American Midstream Partners, LP - FORM 8-K - EX-99.1 - EXHIBIT

Attached files

file	filename
8-K - 8-K - American Midstream Partners, LP	form8-k.htm
EX-23.1 - EXHIBIT - American Midstream Partners, LP	exh231.htm
EX-23.2 - EXHIBIT - American Midstream Partners, LP	exh232.htm
EX-99.2 - EXHIBIT - American Midstream Partners, LP	exh992.htm

Exhibit 99.1

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

To the Board of Directors of the General Partner of

American Midstream Partners, LP

We have audited the accompanying consolidated balance sheets of American Midstream Partners, LP and its subsidiaries as of December 31, 2011 and 2010 and the related consolidated statements of operations, of changes in partners’ capital and of cash flows for the years ended December 31, 2011 and 2010 and the period from August 20, 2009 (inception date) to December 31, 2009. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Midstream Partners, LP and its subsidiaries at December 31, 2011 and 2010 and the results of their operations and their cash flows for the years ended December 31, 2011 and 2010 and the period from August 20, 2009 (inception date) to December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

March 19, 2012 except for Note 22, as to which the date is October 18, 2012.

Report of Independent Registered Public Accounting Firm

To the Board of Directors of the General Partner of

American Midstream Partners, LP

We have audited the accompanying combined statement of operations of American Midstream Partners Predecessor (the “Predecessor), and the related combined statements of group equity and of cash flows for the ten-month period ended October 31, 2009. These financial statements are the responsibility of American Midstream Partners, LP. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the results of operations of American Midstream Predecessor and their cash flows for the ten-month period ended October 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 17 to the financial statements, the financial results contain significant transactions with related parties.

/s/ PricewaterhouseCoopers, LLP

Houston, Texas

March 30, 2011

American Midstream Partners, LP and Subsidiaries

Consolidated Balance Sheets

(In thousands except unit amounts)



	December 31,
	2011		2010
Assets
Current assets
Cash and cash equivalents	$	871	$	63
Accounts receivable	1,218		656
Unbilled revenue	19,745		22,194
Risk management assets	456		—
Other current assets	3,323		1,523
Total current assets	25,613		24,436
Property, plant and equipment, net	170,231		146,808
Other assets, net	3,707		1,985
Total assets	$	199,551	$	173,229
Liabilities and Partners’ Capital
Current liabilities
Accounts payable	$	837	$	980
Accrued gas purchases	14,715		18,706
Current portion of long-term debt	—		6,000
Other loans	—		615
Risk management liabilities	635		—
Accrued expenses and other current liabilities	7,086		2,676
Total current liabilities	23,273		28,977
Other liabilities	8,612		8,078
Long-term debt	66,270		50,370
Total liabilities	98,155		87,425
Commitments and contingencies (see Note 16)
Partners’ capital
General partner interest (0.2 and 0.1 million units issued and outstanding as of December 31, 2011 and 2010, respectively)	1,091		2,124
Limited partner interest (9.1 and 5.4 million units issued and outstanding as of December 31, 2011 and 2010, respectively)	99,890		83,624
Accumulated other comprehensive income	415		56
Total partners’ capital	101,396		85,804
Total liabilities and partners’ capital	$	199,551	$	173,229

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

American Midstream Partners, LP and Subsidiaries

Consolidated Statements of Operations

(In thousands, except per unit amounts)



							Period from August 20, 2009			Predecessor
							(Inception Date)			Ten Months
	For the Year Ended December 31,						to December 31,			ended October 31,
	2011			2010			2009			2009
Revenue	$	248,282		$	212,248		$	32,833		$	143,132
Realized gain (loss) on early termination of commodity derivatives	(2,998		)	—			—			—
Unrealized gain (loss) on commodity derivatives	(541		)	(308		)	—			—
Total revenue	244,743			211,940			32,833			143,132
Operating expenses:
Purchases of natural gas, NGLs and condensate	202,403			173,821			26,593			113,227
Direct operating expenses	12,856			12,187			1,594			10,331
Selling, general and administrative expenses	10,794			7,120			1,196			8,553
Advisory services agreement termination fee (See Note 17)	2,500			—			—			—
Transaction expenses (See Note 2)	282			303			6,404			—
Equity compensation expense (See Note 14)	3,357			1,734			150			—
Depreciation and accretion expense	20,705			20,013			2,978			12,630
Total operating expenses	252,897			215,178			38,915			144,741
Gain (loss) on acquisition of assets	565			—			—			—
Gain (loss) on sale of assets, net	399			—			—			—
Operating income (loss)	(7,190		)	(3,238		)	(6,082		)	(1,609		)
Other income (expenses):
Interest expense	(4,508		)	(5,406		)	(910		)	(3,728		)
Net income (loss)	$	(11,698	)	$	(8,644	)	$	(6,992	)	$	(5,337	)
General partner’s interest in net income (loss)	(233		)	(173		)	(140		)
Limited partners’ interest in net income (loss)	$	(11,465	)	$	(8,471	)	$	(6,852	)
Limited partners’ net income (loss) per unit (See Note 19)	$	(1.64	)	$	(1.66	)	$	(3.13	)
Weighted average number of units used in computation of limited partners’ net income (loss) per unit	6,997			5,099			2,187

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

American Midstream Partners, LP and Subsidiaries

Consolidated Statements of Changes in Partners’ Capital

(In thousands)



	Limited Partner Common Units		Limited Partner Sub-ordinated Units	Group Equity			Limited Partner Interest			General Partner Units	General Partner Interest			Accumu-lated Other Com-prehensive Income		Total
Predecessor:
Balance at December 31, 2008	—		—	$	151,799		—			—	—			—		$	151,799
Net income (loss)	—		—	(5,337		)	—			—	—			—		(5,337		)
Contributions by parent	—		—	111,103			—			—	—			—		111,103
Distributions to parent	—		—	(25,772		)	—			—	—			—		(25,772		)
Other comprehensive loss	—		—	(201		)	—			—	—			—		(201		)
Balance at October 31, 2009	—		—	$	231,592		$	—		—	$	—		$	—	$	231,592
Successor:
Balances at August 20, 2009 (Inception date)	—		—	—			$	—		—	$	—		$	—	$	—
Net income (loss)	—		—	—			(6,852		)	—	(140		)	—		(6,992		)
Unitholder contributions	4,756		—	—			98,000			97	2,000			—		100,000
Unitholder distributions	—		—	—			—			—				—		—
Unit based compensation	—		—	—			—			—	150			—		150
Adjustments to other post retirement plan assets and liabilities	—		—	—			—			—				46		46
Balances at December 31, 2009	4,756		—	—			91,148			97	2,010			46		93,204
Net income (loss)	—		—	—			(8,471		)	—	(173		)	—		(8,644		)
Unitholder contributions	571		—	—			11,760			12	240			—		12,000
Unitholder distributions	—		—	—			(11,545		)	—	(234		)	—		(11,779		)
LTIP vesting	44		—	—			903			—	(903		)			—
Tax netting repurchase	(8	)		—			(171		)	—	—			—		(171		)
Unit based compensation	—		—	—			—			—	1,184			—		1,184
Adjustments to other post retirement plan assets and liabilities			—	—										10		10
Balances at December 31, 2010	5,363		—				83,624			109	2,124			56		85,804
Net income (loss)							(11,465		)		(233		)	—		(11,698		)
Recapitalization	(4,602	)	4,526	—			—			76	—			—		—
Issuance of common units to public, net of offering costs	3,750		—	—			69,085			—	—			—		69,085
Unitholder distributions	—		—	—			(42,682		)	—	(864		)	—		(43,546		)
LTIP vesting	62		—	—			1,286			—	(1,286		)	—		—
Tax netting repurchase	(12	)	—	—			(215		)	—	—			—		(215		)



