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

	•		American Midstream (Midla), LLC, which owns and operates approximately 370 miles of interstate pipeline that runs from the Monroe gas field in northern Louisiana south through Mississippi to Baton Rouge, Louisiana.
	•		American Midstream (AlaTenn), LLC, which owns and operates approximately 295 miles of interstate pipeline that runs through the Tennessee River Valley from Selmer, Tennessee to Huntsville, Alabama and serves an eight-county area in Alabama, Mississippi and Tennessee.

Basis of Presentation

     These unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include disclosures required by GAAP for annual periods. The unaudited condensed consolidated financial statements for the three months and nine months ended September 30, 2011 and 2010 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 and nine months ended September 30, 2011 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2011. These unaudited condensed consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our final prospectus dated July 26, 2011 (the “Prospectus”) filed with the Securities and Exchange Commission pursuant to Rule 424 on July 27, 2011.

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

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 and nine months ended September 30, 2011 and 2010, respectively, the Partnership recognized the following revenues by category:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
Revenue
Transportation — firm		$	2,077			$	2,085			$	7,572			$	7,527
Transportation — interruptible			888				773				2,671				2,341
Sales of natural gas, NGLs and condensate			53,833				50,221				179,545				145,594
Other			207				79				586				224
Realized gain (loss) on early termination of commodity derivatives			—				—				(2,998	)			—
Unrealized gain (loss) on commodity derivatives			953				(205	)			(19	)			(231	)
Total revenue		$	57,958			$	52,953			$	187,357			$	155,455

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 common 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”. All per unit computations give effect to the retroactive application of the reverse unit split as described in Note 8, “Partners’ Capital” and Note 13, “Net Income (Loss) Per Limited and General Partner Unit.”

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 IFRSs. 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 the Company’s 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 the Company’s financial position or results of operations, but will require the Company to present the statements of comprehensive income separately from its statements of equity, as these statements are currently presented on a combined basis.

3. Concentration of Credit Risk and Trade Accounts Receivable

     We maintain allowances for potentially uncollectible accounts receivable. For the nine-month period ended September 30, 2011 and 2010, no allowances on or write-offs of accounts receivable were recorded.

     Enbridge Marketing (US) L.P., ConocoPhillips Corporation and ExxonMobil Corporation were significant customers, representing at least 10% of our consolidated revenue in one or more of the periods presented, accounting for $10.5 million, $24.3 million and $10.1 million, respectively, of our consolidated revenue in the unaudited condensed consolidated statement of operations in the three months ended September 30, 2011 and $33.4 million, $78.6 million and $29.8 million, respectively, for the nine months ended September 30, 2011.

4. Derivatives

     Commodity Derivatives

     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 unaudited condensed consolidated statement of operations for the nine months ended September 30, 2011.

     We may be required to post collateral with our counterparty in connection with our derivative positions. As of September 30, 2011, we had no posted collateral with our counterparty. Our 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 September 30, 2011, the aggregate notional volume of our commodity derivatives was 14.6 million NGL gallons.

  Interest Rate Derivatives

     We also utilize interest rate caps to protect against changes in interest rates on our floating rate debt. At September 30, 2011, we had $29.4 million outstanding under our new $100 million revolving credit facility with interest accruing at a rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates, we have entered into interest rate caps that mitigate the risk of increases in interest rates. As of September 30, 2011, we had interest rate caps with a notional amount of $22.0 million that effectively fix the base rate on that portion of our debt, with a fixed maximum rate of 4%.

     For our accounting purposes, no derivative instruments were designated as hedging instruments and were instead accounted for under the mark-to-market method of accounting, with any changes in the mark-to-market value of the derivatives recorded in the balance sheets and through earnings, rather than being deferred until the anticipated transactions affect earnings. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity prices indices or interest rates.

