1. Organization and Basis of Presentation

Nature of Business

American Midstream Partners, LP (the “Partnership”) was formed on August 20, 2009 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 assets are primarily located in Alabama, Louisiana, Mississippi, and Texas. We organize our operations into two business segments: (1) Gathering and Processing; and (2) Transmission.

Our Gathering and Processing segment is an integrated midstream natural gas system that provides gathering, compression, treating, processing, transportation, and sales of natural gas, NGLs and condensate. Our Gathering and Processing segment includes the following systems:

 

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The Gloria gathering system provides gathering and compression services through our assets, as well as processing services through processing arrangements. The Gloria system is located in Lafourche, Jefferson, Plaquemines, St. Charles and St. Bernard parishes of Louisiana.

 

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The Lafitte gathering system consists of approximately 40 miles of gathering pipeline, with diameters ranging from 4 to 12 inches. The Lafitte system originates onshore in southern Louisiana and terminates in Plaquemines Parish, Louisiana at the Alliance Refinery owned by ConocoPhillips Corporation.

 

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The Bazor Ridge gathering and processing system consists of approximately 160 miles of pipeline with diameters ranging from 3 to 8 inches and 3 compressor stations with a combined compression capacity of 1,069 horsepower. Our Bazor Ridge system is located in Jasper, Clarke, Wayne and Greene Counties of Mississippi.

 

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The Quivira gathering system consists of approximately 34 miles of pipeline, with a 12-inch diameter mainline and several laterals ranging in diameter from 6 to 8 inches. The system originates offshore of Iberia and St. Mary Parishes of Louisiana in Eugene Island Block 24 and terminates onshore at a connection with the Burns Point Plant.

 

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The Burns Point Plant is located in St. Mary Parish, Louisiana, where raw natural gas is processed through a cryogenic processing plant that is jointly owned by us and the operator, Enterprise.

 

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The Offshore Texas system consists of the GIGS and Brazos systems, two parallel gathering systems that share common geography and operating characteristics. The Offshore Texas system provides gathering and dehydration services to natural gas producers in the shallow waters of the Gulf of Mexico region. The Offshore Texas system consists of approximately 56 miles of pipeline with diameters ranging from 6 to 16 inches.

 

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The Alabama Processing system consists of two small skid-mounted treating and processing plants that we refer to, individually, as Atmore and Wildfork. These treating and processing plants are located in Escambia and Monroe Counties of Alabama.

 

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The Magnolia gathering system is a Section 311 intrastate pipeline that gathers coalbed methane in Tuscaloosa, Greene, Bibb, Chilton and Hale counties of Alabama and delivers this natural gas to an interconnect with the Transco Pipeline system, an interstate pipeline owned by The Williams Companies, Inc. The Magnolia system consists of approximately 116 miles of pipeline with small-diameter gathering lines and trunklines ranging from 6 to 24 inches in diameter and 1 compressor station with 3,328 horsepower.

 

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Our other gathering and processing systems include the Fayette and Heidelberg gathering systems, located in Fayette County, Alabama and Jasper County, Mississippi, respectively.

 

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We also own a small Joule Thompson processing skid, called Stringer, which we lease to a producer in Wayne County, Mississippi.

Our intrastate natural gas pipeline assets transport natural gas through pipelines in Alabama and Louisiana. Our intrastate pipelines include:

 

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Our Bamagas system is a Hinshaw intrastate natural gas pipeline that travels west to east from an interconnection point with TGP in Colbert County, Alabama to 2 power plants owned by Calpine Corporation, in Morgan County, Alabama. The Bamagas system consists of 52 miles of high pressure, 30-inch pipeline.

 

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The MLGT system is an intrastate transmission system that sources natural gas from interconnects with the FGT Pipeline system, the Tetco Pipeline system, the Transco Pipeline system and our Midla system to a Baton Rouge, Louisiana refinery owned and operated by ExxonMobil and 7 other industrial customers. Our MLGT system is comprised of approximately 54 miles of pipeline with diameters ranging from 3 to 14 inches.

 

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Our other transmission systems include the Chalmette system, located in St. Bernard Parish, Louisiana, and the Trigas system, located in 3 counties in northwestern Alabama.

 

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We also own a number of miscellaneous interconnects and small laterals that are collectively referred to as the SIGCO assets.

