Edgar Filing: American Midstream Partners, LP

AMID 2013.09.30 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



S	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2013



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-35257

AMERICAN MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)



Delaware	27-0855785
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1614 15th Street, Suite 300
Denver, CO	80202
(Address of principal executive offices)	(Zip code)

(720) 457-6060

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ý Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ý Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	ý (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes ý No

There were 4,706,893 common units representing limited partnership interests of American Midstream Partners, LP outstanding as of October 31, 2013. Our common units trade on the New York Stock Exchange under the ticker symbol “AMID.”

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TABLE OF CONTENTS



		Page
PART I. FINANCIAL INFORMATION		4
Item 1.	Financial Statements	4
	Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012 (unaudited)	4
	Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012 (unaudited)	5
	Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2013 and 2012 (unaudited)	6
	Condensed Consolidated Statements of Changes in Partners’ Capital and Noncontrolling Interest as of and for the nine months ended September 30, 2013 and 2012 (unaudited)	7
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012 (unaudited)	8
	Notes to Unaudited Consolidated Financial Statements	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
	Cautionary Statement About Forward-Looking Statements	38
	Overview	39
	Recent Developments	39
	Subsequent Event	43
	Our Operations	43
	How We Evaluate Our Operations	44
	General Trends and Outlook	47
	Liquidity and Capital Resources	54
	Critical Accounting Policies	57
	Recent Accounting Pronouncements	57

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	57

Item 4.	Controls and Procedures	59

PART II. OTHER INFORMATION		59

Item 1.	Legal Proceedings	60
Item 1A.	Risk Factors	60
Item 6.	Exhibits	61

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Glossary of Terms

As generally used in the energy industry and in this Quarterly Report on Form 10-Q (the “Quarterly Report”), the identified terms have the following meanings:

ASC Accounting Standards Codification; trademark of the Financial Accounting Standards Board (FASB).

Bbl Barrels: 42 U.S. gallons measured at 60 degrees Fahrenheit.

Bcf One billion cubic feet.


Btu	British thermal unit; the approximate amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.


Condensate	Liquid hydrocarbons present in casinghead gas that condense within the gathering system and are removed prior to delivery to the gas plant. This product is generally sold on terms more closely tied to crude oil pricing.

/d Per day.


EBITDA	Net income (loss) before net interest expense, income taxes, and depreciation and amortization. EBITDA is a non-GAAP measurement.

FERC Federal Energy Regulatory Commission.

Fractionation Process by which natural gas liquids are separated into individual components.


GAAP	General Accepted Accounting Principles: Accounting principles generally accepted in the United States of America.

Gal Gallons.

MMBtu One million British thermal units.

Mcf One thousand cubic feet.

MMcf One million cubic feet.

Mgal One thousand gallons


NGL or NGLs	Natural gas liquid(s): The combination of ethane, propane, normal butane, isobutane and natural gasoline that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.


Throughput	The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.

As used in this Quarterly Report, unless the context otherwise requires, “we,” “us,” “our,” the “Partnership” and similar terms refer to American Midstream Partners, LP, together with its consolidated subsidiaries.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

American Midstream Partners, LP and Subsidiaries

Condensed Consolidated Balance Sheets

(Unaudited, in thousands)



	September 30, 2013		December 31, 2012
Assets
Current assets
Cash and cash equivalents	$	1,076	$	576
Accounts receivable	4,992		1,958
Unbilled revenue	24,927		21,512
Risk management assets	1,050		969
Other current assets	4,573		3,226
Total current assets	36,618		28,241
Property, plant and equipment, net	280,516		223,819
Noncurrent assets held for sale, net	874		—
Other assets, net	6,202		4,636
Total assets	$	324,210	$	256,696
Liabilities, Equity and Partners’ Capital
Current liabilities
Accounts payable	$	1,595	$	5,527
Accrued gas purchases	17,307		17,034
Accrued expenses and other current liabilities	14,709		9,619
Current portion of long-term debt	157		—
Risk management liabilities	349		—
Total current liabilities	34,117		32,180
Risk management liabilities	122		—
Asset retirement obligations	34,440		8,319
Other liabilities	215		309
Long-term debt	121,035		128,285
Total liabilities	189,929		169,093
Commitments and contingencies (see Note 14)
Convertible preferred units
Series A convertible preferred units (5,204 thousand units issued and outstanding as of September 30, 2013)	92,912		—
Equity and partners’ capital
General partner interest (185 thousand units issued and outstanding as of September 30, 2013 and December 31, 2012)	12,106		548
Limited partner interest (4,705 and 9,165 thousand units issued and outstanding as of September 30, 2013 and December 31, 2012, respectively)	21,602		79,266
Accumulated other comprehensive income	261		351
Total partners’ capital	33,969		80,165
Noncontrolling interests	7,400		7,438
Total equity and partners' capital	41,369		87,603
Total liabilities, equity and partners' capital	$	324,210	$	256,696

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

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American Midstream Partners, LP and Subsidiaries

Condensed Consolidated Statements of Operations

(Unaudited, in thousands, except for per unit amounts)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Revenue	$	76,577		$	54,347		$	210,190		$	138,423
(Loss) gain on commodity derivatives, net	(499		)	(946		)	110			3,157
Total revenue	76,078			53,401			210,300			141,580
Operating expenses:
Purchases of natural gas, NGLs and condensate	57,973			41,365			162,671			100,075
Direct operating expenses	7,714			5,329			19,637			11,550
Selling, general and administrative expenses	3,969			3,246			11,982			10,101
Equity compensation expense	392			474			1,877			1,272
Depreciation and accretion expense	6,458			5,504			18,802			15,722
Total operating expenses	76,506			55,918			214,969			138,720
Gain on involuntary conversion of property, plant and equipment	—			—			343			—
Gain on sale of assets, net	—			4			—			121
Loss on impairment of property, plant and equipment	—			—			(15,232		)	—
Operating (loss) income	(428		)	(2,513		)	(19,558		)	2,981
Other expense:
Interest expense	(2,082		)	(1,501		)	(6,003		)	(3,083		)
Net loss from continuing operations	(2,510		)	(4,014		)	(25,561		)	(102		)
Discontinued operations
Income (loss) from operations of disposal groups	144			(12		)	(1,652		)	94
Net loss	(2,366		)	(4,026		)	(27,213		)	(8		)
Net income attributable to noncontrolling interests	190			249			533			249
Net loss attributable to the Partnership	$	(2,556	)	$	(4,275	)	$	(27,746	)	$	(257	)

General partner's interest in net loss	$	(46	)	$	(85	)	$	(544	)	$	(5	)
Limited partners' interest in net loss	$	(2,510	)	$	(4,190	)	$	(27,202	)	$	(252	)

Limited partners' net (loss) income per common unit (See Note 4 and Note 11):
Basic and diluted:
Loss from continuing operations	$	(0.82	)	$	(0.46	)	$	(5.54	)	$	(0.04	)
Income (loss) from discontinued operations	0.02			—			(0.19		)	0.01
Net loss	$	(0.80	)	$	(0.46	)	$	(5.73	)	$	(0.03	)
Weighted average number of common units outstanding:
Basic and diluted	6,663			9,108			8,334			9,103

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

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American Midstream Partners, LP and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income

(Unaudited, in thousands)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Net loss	$	(2,366	)	$	(4,026	)	$	(27,213	)	$	(8	)
Unrealized (loss) gain on post retirement benefit plan assets and liabilities	(34		)	23			(90		)	40
Comprehensive (loss) income	(2,400		)	(4,003		)	(27,303		)	32
Less: Comprehensive income attributable to noncontrolling interests	190			249			533			249
Comprehensive loss attributable to Partnership	$	(2,590	)	$	(4,252	)	$	(27,836	)	$	(217	)

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

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American Midstream Partners, LP and Subsidiaries

Condensed Consolidated Statements of Changes in Partners’ Capital

and Noncontrolling Interest

(Unaudited, in thousands)



	Limited Partner Interest			General Partner Interest			Accumulated Other Comprehensive Income			Total Partners' Capital			Noncontrolling Interest
Balances at December 31, 2011	$	99,890		$	1,091		$	415		$	101,396		—
Acquisition of noncontrolling interests	—			—			—			—			7,407
Net loss	(252		)	(5		)	—			(257		)	249
Unitholder contributions	—			13			—			13			—
Unitholder distributions	(11,809		)	(241		)	—			(12,050		)	—
Net distributions to noncontrolling interest owners	—			—			—			—			(249		)
LTIP vesting	364			(364		)	—			—			—
Tax netting repurchase	(88		)	—			—			(88		)	—
Unit based compensation	97			1,175			—			1,272			—
Other comprehensive income	—			—			40			40			—
Balances at September 30, 2012	$	88,202		$	1,669		$	455		$	90,326		7,407

Balances at December 31, 2012	$	79,266		$	548		$	351		$	80,165		$	7,438
Net loss	(27,202		)	(544		)	—			(27,746		)	533
Unitholder contributions	—			12,500			—			12,500			—
Unitholder distributions	(16,332		)	(340		)	—			(16,672		)	—
Fair value of Series A Units in excess of net assets received	(15,300		)	(312		)	—			(15,612		)	—
Net distributions to noncontrolling interest owners	—			—			—			—			(571		)
LTIP vesting	1,570			(1,570		)	—			—			—
Tax netting repurchase	(400		)	—			—			(400		)	—
Unit based compensation	—			1,824			—			1,824			—
Other comprehensive loss	—			—			(90		)	(90		)	—
Balances at September 30, 2013	$	21,602		$	12,106		$	261		$	33,969		$	7,400

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

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American Midstream Partners, LP and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited, in thousands)



	Nine Months Ended September 30,
	2013			2012
Cash flows from operating activities
Net loss	$	(27,213	)	$	(8	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and accretion expense	18,802			15,819
Amortization of deferred financing costs	975			493
Amortization of weather derivative premium	378			—
Unrealized loss (gain) on commodity derivatives	1,159			(1,733		)
Unit based compensation	1,824			1,272
OPEB plan net periodic benefit	(55		)	(61		)
Gain on involuntary conversion of property, plant and equipment	(343		)	—
Gain on sale of assets, net	—			(126		)
Loss on impairment of property, plant and equipment	15,232			—
Loss on impairment of noncurrent assets held for sale	1,807			—
Changes in operating assets and liabilities, net:
Accounts receivable	595			(558		)
Unbilled revenue	(1,970		)	6,677
Risk management assets	(1,147		)	—
Other current assets	702			1,285
Other assets, net	(67		)	(65		)
Accounts payable	(808		)	1,396
Accrued gas purchases	273			(5,833		)
Accrued expenses and other current liabilities	2,766			(1,879		)
Other liabilities	(94		)	(203		)
Net cash provided by operating activities	12,816			16,476
Cash flows from investing activities
Cost of acquisition, net of cash acquired	—			(51,377		)
Additions to property, plant and equipment	(16,767		)	(4,465		)
Proceeds from disposals of property, plant and equipment	—			126
Insurance proceeds from involuntary conversion of property, plant and equipment	482			—
Net cash used in investing activities	(16,285		)	(55,716		)
Cash flows from financing activities
Unit holder contributions	12,500			13
Unit holder distributions	(12,458		)	(12,050		)
Issuance of Series A convertible preferred units, net	14,393			—
Net distributions to noncontrolling interest owners	(571		)	(249		)
LTIP tax netting unit repurchase	(400		)	(88		)
Payments for deferred debt issuance costs	(1,509		)	(1,140		)
Payments on other debt	(2,231		)	—
Borrowings on other debt	1,495			—
Payments on long-term debt	(99,821		)	(42,310		)
Borrowings on long-term debt	92,571			94,690
Net cash provided by financing activities	3,969			38,866

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Net increase (decrease) in cash and cash equivalents	500			(374		)
Cash and cash equivalents
Beginning of period	576			871
End of period	$	1,076		$	497
Supplemental cash flow information
Interest payments	$	4,933		$	1,894
Supplemental non-cash information
(Decrease) increase in accrued property, plant and equipment	$	(6,169	)	$	808
Net assets contributed in exchange for the issuance of Series A convertible preferred units (see Note 3)	$	59,995		$	—
Fair value of Series A Units in excess of net assets received	$	15,612		$	—
Accrued and in-kind unitholder distribution for Series A Units	$	2,912		$	—

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

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American Midstream Partners, LP and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(Unaudited)

1. Organization and Basis of Presentation

Nature of business

American Midstream Partners, LP (the “Partnership”) was formed on August 20, 2009 as a Delaware limited partnership for the purpose of acquiring and operating certain natural gas pipeline and processing businesses. We provide natural gas gathering, treating, processing, fractionating, marketing and transportation services primarily in the Gulf Coast and Southeast regions of the United States through our ownership and operation of eleven gathering systems, four processing facilities, three interstate pipelines and five intrastate pipelines. We also own a 50% undivided, non-operating interest in a processing plant located in southern Louisiana. We hold our assets in a series of wholly owned limited liability companies as well as a limited partnership. Our capital accounts consist of general partner interests and limited partner interests.