     As of September 30, 2011 and December 31, 2010, 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:

		September 30,				December 31,
		2011				2010
		(in thousands)
Risk management assets:
Commodity derivatives		$	1,153			$	—
Interest rate derivatives			—				—
		$	1,153			$	—
Risk management liabilities:
Commodity derivatives		$	502			$	—
Interest rate derivatives			—				—
		$	502			$	—

     For the three and nine months ended September 30, 2011 and 2010 we recorded the following unrealized mark-to-market gains (losses):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
		(in thousands)
Commodity derivatives		$	953			$	(205	)		$	(19	)		$	(231	)
Interest rate derivatives			—				(8	)			—				(23	)
		$	953			$	(213	)		$	(19	)		$	(254	)

  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.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
		(in thousands)
Fair value asset (liability), beginning		$	(302	)		$	344			$	—			$	77
Realized gain (loss) on early termination of commodity derivatives			—				—				(2,998	)			—
Unrealized gain (loss) on commodity derivatives			953				(205	)			(19	)			(231	)
Unrealized gain (loss) on interest rate cap			—				(8	)			—				(23	)
Purchases			—				—				670				308
Settlements			—								2,998				—
Fair value asset (liability), ending		$	651			$	131			$	651			$	131

     Also included in revenue were ($0.4) million and ($1.3) million in realized gains (losses) for the three and nine months ended September 30, 2011, respectively, representing our monthly swap settlements. No such gains (losses) were recorded for the three and nine months ended September 30, 2010.

5. Property, Plant and Equipment, Net

     Property, plant and equipment, net, as of September 30, 2011 and December 31, 2010 were as follows:

						September 30,				December 31,
		Useful Life				2011				2010
						(in thousands)
Land						$	41			$	41
Buildings and improvements			4 to 40				4,684				2,523
Processing and treating plants			8 to 40				10,978				11,954
Pipelines			5 to 40				146,905				143,805
Compressors			4 to 20				8,032				7,163
Equipment			8 to 20				1,653				1,711
Computer software			5				1,506				1,390
Total property, plant and equipment							173,799				168,587
Accumulated depreciation							(36,209	)			(21,779	)
Property, plant and equipment, net						$	137,590			$	146,808

     Of the gross property, plant and equipment balances at September 30, 2011 and December 31, 2010, $24.0 million was related to AlaTenn and Midla, our FERC regulated interstate assets.

6. Asset Retirement Obligations

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

     During the year ended December 31, 2010, we recognized $6.1 million of ARO which is included in other liabilities for specific assets that we intend to retire for operational purposes. We recorded accretion expense, which is included in depreciation expense in our unaudited condensed consolidated statements of operations, of $0.4 million and $0.3 million for the three months ended September 30, 2011 and 2010, respectively, and $1.0 million and $0.9 million for the nine months ended September 30, 2011 and 2010, respectively, related to these AROs.

     No assets were legally restricted for purposes of settling our ARO liabilities during the nine months ended September 30, 2011 and 2010. Following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for the three and nine months ended September 30, 2011 and 2010, respectively.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
		(in thousands)
Balance at beginning of period		$	7,921			$	6,646			$	7,249			$	—
Additions			—				—				—				6,084
Reductions			(486	)			—				(486	)			—
Expenditures			(2	)			(2	)			(10	)			(8	)
Accretion expense			352				304				1,032				872
Balance at end of period		$	7,785			$	6,948			$	7,785			$	6,948

     In August 2011, we sold an abandoned portion of pipe for which we had recorded an ARO. As a result of this sale, we are no longer responsible for the costs of abandonment on this pipe and have reduced our ARO during the three months ended September 30, 2011 by $0.5 million.

