on a senior unsecured basis by our subsidiaries (“Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors. The terms of the new 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, August 1, 2016.
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 4.50 times) and a minimum interest coverage ratio test (which, prior to the Third Amendment count not less than 2.50).
As of December 31, 2012, the total leverage ratio test, one of the primary financial covenants that we are required to maintain under our credit facility, was not to exceed 4.50 times. At December 31, 2012, our total indebtedness was approximately $130.9 million, which caused our total leverage to EBITDA ratio to be approximately 5.70-to-1. As a result, on December 26, 2012, the Partnership entered into the Third Amendment and Waiver to Credit Agreement, dated as of December 26, 2012 (the “Third Amendment”). The Third Amendment provided for a waiver of the Partnership's compliance with the Consolidated Total Leverage Ratio with respect to the quarter ending December 31, 2012 and for one month thereafter. The Third Amendment also requires the Partnership to provide certain financial and operating information of the Partnership on a monthly basis for 2013 and for any month after 2013 in which the Consolidated Total Leverage Ratio of the Partnership is in excess of 4.00 to 1.00. The remaining material terms and conditions of the senior secured revolving credit facility, including pricing, maturity and covenants, remained unchanged by the Third Amendment.
See Note 22 - Liquidity for further updates to our liquidity and Long-term debt.
Our outstanding borrowings under the credit facility at December 31, 2012 and 2011, respectively, were: 
 
 
December 31,
 
 
2012
 
2011
 
 
(in thousands)
Revolving loan facility
 
$
128,285

 
$
66,270


At December 31, 2012 and 2011, respectively, letters of credit outstanding under the credit facility were $2.6 million and $0.6 million, respectively.
In connection with our credit facility and amendments thereto, we have incurred $4.3 million in cumulative debt issuance costs through December 31, 2012 which are being amortized on a straight-line basis over the term of the credit facility.
Partners' Capital
Partners' Capital
Partners’ Capital
Our capital accounts are comprised of a 2.0% general partner interest and 98.0% limited partner interests. Our limited partners have limited rights of ownership as provided in 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 that may be made pursuant to the incentive distribution rights that are nonvoting limited partner interests held by our general partner.
On August 1, 2011, we closed our initial public offering (the “IPO”) of our 3,750,000 common units at an offering price of $21 per unit. After deducting underwriting discounts and commissions of $4.9 million paid to the underwriters, offering expenses of $4.2 million and a structuring fee of $0.6 million, the net proceeds from our initial public offering were $69.1 million. We used all of the net offering proceeds from our initial public offering for the uses described in the Prospectus.
Immediately prior to the closing of our IPO the following recapitalization transactions occurred:
•
each common unit held by AIM Midstream Holdings reverse split into 0.485 common units, resulting in the ownership by AIM Midstream Holdings of an aggregate of 5,327,205 common units, representing an aggregate 97.1% limited partner interest in us;
•
the common units held by AIM Midstream Holdings then converted into 801,139 common units and 4,526,066 subordinated units;
•
each general partner unit held by our general partner reverse split into 0.485 general partner units, resulting in the ownership by our general partner of an aggregate of 108,718 general partner units, representing a 2.0% general partner interest in us;
•
each common unit held by participants in our general partner’s long term incentive plan (the “LTIP”), reverse split into 0.485 common units, resulting in their ownership of an aggregate of 50,946 common units, representing an aggregate 0.9% limited partner interest in us; and
•
each outstanding phantom unit granted to participants in our LTIP reverse split into 0.485 phantom units, resulting in their holding an aggregate of 209,824 phantom units.

In connection with the closing of our IPO and immediately following the recapitalization transactions, the following transactions also occurred:
•
AIM Midstream Holdings contributed 76,019 common units to our general partner as a capital contribution, and;
•
our general partner contributed to us the common units contributed to it by AIM Midstream Holdings in exchange for 76,019 general partner units in order to maintain its 2.0% general partner interest in us.
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.
The subordination period generally will end and all of the subordinated units will convert into an equal number of common units if we have earned and paid at least $1.65 on each outstanding common and subordinated unit and the corresponding distribution on our general partner’s 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2014.
The subordination period will automatically terminate and all of the subordinated units will convert into an equal number of common units if we have earned and paid at least $2.475 (150% of the annualized minimum quarterly distribution) on each outstanding common and subordinated unit and the corresponding distributions on our general partner’s 2.0% interest and incentive distribution rights for any four consecutive quarter period ending on or after September 30, 2012; provided that we have paid at least the minimum quarterly distribution from operating surplus on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner’s 2.0% interest for each quarter in that four-quarter period.
ArcLight Transactions
On April 15, 2013, the Partnership, our general partner and AIM Midstream Holdings, LLC, entered in the ArcLight Transactions with High Point, pursuant to which High Point (i) acquired 90% of our general partner and all of our subordinated units from AIM Midstream Holdings and (ii) contributed certain midstream assets and $15.0 million in cash to us in exchange for 5,142,857 Series A Preferred Units issued by the Partnership.  As a result of these transactions, which were also consummated on April 15, 2013, High Point acquired both control of our general partner and a majority of our outstanding limited partnership interests.  See Note 23 - Subsequent Events for further information.
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
•
we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;
then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:
•
first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $0.47438 per unit for that quarter (the “first target distribution”);
•
second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $0.51563 per unit for that quarter (the “second target distribution”);
•
third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $0.61875 per unit for that quarter (the “third target distribution”); and
•
thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.
Distributions
We made distributions of $16.1 million, $9.8 million and $11.8 million for years ended December 31, 2012, 2011 and 2010, respectively. We have neither adopted a policy nor were we required to make minimum distributions during the periods presented in these financial statements.
In addition to the distributions described above, in August 2011 we made a special distribution of $33.7 million to AIM Midstream Holdings, participants in our LTIP holding common units and our general partner as described in the December 31, 2011 Annual Report.
The number of units outstanding was as follows:
 
 
 
December 31,
 
 
2012
 
2011
 
2010
 
 
(in thousands)
Limited partner common units
 
4,639

 
4,561

 
5,363

Limited partner subordinated units
 
4,526

 
4,526

 
—

General partner units
 
185

 
185

 
109


 
The outstanding units noted above reflect the retroactive treatment of the reverse unit split resulting from the recapitalization described above.
Net Income (Loss) per Limited and General Partner Unit
Net Income (Loss) per Limited and General Partner Unit
Net Income (Loss) per Limited and General Partner Unit
Net income (loss) is allocated to the general partner and the limited partners (common and subordinated unit holders) in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic and diluted net income (loss) per limited partner unit is calculated by dividing limited partners’ interest in net income (loss) by the weighted average number of outstanding limited partner units during the period.

Unvested unit-based payment awards that contain non-forfeitable rights to distributions (whether paid or unpaid) are classified as participating securities and are included in our computation of basic and diluted net income per limited partner unit.
We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.
The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit. We have no dilutive securities, therefore basic and diluted net income per unit are the same.
We determined basic and diluted net income (loss) per general partner unit and limited partner unit as follows, in thousands except per unit amounts:
 
 
 
Year Ended
December 31,
 
 
2012
 
2011
 
2010
Net (loss) attributable to general partner and limited partners
 
$
(6,508
)
 
$
(11,698
)
 
$
(8,644
)
Weighted average general partner and limited partner units outstanding(a)(b)
 
9,298

 
7,137

 
5,199

General partner and limited partner (loss) per unit (basic and diluted)
 
$
(0.70
)
 
$
(1.64
)
 
$
(1.66
)
Net (loss) attributable to limited partners
 
$
(6,379
)
 
$
(11,465
)
 
$
(8,471
)
Weighted average limited partner units outstanding(a)(b)
 
9,113

 
6,997

 
5,099

Limited partners’ net (loss) per unit (basic and diluted)
 
$
(0.70
)
 
$
(1.64
)
 
$
(1.66
)
Net (loss) attributable to general partner
 
$
(129
)
 
$
(233
)
 
$
(173
)
Weighted average general partner units outstanding
 
185

 
140

 
99

General partner net (loss) per unit (basic and diluted)
 
$
(0.70
)
 
$
(1.66
)
 
$
(1.75
)
 
(a)
Includes unvested phantom units with DERs, which are considered participating securities, of 205,864 as of December 31, 2010. The DER’s were eliminated on June 9, 2011. There were no such unvested phantom units with DERs at December 31, 2012 and 2011.
(b)
Gives effect to the reverse unit split as described in Note 13, “Partners’ Capital”.
Long-Term Incentive Plan
Long-Term Incentive Plan
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 an LTIP for its employees, 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 LTIP. On July 11, 2012, the board of directors of our general partner adopted a second amended and restated long-term incentive plan that effectively increased available awards by 871,750 units. At December 31, 2012, 2011 and 2010, there were 920,193, 54,827 and 62,246 units, respectively, available for future grant under the LTIP giving retroactive treatment to the reverse unit split described in Note 13 “Partners’ Capital”.
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 units, our general partner has not historically settled these awards in cash. Although other types of awards are contemplated under the LTIP, the only currently outstanding awards are phantom units without dividend equivalent rights ("DERs").
Generally, grants issued under the LTIP vest in increments of 25% on each grant anniversary date and do not contain any vesting requirements other than continued employment.
Prior to our initial public offering, the fair value of the grants issued was calculated by the general partner based on several valuation models, including: a discounted cash flow ("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:
 
 
 
Year Ended
 
 
December 31,
 
 
2012
 
2011
 
2010
 
 
 
 
 
 
 
Outstanding at beginning of period
 
162,860

 
205,864

 
175,236

Granted
 
38,595

 
19,414

 
74,437

Forfeited
 
(12,517
)
 
—

 
—

Vested
 
(98,000
)
 
(62,418
)
 
(43,809
)
Outstanding at end of period
 
90,938

 
162,860

 
205,864

Fair value per unit
 
$14.70 to $21.40

 
$14.70 to $19.69

 
$14.70 to $16.15


The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our units at the grant date. Compensation costs related to these awards including amortization, modification costs, DER payments and the cost of the DER buy-out for the years ended December 31, 2011 and 2010 was $3.4 million and $1.7 million, respectively, which is classified as equity compensation expense in the consolidated statement of operations and the non-cash portion in partners’ capital on the consolidated balance sheet. There were no remaining DERs as of or for the year ended December 31, 2012.
In June 2011, certain existing LTIP grant agreements were modified to exclude the DER provision in exchange for a cash payment of $1.5 million which has been included in equity compensation expense in the consolidated statement of operations.
The total fair value of vesting units at the time of vesting was $1.9 million, $1.2 million, and $0.9 million for the years ended December 31, 2012, 2011, and 2010, respectively.
The total compensation cost related to unvested awards not yet recognized at December 31, 2012, 2011, and 2010 was $1.4 million, $2.7 million, and $3.8 million, respectively, and the weighted average period over which this cost is expected to be recognized as of December 31, 2012 is approximately 1.3 years.
Post-Employment Benefits
Post-Employment Benefits
Post-Employment Benefits
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”).
The tables below detail the changes in the benefit obligation, the fair value of the plan assets and the recorded asset or liability of the OPEB Plan using the accrual method.
 
 
 
Year ended
December 31,
 
 
2012
 
2011
 
2010
 
 
 
 
(in thousands)
 
 
Change in benefit obligation
 
 
 
 
 
 
Obligation, beginning of period
 
$
466

 
$
869

 
$
734

Service cost
 
4

 
3

 
10

Interest cost
 
18

 
22

 
43

Actuarial (gain) loss
 
22

 
(367
)
 
112

Benefits paid
 
(38
)
 
(61
)
 
(30
)
Benefit obligation, end of period
 
$
472

 
$
466

 
$
869

Change in plan assets
 
 
 
 
 
 
Fair value of plan assets, beginning of period
 
$
1,432

 
$
1,319

 
$
1,174

Actual return on plan assets
 
84

 
99

 
61

Employer’s contributions
 
90

 
90

 
113

Benefits paid
 
(54
)
 
(76
)
 
(29
)
Fair value of plan assets, end of period
 
$
1,552

 
$
1,432

 
$
1,319

Funded status
 
 
 
 
 
 
Funded status
 
$
1,080

 
$
966

 
$
450


The amounts of plan assets recognized in our consolidated balance sheets were as follows:
 
 
 
December 31,
 
 
2012
 
2011
 
2010
 
 
(in thousands)
Other assets
 
$
1,080

 
$
966

 
$
450

 
 
$
1,080

 
$
966


$
450


The amounts included in accumulated other comprehensive income at December 31, 2012, 2011 and 2010 that have not been recognized as components of net periodic benefit expenses are $(0.1) million, $0.4 million and $0.1 million, respectively, which relate to net gains (losses).
 
Components of Net Periodic Benefit Cost and Other amounts Recognized in Other Comprehensive Income
 
 
 
December 31,
 
 
2012
 
2011
 
2010
 
 
(in thousands)
Net Periodic (Benefit) Cost
 
 
 
 
 
 
Service cost
 
$
4

 
$
3

 
$
10

Interest cost
 
18

 
22

 
43

Expected return on plan assets
 
(67
)
 
(60
)
 
(53
)
Amortization of net (gain) loss
 
(43
)
 
(47
)
 
—

Net periodic (benefit) cost
 
$
(88
)
 
$
(82
)
 
$
—

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
 
 
 
 
 
 
Net loss (gain)
 
64

 
(359
)
 
(10
)
Total recognized in other comprehensive income
 
64

 
(359
)
 
(10
)
Total recognized in net periodic benefit cost and other comprehensive income
 
$
(24
)
 
$
(441
)
 
$
(10
)

The estimated net gain that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year is less than $0.1 million.
Economic assumptions
The assumptions made in measurement of the projected benefit obligations or assets of the OPEB Plan were as follows:
 
 
 
December 31,
 
 
2012
 
2011
 
2010
Discount rate
 
3.42
%
 
3.96
%
 
5.50
%
Expected return on plan assets
 
4.50
%
 
4.50
%
 
4.50
%

A one percent increase in the assumed medical and dental care trend rate would result in an increase of less than $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 less than $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 2012, 2011 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:
 
For the year ending
(in thousands)
2013
$
41

2014
35

2015
35

2016
32

2017
30

Five years thereafter
135


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.
Future contributions to the Plans
We expect to make contributions of $0.1 million to the OPEB Plan for the year ending December 31, 2013.
 
Plan assets
The weighted average asset allocation of our OPEB Plan at the measurement date by asset category, which are all classified as Level 1 investments, are as follows: 
 
 
December 31,
 
 
2012
 
2011
 
2010
Fixed income (a)
 
72.2
%
 
72.1
%
 
70.7
%
Cash and short term assets (b)
 
27.8
%
 
27.9
%
 
29.3
%
Total
 
100.0
%
 
100.0
%
 
100.0
%
 
(a)
United States government securities, municipal corporate bonds and notes and asset backed securities
(b)
Cash and securities with maturities of one year or less
Commitments and Contingencies
Commitments and Contingencies
Commitments and Contingencies
Environmental matters
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.
Commitments and contractual obligations
Future non-cancelable commitments related to certain contractual obligations as of December 31, 2012 are presented below:
 
 
 
Payments Due by Period 
 
 
Total
 
2013
 
2014
 
2015
 
2016
 
Thereafter
 
 
(in thousands)
Operating leases and service contracts
 
$
2,576

 
$
661

 
$
450

 
$
428

 
$
179

 
$
858

ARO
 
8,319

 
—

 
—

 
—

 
7,860

 
459

Total
 
$
10,895

 
$
661

 
$
450

 
$
428

 
$
8,039

 
$
1,317


For the periods indicated, total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements were:
 
 
Year ended
December 31,
 
 
2012
 
2011
 
2010
 
 
(in thousands)
Operating leases
 
$
941

 
$
803

 
$
757

ARO
 
32

 
1,393

 
1,191

 
 
$
973

 
$
2,196

 
$
1,948


Bazor Ridge Emissions Matter
In July 2011, in the course of preparing our annual filing for 2010 with the Mississippi Department of Environmental Quality (“MDEQ”) as required by our Title V Air Permit, we determined that we underreported to the MDEQ the SO2 (sulfur dioxide) emissions from the Bazor Ridge plant for 2009 and 2010. In addition, we determined that certain SO2 emissions during 2009 and 2010 exceeded the reportable quantity threshold under the federal Emergency Planning and Community Right-to-Know Act, or EPCRA, requiring notification of various governmental authorities. We did not make any such EPCRA notifications.
In July 2011, we self-reported these issues to the MDEQ and EPA Region IV. In January 2012, we met with EPA Region IV representatives, and have agreed to a settlement with respect to the EPCRA reporting issue. A Consent Agreement and Final Order was executed, which included a civil penalty of $23,010. After discussion with the MDEQ, in February 2012 we submitted an application to amend our Title V Air Permit to account for these SO2 emissions. The MDEQ is currently processing this permit application. In December 2011, EPA Region IV performed an inspection of the plant, and they followed up with an Information Request in May 2012. We have responded to this Information Request and do not anticipate any further action required by the Partnership at this time.
Separation Agreement
For the year ended December 31, 2012, we incurred costs of approximately $0.5 million in relation to a separation agreement with a former officer. As a result of this payment to the former officer pursuant to the separation agreement, we expect to receive insurance proceeds from our insurance carrier of approximately 30% of the amount paid to the former officer.
Related-Party Transactions
Related-Party Transactions
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 years ended December 31, 2012, 2011, and 2010 administrative and operational services expenses of $12.5 million, $9.6 million and $7.6 million, respectively, were charged to us by our general partner. For the year ended December 31, 2012, our general partner incurred approximately $0.4 million of costs associated with certain business development activities.  If the business development activities result in a project that will be pursued and funded by the Partnership, we will reimburse our general partner for the business development costs related to that project.
Prior to our IPO, we had 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 provided 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 agreed to provide us services in obtaining equity, debt, lease and acquisition financing, as well as providing other financial, advisory and consulting services. Under this agreement, $0.2 million and $0.3 million had been recorded to selling, general and administrative expenses for the years ended December 31, 2011 and 2010, respectively.
On August 1, 2011 and in connection with our IPO, we terminated the advisory services agreement in exchange for a payment of $2.5 million.
Reporting Segments
Reporting Segments
Reporting Segments
Our operations are located in the United States and are organized into two reporting segments: (1) Gathering and Processing, and (2) Transmission.
Gathering and Processing
Our Gathering and Processing segment provides “wellhead to market” services to producers of natural gas and oil, which include transporting raw natural gas from the wellhead through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs and selling or delivering pipeline quality natural gas and NGLs to various markets and pipeline systems.
Transmission
Our Transmission segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, including local distribution companies, or LDCs, utilities and industrial, commercial and power generation customers.
These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the business of each segment.
 
The following tables set forth our segment information for the periods indicated:

 
Year ended
 
December 31,
 
2012
 
2011
 
Gathering
and
Processing
 
Transmission
 
Total
 
Gathering
and
Processing
 
Transmission
 
Total
 
(in thousands)
Revenue
$
157,065

 
$
52,529

 
$
209,594

 
$
181,517

 
$
66,765

 
$
248,282

Segment gross margin (a)
37,241

 
13,313

 
50,554

 
32,142

 
13,737

 
45,879

Realized gain (loss) on early termination of commodity derivatives (b)
—

 
—

 
—

 
(2,998
)
 
—

 
(2,998
)
Unrealized gain (loss) on commodity derivatives (b)
992

 
—

 
992

 
(541
)
 
—

 
(541
)
Direct operating expenses
13,171

 
5,031

 
18,202

 
7,636

 
5,220

 
12,856

Selling, general and administrative expenses
 
 
 
 
14,309

 
 
 
 
 
10,794

Advisory services agreement termination fee
 
 
 
 
—

 
 
 
 
 
2,500

Transaction expenses
 
 
 
 
 
 
 
 
 
 
282

Equity compensation expense
 
 
 
 
1,783

 
 
 
 
 
3,357

Depreciation and accretion expense
 
 
 
 
21,414

 
 
 
 
 
20,705

Gain (loss) on acquisition of assets
 
 
 
 
—

 
 
 
 
 
565

Gain (loss) on involuntary conversion of property, plant and equipment
 
 
 
 
(1,021
)
 
 
 
 
 
—

Gain (loss) on sale of assets, net
 
 
 
 
128

 
 
 
 
 
399

Interest expense
 
 
 
 
4,570

 
 
 
 
 
4,508

Net income (loss)
 
 
 
 
(6,252
)
 
 
 
 
 
(11,698
)
Less: Net income (loss) attributable to noncontrolling interests
 
 
 
 
256

 
 
 
 
 
—

Net income (loss) attributable to the Partnership
 
 
 
 
$
(6,508
)
 
 
 
 
 
$
(11,698
)
 
 
Year ended
 
December 31,
 
2011
 
2010
 
Gathering
and
Processing
 
Transmission
 
Total
 
Gathering
and
Processing
 
Transmission
 
Total
 
(in thousands)
Revenue
$
181,517

 
$
66,765

 
$
248,282

 
$
158,763

 
$
53,485

 
$
212,248

Segment gross margin (a)
32,142

 
13,737

 
45,879

 
24,595

 
13,524

 
38,119

Realized gain (loss) on early termination of commodity derivatives (b)
(2,998
)
 
—

 
(2,998
)
 
—

 
—

 
—

Unrealized gain (loss) on commodity derivatives (b)
(541
)
 
—

 
(541
)
 
(308
)
 
—

 
(308
)
Direct operating expenses
7,636

 
5,220

 
12,856

 
7,721

 
4,466

 
12,187

Selling, general and administrative expenses
 
 
 
 
10,794

 
 
 
 
 
7,120

Advisory services agreement termination fee
 
 
 
 
2,500

 
 
 
 
 
—

Transaction expenses
 
 
 
 
282

 
 
 
 
 
303

Equity compensation expense
 
 
 
 
3,357

 
 
 
 
 
1,734

Depreciation and accretion expense
 
 
 
 
20,705

 
 
 
 
 
20,013

Gain (loss) on acquisition of assets
 
 
 
 
565

 
 
 
 
 
—

Gain (loss) on sale of assets, net
 
 
 
 
399

 
 
 
 
 
—

Interest expense
 
 
 
 
4,508

 
 
 
 
 
5,406

Net income (loss)
 
 
 
 
$
(11,698
)
 
 
 
 
 
$
(8,644
)

(a)
Segment gross margin for our Gathering and Processing segment consists of revenue less purchases of natural gas, NGLs and condensate and COMA. Segment gross margin for our Transmission segment consists of revenue, less purchases of natural gas and COMA. 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. Effective October 1, 2012, we changed our segment gross margin measure to exclude construction, operating and maintenance agreement (“COMA”) income. For the year ended December 31, 2012, $0.7 million and $2.7 million in COMA income was excluded from our Gathering and Processing segment gross margin and our Transmission segment gross margin, respectively.