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


•	High Point Gas Transmission, LLC, which owns and operates approximately 400 miles of intrastate pipeline and is connected to 40 meters with 32 active producers and offers processing options at the Toca processing plant with delivery to Southern Natural Gas available downstream of the processing plant in Louisiana;


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


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

ArcLight Transactions

On April 15, 2013, the Partnership, American Midstream GP, LLC, (our "General Partner") and AIM Midstream Holdings, LLC ("AIM"), an affiliate of American Infrastructure MLP Fund, entered into agreements (the "ArcLight Transactions") with High Point Infrastructure Partners, LLC ("HPIP"), an affiliate of ArcLight Capital Partners, LLC, pursuant to which HPIP (i) acquired 90% of our General Partner and all of our subordinated units from AIM and (ii) contributed certain midstream assets and $15.0 million in cash to us in exchange for 5,142,857 newly issued convertible preferred units (the “Series A Units”) issued by the Partnership. Of the $15.0 million cash consideration paid by HPIP, approximately $2.5 million was used to pay certain transaction expenses of HPIP, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's credit facility in connection with the Fourth Amendment to our credit agreement ("Fourth Amendment"). As a result of these transactions, which were also consummated on April 15, 2013, HPIP acquired both control of our General Partner and a majority of our outstanding limited partner interests. The midstream assets contributed by HPIP consist of approximately 700 miles of natural gas and liquids pipeline assets located in southeast Louisiana and the shallow water and deep shelf Gulf of Mexico (commonly referred to as the "High Point System"). The High Point System gathers natural gas from both onshore and offshore producing regions around southeast Louisiana. The onshore footprint is in Plaquemines and St. Bernard's Parishes, LA. The offshore footprint consists of the following federal Gulf of Mexico zones: Mississippi Canyon, Viosca Knoll, West Delta, Main Pass, South Pass and Breton Sound. Natural gas is collected at more than 75 receipt points that connect to hundreds of wells targeting various geological zones in water depths up to 1,000 feet, with an emphasis on oil and liquids-rich reservoirs. The High Point System is comprised of FERC-regulated transmission assets and non-jurisdictional assets, both of which accept natural gas from well production and interconnected pipeline systems. Natural gas is delivered to the Toca Gas Processing Plant, operated by Enterprise, where the products are processed and the residue gas sent to an unaffiliated interstate system owned by Kinder Morgan. See Note 3 "Acquisitions" for further information.

The Partnership believes that the consummation of the ArcLight Transactions will allow it to comply with the Consolidated Total Leverage to EBITDA ratio in the Fourth Amendment. However, while we were in compliance with financial covenants of the Fourth Amendment as of September 30, 2013, no assurances can be given that the Partnership's future results of operations will allow us to comply with financial covenants of the Fourth Amendment. If we are not able to generate sufficient cash flows from operations to comply with the financial covenants in the Fourth Amendment and we are not able to enter into an agreement to refinance or obtain covenant default waivers, then the outstanding balance under our credit facility could become due and payable upon acceleration by the lenders in our banking group and other agreements with cross-default provisions, if any, could become due. In addition, failure to comply with any of the covenants under our Fourth Amendment could adversely affect our ability to fund ongoing operations and growth capital requirements as well as our ability to pay distributions to our unitholders. See Note 18 "Liquidity" for further information.

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Equity Restructuring

Effective August 9, 2013, we executed an equity restructuring agreement ("Equity Restructuring") with our General Partner and HPIP. As part of the Equity Restructuring, the Partnership's 4,526,066 subordinated units and previous incentive distribution rights (the “former IDRs,” all of which were owned by our General Partner, which is controlled by HPIP) were combined into and restructured as a new class of incentive distribution rights (the “new IDRs”). Upon the issuance of the new IDRs, the subordinated units and former IDRs were canceled. The new IDRs are allocated 85.02% to HPIP and 14.98% to our General Partner. The new IDRs entitle the holders of our incentive distribution rights to receive 48% of any quarterly cash distributions from available cash after the Partnership's common unitholders have received the full minimum quarterly distribution ($0.4125 per unit) for each quarter plus any arrearages from prior quarters (of which there are currently none).

The Equity Restructuring Agreement also provided for the issuance of warrants to our General Partner to purchase up to 300,000 of our common units at an exercise price of $0.01 per common unit. These warrants are exercisable on the later of (i) 18 months from the equity restructuring completion date or (ii) the date that the volume weighted average trading price of our common units on the New York Stock Exchange exceeds $25.00 for 30 consecutive trading days. The warrants contain customary anti-dilution and other protections.

Following the announcement of the Equity Restructuring, AIM Midstream Holdings, LLC, or AIM filed an action in Delaware Chancery Court against HPIP, our General Partner and us seeking either rescission of the Equity Restructuring or, in the alternative, monetary damages. While we cannot predict the ultimate outcome of this litigation, we do not believe it will be material to our operations or financial results. As a result of the action filed by AIM, the warrants that were issued by the Partnership, in conjunction with the Equity Restructuring, to the General Partner for subsequent conveyance to AIM, the owner of the Class B interest of our General Partner, were canceled effective August 29, 2013. In addition, the $12.5 million escrowed in connection with our Equity Restructuring was not released to the Partnership. Accordingly, HPIP contributed $12.5 million in cash to the Partnership on September 30, 2013, in order to permit the Partnership to satisfy obligations under our credit agreement and was accounted for as a contribution from our General Partner.

Basis of Presentation

These unaudited condensed consolidated financial statements have been prepared in accordance with GAAP for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include disclosures required by GAAP for annual periods. We have made reclassifications to amounts reported in prior period condensed consolidated financial statements to conform to our current year presentation. These reclassifications did not have an impact on net income for the period previously reported. The information furnished herein reflects all normal recurring adjustments which are, in the opinion of management, necessary for a fair statement of financial position as of September 30, 2013, and December 31, 2012, condensed consolidated statement of operations for the three and nine months ended September 30, 2013 and 2012, statement of comprehensive income for the three and nine months ended September 30, 2013 and 2012, statement of changes in partners’ capital and noncontrolling interest for the nine months ended September 30, 2013 and 2012, and statements of cash flows for the nine months ended September 30, 2013 and 2012.

Our financial results for the nine months ended September 30, 2013 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2013. These unaudited condensed consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in i) our Annual Report on Form 10-K for the year ended December 31, 2012 (“Annual Report”) filed on April 16, 2013 and ii) Exhibit 99.1 to the Current Report on Form 8-K that was filed with the Securities and Exchange Commission ("SEC") on October 1, 2013 which updated portions of our annual report.

Consolidation Policy

Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold a 50% undivided interest in the Burns Point gas processing facility in which we are responsible for our proportionate share of the costs and expenses of the facility. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of this undivided interest. In July 2012, the Partnership acquired a 87.4% undivided interest in the Chatom Processing and Fractionation facility (the "Chatom System"). Our consolidated financial statements reflect the accounts of the Chatom System since acquisition, and the interests in the Chatom System held by non-affiliated working interest owners are reflected as noncontrolling interests in the Partnership's consolidated financial statements.

Use of Estimates

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

2. Summary of Significant Accounting Policies

Transactions Between Entities Under Common Control

We may enter into transactions with our General Partner whereby we receive a contribution of midstream assets or subsidiaries in exchange for consideration from the Partnership. We account for the net assets received using the historical book value of the asset or subsidiary being contributed or transferred as these are transactions between entities under common control. Our historical financial statements may be revised to include the results attributable to the assets contributed from our General Partner as if we owned such assets for all periods presented by the Partnership since the change in control of our General Partner, effective April 15, 2013.

Convertible Preferred Units

We record the issuance of our Series A Preferred Units at fair value and separately classified these units on our balance sheet in between total liabilities and partners’ capital, frequently called “mezzanine equity” as the ability to exercise these units are outside of the Partnership’s control and contain no beneficial conversion features pursuant to Accounting Standards Codification 470-20, Debt with Conversion and Other Options. These units are classified as participating securities and are included in our calculation of net income (loss) per limited and general partner unit using the two-class method.

Recent Accounting Pronouncements

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 net derivative assets and liabilities on our statement of financial position. We have provided additional disclosures regarding the gross amounts of derivative assets and liabilities in Note 6 "Derivatives" in accordance with these new standards updates.

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.

3. Acquisitions

High Point System

Effective April 15, 2013, our General Partner contributed the High Point System, consisting of 100% of the limited liability company interests in High Point Gas Transmission, LLC and High Point Gas Gathering, LLC. The High Point System entities own midstream assets consisting of approximately 700 miles of natural gas and liquids pipeline assets located in southeast Louisiana, in the Plaquemines and St. Bernard's Parishes, and the shallow water and deep shelf Gulf of Mexico, including the Mississippi Canyon, Viosca Knoll, West Delta, Main Pass, South Pass and Breton Sound zones. Natural gas is collected at more than 75 receipt points that connect hundreds of wells with an emphasis on oil and liquids-rich reservoirs.

The High Point System, along with $15.0 million in cash, was contributed to us by HPIP in exchange for 5,142,857 Series A Units. Of the $15.0 million cash consideration paid by HPIP, approximately $2.5 million was used to pay certain transaction expenses of HPIP, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's credit

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facility in connection with the Fourth Amendment. The contribution of the High Point System occurred concurrently with HPIP's acquisition of 90% of our General Partner and all of our subordinated units, which resulted in HPIP gaining control of our General Partner and a majority of our outstanding limited partner interests.

The fair value of the Series A Units on April 15, 2013 was $17.50 per unit, or a total of $90.0 million, and was issued by the Partnership in exchange for net cash of approximately $12.5 million and net assets of $61.9 million contributed to the Partnership by our General Partner. The contribution of net assets of the High Point System was accounted for as a transaction between entities under common control whereby the High Point System was recorded at historical book value. As such, the value of the Series A Units in excess of the net assets contributed by our General Partner amounted to $15.6 million and was allocated pro-rata to our General Partner and existing limited partners' interest based on their ownership interests.

The contribution is being treated as a transaction between entities under common control, under which the net assets received are recorded at their historical book value as of date of transfer. The following table presents the carrying value of the identified assets received and liabilities assumed at the acquisition date (in thousands):



Cash and cash equivalents	$	1,935
Accounts receivable	3,629
Unbilled revenue	1,446
Other current assets	2,049
Property, plant and equipment, net	82,615
Other assets	1,000
Accounts payable	(11		)
Accrued expenses and other current liabilities	(4,077		)
Current portion of long-term debt	(893		)
Asset retirement obligation liability	(25,763		)
Total identifiable net assets	$	61,930

Subsequent to the contribution, for the three and nine months ended September 30, 2013, the High Point System contributed $10.7 million and $19.7 million, respectively, of revenue and $1.2 million and $2.7 million, respectively, of net income attributable to the Partnership's Transmission Segment, which are included in the condensed consolidated statement of operations.

Chatom Gathering, Processing and Fractionation Plant

Effective July 1, 2012, we acquired an 87.4% undivided interest in the Chatom System from affiliates of Quantum Resources Management, LLC. The acquisition fair value consideration of $51.4 million includes a credit associated with the cash flow the Chatom System generated between January 1, 2012 and the effective date of July 1, 2012. The consideration paid by the Partnership consisted of cash, which was funded by borrowings under our credit facility.

The Chatom System is located in Washington County, Alabama, approximately 15 miles from our Bazor Ridge processing plant in Wayne County, Mississippi, and consists of a 25 MMcf/d refrigeration processing plant, a 1,900 Bbl/d fractionation unit, a 160 long-ton per day sulfur recovery unit, and a 29 mile gas gathering system. We believe the fractionating services provide flexibility to the Partnership's product and service offerings.

