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

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8-K/A - 8-K/A - American Midstream Partners, LP	amendedamid8-k9x16x1310xkr.htm

Exhibit 99.1

This Amendment No. 1 on Form 8-K/A (this "Amendment") amends Exhibit 99.1 to the Registrant's Current Report on Form 8-K, which the Registrant previously filed with the Securities and Exchange Commission on October 1, 2013 and which updated certain portions of the Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012 (such Exhibit 99.1, the "Original Exhibit"). The Registrant is filing this Amendment solely to reflect revisions to Part II, Items 6 and 7 which were included in the Original Exhibit. All other Items of the Original Exhibit are unaffected by this Amendment and such items have not been included in this Amendment. This Amendment No. 1 does not reflect events occurring after the filing date of the Original Exhibit or modify or update disclosures in the Original Exhibit except to amend Part II, Items 6 and 7.

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. These risks and uncertainties, many of which are beyond our control, include, but are not limited to, the risks set forth in “Item 1A. Risk Factors” as well as the following risks and uncertainties:


•	our ability to access capital to fund growth including access to the debt and equity markets, which will depend on general market conditions and the credit ratings for our debt obligations;


•	the amount of collateral required to be posted from time to time in our transactions;


•	our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks;


•	the level of creditworthiness of counterparties to transactions;


•	changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;


•	the timing and extent of changes in natural gas, natural gas liquids and other commodity prices, interest rates and demand for our services;


•	weather and other natural phenomena;


•	industry changes, including the impact of consolidations and changes in competition;


•	our ability to obtain necessary licenses, permits and other approvals;


•	the level and success of crude oil and natural gas drilling around our assets and our success in connecting natural gas supplies to our gathering and processing systems;


•	our ability to grow through acquisitions or internal growth projects and the successful integration and future performance of such assets; and


•	general economic, market and business conditions.

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Annual Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in “Item 1A. Risk Factors” in this Annual Report on Form 10-K (the “Annual Report”) and subsequent filing on Form 10-Q. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

Part II, Item 6. Selected Historical Financial and Operating Data

In the second quarter of 2013, the board of directors of American Midstream Partners GP, LLC (the "General Partner") authorized the management of the Partnership to commit to a plan to sell certain non-strategic gathering and processing assets which meet specific criteria as held for sale. As a result of the planned divestiture of these non-strategic midstream assets, we began accounting for the results of operations of these disposal groups as discontinued operations. As a result, we have recast certain information included in our consolidated financial statements for all periods presented in this report.

The following table presents selected historical consolidated financial and operating data for the periods and as of the dates indicated. We derived this information from our historical consolidated financial statements, historical combined Predecessor financial statements and accompanying notes. This information should be read together with, and is qualified in its entirety, by reference to those financial statements and notes, which for the years 2012, 2011, and 2010 are included elsewhere in this Form 8-K.

We acquired the Predecessor assets effective November 1, 2009. During the period from our inception, on August 20, 2009, to October 31, 2009, we had no operations although we incurred certain fees and expenses of approximately $6.4 million associated with our formation and the acquisition of our assets from Enbridge, which are reflected in the “Transaction costs” line item of our consolidated financial data for the period from August 20, 2009 through December 31, 2009.

For a detailed discussion of the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”



	American Midstream Partners, LP and Subsidiaries (Successor)												American Midstream Partners Predecessor
	Year Ended December 31, 2012			Year Ended December 31, 2011			Year Ended December 31, 2010			Period from August 20, 2009 (Inception Date) to 2009 December 31, 2009			10 Months Ended October 31, 2009			Year Ended December 31, 2008
	(in thousands, except per unit and operating data)
Statement of Operations Data:
Revenue	$	197,251		$	231,258		$	195,087		$	29,892		$	129,614		$	326,610
Realized gain (loss) in early termination of commodity derivatives	—			(2,998		)	—			—			—			—
Unrealized gain (loss) on commodity derivatives	992			(541		)	(308		)	—			—			—
Total revenue	198,243			227,719			194,779			29,892			129,614			326,610
Operating expenses:
Purchases of natural gas, NGLs and condensate	145,172			187,398			157,682			23,864			100,613			285,335
Direct operating expenses	16,798			11,419			10,944			1,477			9,328			11,904
Selling, general and administrative expenses	14,309			10,800			7,120			1,196			8,577			8,618
Advisory services agreement termination fee	—			2,500			—			—			—			—
Transaction expenses	—			282			303			6,404			—			—
Equity compensation expense(a)	1,783			3,357			1,734			150			—			—
Depreciation expense	21,284			20,449			19,904			2,962			12,540			13,373
Total operating expenses	199,346			236,205			197,687			36,053			131,058			319,230
Gain on acquisition of assets	—			565			—			—			—			—
Gain (loss) on involuntary conversion of property, plant and equipment	(1,021		)	—			—			—			—			—
Gain on sale of assets, net	123			399			—			—			—			—
Operating (loss) income	(2,001		)	(7,522		)	(2,908		)	(6,161		)	(1,444		)	7,380
Other (expense) income



Interest expense	(4,570		)	(4,508		)	(5,406		)	(910		)	(3,728		)	(5,747		)
Other income (expense)	—			—			—			—			24			854
Net (loss) income from continuing operations	(6,571		)	(12,030		)	(8,314		)	(7,071		)	$	(5,148	)	$	2,487
Discontinued operations
Income (loss) from operations of disposal groups	319			332			(330		)	79			(189		)	241
Net (loss) income	(6,252		)	(11,698		)	(8,644		)	(6,992		)	(5,337		)	2,728
Net income attributable to non-controlling interests	256			—			—			—			—			—
Net income (loss) attributable to the Partnership	(6,508		)	(11,698		)	(8,644		)	(6,992		)	(5,337		)	2,728
General partner’s interest in net loss	(129		)	$	(233	)	$	(173	)	(140		)
Limited partners’ interest in net income (loss)	$	(6,379	)	$	(11,465	)	$	(8,471	)	$	(6,852	)

Limited partners’ net loss per unit:
Net income (loss) from continuing operations	(0.73		)	(1.69		)	(1.60		)
Gain (loss) from discontinued operations	0.03			0.05			(0.06		)
Net loss	$	(0.70	)	$	(1.64	)	$	(1.66	)	$	(3.13	)
Weighted average number of units used in computation of limited partners’ net income (loss) per unit (f)	9,113			6,997			5,099			2,187
Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	18,348		$	10,432		$	13,791		$	(6,531	)	$	14,589		$	18,155
Investing activities	(62,427		)	(41,744		)	(10,268		)	(151,976		)	(853		)	(10,486		)
Financing activities	43,784			32,120			(4,609		)	159,656			(14,088		)	(7,929		)
Other Financial Data:
Adjusted EBITDA(b)	$	18,847		$	20,785		$	18,154		$	3,434		$	10,931		$	21,848
Cash distributions declared per common unit	$1.73			$0.70			—			—			—			—
Gross margin(c)	48,706			43,860			37,097			6,028			29,001			41,275
Segment gross margin:
Gathering and Processing	35,393			30,123			23,573			3,486			19,120			25,486
Transmission	13,313			13,737			13,524			2,542			9,881			15,789
Balance Sheet Data (At Period End):
Cash and cash equivalents	$	576		$	871		$	63		$	1,149		$	149		$	421
Accounts receivable and unbilled revenue	23,470			20,963			22,850			19,776			8,756			9,532



Property, plant and equipment, net	223,819	170,231	146,808	146,226	205,126	216,903
Total assets	256,696	199,551	173,229	174,470	250,162	277,242
Total debt (current and long term)(d)	128,285	66,270	56,370	61,000	—	60,000
Operating Data:
Gathering and processing Segment:
Throughput (MMcf/d)	299.3	250.9	175.6	169.7	211.8	179.2
Plant inlet volume (MMcf/d)(e)	116.1	36.7	9.9	11.4	11.7	12.5
Gross NGL production (Mgal/d)(e)	49.9	54.5	34.1	38.2	39.3	40.2
Gross condensate production (Mgal/d)(e)	22.6	6.8	—	—	—	—
Transmission segment:
Throughput (MMcf/d)	398.5	381.1	350.2	381.3	357.6	336.2
Firm transportation - capacity reservation (MMcf/d)	703.6	702.2	677.6	701.0	613.2	627.3
Interruptible transportation throughput (MMcf/d)	86.6	69.0	80.9	118.0	121.0	141.6


(a)	Represents cash and non-cash costs related to our LTIP. Of these amounts, $1.8 million, $1.6 million, $1.2 million and $0.2 million, for the years ended December 31, 2012, 2011, 2010 and the period ended December 31, 2009, respectively, were non-cash expenses.

(b)

For a definition of adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures,” and for a discussion of how we use adjusted EBITDA to evaluate our operating performance, please read “— How We Evaluate Our Operations.”


(c)	For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, Note 19 to our audited consolidated financial statements included elsewhere in this Annual Report and for a discussion of how we use gross margin to evaluate our operating performance, please read “— How We Evaluate Our Operations.”


(d)	Excludes Predecessor Note payable to Enbridge Midcoast Limited Holdings, L.L.C. of $39.3 million as of December 31, 2008.


(e)	Excludes volumes and gross production under our elective processing arrangements. For a description of our elective processing arrangements, please read “Business — Gathering and Processing Segment — Gloria System.”

(f)

Includes unvested phantom units with DERs, which are considered participating securities, of 205,864 and 175,236 as of December 31, 2010 and 2009, respectively . The DER’s were eliminated on June 9, 2011. There were no such unvested phantom units with DERs at December 31, 2011 or subsequent. The unit count also gives effect to the reverse unit split as described in Note 13, “Partners’ Capital” of our audited consolidated financial statements included in this Annual Report beginning on page F-1.

Part 2, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

In the second quarter of 2013, the board of directors of the General Partner authorized the management of the Partnership to commit to a plan to sell certain non-strategic gathering and processing assets which meet specific criteria as held for sale. As a result of the planned divestiture of these non-strategic midstream assets, we began accounting for the results of operations of these disposal groups as discontinued operations. As a result, we have recast certain information included in our consolidated financial statements for all periods presented in this report.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements and the related notes thereto included elsewhere in this Form 8-K. Our actual results may differ materially from those anticipated in these forward-looking statements or as a result of certain factors such as those set forth below under the caption “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are a growth-oriented Delaware limited partnership that was formed by affiliates of AIM in August 2009 to own, operate, develop and acquire a diversified portfolio of natural gas midstream energy assets. We are engaged in the business of gathering, treating, processing, fractionating and transporting natural gas through our ownership and operation of ten gathering systems, four processing facilities, two interstate pipelines and four intrastate pipelines. We also own a 50% undivided, non-operating interest in a processing plant located in southern Louisiana. Our primary assets, which are strategically located in Alabama, Louisiana, Mississippi, and Texas, provide critical infrastructure that links producers and suppliers of natural gas to diverse natural gas markets, including various interstate and intrastate pipelines, as well as utility, industrial and other commercial customers. We currently operate approximately 1,400 miles of pipelines that gather and transport over 600 MMcf/d of natural gas.

Significant financial highlights during the year ended December 31, 2012, include the following:


•	We distributed $16.1 million to our unitholders, or $1.73 per unit;


•	For the year ended December 31, 2012, gross margin increased to $48.7 million or 10.9% compared to the same period in 2011;


•	The Partnership acquired an 87.4% interest in the Chatom processing and fractionation plant and associated gathering infrastructure (the "Chatom system") from affiliates of Quantum Resources Management, LLC, effective July 1, 2012, for approximately $51.4 million; and


•	The Partnership amended its August 2011 credit facility to increase the borrowing capacity from $100 million to $200 million with a syndicate of eight banks led by Bank of America, N.A., as Administrative Agent, Collateral Agent, L/C Issuer and Lender.