(b)
Effective January 1, 2011, we changed our segment gross margin measure to exclude unrealized non-cash mark-to-market adjustments related to our commodity derivatives. For the years ended December 31, 2012 and 2011, $1.0 million and $(0.5) million in unrealized gains (losses) on commodity derivatives were excluded from our Gathering and Processing segment gross margin. Effective April 1, 2011, we changed our segment gross margin measure to exclude realized early termination costs on commodity derivatives. For the year ended December 31, 2011, $(3.0) million in realized gains (losses) on the early termination of commodity derivatives were excluded from our Gathering and Processing segment gross margin.

Asset information, including capital expenditures, by segment is not included in reports used by our management to monitor our performance and therefore is not disclosed.
The following table summarizes the percentage of revenue earned from those customers in each segment that exceed 10% or greater of the Partnership's consolidated segment revenue for the each of the periods presented below:

 
For the year ended December 31,
 
2012
 
2011
 
2010
Gathering and Processing:
 
 
 
 
 
Customer A
40
%
 
55
%
 
34
%
Customer B
12
%
 
16
%
 
30
%
Customer C
11
%
 
—
%
 
—
%
Customer D
—
%
 
—
%
 
10
%
Other
37
%
 
29
%
 
26
%
Total
100
%
 
100
%
 
100
%
Transmission:
 
 
 
 
 
Customer E
22
%
 
22
%
 
31
%
Customer F
50
%
 
57
%
 
43
%
Customer G
10
%
 
—
%
 
10
%
Other
18
%
 
21
%
 
16
%
Total
100
%
 
100
%
 
100
%
Quarterly Financial Data
Quarterly Financial Data
Quarterly Financial Data (Unaudited)
Summarized unaudited quarterly financial data for 2012 and 2011 are as follows:
 
 
 
First
Quarter (a)
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 
Total (a)
 
 
(in thousands expect per unit amounts)
Year ended December 31, 2012
 
 
 
 
 
 
 
 
 
 
Total revenues
 
$
47,711

 
$
46,060

 
$
56,324

 
$
60,491

 
$
210,586

Gross margin (b)
 
12,974

 
11,694

 
13,367

 
12,519

 
50,554

Operating income (loss)
 
2,448

 
3,152

 
(2,525
)
 
(4,757
)
 
(1,682
)
Net income (loss)
 
$
1,691

 
$
2,327

 
$
(4,026
)
 
$
(6,244
)
 
$
(6,252
)
Net income (loss) attributable to noncontrolling interest
 
—

 
—

 
249

 
7

 
256

Net income (loss) attributable to the Partnership
 
$
1,691

 
$
2,327

 
$
(4,275
)
 
$
(6,251
)
 
$
(6,508
)
General partner’s interest in net income (loss)
 
34

 
46

 
(85
)
 
(124
)
 
(129
)
Limited partners’ interest in net income (loss)
 
$
1,657

 
$
2,281

 
$
(4,190
)
 
$
(6,127
)
 
$
(6,379
)
Limited partners’ net income (loss) per unit
 
0.18

 
0.25

 
(0.46
)
 
(0.67
)
 
(0.70
)
Year ended December 31, 2011
 
 
 
 
 
 
 
 
 
 
Total revenues
 
$
63,765

 
$
65,634

 
$
57,958

 
$
57,386

 
$
244,743

Gross margin
 
12,312

 
10,617

 
9,646

 
13,304

 
45,879

Operating income (loss)
 
(2,246
)
 
(2,901
)
 
(3,375
)
 
1,332

 
(7,190
)
Net income (loss)
 
$
(3,510
)
 
$
(4,182
)
 
$
(4,167
)
 
$
161

 
$
(11,698
)
General partner’s interest in net income (loss)
 
(70
)
 
(84
)
 
(83
)
 
4

 
(233
)
Limited partners’ interest in net income (loss)
 
$
(3,440
)
 
$
(4,098
)
 
$
(4,084
)
 
$
157

 
$
(11,465
)
Limited partners’ net income (loss) per unit
 
(0.62
)
 
(0.74
)
 
(0.53
)
 
0.02

 
(1.64
)
 
(a)
During the fourth quarter, we identified revenues in the amount of $0.3 million associated with proceeds received in connection with COMA reimbursable projects that were incorrectly recognized in the first quarter of 2012 that should have been recognized ratably during each of the succeeding quarters of 2012 for approximately $0.1 million per quarter. In addition, we recorded in the first quarter of 2012 and for the year ended December 31, 2012 out-of-period adjustments amounting to $0.1 million for the correction of immaterial errors associated with additional depreciation expense and selling, general and administrative expense.  Based upon our evaluation of relevant factors, we concluded that these errors were not material to any previously issued and current consolidated financial statements.
(b)
For a definition of gross margin and a reconciliation to its mostly directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 19, "Reporting Segments".
Subsidiary Guarantors
Subsidiary Guarantors
Subsidiary Guarantors

The Partnership filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities, which was effective in the fourth quarter of 2012. The subsidiaries of the Partnership (the "Subsidiaries") are co-registrants with the Partnership, and the registration statement registers guarantees of debt securities by one or more of the Subsidiaries (other than American Midstream Finance Corporation, a 100% owned subsidiary of the Partnership whose sole purpose is to act as co-issuer of such debt securities). The financial position and operations of the co-issuer are minor and therefore have been included with the Parent's financial information. As of June 30, 2012, the Subsidiaries were 100% owned by the Partnership and any guarantees by the Subsidiaries will be full and unconditional. As of December 31, 2012, the Subsidiaries have an investment in the non-guarantor subsidiaries equal to an 87.4% undivided interest in its Chatom system. The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. In the event that more than one of the Subsidiaries provide guarantees of any debt securities issued by the Partnership, such guarantees will constitute joint and several obligations. None of the assets of the Partnership or the Subsidiaries represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended. For purposes of the following condensed consolidating financial information, the Partnership's investments in its Subsidiaries and the guarantor subsidiaries' investment in its 87.4% undivided interest in the Chatom system are presented in accordance with the equity method of accounting. The financial information may not necessarily be indicative of the financial position, results of operations, or cash flows had the subsidiary guarantors operated as independent entities. Condensed consolidating financial information for the Partnership, its combined guarantor subsidiaries and non-guarantor subsidiary as of December 31, 2012 and for the year ended is as follows:

 
Balance Sheet
 
December 31, 2012
 
 Parent
 Guarantor Subsidiaries
 Non-Guarantor Subsidiaries
 Consolidating Adjustments
 Consolidated
 
(in thousands)
Assets
 
 
 
 
 
Current assets
 
 
 
 
 
Cash and cash equivalents
$
1

$
575

$
—

$
—

$
576

Accounts receivable
—

1,612

346

—

1,958

Unbilled revenue
—

18,102

3,410

—

21,512

Risk management assets
—

969

—

—

969

Other current assets
—

2,967

259

—

3,226

Total current assets
1

24,225

4,015

—

28,241

Property, plant and equipment, net
—

165,001

58,818

—

223,819

Investment in subsidiaries
80,164

51,613

—

(131,777
)
—

Other assets, net
—

4,636

—

—

4,636

Total assets
$
80,165

$
245,475

$
62,833

$
(131,777
)
$
256,696

 
 
 
 
 
 
Liabilities and Partners’ Capital
 
 
 
 
 
Current liabilities
 
 
 
 
 
Accounts payable
$
—

$
5,100

$
427

$
—

$
5,527

Accrued gas purchases
—

14,606

2,428

—

17,034

Accrued expenses and other current liabilities
—

9,150

469

—

9,619

Total current liabilities
—

28,856

3,324

—

32,180

Other liabilities
—

8,170

458

—

8,628

Long-term debt
—

128,285

—

—

128,285

Total liabilities
—

165,311

3,782

—

169,093

Partners' capital
 
 
 
 
 
Total partners' capital
80,165

80,164

51,613

(131,777
)
80,165

Noncontrolling interest
—

—

7,438

—

7,438

Total equity
80,165

80,164

59,051

(131,777
)
87,603

Total liabilities and equity
$
80,165

$
245,475

$
62,833

$
(131,777
)
$
256,696







 
Statement of Operations
 
Year ended December 31, 2012
 
 Parent
 Guarantor Subsidiaries
 Non-Guarantor Subsidiaries
 Consolidating Adjustments
 Consolidated
 
(in thousands)
Revenue
$
—

$
185,320

$
25,441

$
(1,167
)
$
209,594

Unrealized gains (loss) on commodity derivatives
—

992

—

—

992

Total revenue
—

186,312

25,441

(1,167
)
210,586

Operating expenses:
 
 
 
 
 
Purchases of natural gas, NGLs and condensate
—

137,144

19,690

(1,167
)
155,667

Direct operating expenses
—

15,299

2,903

—

18,202

Selling, general and administrative expenses
—

14,309

—

—

14,309

Equity compensation expense
—

1,783

—

—

1,783

Depreciation and accretion expense
—

20,604

810

—

21,414

Total operating expenses
—

189,139

23,403

(1,167
)
211,375

Gain (loss) on involuntary conversion of property, plant and equipment
—

(1,021
)
—

—

(1,021
)
Gain (loss) on sale of assets, net
—

128

—

—

128

Operating income (loss)
—

(3,720
)
2,038

—

(1,682
)
Other income (expenses):
 
 
 
 
 
Earnings from consolidated affiliates
(6,509
)
1,781

—

4,728

—

Interest expense
—

(4,570
)
—

—

(4,570
)
Net income (loss)
(6,509
)
(6,509
)
2,038

4,728

(6,252
)
Net income (loss) attributable to noncontrolling interests
—

—

256

—

256

Net income (loss) attributable to the Partnership
$
(6,509
)
$
(6,509
)
$
1,782

$
4,728

$
(6,508
)


 
Statement of Cash Flows
 
Year ended December 31, 2012
 
 Parent
 Guarantor Subsidiaries
 Non-Guarantor Subsidiaries
 Consolidating Adjustments
 Consolidated
 
(in thousands)
Net cash provided (used) in operating activities
$
—

$
16,310

$
2,038

$
—

$
18,348

Cash flows from investing activities
 
 
 
 
 
Cost of acquisition, net of cash acquired
—

(51,377
)
—

—

(51,377
)
Additions to property, plant and equipment
—

(10,870
)
(835
)
—

(11,705
)
Proceeds from disposals of property, plant and equipment
—

128

—

—

128

Proceeds from property damage insurance recoveries
—

527

—

—

527

Net contributions from affiliates
16,057

—

—

(16,057
)
—

Net cash provided (used) in investing activities
16,057

(61,592
)
(835
)
(16,057
)
(62,427
)
Cash flows from financing activities
 
 
 
 
 
Net distributions to affiliates
—

(15,079
)
(978
)
16,057

—

Unit holder contributions
13

—

—

—

13

Unit holder distributions
(16,070
)
—

—

—

(16,070
)
Net distributions to noncontrolling interest owners
—

—

(225
)
—

(225
)
LTIP tax netting unit repurchase
—

(385
)
—

—

(385
)
Deferred debt issuance costs
—

(1,564
)
—

—

(1,564
)
Payments on long-term debt
—

(59,230
)
—

—

(59,230
)
Borrowings on long-term debt
—

121,245

—

—

121,245

Net cash provided (used) in financing activities
(16,057
)
44,987

(1,203
)
16,057

43,784

Net increase (decrease) in cash and cash equivalents
—

(295
)
—

—

(295
)
Cash and cash equivalents
 
 
 
 
 
Beginning of period
1

870

—

—

871

End of period
$
1

$
575

$
—

$
—

$
576

Supplemental cash flow information
 
 
 
 
 
Interest payments
$
—

$
3,185

$
—

$
—

$
3,185

Supplemental non-cash information
 
 
 
 
 
Increase (decrease) in accrued property, plant and equipment
$
—

$
6,968

$
—

$
—

$
6,968

Increase (decrease) in receivables for reimbursable construction in progress projects
$
—

$
141

$
—

$
—

$
141

Liquidity (Notes)
Liquidity
Liquidity
We are required to comply with certain financial covenants and ratios in our credit facility. As of December 31, 2012, the total leverage ratio test, one of the primary financial covenants that we are required to maintain under our credit facility, was not to exceed 4.50 times. At December 31, 2012, our total indebtedness was approximately $130.9 million, which caused our total leverage to EBITDA ratio to be approximately 5.70-to-1. As a result, on December 26, 2012, the Partnership entered into the Third Amendment and Waiver to Credit Agreement, dated as of December 26, 2012 (the “Third Amendment”). The Third Amendment provided for a waiver of the Partnership's compliance with the Consolidated Total Leverage Ratio with respect to the quarter ending December 31, 2012 and for one month thereafter. The Third Amendment also requires the Partnership to provide certain financial and operating information of the Partnership on a monthly basis for 2013 and for any month after 2013 in which the Consolidated Total Leverage Ratio of the Partnership is in excess of 4.00 to 1.00. The remaining material terms and conditions of the senior secured revolving credit facility, including pricing, maturity and covenants, remained unchanged by the Third Amendment.
On January 24, 2013, the Partnership entered into the second waiver to the credit facility that extended the waiver period with respect to the Consolidated Total Leverage Ratio to March 31, 2013 (and subsequently extended to April 16, 2013). Additional covenants during the waiver period included i) total outstanding borrowings under the credit facility shall not exceed $150,000,000; ii) restrictions on certain acquisitions; iii) an increase to the Eurodollar rate by 0.50%; iv) additional fees of 0.125% of the principal amount on each of February 28, 2013 and March 31, 2013; and v) execution of a compliance certificate.
On April 15, 2013, we repaid approximately $12.5 million in outstanding borrowings under the credit agreement and entered into the Fourth Amendment in connection with the ArcLight Transaction (see Note 23 - Subsequent Events for further information). As a result, we had approximately $130 million of outstanding borrowings as of April 15, 2013 and approximately $45 million of available borrowing capacity as a result of the reduction of our borrowing capacity to a total of $175 million as described below. Until June 30, 2013, we will not be required to meet a Consolidated Leverage Ratio under our June 2012 amended credit facility. We expect that we will have availability under our June 2012 amended credit facility and be able to meet the Fourth Amendment's Consolidated Leverage Ratio once it is reinstated on June 30, 2013, but there can be no assurance that will be the case or what that availability might be. Under the terms of the Fourth Amendment:
•
Permits the consummation of the ArcLight Transactions and the PIK Distribution according to the terms of the Amended Partnership Agreement;
•
On October 1, 2013, the aggregate commitments of the lenders under the credit agreement will be reduced to $175 million unless before such date AIM Midstream Holdings makes an equity contribution to the Partnership of $12.5 million that is used to repay borrowings under the credit facility by October 1, 2013;
•
The total outstanding borrowings under the credit agreement are limited to $175 million until such equity contribution by AIM Midstream Holdings and debt repayment has occurred, at which time the maximum permitted borrowings under the credit agreement will be raised to $200 million;
•
The margins relating to our (i) Eurodollar-based loans range from 2.50% to 4.75% depending on the Consolidated Total Leverage ratio then in effect, and (ii) base rate loans range from 1.5% to 3.75%;
•
The definition of Consolidated Total Indebtedness will not include the Series A Preferred Units or certain unsecured surety bonds relating to the High Point Assets;
•
The definition of Consolidated EBITDA (the consolidated EBITDA for the quarters ending June 30 and September 30, 2013 will be annualized for purposes of the Consolidated Total Leverage Ratio) will:
◦
include, on a pro forma basis, the consolidated EBITDA of the High Point Subsidiaries as if they were owned by the Partnership beginning on January 1, 2013;
◦
exclude any insurance proceeds attributable to any event occurring prior to January 1, 2013; and
◦
exclude any one-time, non-recurring transaction expenses of the Partnership incurred in connection with the ArcLight Transactions or the Fourth Amendment.
•
Starting with the quarter ending March 31, 2013 and ending with the quarter ending December 31, 2013, unless the Partnership has permanently canceled at least 20% of the number of subordinated units outstanding on April 15, 2013, the Partnership must reduce any quarterly cash distribution on either its subordinated units or Series A Preferred Units (at the Partnership's election) by an aggregate of $0.4 million per quarter, and such reduction may not be replaced by in-kind distributions of Partnership securities;
•
The maximum Consolidated Total Leverage Ratio permitted as of the end of any fiscal quarter cannot exceed the ratio set forth below:
Fiscal Quarter Ending
Consolidated Total Leverage Ratio
June 30, 2013
5.90:1.00
September 30, 2013
5.90:1.00
December 31, 2013
5.75:1.00
March 31, 2014
5.75:1.00
June 30, 2014
5.75:1.00
September 30, 2014
5.50:1.00
December 31, 2014
5.25:1.00
March 31, 2015 and each fiscal quarter thereafter
4.50:1.00


•
The Partnership agrees to cooperate with and pay the fees and expenses incurred by Bank of America, N.A., the administrative agent for the credit agreement, in connection with its engagement of FTI Consulting to advise and assist it in an assessment of the Partnership's financial condition; and
•
The lenders permanently waived the Partnership's failure to comply with covenants relating to the Partnership's Consolidated Total Leverage Ratio for the quarters ended December 31, 2012 and March 31, 2013. As of April 15, 2013, we had approximately $130 million of outstanding borrowings and approximately $45 million of available borrowing capacity as a result of the reduction of our borrowing capacity to a total of $175 million as described herein. Until June 30, 2013, we will not be required to meet a Consolidated Leverage Ratio under our June 2012 amended credit facility. We expect that we will have availability under our June 2012 amended credit facility and be able to meet the Fourth Amendment's Consolidated Leverage Ratio once it is reinstated on June 30, 2013, but there can be no assurance that will be the case or what that availability might be.