The following table presents the fair value of consideration transferred to acquire the Chatom System and the amounts of identified assets acquired and liabilities assumed at the acquisition date, as well as the fair value of the 12.6% noncontrolling interest in the Chatom System at the acquisition date (in thousands):

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Cash	$	51,377
Recognized amounts of identifiable assets acquired and liabilities assumed:
Unbilled revenue	$	4,535
Property, plant and equipment	58,279
Asset retirement cost	452
Accounts payable	(399		)
Accrued gas purchases	(3,631		)
Asset retirement obligations	(452		)
Noncontrolling interest	(7,407		)
Total identifiable net assets	$	51,377

The fair value of the property, plant and equipment and noncontrolling interests were estimated by applying a combination of the market and income approaches. These fair value measurements were based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimates were based on i) an assumed cost of capital of 9.25%, ii) an assumed terminal value based on the present value of estimated EBITDA, iii) an inflationary cost increase of 2.5%, iv) forward market prices as of July 2012 for natural gas and crude oil, v) a Federal tax rate of 35% and a state tax rate of 6.5%, and vi) an increase in processed and fractionated volumes in 2013, declining thereafter. Working capital was estimated using net realizable value. Accrued revenue was deemed to be fully collectible at July 1, 2012.

For the three and nine months ended September 30, 2013, our 87.4% undivided interest in the Chatom System contributed $14.6 million and $41.8 million, respectively, of revenue and $1.2 million and $3.6 million, respectively, of net income attributable to the Partnership, which are included in the condensed consolidated statement of operations.

For the three and nine months ended September 30, 2012, our 87.4% undivided interest in the Chatom System contributed $15.4 million of revenue and $2.1 million of net income attributable to the Partnership, which are included in the condensed consolidated statement of operations.

The following table presents unaudited pro forma consolidated information of the Partnership, adjusted for the acquisition of the Chatom System, as if the acquisition had occurred on January 1, 2011:



(unaudited, in thousands)	Nine months ended September 30, 2012
Revenue	$	174,179
Net income	$	1,422
Limited partners’ net income per unit	$	0.14

These amounts have been calculated after applying the Partnership's accounting policies and adjusting the results to reflect i) additional depreciation and amortization that would have been charged assuming fair value adjustments to property, plant and equipment, ii) recording pro forma interest expense on debt that would have been incurred to acquire the Chatom System as of January 1, 2011, iii) the elimination of transaction costs included in the historical financial statement of the Partnership which were directly related to the acquisition and iv) the elimination of the noncontrolling interest holders' proportionate share of earnings. The unaudited pro forma adjustments are based on available information and certain assumptions we believe are reasonable.

4. Discontinued Operations

We classify long-lived assets to be disposed of through sales that meet specific criteria as held for sale. We cease depreciating those assets effective on the date the asset is classified as held for sale. We record those assets at the lower of their carrying value or the estimated fair value less the cost to sell. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.

During the second quarter of 2013, the board of directors of our General Partner approved a plan to sell certain non-strategic gathering and processing assets which meet specific criteria, qualifying them as held for sale. As of September 30, 2013, certain gathering and processing assets were written down by $1.8 million to the estimated fair value less cost to sell. These fair value measurements are based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined

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by ASC 820. Primarily using the income approach, the fair value estimates are based on i) present value of estimated EBITDA, ii) an assumed discount rate of 10.0%, and iii) a decline in throughput volumes of 2.5% in 2013 and thereafter.

The net book value of the gathering and processing assets of $0.9 million is presented as Noncurrent assets held for sale, net on the condensed consolidated balance sheet. The following table presents the identifiable assets and liabilities of the assets classified as held for sale as of September 30, 2013 in the condensed consolidated balance sheet (in thousands):



Unbilled revenue	$	1,171
Property, plant and equipment, net	874
Accrued gas purchases	(987		)

As a result of the planned divestiture of these non-strategic midstream assets, we have accounted for these disposal groups as discontinued operations within our Gathering and Processing Segment. Accordingly, we reclassified and excluded the disposal groups' results of operations from our results of continuing operations and reported the disposal groups' results of operations as Income (loss) from operations of disposal groups in our accompanying condensed consolidated statement of operations for all periods presented. We did not, however, elect to present separately the operating, investing and financing cash flows related to the disposal groups in our accompanying condensed consolidated statement of cash flows as this activity was immaterial for all periods presented. The following table presents the revenue, expense and (loss) gain from operations of disposal groups associated with the assets classified as held for sale for the three and nine months ended September 30, 2013 and 2012 (in thousands):



	Three months ended September 30,					Nine months ended September 30,
	2013		2012			2013			2012
Revenue	$	3,760	$	2,923		$	11,319		$	8,515
Expense	3,616		2,935			11,164			8,421
Impairment	—		—			1,807			—
Income (loss) from operations of disposal groups	$	144	$	(12	)	$	(1,652	)	$	94
Limited partners' net income (loss) per unit from discontinued operations (basic and diluted)	$	0.02	$	—		$	(0.19	)	$	0.01

5. Concentration of Credit Risk and Trade Accounts Receivable

Our primary market areas are located in the United States along the Gulf Coast and in the Southeast. We have a concentration of trade receivable balances due from companies engaged in the production, trading, distribution and marketing of natural gas, NGL and condensate products. This concentration of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. Generally, our customers’ historical financial and operating information is analyzed prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. We maintain allowances for potentially uncollectible accounts receivable; however, for the nine months ended September 30, 2013 and 2012, no allowances on or write-offs of accounts receivable were recorded.

The following table summarizes the percentage of revenue earned from those customers that accounted for 10% or more of the Partnership's consolidated revenue in the consolidated statement of operations for the each of the periods presented below:



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Customer A	27	%	23	%	29	%	29	%
Customer B	13	%	17	%	13	%	—	%
Customer C	13	%	11	%	12	%	12	%
Customer D	—	%	12	%	—	%	16	%
Other	47	%	37	%	46	%	43	%
Total	100	%	100	%	100	%	100	%

6. Derivatives

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Commodity Derivatives

To minimize the effect of commodity prices and maintain our cash flow and the economics of our development plans, we enter into commodity hedge contracts from time to time. The terms of the contracts depend on various factors, including management’s view of future commodity prices, acquisition economics on purchased assets and future financial commitments. This hedging program is designed to mitigate the effect of commodity price downturns while allowing us to participate in some commodity price upside. Management regularly monitors the commodity markets and financial commitments to determine if, when, and at what level commodity hedging is appropriate in accordance with policies that are established by the board of directors of our General Partner. Currently, the commodity derivatives are in the form of swaps, puts and collars. As of September 30, 2013, the aggregate notional volume of our commodity derivatives was 3.0 million gallons.

We enter into commodity contracts with multiple counterparties. We may be required to post collateral with our counterparties in connection with our derivative positions. As of September 30, 2013, we have not posted collateral with any counterparty. Our counterparties are not required to post collateral with us in connection with their derivative positions. Netting agreements are in place with our counterparties that permit us to offset our commodity derivative asset and liability positions.

Interest Rate Swap

We entered into an interest rate swap to manage the impact of the interest rate risk associated with our credit facility, effectively converting a portion of the cash flows related to our long-term variable rate debt into fixed rate cash flows. As of September 30, 2013, the notional amount of our interest rate swap was $100 million. The interest rate swap was entered into with a single counterparty and we were not required to post collateral.

Weather Derivative

In the second quarter of 2013, we entered into a weather derivative to mitigate the impact of potential unfavorable weather to our operations under which we could receive payments totaling up to $10 million in the event that a hurricane or hurricanes of certain strength pass through the area as identified in the derivative agreement. The weather derivative is being accounted for using the intrinsic value method, under which the fair value of the contract is zero and any amounts received are recognized as gains during the period received. The weather derivative was entered into with a single counterparty and we were not required to post collateral. We paid a premium of approximately $1.1 million which is recorded in Risk management assets on the condensed consolidated balance sheet and is being amortized to Direct operating expense on a straight-line basis over the 12 month term of the contract. As of September 30, 2013, the unamortized amount of the risk management asset was approximately $0.8 million.

As of September 30, 2013 and December 31, 2012, the value associated with our commodity derivatives, interest rate swap instrument and weather derivative were recorded in our condensed consolidated balance sheets, under the captions as follows (in thousands):



	Gross Risk Management Assets				Gross Risk Management Liabilities						Net Risk Management Assets (Liabilities)
Balance Sheet Classification	September 30, 2013		December 31, 2012		September 30, 2013			December 31, 2012			September 30, 2013			December 31, 2012
Current	$	1,196	$	1,889	$	(146	)	$	(920	)	$	1,050		$	969
Noncurrent	—		—		—			—			—			—
Total assets	$	1,196	$	1,889	$	(146	)	$	(920	)	$	1,050		$	969

Current	$	—	$	—	$	(349	)	$	—		$	(349	)	$	—
Noncurrent	—		—		(122		)	—			(122		)	—
Total liabilities	$	—	$	—	$	(471	)	$	—		$	(471	)	$	—

For the three and nine months ended September 30, 2013 and 2012, respectively, the realized and unrealized gains (losses) associated with our commodity derivatives, interest rate swap instrument and weather derivative were recorded in our condensed consolidated statements of operations, under the captions as follows (in thousands):

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	Three months ended September 30,						Nine months ended September 30,
	Gain (loss) on derivatives						Gain (loss) on derivatives
Statement of Operations Classification	Realized			Unrealized			Realized			Unrealized
2013
Gain (loss) on commodity derivatives, net	$	261		$	(760	)	$	797		$	(687	)
Interest expense	(101		)	(153		)	(101		)	(471		)
Direct operating expenses	(284		)	—			(378		)	—
Total	$	(124	)	$	(913	)	$	318		$	(1,158	)
2012
Gain (loss) on commodity derivatives, net	$	816		$	(1,762	)	$	1,425		$	1,732

7. Fair Value Measurement

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


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


•	Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets that are either directly or indirectly observable; and


•	Level 3 – Inputs are unobservable and considered significant to fair value measurement.

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

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

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

The fair value of all derivatives instruments is estimated using a market valuation methodology based upon forward commodity price curves, volatility curves as well as other relevant economic measures, if necessary. Discount factors may be utilized to extrapolate a forecast of future cash flows associated with long dated transactions or illiquid market points. The inputs are obtained from independent pricing services, and we have made no adjustments to the obtained prices.

We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivatives contracts held. We recognize transfers between levels at the end of the reporting period for which the transfer has occurred. We recognized transfers out of Level 3 into Level 2 as a result of changes in tenure and market points of certain contracts in the amount of $1.0 million for the year ended December 31, 2012. There were no such transfers for the three and nine months ended September 30, 2013 and 2012.

Fair Value of Financial Instruments

The following table sets forth by level within the fair value hierarchy, our commodity derivative instruments and interest rate swap, included as part of Risk management assets and Risk management liabilities within the balance sheet, that were measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012 (in thousands):



	Carrying Amount			Estimated Fair Value
	Carrying Amount			Level 1		Level 2			Level 3		Total
Commodity derivative instruments, net
September 30, 2013	$	294		$	—	$	294		$	—	$	294
December 31, 2012	$	969		$	—	$	969		$	—	$	969
Interest rate swap
September 30, 2013	$	(472	)	$	—	$	(472	)	$	—	$	(472	)
December 31, 2012	$	—		$	—	$	—		$	—	$	—

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The premium paid to enter the weather derivative described in Note 6 "Derivatives", is included within Risk management assets on the balance sheet but is not included as part of the above table as it is recorded at amortized carrying cost, not fair value.

8. Property, Plant and Equipment

Property, plant and equipment, net, as of September 30, 2013 and December 31, 2012 were as follows (in thousands):



	Useful Life (in years)	September 30, 2013			December 31, 2012
Land	N/A	$	2,254		$	2,254
Construction in progress	N/A	3,308			5,053
Base gas	N/A	1,108			—
Buildings and improvements	4 to 40	1,664			1,432
Processing and treating plants	8 to 40	98,819			98,106
Pipelines	5 to 40	236,450			163,447
Compressors	4 to 20	11,278			8,957
Equipment	8 to 20	5,259			4,785
Computer software	5	2,566			1,950
Total property, plant and equipment		362,706			285,984
Accumulated depreciation		(82,190		)	(62,165		)
Property, plant and equipment, net		$	280,516		$	223,819

Of the gross property, plant and equipment balances at September 30, 2013 and December 31, 2012, $99.5 million and $26.1 million, respectively, were related to AlaTenn, Midla and HPGT, our FERC regulated interstate and intrastate assets.

Capitalized interest was less than $0.1 million for the three and nine months ended September 30, 2013.

Depreciation expense was $6.3 million and $18.5 million for the three and nine months ended September 30, 2013, respectively.

Asset Impairments

During the second quarter of 2013, management determined to change its commercial approach towards certain non-strategic gathering and processing assets. As a result, an asset impairment charge of $15.2 million was recorded in the three months ended June 30, 2013. These fair value measurements are based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimates are based on i) present value of estimated EBITDA, ii) an assumed discount rate of 10.0%, and iii) a decline in throughput volumes of 2.5% in 2013 and thereafter.