Unit based compensation	—	—	—		257		—	1,350		—		1,607
Adjustments to other post retirement plan assets and liabilities	—	—	—		—		—	—		359		359
Balances at December 31, 2011	4,561	4,526	$	—	$	99,890	185	$	1,091	$	415	$	101,396

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

American Midstream Partners, LP and Subsidiaries

Consolidated Statements of Cash Flows

(In thousands)



							Period from August 20, 2009			Predecessor
							(Inception Date)			Ten Months
	Year Ended December 31,						to December 31,			ended October 31,
	2011			2010			2009			2009
Cash flows from operating activities
Net income (loss)	$	(11,698	)	$	(8,644	)	$	(6,992	)	$	(5,337	)
Adjustments to reconcile net income (loss) to net cash provided (used) in from operating activities:
Depreciation and accretion expense	20,705			20,013			2,978			12,630
Amortization of deferred financing costs	1,262			807			118			—
Mark-to-market on derivatives	849			385			5			—
Unit based compensation	1,607			1,185			150			—
OPEB plan net periodic (benefit) cost	(82		)	—			—			—
(Gain) loss on acquisition of assets	(565		)	—			—			—
(Gain) loss on sale of assets	(399		)	—			—			—
Changes in operating assets and liabilities:
Accounts receivable	(562		)	791			(1,447		)	1,163
Unbilled revenue	2,449			(3,865		)	(18,329		)	(387		)
Due from affiliates	—			—			—			(13,144		)
Notes receivable from affiliates	—			—			—			26,872
Risk management assets	(670		)	(308		)	(82		)	—
Other current assets	(1,800		)	—			(1,523		)	646
Other assets, net	(54		)	(104		)	(199		)	(320		)
Accounts payable	(218		)	(954		)	1,934			1,242
Accrued gas purchases	(3,991		)	3,825			14,881			(8,113		)
Accrued expenses and other current liabilities	4,410			268			1,997			(922		)
Other liabilities	(811		)	392			(22		)	259
Net cash provided (used) in operating activities	10,432			13,791			(6,531		)	14,589
Cash flows from investing activities
Acquisition of operating assets from Enbridge Midcoast Energy, LP	—			—			(150,818		)	—
Acquisition of 50% interest in Burns Point Gas Plant from Marathon Oil Company	(35,500		)	—			—			—
Additions to property, plant and equipment	(6,369		)	(10,268		)	(1,158		)	(853		)
Proceeds from disposals of property, plant and equipment	125			—			—			—
Net cash provided (used) in investing activities	(41,744		)	(10,268		)	(151,976		)	(853		)
Cash flows from financing activities
Unit holder distributions	(43,546		)	(11,779		)	—			—
Contributions from parent	—			—			—			111,103
Proceeds upon issuance of common units to public, net of offering costs	69,085			—			—			—
Unit holder contributions	—			12,000			100,000			—
LTIP tax netting unit repurchase	(215		)	—			—			—
Distributions to parent	—			—			—			(25,772		)



Payments on other loan	(615		)	(1,000		)	(89		)	—
Borrowings on other loan	—			800			903			—
Repayments of notes to affiliates	—			—			—			(39,339		)
Deferred debt issuance costs	(2,489		)	—			(2,158		)	—
Borrowings on long-term debt	130,570			26,500			63,000			—
Payments on long-term debt	(120,670		)	(31,130		)	(2,000		)	(60,000		)
Net cash provided (used) in financing activities	32,120			(4,609		)	159,656			(14,008		)
Net increase (decrease) in cash and cash equivalents	808			(1,086		)	1,149			(272		)
Cash and cash equivalents
Beginning of period	63			1,149			—			421
End of period	$	871		$	63		$	1,149		$	149
Supplemental cash flow information
Interest payments	$	3,349		$	4,523		$	337		132
Supplemental non-cash information
Accrual of property, plant and equipment	$	75		$	—		$	—		$	—
Accrual of asset retirement obligation	$	872		$	6,058		$	—		$	—

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

American Midstream Partner’s LP and Subsidiaries

Notes to Consolidated Financial Statements

1. 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, marketing and transportation services in the Gulf Coast and Southeast regions of the United States. We hold our assets in a series of wholly owned limited liability companies as well as a limited partnership. Our capital accounts consist of general partner interests and limited partner interests.

We are controlled by our general partner, American Midstream GP, LLC, which is a wholly owned subsidiary of AIM Midstream Holdings, LLC.

Our interstate natural gas pipeline assets transport natural gas through Federal Energy Regulatory Commission (the “FERC”) regulated interstate natural gas pipelines in Louisiana, Mississippi, Alabama and Tennessee. Our interstate pipelines include:


•	American Midstream (Midla), LLC, which owns and operates approximately 370 miles of interstate pipeline that runs from the Monroe gas field in northern Louisiana south through Mississippi to Baton Rouge, Louisiana.


•	American Midstream (AlaTenn), LLC, which owns and operates approximately 295 miles of interstate pipeline that runs through the Tennessee River Valley from Selmer, Tennessee to Huntsville, Alabama and serves an eight-county area in Alabama, Mississippi and Tennessee.

Basis of Presentation

We have prepared the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The accompanying consolidated financial statements include 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.

Since we acquired our assets from Enbridge Midcoast Energy, L.P. effective November 1, 2009, the financial and operational data for 2009 is bifurcated between the period that American Midstream Partners Predecessor (our “Predecessor”) owned those assets and the period from our acquisition through the end of the year. Moreover, there is some overlap between these two periods resulting from the fact that we were formed on August 20, 2009, which was prior to the acquisition on November 1, 2009. As a result, the 2009 period that our Predecessor owned and operated the assets is the ten months ended October 31, 2009, while the successor 2009 period begins with our inception on August 20, 2009 and ends on December 31, 2009. Between the date of inception and the date of acquisition of the assets discussed in Note 2 on November 1, 2009, no operating activity occurred in the partnership.

We have made reclassifications to amounts reported in prior period consolidated financial statements to conform to our current year presentation. These reclassifications did not have an impact on net income for the period previously reported.

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 a 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.