We depend on our June 2012 amended credit facility for future capital needs and may use it to fund a portion of cash distributions to unitholders, as necessary, depending on the level of our operating cashflow. The Partnership believes that the consummation of the ArcLight Transactions will allow it to maintain compliance with the Consolidated Total Leverage to EBTIDA ratio in the Fourth Amendment for a period of at least the next twelve months from the date of the Annual Report on Form 10-K. However, no assurances can be given that the ArcLight Transactions will achieve the necessary ratios or that the contributed business can yield the necessary cash flows. If the foregoing does not occur and we are not able to generate sufficient cash flows from operations to maintain compliance with the financial covenants in the Fourth Amendment and we are not able enter into an agreement to refinance or obtain covenant default waivers the debt could become due and payable upon acceleration by the lenders in our banking group and other agreements with cross-default provisions could become due. In addition, failure to comply with any of the covenants under our Fourth Amendment could adversely affect our ability to fund ongoing operations and growth capital requirements as well as our ability to pay distributions to our unitholders.
Subsequent Events
Subsequent Events
Subsequent Events
Distribution
On January 25, 2013, we announced a distribution of $0.4325 per unit payable on February 14, 2013 to unitholders of record on February 7, 2013.
ArcLight Transactions
Purchase Agreement
On April 15, 2013, AIM Midstream Holdings and High Point entered into a Purchase Agreement, pursuant to which High Point purchased from AIM Midstream Holdings all of the Partnership's 4,526,066 subordinated units and 90% of the limited liability company interests in our general partner. The transactions contemplated by the Purchase Agreement were consummated on April 15, 2013. Of the cash consideration paid to AIM Midstream Holdings, $12.5 million is being held in escrow until its release upon satisfaction of certain conditions.
Contribution Agreement
On April 15, 2013, the Partnership and High Point entered into a Contribution Agreement, pursuant to which High Point contributed to us 100% of the limited liability company interests in certain of its subsidiaries that own midstream assets located in southern and offshore Louisiana (the “High Point Assets”) and $15 million in cash in exchange for 5,142,857 newly issued Series A Preferred Units. Of the $15.0 million cash consideration paid by High Point, approximately $2.5 million was used to pay certain transaction expenses of High Point, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's credit facility in connection with the Fourth Amendment. The transactions contemplated by the Contribution Agreement were consummated on April 15, 2013.
Third Amended & Restated Agreement of Limited Partnership
On April 15, 2013, our general partner amended our partnership agreement with the Third Amended & Restated Agreement of Limited Partnership (the “Amended Partnership Agreement”) providing for the creation and designation of the rights, preferences, terms and conditions of the Series A Preferred Units.
Under the terms of the Amended Partnership Agreement, commencing with the quarter ending on June 30, 2013 and ending with the earlier of the quarter that includes a conversion of the Series A Preferred Units and the quarter beginning October 1, 2014 (the “Coupon Conversion Quarter”), the Series A Preferred Units will each receive quarterly distributions (the “Series A Quarterly Distributions”) in an amount equal to (i) 0.01428571 of additional Series A Preferred Units (subject to customary anti-dilution adjustments) (the "PIK Distribution") and (ii) $0.25 in cash (with the additional Series A Preferred Units and cash portion relating to the quarter ending June 30, 2013 being prorated based on the number of days in such quarter that follow the date on which the Series A Preferred Units were issued). Commencing with the Coupon Conversion Quarter, the Series A Preferred Units will receive the Series A Quarterly Distributions in an amount equal to the greater of (a) the amount of aggregate distributions that would be payable had such Series A Preferred Units converted into Common Units and (b) a fixed rate of 0.023571428 multiplied by the conversion price, which will initially be $17.50 per Series A Preferred Unit (subject to customary anti-dilution adjustments) (the “Conversion Price”), paid in arrears within 45 days after the end of each quarter and prior to distributions with respect to the Common Units and Subordinated units. The record date for the determination of holders entitled to receive Series A Quarterly Distributions will be the same as the record date for determination of Common Unit holders entitled to receive quarterly distributions.
If we fail to pay in full any Series A Quarterly Distribution, the amount of such unpaid distribution will accrue, accumulate and bear interest at a rate of 6.0% per annum from the first day of the quarter immediately following the quarter for which such distribution is due until paid in full.
The Series A Preferred Units have voting rights that are identical to the voting rights of the Common Units and will vote with the Common Units as a single class, with each Series A Preferred Unit entitled to one vote for each Common Unit into which such Series A Preferred Unit is convertible. The Series A Preferred Units also have separate class voting rights on any matter, including a merger, consolidation or business combination, that adversely affects, amends or modifies any of the rights, preferences, privileges or terms of the Series A Preferred Units. Moreover, the general partner may not take any of the following actions without the prior written consent of High Point or any of its affiliates, as long as High Point or such affiliates together hold at least 50% of the Series A Preferred Units and Subordinated Units held by High Point immediately following the issuance of the Series A Preferred Units on April 15, 2013:
•
cause or permit us to invest in, or dispose of, the equity securities or debt securities of any person or otherwise acquire or dispose of any interest in any person, to acquire or dispose of interest in any joint venture or partnership or any similar arrangement with any person, or to acquire or dispose of assets of any person, or to make any capital expenditure (other than maintenance capital expenditures), or to make any loan or advance to any person if the total consideration (including cash, equity issued and debt assumed) paid or payable, or received or receivable, by us exceeds $15,000,000 in any one or series of related transactions or in the aggregate exceeds $50,000,000 in any twelve-month period;
•
cause or permit us to (i) incur, create or guarantee any indebtedness that exceeds (x) $75,000,000 in any one or series of related transactions to the extent the proceeds of such financing are used to refinance our existing indebtedness, or (y) $25,000,000 in any twelve-month period to the extent such indebtedness increases our aggregate indebtedness or (ii) incur, create or guarantee any indebtedness with a yield to maturity exceeding ten percent (10)%;
•
authorize or permit the purchase, redemption or other acquisition of Partnership interests (or any options, rights, warrants or appreciation rights relating to the Partnership interests) by us;
•
select or dismiss, or enter into any employment agreement or amendment of any employment agreement of, the chief executive officer and the chief financial officer of the Partnership or its subsidiary, American Midstream, LLC;
•
enter into any agreement or effect any transaction between us or any of our subsidiaries, on the one hand, and any affiliate of the Partnership or the general partner, on the other hand, other than any transaction in the ordinary course of business and determined by the board of directors of the general partner to be on an arm's length basis; or
•
cause or permit us or any of our subsidiaries to enter into any agreement or make any commitment to do any of the foregoing.
The Series A Preferred Units are convertible in whole or in part into Common Units at any time after January 1, 2014 or, prior to that date, with the consent of the required lenders under the June 2012 amended credit agreement, at the holder's election. The number of Common Units into which a Series A Preferred Unit is convertible will be an amount equal to (i) the sum of $17.50 and all accrued and accumulated but unpaid distributions, divided by (ii) the Conversion Price, which will initially be $17.50 per Series A Preferred Unit (subject to customary anti-dilution adjustments) (the “Conversion).
In the event that the Partnership issues, sells or grants any Common Units or convertible securities at an indicative per Common Unit price that is less than $17.50 (subject to customary anti-dilution adjustments), then the Conversion Rate will be adjusted according to a formula to provide an increase in the number of Common Units into which Series A Preferred Units are convertible.
Prior to the consummation of any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of Common Units are to receive securities, cash or other assets (a “Partnership Event”), we are obligated to make an irrevocable written offer, subject to consummation of the Partnership Event, to each holder of Series A Preferred Units to redeem all (but not less than all) of such holder's Series A Preferred Units for a price per Series A Preferred Unit payable in cash equal to the greater of:
•
the sum of $17.50 and all accrued and accumulated but unpaid distributions for each Series A Preferred Unit; and
•
an amount equal to the product of:
(i) the number of Common Units into which each Series A Preferred Unit is convertible; and
(ii) the sum of:
(A) the cash consideration per Common Unit to be paid to the holders of Common Units pursuant to the Partnership Event, plus
(B) the fair market value per Common Unit of the securities or other assets to be distributed to the holders of the Common Units pursuant to the Partnership Event.
Upon receipt of such a redemption offer from us, each holder of Series A Preferred Units may elect to receive such cash amount or a preferred security issued by the person surviving or resulting from such Partnership Event and containing provisions substantially equivalent to the provisions set forth in the Amended Partnership Agreement with respect to the Series A Preferred Units without material abridgement.
Upon any liquidation and winding up of the Partnership or the sale of substantially all of the assets of the Partnership, the holders of Series A Preferred Units generally will be entitled to receive, in preference to the holders of any of the Partnership's other securities, an amount equal to the sum of the $17.50 multiplied by the number of Series A Preferred Units owned by such holders, plus all accrued but unpaid distributions on such Series A Preferred Units.
Change of Control of the General Partner and the Partnership
Through the acquisition of the 90% interest in our general partner, the acquisition of all of our 4,526,066 subordinated units and the issuance of the 5,142,857 Series A Units, High Point acquired control of our general partner and a majority of our outstanding limited partnership interests.
Organization and Basis of Presentation (Policies)
Nature of Business 
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, fractionating, marketing and transportation services primarily 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.
Our interstate natural gas pipeline assets transport natural gas through the Federal Energy Regulatory Commission (“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 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 
Basis of presentation
The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2012 and 2011, and results of operations, comprehensive income, changes in partners' capital and noncontrolling interest, and cash flows for the years ended December 31, 2012, 2011 and 2010.
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 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. We have made reclassifications to amounts reported in prior period consolidated financial statements to conform with current year presentation. These reclassifications did not have an impact on net income for the period previously reported.
The results of operations for acquisitions accounted for as business combinations have been included in the consolidated financial statements since their respective acquisition dates (see Note 2).
Consolidation Policy 
Consolidation policy
Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold an undivided interest in the Burns Point gas processing facility in which we are responsible for our proportionate share of the costs and expenses of the facility. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of this undivided interest. In July 2012, the Partnership acquired a 87.4% undivided interest in the Chatom Processing and Fractionation facility (the "Chatom system"). Our consolidated financial statements reflect the accounts of the Chatom system since acquisition, and the interests in the Chatom system held by non-affiliated working interest owners are reflected as noncontrolling interests in the Partnership's consolidated financial statements.
Use of Estimates 
Use of estimates
When preparing financial statements in conformity with GAAP, 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 (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.
Accounting for Regulated Operations 
Accounting for regulated operations
Certain of our natural gas pipelines are subject to regulations by FERC. 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 be recorded under GAAP for our regulated entities. As of December 31, 2012 and 2011, we had no such material regulatory assets or liabilities.
Revenue Recognition and the Estimation of Revenues and Cost of Natural Gas 
Revenue recognition and the estimation of revenues and cost of purchases
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, natural gas liquids ("NGLs") or condensates that are purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating or transportation, we record those fees separately in revenues. We have the following arrangements:

Fee-based
Under these arrangements, we generally are paid a fixed fee for gathering and transporting natural gas. Fee-based revenues, which are included in sales of natural gas, NGLs and condensate, are recorded when services have been provided, and collectability of the revenue is reasonably assured.
Percent-of-proceeds, or POP
Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas and NGLs at market prices. Where we provide processing services at the processing plants that we own, or obtain processing service for our own account under our own elective processing arrangements we typically retain and sell a percentage of the residue natural gas and resulting NGLs. We recognize percent-of-proceeds contract revenue, which is included in sales of natural gas, NGLs and condensate, when the natural gas, NGLs or condensate is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.
Fixed-margin
Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. We recognize revenue from fixed-margin contracts, which is included in sales of natural gas, NGLs and condensate, when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred and collectability of the revenue is reasonably assured.
Firm transportation
Under arrangements to provide firm transportation service, 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 they utilize the capacity. In most cases, the shipper also pays a variable use charge with respect to quantities actually transported by us. Firm transportation revenue is recorded when products are delivered, services have been provided and collectability of the revenue is reasonably assured.
 
Interruptible transportation
Under arrangements to provide interruptible transportation service, we are only obligated to transport natural gas nominated by the shipper to the extent we have available capacity. For this service the shipper pays no reservation charge but pays a variable use charge for quantities actually shipped. Interruptible transportation revenue is recorded when products are delivered, services have been provided and collectability of revenue is reasonably assured.
Interest in the Burns Point Plant
We account for our interest in the Burns Point Plant using the proportionate consolidation method. Under this method, we include in our consolidated statement of operations our value of plant revenues taken in-kind and plant expenses reimbursed to the operator.
Cash and Cash Equivalents 
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 
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. As of December 31, 2012 and 2011, the Partnership recorded no allowances for losses on accounts receivable.
Inventory 
Inventory
Inventory includes NGL product inventory. The Partnership records all product inventories at the lower of cost or market (“LCM”), which is determined on a weighted average basis and included within Other current assets on the consolidated balance sheets.
Operational Balancing Agreements and Natural Gas Imbalances 
Operational balancing agreements and natural gas imbalances
To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through future receipt or delivery of natural gas. Natural gas imbalances are recorded as gas imbalances and classified within other current assets or other current liabilities on our consolidated balance sheets based on the market value.
Property, Plant and Equipment 
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 assets.
The Partnership calculated the fair value of net assets acquired from Quantum Resources Management, LLC in July 2012 with the assistance of an independent third party valuation firm. These valuations were performed primarily using a discounted cash flow model that included certain market assumptions related to future throughput discount rates. We created the projections and reviewed the calculations, assumptions and valuation methodology used to determine the fair value of the assets acquired. We determined the final fair values to assign to the assets and liabilities in determining the purchase price allocation and had sole responsibility for those items in the financial statements.
Impairment of Long-Lived Assets 
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 business, 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 years ended December 31, 2012, 2011 and 2010.
Income Taxes 
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 tax expense results from the enactment of state income tax laws by the State of Texas that apply to entities organized as partnerships and is included in selling, general and administrative expenses in the consolidated statements of operations. The Texas margin tax is computed on our modified gross margin and was not significant for each of the years ended December 31, 2012, 2011 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 requirement 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 Enciornmental Liabilities 
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 from the remediation of existing environmental contamination caused by past operations that do not benefit future period 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 regulation 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 cost or new information. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record 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 in more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.
We have legal obligations requiring us to decommission our offshore pipeline systems at retirement. In certain rate jurisdictions, we are permitted to include annual charges for removal costs in the regulated cost of service rates we charge our customers. Additionally, legal obligations exist for a minority of our offshore 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 of 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 exist to reasonably estimate potential settlement dates and methods.
Asset Retirement Obligations (AROs) 
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 amount of estimated cash flows or their timing.
Derivative Financial Instruments 
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 sheet 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 or trading purposes.
The price assumptions we use to value our derivative financial instruments can affect net income for each period. We use published market price information where available, or quotations from over-the-counter, or OTC, market makers to find executable bids and offers. The valuations also reflect the potential impact of 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 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.
Comprehensive Income (Loss) 
Comprehensive income (loss)
The Partnership’s other comprehensive income (loss) is comprised of adjustments to other post-retirement plan assets and liabilities. See Note 16, "Post-Employment Benefits".
Unit-Based Employee Compensation 
Unit-based employee compensation
We award unit-based compensation to management, non-management 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 equity compensation expense over the requisite service period of each award. See Note 15, "Long-Term Incentive Plan".
Fair Value Measurements 
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 use various assumptions and methods in estimating the fair values of our financial instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of our various credit facilities approximate fair value, because the interest rates on these facilities are variable.
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 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities;
•
Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets that are either directly or indirectly observable; and
•
Level 3 – Inputs are unobservable and considered significant to fair value measurement.
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 
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 extinguishment include any associated unamortized debt issue costs.
Noncontrolling Interest 
Noncontrolling interest

Noncontrolling interest represents the noncontrolling interest holders' proportionate share of the equity of the Chatom system.  Noncontrolling interest is adjusted for the noncontrolling interest holders' proportionate share of the earnings or losses.  Management reports noncontrolling interest in the Chatom system in the financial statements pursuant to paragraph ASC No. 810-10-65-1.  The 12.6% noncontrolling interest is held by non-affiliated working interest owners.
Limited Partners' Net Income (Loss) Per Unit 
Limited partners’ net income (loss) per unit
We compute limited partners’ net income (loss) per unit by dividing our limited partners’ interest in net income (loss) by the weighted average number of units outstanding during the period. The overall computation, presentation and disclosure of our limited partners’ net income (loss) per unit are made in accordance with the FASB Accounting Standards Codification (ASC) Topic 260 “Earnings per Share”.
Acquisitions (Tables)
Unaudited pro forma consolidated information of the partnership, adjusted for the acquisition of the chatom assets 
The following table presents unaudited pro forma consolidated information of the Partnership, adjusted for the acquisition of the Chatom system, as if the acquisition had occurred on January 1, 2011:
 
Year Ended
 
December 31,
 
2012
 
2011
 
(unaudited, in thousands)
Revenue
$
246,342

 
$
296,387

Net income (loss)
$
(4,319
)
 
$
(10,411
)
Limited partners’ net income (loss) per unit
$
(0.49
)
 
$
(1.53
)
The following table presents unaudited pro forma consolidated information of the Partnership, adjusted for the acquisition of the Interest in the Plant, as if the acquisition had occurred on January 1, 2010:

 
Year Ended
 
December 31,
 
2011
 
2010
 
(unaudited, in thousands)
Revenue
$
249,908

 
$
216,585

Net income (loss)
$
(11,741
)
 
$
(8,844
)
Limited partners’ net income (loss) per unit
$
(1.65
)
 
$
(1.70
)
Schedule of recognized identified assets acquired and liabilities assumed 
The following table presents the fair value of consideration transferred to acquire our Interest in the Plant and the amounts of identified assets acquired and liabilities assumed at the acquisition date:
 
(in thousands)
Cash consideration:
$
35,500

Recognized amounts of identifiable assets acquired and liabilities assumed:
 
Property, plant and equipment
$
36,065

Liabilities assumed
—

Total identifiable net assets:
$
36,065

Bargain purchase (gain)
(565
)
 
$
35,500

The following table presents the fair value of consideration transferred to acquire the Chatom system and the amounts of identified assets acquired and liabilities assumed at the acquisition date, as well as the fair value of the 12.6% noncontrolling interest in the Chatom system at the acquisition date:
 
 
 
(in thousands)
Cash consideration:
 
 
$
51,377

Recognized amounts of identifiable assets acquired and liabilities assumed:
 
Unbilled revenue
 
 
$
4,535

Property, plant and equipment
58,279

Asset retirement cost
452

Accounts payable
 
 
(399
)
Accrued gas purchases
(3,631
)
Asset retirement obligations
(452
)
Noncontrolling interest
(7,407
)
Total identifiable net assets:
$
51,377

Concentration of Credit Risk and Trade Accounts Receivable (Tables)
Percentage of revenue earned from major customers
The following table summarizes the percentage of revenue earned from those customers that exceed 10% or greater of the Partnership's consolidated revenue in the consolidated statement of operations for the each of the periods presented below:
 
For the year ended December 31,
 
2012
 
2011
 
2010
Customer A
30
%
 
41
%
 
25
%
Customer B
14
%
 
18
%
 
30
%
Customer C
13
%
 
15
%
 
11
%
Other
43
%
 
26
%
 
34
%
Total
100
%
 
100
%
 
100
%
The following table summarizes the percentage of revenue earned from those customers in each segment that exceed 10% or greater of the Partnership's consolidated segment revenue for the each of the periods presented below:

 
For the year ended December 31,
 
2012
 
2011
 
2010
Gathering and Processing:
 
 
 
 
 
Customer A
40
%
 
55
%
 
34
%
Customer B
12
%
 
16
%
 
30
%
Customer C
11
%
 
—
%
 
—
%
Customer D
—
%
 
—
%
 
10
%
Other
37
%
 
29
%
 
26
%
Total
100
%
 
100
%
 
100
%
Transmission:
 
 
 
 
 
Customer E
22
%
 
22
%
 
31
%
Customer F
50
%
 
57
%
 
43
%
Customer G
10
%
 
—
%
 
10
%
Other
18
%
 
21
%
 
16
%
Total
100
%
 
100
%
 
100
%
Other Current Assets (Tables)
Schedule of other current assets
 
 
December 31,
 
 
2012
 
2011
 
 
(in thousands)
Other receivables
 
$
452

 
$
663

Construction, operating and maintenance agreement (“COMA”)
 
—

 
623

Prepaid insurance—current portion
 
458

 
567

Other prepaid amounts
 
451

 
508

Gas imbalances receivable
 
932

 
852

NGL inventory
 
931

 
96

Other current assets
 
2

 
14

 
 
$
3,226

 
$
3,323

Derivatives (Tables)
Fair value associated with commodity derivative instruments 
As of December 31, 2012 and 2011, the fair value associated with our commodity derivative instruments were recorded in our consolidated balance sheets, under the captions as follows:
 
(in thousands)
 
Gross Derivative Assets
 
Gross Derivative Liabilities
Balance Sheet Classification
 
December 31, 2012
 
December 31, 2011
 
December 31, 2012
 
December 31, 2011
 
 
 
 
 
 
 
 
 
Risk management assets
 
$
1,889

 
$
—

 
$
(920
)
 
$
—

Risk management assets - long term
 
—

 
—

 
—

 
—

Total
 
$
1,889

 
$
—

 
$
(920
)
 
$
—

 
 
 
 
 
 
 
 
 
Risk management liabilities
 
$
—

 
$
456

 
$
—

 
$
(635
)
Risk management liabilities - long term
 
—

 
—

 
—

 
—

Total
 
$
—

 
$
456

 
$
—

 
$
(635
)
Realized and unrealized gains (losses) with commodity and interst rate derivative instruments 
For the years ended December 31, 2012, 2011 and 2010, the realized and unrealized gains (losses) associated with our commodity and interest rate derivative instruments were recorded in our consolidated statements of operations, under the captions as follows:
 
(in thousands)
 
Gain (loss) on derivatives
Statement of Operations Classification
 
Realized
 
Unrealized
2012
 

Revenue
 
$
2,408

 
$
—

Unrealized gain (loss) on commodity derivatives
 
—

 
992

Total
 
$
2,408

 
$
992

2011
 

 

Revenue
 
$
(1,911
)
 
$
—

Realized gain (loss) on early termination of commodity derivatives
 
(2,998
)
 
—

Unrealized gain (loss) on commodity derivatives
 
—

 
(541
)
Total
 
$
(4,909
)
 