7. Long-Term Debt

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

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

     The new credit facility provides for a maximum borrowing equal to the lesser of (i) $100 million or (ii) 4.50 times adjusted consolidated EBITDA. We may elect to have loans under the new credit facility bear interest either at a Eurodollar-based rate plus a margin ranging from 2.25% to 3.50% depending on our total leverage ratio then in effect, or a base rate which is a fluctuating rate per annum equal to the highest of (a) the Federal Funds Rate plus 1/2 of 1% (b) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its “prime rate”, and (c) the Eurodollar Rate plus 1.00% plus a margin ranging from 1.25% to 2.50% depending on the total leverage ratio then in effect. We also pay a commitment fee of 0.50% per annum on the undrawn portion of the revolving loan. For the nine months ended September 30, 2011 and 2010, the weighted average interest rate on borrowings under our old and new credit facilities were approximately 7.37% and 7.35%, respectively.

     Our obligations under the new credit facility are secured by a first mortgage in favor of the lenders in our real property. The terms of the new credit facility include covenants that restrict our ability to make cash distributions and acquisitions in some circumstances. The remaining principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date, August 1, 2016.

     The new credit facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the new 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 new credit facility as of September 30, 2011.

     Our outstanding borrowings under the new credit facility at September 30, 2011 and the old credit facility at December 31, 2010, respectively, were:

		September 30,				December 31,
		2011				2010
		(in thousands)
Term loan facility		$	—			$	45,000
Revolving loan facility			29,350				11,370
			29,350				56,370
Less: current portion			—				6,000
		$	29,350			$	50,370

     At September 30, 2011 and December 31, 2010, respectively, letters of credit outstanding under the old and new credit facilities were $0.6 million.

      In connection with our new credit facility, we incurred $2.3 million in debt issuance costs which are being amortized on a straight line basis until maturity of the new credit facility.

Fair Market Value of Financial Instruments

     We use various assumptions and methods in estimating the fair values of its financial instruments. The carrying amounts of cash and cash equivalents and accounts receivable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of our new and old credit facilities approximates fair value, because the interest rate on both facilities are variable.

8. Partners’ Capital

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

     On August 1, 2011, we closed the initial public offering (the “IPO”) of 3,750,000 of our common units at an offering price of $21 per unit. After deducting underwriting discounts and commissions of $4.9 million paid to the underwriters, offering expenses of $4.2 million and a structuring fee of $0.6 million, the net proceeds from our initial public offering were $69.1 million. We used all of the net offering proceeds from our initial public offering for the uses described in the Prospectus.

Immediately prior to the closing of our IPO the following recapitalization transactions occurred:

	•		each common unit held by AIM Midstream Holdings reverse split into 0.485 common units, resulting in the ownership by AIM Midstream Holdings of an aggregate of 5,327,205 common units, representing an aggregate 97.1% limited partner interest in us;
	•		the common units held by AIM Midstream Holdings then converted into 801,139 common units and 4,526,066 subordinated units;
	•		each general partner unit held by our general partner reverse split into 0.485 general partner units, resulting in the ownership by our general partner of an aggregate of 108,718 general partner units, representing a 2.0% general partner interest in us;

•

each common unit held by participants in our general partner’s long term incentive plan (the “LTIP”), reverse split into 0.485 common units, resulting in their ownership of an aggregate of 50,946 common units, representing an aggregate 0.9% limited partner interest in us; and

•

each outstanding phantom unit granted to participants in our LTIP reverse split into 0.485 phantom units, resulting in their holding an aggregate of 209,824 phantom units.

     In connection with the closing of our IPO and immediately following the recapitalization transactions, the following transactions also occurred:

•

AIM Midstream Holdings contributed 76,019 common units to our general partner as a capital contribution, and;

•

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

     The number of units outstanding were as follows:

		September 30,				December 31,				September 30,
		2011				2010				2010
		(in thousands)
Limited partner units			4,526				5,363				4,994
Limited partner subordinated units			4,526				—				—
General partner units			185				109				102

     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 $7.4 million and $8.5 million for the nine months ended September 30, 2011 and 2010, 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 AIM Midstream Holdings, participants in our LTIP holding common units and our general partner as described in the Prospectus.