Significant operational highlights and challenges during the year ended December 31, 2012, include the following:


•	Throughput attributable to American Midstream Partners, LP totaled 697.8 MMcf/d for the year, representing a 10.4% increase compared to the same period in 2011;

•

Certain assets were impacted by Hurricane Isaac, the negative financial impact for which was approximately $3.0 million. A portion of this amount related to foregone cash flows resulting from production curtailments immediately following the hurricane, and the remainder resulted from costs incurred to repair the damaged assets during the third and fourth quarters of 2012. The Partnership is insured for named windstorms on the affected assets after a $1.0 million deductible. The gathering and processing volumes associated with the assets that were damaged during Hurricane Isaac have returned to pre-hurricane levels;

•

The Partnership completed a scheduled turnaround of its Bazor Ridge processing plant in eastern Mississippi. The turnaround took longer than anticipated as a result of unscheduled repairs and upgrades that slowed the turnaround process but are expected to deliver long-term, improved efficiencies at the plant. The negative financial impact of the turnaround in the fourth quarter was approximately $1.1 million; and


•	The Partnership saw a decline in volumes on one of its offshore pipeline systems during the third and fourth quarters of 2012 as a result of a producer's work on one of its platforms. The Partnership continues to work with this producer to

negotiate the return of incremental volumes to the offshore pipeline system, although the contract terms may change for the incremental volumes going forward and a change in contract terms may have a material negative impact on financial results. While the Partnership expects the incremental volumes to return during the first half of 2013, the reduced volumes during the third and fourth quarters of 2012 resulted in a negative financial impact of approximately $2.0 million.

Our Operations

We manage our business and analyze and report our results of operations through two business segments:

•

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 various receipt points through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs from the natural gas, fractionating NGLs and selling or delivering pipeline quality natural gas as well as 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, which include local distribution companies (“LDCs”), utilities and industrial, commercial and power generation customers.

Gathering and Processing Segment

Results of operations from our Gathering and Processing segment are determined primarily by the volumes of natural gas we gather and process, the commercial terms in our current contract portfolio and natural gas, NGL and condensate prices. We gather and process gas primarily pursuant to the following arrangements:


•	Fee-Based Arrangements. Under these arrangements, we generally are paid a fixed cash fee for gathering and processing and transporting natural gas.

•

Fixed-Margin Arrangements. Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. By entering into back-to-back purchases and sales of natural gas, we are able to lock in a fixed-margin on these transactions. We view the segment gross margin earned under our fixed-margin arrangements to be economically equivalent to the fee earned in our fee-based arrangements.

•

Percent-of-Proceeds Arrangements (“POP”). Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas and NGLs at market prices. Where we provide processing services at the processing plants that we own or obtain processing services for our own account in connection with our elective processing arrangements, such as under our Toca contract, we generally retain and sell a percentage of the residue natural gas and resulting NGLs. However, we also have contracts under which we retain a percentage of the resulting NGLs and do not retain a percentage of residue natural gas, such as for our interest in the Burns Point Plant. Our POP arrangements also often contain a fee-based component.


•	Interest in the Burns Point Plant. We account for our interest in the Burns Point Plant using the proportionate consolidation method. Under this method, we include in our consolidated statement of operations, our value of plant revenues taken in-kind and plant expenses reimbursed to the operator.

•

Interest in the Chatom System. We account for our 87.4% undivided interest in the Chatom system pursuant to ASC No. 810-10-65-1, Noncontrolling Interests. Under this method, revenues, expenses, gains, losses, net income or loss, and other comprehensive income are reported in the consolidated financial statements at the consolidated amounts, which include the amounts attributable to the partners' interests and the noncontrolling interests. The consolidated income statement shall separately present net income attributable to the partners' interests and the noncontrolling interests.

Gross margin earned under fee-based and fixed-margin arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. However, a sustained decline in commodity prices could result in a decline in volumes and, thus, a decrease in our fee-based and fixed-margin gross margin. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. Under our typical POP arrangement, our gross margin is directly impacted by the commodity prices we realize on our share of natural gas and NGLs received as compensation for processing raw natural gas. However, our POP arrangements also often contain a fee-based component, which helps to mitigate the degree of commodity-price volatility we could experience under these arrangements. We further seek to mitigate our exposure to commodity price risk through our hedging program. Please read “ — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”

Transmission Segment

Results of operations from our Transmission segment are determined primarily by capacity reservation fees from firm transportation contracts and, to a lesser extent, the volumes of natural gas transported on the interstate and intrastate pipelines we own pursuant to interruptible transportation or fixed-margin contracts. Our transportation arrangements are further described below:

•

Firm Transportation Arrangements. Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not the shipper utilizes the capacity. In most cases, the shipper also pays a variable use charge with respect to quantities actually transported by us.


•	Interruptible Transportation Arrangements. Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable use charge for quantities actually shipped.

•

Fixed-Margin Arrangements. Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. We view fixed-margin arrangements to be economically equivalent to our interruptible transportation arrangements.

Contract Mix

Set forth below is a table summarizing our average contract mix for the years ended December 31, 2012 and 2011:



	For the Year Ended December 31, 2012				For the Year Ended December 31, 2011
	Segment Gross Margin		Percent of Segment Gross Margin		Segment Gross Margin		Percent of Segment Gross Margin
	(in millions)				(in millions)
Gathering and Processing
Fee based	$	8.5	24.0	%	$	9.0	29.9	%
Fixed Margin	1.9		5.4	%	3.7		12.3	%
Percent-of-Proceeds	25.0		70.6	%	17.4		57.8	%
Total	$	35.4	100.0	%	$	30.1	100.0	%
Transmission
Firm transportation	$	10.8	81.2	%	$	10.4	75.9	%
Interruptible transportation	1.9		14.3	%	2.1		15.3	%
Fixed margin	0.6		4.5	%	1.2		8.8	%
Total	$	13.3	100.0	%	$	13.7	100.0	%

How We Evaluate Our Operations

Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include throughput volumes, gross margin and direct operating expenses on a segment basis, and adjusted EBITDA on a company-wide basis.

Throughput Volumes

In our Gathering and Processing segment, we must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our systems. Our ability to maintain or increase existing volumes of natural gas and obtain new supplies is impacted by (i) the level of work-overs or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to or near our gathering systems, (ii) our ability to compete for volumes from successful new wells in the areas in which we operate, (iii) our ability to obtain natural gas that has been released from other commitments and (iv) the volume of natural gas that we purchase from connected systems. We actively monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.

In our Transmission segment, the majority of our segment gross margin is generated by firm capacity reservation fees, as opposed to the actual throughput volumes, on our interstate and intrastate pipelines. Substantially all Transmission segment gross margin is generated under contracts with shippers, including producers, industrial companies, LDCs and marketers, for firm and interruptible natural gas transportation on our pipelines. We routinely monitor natural gas market activities in the areas served by our transmission systems to pursue new shipper opportunities.

Gross Margin and Segment Gross Margin

Gross margin and segment gross margin are metrics that we use to evaluate our performance. We define segment gross margin in our Gathering and Processing segment as revenue generated from gathering and processing operations less the cost of natural gas, NGLs and condensate purchased. Revenue includes revenue generated from fixed fees associated with the gathering and treating of natural gas and from the sale of natural gas, NGLs and condensate resulting from gathering and processing activities under fixed-margin and percent-of-proceeds arrangements. The cost of natural gas, NGLs and condensate includes volumes of natural gas, NGLs and condensate remitted back to producers pursuant to percent-of-proceeds arrangements and the cost of natural gas purchased for our own account, including pursuant to fixed-margin arrangements.

We define segment gross margin in our Transmission segment as revenue generated from firm and interruptible transportation agreements and fixed-margin arrangements, plus other related fees, less the cost of natural gas purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.

We define gross margin as the sum of our segment gross margin for our Gathering and Processing and Transmission segments. The GAAP measure most comparable to gross margin is net income.

Effective January 1, 2011, we changed our gross margin and segment gross margin measure to exclude unrealized mark-to-market adjustments related to our commodity derivatives. For the year ended December 31, 2011, $0.5 million of unrealized losses was excluded from gross margin and the Gathering and Processing segment gross margin.

Effective April 1, 2011, we changed our gross margin and segment gross margin measure to exclude realized gains and losses associated with the early termination of commodity derivative contracts. For the year ended December 31, 2011, $3.0 million in such realized losses was excluded from gross margin and the Gathering and Processing segment gross margin.

Effective October 1, 2012, we changed our segment gross margin measure to exclude construction, operating and maintenance agreement (“COMA”) income. For the year ended December 31, 2012, $0.7 million and $2.7 million in COMA income was excluded from our Gathering and Processing segment gross margin and our Transmission segment gross margin, respectively.

Direct Operating Expenses

Our management seeks to maximize the profitability of our operations in part by minimizing direct operating expenses without sacrificing safety or the environment. Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities, lost and unaccounted for gas, and contract services comprise the most significant portion of our operating expenses. These expenses are relatively stable and largely independent of throughput volumes through our systems, but may fluctuate depending on the activities performed during a specific period.

Adjusted EBITDA

Adjusted EBITDA is a measure used by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:


•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;


•	the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unit holders and general partner;


•	our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and


•	the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

We define adjusted EBITDA as net income attributable to the Partnership, plus interest expense, income tax expense, depreciation expense less amounts attributable to discontinued operations, certain non-cash charges such as non-cash equity compensation, unrealized losses on commodity derivative contracts and selected charges that are unusual or non-recurring, less interest income, income tax benefit, unrealized gains on commodity derivative contracts, amortization of commodity put purchase costs, and selected gains that are unusual or non-recurring less amounts attributable to discontinued operations . The GAAP measure most directly comparable to adjusted EBITDA is net income.

We changed our calculation of adjusted EBITDA for 2011 to include the straight-line amortization of commodity put premiums over the life of the associated commodity put contracts. This is necessary as all unrealized commodity gains and losses, by definition, are excluded in calculating adjusted EBITDA and such premium costs would only be included in the calculation of adjusted EBITDA at the expiration of the put contract. We believe this treatment better reflects the allocation of commodity put premium costs over the benefit period of the commodity put contract. Commodity put premium amortization included in the calculation of adjusted EBITDA was $0.4 million for the year ended December 31, 2011. Further, we made a change to the calculation to exclude COMA income from adjusted EBITDA. COMA income excluded from adjusted EBITDA for the year ended December 31, 2011 was $0.9 million.

Note About Non-GAAP Financial Measures

Gross margin and adjusted EBITDA are non-GAAP financial measures. Each has important limitations as an analytical tool because it excludes some, but not all, items that affect the most directly comparable GAAP financial measures. Management compensates for the limitations of these non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.

You should not consider any of gross margin or adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin and adjusted EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

For a reconciliation of segment gross margin to net income, its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 19 to our audited consolidated financial statements included in this Form 10-K.

The following table reconciles the non-GAAP financial measure of adjusted EBITDA used by management to Net (loss) income attributable to the Partnership, their most directly comparable GAAP measure:



	For the Year Ended December 31,
	2012			2011			2010
	(in thousands)

Net income (loss) attributable to the Partnership	$	(6,508	)	$	(11,698	)	$	(8,644	)
Add:
Depreciation and accretion expense	21,284			20,449			19,904
Interest expense	4,570			4,508			5,406
Debt issuance costs	1,564			—			—
Realized loss on early termination of commodity derivatives	—			2,998			—
Realized loss on commodity put purchase costs	—			308			—
Unrealized (gain) loss on commodity derivatives	(992		)	541			—
Non-cash equity compensation expense	1,783			1,607			1,185
Advisory services agreement termination fee	—			2,500			—
Special distribution to holders of LTIP phantom units	—			1,624			—
Transaction expenses	—			282			303
Deduct:
COMA income	3,373			879			—
Straight-line amortization of put costs (1)	291			409			—
OPEB plan net periodic benefit (cost)	88			82			—
Gain (loss) on acquisition of assets	—			565			—
Gain (loss) on involuntary conversion of property, plant and equipment	(1,021		)	—			—
Gain (loss) on sale of assets, net	123			399			—
Adjusted EBITDA	$	18,847		$	20,785		$	18,154


(1)	Amounts noted represent the straight-line amortization of the cost of commodity put contracts over the life of the contract.

Items Affecting the Comparability of Our Financial Results

Our historical results of operations for the periods presented and those of our Predecessor may not be comparable, either to each other or to our future results of operations, for the reasons described below:

•

After our initial public offering, we began incurring incremental general and administrative expenses attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly SEC reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs; and director compensation.