$
(541
)
2010
 
 
 
 
Revenue
 
$
—

 
$
—

Unrealized gain (loss) on commodity derivatives
 
—

 
(308
)
Interest expense
 
—

 
(77
)
Total
 
$
—

 
$
(385
)
Fair Value Measurement (Tables)
Fair value of financial instruments 
Fair Value of Financial Instruments
The following table sets forth by level within the fair value hierarchy, our net derivative assets (liabilities) that were measured at fair value on a recurring basis as of December 31, 2012 and 2011:
 
 
Carrying
Amount
 
Estimated Fair Value
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
 
(in thousands)
 
 
Commodity derivative asset (liability), net
 
 
 
 
 
 
 
 
 
December 31, 2012
$
969

 
$
—

 
$
969

 
$
—

 
$
969

December 31, 2011
$
(179
)
 
$
—

 
$
—

 
$
(179
)
 
$
(179
)
Changes in level three fair value measurements 
Contracts classified as Level 3 are valued using internally developed price inputs and curves constructed as a result of the long dated nature of the transactions or the illiquidity of the market points. Contracts classified as Level 2 are valued using inputs and curves that are supported and available from public markets to the extent that the markets or the relevant settlement periods are liquid:
 
 
Year Ended
 
December 31,
 
2012
 
2011
 
(in thousands)
Fair value asset (liability), beginning of period
$
(179
)
 
$
—

Realized gain (loss) on early termination of commodity derivatives
—

 
(2,998
)
Realized gain (loss) on expiration of commodity put contract
—

 
(308
)
Unrealized gain (loss) on commodity derivatives
992

 
(541
)
Purchases
156

 
670

Settlements
—

 
2,998

Transfers out of Level 3 (a)
(969
)
 
—

Fair value asset (liability), end of period
$
—

 
$
(179
)
(a)Amounts transferred out are reflected at fair value as of the end of the period

Property, Plant and Equipment, Net (Tables)
Property, plant, and equipment, net
Property, plant and equipment, net, as of December 31, 2012 and 2011 were as follows:
 
 
 
 
 
December 31,
 
 
Useful Life
 
2012
 
2011
 
 
 
 
(in thousands)
Land
 
 
 
$
2,254

 
$
41

Construction in progress
 
 
 
5,053

 
3,380

Buildings and improvements
 
4 to 40
 
1,432

 
1,490

Processing and treating plants
 
8 to 40
 
98,106

 
49,396

Pipelines
 
5 to 40
 
163,447

 
146,788

Compressors
 
4 to 20
 
8,957

 
7,437

Equipment
 
8 to 20
 
4,785

 
1,198

Computer software
 
5
 
1,950

 
1,500

Total property, plant and equipment
 
 
 
285,984

 
211,230

Accumulated depreciation
 
 
 
(62,165
)
 
(40,999
)
Property, plant and equipment, net
 
 
 
$
223,819

 
$
170,231

Asset Retirement Obligation (Tables)
Schedule of reconciliation of the beginning and ending aggregate carrying amount of ARO liabilities
The following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for years ended December 31, 2012 and 2011, respectively:

 
Year Ended
 
December 31,
 
2012
 
2011
 
(in thousands)
Balance at beginning of period
$
8,093

 
$
7,249

Additions
452

 
872

Reductions
—

 
(920
)
Expenditures
(258
)
 
(501
)
Accretion expense
32

 
1,393

Balance at end of period
$
8,319

 
$
8,093

For the periods indicated, total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements were:
 
 
Year ended
December 31,
 
 
2012
 
2011
 
2010
 
 
(in thousands)
Operating leases
 
$
941

 
$
803

 
$
757

ARO
 
32

 
1,393

 
1,191

 
 
$
973

 
$
2,196

 
$
1,948

Other Assets, Net (Tables)
Other assets, net
Other assets, net, were as follows:
 
 
 
December 31,
 
 
2012
 
2011
 
 
(in thousands)
Deferred financing costs
 
$
3,394

 
$
2,545

Other post retirement benefit plan assets, net
 
1,080

 
966

Prepaid amounts—long term
 
97

 
139

Security deposits
 
65

 
57

Other
 
—

 
—

 
 
$
4,636

 
$
3,707

Accrued Expenses and Other Current Liabilities (Tables)
Schedule of accrued expenses and other current liabilities
Accrued expenses and other current liabilities were as follows:
 
 
 
December 31,
 
 
2012
 
2011
 
 
(in thousands)
Deferred revenue—short term
 
$
288

 
$
2,314

Accrued salaries
 
944

 
1,542

Accrued expenses
 
6,519

 
953

Construction operating and maintenance agreement deposits
 
30

 
710

Gas imbalances payable
 
971

 
1,200

Contract obligations—short term
 
—

 
240

Accrued interest payable
 
724

 
123

Other
 
143

 
4

 
 
$
9,619

 
$
7,086

Other Liabilities (Tables)
Schedule of other liabilities
Other liabilities were as follows: 
 
 
December 31,
 
 
2012
 
2011
 
 
(in thousands)
Deferred revenue—long term
 
$
245

 
$
351

Asset retirement obligations
 
8,319

 
8,093

Contract obligations—long term
 
—

 
88

Other deferred expenses
 
64

 
80

 
 
$
8,628

 
$
8,612

Long-Term Debt (Tables)
Outstanding borrowings under the credit facility
Our outstanding borrowings under the credit facility at December 31, 2012 and 2011, respectively, were: 
 
 
December 31,
 
 
2012
 
2011
 
 
(in thousands)
Revolving loan facility
 
$
128,285

 
$
66,270

Partners' Capital (Tables)
Schedule for number of units outstanding
The number of units outstanding was as follows:
 
 
 
December 31,
 
 
2012
 
2011
 
2010
 
 
(in thousands)
Limited partner common units
 
4,639

 
4,561

 
5,363

Limited partner subordinated units
 
4,526

 
4,526

 
—

General partner units
 
185

 
185

 
109

Net Income (Loss) per Limited and General Partner Unit (Tables)
Basic and diluted net income (loss) per general partner unit and limited partner unit
We determined basic and diluted net income (loss) per general partner unit and limited partner unit as follows, in thousands except per unit amounts:
 
 
 
Year Ended
December 31,
 
 
2012
 
2011
 
2010
Net (loss) attributable to general partner and limited partners
 
$
(6,508
)
 
$
(11,698
)
 
$
(8,644
)
Weighted average general partner and limited partner units outstanding(a)(b)
 
9,298

 
7,137

 
5,199

General partner and limited partner (loss) per unit (basic and diluted)
 
$
(0.70
)
 
$
(1.64
)
 
$
(1.66
)
Net (loss) attributable to limited partners
 
$
(6,379
)
 
$
(11,465
)
 
$
(8,471
)
Weighted average limited partner units outstanding(a)(b)
 
9,113

 
6,997

 
5,099

Limited partners’ net (loss) per unit (basic and diluted)
 
$
(0.70
)
 
$
(1.64
)
 
$
(1.66
)
Net (loss) attributable to general partner
 
$
(129
)
 
$
(233
)
 
$
(173
)
Weighted average general partner units outstanding
 
185

 
140

 
99

General partner net (loss) per unit (basic and diluted)
 
$
(0.70
)
 
$
(1.66
)
 
$
(1.75
)
 
(a)
Includes unvested phantom units with DERs, which are considered participating securities, of 205,864 as of December 31, 2010. The DER’s were eliminated on June 9, 2011. There were no such unvested phantom units with DERs at December 31, 2012 and 2011.
(b)
Gives effect to the reverse unit split as described in Note 13, “Partners’ Capital”.
Long-Term Incentive Plan (Tables)
Summarizes unit-based awards
The following table summarizes our unit-based awards for each of the periods indicated, in units:
 
 
 
Year Ended
 
 
December 31,
 
 
2012
 
2011
 
2010
 
 
 
 
 
 
 
Outstanding at beginning of period
 
162,860

 
205,864

 
175,236

Granted
 
38,595

 
19,414

 
74,437

Forfeited
 
(12,517
)
 
—

 
—

Vested
 
(98,000
)
 
(62,418
)
 
(43,809
)
Outstanding at end of period
 
90,938

 
162,860

 
205,864

Fair value per unit
 
$14.70 to $21.40

 
$14.70 to $19.69

 
$14.70 to $16.15

Post-Employment Benefits (Tables)
Schedule of changes in the benefit obligation, the fair value of the plan assets and the recorded asset or liability of the OPEB Plan using the accrual method 
The tables below detail the changes in the benefit obligation, the fair value of the plan assets and the recorded asset or liability of the OPEB Plan using the accrual method.
 
 
 
Year ended
December 31,
 
 
2012
 
2011
 
2010
 
 
 
 
(in thousands)
 
 
Change in benefit obligation
 
 
 
 
 
 
Obligation, beginning of period
 
$
466

 
$
869

 
$
734

Service cost
 
4

 
3

 
10

Interest cost
 
18

 
22

 
43

Actuarial (gain) loss
 
22

 
(367
)
 
112

Benefits paid
 
(38
)
 
(61
)
 
(30
)
Benefit obligation, end of period
 
$
472

 
$
466

 
$
869

Change in plan assets
 
 
 
 
 
 
Fair value of plan assets, beginning of period
 
$
1,432

 
$
1,319

 
$
1,174

Actual return on plan assets
 
84

 
99

 
61

Employer’s contributions
 
90

 
90

 
113

Benefits paid
 
(54
)
 
(76
)
 
(29
)
Fair value of plan assets, end of period
 
$
1,552

 
$
1,432

 
$
1,319

Funded status
 
 
 
 
 
 
Funded status
 
$
1,080

 
$
966

 
$
450

Schedule of amounts of plan assets recognized in consolidated balance sheets 
The weighted average asset allocation of our OPEB Plan at the measurement date by asset category, which are all classified as Level 1 investments, are as follows: 
 
 
December 31,
 
 
2012
 
2011
 
2010
Fixed income (a)
 
72.2
%
 
72.1
%
 
70.7
%
Cash and short term assets (b)
 
27.8
%
 
27.9
%
 
29.3
%
Total
 
100.0
%
 
100.0
%
 
100.0
%
 
(a)
United States government securities, municipal corporate bonds and notes and asset backed securities
(b)
Cash and securities with maturities of one year or less
The amounts of plan assets recognized in our consolidated balance sheets were as follows:
 
 
 
December 31,
 
 
2012
 
2011
 
2010
 
 
(in thousands)
Other assets
 
$
1,080

 
$
966

 
$
450

 
 
$
1,080

 
$
966


$
450

Schedule of components of net periodic benefit cost and other amounts recognized in other comprehensive income 
Components of Net Periodic Benefit Cost and Other amounts Recognized in Other Comprehensive Income
 
 
 
December 31,
 
 
2012
 
2011
 
2010
 
 
(in thousands)
Net Periodic (Benefit) Cost
 
 
 
 
 
 
Service cost
 
$
4

 
$
3

 
$
10

Interest cost
 
18

 
22

 
43

Expected return on plan assets
 
(67
)
 
(60
)
 
(53
)
Amortization of net (gain) loss
 
(43
)
 
(47
)
 
—

Net periodic (benefit) cost
 
$
(88
)
 
$
(82
)
 
$
—

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
 
 
 
 
 
 
Net loss (gain)
 
64

 
(359
)
 
(10
)
Total recognized in other comprehensive income
 
64

 
(359
)
 
(10
)
Total recognized in net periodic benefit cost and other comprehensive income
 
$
(24
)
 
$
(441
)
 
$
(10
)
Schedule of assumptions made in measuremnet of the projected benefit obligations or assets of the OPEB Plan 
The assumptions made in measurement of the projected benefit obligations or assets of the OPEB Plan were as follows:
 
 
 
December 31,
 
 
2012
 
2011
 
2010
Discount rate
 
3.42
%
 
3.96
%
 
5.50
%
Expected return on plan assets
 
4.50
%
 
4.50
%
 
4.50
%
Schedule of benefits expected to be paid in each of the next five fiscal years 
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:
 
For the year ending
(in thousands)
2013
$
41

2014
35

2015
35

2016
32

2017
30

Five years thereafter
135

Commitments and Contingencies (Tables)
Future non-cancelable commitments related to certain contractual obligations 
Future non-cancelable commitments related to certain contractual obligations as of December 31, 2012 are presented below:
 
 
 
Payments Due by Period 
 
 
Total
 
2013
 
2014
 
2015
 
2016
 
Thereafter
 
 
(in thousands)
Operating leases and service contracts
 
$
2,576

 
$
661

 
$
450

 
$
428

 
$
179

 
$
858

ARO
 
8,319

 
—

 
—

 
—

 
7,860

 
459

Total
 
$
10,895

 
$
661

 
$
450

 
$
428

 
$
8,039

 
$
1,317

Total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements 
The following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for years ended December 31, 2012 and 2011, respectively:

 
Year Ended
 
December 31,
 
2012
 
2011
 
(in thousands)
Balance at beginning of period
$
8,093

 
$
7,249

Additions
452

 
872

Reductions
—

 
(920
)
Expenditures
(258
)
 
(501
)
Accretion expense
32

 
1,393

Balance at end of period
$
8,319

 
$
8,093

For the periods indicated, total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements were:
 
 
Year ended
December 31,
 
 
2012
 
2011
 
2010
 
 
(in thousands)
Operating leases
 
$
941

 
$
803

 
$
757

ARO
 
32

 
1,393

 
1,191

 
 
$
973

 
$
2,196

 
$
1,948

Reporting Segments (Tables)
Segment information for the periods 
The following tables set forth our segment information for the periods indicated:

 
Year ended
 
December 31,
 
2012
 
2011
 
Gathering
and
Processing
 
Transmission
 
Total
 
Gathering
and
Processing
 
Transmission
 
Total
 
(in thousands)
Revenue
$
157,065

 
$
52,529

 
$
209,594

 
$
181,517

 
$
66,765

 
$
248,282

Segment gross margin (a)
37,241

 
13,313

 
50,554

 
32,142

 
13,737

 
45,879

Realized gain (loss) on early termination of commodity derivatives (b)
—

 
—

 
—

 
(2,998
)
 
—

 
(2,998
)
Unrealized gain (loss) on commodity derivatives (b)
992

 
—

 
992

 
(541
)
 
—

 
(541
)
Direct operating expenses
13,171

 
5,031

 
18,202

 
7,636

 
5,220

 
12,856

Selling, general and administrative expenses
 
 
 
 
14,309

 
 
 
 
 
10,794

Advisory services agreement termination fee
 
 
 
 
—

 
 
 
 
 
2,500

Transaction expenses
 
 
 
 
 
 
 
 
 
 
282

Equity compensation expense
 
 
 
 
1,783

 
 
 
 
 
3,357

Depreciation and accretion expense
 
 
 
 
21,414

 
 
 
 
 
20,705

Gain (loss) on acquisition of assets
 
 
 
 
—

 
 
 
 
 
565

Gain (loss) on involuntary conversion of property, plant and equipment
 
 
 
 
(1,021
)
 
 
 
 
 
—

Gain (loss) on sale of assets, net
 
 
 
 
128

 
 
 
 
 
399

Interest expense
 
 
 
 
4,570

 
 
 
 
 
4,508

Net income (loss)
 
 
 
 
(6,252
)
 
 
 
 
 
(11,698
)
Less: Net income (loss) attributable to noncontrolling interests
 
 
 
 
256

 
 
 
 
 
—

Net income (loss) attributable to the Partnership
 
 
 
 
$
(6,508
)
 
 
 
 
 
$
(11,698
)
 
 
Year ended
 
December 31,
 
2011
 
2010
 
Gathering
and
Processing
 
Transmission
 
Total
 
Gathering
and
Processing
 
Transmission
 
Total
 
(in thousands)
Revenue
$
181,517

 
$
66,765

 
$
248,282

 
$
158,763

 
$
53,485

 
$
212,248

Segment gross margin (a)
32,142

 
13,737

 
45,879

 
24,595

 
13,524

 
38,119

Realized gain (loss) on early termination of commodity derivatives (b)
(2,998
)
 
—

 
(2,998
)
 
—

 
—

 
—

Unrealized gain (loss) on commodity derivatives (b)
(541
)
 
—

 
(541
)
 
(308
)
 
—

 
(308
)
Direct operating expenses
7,636

 
5,220

 
12,856

 
7,721

 
4,466

 
12,187

Selling, general and administrative expenses
 
 
 
 
10,794

 
 
 
 
 
7,120

Advisory services agreement termination fee
 
 
 
 
2,500

 
 
 
 
 
—

Transaction expenses
 
 
 
 
282

 
 
 
 
 
303

Equity compensation expense
 
 
 
 
3,357

 
 
 
 
 
1,734

Depreciation and accretion expense
 
 
 
 
20,705

 
 
 
 
 
20,013

Gain (loss) on acquisition of assets
 
 
 
 
565

 
 
 
 
 
—

Gain (loss) on sale of assets, net
 
 
 
 
399

 
 
 
 
 
—

Interest expense
 
 
 
 
4,508

 
 
 
 
 
5,406

Net income (loss)
 
 
 
 
$
(11,698
)
 
 
 
 
 
$
(8,644
)

(a)
Segment gross margin for our Gathering and Processing segment consists of revenue less purchases of natural gas, NGLs and condensate and COMA. Segment gross margin for our Transmission segment consists of revenue, less purchases of natural gas and COMA. 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. Effective October 1, 2012, we changed our segment gross margin measure to exclude construction, operating and maintenance agreement (“COMA”) income. For the year ended December 31, 2012, $0.7 million and $2.7 million in COMA income was excluded from our Gathering and Processing segment gross margin and our Transmission segment gross margin, respectively.

(b)
Effective January 1, 2011, we changed our segment gross margin measure to exclude unrealized non-cash mark-to-market adjustments related to our commodity derivatives. For the years ended December 31, 2012 and 2011, $1.0 million and $(0.5) million in unrealized gains (losses) on commodity derivatives were excluded from our Gathering and Processing segment gross margin. Effective April 1, 2011, we changed our segment gross margin measure to exclude realized early termination costs on commodity derivatives. For the year ended December 31, 2011, $(3.0) million in realized gains (losses) on the early termination of commodity derivatives were excluded from our Gathering and Processing segment gross margin.