Use of Estimates

When preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in

the preparation of financial statements. Estimates and judgments are used in, among other things (1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and (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 the FERC. The FERC exercises statutory authority over matters such as construction, transportation rates we charge and our underlying accounting practices and ratemaking agreements with customers. Accordingly, we record costs that are allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a non-regulated entity. Also, we record assets and liabilities that result from the regulated ratemaking process that would be recorded under GAAP for our regulated entities. As of December 31, 2011 and 2010, we had no such material regulatory assets or liabilities.

Revenue Recognition and the Estimation of Revenues and Cost of Natural Gas

We recognize revenue when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured. We record revenue and cost of product sold on a gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that are purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating or transportation, we record those fees separately in revenues. For the year ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009, respectively, we recognized the following revenues by category:



							Period from August 20, 2009		Predecessor
							(Inception Date)		Ten Months
	Year Ended December 31,						to December 31,		ended October 31,
	2011			2010			2009		2009
	(in thousands)
Revenue
Transportation - firm	$	10,504		$	10,610		$	2,274	$	10,616
Transportation - interruptible	3,583			3,313			444		1,662
Sales of natural gas, NGLs and condensate	233,319			197,706			30,078		129,673
Other	1,184			619			37		1,181
Realized gain (loss) on early termination of commodity derivatives	(2,998		)	—			—		—
Realized loss on expiration of commodity put contract	(308		)	—			—		—
Unrealized gain (loss) on commodity derivatives	(541		)	(308		)	—		—
Total revenue	$	244,743		$	211,940		$	32,833	$	143,132

Fee-based

Under these arrangements, we generally are paid a fixed cash fee for gathering and transporting natural gas. Fee-based revenues, which are included in sales of natural gas, NGLs and condensate above, are recorded when services have been provided, and collectability of the revenue is reasonably assured.

Percent-of-proceeds, or POP

Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas and NGLs 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 above, 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, above, when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred and collectability of the revenue is reasonably assured.

Firm transportation

Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not it utilizes the capacity. In most cases, the shipper also pays a variable use charge with respect to quantities actually transported by us. Firm transportation revenue is recorded when products are delivered, services have been provided and collectability of the revenue is reasonably assured.

Interruptible transportation

Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent 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. For each of the years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009, 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 assets acquired from Enbridge Pipelines, LP in November 2009 and the assets acquired from Marathon Oil Company in December 2011 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, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009.

We assess our long lived assets for impairment using authoritative guidance. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. Fair values, for the purposes of the impairment test, are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

Examples of long-lived asset impairment indicators include:


•	A significant decrease in the market price of a long-lived asset or group;


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


•	A significant adverse change in legal factors or in the business climate could affect the value of long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;


•	An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group;


•	A current-period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long lived asset or asset group; and


•	A current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

Income Taxes

We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of state income tax laws by the State of Texas that apply to entities organized as partnerships 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, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009.

Net income for financial statement purposes may differ significantly for 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 date 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 and report an asset separately from the associated liability in our consolidated financial statements.

We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount or if no amount 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 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 changes in the net pension asset or liability associated with the OPEB plan (Note 15). Comprehensive income (loss) for the years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009 is as follows:



							Period from August 20, 2009			Predecessor
							(Inception Date)			Ten Months
	Year Ended December 31,						to December 31,			ended October 31,
	2011			2010			2009			2009
	(in thousands)
Net income (loss)	$	(11,698	)	$	(8,644	)	$	(6,992	)	$	(5,337	)
Unrealized gains (losses) on post retirement benefit
plan assets and liabilities	359			10			46			(201		)
Comprehensives income (loss)	$	(11,339	)	$	(8,634	)	$	(6,946	)	$	(5,538	)

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 14.

Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value of our derivative instruments and disclosures associated with our outstanding indebtedness. We define fair value as an exit price representing the expected amount we would receive when selling an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.

We use various assumptions and methods in estimating the fair values of our financial instruments. The carrying amounts of cash and cash equivalents and accounts receivable approximated their fair value due to the short-term maturity of these

instruments. The carrying amount of our old and new credit facilities approximate fair value, because the interest rates on both 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 – We include in this category the fair value of assets and liabilities that we measure based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

•

Level 2 – We categorize the fair value of assets and liabilities that we measure with either directly or indirectly observable inputs as of the measurement date, where pricing inputs are other ant quoted prices in active markets for the identical instrument, as a Level 2. Assets and liabilities that we value using either models or other valuation methodologies are derived from observable market data. These models are primarily industry-standard models that consider various inputs including: (a) quoted prices for assets and liabilities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the assets and liabilities, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.

•

Level 3 – We include in this category the fair value of assets and liabilities that we measure based on prices or valuation techniques that require inputs which are both significant to the fair value measurement and less observable from objective sources (i.e., values supported by lesser volumes of market activity). We may also use these inputs with internally developed methodologies that result in our best estimate of the fair value. Level 3 assets and liabilities primarily include debt and derivative instruments for which we do not have sufficient corroborating market evidence support classifying the asset or liability as Level 2. Additionally, Level 3 valuations may utilize modeled pricing inputs to derive forward valuations, which may include some or all of the following inputs: nonbinding broker quotes, time value, volatility, correlation and extrapolation methods.

We utilize a mid-market pricing convention, or the “market approach”, for valuation for assigning fair value to our derivative assets and liabilities. Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.

Debt Issuance Costs

Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchase and debt extinguishment include any associated unamortized debt issue costs.

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”.

Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04 Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRS. The ASU amends previously issued authoritative guidance and is effective for interim and annual periods beginning after December 15, 2011. The amendments change requirements for measuring fair value and disclosing information about those measurements. Additionally, the ASU clarifies the FASB’s intent regarding the application of existing fair value measurement requirements and changes certain principles or requirements for measuring fair value or disclosing information about its measurements. For

many of the requirements, the FASB does not intend the amendments to change the application of the existing Fair Value Measurements guidance. This guidance will not have an impact on our financial position or results of operations.

In June 2011, the FASB issued ASU No. 2011-05 Presentation of Comprehensive Income. The ASU amends previously issued authoritative guidance and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. These amendments remove the option under current U.S. GAAP to present the components of other comprehensive income as part of the statements of changes in stockholder’s equity. The adoption of this guidance will not have an impact on our financial position or results of operations, but will require the us to present the statements of comprehensive income separately from its statements of equity, as these statements are currently presented on a combined basis.

In December 2011, the FASB issued ASU No. 2011-11 Disclosures about Offsetting Assets and Liabilities. The ASU requires additional disclosures about the impact of offsetting, or netting, on a company’s financial position, and is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods, and retrospectively for all comparative periods presented. Under US GAAP, derivative assets and liabilities can be offset under certain conditions. The ASU requires disclosures showing both gross information and net information about instruments eligible for offset in the balance sheet. The Company is currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on our financial position or results of operations.

2. Acquisitions

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 looked at 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 the necessary 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.




	(in thousands)
Consideration paid to seller
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.

Pro forma consolidated information

The following unaudited pro forma consolidated information sets forth our unaudited historical and pro forma consolidated statements of operations for the years ended December 31, 2011 and 2010.