•	In November 2010, we completed the construction of the Winchester lateral into our Bazor Ridge processing plant. Since its completion, the lateral has provided approximately 4,000 MMcf/d of incremental gas into the Bazor Ridge plant.


•	In December 2010, we completed an interconnect between our Lafitte pipeline and a pipeline on the TGP interstate system. This interconnect enables us to purchase natural gas from producers on the TGP system and deliver it to the Alliance Refinery and the Toca processing plant, which will enable us to process substantially more natural gas under our elective processing arrangements.


•	On December 1, 2011, we acquired a 50% undivided interest in the Burns Point Plant from Marathon Oil Company for total cash consideration of $35.5 million. No liabilities of the Seller were assumed. The purchase was effective November 1, 2011.

•

Effective July 1, 2012, we acquired an 87.4% undivided interest in the Chatom processing and fractionation plant and associated gathering infrastructure (the “Chatom system”) from affiliates of Quantum Resources Management, LLC. The acquisition fair value of consideration of $51.4 million includes a credit associated with the cash flow the Chatom Assets generated between January 1, 2012, and the effective date of July 1, 2012.

General Trends and Outlook

We expect our business to continue to be affected by the key trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Outlook

Prior to 2012, the United States and other industrialized countries experienced a significant economic downturn that led to a decline in worldwide energy demand. North American oil and natural gas supply was increasing as a result of the rise in domestic unconventional production. The combination of lower energy demand due to the economic downturn and higher North American oil and natural gas supply resulted in significant declines in oil, NGL and natural gas prices. While oil and NGL prices began to increase steadily during 2011, natural gas prices remained depressed and volatile throughout 2012 due to a continued increase in natural gas supply despite weaker offsetting demand growth. The outlook for a worldwide economic recovery in 2013 remains uncertain, and the timing of a recovery in worldwide demand for energy is difficult to predict. As a result, we expect natural gas prices to remain relatively low in the near term.

Notwithstanding the ongoing volatility in commodity prices, there has been a recent resurgence in the level of acquisition and divestiture activity in the midstream energy industry and we expect that trend to continue. In particular, we believe that opportunities to acquire midstream energy assets from third parties that fulfill our strategic objectives will continue to arise in the foreseeable future.

Supply and Demand Outlook for Natural Gas and Oil

Natural gas and oil continue to be critical components of energy consumption in the United States. According to the U.S. Energy Information Administration, or EIA, annual consumption of natural gas in the U.S. was approximately 25.4 trillion cubic feet, or Tcf, in 2012, compared to approximately 24.4 Tcf in 2011, representing an increase of approximately 4.1%. Domestic production of natural gas grew from approximately 24.0 Tcf in 2011 to approximately 25.3 Tcf in 2012, or an 5.4% increase. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States, representing approximately 63.9% of the total natural gas consumed in the United States during 2012. In particular, based on a report by the EIA, industrial natural gas demand is expected to grow from 6.1 Tcf in 2009 to 8.2 Tcf in 2020 as a result of an expected recovery in industrial production. According to the EIA, domestic crude oil production was approximately 6.4 million barrels per day, or MMBbl/d, in 2012, compared to approximately 5.7 MMBbl/d in 2011, representing an increase of approximately 12.3%. Domestic crude oil production is expected to continue to increase over time primarily due to improvements in technology that have enabled U.S. onshore producers to economically extract sources of supply, such as secondary and tertiary oil reserves and unconventional oil reserves, that were previously unavailable or uneconomic. We believe that current oil and natural gas prices and the existing demand for oil and natural gas will continue to result in ongoing oil and natural gas-related drilling in the United States as producers seek to increase their production levels. In particular, we believe that drilling activity targeting oil with associated natural gas, such as on our Bazor Ridge and Chatom systems, will remain active. We also believe that the current relatively low natural gas price environment will encourage the development of net industrial facilities that consume natural gas, which will benefit our transmission systems that are strategically located next to inland waterways, such as our AlaTenn and Midla complexes. Although we anticipate continued exploration and production activity in the areas in which we operate, fluctuations in energy prices can affect natural gas production levels over time as well as the timing and level of investment activity by third parties in the exploration for and development of new oil and natural gas reserves. We have no control over the level of oil and natural gas exploration and development activity in the areas of our operations.

Impact of Interest Rates

The credit markets recently have experienced near-record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. If this occurs, interest rates on floating rate credit facilities and future offerings in the debt capital markets could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price will be impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, reduce debt or for other purposes.

Credit markets continue to experience near-record lows, which we believe will continue through 2013; however, if monetary policy begins to tighten, our interest rates on floating rate debt facilities and future offerings in the debt capital markets could be higher. An increase in financing costs may affect yield requirements of investors who invest in our common units.

Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Other Matters

We believe the diversity of our assets and our hedged commodity position to protect against downside commodity risk are key elements to long-term growth and sustainable distributions.

We continue to actively manage our capital maintenance and capital program. On August 13, 2012, we announced a growth project and expect to construct a midstream system to gather, treat, compress and process natural gas from wells targeting multiple liquids-rich producing formations, including the Eaglebine Formation. The anticipated midstream system would include gathering and processing capacity to support customers' production as well as other third-party development in the area. We have completed construction on the initial phase of the midstream infrastructure and began operations in early 2013.

In our Gathering and Processing segment, favorable oil prices are supporting drilling activity in the liquids-rich Upper Smackover formation, which continues to benefit our Bazor Ridge and Chatom systems. In our Transmission segment, as a result of lower natural gas prices, we have seen increased interest from the industrial and utility markets in northern Alabama and southwestern Mississippi, which we believe will positively impact our AlaTenn and Midla systems.

Our expectations are based on assumptions we made and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Recent Events

On April 15, 2013, the Partnership, our general partner and AIM Midstream Holdings, LLC, an affiliate of American Infrastructure MLP Fund, entered into agreements with High Point Infrastructure Partners, LLC, an affiliate of ArcLight Capital Partners, LLC (“High Point”), pursuant to which High Point (i) acquired 90% of our general partner, which holds all of our general partner units and incentive distribution rights, and all of our subordinated units from AIM Midstream Holdings and (ii) contributed certain midstream assets and $15.0 million in cash to us in exchange for 5,142,857 convertible preferred units (the “Series A Preferred Units”) issued by the Partnership. As a result of these transactions, which were also consummated on April 15, 2013, High Point acquired both control of our general partner and a majority of our outstanding limited partnership interests. Please read "— ArcLight Transactions." Contemporaneously with the consummation of these transactions, we also entered into a Fourth Amendment to our credit agreement that, among other things, provides for the waiver of recent covenant breaches relating to consolidated total leverage ratio, modifies the covenant relating to total leverage ratio through the quarter ended December 31, 2014 and reduces the quarterly cash distribution that would otherwise be payable in respect of our subordinated units or Series A Preferred Units for the first, second, third and fourth quarters of 2013. Please read "— Fourth Amendment to Credit Facility" and "—Liquidity and Capital Resources — Our Credit Facility" for more information about our credit facility, covenant violations and related waivers and the Fourth Amendment.

ArcLight Transactions

Purchase Agreement

On April 15, 2013, AIM Midstream Holdings and High Point entered into a Purchase Agreement, pursuant to which High Point purchased from AIM Midstream Holdings all of the Partnership's 4,526,066 subordinated units and 90% of the limited liability company interests in our general partner, which holds all of our general partner units and incentive distribution rights. The transactions contemplated by the Purchase Agreement were consummated on April 15, 2013. Of the cash consideration paid to AIM Midstream Holdings, $12.5 million is being held in escrow until its release upon satisfaction of certain conditions.

Contribution Agreement

On April 15, 2013, the Partnership and High Point entered into a Contribution Agreement, pursuant to which High Point contributed to us 100% of the limited liability company interests in certain of its subsidiaries that own midstream assets located in southern and offshore Louisiana (the “High Point Assets”) and $15 million in cash in exchange for 5,142,857 newly issued Series A Preferred Units. Of the $15.0 million cash consideration paid by High Point, approximately $2.5 million was used to pay certain transaction expenses of High Point, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's June 2012 amended credit facility in connection with the Fourth Amendment. The transactions contemplated by the Contribution Agreement were consummated on April 15, 2013.

Third Amended & Restated Agreement of Limited Partnership

On April 15, 2013, our general partner amended our partnership agreement with the Third Amended & Restated Agreement of Limited Partnership (the “Amended Partnership Agreement”) providing for the creation and designation of the rights, preferences, terms and conditions of the Series A Preferred Units.

Under the terms of the Amended Partnership Agreement, commencing with the quarter ending on June 30, 2013 and ending with the earlier of the quarter that includes a conversion of the Series A Preferred Units and the quarter beginning October 1, 2014 (the “Coupon Conversion Quarter”), the Series A Preferred Units will each receive quarterly distributions (the “Series A Quarterly Distributions”) in an amount equal to (i) 0.01428571 of additional Series A Preferred Units (subject to customary anti-dilution adjustments) (the "PIK Distribution") and (ii) $0.25 in cash (with the additional Series A Preferred Units and cash portion relating to the quarter ending June 30, 2013 being prorated based on the number of days in such quarter that follow the date on which the Series A Preferred Units were issued). Commencing with the Coupon Conversion Quarter, the Series A Preferred Units will receive the Series A Quarterly Distributions in an amount equal to the greater of (a) the amount of aggregate distributions that would be payable had such Series A Preferred Units converted into Common Units and (b) a fixed rate of 0.023571428 multiplied by the conversion price, which will initially be $17.50 per Series A Preferred Unit (subject to customary anti-dilution adjustments) (the “Conversion Price”), paid in arrears within 45 days after the end of each quarter and prior to distributions with respect to the Common Units and Subordinated units. If we elect to reduce distributions on the Series A Preferred Units in order to satisfy our obligation under the Fourth Amendment to reduce distributions on either our subordinated units or Series A Preferred Units in respect of each of the quarters ending June 30, September 30 and December 31, 2013, no part of any such reduction will accrue or accumulate or bear interest.

The record date for the determination of holders entitled to receive Series A Quarterly Distributions will be the same as the record date for determination of Common Unit holders entitled to receive quarterly distributions.

If we fail to pay in full any Series A Quarterly Distribution, the amount of such unpaid distribution will accrue, accumulate and bear interest at a rate of 6.0% per annum from the first day of the quarter immediately following the quarter for which such distribution is due until paid in full.

The Series A Preferred Units have voting rights that are identical to the voting rights of the Common Units and will vote with the Common Units as a single class, with each Series A Preferred Unit entitled to one vote for each Common Unit into which such Series A Preferred Unit is convertible. The Series A Preferred Units also have separate class voting rights on any matter, including a merger, consolidation or business combination, that adversely affects, amends or modifies any of the rights, preferences, privileges or terms of the Series A Preferred Units. Moreover, the general partner may not take any of the following actions without the prior written consent of High Point or any of its affiliates, as long as High Point or such affiliates together hold at least 50% of the Series A Preferred Units and Subordinated Units held by High Point immediately following the issuance of the Series A Preferred Units on April 15, 2013:

•

cause or permit us to invest in, or dispose of, the equity securities or debt securities of any person or otherwise acquire or dispose of any interest in any person, to acquire or dispose of interest in any joint venture or partnership or any similar arrangement with any person, or to acquire or dispose of assets of any person, or to make any capital expenditure (other than maintenance capital expenditures), or to make any loan or advance to any person if the total consideration (including cash, equity issued and debt assumed) paid or payable, or received or receivable, by us exceeds $15 million in any one or series of related transactions or in the aggregate exceeds $50 million in any twelve-month period;

•

cause or permit us to (i) incur, create or guarantee any indebtedness that exceeds (x) $75 million in any one or series of related transactions to the extent the proceeds of such financing are used to refinance our existing indebtedness, or (y) $25 million in any twelve-month period to the extent such indebtedness increases our aggregate indebtedness or (ii) incur, create or guarantee any indebtedness with a yield to maturity exceeding ten percent;


•	authorize or permit the purchase, redemption or other acquisition of Partnership interests (or any options, rights, warrants or appreciation rights relating to the Partnership interests) by us;


•	select or dismiss, or enter into any employment agreement or amendment of any employment agreement of, the chief executive officer and the chief financial officer of the Partnership or its subsidiary, American Midstream, LLC;


•	enter into any agreement or effect any transaction between us or any of our subsidiaries, on the one hand, and any affiliate of the Partnership or the general partner, on the other hand, other than any transaction in the ordinary course of business and determined by the board of directors of the general partner to be on an arm's length basis; or


•	cause or permit us or any of our subsidiaries to enter into any agreement or make any commitment to do any of the foregoing.