Percentage of revenue earned from major customers 
The following table summarizes the percentage of revenue earned from those customers that exceed 10% or greater of the Partnership's consolidated revenue in the consolidated statement of operations for the each of the periods presented below:
 
For the year ended December 31,
 
2012
 
2011
 
2010
Customer A
30
%
 
41
%
 
25
%
Customer B
14
%
 
18
%
 
30
%
Customer C
13
%
 
15
%
 
11
%
Other
43
%
 
26
%
 
34
%
Total
100
%
 
100
%
 
100
%
The following table summarizes the percentage of revenue earned from those customers in each segment that exceed 10% or greater of the Partnership's consolidated segment revenue for the each of the periods presented below:

 
For the year ended December 31,
 
2012
 
2011
 
2010
Gathering and Processing:
 
 
 
 
 
Customer A
40
%
 
55
%
 
34
%
Customer B
12
%
 
16
%
 
30
%
Customer C
11
%
 
—
%
 
—
%
Customer D
—
%
 
—
%
 
10
%
Other
37
%
 
29
%
 
26
%
Total
100
%
 
100
%
 
100
%
Transmission:
 
 
 
 
 
Customer E
22
%
 
22
%
 
31
%
Customer F
50
%
 
57
%
 
43
%
Customer G
10
%
 
—
%
 
10
%
Other
18
%
 
21
%
 
16
%
Total
100
%
 
100
%
 
100
%
Quarterly Financial Data (Tables)
Quarterly financial data
Summarized unaudited quarterly financial data for 2012 and 2011 are as follows:
 
 
 
First
Quarter (a)
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 
Total (a)
 
 
(in thousands expect per unit amounts)
Year ended December 31, 2012
 
 
 
 
 
 
 
 
 
 
Total revenues
 
$
47,711

 
$
46,060

 
$
56,324

 
$
60,491

 
$
210,586

Gross margin (b)
 
12,974

 
11,694

 
13,367

 
12,519

 
50,554

Operating income (loss)
 
2,448

 
3,152

 
(2,525
)
 
(4,757
)
 
(1,682
)
Net income (loss)
 
$
1,691

 
$
2,327

 
$
(4,026
)
 
$
(6,244
)
 
$
(6,252
)
Net income (loss) attributable to noncontrolling interest
 
—

 
—

 
249

 
7

 
256

Net income (loss) attributable to the Partnership
 
$
1,691

 
$
2,327

 
$
(4,275
)
 
$
(6,251
)
 
$
(6,508
)
General partner’s interest in net income (loss)
 
34

 
46

 
(85
)
 
(124
)
 
(129
)
Limited partners’ interest in net income (loss)
 
$
1,657

 
$
2,281

 
$
(4,190
)
 
$
(6,127
)
 
$
(6,379
)
Limited partners’ net income (loss) per unit
 
0.18

 
0.25

 
(0.46
)
 
(0.67
)
 
(0.70
)
Year ended December 31, 2011
 
 
 
 
 
 
 
 
 
 
Total revenues
 
$
63,765

 
$
65,634

 
$
57,958

 
$
57,386

 
$
244,743

Gross margin
 
12,312

 
10,617

 
9,646

 
13,304

 
45,879

Operating income (loss)
 
(2,246
)
 
(2,901
)
 
(3,375
)
 
1,332

 
(7,190
)
Net income (loss)
 
$
(3,510
)
 
$
(4,182
)
 
$
(4,167
)
 
$
161

 
$
(11,698
)
General partner’s interest in net income (loss)
 
(70
)
 
(84
)
 
(83
)
 
4

 
(233
)
Limited partners’ interest in net income (loss)
 
$
(3,440
)
 
$
(4,098
)
 
$
(4,084
)
 
$
157

 
$
(11,465
)
Limited partners’ net income (loss) per unit
 
(0.62
)
 
(0.74
)
 
(0.53
)
 
0.02

 
(1.64
)
 
(a)
During the fourth quarter, we identified revenues in the amount of $0.3 million associated with proceeds received in connection with COMA reimbursable projects that were incorrectly recognized in the first quarter of 2012 that should have been recognized ratably during each of the succeeding quarters of 2012 for approximately $0.1 million per quarter. In addition, we recorded in the first quarter of 2012 and for the year ended December 31, 2012 out-of-period adjustments amounting to $0.1 million for the correction of immaterial errors associated with additional depreciation expense and selling, general and administrative expense.  Based upon our evaluation of relevant factors, we concluded that these errors were not material to any previously issued and current consolidated financial statements.
(b)
For a definition of gross margin and a reconciliation to its mostly directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 19, "Reporting Segments".
Subsidiary Guarantors (Tables)
Schedule of Condensed Consolidating Balance Sheet 
 
Balance Sheet
 
December 31, 2012
 
 Parent
 Guarantor Subsidiaries
 Non-Guarantor Subsidiaries
 Consolidating Adjustments
 Consolidated
 
(in thousands)
Assets
 
 
 
 
 
Current assets
 
 
 
 
 
Cash and cash equivalents
$
1

$
575

$
—

$
—

$
576

Accounts receivable
—

1,612

346

—

1,958

Unbilled revenue
—

18,102

3,410

—

21,512

Risk management assets
—

969

—

—

969

Other current assets
—

2,967

259

—

3,226

Total current assets
1

24,225

4,015

—

28,241

Property, plant and equipment, net
—

165,001

58,818

—

223,819

Investment in subsidiaries
80,164

51,613

—

(131,777
)
—

Other assets, net
—

4,636

—

—

4,636

Total assets
$
80,165

$
245,475

$
62,833

$
(131,777
)
$
256,696

 
 
 
 
 
 
Liabilities and Partners’ Capital
 
 
 
 
 
Current liabilities
 
 
 
 
 
Accounts payable
$
—

$
5,100

$
427

$
—

$
5,527

Accrued gas purchases
—

14,606

2,428

—

17,034

Accrued expenses and other current liabilities
—

9,150

469

—

9,619

Total current liabilities
—

28,856

3,324

—

32,180

Other liabilities
—

8,170

458

—

8,628

Long-term debt
—

128,285

—

—

128,285

Total liabilities
—

165,311

3,782

—

169,093

Partners' capital
 
 
 
 
 
Total partners' capital
80,165

80,164

51,613

(131,777
)
80,165

Noncontrolling interest
—

—

7,438

—

7,438

Total equity
80,165

80,164

59,051

(131,777
)
87,603

Total liabilities and equity
$
80,165

$
245,475

$
62,833

$
(131,777
)
$
256,696

Schedule of Condensed Consolidating Statements of Operations 
 
Statement of Operations
 
Year ended December 31, 2012
 
 Parent
 Guarantor Subsidiaries
 Non-Guarantor Subsidiaries
 Consolidating Adjustments
 Consolidated
 
(in thousands)
Revenue
$
—

$
185,320

$
25,441

$
(1,167
)
$
209,594

Unrealized gains (loss) on commodity derivatives
—

992

—

—

992

Total revenue
—

186,312

25,441

(1,167
)
210,586

Operating expenses:
 
 
 
 
 
Purchases of natural gas, NGLs and condensate
—

137,144

19,690

(1,167
)
155,667

Direct operating expenses
—

15,299

2,903

—

18,202

Selling, general and administrative expenses
—

14,309

—

—

14,309

Equity compensation expense
—

1,783

—

—

1,783

Depreciation and accretion expense
—

20,604

810

—

21,414

Total operating expenses
—

189,139

23,403

(1,167
)
211,375

Gain (loss) on involuntary conversion of property, plant and equipment
—

(1,021
)
—

—

(1,021
)
Gain (loss) on sale of assets, net
—

128

—

—

128

Operating income (loss)
—

(3,720
)
2,038

—

(1,682
)
Other income (expenses):
 
 
 
 
 
Earnings from consolidated affiliates
(6,509
)
1,781

—

4,728

—

Interest expense
—

(4,570
)
—

—

(4,570
)
Net income (loss)
(6,509
)
(6,509
)
2,038

4,728

(6,252
)
Net income (loss) attributable to noncontrolling interests
—

—

256

—

256

Net income (loss) attributable to the Partnership
$
(6,509
)
$
(6,509
)
$
1,782

$
4,728

$
(6,508
)
Schedule of Condensed Consolidating Statements of Cash Flow 
 
Statement of Cash Flows
 
Year ended December 31, 2012
 
 Parent
 Guarantor Subsidiaries
 Non-Guarantor Subsidiaries
 Consolidating Adjustments
 Consolidated
 
(in thousands)
Net cash provided (used) in operating activities
$
—

$
16,310

$
2,038

$
—

$
18,348

Cash flows from investing activities
 
 
 
 
 
Cost of acquisition, net of cash acquired
—

(51,377
)
—

—

(51,377
)
Additions to property, plant and equipment
—

(10,870
)
(835
)
—

(11,705
)
Proceeds from disposals of property, plant and equipment
—

128

—

—

128

Proceeds from property damage insurance recoveries
—

527

—

—

527

Net contributions from affiliates
16,057

—

—

(16,057
)
—

Net cash provided (used) in investing activities
16,057

(61,592
)
(835
)
(16,057
)
(62,427
)
Cash flows from financing activities
 
 
 
 
 
Net distributions to affiliates
—

(15,079
)
(978
)
16,057

—

Unit holder contributions
13

—

—

—

13

Unit holder distributions
(16,070
)
—

—

—

(16,070
)
Net distributions to noncontrolling interest owners
—

—

(225
)
—

(225
)
LTIP tax netting unit repurchase
—

(385
)
—

—

(385
)
Deferred debt issuance costs
—

(1,564
)
—

—

(1,564
)
Payments on long-term debt
—

(59,230
)
—

—

(59,230
)
Borrowings on long-term debt
—

121,245

—

—

121,245

Net cash provided (used) in financing activities
(16,057
)
44,987

(1,203
)
16,057

43,784

Net increase (decrease) in cash and cash equivalents
—

(295
)
—

—

(295
)
Cash and cash equivalents
 
 
 
 
 
Beginning of period
1

870

—

—

871

End of period
$
1

$
575

$
—

$
—

$
576

Supplemental cash flow information
 
 
 
 
 
Interest payments
$
—

$
3,185

$
—

$
—

$
3,185

Supplemental non-cash information
 
 
 
 
 
Increase (decrease) in accrued property, plant and equipment
$
—

$
6,968

$
—

$
—

$
6,968

Increase (decrease) in receivables for reimbursable construction in progress projects
$
—

$
141

$
—

$
—

$
141

Liquidity (Tables)
Schedule of Consolidated Total Leverage Ratios Permitted
The maximum Consolidated Total Leverage Ratio permitted as of the end of any fiscal quarter cannot exceed the ratio set forth below:
Fiscal Quarter Ending
Consolidated Total Leverage Ratio
June 30, 2013
5.90:1.00
September 30, 2013
5.90:1.00
December 31, 2013
5.75:1.00
March 31, 2014
5.75:1.00
June 30, 2014
5.75:1.00
September 30, 2014
5.50:1.00
December 31, 2014
5.25:1.00
March 31, 2015 and each fiscal quarter thereafter
4.50:1.00
Organization and Basis of Presentation (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended 12 Months Ended
Dec. 31, 2012
counties
Dec. 31, 2012
Midla system [Member]
mi
Dec. 31, 2012
AlaTenn system [Member]
mi
Dec. 31, 2012
Chatom processing, gathering and fractionation plant [Member]
Jul. 2, 2012
Chatom processing, gathering and fractionation plant [Member]
Dec. 31, 2012
Subsequent Event [Member]
ArcLight [Member]
ft
mi
Apr. 15, 2013
Subsequent Event [Member]
ArcLight [Member]
High Point [Member]
Apr. 15, 2013
Series A [Member]
Issuance of Preferred Units [Member]
Subsequent Event [Member]
High Point [Member]
Apr. 15, 2013
High Point [Member]
Series A [Member]
Issuance of Preferred Units [Member]
Subsequent Event [Member]
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
 
 
 
 
 
 
 
 
 
Gathering pipeline (miles)
 
370 
295 
 
 
700 
 
 
 
Counties in which entity operates, Alabama, Mississippi, and Tennessee (counties)
8 
 
 
 
 
 
 
 
 
Acquired interest (percent)
 
 
 
 
87.40% 
 
90.00% 
 
 
Contributed capital
 
 
 
 
 
 
 
 
$ 15 
Preferred units issued (shares)
 
 
 
 
 
 
 
5,142,857 
5,142,857 
Number of natural gas collection receipt points (receipt points)
 
 
 
 
 
75 
 
 
 
Water depth of natural gas collection receipt points, maximum (feet)
 
 
 
 
 
1,000 
 
 
 
Highly liquid investments, less than
3 months 
 
 
 
 
 
 
 
 
Property, plant and equipment useful life greater than
1 year 
 
 
 
 
 
 
 
 
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners
12.60% 
 
 
12.60% 
 
 
 
 
 
Acquisitions (Consideration Transferred) (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended 12 Months Ended
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2012
Chatom processing, gathering and fractionation plant [Member]
mi
Jul. 2, 2012
Chatom processing, gathering and fractionation plant [Member]
Dec. 1, 2011
Plant operator, enterprise gas processing, llc [Member]
Dec. 31, 2012
Burns point plant [Member]
MMcf
Dec. 1, 2011
Burns point plant [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash consideration
 
 
 
 
 
 
 
 
 
 
 
 
$ 51,400 
 
$ 35,500 
$ 35,500 
Property, plant and equipment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
36,065 
 
Liabilities assumed
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0 
 
Total identifiable net assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
36,065 
 
Bargain purchase (gain)
 
 
 
 
 
 
 
 
0 
(565)
0 
 
 
 
(565)
 
Cash consideration:
 
 
 
 
 
 
 
 
 
 
 
 
51,377 
 
 
 
Unbilled revenue
 
 
 
 
 
 
 
 
 
 
 
 
4,535 
 
 
 
Property, plant and equipment
223,819 
 
 
 
170,231 
 
 
 
223,819 
170,231 
 
 
58,279 
 
 
 
Asset retirement cost
(8,319)
 
 
 
(8,093)
 
 
 
(8,319)
(8,093)
(7,249)
 
452 
 
 
 
Accounts payable
(5,527)
 
 
 
(837)
 
 
 
(5,527)
(837)
 
 
(399)
 
 
 
Accrued gas purchases
(17,034)
 
 
 
(14,715)
 
 
 
(17,034)
(14,715)
 
 
(3,631)
 
 
 
Asset retirement obligation
 
 
 
 
 
 
 
 
 
 
 
 
(452)
 
 
 
Non-controlling interest
(7,438)
 
 
 
0 
 
 
 
(7,438)
0 
 
 
(7,407)
 
 
 
Total identifiable net assets
 
 
 
 
 
 
 
 
 
 
 
 
51,377 
 
 
 
Acquired interest (percent)
 
 
 
 
 
 
 
 
 
 
 
 
87.40% 
50.00% 
 
50.00% 
Quivira system currently supplies inlet volume to the plant
 
 
 
 
 
 
 
 
 
 
 
 
 
 
85.00% 
 
Current capacity of plant
 
 
 
 
 
 
 
 
 
 
 
 
 
 
165 
 
Property plant and equipment in useful life
 
 
 
 
 
 
 
 
 
 
 
 
 
 
40 years 
 
Chatom assets location
 
 
 
 
 
 
 
 
 
 
 
15 
 
 
 
 
Current capacity of the refrigeration processing plant
 
 
 
 
 
 
 
 
 
 
 
25 
 
 
 
 
Fractionation unit
 
 
 
 
 
 
 
 
 
 
 
1,900 
 
 
 
 
Long-ton per day sulfur recovery
 
 
 
 
 
 
 
 
 
 
 
160 
 
 
 
 
Gas gathering system
 
 
 
 
 
 
 
 
 
 
 
29 
 
 
 
 
Non-controlling interest
12.60% 
 
 
 
 
 
 
 
12.60% 
 
 
12.60% 
 
 
 
 
Assumed cost of capital
 
 
 
 
 
 
 
 
9.25% 
 
 
 
 
 
 
 
Inflationary cost
 
 
 
 
 
 
 
 
2.50% 
 
 
 
 
 
 
 
Effective income tax rate, continuing operations
 
 
 
 
 
 
 
 
35.00% 
 
 
 
 
 
 
 
Effective income tax rate reconciliation, state and local income taxes
 
 
 
 
 
 
 
 
6.50% 
 
 
 
 
 
 
 
Revenues
60,491 
56,324 
46,060 
47,711 1
57,386 
57,958 
65,634 
63,765 1
210,586 1
244,743 1
211,940 
25,200 
 
 
 
 
Net income (loss) attributable to the partnership
$ (6,251)
$ (4,275)
$ 2,327 
$ 1,691 1
$ 161 
$ (4,167)
$ (4,182)
$ (3,510)1
$ (6,508)1
$ (11,698)1
$ (8,644)
$ 2,000 
 
 
 
 
[1] During the fourth quarter, we identified revenues in the amount of $0.3 million associated with proceeds received in connection with COMA reimbursable projects that were incorrectly recognized in the first quarter of 2012 that should have been recognized ratably during each of the succeeding quarters of 2012 for approximately $0.1 million per quarter. In addition, we recorded in the first quarter of 2012 and for the year ended December 31, 2012 out-of-period adjustments amounting to $0.1 million for the correction of immaterial errors associated with additional depreciation expense and selling, general and administrative expense. Based upon our evaluation of relevant factors, we concluded that these errors were not material to any previously issued and current consolidated financial statements.(b)For a definition of gross margin and a reconciliation to its mostly directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 19, "Reporting Segments".
Acquisitions (Pro Forma Information) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Chatom processing, gathering and fractionation plant [Member]
 
 
 
Business Combination, Pro Forma Information [Abstract]
 
 
 
Revenue
$ 246,342 
$ 296,387 
 
Net income (loss)
(4,319)
(10,411)
 
Limited partners’ net income (loss) per unit
(0.49)
(1.53)
 
Burns Point Plant [Member]
 
 
 
Business Combination, Pro Forma Information [Abstract]
 
 
 
Revenue
 
249,908 
216,585 
Net income (loss)
 
$ 11,741 
$ 8,844 
Limited partners’ net income (loss) per unit
(1.65)
(1.70)
 
Concentration of Credit Risk and Trade Accounts Receivable (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
100.00% 
100.00% 
100.00% 
Allowance for doubtful accounts receivable
$ 0 
$ 0 
$ 0 
Customer A [Member]
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
30.00% 
41.00% 
25.00% 
Customer B [Member]
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
14.00% 
18.00% 
30.00% 
Cusotmer C [Member]
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
13.00% 
15.00% 
11.00% 
Customer Other [Member]
 
 
 
Revenue, Major Customer
 
 
 
Entity-wide revenue by major customer, percentage
43.00% 
26.00% 
34.00% 
Other Current Assets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Other Current Assets [Abstract]
 
 
Other receivables
$ 452 
$ 663 
Construction, operating and maintenance agreement (“COMA”)
0 
623 
Prepaid insurance—current portion
458 
567 
Other prepaid amounts
451 
508 
Gas imbalances receivable
932 
852 
NGL inventory
931 
96 
Other current assets
2 
14 
Other current assets
$ 3,226 
$ 3,323 
Derivatives (Fair Value of Commodity Derivatives) (Details) (Commodity derivatives [Member], USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Risk management assets and Risk management liabilities
 
 
Derivative asset, gross derivative asset
$ 1,889 
$ 0 
Derivative asset, gross derivative liabilities
(920)
0 
Derivative liability, gross derivative assets
0 
456 
Derivative liability, gross derivative liabilities
0 
(635)
Risk Management Assets [Member]
 
 
Risk management assets and Risk management liabilities
 
 
Derivative asset, gross derivative asset
1,889 
0 
Derivative asset, gross derivative liabilities
(920)
0 
Risk Management Assets - Long Term [Member]
 
 
Risk management assets and Risk management liabilities
 
 
Derivative asset, gross derivative asset
0 
0 
Derivative asset, gross derivative liabilities
0 
0 
Risk Management Liabilities [Member]
 
 
Risk management assets and Risk management liabilities
 
 
Derivative liability, gross derivative assets
0 
456 
Derivative liability, gross derivative liabilities
0 
(635)
Risk Management Liabilities - Long Term [Member]
 
 
Risk management assets and Risk management liabilities
 
 
Derivative liability, gross derivative assets
0 
0 
Derivative liability, gross derivative liabilities
$ 0 
$ 0 
Derivatives (Realized and Unrealized Gains (Losses)) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Derivatives, Fair Value [Line Items]
 
 
 
Gain (loss) on derivatives, realized
$ 0 1
$ (2,998)1
$ 0 1
Gain (loss) on derivatives, unrealized
992 1
(541)1
(308)1
Commodity derivatives [Member]
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Gain (loss) on derivatives, realized
2,408 
(4,909)
0 
Gain (loss) on derivatives, unrealized
992 
(541)
(385)
Commodity derivatives [Member] |
Revenue [Member]
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Gain (loss) on derivatives, realized
2,408 
(1,911)
0 
Gain (loss) on derivatives, unrealized
0 
0 
0 
Commodity derivatives [Member] |
Realized Gain (Loss) Derivatives [Member]
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Gain (loss) on derivatives, realized
 
(2,998)
 
Gain (loss) on derivatives, unrealized
 
0 
 
Commodity derivatives [Member] |
Unrealized Gain (Loss) on Derivatives [Member]
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Gain (loss) on derivatives, realized
0 
0 
0 
Gain (loss) on derivatives, unrealized
992 
(541)
(308)
Commodity derivatives [Member] |
Interest Expense [Member]
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Gain (loss) on derivatives, realized
 
 
0 
Gain (loss) on derivatives, unrealized
 
 
$ (77)
Derivatives (Details Textual) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
gal
Derivative Instruments and Hedging Activities Disclosure [Abstract]
 
Aggregate notional volume of our commodity derivative
15,100,000 
Interest rate caps with a notional amount up to
$ 25.0 
Fixed maximum rate
4.00% 
Fair Value Measurement (Fair Value of Financial Instruments) (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Quantitative Information about Level 3 Fair Value Measurements
 
 
Estimated Fair Value
$ 969 
$ (179)
Carrying Reported Amount Fair Value Disclosure [Member]
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
Carrying Amount
969 
(179)
Level 1 [Member] |
Estimate of Fair Value, Fair Value Disclosure [Member]
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
Estimated Fair Value
0 
0 
Level 2 [Member] |
Estimate of Fair Value, Fair Value Disclosure [Member]
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
Estimated Fair Value
969 
0 
Level 3 [Member] |
Estimate of Fair Value, Fair Value Disclosure [Member]
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
Estimated Fair Value
$ 0 
$ (179)
Fair Value Measurement (Changes in Level 3 Fair Value Measurements) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Changes in Level 3 Fair Value Measurements
 
 
 
Fair value asset (liability), beginning of period
$ (179)
$ 0 
 
Realized gain (loss) on early termination of commodity derivatives
0 1
(2,998)1
0 1
Realized gain (loss) on expiration of commodity put contract
0 
(308)
 
Unrealized gain (loss) on commodity derivatives
992 
(541)
(308)
Transfers out of Level 3
(969)2
0 2
 
Fair value asset (liability), end of period
0 
(179)
0 
Purchase [Member]
 
 
 
Changes in Level 3 Fair Value Measurements
 
 
 
Purchases
156 
670 
 
Settlements [Member]
 
 
 
Changes in Level 3 Fair Value Measurements
 
 
 
Settlements
$ 0 
$ 2,998 
 
Fair Value Measurement (Details Textual) (USD $)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Fair Value Disclosures [Abstract]
 