Our interstate natural gas pipeline assets transport natural gas through FERC regulated interstate natural gas pipelines in Louisiana, Mississippi, Alabama and Tennessee. Our interstate pipelines include:

 

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Our Midla system includes 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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Our AlaTenn system includes approximately 295 miles of interstate pipeline that runs through the Tennessee River Valley from Selmer, Tennessee to Huntsville, Alabama and serves an 8 county area in Alabama, Mississippi and Tennessee.

Initial Public Offering

On July 26, 2011, we commenced the initial public offering of our common units pursuant to our Registration Statement on Form S-1, Commission File No. 333-173191 (the “Registration Statement”), which was declared effective by the SEC on July 26, 2011. Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner, & Smith Incorporated acted as representatives of the underwriters and as joint book-running managers of the offering.

Upon closing of our IPO on August 1, 2011, we issued 3,750,000 common units pursuant to the Registration Statement at a price per unit of $21.00. The Registration Statement registered the offer and sale of securities with a maximum aggregate offering price of $90,562,500. The aggregate offering amount of the securities sold pursuant to the Registration Statement was $78,750,000. In our IPO, we granted the underwriters a 30 day option to purchase up to 562,500 additional units to cover over-allotments, if any, on the same terms. This option expired unexercised on August 30, 2011.

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 IPO were $69.1 million. We used all of the net offering proceeds from our IPO for the uses described in the final prospectus filed with the SEC pursuant to Rule 424(b) on July 27, 2011.

On July 29, 2011, in connection with the closing of our initial public offering, our general partner contributed 76,019 of our common units to us in exchange for 76,019 general partner units in order to maintain its 2.0% general partnership interest in us. This transaction was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended.

Basis of Presentation

These unaudited condensed consolidated financial statements have been prepared in accordance with GAAP for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include disclosures required by GAAP for annual periods. The unaudited condensed consolidated financial statements for the three months ended March 31, 2012 and 2011 include all adjustments and disclosures that we believe are necessary for a fair statement of the results for the interim periods.

Our financial results for the three months ended March 31, 2012 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2012. These unaudited condensed consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2011 (“Annual Report”) filed on March 19, 2012.

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 GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things (1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.

Accounting for Regulated Operations

Certain of our natural gas pipelines are subject to regulations by 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 March 31, 2012 and 2011, we had no such material regulatory assets or liabilities.

 

2. Summary of Significant Accounting Policies

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

We recognize revenue when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured. We record revenue and cost of product sold on a gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that are purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating or transportation, we record those fees separately in revenues. For the three months ended March 31, 2012 and 2011, respectively, we recognized the following revenues by category:

 

		Three Months Ended March 31,
		2012				2011
		(in thousands)
Revenue
Transportation - firm		$	3,303			$	3,318
Transportation - interruptible			1,110				965
Sales of natural gas, NGLs and condensate			41,662				62,822
Other			1,313				160
Unrealized gain (loss) on commodity derivatives			323				(3,500	)
Total revenue		$	47,711			$	63,765

Limited Partners’ Net Income (Loss) Per Common Unit

We compute limited partners’ net income (loss) per common unit by dividing our limited partners’ interest in net income (loss) by the weighted average number of common units outstanding during the period. The overall computation, presentation and disclosure requirements for our limited partners’ net income (loss) per common unit are made in accordance with the “Earnings per Share” Topic of the Codification as described in the Annual Report. All per unit computations give effect to the retroactive application of the reverse unit split as described in Note 10, “Partners’ Capital”.

Recent Accounting Pronouncements

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 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.

3. 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 joint 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 Quivira system currently supplies approximately 88% 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 it is the majority of the inlet volume to the Quivira system and is included in our Gathering and Processing segment.

The Plant is not a legal entity but rather an asset that is jointly owned by the Operator and us. We acquired an interest in the asset group and do not hold an interest in a legal entity. Each of the owners in the asset group is proportionately liable for the liabilities. Outside of the rights and responsibilities of the Operator, we and the Operator have equal rights and obligations to the assets. Significant non-capital and maintenance capital expenditures, plant expansions and significant plant dispositions require the approval of both owners.

Under the terms of the Agreement, the Operator is required to provide monthly production allocation and expense statements to us and is not required to prepare and provide to us balance sheet information or stand-alone financial statements. Historically, balance sheet and stand-alone financial statements for the Plant have not been prepared and are, therefore, not available.