The Series A Preferred Units are convertible in whole or in part into Common Units at any time after January 1, 2014 or, prior to that date, with the consent of the required lenders under the June 2012 amended credit agreement, at the holder's election. The number of Common Units into which a Series A Preferred Unit is convertible will be an amount equal to (i) the sum of $17.50

and all accrued and accumulated but unpaid distributions, divided by (ii) the Conversion Price, which will initially be $17.50 per Series A Preferred Unit (subject to customary anti-dilution adjustments) (the “Conversion Rate”).

In the event that the Partnership issues, sells or grants any Common Units or convertible securities at an indicative per Common Unit price that is less than $17.50 (subject to customary anti-dilution adjustments), then the Conversion Rate will be adjusted according to a formula to provide an increase in the number of Common Units into which Series A Preferred Units are convertible.

Prior to the consummation of any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of Common Units are to receive securities, cash or other assets (a “Partnership Event”), we are obligated to make an irrevocable written offer, subject to consummation of the Partnership Event, to each holder of Series A Preferred Units to redeem all (but not less than all) of such holder's Series A Preferred Units for a price per Series A Preferred Unit payable in cash equal to the greater of:


•	the sum of $17.50 and all accrued and accumulated but unpaid distributions for each Series A Preferred Unit; and


•	an amount equal to the product of:

(i) the number of Common Units into which each Series A Preferred Unit is convertible; and

(ii) the sum of:

(A) the cash consideration per Common Unit to be paid to the holders of Common Units pursuant to the Partnership Event, plus

(B) the fair market value per Common Unit of the securities or other assets to be distributed to the holders of the Common Units pursuant to the Partnership Event.

Upon receipt of such a redemption offer from us, each holder of Series A Preferred Units may elect to receive such cash amount or a preferred security issued by the person surviving or resulting from such Partnership Event and containing provisions substantially equivalent to the provisions set forth in the Amended Partnership Agreement with respect to the Series A Preferred Units without material abridgement.

Upon any liquidation and winding up of the Partnership or the sale of substantially all of the assets of the Partnership, the holders of Series A Preferred Units generally will be entitled to receive, in preference to the holders of any of the Partnership's other securities, an amount equal to the sum of the $17.50 multiplied by the number of Series A Preferred Units owned by such holders, plus all accrued but unpaid distributions on such Series A Preferred Units.

Change of Control of the General Partner and the Partnership

Through the acquisition of the 90% interest in our general partner, the acquisition of all of our 4,526,066 subordinated units and the issuance of the 5,142,857 Series A Units, High Point acquired control of our general partner and a majority of our outstanding limited partnership interests. In connection with High Point's acquisition of control of our general partner, each of Robert B. Hellman, Jr., Edward O. Diffendal and L. Kent Moore resigned from the board of directors of our general partner. Mr. Hellman also resigned as chairman of the board of directors of our general partner. These resignations occurred on April 15, 2013. High Point, as the owner of 90% of the limited liability company interests in our general partner, will have the right to fill the board vacancies created by these resignations. Effective April 15, 2013, High Point appointed Messrs. Bergstrom, Erhard and Revers to the board of directors of our general partner. Please read "Part III, Item 10. Directors, Executive Officers and Corporate Governance" for more information about the new directors.

Fourth Amendment to Credit Agreement

On April 15, 2013, a subsidiary of the Partnership, American Midstream, LLC, as borrower (the “Borrower”) and the Partnership entered into a Fourth Amendment with its lenders under its June 2012 amended credit agreement. The Fourth Amendment provides for the following:


•	Permits the consummation of the ArcLight Transactions and the PIK Distribution according to the terms of the Amended Partnership Agreement;


•	The aggregate commitments of the lenders under the June 2012 amended credit agreement will be reduced to $175 million if an equity contribution of $12.5 million has not been made by AIM Midstream Holdings and used to repay borrowings under the June 2012 amended credit facility by October 1, 2013;


•	The total outstanding borrowings under the June 2012 amended credit facility shall not exceed $175 million until such equity contribution by AIM Midstream Holdings has occurred;


•	The margins relating to our (i) Eurodollar-based loans range from 2.50% to 4.75% depending on the Consolidated Total Leverage ratio then in effect, and (ii) base rate loans range from 1.5% to 3.75%;


•	The definition of Consolidated Total Indebtedness will not include the Series A Preferred Units or certain surety bonds relating to the High Point Assets;


•	The definition of Consolidated EBITDA (the consolidated EBITDA for the quarters ending June 30 and September 30, 2013 will be annualized for purposes of the Consolidated Total Leverage Ratio) will:


◦	include, on a pro forma basis, the consolidated EBITDA of the High Point Subsidiaries as if they were owned by the Partnership beginning on January 1, 2013;


◦	exclude any insurance proceeds attributable to any event occurring prior to January 1, 2013; and


◦	exclude any one-time, non-recurring transaction expenses of the Partnership incurred in connection with the ArcLight Transactions or the Fourth Amendment.

•

Starting with the quarter ending March 31, 2013 and ending with the quarter ending December 31, 2013, unless the Partnership has permanently cancelled at least 20% of the number of subordinated units outstanding on April 15, 2013, the Partnership must reduce any quarterly cash distribution on either its subordinated units or Series A Preferred Units (at the Partnership's election) by an aggregate of $0.4 million per quarter, and such reduction may not be replaced by in-kind distributions of Partnership securities;


•	The maximum Consolidated Total Leverage Ratio permitted as of the end of any fiscal quarter cannot exceed the ratio set forth below:



Fiscal Quarter Ending	Consolidated Total Leverage Ratio
June 30, 2013	5.90:1.00
September 30, 2013	5.90:1.00
December 31, 2013	5.75:1.00
March 31, 2014	5.75:1.00
June 30, 2014	5.75:1.00
September 30, 2014	5.50:1.00
December 31, 2014	5.25:1.00
March 31, 2015 and each fiscal quarter thereafter	4.50:1.00


•	The Partnership agrees to cooperate with and pay the fees and expenses incurred by Bank of America, N.A., the administrative agent for the June 2012 amended credit agreement, in connection with its engagement of FTI Consulting to advise and assist it in an assessment of the Partnership's financial condition; and


•	The lenders permanently waived the Partnership's failure to comply with covenants relating to the Partnership's Consolidated Total Leverage Ratio for the quarters ended December 31, 2012 and March 31, 2013.

Results of Operations — Combined Overview

We distributed $16.1 million to our unitholders or $1.73 per unit. For the year ended December 31, 2012, gross margin increased to $48.7 million or 10.9% compared to the same period in 2011. The increase in gross margin was largely a result of the acquisitions of a 50% undivided, non-operating, interest in the Burns Point Plant effective November 1, 2011 and of a 87.4% undivided interest in the Chatom system, effective July 1, 2012 which contributed incremental gross margin of $3.7 million and $5.8 million, respectively. This positive performance was tempered, in part, by the impact of production shut-ins due to Hurricane Isaac, an extended turnaround at our Bazor Ridge system, and reduced gathering and processing volumes associated with one of our offshore pipeline systems which in turn negatively impacted our financial performance in the third and fourth quarters of 2012.

The following table and discussion presents certain of our historical consolidated financial data for the periods indicated. The results of operations by segment are discussed in further detail following this combined overview.



	For the Year Ended December 31,
	2012			2011			2010
	(in thousands)
Statement of Operations Data:
Revenue	$	197,251		$	231,258		$	195,087
Realized gain (loss) on early termination of commodity derivatives	—			(2,998		)	—
Unrealized gain (loss) on commodity derivatives	992			(541		)	(308		)
Total revenue	198,243			227,719			194,779
Operating expenses:
Purchases of natural gas, NGLs and condensate	145,172			187,398			157,682
Direct operating expenses	16,798			11,419			10,944
Selling, general and administrative expenses	14,309			10,800			7,120
Advisory services agreement termination fee	—			2,500			—
Transaction expenses	—			282			303
Equity compensation expense (a)	1,783			3,357			1,734
Depreciation expense	21,284			20,449			19,904
Total operating expenses	199,346			236,205			197,687
Gain (loss) on acquisition of assets	—			565			—
Gain (loss) on involuntary conversion of property, plant and equipment	(1,021		)	—			—
Gain (loss) on sale of assets, net	123			399			—
Operating income (loss)	(2,001		)	(7,522		)	(2,908		)
Interest (expense)	(4,570		)	(4,508		)	(5,406		)
Net income (loss) from continuing operations	(6,571		)	(12,030		)	(8,314		)
Discontinued operations
Income (loss) from operations of disposal groups	319			332			(330		)
Net income (loss)	$	(6,252	)	$	(11,698	)	$	(8,644	)
Other Financial Data:
Gross margin (b)	$	48,706		$	43,860		$	37,097
Adjusted EBITDA (c)	$	18,847		$	20,785		$	18,154


(a)	Represents cash and non-cash costs related to our Long Term Incentive Plan (" LTIP"). Of these amounts, $1.8 million, $1.6 million and $1.2 million, for the years ended December 31, 2012, 2011 and 2010, respectively, were non-cash expenses.

(b)

For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 19 to our audited consolidated financial statements included in this Annual Report beginning on page F-1 for a discussion of how we use gross margin to evaluate our operating performance, please read “— How We Evaluate Our Operations”.


(c)	For a definition of adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use adjusted EBITDA to evaluate our operating performance, please read “—How We Evaluate Our Operations”.

Year ended December 31, 2012 compared to year ended December 31, 2011

Revenue. Our revenue for the year ended December 31, 2012 was $197.3 million compared to $231.3 million for the year ended December 31, 2011. This decrease of $34.0 million was primarily due to the following -


•	Natural gas revenues decreased $25.8 million as a result of a decline in realized natural gas prices of $1.12/Mcf along with a decrease in natural gas sales volumes of approximately 2.0 Mmcf attributable to production shut-ins caused by Hurricane Isaac;

•

NGL revenues decreased $8.8 million as a result of a decline in realized NGL prices of $0.24/gal and a decrease in NGL sales volumes of 1.3 m/gal due to a turnaround taking longer than anticipated as a result of unscheduled repairs and upgrades that slowed the turnaround process but are expected to deliver long-term, improved efficiencies at our Bazor Ridge processing facility offset by an increase in volumes from the newly acquired Chatom system;


•	Transmission revenues from the transportation of natural gas decreased $13.5 million as a result of declines in realized natural gas prices on our fixed margin contracts of $1.26/Mcf amounting to $13.5 million and a decrease in sales volumes of 5% period over period; and


•	Condensate revenues increased $13.8 million as a result of an increase in condensate sales volumes of 5.7 m/gal due to the newly acquired Chatom system while realized condensate prices remained consistent period over period; and

Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate for the year ended December 31, 2012 were $145.2 million compared to $187.4 million in the year ended December 31, 2011. This decrease of $42.2 million was primarily due to lower natural gas and NGL sales volumes and related realized prices related to POP contracts associated with owned processing plants in our Gathering and Processing and Transmission segments. This decrease was partially offset by higher condensate purchase costs in our Gathering and Processing segment.

Gross Margin. Gross margin for the year ended December 31, 2012 was $48.7 million compared to $43.9 million for the year ended December 31, 2011. This increase of $4.8 million was primarily due to higher throughput volume and associated condensate production from owned processing plants in our Gathering and Processing segment. This was a result of our recent acquisitions of the Burns Point Plant, effective November 1, 2011 and of the Chatom system, effective July 1, 2012 which contributed incremental gross margin of $3.7 million and $5.7 million, respectively. These increases were offset by a decline in gross margin from our Bazor Ridge and Quivira systems due to unscheduled repairs and upgrades that slowed the turnaround process amounting to $0.7 million and declined in volumes during the third and fourth quarters of 2012 as a result of a producer's work on one of its platforms amounting to approximately $2.0 million, respectively.