During the second quarter of 2013, the board of directors of our General Partner approved a plan to sell certain non-strategic gathering and processing assets which meet specific criteria, qualifying them as held for sale. As a result, certain gathering and processing assets were written down by $1.8 million to the estimated fair value less cost to sell. See Note 4 "Discontinued Operations".

Insurance proceeds

Involuntary conversions result from the loss of an asset because of some unforeseen event (e.g., destruction due to hurricanes). Some of these events are insurable, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. During the three and nine months ended September 30, 2013, we collected zero and $1.1 million, respectively, of nonrefundable cash proceeds from our insurance carrier. During the first quarter of 2013, $0.5 million of nonrefundable cash proceeds were recognized as an offset to property, plant and equipment write-downs of $0.1 million and presented as $0.4 million under the caption Gain (loss) on involuntary conversion of property, plant and equipment. During the second quarter of 2013, $0.6 million of nonrefundable cash proceeds were associated with business interruption insurance and recorded to Revenue in the condensed consolidated statement of operations.

9. Asset Retirement Obligations

We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis, in the period in which the liability is incurred. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO.

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Certain assets related to our transmission segment have regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These asset retirement obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transmission services will cease, and we do not believe that such demand will cease for the foreseeable future. A portion of our regulatory obligations is related to assets that we plan to take out of service.

The following table is a reconciliation of the asset retirement obligations (in thousands):



Asset retirement obligation at December 31, 2012	$	8,319
Obligations assumed	25,763
Accretion expense	358
Asset retirement obligation at September 30, 2013	$	34,440

We recorded accretion expense, which is included in Depreciation and accretion expense, of approximately $0.2 million and approximately $0.4 million in our consolidated statements of operations for each of the three and nine months ended September 30, 2013, respectively, and less than $0.1 million for the three and nine months ended September 30, 2012.

We are required to establish security against any potential secondary obligations relating to the abandonment of the certain transmission assets that may be imposed on the previous owner by applicable regulatory authorities. As such, we have a restricted cash account that is established, held, and maintained by a third party that amounts to $1.0 million and is presented in Other assets, net in our condensed consolidated balance sheet as of September 30, 2013.

10. Debt Obligations

Credit facility

As of December 31, 2012, the total leverage to EBITDA ratio (the "Consolidated Total Leverage Ratio"), one of the primary financial covenants that we were required to maintain under our credit facility, was limited to a maximum of 4.50 to 1.00. At December 31, 2012, our total indebtedness was approximately $130.9 million, which caused our total leverage to EBITDA ratio to be approximately 5.70 to 1.00. 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 ended 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 senior secured revolving 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 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 credit facility shall not exceed $150.0 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.

On September 30, 2013, we received $12.5 million from HPIP which was used to repay outstanding borrowings under the credit agreement. Please see Note 11 "Partners' Capital" for more details.

We were in compliance with the Consolidated Total Leverage Ratio test, which was 4.48 under our credit facility as of September 30, 2013, in accordance with the leverage covenants as modified in the Fourth Amendment to the credit facility executed on April 15, 2013. As of September 30, 2013, we had approximately $123.7 million of outstanding borrowings and approximately $39.3 million of available borrowing capacity. For the nine months ended September 30, 2013 and 2012, the weighted average interest rate on borrowings under our credit facility was approximately 4.50% and 4.09%, respectively.

See Note 18 "Liquidity" for further updates to our liquidity and long-term debt.

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Other debt

Other debt represents insurance premium financing in the original amounts of $3.3 million bearing interest at between 3.22% and 4.00% per annum, which is repayable in equal monthly installments of approximately $0.2 million through the fourth quarter of 2013.

Our outstanding borrowings at September 30, 2013 and December 31, 2012, respectively, were (in thousands):



	September 30, 2013		December 31, 2012
Revolving loan facility	$	121,035	$	128,285
Other debt	157		—
	121,192		128,285
Less: current portion	157		—
	$	121,035	$	128,285

At September 30, 2013 and December 31, 2012, letters of credit outstanding under the credit facility totaled $2.6 million.

In connection with our credit facility and amendments thereto, we incurred $5.8 million in debt issuance costs that are being amortized on a straight-line basis over the term of the credit facility.

11. Partners’ Capital and Convertible Preferred Units

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

Equity Restructuring

Effective August 9, 2013, we executed an equity restructuring agreement ("Equity Restructuring") with our General Partner and HPIP. As part of the Equity Restructuring, the Partnership's 4,526,066 subordinated units and previous incentive distribution rights (the “former IDRs,” all of which were owned by our General Partner, which is controlled by HPIP) were combined into and restructured as a new class of incentive distribution rights (the “new IDRs”). Upon the issuance of the new IDRs, the subordinated units and former IDRs were cancelled. The new IDRs are allocated 85.02% to HPIP and 14.98% to our General Partner. The new IDRs entitle the holders of our incentive distribution rights to receive 48% of any quarterly cash distributions from available cash after the Partnership's common unitholders have received the full minimum quarterly distribution ($0.4125 per unit) for each quarter plus any arrearages from prior quarters (of which there are currently none).

The Equity Restructuring also provided for the issuance of warrants to our General Partner to purchase up to 300,000 of our common units at an exercise price of $0.01 per common unit. These warrants are exercisable on the later of (i) 18 months from the equity restructuring completion date and (ii) the date that the volume weighted average trading price of our common units on the New York Stock Exchange exceeds $25.00 for 30 consecutive trading days. The warrants contain customary anti-dilution and other protections.

Series A Convertible Preferred Units

On April 15, 2013, the Partnership, our General Partner and AIM entered into the ArcLight Transactions with HPIP, pursuant to which HPIP (i) acquired 90% of our General Partner and all of our subordinated units from AIM Midstream Holdings and (ii)

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contributed certain midstream assets and $15.0 million in cash to us in exchange for 5,142,857 Series A Units issued by the Partnership. Of the $15.0 million cash consideration paid by HPIP, approximately $2.5 million was used to pay certain transaction expenses of HPIP, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's credit facility in connection with the Fourth Amendment. As a result of these transactions, which were also consummated on April 15, 2013, HPIP acquired both control of our General Partner and a majority of our outstanding limited partnership interests. On April 15, 2013, our General Partner entered into the Third Amended & Restated Agreement of Limited Partnership (the “Amended Partnership Agreement”) of the Partnership providing for the creation and designation of the rights, preferences, terms and conditions of the Series A Units.

The Series A Units receive distributions prior to distributions to Partnership common unitholders. Through October 1, 2014, the distributions to the Series A Unitholders are equal to $0.25 per unit and additional Series A Units in an amount equal to the cash portion of the distribution. Subsequent to that date, the distribution will be the greater of the distribution to be made to common unitholders or approximately $0.50 per unit. The Series A Units may be converted into common units on a one-to-one basis, subject to customary anti-dilutive adjustments, at the option of the unitholders on or any time after January 1, 2014.

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 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 $17.50 multiplied by the number of Series A Units owned by such holders, plus all accrued but unpaid distributions on such Series A Units.

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 Units to redeem all (but not less than all) of such holder's Series A Units for a price per Series A 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 Unit; or


•	an amount equal to the product of:

(i) the number of common units into which each Series A 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 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 Units without material abridgement.

Except as provided in the Amended Partnership Agreement, the Series A 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 Unit entitled to one vote for each common unit into which such Series A Unit is convertible.

The fair value of the Series A Units on April 15, 2013 was $17.50 per unit, or a total of $90.0 million and was issued by the Partnership in exchange for cash of approximately $12.5 million and net assets of $61.9 million contributed to the Partnership by our General Partner. The contribution of net assets of the High Point System was accounted for as a transaction between entities under common control whereby the High Point System was recorded at historical book value. As such, the value of the Series A Units in excess of the net assets contributed by our General Partner amounted to $15.6 million and was allocated pro-rata to our General Partner and existing limited partners' interest based on their ownership interests. The fair value measurement was based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimate was based on i) present value of estimated future contracted distributions, ii) an assumed discount rate of 18.0%, and iii) an assumed distribution growth rate of 1.0% in 2014 and thereafter.

The fair value of the additional Series A Units in an amount equal to the cash portion of the distribution was $21.15 per unit, or a total distribution of $1.6 million for the three months ended September 30, 2013. Primarily using the market and income approach, the fair value estimate was based on i) present value of estimated future contracted distributions, ii) an option value of $3.18 per unit using a Black-Scholes model, iii) an assumed discount rate of 10.0%, and iv) an assumed distribution growth rate of 1.0% in 2014 and thereafter.

The numbers of units outstanding as of September 30, 2013 and December 31, 2012, respectively, were as follows (in thousands):

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	September 30, 2013	December 31, 2012
Limited partner common units	4,705	4,639
Limited partner subordinated units	—	4,526
Series A Units	5,204	—
General partner units	185	185

Net Income (Loss) attributable to Limited and General Partner Units

Net income (loss) attributable to our General Partner and the limited partners (common and subordinated unit holders) is allocated in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to our General Partner. Basic net income per limited partner unit is computed based on the weighted average number of units outstanding during the period. Diluted net income per limited partner unit is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period. Unvested share-based payment awards that contain non-forfeitable rights to distributions (whether paid or unpaid) are classified as participating securities and are included in our computation of diluted net income per limited partner unit. There was no dilutive effect of unit based awards for the three and nine months ended September 30, 2013 and 2012.

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

The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of our General Partner, even though we make distributions on the basis of available cash and not earnings.

The following table is the calculation of net income (loss) per limited partner unit for the three and nine months ended September 30, 2013 and 2012, respectively (in thousands, with the exception of per unit amounts):

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	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Net (loss) income from continuing operations	$	(2,510	)	$	(4,014	)	$	(25,561	)	$	(102	)
Net income attributable to noncontrolling interests	190			249			533			249
Net loss from continuing operations attributable to the Partnership	$	(2,700	)	$	(4,263	)	$	(26,094	)	$	(351	)
Less:
Declared cash distributions on Series A Units	1,301			—			2,375			—
Declared PIK distributions on Series A Units	1,572			—			2,912			—
Fair value of Series A Units in excess of value of contributed High Point System	—			—			15,612			—
General partner's distribution	80			80			240			241
General partner's share in undistributed loss	(170		)	(166		)	(1,074		)	(248		)
Net loss from continuing operations available to limited partners	$	(5,483	)	$	(4,177	)	$	(46,159	)	$	(344	)

Net loss attributable to the Partnership	$	(2,556	)	$	(4,275	)	$	(27,746	)	$	(257	)
Less:
Declared cash distributions on Series A Units	1,301			—			2,375			—
Declared PIK distributions on Series A Units	1,572			—			2,912			—
Fair value of Series A Units in excess of value of contributed High Point System	—			—			15,612			—
General partner's distribution	80			80			240			241
General partner's share in undistributed loss	(167		)	(166		)	(1,102		)	(246		)
Net loss available to limited partners	$	(5,342	)	$	(4,189	)	$	(47,783	)	$	(252	)

Weighted average number of units used in computation of limited partners’ net (loss) income per unit (basic and diluted)	6,663			9,108			8,334			9,103

Limited partners’ net loss from continuing operations per unit (basic and diluted)	$	(0.82	)	$	(0.46	)	$	(5.54	)	$	(0.04	)
Limited partners’ net loss per unit (basic and diluted)	$	(0.80	)	$	(0.46	)	$	(5.73	)	$	(0.03	)

Distributions

We made distributions of $16.7 million and $12.1 million in the nine months ended September 30, 2013 and 2012, respectively. We made no distributions in respect of our General Partner’s incentive distribution rights during 2013 or 2012. We depend on our 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.

For the Series A Unit distributions as of September 30, 2013, we have accrued $1.3 million for the cash portion of the distribution and $1.6 million for the paid-in-kind Series A Units. The distributions will be made in the fourth quarter of 2013.

12. Long-Term Incentive Plan

Our General Partner manages our operations and activities and employs the personnel who provide support to our operations. On November 2, 2009, the board of directors of our General Partner adopted a long-term incentive plan (“LTIP”) for its employees, consultants and directors who perform services for it or its affiliates. On May 25, 2010, the board of directors of our General Partner adopted an amended and restated LTIP. On July 11, 2012, the board of directors of our General Partner adopted a second amended and restated LTIP that effectively increased available awards by 871,750 units. At September 30, 2013 and December 31, 2012, 846,203 and 920,193 units, respectively, were available for future grant under the LTIP, giving retroactive treatment to the reverse unit split in connection with our recapitalization described in our Annual Report.