We reviewed the governance structure of the Plant and applied the concepts discussed in ASC-810-10-45 (“Other Presentation Matters.”) We determined that while the facility is an unincorporated joint venture, the asset group is jointly controlled with the Operator.

We reviewed the requirements for the application of the equity method of accounting, given the joint control attribute of the Plant, and because 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.

 

 

4. Concentration of Credit Risk and Trade Accounts Receivable

Our primary market areas are located in the United States along the Gulf Coast and in the Southeast. We have a concentration of trade receivable balances due from companies engaged in the production, trading, distribution and marketing of natural gas and NGL products. This concentration 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 three months ended March 31, 2012 and period ended December 31, 2011, no allowances on or write-offs of accounts receivable were recorded.

ConocoPhillips Corporation, Enbridge Marketing (US) L.P., and ExxonMobil Corporation were significant customers, representing at least 10% of our consolidated revenue, accounting for $16.1 million, $9.0 million, and $6.4 million, respectively, of our consolidated revenue in the consolidated statement of operations in the three months ended March 31, 2012, and $28.7 million, $12.0 million, and $9.5 million, respectively, for the three months ended March 31, 2011.

5. Derivatives

Commodity Derivatives

To minimize the effect of commodity prices and maintain our cash flow and the economics of our development plans, we enter into commodity hedge contracts from time to time. The terms of the contracts depend on various factors, including management’s view of future commodity prices, acquisition economics on purchased assets and future financial commitments. This hedging program is designed to mitigate the effect of commodity price downturns while allowing us to participate in some commodity price upside. Management regularly monitors the commodity markets and financial commitments to determine if, when, and at what level commodity hedging is appropriate in accordance with policies that are established by the board of directors of our general partner. Our existing 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.

In March 2012 we entered into a propane swap arrangement with an existing counterparty that extends through the end of 2013.

We enter into commodity contracts with multiple counterparties. We may be required to post collateral with our counterparties in connection with our derivative positions. As of March 31, 2012, we have not posted collateral with our counterparties. The counterparties are not required to post collateral with us in connection with their derivative positions. Netting agreements are in place with our counterparties that permit us to offset our commodity derivative asset and liability positions.

As of March 31, 2012, the aggregate notional volume of our commodity derivatives was 10.4 million NGL gallons.

Interest Rate Derivatives

Prior to the termination of our $85 million credit facility in August 2011, we utilized interest rate caps to protect against changes in interest rates on our floating rate debt.

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 changes in the mark-to-market value of the derivatives recorded in the balance sheets and through earnings, rather than being deferred until the anticipated transactions affect earnings. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices or interest rates.

As of March 31, 2012 and December 31, 2011, the fair value associated with our derivative instruments were recorded in our financial statements, under the caption Risk management assets and Risk management liabilities, as follows:

 

		March 31, 2012				December 31, 2011
		(in thousands)
Risk management assets:
Commodity derivatives		$	461			$	456
Risk management assets-long term:
Commodity derivatives		$	79			$	—
Risk management liabilities:
Commodity derivatives		$	396			$	635
Risk management liabilities-long term:
Commodity derivatives		$	—			$	—

We recorded the following unrealized mark-to-market gains (losses):

 

		Three Months Ended
		March 31,
		2012				2011
		(in thousands)
Commodity derivatives		$	323			$	(3,500	)
Interest rate derivatives			—				—
		$	323			$	(3,500	)

6. Fair Value

The authoritative guidance for fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers include:

 

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Level 1 – unadjusted quoted prices in active markets for identical assets or liabilities;

 

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Level 2 – inputs other than quoted prices in active markets that are either directly or indirectly observable; and

 

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Level 3 – defined as unobservable inputs for use when little or no market data exits, therefore requiring an entity to develop its own assumptions.

A financial instrument’s categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy.

We believe the carrying amount of cash and cash equivalents approximates fair value because of the short-term maturity of these instruments would be classified as Level 1 under the fair value hierarchy.

The recorded value of the amounts outstanding under the existing credit facility approximates its fair value, as interest rates are variable, based on prevailing market rates and the short-term nature of borrowings and repayments under the credit facility. Our existing revolving credit facility would be classified as Level 1 under the fair value hierarchy.