Direct Operating Expenses. Direct operating expenses in the year ended December 31, 2012 were $16.8 million compared to $11.4 million in the year ended December 31, 2011. This increase of $5.4 million was primarily due to: (i) $0.7 million incremental costs related to additional insurance premiums; (ii) $1.8 million of added expenses associated with our 50% undivided interest in the operating costs incurred at the Burns Point Plant; and (iii) $2.9 million of added expenses associated with our new acquired Chatom system.

Selling, General and Administrative Expenses ("SG&A"). SG&A expenses for the year ended December 31, 2012 were $14.3 million compared to $10.8 million for the year ended December 31, 2011. This increase of $3.5 million was primarily due to: (i) $1.5 million of incremental personnel costs, recruiting fees and related benefits necessary to operate and grow a public company; (ii) $0.7 million in additional legal expenses associated with SEC and other regulatory compliance; (iii) $0.8 million of incremental accounting, auditing and tax costs associated with our acquisition of the Chatom Assets and shelf registration statement; and (iv) $0.4 million of incremental costs associated with outside services and contract labor to assist in maintaining and maximizing operational efficiency of our systems and internal controls over financial reporting.

Advisory Services Agreement Termination Fee. In connection with our initial public offering in August 2011, we terminated the advisory services agreement with our sponsor in exchange for a payment of $2.5 million.

Equity Compensation Expense. Compensation expense related our LTIP for the year ended December 31, 2012 was $1.8 million compared to $3.4 million for the year ended December 31, 2011. This decrease of $1.6 million was primarily due to a 2011 buy-out of distribution equivalent rights (“DER’s”) associated with unvested phantom units at a cost of $1.5 million, a payment to holders of unvested phantom units without DER’s of $0.1 million, increased amortization of $0.1 million associated with March 2011 phantom unit grants, off-set in part by the lack of DER payments in the second half of 2011 and a modification in amounts amortized due to the elimination of the DER’s that did not occur in the year ended December 31, 2012.

Depreciation Expense. Depreciation expense in the year ended December 31, 2012 was $21.3 million compared to $20.4 million for the year ended December 31, 2011. This increase of $0.9 million was due to depreciation associated with newly acquired facilities and capital projects placed into service during the period.

Income (loss) from operations of disposal groups. Income (loss) from operations of disposal groups for the years ended December 31, 2012 and 2011 was income of $0.3 million.

Year ended December 31, 2011 compared to year ended December 31, 2010

Revenue. Our revenue for the year ended December 31, 2011 was $231.3 million compared to $195.1 million for the year ended December 31, 2010. This increase of $36.2 million was primarily due to the following -


•	Natural gas revenues increased $10.0 million as a result of an increase in natural gas sales volumes of approximately 6.8 Mmcf attributable to increased production on our Gathering and Processing systems and increased throughput on our Transmission assets offset by declines in realized natural gas prices of $0.51/Mcf;


•	NGL revenues increased $16.1 million as a result of an increase in realized NGL prices of $0.25/gal and an increase in NGL sales volumes of 7.2 m/gal due improved efficiencies at our Bazor Ridge processing facility;


•	Condensate revenues increased $2.6 million as a result of an increase in realized condensate prices of $0.60/gal and increases in condensate sales volumes of 0.5 m/gal attributable to increased production with a producer on a Gathering and Processing system; and


•	Transmission revenues from the transportation of natural gas increased approximately $13.3 million as a result of an increase in sales volumes of 52% amounting to $14.0 million period over period offset realized natural gas prices on our fixed margin contracts declining slightly by $0.05/Mcf .

Realized gain (loss) on early termination of commodity derivatives. We recognized a one-time charge of $3.0 million resulting from the unwind and reset of our commodity derivative contracts in June 2011.

Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate for the year ended December 31, 2011 were $187.4 million compared to $157.7 million in the year ended December 31, 2010. This increase of $29.7 million was primarily due to higher NGL sales volumes and NGL prices related to owned processing plants’ POP contracts and higher natural gas purchase volumes in our Gathering and Processing and Transmission segments. This increase was partially offset by lower natural gas purchase costs in our Gathering and Processing segment.

Gross Margin. Gross margin for the year ended December 31, 2011 was $43.9 million compared to $37.1 million for the year ended December 31, 2010. This increase of $6.8 million was primarily due to higher throughput volume and associated NGL production from owned processing plants, improved processing and POP margins from higher NGL and condensate prices and higher throughput in our Gathering and Processing segment. We also achieved incremental gross margin of $1.1 million associated with our acquisition of a 50% undivided, non-operating, interest in the Burns Point Plant effective November 1, 2011. In addition this increase was also attributable to a $0.5 million increase in COMA income.

Direct Operating Expenses. Direct operating expenses in the year ended December 31, 2011 were $11.4 million compared to $10.9 million in the year ended December 31, 2010. This increase of $0.5 million was primarily due to: (i) $0.2 million incremental costs related to service fees and costs to address operational matters; (ii) $0.3 million of added expenses associated with our 50% interest in the operating costs incurred at the Burns Point Plant; and (iii) $0.4 million of line losses in our Transmission segment. The operational cost increases were partially offset by a reduction in personnel related costs.

Selling, General and Administrative Expenses. SG&A expenses for the year ended December 31, 2011 were $10.8 million compared to $7.1 million for the year ended December 31, 2011. This increase of $3.7 million was primarily due to: (i) $1.9 million of incremental personnel costs and related benefits necessary to operate and grow a public company; (ii) $0.2 million in additional expenses associated with maintaining operational locations and services; (iii) $1.0 million of added costs associated with our IPO process and continued compliance and requirements for a publicly traded company; and (iv) $0.3 million of incremental costs associated with outside services and contract labor to assist in maintaining and maximizing operational efficiency of our systems.

Equity Compensation Expense. Compensation expense related our LTIP for the year ended December 31, 2011 was $3.4 million compared to $1.7 million for the year ended December 31, 2010. This increase of $1.7 million was primarily due to a buy-out of DER’s associated with unvested phantom units at a cost of $1.5 million, a payment to holders of unvested phantom units without DER’s of $0.1 million, increased amortization of $0.1 million associated with March 2011 phantom unit grants, off-set in part by the lack of DER payments in the second half of 2011 and a modification in amounts amortized due to the elimination of the DER’s.

Depreciation Expense. Depreciation expense in the year ended December 31, 2011 was $20.5 million compared to $19.9 million for the year ended December 31, 2010. This increase of $0.6 million was due to depreciation associated with capital projects placed into service during the period.

Income (loss) from operations of disposal groups. Income (loss) from operations of disposal groups for the year ended December 31, 2011 was income of $0.3 million compared to a loss of $0.3 million for the year ended December 31, 2010. This change of $0.6 million was primarily due to lower gross margins of a certain midstream asset as a result of its relocation during 2010.

Results of Operations — Segment Results

The table below contains key segment performance indicators related to our segment results of operations.



	For the Year Ended December 31,
	2012		2011			2010
	(in thousands except operational data)
Segment Financial and Operating Data:
Gathering and Processing segment
Financial data:
Revenue	$	144,722	$	164,493		$	141,602
Realized gain (loss) on early termination of commodity derivatives	—		(2,998		)	—
Unrealized gain (loss) on commodity derivatives	992		(541		)	(308		)
Total revenue	145,714		160,954			141,294
Purchases of natural gas, NGLs and condensate	$	108,657	$	134,370		$	117,721
Direct operating expenses	11,767		6,199			6,478
Other financial data:
Segment gross margin	$	35,393	$	30,123		$	23,573
Operating data (a):
Average throughput (MMcf/d)	299.3		250.9			175.6
Average plant inlet volume (MMcf/d) (b)	116.1		36.7			9.9
Average gross NGL production (Mgal/d) (b)	49.9		54.5			34.1
Average gross condensate production (Mgal/d) (b)	22.6		6.8			5.1
Average realized prices:
Natural gas ($/MMcf)	$	2.98	$	4.09		$	4.61
NGLs ($/gal)	$	1.09	$	1.32		$	1.08
Condensate ($/gal)	$	2.30	$	2.41		$	1.82
Transmission segment
Financial data:
Total revenue	$	52,529	$	66,765		$	53,485
Purchases of natural gas, NGLs and condensate	$	36,516	$	53,029		$	39,961
Direct operating expenses	$	5,031	$	5,220		$	4,466
Other financial data:
Segment gross margin	$	13,313	$	13,737		$	13,524
Operating data:
Average throughput (MMcf/d)	398.5		381.1			350.2
Average firm transportation - capacity reservation (MMcf/d)	703.6		702.2			677.6
Average interruptible transportation - throughput (MMcf/d)	86.6		69.0			80.9


(a)	Includes volumes attributable to discontinued operations.


(b)	Excludes volumes and gross production under our elective processing arrangements.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Gathering and Processing Segment

Revenue. Segment revenue for the year ended December 31, 2012 was $144.7 million compared to $164.5 million for the year ended December 31, 2011. This decrease of $19.8 million was primarily due to the following -


•	A decline in realized natural gas prices of 27%, realized NGL prices of 18% and realized condensate prices of 5% period over period as a result of variable commodity prices;


•	A decline in average gross NGL production amounting to 4.6 Mgal/d period over period as a result of extended turnaround efforts at the our Bazor Ridge system during the fourth quarter, offset by;

•

An increase in average throughput amounting to 40.4 MMcf/d or 16% period over period as a result of having a full year's operational impact of our 50% undivided interest in the Burns Point plant offset by declines in average throughput associated with our Quivera and Gloria systems as well as production shut-ins surrounding our Gulf Coast systems during the third quarter as result of Hurricane Isaac;


•	A significant increase in average gross condensate production amounting to 15.7 Mgal/d period over period as a result of our our newly acquired Chatom system in the third quarter of 2012; and


•	An increase in realized gains of $4.3 million period over period on our commodity derivatives which comprised of financial swaps and option contracts to mitigate commodity price risk that settled in 2012.

Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for the year ended December 31, 2012 were $108.7 million compared to $134.4 million for the year ended December 31, 2011. This decrease of $25.7 million was primarily due to lower natural gas and NGL sales volumes and related realized commodity prices related to POP contracts associated with our Bazor Ridge system. This decrease was partially offset by higher condensate sales volumes associated with the newly acquired Chatom system, effective July 1, 2012 and higher NGL sales volumes at the Burns Point Plant.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2012 was $35.4 million compared to $30.1 million for the year ended December 31, 2011. This increase of $5.3 million was primarily due to the following -


•	Incremental gross margin of $5.6 million associated with higher average condensate production of 17.1 Mgal/d as a result of the new acquired Chatom system, effective July 1, 2012;

•

Incremental gross margin of $2.5 million associated with higher average throughput of 76.4 Mcf/d and NGL production of 7.7 Mgal/d as a result of having a full year of operational results of the Burns Point plant, acquired effective November 1, 2011, offset by lower gross margins of $1.3 million associated with our Quivira system which saw a decline in volumes on one of its offshore pipeline systems during the third and fourth quarters of 2012 as a result of a producer completing work on one of its platforms. The Partnership continued to work with this producer to return volumes to historical levels, although the contract terms may change for a portion of the volumes going forward and a change in contract terms may have a material negative impact on financial results;


•	A decline in gross margin of $1.8 million associated with lower NGL production of 14.9 Mgal/d at our Bazor Ridge processing plant due to a turnaround taking longer than anticipated as a result of unscheduled repairs and upgrades that slowed the turnaround process but are expected to deliver long-term, improved efficiencies at our Bazor Ridge processing facility;


•	Gross margins associated with facilities damaged and/or impacted by production shut-ins as a result of the named windstorm Hurricane Isaac were estimated to approximate $0.8 million are covered by our insurance carrier; and


•	An increase in realized gains of $4.3 million period over period on our commodity derivatives which comprised of financial swaps and option contracts which were used to mitigate commodity price risk that settled in 2012.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2012 were $11.8 million compared to $6.2 million for the year ended December 31, 2011. This increase of $5.6 million was primarily due (i) $0.6 million incremental costs related to additional insurance premiums; (ii) $1.7 million of added expenses associated with operating costs incurred at the Burns Point Plant; and (iii) $2.5 million of added expenses associated with operating costs incurred at our Chatom system.