 
 
Transfers out of Level 3
$ 969,000 1
$ 0 1
 
Monthly swap settlements
$ 2,400,000 
$ (1,600,000)
$ 0 
Property, Plant and Equipment, Net (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2012
Land [Member]
Dec. 31, 2011
Land [Member]
Dec. 31, 2012
Construction in progress [Member]
Dec. 31, 2011
Construction in progress [Member]
Dec. 31, 2012
Buildings and improvements [Member]
Dec. 31, 2011
Buildings and improvements [Member]
Dec. 31, 2012
Processing and treating plants [Member]
Dec. 31, 2011
Processing and treating plants [Member]
Dec. 31, 2012
Pipelines [Member]
Dec. 31, 2011
Pipelines [Member]
Dec. 31, 2012
Compressors [Member]
Dec. 31, 2011
Compressors [Member]
Dec. 31, 2012
Equipment [Member]
Dec. 31, 2011
Equipment [Member]
Dec. 31, 2012
Computer software [Member]
Dec. 31, 2011
Computer software [Member]
Dec. 31, 2012
Minimum [Member]
Buildings and improvements [Member]
Dec. 31, 2012
Minimum [Member]
Processing and treating plants [Member]
Dec. 31, 2012
Minimum [Member]
Pipelines [Member]
Dec. 31, 2012
Minimum [Member]
Compressors [Member]
Dec. 31, 2012
Minimum [Member]
Equipment [Member]
Dec. 31, 2012
Maximum [Member]
Buildings and improvements [Member]
Dec. 31, 2012
Maximum [Member]
Processing and treating plants [Member]
Dec. 31, 2012
Maximum [Member]
Pipelines [Member]
Dec. 31, 2012
Maximum [Member]
Compressors [Member]
Dec. 31, 2012
Maximum [Member]
Equipment [Member]
Dec. 31, 2012
Maximum [Member]
Computer software [Member]
Dec. 31, 2012
Ala Tenn System [Member]
Dec. 31, 2011
Midla System [Member]
Property, Plant and Equipment, Net [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property plant and equipment gross
$ 285,984 
$ 211,230 
$ 2,254 
$ 41 
$ 5,053 
$ 3,380 
$ 1,432 
$ 1,490 
$ 98,106 
$ 49,396 
$ 163,447 
$ 146,788 
$ 8,957 
$ 7,437 
$ 4,785 
$ 1,198 
$ 1,950 
$ 1,500 
 
 
 
 
 
 
 
 
 
 
 
$ 26,100 
$ 24,000 
Accumulated depreciation
(62,165)
(40,999)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$ 223,819 
$ 170,231 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property plant and equipment in useful life
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4 years 
8 years 
5 years 
4 years 
8 years 
40 years 
40 years 
40 years 
20 years 
20 years 
5 years 
 
 
Property, Plant and Equipment, Net (Issuance Proceeds) (Details) (USD $)
12 Months Ended
Dec. 31, 2012
Property, Plant and Equipment [Abstract]
 
Insurance settlements receivable
$ 0.5 
Impairment of long-lived assets held-for-use
$ 1,500,000 
Asset Retirement Obligation (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended 1 Months Ended 12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Aug. 31, 2011
West Cameron Pipeline [Member]
Dec. 31, 2011
West Cameron Pipeline [Member]
Asset Retirement Obligaiton [Line Items]
 
 
 
 
 
Balance at beginning of period
$ 8,319 
$ 8,093 
$ 7,249 
 
 
Additions
452 
872 
 
 
 
Reductions
0 
(920)
 
 
400 
Expenditures
(258)
 
 
(500)
(501)
Accretion expense
32 
1,393 
1,200 
 
 
Balance at end of period
$ 8,093 
$ 7,249 
 
 
 
Other Assets, Net (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Line of Credit Facility [Line Items]
 
 
Deferred financing costs
$ 3,394 
$ 2,545 
Other post retirement benefit plan assets, net
1,080 
966 
Prepaid amounts—long term
97 
139 
Security deposits
65 
57 
Other
0 
0 
Other assets, noncurrent
4,636 
3,707 
Revolving Credit Facility [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Deferred financing costs
$ 700 
$ 1,300 
Accrued Expenses and Other Current Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Payables and Accruals [Abstract]
 
 
Deferred revenue—short term
$ 288 
$ 2,314 
Accrued salaries
944 
1,542 
Accrued expenses
6,519 
953 
Construction operating and maintenance agreement deposits
30 
710 
Gas imbalances payable
971 
1,200 
Contract obligations—short term
0 
240 
Accrued interest payable
724 
123 
Other
143 
4 
Accrued expenses and other current liabilities
$ 9,619 
$ 7,086 
Other Liabilities Other Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Other Liabilities Disclosure [Abstract]
 
 
Deferred revenue—long term
$ 245 
$ 351 
Asset retirement obligations
8,319 
8,093 
Contract obligations—long term
0 
88 
Other deferred expenses
64 
80 
Other liabilities, noncurrent
$ 8,628 
$ 8,612 
Long-Term Debt (Outstanding Borrowings) (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Debt Instrument [Line Items]
 
 
Revolving loan facility
$ 128,285 
$ 66,270 
Revolving Credit Facility [Member]
 
 
Debt Instrument [Line Items]
 
 
Revolving loan facility
$ 128,285 
$ 66,270 
Long-Term Debt (Textual) (Details) (USD $)
12 Months Ended 12 Months Ended 12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2012
Federal Funds [Member]
Dec. 31, 2012
Eurodollar [Member]
Dec. 31, 2012
Eurodollar [Member]
Minimum [Member]
Dec. 31, 2012
Eurodollar [Member]
Maximum [Member]
Dec. 31, 2012
Third Amendment [Member]
Jun. 27, 2012
Revolving Credit Facility [Member]
Jun. 26, 2012
Revolving Credit Facility [Member]
Aug. 2, 2011
Revolving Credit Facility [Member]
Jun. 27, 2012
Revolving Credit Facility [Member]
Accordian Feature [Member]
Aug. 2, 2011
Revolving Credit Facility [Member]
Accordian Feature [Member]
Dec. 31, 2012
Revolving Credit Facility [Member]
Third Amendment [Member]
Federal Funds [Member]
Dec. 31, 2012
Revolving Credit Facility [Member]
Third Amendment [Member]
Eurodollar [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revolving credit facility, borrowing capacity
 
 
 
 
 
 
 
 
 
 
$ 100,000,000 
 
$ 50,000,000 
 
 
Maximum outstanding borrowings under credit facility
 
 
 
 
 
 
 
 
250,000,000 
 
150,000,000 
50,000,000 
 
 
 
Former credit facility
 
 
 
 
 
 
 
 
200,000,000 
100,000,000 
 
 
 
 
 
Interest rate minimum
2.25% 
 
 
 
 
1.25% 
 
 
 
 
 
 
 
 
 
Interest margin maximum
3.50% 
 
 
 
 
 
2.50% 
 
 
 
 
 
 
 
 
Basis spread on variable rate
 
 
 
0.50% 
 
 
 
 
 
 
 
 
 
 
 
Description of variable rate basis
 
 
 
Federal Funds Rate 
Eurodollar Rate 
 
 
 
 
 
 
 
 
Eurodollar rate 
 
Adjusted EBITDA
4.50 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Facility fee (percent)
 
 
 
 
1.00% 
 
 
 
 
 
 
 
 
 
0.50% 
Commitment fee on undrawn portion of the revolving loan
0.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt, weighted average interest rate
4.09% 
6.71% 
7.48% 
 
 
 
 
 
 
 
 
 
 
 
 
Leverage ratio requirement
4.50 
 
 
 
 
 
 
4.00 
 
 
 
 
 
 
 
Total indebtedness
130,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest minimum coverage ratio
2.50 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of credit outstanding amount
2,600,000 
600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt issuance cost
$ 4,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ratio of indebtedness to net capital
5.70 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Partners' Capital (Units Outstanding) (Details)
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Limited partner common units
9,165,000 
9,087,000 
 
General partner units
185,000 
185,000 
 
AIM Midstream Holdings No. of units outstanding [Member]
 
 
 
Limited partner common units
4,639,000 
4,561,000 
5,363,000 
Limited partner subordinated units
4,526,000 
4,526,000 
0 
General partner units
185,000 
185,000 
109,000 
Partners Capital (Details Textual) (USD $)
In Millions, except Share data, unless otherwise specified
6 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 3 Months Ended
Jun. 30, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Jul. 31, 2011
Dec. 31, 2012
General Partner Interest [Member]
Dec. 31, 2012
First Target Distribution [Member]
Dec. 31, 2012
First Target Distribution [Member]
General Partner Interest [Member]
Dec. 31, 2012
Second Target Distribution [Member]
Dec. 31, 2012
Second Target Distribution [Member]
General Partner Interest [Member]
Dec. 31, 2012
Third Target Distribution [Member] [Member]
Dec. 31, 2012
Third Target Distribution [Member] [Member]
General Partner Interest [Member]
Dec. 31, 2012
Thereafter Target Distribution [Member]
General Partner Interest [Member]
Dec. 31, 2012
Cash Distribution [Member]
Dec. 31, 2012
Conversion Requirement One [Member]
Cash Distribution [Member]
Dec. 31, 2012
Conversion Requirement Two [Member]
Cash Distribution [Member]
Dec. 31, 2012
IPO [Member]
Jul. 31, 2011
IPO [Member]
Common Units [Member]
Dec. 31, 2012
First Target Distribution [Member]
Dec. 31, 2012
First Target Distribution [Member]
Cash Distribution [Member]
Dec. 31, 2012
Second Target Distribution [Member]
Dec. 31, 2012
Second Target Distribution [Member]
Cash Distribution [Member]
Dec. 31, 2012
Third Target Distribution [Member] [Member]
Dec. 31, 2012
Third Target Distribution [Member] [Member]
Cash Distribution [Member]
Dec. 31, 2012
Thereafter Target Distribution [Member]
Apr. 15, 2013
Subsequent Event [Member]
High Point [Member]
Partnership Interest [Member]
AIM Midstream Holdings [Member]
Apr. 15, 2013
Issuance of Preferred Units [Member]
Series A [Member]
Subsequent Event [Member]
High Point [Member]
Subsidiary, Sale of Stock [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
General partner interest
 
 
 
 
 
2.00% 
 
2.00% 
 
15.00% 
 
25.00% 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Limited partner interest
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
98.00% 
 
85.00% 
 
75.00% 
 
50.00% 
 
 
IPO common units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,750,000 
 
 
 
 
 
 
 
 
 
Price per unit
 
 
 
 
$ 21 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Underwriting discounts and commissions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 4.9 
 
 
 
 
 
 
 
 
 
 
Offering expenses
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.2 
 
 
 
 
 
 
 
 
 
 
Structuring fee
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.6 
 
 
 
 
 
 
 
 
 
 
Proceeds from our initial public offering
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
69.1 
 
 
 
 
 
 
 
 
 
 
Percentage of agregate limited partnership
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
97.10% 
 
 
 
 
 
 
 
 
 
 
Holdings converted to common units
 
801,139 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
General partner units
 
185,000 
185,000 
 
 
108,718 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earned and paid (usd per unit)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 1.65 
$ 2.475 
 
 
 
$ 0.47438 
 
$ 0.51563 
 
$ 0.61875 
 
 
 
Minimum quarterly distribution annualized (percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
150.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
Incentive distribution right, after minimum auarterly distributions (percent)
 
 
 
 
 
 
13.00% 
 
23.00% 
 
48.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Partnership cancellation of subordinated units (percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
90.00% 
 
Contributed capital
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15 
Preferred units issued (shares)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5,142,857 
Partners Capital (Textual) [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Holdings reverse split in to common units
 
0.485 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Aggregate common units
 
 
 
 
5,327,205 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Holdings converted to common units
 
801,139 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Holdings converted to subordinated units
 
4,526,066 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reverse split up results to ownership of aggregate common units
 
50,946 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of agragate limited partner interest
100.00% 
0.90% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Aggregate holding of phantom units
 
209,824 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common units contributed to general partners as a capital contribution
 
76,019 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exchange of general partner units in order to maintain general partners interest
 
76,019 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distributions
 
16.1 
9.8 
11.8 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Special distribution to participants in long term incentive plan
 
$ 33.7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss) per Limited and General Partner Unit (Details) (USD $)
In Thousands, except Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Net Income (Loss) per Limited and General Partner Unit [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Net income (loss) attributable to the partnership
$ (6,251)
$ (4,275)
$ 2,327 
$ 1,691 1
$ 161 
$ (4,167)
$ (4,182)
$ (3,510)1
$ (6,508)1
$ (11,698)1
$ (8,644)
Weighted average general partner and limited partner units outstanding
 
 
 
 
 
 
 
 
9,298,000 2 3
7,137,000 2 3
5,199,000 2 3
General partner and limited partner (loss) per unit (basic and diluted)
 
 
 
 
 
 
 
 
$ (0.70)
$ (1.64)
$ (1.66)
Net (loss) attributable to limited partners
(6,127)
(4,190)
2,281 
1,657 1
157 
(4,084)
(4,098)
(3,440)1
(6,379)1
(11,465)1
(8,471)
Weighted average limited partner units outstanding
 
 
 
 
 
 
 
 
9,113,000 2 3
6,997,000 2 3
5,099,000 2 3
Limited partners’ net (loss) per unit (basic and diluted)
 
 
 
 
 
 
 
 
(0.70)
(1.64)
(1.66)
Net (loss) attributable to general partner
$ (124)
$ (85)
$ 46 
$ 34 1
$ 4 
$ (83)
$ (84)
$ (70)1
$ (129)1
$ (233)1
$ (173)
Weighted average general partner units outstanding
 
 
 
 
 
 
 
 
185,000 
140,000 
99,000 
General partner net (loss) per unit (basic and diluted)
 
 
 
 
 
 
 
 
(0.70)
(1.66)
(1.75)
Phantom Share Units (PSUs) [Member]
 
 
 
 
 
 
 
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Unvested phantom units
 
 
 
 
 
 
 
 
 
 
205,864 
[1] During the fourth quarter, we identified revenues in the amount of $0.3 million associated with proceeds received in connection with COMA reimbursable projects that were incorrectly recognized in the first quarter of 2012 that should have been recognized ratably during each of the succeeding quarters of 2012 for approximately $0.1 million per quarter. In addition, we recorded in the first quarter of 2012 and for the year ended December 31, 2012 out-of-period adjustments amounting to $0.1 million for the correction of immaterial errors associated with additional depreciation expense and selling, general and administrative expense. Based upon our evaluation of relevant factors, we concluded that these errors were not material to any previously issued and current consolidated financial statements.(b)For a definition of gross margin and a reconciliation to its mostly directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 19, "Reporting Segments".
Long-Term Incentive Plan (Unit-based Awards) (Details)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding
 
 
 
Outstanding at beginning of period
162,860 
205,864 
175,236 
Granted
38,595 
19,414 
74,437 
Forfeited
(12,517)
0 
0 
Vested
(98,000)
(62,418)
(43,809)
Outstanding at end of period
90,938 
162,860 
205,864 
Minimum [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding
 
 
 
Fair value per unit
14.70 
14.70 
14.70 
Maximum [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding
 
 
 
Fair value per unit
21.40 
19.69 
16.15 
Long Term Incentive Plan (Textual) (Details) (USD $)
3 Months Ended 12 Months Ended
Jun. 30, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Jul. 11, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
 
Equity compensation expense
$ 1,500,000 
$ 1,783,000 
$ 3,357,000 
$ 1,734,000 
 
Long-term incentive plan, increase in available awards
 
 
 
 
871,750,000 
Long term incentive plan available for future grant
 
920,193,000 
54,827 
62,246 
 
Grants issued under long term incentive plan
 
25.00% 
 
 
 
Total fair value of vested units
 
1,900,000 
1,200,000 
900,000 
 
Compensation cost related unvested awards
 
1,400,000 
2,700,000 
3,800,000 
 
Weighted average period cost recognized
 
1 year 3 months 18 days 
 
 
 
Phantom units [Member]
 
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
 
Equity compensation expense
 
 
$ 3,400,000 
$ 1,700,000 
 
Post-Employment Benefits (Changes in Benefit Obligation) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Change in plan assets
 
 
 
Funded status
$ 1,080 
$ 966 
$ 450 
Change in Benefit Obligation [Member]
 
 
 
Change in benefit obligation
 
 
 
Obligation, beginning of period
466 
869 
734 
Service cost
4 
3 
10 
Interest cost
18 
22 
43 
Actuarial (gain) loss
22 
(367)
112 
Benefits paid
(38)
(61)
(30)
Benefit obligationm, ending
472 
466 
869 
Change in plan assets
 
 
 
Benefits paid
(38)
(61)
(30)
Change in Plan Assets [Member]
 
 
 
Change in benefit obligation
 
 
 
Benefits paid
(54)
(76)
(29)
Change in plan assets
 
 
 
Fair value of plan assets, beginning of period
1,432 
1,319 
1,174 
Actual return on plan assets
84 
99 
61 
Employer’s contributions
90 
90 
113 
Benefits paid
(54)
(76)
(29)
Fair value of plan assets, ending
$ 1,552 
$ 1,432 
$ 1,319 
Post-Employment Benefits (Plan Assets Recognized) (Details) (OPEB Plan [Member], USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
OPEB Plan [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Other assets
$ 1,080 
$ 966 
$ 450 
Post-Employment Benefits (Net Periodic Benefit Cost) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Cost recognized in Unaudited Condensed Consolidated Statements of Operations
 
 
 
Amortization of net (gain) loss
$ (100)
$ 400 
$ 100 
Net periodic (benefit) cost
(88)
(82)
   
Net loss (gain)
64 
(359)
(10)
OPEB Plan [Member]
 
 
 
Cost recognized in Unaudited Condensed Consolidated Statements of Operations
 
 
 
Service cost
4 
3 
10 
Interest cost
18 
22 
43 
Expected return on plan assets
(67)
(60)
(53)
Amortization of net (gain) loss
(43)
(47)
   
Net periodic (benefit) cost
(88)
(82)
0 
Net loss (gain)
64 
(359)
(10)
Total recognized in other comprehensive income
64 
(359)
(10)
Total recognized in net periodic benefit cost and other comprehensive income
$ (24)
$ (441)
$ (10)
Post-Employment Benefits (Economic Assumptions) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2012
OPEB Plan [Member]
Dec. 31, 2011
OPEB Plan [Member]
Dec. 31, 2010
OPEB Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
 
 
 
 
Discount rate
 
3.42% 
3.96% 
5.50% 
Expected return on plan assets
 
4.50% 
4.50% 
4.50% 
Effect of one percentage point increase in assumed medical and dental care trend
$ 0.1 
 
 
 
Effect of one percentage point decrease in assumed medical and dental care trend
$ 0.1 
 
 
 
Post-Employment Benefits (Expected Future Benefit Payments) (Details) (OPEB Plan [Member], USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
OPEB Plan [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
2013
$ 41 
2014
35 
2015
35 
2016
32 
2017
30 
Five years thereafter
$ 135 
Post-Employment Benefits (Weighted Average Asset Allocation) (Details)
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Weighted average asset allocation (as a percent)
100.00% 
100.00% 
100.00% 
Fixed Income [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Weighted average asset allocation (as a percent)
72.20% 1
72.10% 1
70.70% 1
Cash and Short Term Assets [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Weighted average asset allocation (as a percent)
27.80% 2
27.90% 2
29.30% 2
Post-Employment Benefits (Details Textual) (USD $)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Net periodic benefit expense in AOCI, related to net gains (losses)
$ (100,000)
$ 400,000 
$ 100,000 
Amortization, net periodic benefit cost
100,000 
 
 
OPEB Plan [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Net periodic benefit expense in AOCI, related to net gains (losses)
(43,000)
(47,000)
   
Contributions by employer
$ 100,000 
 
 
Commitments and Contingencies (Contractual Obligations) (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Future Non Cancelable Commitment [Line Items]
 
2013
$ 661 
2014
450 
2015
428 
2016
8,039 
Thereafter
1,317 
Total
10,895 
Operating leases and service contract [Member]
 
Future Non Cancelable Commitment [Line Items]
 
2013
661 
2014
450 
2015
428 
2016
179 
Thereafter
858 
Total
2,576 
ARO [Member]
 
Future Non Cancelable Commitment [Line Items]
 
2013
0 
2014
0 
2015
0 
2016
7,860 
Thereafter
459 
Total
$ 8,319 
Commitments and Contingencies (Expenses) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Commitments and Contingencies Disclosure [Abstract]
 
 
 
Operating leases
$ 941 
$ 803 
$ 757 
Asset retirement obligation
32 
1,393 
1,191 
Total expenses
$ 973 
$ 2,196 
$ 1,948 
Commitments and Contingencies (Details Textual) (USD $)
1 Months Ended
Feb. 29, 2012
Dec. 31, 2012
Commitments and Contingencies Disclosure [Abstract]
 