9. Long-Term Incentive Plan

     Our general partner manages our operations and activities and employs the personnel who provide support to our operations. On November 2, 2009, the board of directors of our general partner adopted an LTIP for its employees, consultants and directors who perform services for it or its affiliates. On May 25, 2010, the board of directors of our general partner adopted an amended and restated LTIP. The LTIP currently permits the grant of awards that include phantom units that typically vest ratably over four years and may also include distribution equivalent rights (“DER”s), covering an aggregate of 303,601 of our units. A DER entitles the grantee to a cash payment equal to the cash distribution made by the us with respect to a unit during the period such DER is outstanding. At September 30, 2011 and December 31, 2010, 34,514 and 53,928 units, respectively, were available for future grant under the LTIP giving retroactive treatment to the reverse unit split described in Note 8 “Partners’ Capital”.

     Ownership in the awards is subject to forfeiture until the vesting date. The LTIP is administered by the board of directors of our general partner. The board of directors of our general partner, at its discretion, may elect to settle such vested phantom units with a number of units equivalent to the fair market value at the date of vesting in lieu of cash. Although our general partner has the option to settle in cash upon the vesting of phantom units, our general partner has not historically settled these awards in cash. Although other types of awards are contemplated under the LTIP, the only currently outstanding awards are phantom units without DERs.

     Grants issued under the LTIP vest in increments of 25% on each grant anniversary date and do not contain any vesting requirements other than continued employment.

     During 2011, the fair value of the grants issued was calculated by the general partner based on several valuation models, including: a DCF model, a comparable company multiple analysis and a comparable recent transaction multiple analysis. As it relates to the DCF model, the model includes certain market assumptions related to future throughput volumes, projected fees and/or prices, expected costs of sales and direct operating costs and risk adjusted discount rates. Both the comparable company analysis and recent transaction analysis contain significant assumptions consistent with the DCF model, in addition to assumptions related to comparability, appropriateness of multiples (primarily based on EBITDA and DCF) and certain assumptions in the calculation of enterprise value.

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
Outstanding at beginning of period			209,824				237,055				205,864				175,237
Granted			—				—				19,414				61,818
Vested			—				—				(15,454	)			—
Outstanding at end of period			209,824				237,055				209,824				237,055
Grant date fair value per share		$	14.70 to $19.69			$	14.70 to $16.15			$	14.70 to $19.69			$	14.70 to $16.15

     The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our units at each balance sheet date. Compensation costs related to these awards for the three months ended September 30, 2011 and 2010 was $0.3 million and $0.5 million, respectively, and for the nine months ended September 30, 2011 and 2010 was $3.0 million and $1.3 million, respectively, which is classified as equity compensation expense in the consolidated statement of operations and the noncash portion in partners’ capital on the consolidated balance sheet.

     The total compensation cost related to unvested awards not yet recognized on September 30, 2011 and December 31, 2010 was $3.0 million and $3.8 million, respectively, and the weighted average period over which this cost is expected to be recognized is approximately 2 years.

10. Commitments and Contingencies

  Environmental matters

     We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to natural gas pipeline operations and we could, at times, be subject to environmental cleanup and enforcement actions. We attempt to manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment.

  Commitments and contractual obligations

     Future non-cancelable commitments related to certain contractual obligations as of September 30, 2011 are presented below:

		Payments Due by Period (in thousands)
		Total				2011				2012				2013				2014				2015				Thereafter
Operating leases and service contract		$	1,918			$	144			$	415			$	361			$	377			$	367			$	254
ARO			7,785				—				—				—				—				—				7,785
Total		$	9,703			$	144			$	415			$	361			$	377			$	367			$	8,039

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
		(in thousands)
Operating leases		$	177			$	227			$	578			$	545
ARO			2				2				10				8
		$	179			$	229			$	588			$	553