The unaudited pro forma consolidated statements of operations for the years ended December 31, 2011 and 2010, give effect to the acquisition by us of the Interest as if it had occurred on January 1, 2010.

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 this acquisition 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.



	Year Ended December 31, 2011										Year Ended December 31, 2010
	American Midstream Partners, LP as previously reported			Pro forma adjustments				American Midstream Partners, LP pro forma			American Midstream Partners, LP as previously reported			Pro forma adjustments				American Midstream Partners, LP pro forma
	(unaudited in thousands, except per unit amounts)
Revenue	$	248,282		$	5,165		(a)	$	253,447		$	212,248		$	4,645		(a)	$	216,893
Realized gain (loss) on early termination of commodity derivatives	(2,998		)					(2,998		)	—							—
Unrealized gain (loss) on commodity derivatives	(541		)					(541		)	(308		)					(308		)
Total revenue	244,743			5,165				249,908			211,940			4,645				216,585
Operating expenses:
Purchases of natural gas, NGLs and condensate	202,403							202,403			173,821							173,821
Direct operating expenses	12,856			1,290			(b)	14,146			12,187			1,805			(b)	13,992
Selling, general and administrative expenses	10,794							10,794			7,120							7,120
Advisory services agreement termination fee	2,500							2,500			—							—
Transaction expenses	282							282			303							303
Equity compensation expense	3,357							3,357			1,734							1,734
Depreciation expense	20,705			751			(c)	21,456			20,013			902			(c)	20,915
Total operating expenses	252,897			2,041				254,938			215,178			2,707				217,885
Gain on purchase of assets	565			(565		)	(g)	—			—			565			(e)	565
Gain (loss) on sale of assets, net	399							399			—							—
Operating income (loss)	(7,190		)	2,559				(4,631		)	(3,238		)	2,503				(735		)
Other income (expenses):
Interest expense	(4,508		)	(2,602		)	(d)(f)	(7,110		)	(5,406		)	(2,703		)	(d)(f)	(8,109		)
Net income (loss)	$	(11,698	)	$	(43	)		$	(11,741	)	$	(8,644	)	$	(200	)		$	(8,844	)
General partner’s interest in net income (loss)	(233		)	(1		)		(234		)	(173		)	(4		)		(177		)
Limited partners’ interest in net income (loss)	$	(11,465	)	$	(42	)		$	(11,507	)	$	(8,471	)	$	(196	)		$	(8,667	)
Limited partners’ net income (loss) per unit	$	(1.64	)	$	(0.01	)		$	(1.65	)	$	(1.66	)	$	(0.04	)		$	(1.70	)
Weighted average number of units used in computation of limited partners’ net income (loss) per unit	6,997			6,997				6,997			5,099			5,099				5,099

Pro forma adjustments:


(a)	Assumes the value of allocated in-kind revenues from the beginning of the period.


(b)	Assumes allocated Plant direct operating costs and administrative fees from the beginning of the period.


(c)	Assumes depreciation expense from the beginning of the period, calculated on a straight-line basis over a 40 year useful life.


(d)	Assumes interest expense from the beginning of the period at the Partnership’s weighted average interest rate of 7.21% for the ten months ended October 31, 2011 and 7.48% for the year ended December 31, 2010.


(e)	Assumes a gain on purchase resulting from the difference between the cash consideration paid of $35.5 million and the fair value of the Interest of $36.1 million.


(f)	Assumes the straight-line amortization additional debt issuance costs over the remaining life of the credit facility, or 57 months, from the beginning of the period.


(g)	Elimination of bargain purchase gain which was assumed to have occurred at the beginning of the period presented.

Enbridge Assets

Effective November 1, 2009, American Midstream, LLC, a wholly owned subsidiary, acquired certain pipeline assets from Enbridge Midcoast Energy, LP, for an aggregate purchase price of $158.0 million. Prior to the acquisition, we had no operating tangible assets.

The acquired businesses were renamed as follows:

American Midstream (Alabama Intrastate), LLC

American Midstream (Bamagas Intrastate), LLC

American Midstream (Tennessee River), LLC

American Midstream (Mississippi), LLC

American Midstream (Midla), LLC

American Midstream (Alabama Gathering), LLC

American Midstream (AlaTenn), LLC

American Midstream Onshore Pipelines, LLC

Mid Louisiana Gas Transmission, LLC

American Midstream Offshore (Seacrest), LP

American Midstream (SIGCO Intrastate), LLC

American Midstream (Louisiana Intrastate), LLC

The acquisition qualifies as a business combination and, and as such we estimated the fair value of each property as of the acquisition date (the date on which we obtained control of the properties). The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements also utilize assumptions of market participants. We used a discounted cash flow model and made market assumptions as to future commodity prices, expectations for timing and amount of future development and operating costs, projections of future rates of production, and risk adjusted discount rates. These assumptions represent Level 3 inputs.

The following table summarizes the consideration paid to the seller and the amounts of assets acquired and liabilities assumed in the acquisition:




	(in thousands)
Consideration paid to seller
Cash consideration	$	150,818

Recognized amounts of identifiable assets acquired and liabilities assumed
Property, plant and equipment	$	151,085
Other post-retirement benefit plan assets, net	394
Other liabilities assumed	(661		)

Total identifiable net assets	$	150,818

Acquisition costs of $0.3 million and $6.4 million have been recorded in the statements of operations under the caption “Transaction expenses” for the year ended December 31, 2010 and the period ended December 31, 2009, respectively.

3. Concentration of Credit Risk and Trade Accounts Receivable

Our primary market areas are located in the United States along the Gulf Coast and in the Southeast. We have 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, 2011 and 2010 and the period ended December 31, 2009, no allowances on or write-offs of accounts receivable were recorded.

Enbridge Marketing (US) L.P., ConocoPhillips Corporation, Dow Chemical and ExxonMobil Corporation were significant customers, representing at least 10% of our consolidated revenue in the consolidated statement of operations in one or more of the periods presented, accounting for $44.8 million, $100.7 million, $15.7 million and $38.0 million, respectively, for the year ended December 31, 2011, $63.9 million, $53.4 million, $16.4 million and $22.9 million, respectively, for year ended December 31, 2010 and $17.8 million, $5.0 million, $3.1 million and $0.1 million, respectively, for the period ended December 31, 2009.

4. Other Current Assets



	December 31,
	2011		2010
	(in thousands)
Other receivables	$	663	$	30
Construction, operating and maintenance agreement (“COMA”)	623		—
Prepaid insurance—current portion	567		767
Other prepaid amounts	508		608
Gas imbalances receivable	852		—
NGL inventory	96		101
Other current assets	14		17
	$	3,323	$	1,523

For the years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009, we recorded no LCM write-downs on our inventory.