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Ownership in the awards is subject to forfeiture until the vesting date. The LTIP is administered by the Compensation Committee of the board of directors of our General Partner. The board of directors of our General Partner, at its discretion, may elect to settle such vested phantom units with a number of units equivalent to the fair market value at the date of vesting in lieu of cash. Although, our General Partner has the option to settle in cash upon the vesting of phantom units, our General Partner does not currently intend to settle these awards in cash. Although other types of awards are contemplated under the LTIP, all currently outstanding awards are phantom units without distribution equivalent rights ("DERs"). Generally, grants issued under the LTIP vest in increments of 25% on each of the first four anniversary dates of the date of the grant and do not contain any other restrictive conditions related to vesting other than continued employment.

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



	Three Months Ended				Nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
Outstanding at beginning of period	96,733		172,551		90,938		162,860
Granted	28,042		—		108,430		34,560
Forfeited	(893	)	(12,517	)	(13,320	)	(12,517	)
Vested	(24,482	)	—		(86,648	)	(24,869	)
Outstanding at end of period	99,400		160,034		99,400		160,034
Fair value per unit	$13.36 to $21.89		$14.70 to $21.40		$13.36 to $21.89		$14.70 to $21.40

The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our units at the grant date. Compensation costs related to these awards, including amortization, for the three months ended September 30, 2013 and 2012 was $0.4 million and $0.5 million, respectively, and for the nine months ended September 30, 2013 and 2012 was $1.8 million and $1.3 million, respectively, which is classified as equity compensation expense in the condensed consolidated statements of operations and the non-cash portion in partners’ capital on the condensed consolidated balance sheets.

The total fair value of vested units at the time of vesting was $1.6 million and $0.5 million for the nine months ended September 30, 2013 and 2012, respectively.

The total compensation cost related to unvested awards not yet recognized at September 30, 2013 and 2012 was $1.1 million and $2.1 million, respectively, and the weighted average period over which this cost is expected to be recognized as of September 30, 2013 is approximately 1.6 years.

13. Post-Employment Benefits

We sponsor a contributory post-retirement plan that provides medical, dental and life insurance benefits for qualifying U.S. retired employees (referred to as the “OPEB Plan”).

The following table summarizes the components of net periodic benefit recognized in the condensed consolidated statements of operations (in thousands):



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Service cost	$	1		$	1		$	3		3
Interest cost	4			4			12			12
Expected return on plan assets	(17		)	(16		)	(51		)	(49		)
Amortization of net gain	(6		)	(9		)	(18		)	(27		)
Net periodic benefit	$	(18	)	$	(20	)	$	(54	)	$	(61	)

Future contributions to the Plans

We expect to make contributions to the OPEB Plan for the year ended December 31, 2013 of $0.1 million.

14. Commitments and Contingencies

Legal proceedings

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On September 5, 2013, HPIP, our General Partner and the Partnership were named as defendants in an action filed by AIM challenging the Equity Restructuring. AIM Midstream Holdings, LLC v. High Point Infrastructure Partners, LLC, American Midstream GP, LLC and American Midstream Partners, LP (Civil Action No. 8803-VCP) was filed in the Court of Chancery of the State of Delaware. Among claims against the other parties to the litigation, the action asserts a claim of tortuous interference with contract against the Partnership and seeks either rescission of the Equity Restructuring Agreement or, in the alternative, monetary damages. While we cannot predict the ultimate outcome of this litigation, we do not believe it will be material to our operations or financial results.

Environmental matters

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

Commitments and contractual obligations

Future non-cancelable commitments related to certain contractual obligations as of September 30, 2013 are presented below (in thousands):



	Payments Due by Period
	Total		2013		2014		2015		2016		2017		Thereafter
Operating leases and service contracts (a)	$	4,282	$	154	$	793	$	762	$	531	$	506	$	1,536
Asset retirement obligations	34,440		—		—		—		7,867		—		26,573
Total	$	38,722	$	154	$	793	$	762	$	8,398	$	506	$	28,109

(a) Operating leases and service contracts have been reduced by total minimum sublease rentals of $0.2 million due in the future under non-cancelable subleases.

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Operating leases	$	357	$	254	$	841	$	692
Asset retirement obligation	191		10		358		23
	$	548	$	264	$	1,199	$	715

15. Related-Party Transactions

Employees of our General Partner are assigned to work for us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by our General Partner to American Midstream, LLC, which, in turn, charges the appropriate subsidiary. Our General Partner does not record any profit or margin for the administrative and operational services charged to us. During the three and nine months ended September 30, 2013, administrative and operational services expenses of $3.3 million and $10.3 million, respectively, were charged to us by our General Partner. During the three and nine months ended September 30, 2012, administrative and operational services expenses of $3.1 million and $9.3 million, respectively, were charged to us by our General Partner. For the three and nine months ended September 30, 2013, our General Partner incurred approximately $0.2 million and $0.6 million, respectively, of costs associated with certain business development activities. If the business development activities result in a project that will be pursued and funded by the Partnership, we will reimburse our General Partner for the business development costs related to that project. For the three and nine months ended September 30, 2013, we incurred business development costs of approximately $0.9 million associated with projects led by an affiliate of our General Partner. We expect to be reimbursed by this affiliate of our General Partner for the business development costs related to those projects.

16. Reporting Segments

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

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Gathering and Processing

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

Transmission

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

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

The contribution of the High Point System, which occurred concurrently with HPIP's acquisition of 90% of our General Partner, is presented within our Transmission Segment. The following tables set forth our segment information for the three and nine months ended September 30, 2013 and 2012 (in thousands):



	Three months ended September 30,
	2013								2012
	Gathering and Processing			Transmission		Total			Gathering and Processing			Transmission		Total
Revenue	$	48,873		$	27,704	$	76,577		$	41,637		$	12,710	$	54,347
Loss on commodity derivatives, net	(499		)	—		(499		)	(946		)	—		(946		)
Total revenue	48,374			27,704		76,078			40,691			12,710		53,401
Operating expenses:
Purchases of natural gas, NGLs and condensate	38,162			19,811		57,973			32,105			9,260		41,365
Direct operating expenses	3,720			3,994		7,714			3,567			1,762		5,329
Selling, general and administrative expenses						3,969								3,246
Equity compensation expense						392								474
Depreciation and accretion expense						6,458								5,504
Total operating expenses						76,506								55,918
Gain on sale of assets, net						—								4
Operating loss						(428		)						(2,513		)
Interest and other expense						(2,082		)						(1,501		)
Net loss from continuing operations						(2,510		)						(4,014		)
Gain (loss) on discontinued operations (a)						144								(12		)
Net loss						(2,366		)						(4,026		)
Less: Net income attributable to noncontrolling interests						190								249
Net loss attributable to the Partnership						$	(2,556	)						$	(4,275	)
Segment gross margin (b)	$	10,688		$	7,864	$	18,552		$	10,310		$	2,668	$	12,978

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	Nine months ended September 30,
	2013							2012
	Gathering and Processing		Transmission		Total			Gathering and Processing		Transmission		Total
Revenue	$	144,658	$	65,532	$	210,190		$	101,307	$	37,116	$	138,423
Gain on commodity derivatives, net	110		—		110			3,157		—		3,157
Total revenue	144,768		65,532		210,300			104,464		37,116		141,580
Operating expenses:
Purchases of natural gas, NGLs and condensate	116,568		46,103		162,671			74,775		25,300		100,075
Direct operating expenses	10,694		8,943		19,637			7,531		4,019		11,550
Selling, general and administrative expenses					11,982							10,101
Equity compensation expense					1,877							1,272
Depreciation and accretion expense					18,802							15,722
Total operating expenses					214,969							138,720
Gain on involuntary conversion of property, plant and equipment					343							—
Gain on sale of assets, net					—							121
Loss on impairment of property, plant and equipment					(15,232		)					—
Operating (loss) income					(19,558		)					2,981
Interest and other expense					(6,003		)					(3,083		)
Net loss from continuing operations					(25,561		)					(102		)
(Loss) gain on discontinued operations (a)					(1,652		)					94
Net loss					(27,213		)					(8		)
Less: Net income attributable to noncontrolling interests					533							249
Net loss attributable to the Partnership					$	(27,746	)					$	(257	)
Segment gross margin (b)	$	28,454	$	19,296	$	47,750		$	27,321	$	9,472	$	36,793


(a)	Gain (loss) on discontinued operations impacts our Gathering and Processing Segment.

(b)

Segment gross margin for our Gathering and Processing Segment consists of revenue, realized gain (loss) on commodity derivatives less construction, operating and maintenance agreement (“COMA”) income, less purchases of natural gas, NGLs and condensate. Segment gross margin for our Transmission Segment consists of revenue, less COMA income, less purchases of natural gas. Gross margin consists of the sum of the segment gross margin amounts for each of these segments. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow from operations as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. Effective October 1, 2012, we changed our segment gross margin measure to exclude COMA income. For the three months ended September 30, 2013 and 2012, $0.3 million and less than $0.1 million, respectively in COMA income was excluded from our Gathering and Processing Segment gross margin and less than $0.1 million and $0.8 million, respectively, in COMA income was excluded from our Transmission Segment gross margin. For the nine months ended September 30, 2013 and 2012, $0.4 million and $0.6 million, respectively, in COMA income was excluded from our Gathering and Processing Segment gross margin and $0.1 million and $2.3 million, respectively, in COMA income was excluded from our Transmission Segment gross margin.

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

17. Subsidiary Guarantors

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The Partnership has filed a registration statement on Form S-3 with the SEC to register, among other securities, the future issuance of debt securities. The subsidiaries of the Partnership (the "Subsidiaries") are co-registrants with the Partnership for the purpose of issuing guarantees of debt securities by one or more of the Subsidiaries (other than American Midstream Finance Corporation, a 100% owned subsidiary of the Partnership whose sole purpose is to act as co-issuer of such debt securities). The financial position and operations of the co-issuer are minor and therefore have been included with the Parent's financial information. As of June 30, 2012, the Subsidiaries were 100% owned by the Partnership and any guarantees by the Subsidiaries will be full and unconditional. Beginning July 1, 2012, the Partnership has had an investment in the non-guarantor subsidiaries equal to a 87.4% undivided interest in its Chatom System. The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. In the event that more than one of the Subsidiaries provides guarantees of any debt securities issued by the Partnership, such guarantees will constitute joint and several obligations. None of the assets of the Partnership or the Subsidiaries represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended. For purposes of the following unaudited condensed consolidating financial information, the Partnership's investments in its Subsidiaries and the guarantor subsidiaries' investment in its 87.4% undivided interest in the Chatom System are presented in accordance with the equity method of accounting. The financial information may not necessarily be indicative of the financial position, results of operations, or cash flows had the subsidiary guarantors operated as independent entities. Condensed consolidating financial information for the Partnership, its combined guarantor subsidiaries and non-guarantor subsidiary as of September 30, 2013 and December 31, 2012 and for the three and nine months ended September 30, 2013 and 2012 are as follows (in thousands):

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	Condensed Consolidating Balance Sheet
	September 30, 2013
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiary		Consolidating Adjustments			Consolidated
Assets
Current assets
Cash and cash equivalents	$	1	$	1,075	$	—	$	—		$	1,076
Accounts receivable	—		3,490		1,502		—			4,992
Unbilled revenue	—		21,278		3,649		—			24,927
Risk management assets	—		1,050		—		—			1,050
Other current assets	—		4,100		473		—			4,573
Total current assets	1		30,993		5,624		—			36,618
Property, plant and equipment, net	—		221,725		58,791		—			280,516
Noncurrent assets held for sale, net	—		874		—		—			874
Investment in subsidiaries	127,736		53,607		—		(181,343		)	—
Other assets, net	—		6,202		—		—			6,202
Total assets	$	127,737	$	313,401	$	64,415	$	(181,343	)	$	324,210

Liabilities, Equity and Partners’ Capital
Current liabilities
Accounts payable	$	—	$	1,385	$	210	$	—		$	1,595
Accrued gas purchases	—		14,693		2,614		—			17,307
Accrued expenses and other current liabilities	856		13,737		116		—			14,709
Risk management liabilities	—		349		—		—			349
Current portion of long-term debt	—		157		—		—			157
Total current liabilities	856		30,321		2,940		—			34,117
Risk management liabilities	—		122		—		—			122
Assets retirement obligations	—		33,972		468		—			34,440
Other liabilities	—		215		—		—			215
Long-term debt	—		121,035		—		—			121,035
Total liabilities	856		185,665		3,408		—			189,929
Convertible preferred units	92,912		—		—		—			92,912
Total partners' capital	33,969		127,736		53,607		(181,343		)	33,969
Noncontrolling interest	—		—		7,400		—			7,400
Total equity and partners' capital	33,969		127,736		61,007		(181,343		)	41,369
Total liabilities, equity and partners' capital	$	127,737	$	313,401	$	64,415	$	(181,343	)	$	324,210