The fair value of all derivatives instruments is estimated using a market valuation methodology based upon forward commodity price and volatility curves, as well as other relevant economic measures. To extrapolate a forecast of future cash flows, discount factors are utilized. The inputs are obtained from independent pricing services, and we have made no adjustments to the obtained prices.

We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivatives contracts held. We will recognize transfers between levels at the end of the reporting period for which the transfer has occurred, there were no such transfers for three months ended March 31, 2012 or period ended December 31, 2011.

Quantitative Information about Level 3 Fair Value Measurements

 

		Fair Value at March 31, 2012				Valuation Technique		Unobservable Input		Range
Commodity derivative asset (liability), net			$144			Forecasted future cash flow		Forward commodity prices Volatility curves Discount factors		$1.354 to $1.671 20.0% to 33.8% 1.048 to 1.130

The significant unobservable inputs used in the fair value measurement of the commodity derivative asset (liability) are forward commodity prices and volatility curves. Significant increases or decreases in the inputs in isolation would result in a significantly lower or higher fair value measurement.

Fair Value of Financial Instruments

The following table sets forth by level within the fair value hierarchy for our net derivative assets (liabilities) that were measured at fair value on a recurring basis as of March 31, 2012 and December 31, 2011:

 

		Carrying Amount				Estimated Fair Value
						Level 1				Level 2				Level 3				Total
Commodity derivative asset (liability), net
March 31, 2012		$	144			$	—			$	—			$	144			$	144
December 31, 2011		$	(179	)		$	—			$	—			$	(179	)		$	(179	)

Changes in Level 3 Fair Value Measurements

The table below includes a roll forward of the balance sheet amounts (including the change in fair value) for financial instruments classified 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 or the relevant settlement periods:

 

		Three Months Ended
		March 31,
		2012				2011
		(in thousands)
Fair value asset (liability), beginning of period		$	(179	)		$	—
Unrealized gain (loss) on commodity derivatives			323				(3,920	)
Purchases			—				670
Settlements			—				345
Fair value asset (liability), end of period		$	144			$	(2,905	)

Also included in revenue were less than $0.1 million and $0.3 million in realized gains (losses) for the three months ended March 31, 2012 and 2011, respectively, representing our monthly swap settlements.

7. Property, Plant and Equipment, Net

Property, plant and equipment, net, as of March 31, 2012 and December 31, 2011 were as follows:

 

		Useful Life		March 31, 2012				December 31, 2011
		(in years)		(in thousands)
Land				$	41			$	41
Construction in progress					1,049				3,380
Buildings and improvements		4 to 40			1,439				1,490
Processing and treating plants		8 to 40			48,641				49,396
Pipelines		5 to 40			148,888				146,788
Compressors		4 to 20			8,156				7,437
Equipment		8 to 20			1,642				1,198
Computer software		5			1,508				1,500
Total property, plant and equipment					211,364				211,230
Accumulated depreciation					(46,152	)			(40,999	)
Property, plant and equipment, net				$	165,212			$	170,231

Of the gross property, plant and equipment balances at March 31, 2012 and December 31, 2011, $24.8 million and $24.0 million was related to AlaTenn and Midla, our FERC regulated interstate assets.

8. Asset Retirement Obligations

We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis, in the period in which the liability is incurred. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO. Typically, we record an ARO at the time the assets are installed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an ARO, we capitalize the costs as part of the carrying value of the related assets. We recognize an ongoing expense for the interest component of the liability as part of depreciation expense resulting from changes in the value of the ARO due to the passage of time. We depreciate the initial capitalized costs over the useful lives of the related assets. We extinguish the liabilities for an ARO when assets are taken out of service or otherwise abandoned.

During the three months ended March 31, 2012 and year ended December 31, 2011, we recognized $0 and $0.9 million of AROs 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, of less than $0.1 million and $0.3 million in our consolidated statements of operations for the three months ended March 31, 2012 and 2011, respectively, in our consolidated statements of operations related to these AROs.

No assets were legally restricted for purposes of settling our ARO during the three months ended March 31, 2012 and 2011. The following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for the three months ended March 31, 2012.

 

		March 31,
		2012
		(in thousands)
Balance at beginning of period		$	8,093
Additions			—
Reductions			—
Expenditures			—
Accretion expense			6
Balance at end of period		$	8,099

9. Long-Term Debt

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

The former 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 capped our Eurodollar-based rate exposure on that portion of our debt at 4.0%. The interest rate caps expired in December 2011.