5. Derivatives

Commodity derivatives

To minimize the effect of a downturn in commodity prices and protect our profitability and the economics of our development plans, we enter into commodity economic 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 moderate the effects of a severe commodity price downturn while allowing us to participate in some commodity price increases. Management regularly monitors the commodity markets and financial commitments to determine if, when, and at what level some form of commodity hedging is appropriate in accordance with policies which are established by the board of directors of our general partner. Currently, the commodity hedges are in the form of swaps and puts.

In June 2011, the Board of Directors of our general partner determined that we would gain operational and strategic flexibility from cancelling our then-existing NGL swap contracts and entering into new NGL swap contracts with an existing counterparty that extend through the end of 2012. A $3.0 million realized loss resulting from the early termination of these swap contracts was recorded in the consolidated statement of operations for year ended December 31, 2011.

We may be required to post collateral with our counterparty in connection with our derivative positions. As of December 31, 2011, we had no posted collateral with our counterparty. The counterparty is not required to post collateral with us in connection with their derivative positions. Netting agreements are in place with our counterparty allowing us to offset our commodity derivative asset and liability positions.

As of December 31, 2011, the aggregate notional volume of our commodity derivatives was 11.4 million NGL gallons.

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, 2011 and 2010, the fair value associated with our derivative instruments were recorded in our consolidated balance sheets, under the caption Risk management assets and Risk management liabilities, as follows:



	December 31,
	2011		2010
	(in thousands)
Risk management assets:
Commodity derivatives	$	456	$	—
Risk management liabilities:
Commodity derivatives	$	635	$	—

For the years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009, we recorded the following realized and unrealized mark-to-market (losses):



							Period from August 20, 2009			Predecessor
							(Inception Date)			Ten Months
	Year Ended December 31,						to December 31,			ended October 31,
	2011			2010			2009			2009
	(in thousands)
Commodity derivatives	$	(849	)	$	(308	)	$	—		$	—
Interest rate derivatives	—			(77		)	(5		)	—
	$	(849	)	$	(385	)	$	(5	)	$	—

Fair Value Measurements

Our interest rate caps and commodity derivatives discussed above were classified as Level 3 derivatives for all periods presented.

The table below includes a roll-forward of the balance sheet amounts (including the change in fair value) for financial instruments classified by us within Level 3 of the valuation hierarchy. When a determination is made to classify a financial instrument within Level 3 of the valuation hierarchy, the determination is based upon the significance of the unobservable factors to the overall fair value measurement. Level 3 financial instruments typically include, in addition to the unobservable or Level 3 components, observable components (that is, components that are actively quoted and can be validated to external sources). Contracts classified as Level 3 are valued using price inputs available from public markets to the extent that the markets are liquid for the relevant settlement periods.



							Period from August 20, 2009			Predecessor
							(Inception Date)			Ten Months
	Year Ended December 31,						to December 31,			ended October 31,
	2011			2010			2009			2009
	(in thousands)
Fair value asset (liability), beginning of period	$	—		$	77		$	—		$	—
Realized gain (loss) on early termination of commodity derivatives	(2,998		)	—			—			—
Realized (loss) on expiration of commodity put Contract	(308		)	—			—			—
Unrealized gain (loss) on commodity derivatives	(541		)	(308		)	—			—
Unrealized gain (loss) on interest rate caps	—			(77		)	(5		)	—
Purchases	670			308			82			—
Settlements	2,998			—			—			—
Fair value asset (liability), end of period	$	(179	)	$	—		$	77		$	—

Also included in revenue were ($1.6) million and $nil million in realized gains (losses) for the years ended December 31, 2011 and 2010, respectively, representing our monthly swap settlements. No such gains (losses) were recorded for the periods ended December 31, 2009 and October 31, 2009.

6. Property, Plant and Equipment, Net

Property, plant and equipment, net, as of December 31, 2011 and 2010 were as follows:



		December 31,
	Useful Life	2011			2010
		(in thousands)
Land		$	41		$	41
Buildings and improvements	4 to 40	1,490			1,467
Processing and treating plants	8 to 40	49,396			13,010
Pipelines	5 to 40	149,040			143,805
Compressors	4 to 20	8,154			7,163
Equipment	8 to 20	1,580			1,711
Computer software	5	1,529			1,390
Total property, plant and equipment		211,230			168,587
Accumulated depreciation		(40,999		)	(21,779		)
Property, plant and equipment, net		$	170,231		$	146,808

Of the gross property, plant and equipment balances at December 31, 2011 and 2010, $24.0 million and $24.3 million, respectively, was related to AlaTenn and Midla, our FERC regulated interstate assets.

7. Asset Retirement Obligations

We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis, in the period in which the liability is incurred. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO. Typically, we record an ARO at the time the assets are installed or acquired if a reasonable estimate of fair value can 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, 2011 and 2010, we recognized $0.9 million and $6.1 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 $1.4 million, $1.2 million, $nil and $0.1 million for the years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009, respectively, in our consolidated statements of operations related to these AROs.

No assets were legally restricted for purposes of settling our ARO liabilities during the years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009. The following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009, respectively:



						Period from August 20, 2009		Predecessor
						(Inception Date)		Ten Months
	Year Ended December 31,					to December 31,		ended October 31,
	2011			2010		2009		2009
	(in thousands)
Balance at beginning of period	$	7,249		$	—	$	—	$	2,006
Additions	872			6,058		—		—
Reductions	(920		)	—		—		—
Expenditures	(501		)	—		—		—
Accretion expense	1,393			1,191		—		108
Balance at end of period	$	8,093		$	7,249	$	—	$	2,114

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 during 2011. 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.

8. Other Assets, Net

Other assets, net were as follows:



	December 31,
	2011		2010
	(in thousands)
Deferred financing costs	$	2,545	$	1,338
Other post retirement benefit plan assets, net	966		450
Prepaid amounts—long term	139		140
Security deposits	57		57
	$	3,707	$	1,985

Deferred financing costs

During the years ended December 31, 2011 and 2010 and the period ended December 31, 2009, 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, 2011 and 2010 and the period ended December 31, 2009, we recorded deferred financing costs of $1.3 million, $2.2 million and $0.1 million, respectively.

9. Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities were as follows:



	December 31,
	2011		2010
	(in thousands)
Deferred revenue—short term	$	2,314	$	210
Accrued salaries	1,542		957
Accrued expenses	953		839
Construction operating and maintenance agreement deposits	710		—
Gas imbalances payable	1,200		—
Contract obligations—short term	240		240
Accrued interest payable	123		407
Other	4		23
	$	7,086	$	2,676

10. Other Liabilities

Other liabilities were as follows:



	December 31,
	2011		2010
	(in thousands)
Deferred revenue—long term	$	351	$	528
Asset retirement obligations	8,093		7,249
Contract obligations—long term	88		208
Other deferred expenses	80		93
	$	8,612	$	8,078

11. Other Loan

Other loan represents insurance premium financing in the original amounts of $0.8 million bearing interest at 4.25 % per annum, which was repayable in equal monthly installments of less than $0.1 million through October 1, 2011.