Bazor Ridge Emissions Matter

     In July 2011, in the course of preparing our annual filing for 2010 with the Mississippi Department of Environmental Quality (“MDEQ”) as required by our Title V Air Permit, we determined that we underreported to MDEQ the SO₂ emissions from the Bazor Ridge plant for 2009 and 2010. Moreover, we recently discovered that SO₂ emission levels during 2009 may have exceeded the threshold that triggers the need for a Prevention of Significant Deterioration, or a PSD, permit under the federal Clean Air Act. No PSD permit has been issued for the Bazor Ridge plant. In addition, we recently determined that certain SO₂ emissions during 2009 and 2010 exceeded the reportable quantity threshold under the federal Emergency Planning and Community Right-to-Know Act, or EPCRA, requiring notification of various governmental authorities. We did not make any such EPCRA notifications. In July 2011, we self-reported these issues to the MDEQ and the EPA.

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

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

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

     11. Related-Party Transactions

     Employees of our general partner are assigned to work for us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by our general partner to American Midstream, LLC which, in turn, charges the appropriate subsidiary. Our general partner does not record any profit or margin for the administrative and operational services charged to us. During the three months ended September 30, 2011 and 2010, administrative and operational services expenses of $2.0 million and $1.9 million, respectively, were charged to us by our general partner. During the nine months ended September 30, 2011 and 2010, administrative and operational services expenses of $7.4 million and $5.2 million, respectively, were charged to us by our general partner.

     Prior to our IPO, we had entered into an advisory services agreement with American Infrastructure MLP Management, L.L.C., American Infrastructure MLP PE Management, L.L.C., and American Infrastructure MLP Associates Management, L.L.C., as the advisors. The agreement provided for the payment of $0.3 million in 2010 and annual fees of $0.3 million plus annual increases in proportion to the increase in budgeted gross revenues thereafter. In exchange, the advisors agreed to provide us services in obtaining equity, debt, lease and acquisition financing, as well as providing other financial, advisory and consulting services. For each of the three months ended September 30, 2011 and 2010, less than $0.1 million had been recorded to selling, general and administrative expenses under this agreement. For each of the nine months ended September 30, 2011 and 2010, $0.1 million had been recorded to selling, general and administrative expenses under this agreement.

     On August 1, 2011 and in connection with our IPO, we terminated the advisory services agreement in exchange for a payment of $2.5 million.

12. Reporting Segments

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

Gathering and Processing

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

Transmission

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

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

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

		Gathering
		and
		Processing				Transmission				Total
		(in thousands)
Three months ended September 30, 2011
Revenue		$	41,218			$	15,787			$	57,005
Segment gross margin (a),(b)			6,821				2,825				9,646
Realized gains (loss) on early termination of commodity derivatives			—				—				—
Unrealized gains (loss) on commodity derivatives			953				—				953
Direct operating expenses											3,385
Selling, general and administrative expenses											2,497
Advisory services agreement termination fee											2,500
Equity compensation expense											331
Depreciation expense											5,261
Interest expense											1,378
Gain on sale of assets, net											586
Net income (loss)											(4,167	)

		Gathering
		and
		Processing				Transmission				Total
		(in thousands)
Three months ended Sepetmber 30, 2010
Revenue		$	34,974			$	18,184			$	53,158
Segment gross margin (a)			5,720				2,717				8,437
Direct operating expenses											3,097
Selling, general and administrative expenses											1,803
Equity compensation expense											464
Depreciation expense											5,014
Interest expense											1,419
Net income (loss)											(3,360	)

		Gathering
		and
		Processing				Transmission				Total
		(in thousands)
Nine months ended September 30, 2011
Revenue		$	138,487			$	51,887			$	190,374
Segment gross margin (a)(b)			22,988				9,661				32,649
Realized gains (loss) on early termination of commodity derivatives			(2,998	)			—				(2,998	)
Unrealized gains (loss) on commodity derivatives			(19	)			—				(19	)
Direct operating expenses											9,548
Selling, general and administrative expenses											7,649
Advisory services agreement termination fee											2,500
Equity compensation expense											2,989
Depreciation expense											15,468
Interest expense											3,923
Gain on sale of assets, net											586
Net income (loss)											(11,859	)