Transmission Segment

Revenue. Segment revenue for the year ended December 31, 2012 was $52.5 million compared to $66.8 million for the year ended December 31, 2011. This decrease of $14.3 million in revenue was primarily due to the following -


•	A decline in realized natural gas prices on our fixed margin contracts of $1.26/Mcf along with a decline in sales volumes of 5% amounting to $13.5 million period over period;


•	Total natural gas throughput on our Transmission systems for the year ended December 31, 2012 was 398.5 MMcf/d compared to 381.1 MMcf/d for the year ended December 31, 2011 representing a 5% increase period over period; and


•	Lower transportation fees associated with our interruptible transportation contracts offset by an increase in throughput of 17.5 MMcf/d amounting to amounting to $0.5 million period over period.

Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for the year ended December 31, 2012 were $36.5 million compared to $53.0 million for the year ended December 31, 2011. This decrease of $16.5 million was primarily due to a decrease in our purchases costs associated with fixed margin contracts as a result of a decline in natural gas market prices and sales volumes.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2012 was $13.3 million compared to $13.7 million for the year ended December 31, 2011. This decrease of $0.4 million was primarily associated with a slight change to our contract mix of fixed margin, firm and interruptible transportation contracts offset by a slight increase in throughput volumes period over period.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2012 were $5.0 million compared to $5.2 million for the year ended December 31, 2011. This decrease of $0.2 million was primarily due to lower property taxes incurred period over period.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Gathering and Processing Segment

Revenue. Segment revenue for the year ended December 31, 2011 was $164.5 million compared to $141.6 million for the year ended December 31, 2010. This increase of $22.9 million was primarily due to the following -


•	Increases in realized NGL prices of 22% and realized condensate prices of 33%, offset by a decline in realized natural gas prices of 11% period over period as a result of variable commodity prices;


•	An increase in average gross NGL production amounting to 20.4 Mgal/d or 60% period over period as a result of the completion of our Winchester lateral in the fourth quarter of 2010 and the production from several new wells drilled in 2011 on our Bazor Ridge system;

•

An increase in average throughput amounting to 75.3 MMcf/d or 43% period over period as a result of higher natural gas sales volumes, i) primarily the increased demand at the Conoco Alliance refinery, which we serve with production from our Lafitte system and our interconnect with the Tennessee Gas Pipeline representing an increase of 28% year over year; ii) additional natural gas production from a producer on our Quivira system in the third quarter 2010 representing a 43% increase year over year; and iii) new incremental throughput volume from the Burns Point Plant from the 50% interest we acquired effective November 1, 2011; offset by


•	A series of swap and put contracts that we entered into in January 2011 and swap contracts again in June 2011. These commodity derivative transactions had a negative net effect of $1.9 million on our revenue related to realized losses for the year ended December 31, 2011. In June 2010, we purchased put contracts that extended through June 2011.

Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for the year ended December 31, 2011 were $134.4 million compared to $117.7 million for the year ended December 31, 2010. This increase of $16.7 million was primarily due to higher NGL sales volumes and NGL prices related to owned processing plants’ POP contracts and higher natural gas purchase volumes to provide natural gas for the Conoco Alliance refinery. This increase was partially offset by lower natural gas prices.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2011 was $30.1 million compared to $23.6 million for the year ended December 31, 2010. This increase of $6.5 million was primarily due to the following -


•	Higher throughput volume and associated NGL production of 16.0 Mgal/d or 16% at our Bazor Ridge processing plant;


•	Increased throughput volume of 33.4 MMcf/d or 43% on our Quivira system;


•	Higher realized NGL prices of $1.32/gal which positively impacted margins associated with our POP and elective processing agreements; and


•	The acquisition of our 50% interest in the Burns Point Plant, effective November 2011; offset by


•	Commodity derivative transactions that had a negative net effect of $1.9 million on our margin related to realized losses for the year ended December 31, 201

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2011 were $6.2 million compared to $6.5 million for the year ended December 31, 2010.

Transmission Segment

Revenue. Segment revenue for the year ended December 31, 2011 was $66.8 million compared to $53.5 million for the year ended December 31, 2010. Total natural gas throughput on our Transmission systems for the year ended December 31, 2011 was 381.1MMcf/d compared to 350.2 MMcf/d in the year ended December 31, 2010. This increase of $13.3 million in revenue was primarily due to a full year’s impact of our fixed margin agreement which began in the second quarter 2010 to supply gas to Exxon on our MLGT system offset in part by lower volumes and natural gas prices associated with an affiliate fixed margin agreement on the Midla system. Our commodity derivatives had no effect on segment revenue for the years ended December 31, 2011 and 2010.

Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for the year ended December 31, 2011 were $53.0 million compared to $40.0 million for the year ended December 31, 2010. This increase of $13.0 million was primarily due to a full year’s impact of our fixed margin agreement began in the second quarter 2010 to supply gas to Exxon on our MLGT system offset in part by lower volumes and natural gas prices associated with an affiliate fixed margin agreement on the Midla system.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2011 was $13.7 million compared to $13.5 million for the year ended December 31, 2010. Segment gross margin for the Transmission segment represented 29.7% of our total gross margin for year ended December 31, 2011, compared to 35.5% for the year ended December 31, 2010.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2011 were $5.2 million compared to $4.5 million for the year ended December 31, 2010. This increase of $0.7 million was primarily due to $0.2 million incremental costs related to service fees and costs to address operational matters and a $0.5 million increase in line losses.

Liquidity and Capital Resources

Our business is capital intensive and requires significant investment for the maintenance of existing assets and the acquisition and development of new systems and facilities.

The principal indicators of our liquidity at December 31, 2012 were our cash on hand and availability under our June 2012 amended credit facility as it existed prior to the Fourth Amendment as discussed below. As of December 31, 2012, our available liquidity was $19.7 million, comprised of cash on hand of $0.6 million and $19.1 million available under our June 2012 amended credit facility as it existed at that time. As of March 31, 2013, our available liquidity was $9.1 million. In the near term, we expect our sources of liquidity to include cash generated from operations, borrowings under our June 2012 amended credit facility and issuances of debt and equity securities. As a result of the contribution of the High Point assets to the Partnership (with the resultant expected increase in the Partnership's EBITDA for the trailing twelve months), Fourth Amendment, the PIK Distribution on the Series A Preferred Units and the Preferred Unit Distribution Waiver, we expect to generate sufficient cash flow from operations and borrowings under our June 2012 amended credit facility, as needed, to:


•	pay the required distribution on the Series A Convertible Preferred Units (a portion of which is payable in-kind in additional Series A Preferred Units (“Series A PIK Units”), less the Preferred Unit Distribution Waiver;


•	pay at least the minimum quarterly distribution on all outstanding common units, subordinated units, and general partner units; and


•	meet our requirements for working capital and capital expenditures,

in each case, for the next twelve months from the date of this Annual Report on Form 10-K. Please read "— Our Credit Facility" for more information about our June 2012 amended credit facility. Please see “Recent Developments — ArcLight Transactions” for more information about the ArcLight Transactions.

We depend on our June 2012 amended credit facility for future capital needs and may use it to fund a portion of cash distributions to unitholders, as necessary, depending on the level of our operating cashflow. We are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of financial markets and commodity price levels. Our failure to comply with any of the covenants under our June 2012 amended credit facility could result in a default, which could cause all of our existing indebtedness to become immediately due and payable. We were unable to maintain compliance with consolidated total leverage ratio required by our June 2012 amended credit agreement as it existed prior to the Fourth Amendment during the quarters ended December 31, 2012 and March 31, 2013. On April 15, 2013, we entered into a Fourth Amendment to our June 2012 amended credit agreement that, among other things, modified the maximum permitted consolidated total leverage ratio. The maximum consolidated total leverage ratio permitted by the Fourth Amendment varies by quarter, initially permitting a ratio of 5.90 to 1.00 for the quarter ending June 30, 2013 and then gradually lowering to 4.50 to 1.00 commencing with the quarter ending March 31, 2015. The Partnership believes that the consummation of the ArcLight Transactions will allow it to maintain compliance with the Consolidated Total Leverage to EBTIDA ratio in the Fourth Amendment for a period of at least the next twelve months from the date of the Annual Report on

Form 10-K. However, no assurances can be given that the ArcLight Transactions will achieve the necessary ratios or that the contributed business can yield the necessary cash flows. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Our Credit Facility" for more information about the Fourth Amendment and our June 2012 amended credit facility.

Working Capital

Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received from our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors. Our working capital deficit was $3.6 million at December 31, 2012.

Cash Flows

The following table reflects cash flows for the applicable periods:



(in thousands)	For the Year Ended December 31,
	2012			2011			2010
Net cash provided by (used in):
Operating activities	$	18,348		$	10,432		$	13,791
Investing activities	(62,427		)	(41,744		)	(10,268		)
Financing activities	43,784			32,120			(4,609		)

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Operating Activities. Net cash provided by operating activities was $18.3 million for year ended December 31, 2012 compared to $10.4 million for the year ended December 31, 2011. Net cash provided by operating activities for the year ended December 31, 2012 increased year over year primarily due to i) incremental gross margin associated with our acquisitions of the Burns Point Plant and the Chatom system of $3.7 million and $5.7 million, respectively; ii) net positive changes in operating assets and liabilities of $0.9 million due to higher average throughput volumes; iii) a reduction in premium payments associated with our commodity derivatives of $0.5 million; and iv) an increase in proceeds received from the settlement of commodity derivatives of $0.5 million.

One of the primary sources of variability in our cash flows from operating activities is fluctuation in commodity prices, which we partially mitigate by entering into commodity derivatives. Average throughput volume changes also impact cash flow, but have not been as volatile as commodity prices. Our long-term cash flows from operating activities is dependent on commodity prices, average throughput volumes, costs required for continued operations and cash interest expense.

Investing Activities. Net cash used in investing activities was $62.4 million for the year ended December 31, 2012 compared to $41.7 million for the year ended December 31, 2011. Cash used in investing activities for the year ended December 31, 2012 increased year over year primarily due to i) the purchase of the Chatom system for $51.4 million; ii) $1.9 million for replacement and capital improvements to assets damaged by Hurricane Isaac during 2012; iii) $1.7 million for the development of our Madison County system during 2012; and iv) $1.2 million for turnaround expenditures at the Bazor Ridge and Chatom processing plants.

Financing Activities. Net cash provided by financing activities was $43.8 million for the year ended December 31, 2012 compared to $32.1 million for the year ended December 31, 2011. Cash provided by financing activities for the year ended December 31, 2012 increased year over year primarily due to i) an increase of $52.1 million in net borrowings from our June 2012 amended credit facility to fund acquisition and growth opportunities; ii) a decrease in unit holder distributions of $27.5 million; offset by iii) a decrease of $69.1 million in net proceeds from our initial public offering in 2011.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Operating Activities. Net cash provided by operating activities was $10.4 million for year ended December 31, 2011 compared to $13.8 million for the year ended December 31, 2010. Net cash provided by operating activities for the year ended December 31, 2011 decreased year over year primarily due i) net negative changes in operating assets and liabilities of $1.0 million due to

lower realized natural gas prices; ii) $1.5 million was used to pay holders of phantom units under our LTIP in consideration for the elimination of the DER provision in previously existing LTIP agreements; iii) and $2.5 million was used to buy-out the management agreement with AIM; iv) net proceeds of $3.0 million and $1.5 million were used to terminate our NGL swaps and settle our other commodity derivatives, respectively; and v) an increase in premium payments associated with our commodity derivatives of $0.4 million.