12. Long-Term Debt

On November 4, 2009, we entered into an $85 million secured credit facility (“old credit facility”) with a consortium of lending institutions. The old credit facility was composed of a $50 million term loan facility and a $35 million revolving credit facility.

That credit facility provided for a maximum borrowing equal to the lesser of (i) $85 million less required amortization of term loan payments and (ii) 3.50 times adjusted consolidated EBITDA. We could have elected to have the loans under this credit facility bear interest at either (i) a Eurodollar-based rate with a minimum of 2.0% plus a margin ranging from 3.25% to 4.0% depending on our total leverage ratio then in effect, or (ii) at a base rate (the greater of (i) the daily adjusting LIBOR rate and (ii) a Prime-based rate which is equal to the greater of (A) the prime rate and (B) an interest rate per annum equal to the Federal Funds Effective Rate in effect that day, plus one percent) plus a margin ranging from 2.25% to 3.00% depending on the total leverage ratio then in effect. We also paid a facility fee of 1.0% per annum. In December 2009 we entered into an interest rate cap with participating lenders that effectively caped our Eurodollar-based rate exposure on that portion of our debt at 4.0%. The interest rate caps expired in December 2011. Prior to our initial public offering the weighted average interest rate on borrowings under our old credit facility was approximately 7.66%, 7.48% and 5.79% for the 7 months ended July 31, 2011 (date of termination), the year ended December 31, 2010 and the period ended December 31, 2009, respectively.

On August 1, 2011, we terminated the old credit facility and entered into our $100 million revolving credit facility (“new credit facility’). This new facility also contains a $50 million accordion feature which could bring the total facility commitment to $150 million.

The new credit facility provides for a maximum borrowing equal to the lesser of (i) $100 million or (ii) 4.50 times adjusted consolidated EBITDA. We may 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”, and (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 pay a commitment fee of 0.50% per annum on the undrawn portion of the revolving loan. Following our initial public offering the weighted average interest rate on borrowings under our new credit facility was 4.65% for the 5 months ended December 31, 2011. The blended weighted average interest rate for the year ended December 31, 2011 was 6.71%.

Our obligations under the new 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 new 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 (not less than 2.50 times). We were in compliance with all of the covenants under our credit facility as of December 31, 2011.

Our outstanding borrowings under the new credit facility at December 31, 2011 and the old credit facility at December 31, 2010, respectively, were:



	December 31,
	2011		2010
	(in thousands)
Term loan facility	$	—	$	45,000
Revolving loan facility	66,270		11,370
	66,270		56,370
Less: current portion	—		6,000
	$	66,270	$	50,370

At December 31, 2011 and 2010, respectively, letters of credit outstanding under the new and old credit facilities were $0.6 million.

In connection with our new credit facility and amendments thereto, we incurred $2.5 million in debt issuance costs which are being amortized on a straight-line basis over the term of the new credit facility. In addition, we recognized a $0.6 million loss upon the early termination of our old credit facility which has been included in interest expense in our consolidated statement of operations.

13. Partners’ Capital

Our capital accounts are comprised of a 2% general partner interest and 98% limited partner interests. Our limited partners have limited rights of ownership as provided 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.

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 $9.8 million and $11.8 million for years ended December 31, 2011 and 2010, respectively. No distributions were made during the period ended December 31, 2009. We made no distributions in respect of our general partner’s incentive distribution rights during any of the periods presented. 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 Prospectus.

The number of units outstanding was as follows:



	December 31,
	2011	2010
	(in thousands)
Limited partner common units	4,561	5,363
Limited partner subordinated units	4,526	—
General partner units	185	109

The outstanding units noted above reflect the retroactive treatment of the reverse unit split resulting from the recapitalization described above.

14. Long-Term Incentive Plan

Our general partner manages our operations and activities and employs the personnel who provide support to our operations. On November 2, 2009, the board of directors of our general partner adopted 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. The LTIP currently permits the grant of awards that include phantom units that typically vest ratably over four years and may also include distribution equivalent rights (“DER”s), covering an aggregate of 303,601 of our units. A DER entitles the grantee to a cash payment equal to the cash distribution made by us with respect to a unit during the period such DER is outstanding. At December 31, 2011 and 2010, 54,827 and 62,246 units, respectively, were 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 DERs.

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 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:



					Period from August 20, 2009 (Inception Date)
	Year Ended December 31,				to December 31,
	2011		2010		2009
	(in thousands)
Outstanding at beginning of period	205,864		175,236		—
Granted	19,414		74,437		175,236
Vested	(62,418	)	(43,809	)	—
Outstanding at end of period	162,860		205,864		175,236
Fair value per unit	14.70 to $19.69		14.70 to $16.15		$	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, 2011 and 2010 and the period ended December 31, 2009 was $3.4 million, $1.7 million and $0.2 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.

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 $1.2 million and $0.9 million for the years ending December 31, 2011 and 2010, respectively. No units vested during the period ended December 31, 2009.

The total compensation cost related to unvested awards not yet recognized at December 31, 2011 and 2010 was $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, 2011 is approximately 2.1 years.

15. 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.



	OPEB Plan
							Period from August 20, 2009			Predecessor
							(Inception Date)			Ten Months
	Year Ended December 31,						to December 31,			ended October 31,
	2011			2010			2009			2009
	(in thousands)
Change in benefit obligation
Obligation, beginning of period	$	869		$	734		$	—		$	741
Obligation assumed from the acquisition from Enbridge	—			—			771			—
Service cost	3			10			2			8
Interest cost	22			43			7			36
Actuarial (gain) loss	(367		)	112			(44		)	10
Benefits paid	(61		)	(30		)	(2		)	(24		)
Benefit obligation, ending	$	466		$	869		$	734		$	771
Change in plan assets
Fair value of plan assets, beginning of period	$	1,319		$	1,174		$	—		$	999
Plan assets acquired from Enbridge	—			—			1,165			—
Actual return on plan assets	99			61			11			122
Employer’s contributions	90			113			—			68
Benefits paid	(76		)	(29		)	(2		)	(24		)
Fair value of plan assets, ending	$	1,432		$	1,319		$	1,174		$	1,165
Funded status
Funded status	$	966		$	450		$	440		$	257

The amounts of plan assets recognized in our consolidated balance sheets were as follows:



	OPEB Plan
	December 31,
	2011		2010
	(in thousands)
Other assets	$	966	$	450
	$	966	$	450

The amounts included in accumulated other comprehensive income at December 31, 2011 and 2010 that have not been recognized as components of net periodic benefit expense are $0.4 million and $0.1 million, respectively, which relate to net gains.