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	Condensed Consolidating Balance Sheet
	December 31, 2012
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiary		Consolidating Adjustments			Consolidated
Assets
Current assets
Cash and cash equivalents	$	1	$	575	$	—	$	—		$	576
Accounts receivable	—		1,612		346		—			1,958
Unbilled revenue	—		18,102		3,410		—			21,512
Risk management assets	—		969		—		—			969
Other current assets	—		2,967		259		—			3,226
Total current assets	1		24,225		4,015		—			28,241
Property, plant and equipment, net	—		165,001		58,818		—			223,819
Investment in subsidiaries	80,164		51,613		—		(131,777		)	—
Other assets, net	—		4,636		—		—			4,636
Total assets	$	80,165	$	245,475	$	62,833	$	(131,777	)	$	256,696

Liabilities, Equity and Partners’ Capital
Current liabilities
Accounts payable	$	—	$	5,100	$	427	$	—		$	5,527
Accrued gas purchases	—		14,606		2,428		—			17,034
Accrued expenses and other current liabilities	—		9,150		469		—			9,619
Total current liabilities	—		28,856		3,324		—			32,180
Asset retirement obligations	—		7,861		458		—			8,319
Other liabilities	—		309		—		—			309
Long-term debt	—		128,285		—		—			128,285
Total liabilities	—		165,311		3,782		—			169,093
Total partners' capital	80,165		80,164		51,613		(131,777		)	80,165
Noncontrolling interest	—		—		7,438		—			7,438
Total equity and partners' capital	80,165		80,164		59,051		(131,777		)	87,603
Total liabilities, equity and partners' capital	$	80,165	$	245,475	$	62,833	$	(131,777	)	$	256,696

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	Condensed Consolidating Statements of Operations
	Three months ended September 30, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Consolidating Adjustments			Consolidated
Revenue	$	—		$	62,905		$	14,562	$	(890	)	$	76,577
Loss on commodity derivatives, net	—			(499		)	—		—			(499		)
Total revenue	—			62,406			14,562		(890		)	76,078
Operating expenses:
Purchases of natural gas, NGLs and condensate	—			47,361			11,502		(890		)	57,973
Direct operating expenses	—			6,508			1,206		—			7,714
Selling, general and administrative expenses	—			3,969			—		—			3,969
Equity compensation expense	—			392			—		—			392
Depreciation and accretion expense	—			6,043			415		—			6,458
Total operating expenses	—			64,273			13,123		(890		)	76,506
Operating (loss) income	—			(1,867		)	1,439		—			(428		)
Other income (expense):
(Loss) earnings from consolidated affiliates	(2,556		)	1,249			—		1,307			—
Interest expense	—			(2,082		)	—		—			(2,082		)
Net (loss) income from continuing operations	(2,556		)	(2,700		)	1,439		1,307			(2,510		)
Discontinued operations	—			144			—		—			144
Net (loss) income	(2,556		)	(2,556		)	1,439		1,307			(2,366		)
Net income attributable to noncontrolling interests	—			—			190		—			190
Net (loss) income attributable to the Partnership	$	(2,556	)	$	(2,556	)	$	1,249	$	1,307		$	(2,556	)



	Condensed Consolidating Statements of Operations
	Three months ended September 30, 2012
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Consolidating Adjustments			Consolidated
Revenue	$	—		$	39,346		$	15,371	$	(370	)	$	54,347
Loss on commodity derivatives, net	—			(946		)	—		—			(946		)
Total revenue	—			38,400			15,371		(370		)	53,401
Operating expenses:
Purchases of natural gas, NGLs and condensate	—			30,194			11,541		(370		)	41,365
Direct operating expenses	—			4,351			978		—			5,329
Selling, general and administrative expenses	—			3,150			96		—			3,246
Equity compensation expense	—			474			—		—			474
Depreciation and accretion expense	—			5,102			402		—			5,504
Total operating expenses	—			43,271			13,017		(370		)	55,918
Gain on sale of assets, net	—			4			—		—			4
Operating (loss) income	—			(4,867		)	2,354		—			(2,513		)
Other income (expense):
(Loss) earnings from consolidated affiliates	(4,275		)	2,105			—		2,170			—
Interest expense	—			(1,501		)	—		—			(1,501		)
Net (loss) income from continuing operations	(4,275		)	(4,263		)	2,354		2,170			(4,014		)
Discontinued operations	—			(12		)	—		—			(12		)
Net (loss) income	(4,275		)	(4,275		)	2,354		2,170			(4,026		)
Net income attributable to noncontrolling interests	—			—			249		—			249
Net (loss) income attributable to the Partnership	$	(4,275	)	$	(4,275	)	$	2,105	$	2,170		$	(4,275	)

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	Condensed Consolidating Statements of Operations
	Nine months ended September 30, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Consolidating Adjustments			Consolidated
Revenue	$	—		$	172,733		$	41,818	$	(4,361	)	$	210,190
Gains on commodity derivatives, net	—			110			—		—			110
Total revenue	—			172,843			41,818		(4,361		)	210,300
Operating expenses:
Purchases of natural gas, NGLs and condensate	—			134,041			32,991		(4,361		)	162,671
Direct operating expenses	—			16,229			3,408		—			19,637
Selling, general and administrative expenses	—			11,982			—		—			11,982
Equity compensation expense	—			1,877			—		—			1,877
Depreciation and accretion expense	—			17,559			1,243		—			18,802
Total operating expenses	—			181,688			37,642		(4,361		)	214,969
Gain on involuntary conversion of property, plant and equipment	—			343			—		—			343
Loss on impairment of property, plant and equipment	—			(15,232		)	—		—			(15,232		)
Operating (loss) income	—			(23,734		)	4,176		—			(19,558		)
Other income (expense):
(Loss) earnings from consolidated affiliates	(27,746		)	3,643			—		24,103			—
Interest expense	—			(6,003		)	—		—			(6,003		)
Net (loss) income from continuing operations	(27,746		)	(26,094		)	4,176		24,103			(25,561		)
Discontinued operations	—			(1,652		)	—		—			(1,652		)
Net (loss) income	(27,746		)	(27,746		)	4,176		24,103			(27,213		)
Net income attributable to noncontrolling interests	—			—			533		—			533
Net (loss) income attributable to the Partnership	$	(27,746	)	$	(27,746	)	$	3,643	$	24,103		$	(27,746	)



	Condensed Consolidating Statements of Operations
	Nine months ended September 30, 2012
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Consolidating Adjustments			Consolidated
Revenue	$	—		$	123,422		$	15,371	$	(370	)	$	138,423
Gain on commodity derivatives, net	—			3,157			—		—			3,157
Total revenue	—			126,579			15,371		(370		)	141,580
Operating expenses:
Purchases of natural gas, NGLs and condensate	—			88,904			11,541		(370		)	100,075
Direct operating expenses	—			10,572			978		—			11,550
Selling, general and administrative expenses	—			10,005			96		—			10,101
Equity compensation expense	—			1,272			—		—			1,272
Depreciation and accretion expense	—			15,320			402		—			15,722
Total operating expenses	—			126,073			13,017		(370		)	138,720
Gain on sale of assets, net	—			121			—		—			121
Operating income	—			627			2,354		—			2,981
Other income (expense):
(Loss) earnings from consolidated affiliates	(257		)	2,105			—		(1,848		)	—
Interest expense	—			(3,083		)	—		—			(3,083		)
Net (loss) income from continuing operations	(257		)	(351		)	2,354		(1,848		)	(102		)
Discontinued operations	—			94			—		—			94
Net (loss) income	(257		)	(257		)	2,354		(1,848		)	(8		)
Net income attributable to noncontrolling interests	—			—			249		—			249
Net (loss) income attributable to the Partnership	$	(257	)	$	(257	)	$	2,105	$	(1,848	)	$	(257	)

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	Condensed Consolidating Statements of Comprehensive Income
	Three months ended September 30, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Consolidating Adjustments		Consolidated
Net (loss) income	$	(2,556	)	$	(2,556	)	$	1,439	$	1,307	$	(2,366	)
Unrealized loss on post retirement benefit plan assets and liabilities	(34		)	(34		)	—		34		(34		)
Comprehensive (loss) income	(2,590		)	(2,590		)	1,439		1,341		(2,400		)
Less: Comprehensive income attributable to noncontrolling interests	—			—			190		—		190
Comprehensive (loss) income attributable to the Partnership	$	(2,590	)	$	(2,590	)	$	1,249	$	1,341	$	(2,590	)



	Condensed Consolidating Statements of Comprehensive Income
	Three months ended September 30, 2012
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Consolidating Adjustments			Consolidated
Net (loss) income	$	(4,275	)	$	(4,275	)	$	2,354	$	2,170		$	(4,026	)
Unrealized gain on post retirement benefit plan assets and liabilities	23			23			—		(23		)	23
Comprehensive (loss) income	(4,252		)	(4,252		)	2,354		2,147			(4,003		)
Less: Comprehensive income attributable to noncontrolling interests	—			—			249		—			249
Comprehensive (loss) income attributable to the Partnership	$	(4,252	)	$	(4,252	)	$	2,105	$	2,147		$	(4,252	)



	Condensed Consolidating Statements of Comprehensive Income
	Nine months ended September 30, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Consolidating Adjustments		Consolidated
Net (loss) income	$	(27,746	)	$	(27,746	)	$	4,176	$	24,103	$	(27,213	)
Unrealized loss on post retirement benefit plan assets and liabilities	(90		)	(90		)	—		90		(90		)
Comprehensive (loss) income	(27,836		)	(27,836		)	4,176		24,193		(27,303		)
Less: Comprehensive income attributable to noncontrolling interests	—			—			533		—		533
Comprehensive (loss) income attributable to the Partnership	$	(27,836	)	$	(27,836	)	$	3,643	$	24,193	$	(27,836	)



	Condensed Consolidating Statements of Comprehensive Income
	Nine months ended September 30, 2012
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Consolidating Adjustments			Consolidated
Net (loss) income	$	(257	)	$	(257	)	$	2,354	$	(1,848	)	$	(8	)
Unrealized gain on post retirement benefit plan assets and liabilities	40			40			—		(40		)	40
Comprehensive (loss) income	(217		)	(217		)	2,354		(1,888		)	32
Less: Comprehensive income attributable to noncontrolling interests	—			—			249		—			249
Comprehensive (loss) income attributable to the Partnership	$	(217	)	$	(217	)	$	2,105	$	(1,888	)	$	(217	)

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	Condensed Consolidating Statements of Cash Flows
	Nine months ended September 30, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Consolidating Adjustments			Consolidated
Net cash provided by operating activities	$	—		$	8,642		$	4,174		$	—		$	12,816
Cash flows from investing activities
Additions to property, plant and equipment	—			(16,766		)	(1		)	—			(16,767		)
Proceeds from property damage insurance recoveries	—			482			—			—			482
Net contributions from affiliates	12,458			—			—			(12,458		)	—
Net distributions to affiliates	(26,893		)	—			—			26,893			—
Net cash used in investing activities	(14,435		)	(16,284		)	(1		)	14,435			(16,285		)
Cash flows from financing activities
Net contributions from affiliates	—			26,893			—			(26,893		)	—
Net distributions to affiliates	—			(8,856		)	(3,602		)	12,458			—
Unit holder contributions	12,500			—			—			—			12,500
Unit holder distributions	(12,458		)	—			—			—			(12,458		)
Issuance of Series A convertible preferred units	14,393			—			—			—			14,393
Net distributions to noncontrolling interest owners	—			—			(571		)	—			(571		)
LTIP tax netting unit repurchase	—			(400		)	—			—			(400		)
Payments for deferred debt issuance costs	—			(1,509		)	—			—			(1,509		)
Payments on other debt	—			(2,231		)	—			—			(2,231		)
Borrowings on other debt	—			1,495			—			—			1,495
Payments on long-term debt	—			(99,821		)	—			—			(99,821		)
Borrowings on long-term debt	—			92,571			—			—			92,571
Net cash provided by (used in) financing activities	14,435			8,142			(4,173		)	(14,435		)	3,969
Net increase in cash and cash equivalents	—			500			—			—			500
Cash and cash equivalents
Beginning of period	1			575			—			—			576
End of period	$	1		$	1,075		$	—		$	—		$	1,076
Supplemental cash flow information
Interest payments	$	—		$	4,933		$	—		$	—		$	4,933
Supplemental non-cash information
Decrease in accrued property, plant and equipment	$	—		$	(6,169	)	$	—		$	—		$	(6,169	)
Net assets contributed in exchange for the issuance of Series A convertible preferred units (see Note 3)	$	59,995		$	—		$	—		$	—		$	59,995
Fair value of Series A Units in excess of net assets received	$	15,612		$	—		$	—		$	—		$	15,612
Accrued unitholder distribution for Series A Units	$	2,912		$	—		$	—		$	—		$	2,912