Investing Activities. Net cash used in investing activities was $41.7 million for the year ended December 31, 2011 compared to $10.3 million for the year ended December 31, 2010. Cash used in investing activities for the year ended December 31, 2011 increased year over year primarily due to i) the purchase of the Burns Point plant for $35.5 million; ii) a meter relocation costing $2.3 million on our MLGT system during 2011; iii) $1.4 million for pipeline relocation work on our Gloria and Chalmette systems associated with levee improvements during 2011; and iv) $5.9 million for a construction of the Winchester lateral associated with our Bazor Ridge system in November 2010.

Financing Activities. Net cash provided by financing activities was $32.1 million for the year ended December 31, 2011 compared to net cash used in financing activities of $4.6 million for the year ended December 31, 2010. Cash provided by (used in) financing activities for the year ended December 31, 2011 increased year over year primarily due to i) $69.1 million in net proceeds from our initial public offering; ii) a decrease in other unit holder contributions of $12.0 million; iii) the $58.6 million pay down of our $85 million credit facility; iv) an initial draw of $30.0 million from our August 2011 credit facility; v) debt issuance costs of $2.5 million; vi) a $14.5 million increase in net borrowings of long-term debt; and vii) an increase of $31.8 million in distributions made to our unitholders.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Capital Requirements

The midstream energy business can be capital intensive, requiring significant investment for the maintenance of existing assets and the acquisition and development of new systems and facilities. We categorize our capital expenditures as either:


•	maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or


•	expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.

Historically, our maintenance capital expenditures have not included all capital expenditures required to maintain volumes on our systems. It is customary in the regions in which we operate for producers to bear the cost of well connections, but we cannot be assured that this will be the case in the future. For the year ended December 31, 2012 capital expenditures totaled $11.7 million including expansion capital expenditures of $4.4 million, maintenance capital expenditures of $6.5 million and reimbursable project expenditures (capital expenditures for which we expect to be reimbursed for all or part of the expenditures by a third party) of $0.8 million. Although we classified our capital expenditures as expansion and maintenance, we believe those classifications approximate, but do not necessarily correspond to, the definitions of estimated maintenance capital expenditures and expansion capital expenditures under our partnership agreement.

We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. As a result of the contribution of the High Point assets to the Partnership, the Fourth Amendment, the PIK Distribution on the Series A Preferred Units and the Preferred Unit Distribution Waiver, we expect to generate sufficient cash flow from operations and borrowings under our June 2012 amended credit facility, as needed, to meet our requirements for future expansion capital expenditures for the next twelve months from the date of this Annual Report on Form 10-K.

permitted by the Fourth Amendment varies by quarter, initially permitting a ratio of 5.90 to 1.00 for the quarter ending June 30, 2013 and then gradually lowering to 4.50 to 1.00 commencing with the quarter ending March 31, 2015. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Our Credit Facility" for more information about the Fourth Amendment and our June 2012 amended credit facility.

Integrity Management

When we acquired our operating assets from Enbridge, we inherited an ongoing integrity management program required under regulations of the U.S. Department of Transportation, or DOT. These regulations require transportation pipeline operators to implement continuous integrity management programs over a seven-year cycle. Our current program will be completed in 2012. In connection with the acquisition of our assets from Enbridge we initiated a comprehensive review of the program and concluded that there were sixteen high consequence areas, or HCAs, in addition to those identified by our Predecessor that required further testing pursuant to DOT regulations. We expect to incur $2.0 million in integrity management expenses in 2013 associated with these HCAs to complete the current integrity management program.

Because DOT regulations require integrity management activities for each HCA to be performed within seven years from when they were last performed, we expect to incur the following expenses:



Year	Integrity Management Expense
	(in thousands)
2013	$	2,000
2014	5,015
2015	839
2016	675
2017	—
2018	—
2019	2,080
Total	$	10,609

In conjunction with the commencement of our next seven-year integrity management program cycle in 2013, we plan to request the DOT’s consent to a modification of the timing of our integrity management expenses so that we spend approximately $1.5 million each year.

Impact of Bazor Ridge Emissions Matter

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

In July 2011, we self-reported these issues to the MDEQ and EPA Region IV. In January 2012, we met with EPA Region IV representatives, and have agreed to a settlement with respect to the EPCRA reporting issue. A Consent Agreement and Final Order was executed, which included a civil penalty of $23,010. After discussion with the MDEQ, in February 2012 we submitted an application to amend our Title V Air Permit to account for these SO₂ emissions. The MDEQ is currently processing this permit application. In December 2011, EPA Region IV performed an inspection of the plant, and they followed up with an Information Request in May 2012. We have responded to this Information Request and do not anticipate any further action required by the Partnership at this time.

Separation Agreement

For the year ended December 31, 2012, we incurred costs of approximately $0.5 million in relation to a separation agreement with a former officer. As a result of this payment to the former officer pursuant to the separation agreement, we received insurance proceeds from our insurance carrier of approximately 30% of the amount paid to the former officer.

Distributions

We intend to pay a quarterly distributions though we do not have a legal obligation to make distributions except as provided in our Amended Partnership Agreement. As a result of the contribution of the High Point assets to the Partnership, the Fourth Amendment, the PIK Distribution on the Series A Preferred Units and the Preferred Unit Distribution Waiver, we expect to generate sufficient cash flow from operations and borrowings under our June 2012 amended credit facility, as needed, to:


•	pay the required distribution on the Series A Convertible Preferred Units (a portion of which is payable in Series A PIK Units, less the Preferred Unit Distribution Waiver); and


•	pay at least the minimum quarterly distribution on all outstanding common units, subordinate units and general partner units.

in each case, for the next twelve months following the date of this Annual Report on Form 10-K.

Our Credit Facility

Prior to the Fourth Amendment, we had a number of credit facilities. The first was a $100 million revolving credit facility that we entered into in August 2011.

On June 27, 2012, we amended that August 2011 credit facility to increase the commitments from an aggregate principal amount of $100 million to an aggregate principal amount of $200 million, evidenced by a credit agreement with Bank of America, N.A., as Administrative Agent, Collateral Agent and L/C Issuer; Comerica Bank and Citicorp North America, Inc., as Co-Syndication Agents; BBVA Compass, as Documentation Agent; and the other financial institutions party thereto.

That June 2012 amended credit facility provided for a maximum borrowing equal to the lesser of (i) $200 million or (ii) 4.50 times adjusted consolidated EBITDA. Prior to the Third Amendment described below, we could elect to have loans under the June 2012 amended credit facility bear interest either at a Eurodollar-based rate plus a margin ranging from 2.25% to 3.50% depending on our total leverage ratio then in effect, or a base rate which is a fluctuating rate per annum equal to the highest of (a) the Federal Funds Rate plus 1/2 of 1%, (b) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its “prime rate”, or (c) the Eurodollar Rate plus 1.00% plus a margin ranging from 1.25% to 2.50% depending on the total leverage ratio then in effect. We also paid a commitment fee of 0.50% per annum on the undrawn portion of the revolving loan.

For the twelve months ended December 31, 2012, 2011 and 2010, the weighted average interest rate on borrowings under our credit facilities was approximately 4.09%, 6.71%, and 7.48%, respectively.

Our obligations under each of our credit facilities, including the current June 2012 amended credit facility, are secured by a first mortgage in favor of the lenders in our real property. Advances made under the June 2012 amended 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 June 2012 amended 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 June 2012 amended 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 June 2012 amended credit facility are (i) a total leverage ratio test (which, prior the Fourth Amendment could not exceed 4.50) and a minimum interest coverage ratio test (which, prior to the Third Amendment could not less be than 2.50).

As of December 31, 2012, the total leverage ratio test, one of the primary financial covenants that we were required to maintain under our June 2012 amended credit facility, exceeded the leverage covenant. As a result, on December 26, 2012, the Partnership entered into the Third Amendment and Waiver to Credit Agreement, dated as of December 26, 2012 (the “Third Amendment”). The Third Amendment provided for a waiver of the Partnership's compliance with the Consolidated Total Leverage Ratio with respect to the quarter ending December 31, 2012 and for one month thereafter. The Third Amendment also required the Partnership to provide certain financial and operating information of the Partnership on a monthly basis for 2013 and for any month after 2013 in which the Consolidated Total Leverage Ratio of the Partnership is in excess of 4.00 to 1.00. The remaining material terms and conditions of the June 2012 amended credit facility, including pricing, maturity and covenants, remained unchanged by the Third Amendment.

On January 24, 2013, the Partnership entered into the second waiver to the June 2012 amended credit facility that extended the waiver period with respect to the Consolidated Total Leverage Ratio to March 31, 2013 (and subsequently extended to April 16, 2013). Additional covenants during the waiver period included i) total outstanding borrowings under the June 2012 amended credit facility could not exceed $150 million; ii) restrictions on certain acquisitions; iii) an increase to the Eurodollar rate by 0.50%; iv)

additional fees of 0.125% of the principal amount on each of February 28, 2013 and March 31, 2013; and v) execution of a compliance certificate.

At December 31, 2012, our total indebtedness was approximately $130.9 million, which caused our total leverage to EBITDA ratio to be approximately 5.7-to-1. Prior to the Fourth Amendment to our June 2012 amended credit agreement, the maximum value permitted under the June 2012 amended credit agreement for that ratio could not exceed 4.5 to 1.0. As of March 31, 2013, outstanding debt under our June 2012 amended credit facility was approximately $139 million, which further exceeded the maximum Consolidated Total Leverage Ratio as of that date and constituted a default under the June 2012 amended credit agreement. Please read “Recent Developments — Fourth Amendment to Credit Agreement” for a description of the Fourth Amendment.

On April 15, 2013, we repaid approximately $12.5 million in outstanding borrowings under the June 2012 amended credit agreement and entered into the Fourth Amendment to our June 2012 amended credit agreement in connection with the ArcLight Transactions. As a result, we had approximately $130 million of outstanding borrowings as of April 15, 2013 and approximately $45 million of available borrowing capacity as a result of the reduction of our borrowing capacity to a total of $175 million as described below. Until June 30, 2013, we will not be required to meet a Consolidated Leverage Ratio under our June 2012 amended credit facility. We expect that we will have availability under our June 2012 amended credit facility and be able to meet the Fourth Amendment's Consolidated Leverage Ratio once it is reinstated on June 30, 2013, but there can be no assurance that will be the case or what that availability might be. Please see “Recent Developments — ArcLight Transactions” for more information about the ArcLight Transactions. Under the terms of the Fourth Amendment:


•	Permits the consummation of the ArcLight Transactions and the PIK Distribution according to the terms of the Amended Partnership Agreement;


•	On October 1, 2013, the aggregate commitments of the lenders under the credit agreement will be reduced to $175 million unless before such date AIM Midstream Holdings makes an equity contribution to the Partnership of $12.5 million that is used to repay borrowings under the June 2012 amended credit facility by October 1, 2013;


•	The total outstanding borrowings under the June 2012 amended credit agreement are limited to $175 million until such equity contribution by AIM Midstream Holdings and debt repayment has occurred, at which time the maximum permitted borrowings under the June 2012 amended credit agreement will be raised to $200 million;


•	The margins relating to our (i) Eurodollar-based loans range from 2.50% to 4.75% depending on the Consolidated Total Leverage ratio then in effect, and (ii) base rate loans range from 1.5% to 3.75%;


•	The definition of Consolidated Total Indebtedness will not include the Series A Preferred Units or certain surety bonds relating to the High Point Assets;


•	The definition of Consolidated EBITDA (the consolidated EBITDA for the quarters ending June 30 and September 30, 2013 will be annualized for purposes of the Consolidated Total Leverage Ratio) will:


◦	include, on a pro forma basis, the consolidated EBITDA of the High Point subsidiaries as if they were owned by the Partnership beginning on January 1, 2013;


◦	exclude any insurance proceeds attributable to any event occurring prior to January 1, 2013; and


◦	exclude any one-time, non-recurring transaction expenses of the Partnership incurred in connection with the ArcLight Transactions or the Fourth Amendment.