On August 1, 2011, we terminated the former credit facility and entered into our $100 million revolving credit facility (“existing credit facility”). The existing credit facility also contains a $50 million accordion feature that could increase the total facility commitment to $150 million.

The existing 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 existing 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 existing credit facility was 4.65% for the five months ended December 31, 2011. The weighted average interest rate for the three months ended March 31, 2012 was 3.72%.

Our obligations under the existing 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 existing 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 existing 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 existing credit facility as of March 31, 2012.

Our outstanding borrowings under the existing credit facility at March 31, 2012 and December 31, 2011, respectively, were:

 

		March 31, 2012				December 31, 2011
		(in thousands)
Revolving loan facility		$	66,470			$	66,270

At March 31, 2012 and December 31, 2011, letters of credit outstanding under the credit facility were $0.6 million.

In connection with our existing credit facility and amendments thereto, we incurred $2.5 million in debt issuance costs that are being amortized on a straight-line basis over the term of the existing credit facility.

10. Partners’ Capital

Our capital accounts are comprised of approximately 2% general partner interest and 98% limited partner interests. Our limited partners have limited rights of ownership as provided for under our partnership agreement and, as discussed below, the right to participate in our distributions. Our general partner manages our operations and participates in our distributions, including certain incentive distributions pursuant to the incentive distribution rights that are nonvoting limited partner interests held by our general partner.

 

On August 1, 2011, we closed our IPO of 3,750,000 common units at an offering price of $21.00 per unit. After deducting underwriting discounts and commissions of $4.9 million paid to the underwriters, estimated 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 Annual Report.

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

The numbers of units outstanding were as follows:

 

		March 31,				December 31,
		2012				2011
		(in thousands)
Limited partner common units			4,577				4,561
Limited partner subordinated units			4,526				4,526
General partner units			185				185

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

Distributions

We made distributions of $4.0 million and $3.7 million for the three months ended March 31, 2012 and 2011, respectively. We made no distributions in respect of our general partner’s incentive distribution rights.

In addition to the distributions described above, in August 2011 we made a special distribution of $33.7 million to participants in our long-term incentive plan (“LTIP”) holding common units, AIM Midstream Holdings and our general partner.

11. Long-Term Incentive Plan

Our general partner manages our operations and activities and employs the personnel who provide support to our operations. On November 2, 2009, the board of directors of our general partner adopted a long-term incentive plan for its employees and consultants and directors who perform services for it or its affiliates. On May 25, 2010, the board of directors of our general partner adopted an amended and restated long-term incentive plan. The LTIP currently permits the grant of awards in the form of Partnership units, which may include distribution equivalent rights (“DER”s), covering an aggregate of 303,601 of our units. A DER entitles the grantee to a cash payment equal to the cash distribution made by the Partnership with respect to a unit during the period such DER is outstanding. At March 31, 2012 and December 31, 2011, 58,881 and 54,827 units, respectively, were available for future grant under the LTIP giving retroactive treatment to the reverse unit split in connection with our recapitalized described in our Annual Report.

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 equivalents 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 does not intend to settle these awards in cash. Although other types of awards are contemplated under the LTIP, all currently outstanding awards are phantom units without DERs.

Grants issued under the LTIP vest in increments of 25% on each of the first four anniversary dates of the date of the grant and do not contain any other restrictive conditions related to vesting other than continued employment.

 

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 adjusted EBITDA and DCF) and certain assumptions in the calculation of enterprise value.

The following table summarizes our unit-based awards for each of the periods indicated, in units:

 

		Three Months Ended March 31,
		2012				2011
		(in thousands)
Outstanding at beginning of period			162,860				205,864
Granted			—				19,414
Vested			(20,308	)			(15,454	)
Outstanding at end of period			142,552				209,824
Fair value per unit		$	14.70 to $19.69			$	14.70 to $19.69

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, for the three months ended March 31, 2012 and 2011 was $0.3 million and $0.3 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.

The total fair value of vested units at the time of vesting was $0.4 million and $1.2 million for the three months ended March 31, 2012 and period ended December 31, 2011, respectively.

The total compensation cost related to unvested awards not yet recognized at March 31, 2012 and period ended December 31, 2011 was $2.4 million and $2.7 million, respectively, and the weighted average period over which this cost is expected to be recognized as of March 31, 2012 is approximately 1.9 years.

