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:

 

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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.

 

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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								to				ended
		December 31,								December 31,				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:

 

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

 

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

 

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A significant adverse change in legal factors or in the business climate could affect the value of 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;

 

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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;

 

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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

 

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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:

 

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Commodity-based derivatives: “Total revenue”

 

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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								to				ended
		December 31,								December 31,				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	)
Compreshensive 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:

 

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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.

 

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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.

 

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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								to				ended
		December 31,								December 31,				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								to				ended
		December 31,								December 31,				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.