		Gathering
		and
		Processing				Transmission				Total
		(in thousands)
Nine months ended September 30, 2010
Revenue		$	119,663			$	36,023			$	155,686
Segment gross margin (a)			17,457				9,675				27,132
Direct operating expenses											9,370
Selling, general and administrative expenses											5,061
Equity compensation expense											1,255
Depreciation expense											14,962
Interest expense											4,151
Net income (loss)											(7,667	)

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

     For the purposes of our Gathering and Processing segment, for the three months ended September 30, 2011 and 2010, Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented significant customers, each representing more than 10% of our segment revenue in our Gathering and Processing segment. Our segment revenue derived from Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented $7.1 million, $24.3 million and $4.5 million of segment revenue for the three months ended September 30, 2011 and $3.6 million, $19.1 million and $3.8 million for the three months ended September 30, 2010, respectively.

     For the nine months ended September 30, 2011 and 2010, Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented significant customers, each representing more than 10% of our segment revenue in one or more of the periods presented in our Gathering and Processing segment. Our segment revenue derived from Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented $22.0 million, $78.6 million and $12.2 million of segment revenue for the nine months ended September 30, 2011 and $40.6 million, $31.8 million and $13.8 million for the nine months ended September 30, 2010, respectively.

     For the three months ended September 30, 2011 and 2010, Enbridge Marketing (US) L.P. and ExxonMobil Corporation represented significant customers, each representing more than 10% of our segment revenue in our Transmission segment. Our segment revenue derived from Enbridge Marketing (US) L.P.

and ExxonMobil Corporation represented $3.3 million and $10.1 million of segment revenue for the three months ended September 30, 2011 and $3.8 million and $10.4 million for the three months ended September 30, 2010, respectively.

     For the nine months ended September 30, 2011 and 2010, Enbridge Marketing (US) L.P. and ExxonMobil Corporation represented significant customers, each representing more than 10% of our segment revenue in our Transmission segment. Our segment revenue derived from Enbridge Marketing (US) L.P. and ExxonMobil Corporation represented $11.4 million and $29.8 million of segment revenue for the nine months ended September 30, 2011 and $12.8 million and $14.0 million for the nine months ended September 30, 2010, respectively.

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

     Net income (loss) is allocated to the general partner and the limited partners (common and subordinated unit holders) in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic and diluted net income (loss) per limited partner unit is calculated by dividing limited partners’ interest in net income (loss) by the weighted average number of outstanding limited partner units during the period.

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

     We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

     The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit. We have no dilutive securities, therefore basic and diluted net income per unit are the same.

     We determined basic and diluted net income per general partner unit and limited partner unit as follows:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
Net loss attributable to general partner and limited partners		$	(4,167	)		$	(3,360	)		$	(11,859	)		$	(7,667	)
Weighted average general partner and limited partner units outstanding(a)(b)			7,932				5,098				6,421				5,079
Earnings per general partner and limited partner unit (basic and diluted)		$	(0.53	)		$	(0.66	)		$	(1.85	)		$	(1.51	)
Net loss attributable to limited partners		$	(4,084	)		$	(3,293	)		$	(11,622	)		$	(7,514	)
Weighted average limited partner units outstanding(a)(b)			7,774				5,001				6,296				4,982
Earnings per limited partner unit (basic and diluted)		$	(0.53	)		$	(0.66	)		$	(1.85	)		$	(1.51	)
Net loss attributable to general partner		$	(83	)		$	(67	)		$	(237	)		$	(153	)
Weighted average general partner units outstanding			158				97				125				97
Earnings per general partner unit (basic and diluted)		$	(0.53	)		$	(0.69	)		$	(1.90	)		$	(1.58	)

14. Subsequent Event

     On October 21, 2011, we announced a pro-rated distribution of $0.2690 per unit for the period from August 2, 2011 through September 30, 2011, payable on November 10, 2011 to unit holders of record on November 3, 2011.