12. 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”).

Components of Net Periodic (Benefit) Cost recognized in the Unaudited Condensed Consolidated Statements of Operations

 

		OPEB Plan
		Three Months Ended March 31,
		2012				2011
Net Periodic (Benefit) Cost		(in thousands)
Service cost		$	1				—
Interest cost			4				—
Expected return on plan assets			(17	)			—
Amortization of net (gain) loss			(9	)			—
Net periodic (benefit) cost		$	(21	)		$	—

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.

13. 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 and processing 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 March 31, 2012 are presented below:

 

		Payments Due by Period
		(in thousands)
		Total				2012				2013				2014				2015				2016				Thereafter
Operating leases and service contract		$	2,245			$	256			$	366			$	371			$	348			$	126			$	778
ARO			8,099				—				—				—				—				8,099				—
Total		$	10,344			$	256			$	366			$	371			$	348			$	8,225			$	778

Total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements were:

 

		Three Months Ended March 31,
		2012				2011
		(in thousands)
Operating leases		$	205			$	250
ARO			6				7
		$	211			$	257

Bazor Ridge Emissions Matter

In July 2011, in the course of preparing our annual filing for 2010 with the Mississippi Department of Environmental Quality (“MDEQ”) as required by our Title V Air Permit, we determined that we underreported to the MDEQ the SO₂ (sulfur dioxide) emissions from the Bazor Ridge plant for 2009 and 2010. In addition, we determined that certain SO₂ emissions during 2009 and 2010 exceeded the reportable quantity threshold under the federal Emergency Planning and Community Right-to-Know Act, or EPCRA, requiring notification of various governmental authorities. We did not make any such EPCRA notifications.

In July 2011, we self-reported these issues to the MDEQ and EPA. In January 2012, we met with EPA Region IV representatives, and have agreed to a settlement with respect to the EPCRA reporting issue. A Consent Agreement and Final Order is being circulated which includes a civil penalty of $23,010. After discussion with the MDEQ, in February 2012 we submitted an application to amend our Title V Air Permit to account for these SO₂ emissions. The MDEQ is currently processing this permit application.

Although these current negotiations with the MDEQ and EPA are proceeding towards completion, either agency could initiate further enforcement proceedings with respect to these matters, which could result in additional monetary sanctions and our Bazor Ridge plant could become subject to significant restrictions or limitations on its operations. 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. In addition, if emission levels for our Bazor Ridge plant were not properly reported by the prior owner 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, in which case we may have an obligation under our purchase agreement with the prior owner to indemnify them for any resulting losses (as defined in the purchase agreement). We cannot estimate the likelihood or financial impact from any further enforcement proceedings at this time, and therefore we have not recorded a loss contingency as the criteria under ASC 450, Contingencies, has not been met.

14. Related-Party Transactions

Employees of our general partner are assigned to work for us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by our general partner to American Midstream, LLC, which, in turn, charges the appropriate subsidiary. Our general partner does not record any profit or margin for the administrative and operational services charged to us. During the three months ended March 31, 2012 and 2011, administrative and operational services expenses of $3.7 million and $2.2 million, respectively, were charged to us by our general partner. The $1.5 million increase is primarily due to increased payroll costs.

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. On August 1, 2011, and in connection with our IPO, we terminated the advisory services agreement in exchange for a one-time payment of $2.5 million. For the three months ended March 31, 2011, $0.1 million was recorded to selling, general and administrative expenses under this agreement.

15. 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, 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, to producers of natural gas and oil.

 

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, and commercial and power generation customers.

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

The following tables set forth our segment information:

 

		Gathering and Processing				Transmission				Total
		(in thousands)
Three months ended March 31, 2012
Revenue		$	34,250			$	13,138			$	47,388
Segment gross margin (a)			9,418				4,761				14,179
Unrealized gain (loss) on commodity derivatives			323				—				323
Direct operating expenses			2,157				1,083				3,240
Selling, general and administrative expenses											3,329
Equity compensation expense											331
Depreciation and accretion expense											5,159
Gain (loss) on sale of assets, net											5
Interest expense											(757	)
Net income (loss)										$	1,691

 