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	Revised Condensed Consolidating Statements of Cash Flows
	Nine months ended September 30, 2012
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Consolidating Adjustments			Consolidated
Net cash provided by operating activities	$	—		$	14,122		$	2,354		—			16,476
Cash flows from investing activities
Cost of acquisition, net of cash acquired	—			(51,377		)	—			—			(51,377		)
Additions to property, plant and equipment	—			(4,196		)	(269		)	—			(4,465		)
Proceeds from disposal of property, plant and equipment	—			126			—			—			126
Net contributions from affiliates	12,050			—			—			(12,050		)	—
Net distributions to affiliates	(13		)	—			—			13			—
Net cash provided by (used in) investing activities	12,037			(55,447		)	(269		)	(12,037		)	(55,716		)
Cash flows from financing activities
Net contributions from affiliates	—			13			—			(13		)	—
Net distributions to affiliates	—			(10,214		)	(1,836		)	12,050			—
Unit holder contributions	13			—			—			—			13
Unit holder distributions	(12,050		)	—			—			—			(12,050		)
Net distributions to noncontrolling interest owners	—			—			(249		)	—			(249		)
LTIP tax netting unit repurchase	—			(88		)	—			—			(88		)
Payments for deferred debt issuance costs	—			(1,140		)	—			—			(1,140		)
Payments on long-term debt	—			(42,310		)	—			—			(42,310		)
Borrowings on long-term debt	—			94,690			—			—			94,690
Net cash (used in) provided by financing activities	$	(12,037	)	$	40,951		$	(2,085	)	$	12,037		$	38,866
Net decrease in cash and cash equivalents	—			(374		)	—			—			(374		)
Cash and cash equivalents
Beginning of period	1			870			—			—			871
End of period	$	1		$	496		$	—		$	—		$	497
Supplemental cash flow information
Interest payments	$	—		$	1,894		—			—			1,894
Supplemental non-cash information
Increase in accrued property, plant and equipment	$	—		$	808		$	—		$	—		$	808

We corrected a classification error in the previously presented subsidiary guarantor statements of cash flows for the nine months ended September 30, 2012 in this Form 10-Q related to net distributions to affiliates within Guarantor Subsidiaries and Non-Guarantor Subsidiary of $10.2 million and $1.8 million, respectively, presented in net cash used in investing activities which is now presented as net distributions to affiliates within Guarantor Subsidiaries and Non-Guarantor Subsidiary of $10.2 million and $1.8 million, respectively in net cash provided by financing activities. This classification error has no impact to the consolidated financial statements.

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18. Liquidity

We are required to comply with certain financial covenants and ratios in our credit facility. As of December 31, 2012, the Consolidated Total Leverage Ratio, one of the primary financial covenants that we are required to maintain under our credit facility, was not to exceed 4.50 times. At December 31, 2012, our total indebtedness was approximately $130.9 million, which caused our Consolidated Total Leverage Ratio to be approximately 5.70 to 1.00. As a result, on December 26, 2012, the Partnership entered into 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 ended December 31, 2012 and for one month thereafter. The Third Amendment also requires 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 senior secured revolving 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 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 credit facility shall not exceed $150.0 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.

On April 15, 2013, we repaid approximately $12.5 million in outstanding borrowings under the credit agreement and entered into the Fourth Amendment in connection with the ArcLight Transaction. 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. After the Fourth Amendment and until the quarter ended June 30, 2013, we were not required to meet a Consolidated Total Leverage Ratio under our credit facility.

On September 30, 2013, we received $12.5 million from HPIP which was used to repay outstanding borrowings under the credit agreement. Please see Note 11 "Partners' Capital" for more details.

As of October 31, 2013, we had approximately $129.2 million of outstanding borrowings and approximately $33.7 million of available borrowing capacity.

The Fourth Amendment provided for the following:


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


•	Commencing on October 1, 2013, the aggregate commitments of the lenders under the credit agreement will be reduced to $175 million if an equity contribution to the Partnership of $12.5 million that is used to repay borrowings under the credit facility by October 1, 2013 (which occurred on September 30, 2013);


•	The total outstanding borrowings under the credit agreement are limited to $175 million until such equity contribution and debt repayment has occurred (which occurred on September 30, 2013), at which time the maximum permitted borrowings under the 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 1.50% to 3.75%;


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


•	The definition of Consolidated EBITDA (the consolidated EBITDA for the quarters ended 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 System 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.

•

During the period that commenced with the quarter ended March 31, 2013 and that ends with the quarter ended December 31, 2013, unless the Partnership has permanently canceled at least 20% of the number of subordinated units outstanding on April 15, 2013 (which occurred through the Equity Restructuring), the Partnership must reduce any quarterly cash distribution on either its subordinated units or Series A 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:

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Fiscal Quarter Ended	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 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.

The Partnership believes that the consummation of the ArcLight Transactions and Equity Restructuring will allow it to comply with the Consolidated Total Leverage to EBITDA ratio in the Fourth Amendment. However, while we were in compliance with financial covenants of the Fourth Amendment as of September 30, 2013, no assurances can be given that the Partnership's future results of operations will allow us to comply with financial covenants of the Fourth Amendment. If we are not able to generate sufficient cash flows from operations to comply with the financial covenants in the Fourth Amendment and we are not able enter into an agreement to refinance or obtain covenant default waivers, then the outstanding balance under our credit facility could become due and payable upon acceleration by the lenders in our banking group and other agreements with cross-default provisions, if any, could become due. In addition, failure to comply with any of the covenants under our Fourth Amendment could adversely affect our ability to fund ongoing operations and growth capital requirements as well as our ability to pay distributions to our unitholders.

19. Subsequent Events

Distribution

On October 25, 2013, we announced a distribution of $0.4525 per unit for the quarter ended September 30, 2013, or $1.81 per unit on an annualized basis, payable on November 14, 2013 to unitholders of record on November 7, 2013.

Amendment to Partnership Agreement

Effective as of October 28, 2013, we entered into the First Amendment to the Fourth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP (“Fourth Amended and Restated Partnership Agreement”) to clarify that only those Unitholders holding Common Units (and not those Unitholders holding Series A Preferred Units) are entitled to receive a distribution of remaining Available Cash from Operating Surplus pursuant to Section 6.4(b)(iii)(C) of Fourth Amended and Restated Partnership Agreement (as each term is defined in the Fourth Amended and Restated Partnership Agreement).

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report and the audited consolidated financial statements and notes thereto and management’s discussion and analysis of financial condition and results of operations as of and for the year ended December 31, 2012 included in i) our Annual Report on Form 10-K (“Annual Report”) that was filed with the SEC on April 16, 2013 and ii) Exhibit 99.1 to our Current Report on Form 8-K that was filed with the SEC on October 1, 2013. This discussion contains forward-looking statements that reflect management’s current views with respect to future events and financial performance. 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.”

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”. 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” and elsewhere in this Quarterly Report, the Annual Report and the following:


•	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 weather, 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 existing and recently acquired 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;


•	our ability to comply with the covenants in our credit facility; 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 Quarterly 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” and elsewhere in this Quarterly Report and our Annual Report. The forward-looking statements in this report speak as of the filing date of this report. 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.

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Overview

We are a growth-oriented Delaware limited partnership that was formed in August 2009 to own, operate, develop and acquire a diversified portfolio of midstream energy assets. We are engaged in the business of gathering, treating, processing, fractionating and transporting natural gas through our ownership and operation of eleven gathering systems, four processing facilities, three interstate pipelines and five 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 2,100 miles of pipelines that gather and transport over 1 Bcf/d of natural gas.

Significant financial highlights and challenges during the three months ended September 30, 2013, include the following:


•	We completed the Equity Restructuring (as described below);


•	We distributed $3.7 million to our unitholders or $0.4325 per unit, net of $0.4 million of distribution foregone by our General Partner for the second quarter of 2013 during the three months ended September 30, 2013;


•	For the three months ended September 30, 2013, gross margin increased to $18.6 million or 43% compared to the same period in 2012; and


•	On September 30, 2013, we received approximately $12.5 million from HPIP which was used to repay outstanding borrowings under the credit agreement in connection with the Equity Restructuring.

Significant operational highlights and challenges during the three months ended September 30, 2013, include the following:


•	Throughput attributable to the Partnership totaled 1,002.4 MMcf/d for the third quarter of 2013 representing a 48.9% increase compared to the same period in 2012; and


•	Average gross NGL production totaled 49.5 Mgal/d for the third quarter of 2013 representing a 11.6% decrease compared to the same period in 2012.

Recent Developments

On April 15, 2013, the Partnership, our General Partner and AIM, entered into agreements with HPIP, pursuant to which HPIP (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 and (ii) contributed certain midstream assets and $15.0 million in cash to us in exchange for 5,142,857 Series A Units issued by the Partnership. Of the $15.0 million cash consideration paid by HPIP, approximately $2.5 million was used to pay certain transaction expenses of HPIP, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's credit facility in connection with the Fourth Amendment. As a result of these transactions, which were also consummated on April 15, 2013, HPIP 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 permanent waiver of any 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 requires us to reduce the quarterly cash distribution that would otherwise be payable in respect of our subordinated units or Series A Units for certain quarters of 2013. Please read "— Fourth Amendment to Credit Agreement" and "—Liquidity and Capital Resources — Our Credit Facility" for more information about our credit facility, covenant violations and related waivers and the Fourth Amendment. On April 15, 2013, our General Partner entered into our Third Amended and 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 Units.

ArcLight Transactions

Purchase Agreement

On April 15, 2013, AIM and HPIP entered into a Purchase Agreement, pursuant to which HPIP purchased from AIM 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

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consummated on April 15, 2013. Of the cash consideration paid to AIM, $12.5 million is being held in escrow until its release upon satisfaction of certain conditions. As of September 30, 2013, due to the action filed by AIM, the escrowed funds of $12.5 million were not released to the Partnership. Please read "— Equity Restructuring" below for more information.

Contribution Agreement

On April 15, 2013, the Partnership and HPIP entered into a Contribution Agreement, pursuant to which HPIP contributed to us 100% of the limited liability interests in the High Point System and $15.0 million in cash in exchange for 5,142,857 newly issued Series A Units. Of the $15.0 million cash consideration paid by HPIP, approximately $2.5 million was used to pay certain transaction expenses of HPIP, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's 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 entered into the Amended Partnership Agreement providing for the creation and designation of the rights, preferences, terms and conditions of the Series A Units.

Under the terms of the Amended Partnership Agreement, during the period that commences with the quarter that ends on June 30, 2013 and ending with the earlier of the quarter that includes a conversion of the Series A Units and the quarter beginning October 1, 2014 (the “Coupon Conversion Quarter”), the Series A Units will each receive quarterly distributions (the “Series A Quarterly Distributions”) in an amount equal to (i) 0.01428571 of additional Series A Units (subject to customary anti-dilution adjustments) (the "PIK Distribution") and (ii) $0.25 in cash (with the additional Series A Units and cash portion relating to the quarter ended June 30, 2013 being prorated based on the number of days in such quarter that follow the date on which the Series A Units were issued). Commencing with the Coupon Conversion Quarter, the Series A 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 Units converted into Common Units or (b) a fixed rate of 0.023571428 multiplied by the conversion price, which will initially be $17.50 per Series A 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. 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 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 Unit entitled to one vote for each common unit into which such Series A Unit is convertible. The Series A 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 Units. Moreover, our General Partner may not take any of the following actions without the prior written consent of HPIP or any of its affiliates, as long as HPIP or such affiliates together hold at least 50% of the Series A Units held by HPIP immediately following the issuance of the Series A 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 $15,000,000 in any one or series of related transactions or in the aggregate exceeds $50,000,000 in any twelve-month period;

•

cause or permit us to (i) incur, create or guarantee any indebtedness that exceeds (x) $75,000,000 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) $25,000,000 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 (10)%;


•	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 our General Partner, on the other hand, other than any transaction in the ordinary course of business and determined by the board of directors of our General Partner to be on an arm's length basis; or

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•	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 Units are convertible in whole or in part into common units at any time on or 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 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 Unit (subject to customary anti-dilution adjustments) (the “Conversion").

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 Units are convertible.


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


•	an amount equal to the product of:

(i) the number of common units into which each Series A 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 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 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 Units owned by such holders, plus all accrued but unpaid distributions on such Series A Units.