Components of Net Periodic Benefit Cost and Other amounts Recognized in Other Comprehensive Income



	OPEB Plan
	December 31,
	2011			2010
	(in thousands)
Net Periodic (Benefit) Cost
Service cost	$	3		$	10
Interest cost	22			43
Expected return on plan assets	(60		)	(53		)
Amortization of net (gain) loss	(47		)	—
Net periodic (benefit) cost	$	(82	)	$	—
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
Net loss (gain)	(359		)	(10		)
Total recognized in other comprehensive income	(359		)	(10		)
Total recognized in net periodic benefit cost and other comprehensive income	$	(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:



	OPEB Plan
	2011		2010		2009
Discount rate	3.96	%	5.50	%	6.00	%
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 2011, 2010 and 2009 we selected the discount rate using the Citigroup Pension Discount Curve, or CPDC. The CPDC spot rates represent the equivalent yield on high-quality, zero-coupon bonds for specific maturities. These rates are used to develop a single, equivalent discount rate based on the OPEB Plan’s expected future cash flows.

Expected future benefit payments

The following table presents the benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five years thereafter by the OPEB Plan:




	Gross Benefit
	Payments
	OPEB Plan
	(in thousands)
For the year ending
2012	$	40
2013	39
2014	34
2015	33
2016	31
Five years thereafter	133

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 to the OPEB Plan for the year ending December 31, 2012 of $0.1 million.

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:



	OPEB Plan
	2011		2010		2009
Fixed income (a)	72.1	%	70.7	%	76.7	%
Cash and short term assets (b)	27.9	%	29.3	%	23.3	%
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

16. 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, 2011 are presented below:



	Payments Due by Period (in thousands)
	Total		2012		2013		2014		2015		2016		Thereafter
Operating leases and service contract	$	1,774	$	415	$	361	$	377	$	367	$	131	$	123
ARO	8,093		—		—		—		—		8,093		—
Total	$	9,867	$	415	$	361	$	377	$	367	$	8,224	$	123

For the periods indicated, total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements were:



					Period from August 20, 2009 (Inception Date)
	Year Ended December 31,				to December 31,
	2011		2010		2009
	(in thousands)
Operating leases	$	803	$	757	$	60
ARO	1,393		1,191		—
	$	2,196	$	1,948	$	60

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 MDEQ the SO2 emissions from the Bazor Ridge plant for 2009 and 2010. Moreover, we recently discovered that SO2 emission levels during 2009 may have exceeded the threshold that triggers the need for a Prevention of Significant Deterioration, or a PSD, permit under the federal Clean Air Act. No PSD permit has been issued for the Bazor Ridge plant. In addition, we recently 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 the EPA.

If the MDEQ or the EPA were to initiate enforcement proceedings with respect to these exceedances and violations, we could be subject to monetary sanctions and our Bazor Ridge plant could become subject to restrictions or limitations (including the possibility of installing additional emission controls) on its operations or be required to obtain a PSD permit or to amend its current Title V Air Permit. If the Bazor Ridge plant were subject to any curtailment or other operational restrictions as a result of any such enforcement proceeding, or were required to incur additional capital expenditures for additional emission controls through any permitting process, the costs to us could be material. Although enforcement proceedings are reasonably possible, we cannot estimate the financial impact on us from such enforcement proceedings until we have completed an investigation of these matters and met with the agencies to determine treatment, extent, and reportability any of exceedances and violations. As a result, we have not recorded a loss contingency as, the criteria under ASC 450, Contingencies, has not been met.

In addition, if emission levels for our Bazor Ridge plant were not properly reported by the prior owner or if a PSD permit was required for periods before our acquisition, it is possible, though not probable at this time, that one or both of the MDEQ and the EPA may institute enforcement actions against us and/or the prior owner. If one or both of the MDEQ and the EPA pursue enforcement actions or other sanctions against the prior owner, we may have an obligation under our purchase agreement with the prior owner to indemnify them for any losses (as defined in the purchase agreement) that may result. Because the existence and extent of any violations is unknown at this time, the financial impact of any amounts due regulatory agencies and/or the prior owner cannot be reasonably estimated at this time.

We are in communication with regulatory officials at both the MDEQ and the EPA regarding the Bazor Ridge plant reporting issue.

17. Related-Party Transactions

Employees of our general partner are assigned to work for us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by our general partner to American Midstream, LLC which, in turn, charges the appropriate subsidiary. Our general partner does not record any profit or margin for the administrative and operational services charged to us. During the years ended December 31, 2011 and 2010 and the period ended December 31, 2009 administrative and operational services expenses of $9.6 million, $7.6 million and $1.1 million, respectively, were charged to us by our general partner.

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. For the years ended December 31, 2011 and 2010 and the period ended December 31, 2009, $0.2 million, $0.3 million and less than $0.1 million had been recorded to selling, general and administrative expenses under this agreement.

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.

Predecessor Related Party Transactions

The Predecessor was wholly owned by Enbridge Midcoast Energy, L.P. (“Enbridge”) and its subsidiaries. For the ten months ended October 31, 2009, the Predecessor received contributions by Enbridge of $111.1 million and paid distributions to the Predecessor’s parent of $25.8 million.

Enbridge allocated certain overhead costs associated with general and administrative services, including executive management, accounting, information services, engineering, and human resources support to the Predecessor. These overhead costs were $6.7 million for the period ended October 31, 2009 and were allocated based primarily on a percentage of revenue, which we believe is reasonable. The Predecessor recorded operating revenues to Enbridge affiliates for natural gas gathering, treating, processing, marketing and transportation services of $73.9 million for the period ended October 31, 2009. The Predecessor also purchased natural gas from Enbridge affiliates for sale to third-parties at market prices on the date of purchase of $0.9 million for the period ended October 31, 2009.

Additionally, for the ten months ended October 31, 2009, the Predecessor had interest income of $0.4 million and interest expense of $4.1 million related to financing transactions with affiliates.

18. Reporting Segments

Our operations are located in the United States and are organized into two reporting segments: (1) Gathering and Processing, and (2) Transmission.

Gathering and Processing

Our Gathering and Processing segment provides “wellhead to market” services to producers of natural gas and oil, which include transporting raw natural gas from the wellhead through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs and selling or delivering pipeline quality natural gas and NGLs to various markets and pipeline systems.

Transmission

Our Transmission segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, including local distribution companies, or LDCs, utilities and industrial, commercial and power generation customers.

These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the business of each segment.