		Gathering and Processing				Transmission				Total
		(in thousands)
Three months ended March 31, 2011
Revenue		$	48,084			$	19,181			$	67,265
Segment gross margin (a)			8,167				4,145				12,312
Unrealized gain (loss) on commodity derivatives			(3,500	)			—				(3,500	)
Direct operating expenses			1,949				1,109				3,058
Selling, general and administrative expenses											2,202
Transaction expenses											288
Equity compensation expense											473
Depreciation and accretion expense											5,037
Interest expense											(1,264	)
Net income (loss)										$	(3,510	)

 

 

(a)

Segment gross margin for our Gathering and Processing segment consists of total revenue less purchases of natural gas, NGLs and condensate. Segment gross margin for our Transmission segment consists of total revenue less purchases of natural gas. Gross margin consists of the sum of the segment gross margin for each segment. 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.

Asset information, including capital expenditures, by segment is not included in reports used by our management in their monitoring of performance and therefore is not disclosed.

For the purposes of our Gathering and Processing segment, for the three months ended March 31, 2012 and 2011, Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented significant customers, each representing more than 10% of our segment revenue for our Gathering and Processing segment. Our segment revenue derived from ConocoPhillips Corporation, Enbridge Marketing (US) L.P., and Dow Hydrocarbons and Resources represented $16.1 million, $5.7 million, and $4.0 million of segment revenue for the three months ended March 31, 2012 and $28.7 million, $7.6 million, and $3.9 million for the three months ended March 31, 2011 respectively.

For the three months ended March 31, 2012 and 2011, Enbridge Marketing (US) L.P., ExxonMobil Corporation and Calpine Corporation represented significant customers, each representing more than 10% of our segment revenue in our Transmission segment. Our segment revenue derived from ExxonMobil Corporation, Enbridge Marketing (US) L.P. and Calpine Corporation represented $6.4 million, $3.3 million and $1.3 million of segment revenue for the three months ended March 31, 2012 and $9.5 million, $4.4 million and $0.8 million for the three months ended March 31, 2011, respectively.

 

16. Net Income (Loss) per Limited Common and General Partner Unit

Net income (loss) is allocated to the general partner and the limited partners (common 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 common unit is calculated by dividing limited partners’ interest in net income (loss) by the weighted average number of outstanding limited partner common units during the period.

Unvested share-based payment awards that contain non-forfeitable rights to distributions (whether paid or unpaid) are classified as participating securities and are included in our computation of basic and diluted net income per limited partner unit.

We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of our 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 determined basic and diluted net income (loss) per general partner unit and limited partner unit as follows:

 

		Three Months Ended March 31,
		2012				2011
Net income (loss) attributable to general partner and limited partners		$	1,691			$	(3,510	)
Weighted average general partner and limited partner units outstanding (basic) (a)(b)			9,277				5,677
General partner and limited partner net income (loss) per unit (basic)		$	0.18			$	(0.62	)
Weighted average general partner and limited partner units outstanding (diluted) (a)(b)(c)			9,435				5,677
General partner and limited partner net income (loss) per unit (diluted)		$	0.18			$	(0.62	)
Net income (loss) attributable to limited partners		$	1,657			$	(3,440	)
Weighted average limited partner units outstanding (basic) (a)(b)			9,092				5,568
Limited partners’ net income (loss) per unit (basic)			0.18			$	(0.62	)
Weighted average limited partner units outstanding (diluted) (a)(b)(c)			9,250				5,568
Limited partners’ net income (loss) per unit (diluted)			0.18			$	(0.62	)
Net income (loss) attributable to general partner		$	34			$	(70	)
Weighted average general partner units outstanding (basic) (b)			185				109
General partner net income (loss) per unit (basic)		$	0.18			$	(0.64	)
Weighted average general partner units outstanding (diluted) (b)(c)			185				109
General partner net income (loss) per unit (diluted)		$	0.18			$	(0.64	)

 

a)	Includes unvested phantom units with DER’s, which are considered participating securities, of 190,409 as of March 31, 2011. There were no such unvested phantom units with DER’s at March 31, 2012.

 

b)	Gives effect to the reverse unit split as described in Note 10, “Partners’ Capital”.

 

c)	Considers all unvested shares as fully vested for Dilutive EPU Calculation.

17. Subsequent Events

On April 27, 2012, we announced a distribution of $0.4325 per unit payable on May 14, 2012 to unitholders of record on May 7, 2012.