 
Civil penalty
$ 23,010 
 
Estimated employee agreement benefit
 
$ 500,000 
Expected percentage payment, insurance carrier
 
30.00% 
Related- Party Transactions (Details Textual) (USD $)
12 Months Ended 1 Months Ended 12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Aug. 31, 2011
American Infrastructure MLP [Member]
Dec. 31, 2011
American Infrastructure MLP [Member]
Dec. 31, 2010
American Infrastructure MLP [Member]
Dec. 31, 2012
American Midstream, LLC [Member]
Dec. 31, 2011
American Midstream, LLC [Member]
Dec. 31, 2010
American Midstream, LLC [Member]
Related Party Transactions (Textual) [Abstract]
 
 
 
 
 
 
 
 
 
Administrative and operational service expenses
 
 
 
 
 
 
$ 12,500,000 
$ 9,600,000 
$ 7,600,000 
Cost of business development activities
 
 
 
 
 
 
400,000 
 
 
Advisory service payment
 
 
 
 
 
300,000 
 
 
 
Annual fee for Advisory Service
 
 
 
 
 
300,000 
 
 
 
Selling, general and administrative expenses
14,309,000 
10,794,000 
7,120,000 
 
200,000 
300,000 
 
 
 
One time payment of Advisory services
 
 
 
$ 2,500,000 
 
 
 
 
 
Reporting Segments (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Jun. 30, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Segment information
 
 
 
 
 
 
 
 
Revenue, net
 
 
 
 
 
$ 209,594 
$ 248,282 
$ 212,248 
Segment gross margin
 
 
 
 
 
50,554 1 2
45,879 1 2
38,119 1
Realized gain (loss) on early termination of commodity derivatives
 
 
 
 
 
0 3
(2,998)3
0 3
Unrealized gain (loss) on commodity derivatives
 
 
 
 
 
992 3
(541)3
(308)3
Direct operating expenses
 
 
 
 
 
18,202 
12,856 
12,187 
Selling, general and administrative expenses
 
 
 
 
 
14,309 
10,794 
7,120 
Advisory services agreement termination fee
 
 
 
 
 
0 
2,500 
0 
Transaction expenses
 
 
 
 
 
0 
282 
303 
Equity compensation expense
 
 
 
 
1,500 
1,783 
3,357 
1,734 
Depreciation and accretion expense
 
 
 
 
 
21,414 
20,705 
20,013 
Gain (loss) on acquisition of assets
 
 
 
 
 
0 
565 
0 
Gain (loss) on involuntary conversion of property, plant and equipment
 
 
 
 
 
(1,021)
0 
0 
Gain (loss) on sale of assets, net
 
 
 
 
 
128 
399 
0 
Interest expense
 
 
 
 
 
4,570 
4,508 
5,406 
Net income (loss)
(6,244)
(4,026)
2,327 
1,691 4
 
(6,252)4
(11,698)
(8,644)
Net income (loss) attributable to noncontrolling interests
7 
249 
0 
0 4
 
256 4
0 
0 
Gathering and Processing [Member]
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
Revenue, net
 
 
 
 
 
157,065 
181,517 
158,763 
Segment gross margin
 
 
 
 
 
37,241 1 2
32,142 1
24,595 1
Realized gain (loss) on early termination of commodity derivatives
 
 
 
 
 
0 3
(2,998)3
0 3
Unrealized gain (loss) on commodity derivatives
 
 
 
 
 
992 3
 
(308)3
Unrealized Gain (Loss), Non-Cash Mark-To-Market Adjustments on Commodity Derivatives
 
 
 
 
 
1,000 
(541)3
 
Direct operating expenses
 
 
 
 
 
13,171 
7,636 
7,721 
Transmission [Member]
 
 
 
 
 
 
 
 
Segment information
 
 
 
 
 
 
 
 
Revenue, net
 
 
 
 
 
52,529 
66,765 
53,485 
Segment gross margin
 
 
 
 
 
13,313 1 2
13,737 1
13,524 1
Realized gain (loss) on early termination of commodity derivatives
 
 
 
 
 
0 3
0 3
0 3
Unrealized gain (loss) on commodity derivatives
 
 
 
 
 
0 3
0 3
0 3
Direct operating expenses
 
 
 
 
 
$ 5,031 
$ 5,220 
$ 4,466 
[1] Segment gross margin for our Gathering and Processing segment consists of revenue less purchases of natural gas, NGLs and condensate and COMA. Segment gross margin for our Transmission segment consists of revenue, less purchases of natural gas and COMA. 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. Effective October 1, 2012, we changed our segment gross margin measure to exclude construction, operating and maintenance agreement (“COMA”) income. For the year ended December 31, 2012, $0.7 million and $2.7 million in COMA income was excluded from our Gathering and Processing segment gross margin and our Transmission segment gross margin, respectively.
[4] During the fourth quarter, we identified revenues in the amount of $0.3 million associated with proceeds received in connection with COMA reimbursable projects that were incorrectly recognized in the first quarter of 2012 that should have been recognized ratably during each of the succeeding quarters of 2012 for approximately $0.1 million per quarter. In addition, we recorded in the first quarter of 2012 and for the year ended December 31, 2012 out-of-period adjustments amounting to $0.1 million for the correction of immaterial errors associated with additional depreciation expense and selling, general and administrative expense. Based upon our evaluation of relevant factors, we concluded that these errors were not material to any previously issued and current consolidated financial statements.(b)For a definition of gross margin and a reconciliation to its mostly directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 19, "Reporting Segments".
Reporting Segments Reporting Segment (Revenue Earned from Customers that Exceed 10%) (Details) (Customer Concentration Risk [Member], Revenue [Member])
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Gathering and Processing [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Concentration risk, percentage
100.00% 
100.00% 
100.00% 
Transmission [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Concentration risk, percentage
100.00% 
100.00% 
100.00% 
Customer A [Member] |
Gathering and Processing [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Concentration risk, percentage
40.00% 
55.00% 
34.00% 
Customer B [Member] |
Gathering and Processing [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Concentration risk, percentage
12.00% 
16.00% 
30.00% 
Customer C [Member] |
Gathering and Processing [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Concentration risk, percentage
11.00% 
0.00% 
0.00% 
Customer D [Member] |
Gathering and Processing [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Concentration risk, percentage
0.00% 
0.00% 
10.00% 
Customer E [Member] |
Transmission [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Concentration risk, percentage
22.00% 
22.00% 
31.00% 
Customer F [Member] |
Transmission [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Concentration risk, percentage
50.00% 
57.00% 
43.00% 
Customer G [Member] |
Transmission [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Concentration risk, percentage
10.00% 
0.00% 
10.00% 
Customer Other [Member] |
Gathering and Processing [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Concentration risk, percentage
37.00% 
29.00% 
26.00% 
Customer Other [Member] |
Transmission [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Concentration risk, percentage
18.00% 
21.00% 
16.00% 
Reporting Segments (Details Textual) (USD $)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Segment Reporting Information [Line Items]
 
 
 
Unrealized gain (loss) on derivative contracts
$ 992,000 
$ (849,000)
$ (385,000)
Gathering and Processing [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Unrealized gain (loss) on commodity derivatives
1,000,000 
(541,000)1
 
Unrealized gain (loss) on derivative contracts
 
(3,000,000)
 
Construction, operating and maintenace agreement expenses
700,000 
 
 
Transmission [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Construction, operating and maintenace agreement expenses
$ 2,700,000 
 
 
Quarterly Financial Data (Details) (USD $)
3 Months Ended 12 Months Ended
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Quarterly Financial Data [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Total revenue
$ 60,491,000 
$ 56,324,000 
$ 46,060,000 
$ 47,711,000 1
$ 57,386,000 
$ 57,958,000 
$ 65,634,000 
$ 63,765,000 1
$ 210,586,000 1
$ 244,743,000 1
$ 211,940,000 
Gross margin
12,519,000 2
13,367,000 2
11,694,000 2
12,974,000 1 2
13,304,000 1
9,646,000 1
10,617,000 1
12,312,000 1
50,554,000 1 2
45,879,000 1
 
Operating income (loss)
(4,757,000)
(2,525,000)
3,152,000 
2,448,000 1
1,332,000 
(3,375,000)
(2,901,000)
(2,246,000)1
(1,682,000)1
(7,190,000)1
(3,238,000)
Net income (loss)
(6,244,000)
(4,026,000)
2,327,000 
1,691,000 1
 
 
 
 
(6,252,000)1
(11,698,000)
(8,644,000)
Net income (loss) attributable to noncontrolling interests
7,000 
249,000 
0 
0 1
 
 
 
 
256,000 1
0 
0 
Net income (loss) attributable to the partnership
(6,251,000)
(4,275,000)
2,327,000 
1,691,000 1
161,000 
(4,167,000)
(4,182,000)
(3,510,000)1
(6,508,000)1
(11,698,000)1
(8,644,000)
General partner’s interest in net income (loss)
(124,000)
(85,000)
46,000 
34,000 1
4,000 
(83,000)
(84,000)
(70,000)1
(129,000)1
(233,000)1
(173,000)
Limited partners’ interest in net income (loss)
(6,127,000)
(4,190,000)
2,281,000 
1,657,000 1
157,000 
(4,084,000)
(4,098,000)
(3,440,000)1
(6,379,000)1
(11,465,000)1
(8,471,000)
Limited partners’ net income (loss) per unit
(0.67)
(0.46)
0.25 
0.18 1
0.02 
(0.53)
(0.74)
(0.62)1
(0.70)1
(1.64)1
(1.66)
Recognition of Proceeds Received in Connection with COMA Reimbursable Projects [Member]
 
 
 
 
 
 
 
 
 
 
 
Quantifying Misstatement in Current Year Financial Statements [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Out-of-period adjustment
 
 
 
 
 
 
 
 
0 
 
 
Quarterly amount to be recognized
 
 
 
 
 
 
 
 
100,000 
 
 
Additional Depreciation Expense and Selling, General and Administrative Expense [Member]
 
 
 
 
 
 
 
 
 
 
 
Quantifying Misstatement in Current Year Financial Statements [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Out-of-period adjustment
 
 
 
 
 
 
 
 
$ 0 
 
 
[1] During the fourth quarter, we identified revenues in the amount of $0.3 million associated with proceeds received in connection with COMA reimbursable projects that were incorrectly recognized in the first quarter of 2012 that should have been recognized ratably during each of the succeeding quarters of 2012 for approximately $0.1 million per quarter. In addition, we recorded in the first quarter of 2012 and for the year ended December 31, 2012 out-of-period adjustments amounting to $0.1 million for the correction of immaterial errors associated with additional depreciation expense and selling, general and administrative expense. Based upon our evaluation of relevant factors, we concluded that these errors were not material to any previously issued and current consolidated financial statements.(b)For a definition of gross margin and a reconciliation to its mostly directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 19, "Reporting Segments".
Subsidiary Guarantors (Narrative) (Details)
6 Months Ended 12 Months Ended
Jun. 30, 2011
Dec. 31, 2012
Property, Plant and Equipment [Line Items]
 
 
Percentage of agragate limited partner interest
100.00% 
0.90% 
American Midstream Finance Corporation [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Percentage of agragate limited partner interest
 
100.00% 
Chatom Assets [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Subsidiaries and guarantor subsidiaries investment percent
 
87.40% 
Subsidiary Guarantors (Balance Sheet) (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Current assets:
 
 
 
 
Cash and cash equivalents
$ 576 
$ 871 
$ 63 
$ 1,149 
Accounts receivable
1,958 
1,218 
 
 
Unbilled revenue
21,512 
19,745 
 
 
Risk management assets
969 
0 
 
 
Other current assets
3,226 
3,323 
 
 
Total current assets
28,241 
25,157 
 
 
Property, plant and equipment, net
223,819 
170,231 
 
 
Investment in subsidiaries
0 
 
 
 
Other assets, net
4,636 
3,707 
 
 
Total assets
256,696 
199,095 
 
 
Current liabilities:
 
 
 
 
Accounts payable
5,527 
837 
 
 
Accrued gas purchases
17,034 
14,715 
 
 
Accrued expenses and other current liabilities
9,619 
7,086 
 
 
Total current liabilities
32,180 
22,817 
 
 
Other liabilities
8,628 
8,612 
 
 
Long-term debt
128,285 
66,270 
 
 
Total liabilities
169,093 
97,699 
 
 
Total partners' capital
80,165 
101,396 
 
 
Noncontrolling interest
7,438 
0 
 
 
Total equity
87,603 
101,396 
 
 
Total liabilities and equity
256,696 
199,095 
 
 
Parent [Member]
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
1 
1 
 
 
Accounts receivable
0 
 
 
 
Unbilled revenue
0 
 
 
 
Risk management assets
0 
 
 
 
Other current assets
0 
 
 
 
Total current assets
1 
 
 
 
Property, plant and equipment, net
0 
 
 
 
Investment in subsidiaries
80,164 
 
 
 
Other assets, net
0 
 
 
 
Total assets
80,165 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
0 
 
 
 
Accrued gas purchases
0 
 
 
 
Accrued expenses and other current liabilities
0 
 
 
 
Total current liabilities
0 
 
 
 
Other liabilities
0 
 
 
 
Long-term debt
0 
 
 
 
Total liabilities
0 
 
 
 
Total partners' capital
80,165 
 
 
 
Noncontrolling interest
0 
 
 
 
Total equity
80,165 
 
 
 
Total liabilities and equity
80,165 
 
 
 
Guarantor Subsidiaries [Member]
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
575 
870 
 
 
Accounts receivable
1,612 
 
 
 
Unbilled revenue
18,102 
 
 
 
Risk management assets
969 
 
 
 
Other current assets
2,967 
 
 
 
Total current assets
24,225 
 
 
 
Property, plant and equipment, net
165,001 
 
 
 
Investment in subsidiaries
51,613 
 
 
 
Other assets, net
4,636 
 
 
 
Total assets
245,475 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
5,100 
 
 
 
Accrued gas purchases
14,606 
 
 
 
Accrued expenses and other current liabilities
9,150 
 
 
 
Total current liabilities
28,856 
 
 
 
Other liabilities
8,170 
 
 
 
Long-term debt
128,285 
 
 
 
Total liabilities
165,311 
 
 
 
Total partners' capital
80,164 
 
 
 
Noncontrolling interest
0 
 
 
 
Total equity
80,164 
 
 
 
Total liabilities and equity
245,475 
 
 
 
Non-Guarantor Subsidiaries [Member]
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
0 
0 
 
 
Accounts receivable
346 
 
 
 
Unbilled revenue
3,410 
 
 
 
Risk management assets
0 
 
 
 
Other current assets
259 
 
 
 
Total current assets
4,015 
 
 
 
Property, plant and equipment, net
58,818 
 
 
 
Investment in subsidiaries
0 
 
 
 
Other assets, net
0 
 
 
 
Total assets
62,833 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
427 
 
 
 
Accrued gas purchases
2,428 
 
 
 
Accrued expenses and other current liabilities
469 
 
 
 
Total current liabilities
3,324 
 
 
 
Other liabilities
458 
 
 
 
Long-term debt
0 
 
 
 
Total liabilities
3,782 
 
 
 
Total partners' capital
51,613 
 
 
 
Noncontrolling interest
7,438 
 
 
 
Total equity
59,051 
 
 
 
Total liabilities and equity
62,833 
 
 
 
Consolidation Adjustments [Member]
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
0 
0 
 
 
Accounts receivable
0 
 
 
 
Unbilled revenue
0 
 
 
 
Risk management assets
0 
 
 
 
Other current assets
0 
 
 
 
Total current assets
0 
 
 
 
Property, plant and equipment, net
0 
 
 
 
Investment in subsidiaries
(131,777)
 
 
 
Other assets, net
0 
 
 
 
Total assets
(131,777)
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
0 
 
 
 
Accrued gas purchases
0 
 
 
 
Accrued expenses and other current liabilities
0 
 
 
 
Total current liabilities
0 
 
 
 
Other liabilities
0 
 
 
 
Long-term debt
0 
 
 
 
Total liabilities
0 
 
 
 
Total partners' capital
(131,777)
 
 
 
Noncontrolling interest
0 
 
 
 
Total equity
(131,777)
 
 
 
Total liabilities and equity
$ (131,777)
 
 
 
Subsidiary Guarantors (Statement of Operations) (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
$ 209,594 
$ 248,282 
$ 212,248 
Unrealized gain (loss) on commodity derivatives
 
 
 
 
 
 
 
 
992 
(541)
(308)
Total revenue
60,491 
56,324 
46,060 
47,711 1
57,386 
57,958 
65,634 
63,765 1
210,586 1
244,743 1
211,940 
Operating Expenses:
 
 
 
 
 
 
 
 
 
 
 
Purchases of natural gas, NGLs and condensate
 
 
 
 
 
 
 
 
155,667 
202,403 
173,821 
Direct operating expenses
 
 
 
 
 
 
 
 
18,202 
12,856 
12,187 
Selling, general and administrative expenses
 
 
 
 
 
 
 
 
14,309 
10,794 
7,120 
Equity compensation expense
 
 
 
 
 
 
1,500 
 
1,783 
3,357 
1,734 
Depreciation expense
 
 
 
 
 
 
 
 
21,414 
20,705 
20,013 
Total operating expenses
 
 
 
 
 
 
 
 
211,375 
 
 
Gain (loss) on involuntary conversion of property, plant and equipment
 
 
 
 
 
 
 
 
(1,021)
0 
0 
Gain (loss) on sale of assets, net
 
 
 
 
 
 
 
 
128 
399 
0 
Operating income (loss)
(4,757)
(2,525)
3,152 
2,448 1
1,332 
(3,375)
(2,901)
(2,246)1
(1,682)1
(7,190)1
(3,238)
Other Income (expenses):
 
 
 
 
 
 
 
 
 
 
 
Earnings from consolidated affiliates
 
 
 
 
 
 
 
 
0 
 
 
Interest expense
 
 
 
 
 
 
 
 
(4,570)
(4,508)
(5,406)
Net income (loss)
(6,244)
(4,026)
2,327 
1,691 1
 
 
 
 
(6,252)1
(11,698)
(8,644)
Net income (loss) attributable to noncontrolling interests
7 
249 
0 
0 1
 
 
 
 
256 1
0 
0 
Net income (loss) attributable to the partnership
(6,251)
(4,275)
2,327 
1,691 1
161 
(4,167)
(4,182)
(3,510)1
(6,508)1
(11,698)1
(8,644)
Parent [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
0 
 
 
Unrealized gain (loss) on commodity derivatives
 
 
 
 
 
 
 
 
0 
 
 
Total revenue
 
 
 
 
 
 
 
 
0 
 
 
Operating Expenses:
 
 
 
 
 
 
 
 
 
 
 
Purchases of natural gas, NGLs and condensate
 
 
 
 
 
 
 
 
0 
 
 
Direct operating expenses
 
 
 
 
 
 
 
 
0 
 
 
Selling, general and administrative expenses
 
 
 
 
 
 
 
 
0 
 
 
Equity compensation expense
 
 
 
 
 
 
 
 
0 
 
 
Depreciation expense
 
 
 
 
 
 
 
 
0 
 
 
Total operating expenses
 
 
 
 
 
 
 
 
0 
 
 
Gain (loss) on involuntary conversion of property, plant and equipment
 
 
 
 
 
 
 
 
0 
 
 
Gain (loss) on sale of assets, net
 
 
 
 
 
 
 
 
0 
 
 
Operating income (loss)
 
 
 
 
 
 
 
 
0 
 
 
Other Income (expenses):
 
 
 
 
 
 
 
 
 
 
 
Earnings from consolidated affiliates
 
 
 
 
 
 
 
 
(6,509)
 
 
Interest expense
 
 
 
 
 
 
 
 
0 
 
 
Net income (loss)
 
 
 
 
 
 
 
 
(6,509)
 
 
Net income (loss) attributable to noncontrolling interests
 
 
 
 
 
 
 
 
0 
 
 
Net income (loss) attributable to the partnership
 
 
 
 
 
 
 
 
(6,509)
 
 
Guarantor Subsidiaries [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
185,320 
 
 
Unrealized gain (loss) on commodity derivatives
 
 
 
 
 
 
 
 
992 
 
 
Total revenue
 
 
 
 
 
 
 
 
186,312 
 
 
Operating Expenses:
 
 
 
 
 
 
 
 
 
 
 
Purchases of natural gas, NGLs and condensate
 
 
 
 
 
 
 
 
137,144 
 
 
Direct operating expenses
 
 
 
 
 
 
 
 
15,299 
 
 
Selling, general and administrative expenses
 
 
 
 
 
 
 
 
14,309 
 
 
Equity compensation expense
 
 
 
 
 
 
 
 
1,783 
 
 
Depreciation expense
 
 
 
 
 
 
 
 
20,604 
 
 
Total operating expenses
 
 
 
 
 
 
 
 
189,139 
 
 
Gain (loss) on involuntary conversion of property, plant and equipment
 
 
 
 
 
 
 
 
(1,021)
 