The following tables set forth our segment information for the periods indicated, in thousands:



	Gathering and Processing			Transmission		Total
Year ended December 31, 2011
Revenue	$	181,517		$	66,765	$	248,282
Segment gross margin (a),(b)	32,450			13,737		46,187
Realized gain (loss) on early termination of commodity derivatives	(2,998		)	—		(2,998		)
Realized (loss) on expiration of commodity put contracts	(308		)	—		(308		)
Unrealized gain (loss) on commodity derivatives	(541		)	—		(541		)
Direct operating expenses						12,856
Selling, general and administrative expenses						10,794
Advisory services agreement termination fee						2,500
Transaction expenses						282
Equity compensation expense						3,357
Depreciation expense						20,705
Gain (loss) on acquisition of assets						565
Gain (loss) on sale of assets, net						399
Interest expense						4,508
Net income (loss)						(11,698		)



	Gathering and Processing		Transmission		Total
Year ended December 31, 2010
Revenue	$	158,455	$	53,485	$	211,940
Segment gross margin (a),(b)	24,595		13,524		38,119
Realized gain (loss) on early termination of commodity derivatives	—		—		—
Unrealized gain (loss) on commodity derivatives	—		—		—
Direct operating expenses					12,187
Selling, general and administrative expenses					7,120
Advisory services agreement termination fee					—
Transaction expenses					303
Equity compensation expense					1,734
Depreciation expense					20,013
Gain (loss) on acquisition of assets					—
Gain (loss) on sale of assets, net					—
Interest expense					5,406
Net income (loss)					(8,644		)



	Gathering and Processing		Transmission		Total
Period from August 9, 2009 (inception date) to December 31, 2009
Revenue	$	27,857	$	4,976	$	32,833
Segment gross margin (a)	3,698		2,542		6,240
Realized gain (loss) on early termination of commodity derivatives
Unrealized gain (loss) on commodity derivatives
Direct operating expenses					1,594
Selling, general and administrative expenses					1,196
Advisory services agreement termination fee					—
Transaction expenses					6,404
Equity compensation expense					150
Depreciation expense					2,978
Gain (loss) on acquisition of assets					—
Gain (loss) on sale of assets, net					—
Interest expense					910
Net income (loss)					(6,992		)



	Gathering and Processing		Transmission		Total
Ten months ended October 31, 2009 (Predecessor)
Revenue	$	132,957	$	10,175	$	143,132
Segment gross margin (a)	20,024		9,881		29,905
Realized gain (loss) on early termination of commodity derivatives					—
Unrealized gain (loss) on commodity derivatives					—
Direct operating expenses					10,331
Selling, general and administrative expenses					8,553
Advisory services agreement termination fee					—
Transaction expenses					—
Equity compensation expense					—
Depreciation expense					12,630
Gain (loss) on acquisition of assets					—
Gain (loss) on sale of assets, net					—
Interest expense					3,728
Net income (loss)					$	(5,337	)

(a)

Segment gross margin for our Gathering and Processing segment consists of total revenue less purchases of natural gas, NGLs and condensate. Segment gross margin for our Transmission segment consists of total revenue, less purchases of natural gas. Gross margin consists of the sum of the segment gross margin amounts for each of these segments. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow from operations as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

(b)

Realized gains (losses) from the early termination of commodity derivatives and unrealized gains (losses) from derivative mark-to-market adjustments are included in total revenue and segment gross margin in our Gathering and Processing segment for the year ended December 31, 2010. 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 year ended December 31, 2011, $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.

For the purposes of our Gathering and Processing segment, for the years ended December 31, 2011 and 2010 and the period ended December 31, 2009, Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented significant customers, each representing more than 10% of our segment revenue in our Gathering and Processing segment. Our segment revenue derived from Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented $29.9 million, $100.7 million and $15.7 million of segment revenue for the year ended December 31, 2011, $47.3 million, $53.4 million and $16.4 million of segment revenue for the year ended December 31, 2010 and $14.7 million, $5.0 million and $3.1 million of segment revenue for the period ended December 31, 2009, respectively.

For purposes of our Transmission segment, for the years ended December 31, 2011 and 2010 and the period ended December 31, 2009, Enbridge Marketing (US) L.P., ExxonMobil Corporation and Calpine Corporation represented significant customers, each representing more than 10% of our segment revenue in our Transmission segment in one or more of the periods presented. Our segment revenue derived from Enbridge Marketing (US) L.P. ExxonMobil Corporation and Calpine Corporation represented $15.0 million, $38.0 and $5.1 million of segment revenue for the year ended December 31, 2011, $16.6 million, $22.9 million and $5.1 million of segment revenue for the year ended December 31, 2010 and $3.0 million, $0.1 million and $0.9 million of segment revenue for the period ended December 31, 2009, respectively.

19. 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:



							Period from August 20, 2009 (Inception Date)
	Year Ended December 31,						to December 31,
	2011			2010			2009
Net (loss) attributable to general partner and limited partners	$	(11,698	)	$	(8,644	)	$	(6,992	)
Weighted average general partner and limited partner units outstanding(a)(b)	7,137			5,199			2,231
General partner and limited partner (loss) per unit (basic and diluted)	$	(1.64	)	$	(1.66	)	$	(3.13	)
Net (loss) attributable to limited partners	$	(11,465	)	$	(8,471	)	$	(6,852	)
Weighted average limited partner units outstanding(a)(b)	6,997			5,099			2,187
Limited partners’ net (loss) per unit (basic and diluted)	(1.64		)	$	(1.66	)	$	(3.13	)
Net (loss) attributable to general partner	$	(233	)	$	(173	)	$	(140	)
Weighted average general partner units outstanding	140			99			43
General partner net (loss) per unit (basic and diluted)	$	(1.66	)	$	(1.75	)	$	(3.26	)


(a)	Includes unvested phantom units with DERs, which are considered participating securities, of 205,864 and 175,236 as of December 31, 2010 and 2009, respectively. The DER’s were eliminated on June 9, 2011. There were no such unvested phantom units with DERs at December 31, 2011.


(b)	Gives effect to the reverse unit split as described in Note 13, “Partners’ Capital”.

20. Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2011 and 2010 are as follows:



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(in thousands expect per unit amounts)
Year ended December 31, 2011
Revenues	$	63,765		$	65,634		$	57,958		$	57,386		$	244,743
Gross margin (a)	12,312			10,617			9,646			13,612			46,187
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	)
Year ended December 31, 2010
Revenues	$	54,712		$	47,790		$	52,953		$	56,485		$	211,940
Gross margin (a)	9,748			8,947			8,437			10,987			38,119
Operating income (loss)	(97		)	(1,478		)	(1,941		)	278			(3,238		)
Net income (loss)	$	(1,454	)	$	(2,853	)	$	(3,360	)	$	(977	)	$	(8,644	)
General partner’s interest in net income (loss)	(29		)	(57		)	(67		)	(20		)	(173		)
Limited partners’ interest in net income (loss)	$	(1,425	)	$	(2,796	)	$	(3,293	)	$	(957	)	$	(8,471	)
Limited partners’ net income (loss) per unit	$	(0.29	)	$	(0.56	)	$	(0.66	)	$	(0.18	)	$	(1.66	)


(a)	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 Note 18, Reporting Segments.

21. Subsequent Event

On January 24, 2012, we announced a distribution of $0.4325 per unit payable on February 10, 2012 to unitholders of record on February 3, 2012.

22. Subsidiary Guarantors

The Partnership has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities. The subsidiaries of the Partnership (the "Subsidiaries") will be co-registrants with the Partnership, and the registration statement will register guarantees of debt securities by one or more of the Subsidiaries (other than American Midstream Finance Corporation, a 100 percent owned subsidiary of the Partnership whose sole purpose is to act as co-issuer of such debt securities). As of December 31, 2011, the Subsidiaries are 100 percent owned by the Partnership and any guarantees by the Subsidiaries will be full and unconditional. 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 by dividend or loan. 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.

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