•


•	The maximum Consolidated Total Leverage Ratio permitted as of the end of any fiscal quarter cannot exceed the ratio set forth below:



Fiscal Quarter Ending	Consolidated Total Leverage Ratio
June 30, 2013	5.90:1.00
September 30, 2013	5.90:1.00
December 31, 2013	5.75:1.00
March 31, 2014	5.75:1.00
June 30, 2014	5.75:1.00
September 30, 2014	5.50:1.00
December 31, 2014	5.25:1.00
March 31, 2015 and each fiscal quarter thereafter	4.50:1.00


•	The Partnership agrees to cooperate with and pay the fees and expenses incurred by Bank of America, the administrative agent for the June 2012 amended credit agreement, in connection with its engagement of FTI Consulting to advise and assist it in an assessment of the Partnership's financial condition; and

•

The lenders permanently waived the Partnership's failure to comply with covenants relating to the Partnership's Consolidated Total Leverage Ratio for the quarters ended December 31, 2012 and March 31, 2013. As of April 15, 2013, we had approximately $130 million of outstanding borrowings and approximately $45 million of available borrowing capacity as a result of the reduction of our borrowing capacity to a total of $175 million as described herein. Until June 30, 2013, we will not be required to meet a Consolidated Leverage Ratio under our June 2012 amended credit facility. We expect that we will have availability under our June 2012 amended credit facility and be able to meet the Fourth Amendment's Consolidated Leverage Ratio once it is reinstated on June 30, 2013, but there can be no assurance that will be the case or what that availability might be.

As a result of the contribution of the High Point assets to the Partnership, the Fourth Amendment, the PIK Distribution on the Series A Preferred Units and the Preferred Unit Distribution Waiver, we expect to generate sufficient cash flow from operations and borrowings under our June 2012 amended credit facility, as needed, to :


•	pay the required distribution on the Series A Convertible Preferred Units (a portion of which is payable in Series A PIK Units, less the Preferred Unit Distribution Waiver);


•	pay at least the minimum quarterly distribution on all outstanding common units, subordinate units and general partner units; and


•	meet our requirements for working capital and capital expenditures,

in each case, for the next twelve months following the date of this Annual Report on Form 10-K.

We depend on our June 2012 amended credit facility for future capital needs and may use it to fund a portion of cash distributions to unitholders, as necessary, depending on the level of our operating cashflow. We are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of financial markets and commodity price levels. Our failure to comply with any of the covenants under our June 2012 amended credit facility could result in a default, which could cause all of our existing indebtedness to become immediately due and payable. We were unable to maintain compliance with consolidated total leverage ratio required by our June 2012 amended credit agreement as it existed prior to the Fourth Amendment during the quarters ended December 31, 2012 and March 31, 2013. On April 15, 2013, we entered into a Fourth Amendment to our June 2012 amended credit agreement that, among other things, modified the maximum permitted consolidated total leverage ratio. The maximum consolidated total leverage ratio permitted by the Fourth Amendment varies by quarter, initially permitting a ratio of 5.90 to 1.00 for the quarter ending June 30, 2013 and then gradually lowering to 4.50 to 1.00 commencing with the quarter ending March 31, 2015. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Our Credit Facility" for more information about the Fourth Amendment and our June 2012 amended credit facility.

Customer Concentration and Credit Risk

Substantially all of the natural gas produced on our Lafitte system is sold to ConocoPhillips for use at its Alliance Refinery in Plaquemines Parish, Louisiana under a contract that expires in 2023. On our Bazor Ridge system, we have a POP arrangement with Venture Oil & Gas Co. that contains an acreage dedication under a contract that expires in 2015. We have a weighted-average remaining life of approximately two years on our fee-based contracts in this segment. The weighted-average remaining life on our POP contracts in this segment is approximately four years. For the year ended December 31, 2012, our Gathering and Processing segment derived 40%, 12% and 11% of its revenue from ConocoPhillips, Enbridge Marketing (US) L.P., and Shell, respectively.

In our Transmission segment, we contract with LDCs, electric utilities, or direct-served industrial complexes, or to interconnections on other large pipelines, to provide firm and interruptible transportation services. Among all of our customers in this segment, the weighted-average remaining life of our firm and interruptible transportation contracts are approximately five years and less than one year, respectively. ExxonMobil, Enbridge Marketing (US) L.P., and Calpine Corporation are the three largest purchasers of natural gas and transmission capacity, respectively, in our Transmission segment and accounted for approximately 50%, 22% and 10%, respectively, of our segment revenue for the year ended December 31, 2012.

We examine the creditworthiness of third-party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.

Although we have gathering, processing or transmission contracts with each of these customers of varying duration, if one or more of these customers were to default on their contract or if we were unable to renew our contract with one or more of these customers on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all. In any of these situations, our gross margin and cash flows and our ability to make cash distributions to our unitholders may be adversely

affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our gross margin.

Contractual Obligations

The table below summarizes our contractual obligations and other commitments as of December 31, 2012:



	Total		Less Than 1 Year		1 - 3 Years		3 - 5 Years		More Than 5 Years
	(in thousands)
Long term debt	$	128,285	$	—	$	—	$	128,285	$	—
Operating leases and service contract	2,576		661		1,057		858		—
Asset retirement obligation (“ARO”)	8,319		—		—		7,860		459
Total	$	139,180	$	661	$	1,057	$	137,003	$	459

Impact of Seasonality

Results of operations in our Transmission segment are directly affected by seasonality due to higher demand for natural gas during the winter months, primarily driven by our LDC customers. On our AlaTenn system, we offer some customers seasonally-adjusted firm transportation rates that require customers to reserve capacity at rates that are higher in the period from October to March compared to other times of the year. On our Midla system, we offer customers seasonally-adjusted firm transportation reservation volumes that allow customers to reserve more capacity during the period from October to March compared to other times of the year. The combination of seasonally-adjusted rates and reservation volumes, as well as higher volumes overall, result in higher revenue and segment gross margin in our Transmission segment during the period from October to March compared to other times of the year. We generally do not experience seasonality in our Gathering and Processing segment.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires our and our Predecessor’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. Actual results could differ from these estimates. The policies and estimates discussed below are considered by our and Predecessor’s management to be critical to an understanding of the financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.

Use of Estimates. The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect our reported financial positions and results of operations. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. 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 revenue and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing tangible and intangible assets for possible impairment, (4) estimating the useful lives of our assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results could differ materially from our estimates.

Property, Plant and Equipment. In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the period it benefits. Our property, plant and equipment is depreciated using the straight-line method over the estimated useful lives of the assets. The costs of renewals and betterments which extend the useful life of property, plant and equipment are also capitalized. The costs of repairs, replacements and maintenance projects are expensed as incurred.

Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values which would impact future depreciation expense.

Impairment of Long-Lived Assets. We assess our long-lived assets for impairment on authoritative guidance. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. Fair

values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

We incurred no impairment charges during the years ended December 31, 2012 and 2011.

Environmental Remediation. Current accounting guidelines require us to recognize a liability and expense associated with environmental remediation if (i) government agencies mandate such activities, (ii) the existence of a liability is probable and (iii) the amount can be reasonably estimated. As of December 31, 2012 we have recorded no liability for remediation expenditures. If governmental regulations change, we could be required to incur remediation costs which may have a material impact on our profitability.

Asset Retirement Obligations. As of December 31, 2012, we have recorded liabilities of $8.3 million for future asset retirement obligations associated with our pipeline assets. Related accretion expense has been recorded in interest expense as discussed in Note 1 in our consolidated financial statements. The recognition of an asset retirement obligation requires that management make numerous estimates, assumptions and judgments regarding such factors as costs of remediation, timing of settlement to changes in the estimate of the costs of remediation. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset or corresponding liability on a prospective basis and an adjustment in our depreciation expense in future periods.

Equity-Based Awards. We account for equity-based awards in accordance with applicable guidance, which establishes standards of accounting for transactions in which an entity exchanges its equity instruments for goods or services. Equity-based compensation expense is recorded based upon the fair value of the award at grant date. Such costs are recognized as expense on a straight-line basis over the corresponding vesting period.

During 2010, the fair values of the phantom-unit grants that we made were calculated based on several valuation models, including a discounted cash flow, or DCF, model, a comparable company multiple analysis and a comparable transaction multiple analysis. The DCF model included 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 comparable 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 certain assumptions in the calculation of enterprise value. The initial valuation of $10.00 per common unit was prepared in August 2009 in connection with our formation in anticipation of the acquisition of our assets from a subsidiary of Enbridge Energy Partners, L.P. In November 2009, we received indirect third-party investments at that same valuation in connection with the acquisition of our assets from Enbridge. We assessed the adequacy of that valuation on each grant date subsequent to the initial fair value calculation to determine if events or circumstances had occurred that would cause that valuation to become less relevant, noting none. Moreover, we received additional indirect third-party investments at $10.00 per common unit in each of September and November 2010. As a result, we maintained that $10.00 valuation for phantom-unit grants made in November 2009, March 2010 and October 2010.

For the phantom-unit grants made during March 2011, the fair values of the grants were calculated by affiliates of our general partner as $13.67 per common unit based on several valuation models as of December 31, 2010, including a DCF model, a comparable company multiple analysis and a comparable transaction multiple analysis. The DCF 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 comparable 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 certain assumptions in the calculation of enterprise value. The year-end 2010 valuation was completed in January 2011. We assessed the adequacy of that valuation in connection with the March 2011 grant date to determine if events or circumstances had occurred since December 31, 2010 that would cause that valuation to become less relevant, noting none.

Revenue Recognition. 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 the gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that is 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 revenue. Under keep-whole contracts, we keep the NGLs extracted and return the processed natural gas or value of the natural gas to the producer.

Interest in the Burns Point Plant. We account for our interest in the Burns Point Plant using the proportionate consolidation method. Under this method, we include in our consolidated statement of operations, our value of plant revenues taken in-kind and plant expenses reimbursed to the operator.

Natural Gas Imbalance Accounting. Quantities of natural gas over-delivered or under-delivered related to operational balancing agreements are recorded monthly as inventory or as a payable using weighted average prices at the time the imbalance was created. Monthly, gas imbalances over-delivered are valued at the lower of cost or market; gas imbalances under-delivered are valued at replacement cost. These imbalances are typically settled in the following month with deliveries of natural gas. Under the contracts, imbalance cash-outs are recorded as a sale or purchase of natural gas, as appropriate.

Price Risk Management Activities. We have structured our hedging activities in order to minimize our commodity pricing and interest rate risks and to help maintain compliance with certain financial covenants in our June 2012 amended credit facility. These hedging activities rely upon forecasts of our expected operations and financial structure through December 2013. If our operations or financial structure are significantly different from these forecasts, we could be subject to adverse financial results as a result of these hedging activities. We mitigate this potential exposure by retaining an operational cushion between our forecasted transactions and the level of hedging activity executed.

From the inception of our hedging program in December 2009, we used mark-to-market accounting for our commodity hedges and interest rate caps. We record monthly realized gains and losses on hedge instruments based upon cash settlements information. The settlement amounts vary due to the volatility in the commodity market prices throughout each month. We also record unrealized gains and losses quarterly based upon the future value on mark-to-market hedges through their expiration dates. The expiration dates vary but are currently no later than December 2013 for our commodity hedges. We monitor and review hedging positions regularly.

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 US GAAP, derivative assets and liabilities can be offset under certain conditions. The ASU requires disclosures showing both gross information and net information about instruments eligible for offset in the balance sheet. The Partnership adopted the provisions of ASU 2011-11 for the year ended December 31, 2012.

In January 2013, the FASB issued Accounting Standards Update ("ASU") No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies that ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities, applies to financial instruments or derivative transactions accounted for under ASC 815. The amendments require disclosures to present both gross and net amounts of derivative assets and liabilities that are subject to master netting arrangements with counterparties. We currently present our derivative assets and liabilities net on our statement of financial position. We adopted this guidance during the first quarter of 2013; it did not have a material impact on our condensed consolidated financial statements with the exception of additional disclosure in the footnotes to the condensed consolidated financial statements.

In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income ("AOCI"), which requires entities to present either in a single note or parenthetically on the face of the financial statements (i) the amount of significant items reclassified from each component of AOCI and (ii) the income statement line items affected by the reclassifications. We adopted this guidance during the first quarter of 2013; it did not have a material impact on our condensed consolidated financial statements as there are currently no items reclassified from AOCI.

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