 
Gain (loss) on sale of assets, net
 
 
 
 
 
 
 
 
128 
 
 
Operating income (loss)
 
 
 
 
 
 
 
 
(3,720)
 
 
Other Income (expenses):
 
 
 
 
 
 
 
 
 
 
 
Earnings from consolidated affiliates
 
 
 
 
 
 
 
 
1,781 
 
 
Interest expense
 
 
 
 
 
 
 
 
(4,570)
 
 
Net income (loss)
 
 
 
 
 
 
 
 
(6,509)
 
 
Net income (loss) attributable to noncontrolling interests
 
 
 
 
 
 
 
 
0 
 
 
Net income (loss) attributable to the partnership
 
 
 
 
 
 
 
 
(6,509)
 
 
Non-Guarantor Subsidiaries [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
25,441 
 
 
Unrealized gain (loss) on commodity derivatives
 
 
 
 
 
 
 
 
0 
 
 
Total revenue
 
 
 
 
 
 
 
 
25,441 
 
 
Operating Expenses:
 
 
 
 
 
 
 
 
 
 
 
Purchases of natural gas, NGLs and condensate
 
 
 
 
 
 
 
 
19,690 
 
 
Direct operating expenses
 
 
 
 
 
 
 
 
2,903 
 
 
Selling, general and administrative expenses
 
 
 
 
 
 
 
 
0 
 
 
Equity compensation expense
 
 
 
 
 
 
 
 
0 
 
 
Depreciation expense
 
 
 
 
 
 
 
 
810 
 
 
Total operating expenses
 
 
 
 
 
 
 
 
23,403 
 
 
Gain (loss) on involuntary conversion of property, plant and equipment
 
 
 
 
 
 
 
 
0 
 
 
Gain (loss) on sale of assets, net
 
 
 
 
 
 
 
 
0 
 
 
Operating income (loss)
 
 
 
 
 
 
 
 
2,038 
 
 
Other Income (expenses):
 
 
 
 
 
 
 
 
 
 
 
Earnings from consolidated affiliates
 
 
 
 
 
 
 
 
0 
 
 
Interest expense
 
 
 
 
 
 
 
 
0 
 
 
Net income (loss)
 
 
 
 
 
 
 
 
2,038 
 
 
Net income (loss) attributable to noncontrolling interests
 
 
 
 
 
 
 
 
256 
 
 
Net income (loss) attributable to the partnership
 
 
 
 
 
 
 
 
1,782 
 
 
Consolidation Adjustments [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Revenue
 
 
 
 
 
 
 
 
(1,167)
 
 
Unrealized gain (loss) on commodity derivatives
 
 
 
 
 
 
 
 
0 
 
 
Total revenue
 
 
 
 
 
 
 
 
(1,167)
 
 
Operating Expenses:
 
 
 
 
 
 
 
 
 
 
 
Purchases of natural gas, NGLs and condensate
 
 
 
 
 
 
 
 
(1,167)
 
 
Direct operating expenses
 
 
 
 
 
 
 
 
0 
 
 
Selling, general and administrative expenses
 
 
 
 
 
 
 
 
0 
 
 
Equity compensation expense
 
 
 
 
 
 
 
 
0 
 
 
Depreciation expense
 
 
 
 
 
 
 
 
0 
 
 
Total operating expenses
 
 
 
 
 
 
 
 
(1,167)
 
 
Gain (loss) on involuntary conversion of property, plant and equipment
 
 
 
 
 
 
 
 
0 
 
 
Gain (loss) on sale of assets, net
 
 
 
 
 
 
 
 
0 
 
 
Operating income (loss)
 
 
 
 
 
 
 
 
0 
 
 
Other Income (expenses):
 
 
 
 
 
 
 
 
 
 
 
Earnings from consolidated affiliates
 
 
 
 
 
 
 
 
4,728 
 
 
Interest expense
 
 
 
 
 
 
 
 
0 
 
 
Net income (loss)
 
 
 
 
 
 
 
 
4,728 
 
 
Net income (loss) attributable to noncontrolling interests
 
 
 
 
 
 
 
 
0 
 
 
Net income (loss) attributable to the partnership
 
 
 
 
 
 
 
 
$ 4,728 
 
 
[1] During the fourth quarter, we identified revenues in the amount of $0.3 million associated with proceeds received in connection with COMA reimbursable projects that were incorrectly recognized in the first quarter of 2012 that should have been recognized ratably during each of the succeeding quarters of 2012 for approximately $0.1 million per quarter. In addition, we recorded in the first quarter of 2012 and for the year ended December 31, 2012 out-of-period adjustments amounting to $0.1 million for the correction of immaterial errors associated with additional depreciation expense and selling, general and administrative expense. Based upon our evaluation of relevant factors, we concluded that these errors were not material to any previously issued and current consolidated financial statements.(b)For a definition of gross margin and a reconciliation to its mostly directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 19, "Reporting Segments".
Subsidiary Guarantors (Statement of Cash Flows) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Statement of Cash Flows [Abstract]
 
 
 
Net cash provided (used) in operating activities
$ 18,348 
$ 10,432 
$ 13,791 
Cost of acquisition, net of cash acquired
(51,377)
(35,500)
0 
Additions to property, plant and equipment
(11,705)
(6,369)
(10,268)
Proceeds from disposals of property, plant and equipment
128 
125 
   
Proceeds from property damage insurance recoveries
527 
0 
0 
Net contributions to affiliates
0 
 
 
Net cash provided (used) in investing activities
(62,427)
(41,744)
(10,268)
Cash flows from financing activities
 
 
 
Unit holder contributions
13 
   
12,000 
Unit holder distributions
(16,070)
(43,546)
(11,779)
Net distributions to noncontrolling interest owners
(225)
0 
0 
LTIP tax netting unit repurchase
(385)
(215)
0 
Deferred debt issuance costs
(1,564)
(2,489)
0 
Payments on long-term debt
(59,230)
(120,670)
(31,130)
Borrowings on long-term debt
121,245 
130,570 
26,500 
Net cash provided (used) in financing activities
43,784 
32,120 
(4,609)
Net increase (decrease) in cash and cash equivalents
(295)
808 
(1,086)
Cash and Cash Equivalents
 
 
 
Beginning of period
871 
63 
1,149 
End of period
576 
871 
63 
Supplemental cash flow information
 
 
 
Interest payments
3,185 
3,349 
4,523 
Supplemental non-cash information
 
 
 
Increase (decrease) in accrued property, plant and equipment
6,968 
75 
0 
Increase (decrease) in receivables for reimbursable construction in progress projects
141 
872 
6,058 
Parent [Member]
 
 
 
Statement of Cash Flows [Abstract]
 
 
 
Net cash provided (used) in operating activities
0 
 
 
Cost of acquisition, net of cash acquired
0 
 
 
Additions to property, plant and equipment
0 
 
 
Proceeds from disposals of property, plant and equipment
0 
 
 
Proceeds from property damage insurance recoveries
0 
 
 
Net contributions to affiliates
16,057 
 
 
Net distributions to affiliates
0 
 
 
Net cash provided (used) in investing activities
16,057 
 
 
Cash flows from financing activities
 
 
 
Unit holder contributions
13 
 
 
Unit holder distributions
(16,070)
 
 
Net distributions to noncontrolling interest owners
0 
 
 
LTIP tax netting unit repurchase
0 
 
 
Deferred debt issuance costs
0 
 
 
Payments on long-term debt
0 
 
 
Borrowings on long-term debt
0 
 
 
Net cash provided (used) in financing activities
(16,057)
 
 
Net increase (decrease) in cash and cash equivalents
0 
 
 
Cash and Cash Equivalents
 
 
 
Beginning of period
1 
 
 
End of period
1 
 
 
Supplemental cash flow information
 
 
 
Interest payments
0 
 
 
Supplemental non-cash information
 
 
 
Increase (decrease) in accrued property, plant and equipment
0 
 
 
Increase (decrease) in receivables for reimbursable construction in progress projects
0 
 
 
Guarantor Subsidiaries [Member]
 
 
 
Statement of Cash Flows [Abstract]
 
 
 
Net cash provided (used) in operating activities
16,310 
 
 
Cost of acquisition, net of cash acquired
(51,377)
 
 
Additions to property, plant and equipment
(10,870)
 
 
Proceeds from disposals of property, plant and equipment
128 
 
 
Proceeds from property damage insurance recoveries
527 
 
 
Net contributions to affiliates
0 
 
 
Net distributions to affiliates
(15,079)
 
 
Net cash provided (used) in investing activities
(61,592)
 
 
Cash flows from financing activities
 
 
 
Unit holder contributions
0 
 
 
Unit holder distributions
0 
 
 
Net distributions to noncontrolling interest owners
0 
 
 
LTIP tax netting unit repurchase
(385)
 
 
Deferred debt issuance costs
(1,564)
 
 
Payments on long-term debt
(59,230)
 
 
Borrowings on long-term debt
121,245 
 
 
Net cash provided (used) in financing activities
44,987 
 
 
Net increase (decrease) in cash and cash equivalents
(295)
 
 
Cash and Cash Equivalents
 
 
 
Beginning of period
870 
 
 
End of period
575 
 
 
Supplemental cash flow information
 
 
 
Interest payments
3,185 
 
 
Supplemental non-cash information
 
 
 
Increase (decrease) in accrued property, plant and equipment
6,968 
 
 
Increase (decrease) in receivables for reimbursable construction in progress projects
141 
 
 
Non-Guarantor Subsidiaries [Member]
 
 
 
Statement of Cash Flows [Abstract]
 
 
 
Net cash provided (used) in operating activities
2,038 
 
 
Cost of acquisition, net of cash acquired
0 
 
 
Additions to property, plant and equipment
(835)
 
 
Proceeds from disposals of property, plant and equipment
0 
 
 
Proceeds from property damage insurance recoveries
0 
 
 
Net contributions to affiliates
0 
 
 
Net distributions to affiliates
(978)
 
 
Net cash provided (used) in investing activities
(835)
 
 
Cash flows from financing activities
 
 
 
Unit holder contributions
0 
 
 
Unit holder distributions
0 
 
 
Net distributions to noncontrolling interest owners
(225)
 
 
LTIP tax netting unit repurchase
0 
 
 
Deferred debt issuance costs
0 
 
 
Payments on long-term debt
0 
 
 
Borrowings on long-term debt
0 
 
 
Net cash provided (used) in financing activities
(1,203)
 
 
Net increase (decrease) in cash and cash equivalents
0 
 
 
Cash and Cash Equivalents
 
 
 
Beginning of period
0 
 
 
End of period
0 
 
 
Supplemental cash flow information
 
 
 
Interest payments
0 
 
 
Supplemental non-cash information
 
 
 
Increase (decrease) in accrued property, plant and equipment
0 
 
 
Increase (decrease) in receivables for reimbursable construction in progress projects
0 
 
 
Consolidation Adjustments [Member]
 
 
 
Statement of Cash Flows [Abstract]
 
 
 
Net cash provided (used) in operating activities
0 
 
 
Cost of acquisition, net of cash acquired
0 
 
 
Additions to property, plant and equipment
0 
 
 
Proceeds from disposals of property, plant and equipment
0 
 
 
Proceeds from property damage insurance recoveries
0 
 
 
Net contributions to affiliates
(16,057)
 
 
Net distributions to affiliates
16,057 
 
 
Net cash provided (used) in investing activities
(16,057)
 
 
Cash flows from financing activities
 
 
 
Unit holder contributions
0 
 
 
Unit holder distributions
0 
 
 
Net distributions to noncontrolling interest owners
0 
 
 
LTIP tax netting unit repurchase
0 
 
 
Deferred debt issuance costs
0 
 
 
Payments on long-term debt
0 
 
 
Borrowings on long-term debt
0 
 
 
Net cash provided (used) in financing activities
16,057 
 
 
Net increase (decrease) in cash and cash equivalents
0 
 
 
Cash and Cash Equivalents
 
 
 
Beginning of period
0 
 
 
End of period
0 
 
 
Supplemental cash flow information
 
 
 
Interest payments
0 
 
 
Supplemental non-cash information
 
 
 
Increase (decrease) in accrued property, plant and equipment
0 
 
 
Increase (decrease) in receivables for reimbursable construction in progress projects
$ 0 
 
 
Liquidity (Details) (USD $)
12 Months Ended 3 Months Ended 0 Months Ended 0 Months Ended 0 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2012
Eurodollar [Member]
Dec. 31, 2012
Third Amendment [Member]
Jun. 27, 2012
Revolving Credit Facility [Member]
Aug. 2, 2011
Revolving Credit Facility [Member]
Dec. 31, 2012
Revolving Credit Facility [Member]
Third Amendment [Member]
Dec. 31, 2012
Revolving Credit Facility [Member]
Third Amendment [Member]
Eurodollar [Member]
Mar. 31, 2013
Subsequent Event [Member]
Fourth Amendment [Member]
Apr. 15, 2013
Subsequent Event [Member]
Fourth Amendment [Member]
Fiscal Quarter Ending June 30, 2013 [Member]
Apr. 15, 2013
Subsequent Event [Member]
Fourth Amendment [Member]
Fiscal Quarter Ending Semptember 30, 2013 [Member]
Apr. 15, 2013
Subsequent Event [Member]
Fourth Amendment [Member]
Fiscal Quarter Ending December 31, 2013 [Member]
Apr. 15, 2013
Subsequent Event [Member]
Fourth Amendment [Member]
Fiscal Quarter Ending March 31, 2014 [Member]
Apr. 15, 2013
Subsequent Event [Member]
Fourth Amendment [Member]
Fiscal Quarter Ending June 30, 2014 [Member]
Apr. 15, 2013
Subsequent Event [Member]
Fourth Amendment [Member]
Fiscal Quarter Ending September 30, 2014 [Member]
Apr. 15, 2013
Subsequent Event [Member]
Fourth Amendment [Member]
Fiscal Quarter Ending December 31, 2014 [Member]
Apr. 15, 2013
Subsequent Event [Member]
Fourth Amendment [Member]
Fiscal Quarter Ending March 31, 2015 and thereafter [Member]
Apr. 15, 2013
Subsequent Event [Member]
Fourth Amendment [Member]
Eurodollar [Member]
Minimum [Member]
Fiscal Quarter Ending December 31, 2014 [Member]
Apr. 15, 2013
Subsequent Event [Member]
Fourth Amendment [Member]
Eurodollar [Member]
Maximum [Member]
Fiscal Quarter Ending December 31, 2014 [Member]
Apr. 15, 2013
Subsequent Event [Member]
Fourth Amendment [Member]
Base Rate [Member]
Minimum [Member]
Fiscal Quarter Ending December 31, 2014 [Member]
Apr. 15, 2013
Subsequent Event [Member]
Fourth Amendment [Member]
Base Rate [Member]
Maximum [Member]
Fiscal Quarter Ending December 31, 2014 [Member]
Apr. 15, 2013
Subsequent Event [Member]
Revolving Credit Facility [Member]
Third Amendment [Member]
Apr. 15, 2013
Subsequent Event [Member]
Revolving Credit Facility [Member]
Fourth Amendment [Member]
Apr. 15, 2013
Subsequent Event [Member]
Revolving Credit Facility [Member]
Fourth Amendment [Member]
Fiscal Quarter Ending December 31, 2014 [Member]
Liquidity Disclosures [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Leverage ratio requirement
4.50 
 
 
 
4.00 
 
 
 
 
 
5.90 
5.90 
5.75 
5.75 
5.75 
5.50 
5.25 
4.50 
 
 
 
 
 
 
 
Total indebtedness
$ 130,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ratio of indebtedness to net capital
5.70 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Credit Facility, amount outstanding limit
 
 
 
 
 
 
 
150,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
175,000,000 
200,000,000 
Equity contribution, to increase borrowings limit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12,500,000 
 
Description of variable rate basis
 
 
 
Eurodollar Rate 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Eurodollar 
 
base rate 
 
 
 
 
Facility fee (percent)
 
 
 
1.00% 
 
 
 
 
0.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Additional fees
 
 
 
 
 
 
 
 
0.125% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payments on long-term debt
59,230,000 
120,670,000 
31,130,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12,500,000 
 
 
Amount outstanding
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
130,000,000 
 
Remaining borrowing capacity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
45,000,000 
 
Maximum outstanding borrowings under credit facility
 
 
 
 
 
250,000,000 
150,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
175,000,000 
 
Basis spread on variable rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2.50% 
4.75% 
1.50% 
3.75% 
 
 
 
Partnership cancellation of subordinated units (percent)
 
 
 
 
 
 
 
 
 
20.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Quarterly dividend reduction
 
 
 
 
 
 
 
 
 
$ 400,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Subsequent Events (Details) (USD $)
12 Months Ended 1 Months Ended 3 Months Ended 3 Months Ended 3 Months Ended 0 Months Ended 0 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Jan. 25, 2013
Subsequent Event [Member]
Dec. 31, 2012
Eurodollar [Member]
Apr. 15, 2013
High Point [Member]
AIM Midstream Holdings [Member]
Partnership Interest [Member]
Subsequent Event [Member]
Apr. 15, 2013
Contribution in Partership [Member]
High Point [Member]
Subsequent Event [Member]
Apr. 15, 2013
Issuance of Preferred Units [Member]
High Point [Member]
Subsequent Event [Member]
Apr. 15, 2013
Issuance of Preferred Units [Member]
Series A [Member]
High Point [Member]
Subsequent Event [Member]
Mar. 31, 2013
Fourth Amendment [Member]
Subsequent Event [Member]
Apr. 15, 2013
Fourth Amendment [Member]
Repayment of Debt [Member]
Subsequent Event [Member]
Revolving Credit Facility [Member]
Apr. 15, 2013
Third Amended and Restated Agreement [Member]
Series A [Member]
Subsequent Event [Member]
Apr. 15, 2013
Third Amended and Restated Agreement [Member]
Unit Distribution [Member]
Series A [Member]
Subsequent Event [Member]
Apr. 15, 2013
Third Amended and Restated Agreement [Member]
Cash Distribution [Member]
Subsequent Event [Member]
Apr. 15, 2013
Third Amended and Restated Agreement [Member]
Cash Distribution [Member]
Series A [Member]
Subsequent Event [Member]
Apr. 15, 2013
Coupon Conversion Quarter [Member]
Third Amended and Restated Agreement [Member]
Series A [Member]
Subsequent Event [Member]
Apr. 15, 2013
Coupon Conversion Quarter [Member]
Third Amended and Restated Agreement [Member]
Unit Distribution [Member]
Series A [Member]
Subsequent Event [Member]
Apr. 15, 2013
Liquidation and Winding-up of Partnership [Member]
Third Amended and Restated Agreement [Member]
Series A [Member]
Subsequent Event [Member]
Apr. 15, 2013
Minimum [Member]
Third Amended and Restated Agreement [Member]
Series A [Member]
Subsequent Event [Member]
Apr. 15, 2013
Maximum [Member]
Third Amended and Restated Agreement [Member]
Series A [Member]
Subsequent Event [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution announced (usd per share)
 
 
 
$ 0.4325 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sale of partnership's subordinated units (shares)
 
 
 
 
 
4,526,066 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Partnership cancellation of subordinated units (percent)
 
 
 
 
 
90.00% 
 
 
 
20.00% 
 
 
 
 
 
 
 
 
 
 
Escrow Deposit
 
 
 
 
 
$ 12,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contributed capital (percentage)
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contributed capital
 
 
 
 
 
 
 
 
15,000,000 
 
 
 
 
 
 
 
 
 
 
 
Preferred units issued (shares)
 
 
 
 
 
 
 
 
5,142,857 
 
 
 
 
 
 
 
 
 
 
 
Payments on long-term debt
59,230,000 
120,670,000 
31,130,000 
 
 
 
 
 
 
 
12,500,000 
 
 
 
 
 
 
 
 
 
Total consideration for issuance of preferred units, series A
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15,000,000 
 
Total consideration aggregate for tweleve months period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50,000,000 
 
Indebtedness in one or series of related transactions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
75,000,000 
Indebtedness in one or series of related transactions, in twelve months
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25,000,000 
Yeild to maturity
 
 
 
 
 
 
 
 
 
 
 
(10.00%)
 
 
 
 
 
 
 
 
Distribution made to member or limited partner per share (shares)
 
 
 
 
 
 
 
 
 
 
 
 
0.01428571 
 
 
 
0.023571428 
 
 
 
Transaction Expenses
 
 
 
 
 
 
 
$ 2,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
Earned and paid (usd per unit)
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 0.25 
 
 
 
 
 
 
Distribution made to member or limited partner, Conversion price (usd per share)
 
 
 
 
 
 
 
 
 
 
 
$ 17.50 
 
 
 
$ 17.50 
 
$ 17.50 
$ 17.50 
 
Facility fee (percent)
 
 
 
 
1.00% 
 
 
 
 
 
 
 
 
 
6.00% 
 
 
 
 
 
Preferred units, percentage of ownership (percent)
 
 
 
 
 
 
 
 
 
 
 
50.00%