Change of Control of our 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, HPIP acquired control of our General Partner and a majority of our outstanding limited partner interests. In connection with HPIP'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. HPIP, as the owner of 90% of the limited liability company interests in our General Partner, had the right and has filled the board vacancies created by these resignations. Effective April 15, 2013, HPIP appointed Messrs. Bergstrom, Erhard and Revers to the board of directors of our General Partner. Effective July 15, 2013, Donald R. Kendall, Jr. was appointed to the board of directors of our General Partner, concurrent with the resignation of Donald H. Anderson as a member of the board of directors of our General Partner.

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 credit agreement. The Fourth Amendment provided 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 credit agreement will be reduced to $175 million if an equity contribution of $12.5 million has not been made and used to repay borrowings under the credit facility by October 1, 2013 (which occurred on September 30, 2013);


•	The total outstanding borrowings under the credit facility shall not exceed $175 million until such equity contribution has occurred (which occurred on September 30, 2013);


•	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%;

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


•	The definition of Consolidated EBITDA (the consolidated EBITDA for the quarters ended 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 System as if it was 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 ended March 31, 2013 and ending with the quarter ended December 31, 2013, unless the Partnership has permanently canceled at least 20% of the number of subordinated units outstanding on April 15, 2013 (which occurred through the Equity Restructuring), the Partnership must reduce any quarterly cash distribution on either its subordinated units or Series A 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 Ended	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.

As of October 31, 2013, we had $129.2 million of outstanding borrowings and $33.7 million of available borrowing capacity.

Equity restructuring

Effective August 9, 2013, we executed an equity restructuring agreement ("Equity Restructuring") with our General Partner and HPIP. As part of the Equity Restructuring, the Partnership's 4,526,066 subordinated units and previous incentive distribution rights (the “former IDRs,” all of which were owned by our General Partner, which is controlled by HPIP) were combined into and restructured as a new class of incentive distribution rights (the “new IDRs”). Upon the issuance of the new IDRs, the subordinated units and former IDRs were cancelled. The new IDRs are allocated 85.02% to HPIP and 14.98% to our General Partner. The new IDRs entitle the holders of our incentive distribution rights to receive 48% of any quarterly cash distributions from available cash after the Partnership's common unitholders have received the full minimum quarterly distribution ($0.4125 per unit) for each quarter plus any arrearages from prior quarters (of which there are currently none).

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with the Equity Restructuring, to the General Partner for subsequent conveyance to AIM, the owner of the Class B interest of our General Partner, were canceled effective August 29, 2013. In addition to the action filed by AIM, the escrowed funds of $12.5 million were not released to the Partnership. Accordingly, HPIP contributed $12.5 million in cash to the Partnership which was used to satisfy obligations under our credit agreement and was accounted for as a contribution from our General Partner.

Subsequent Events

Distribution

Amendment to Partnership Agreement

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, performing fractionation 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, process and fractionate, 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, 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, NGLs and condensate 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 and condensate. 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.

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•

Interest in the Chatom Assets. We account for our 87.4% undivided interest in the Chatom System pursuant to ASC No. 810, Consolidation. 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' and the noncontrolling interests. The consolidated income statement shall separately present net income attributable to the partners' 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 more 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, NGLs and condensate 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.

The contribution of the High Point System, which occurred concurrently with HPIP's acquisition of 90% of our General Partner, is presented within our Transmission Segment.

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 performance measures 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, a significant portion 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. Segment gross margin on our High Point System, effective April 15, 2013, is generated through volumetric fees, and therefore gross margin is highly dependent on throughput

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volumes. 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 and realized gain (loss) on commodity derivatives, less COMA income, 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, processing and fractionating activities under fixed-margin and POP arrangements. The cost of natural gas, NGLs and condensate includes volumes of natural gas, NGLs and condensate remitted back to producers pursuant to POP arrangements and the cost of natural gas purchased for our own account, related 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 COMA income, 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.

Effective October 1, 2012, we changed our segment gross margin measure to exclude COMA income. For the three months ended September 30, 2013 and 2012, $0.3 million and less than $0.1 million, respectively, in COMA income was excluded from our Gathering and Processing Segment gross margin and less than $0.1 million and $0.8 million, respectively, in COMA income was excluded from our Transmission Segment gross margin. For the nine months ended September 30, 2013 and 2012, $0.4 million and $0.6 million, respectively, in COMA income was excluded from our Gathering and Processing Segment gross margin and $0.1 million and $2.3 million, respectively, in COMA income was excluded from our Transmission Segment gross margin.

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.

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 performance, including:


•	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 unitholders 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, plus interest expense, income tax expense, depreciation expense, 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 such as impairments of long-lived assets, less interest income, income tax benefit, unrealized gains on commodity derivative contracts, COMA income, amortization of commodity put purchase costs, and selected gains that are unusual or non-recurring. The GAAP measure most directly comparable to adjusted EBITDA is net income.

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.

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You should not consider any of gross margin or adjusted EBITDA in isolation or as a substitute for or more meaningful than analysis of our results as reported under GAAP. 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.

The following table reconciles the non-GAAP financial measures of gross margin used by management to Net (loss) income attributable to the Partnership, their most directly comparable GAAP measure, for the three and nine months ended September 30, 2013 and 2012 (in thousands):



	For the Three Months ending September 30,						For the Nine Months ending September 30,
	2013			2012			2013			2012
Gathering and processing segment gross margin	$	10,688		$	10,310		$	28,454		$	27,321
Transmission segment gross margin	7,864			2,668			19,296			9,472
Total gross margin	18,552			12,978			47,750			36,793
Plus:
Gain (loss) on commodity derivatives	(499		)	(946		)	110			3,157
Less:
Direct operating expenses	7,714			5,329			19,637			11,550
Selling, general and administrative expenses	3,969			3,246			11,982			10,101
Equity compensation expense	392			474			1,877			1,272
Depreciation and accretion expense	6,458			5,504			18,802			15,722
Loss on impairment of property, plant and equipment	—			—			15,232			—
Interest expense	2,082			1,501			6,003			3,083
Other, net (1)	(52		)	(8		)	(112		)	(1,676		)
Income (loss) from operations of disposal groups	(144		)	12			1,652			(94		)
Net income attributable to noncontrolling interest	190			249			533			249
Net (loss) attributable to the Partnership	$	(2,556	)	$	(4,275	)	$	(27,746	)	$	(257	)

(1)

Other, net includes realized gains on commodity derivatives of $0.3 million and $0.8 million and COMA income of $0.3 million and $0.8 million for the three months ended September 30, 2013 and 2012, respectively. Other, net includes realized gains on commodity derivatives of $0.8 million and $1.4 million and COMA income of $0.5 million and $3.0 million for the nine months ended September 30, 2013 and 2012, respectively.

The following table reconciles the non-GAAP financial measures of adjusted EBITDA used by management to Net (loss) income attributable to the Partnership, their most directly comparable GAAP measure, for the three and nine months ended September 30, 2013 and 2012 (in thousands):

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	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Net (loss) income attributable to the Partnership	$	(2,556	)	$	(4,275	)	$	(27,746	)	$	(257	)
Add:
Depreciation and accretion expense	6,458			5,504			18,802			15,722
Interest expense	1,615			1,501			4,695			3,083
Debt issuance costs	194			—			1,509			—
Unrealized (gain) loss on derivatives, net	913			1,762			1,158			(1,732		)
Non-cash equity compensation expense	392			474			1,877			1,272
Transaction expenses	426			—			1,848			—
Loss on impairment of property, plant and equipment	—			—			15,232			—
Loss on impairment of noncurrent assets held for sale	—			—			1,807			—
Deduct:
COMA income	292			820			544			2,980
Straight-line amortization of put costs (1)	32			46			89			269
OPEB plan net periodic benefit	18			23			54			64
Gain on involuntary conversion of property, plant and equipment	—			—			343			—
Gain on sale of assets, net	—			4			—			121
Adjusted EBITDA	$	7,100		$	4,073		18,152			$	14,654


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

General Trends and Outlook

We expect our business to continue to be affected by the key trends discussed under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — General Trends and Outlook” in the Annual Report.

Results of Operations — Combined Overview

For the three and nine months ended September 30, 2013, gross margin increased by $5.6 million, or 43% and $11.0 million or 30%, respectively, as compared to the same periods in 2012. For the nine months ended September 30, 2013, the increase in gross margin was largely a result of (i) higher gross margin in our Transmission Segment of $9.8 million as a result of incremental gross margin associated with our High Point System of $11.5 million and by (ii) higher gross margin in our Gathering and Processing Segment of $1.2 million due to incremental gross margin associated with our Chatom System of $5.4 million offset by lower throughput volumes of 48.5 Mcf/d associated with our systems in the Gathering and Processing Segment.

We distributed $11.6 million to our limited partner unitholders, or $1.30 per unit, during the nine months ended September 30, 2013.

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.

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	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
	(in thousands)
Statement of Operations Data:
Revenue	$	76,577		$	54,347		$	210,190		$	138,423
(Loss) gain on commodity derivatives	(499		)	(946		)	110			3,157
Total revenue	76,078			53,401			210,300			141,580
Operating expenses
Purchases of natural gas, NGLs and condensate	57,973			41,365			162,671			100,075
Direct operating expenses	7,714			5,329			19,637			11,550
Selling, general and administrative expenses	3,969			3,246			11,982			10,101
Equity compensation expense	392			474			1,877			1,272
Depreciation and accretion expense	6,458			5,504			18,802			15,722
Total operating expenses	76,506			55,918			214,969			138,720
Gain on involuntary conversion of property, plant and equipment	—			—			343			—
Gain on sale of assets, net	—			4			—			121
Loss on impairment of property, plant and equipment	—			—			(15,232		)	—
Operating (loss) income	(428		)	(2,513		)	(19,558		)	2,981
Other income (expense):
Interest expense	(2,082		)	(1,501		)	(6,003		)	(3,083		)
Net (loss) income from continuing operations	(2,510		)	(4,014		)	(25,561		)	(102		)
Discontinued operations	144			(12		)	(1,652		)	94
Net (loss) income	(2,366		)	(4,026		)	(27,213		)	(8		)
Net income attributable to noncontrolling interests	190			249			533			249
Net (loss) income attributable to the Partnership	$	(2,556	)	$	(4,275	)	$	(27,746	)	$	(257	)
Other Financial Data:
Gross margin	$	18,552		$	12,978		$	47,750		$	36,793
Adjusted EBITDA	$	7,100		$	4,073		$	18,152		$	14,654

Three months ended September 30, 2013 Compared to Three months ended September 30, 2012

Revenue. Our revenue for the three months ended September 30, 2013 was $76.6 million compared to $54.3 million for the three months ended September 30, 2012. This increase of $22.3 million was primarily due to the following:


•	Natural gas revenues increased $11.9 million as a result of (i) higher realized natural gas prices of $3.80/Mcf, an increase of $0.72/Mcf, or 23.4%, period over period, and (ii) increased natural gas sales volumes 25.6% period over period;


•	Condensate revenues increased less than $0.1 million as a result of higher condensate production of 3.0 Mgal/d due to higher realized condensate prices of $2.40/gal, an increase of $0.13/gal period over period;


•	NGL revenues increased $0.7 million as a result of higher NGL volumes associated with our elective processing agreement offset by lower gross NGL production volumes of 6.5 Mgal/d due to lower volumes from our Gathering and Processing Segment and lower realized NGL prices of $0.91/gal, a decrease of $0.03/gal period over period; and


•	Transmission revenues from the transportation of natural gas increased $10.4 million primarily as a result of incremental revenue of $10.6 million associated with our High Point System, partially offset by a decrease in revenues of $0.1 million in our Midla System.

Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate for the three months ended September 30, 2013 were $58.0 million compared to $41.4 million for the three months ended September 30, 2012. This increase of $16.6 million was primarily due to higher purchase costs associated with natural gas and condensate due to higher realized natural gas and condensate prices, higher natural gas purchase volumes and higher condensate production related to POP

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contracts associated with owned processing plants in our Gathering and Processing Segment, partially offset by lower realized NGL prices and lower NGL volumes associated with our POP contracts.

Gross Margin. Gross margin for the three months ended September 30, 2013 was $18.6 million compared to $13.0 million for the three months ended September 30, 2012. This increase of $5.6 million was primarily due to (i) higher gross margin in our Transmission Segment of $5.2 million as a result of incremental gross margin associated with our High Point System of $5.8 million and (ii) higher gross margin in our Gathering and Processing Segment of $0.4 million due to higher natural gas throughput volumes of 58.5 MMcf/d, or 23.8%, partially offset by lower margins associated with our POP and elective processing agreements in the segment.

Direct Operating Expenses. Direct operating expenses for the three months ended September 30, 2013 were $7.7 million compared to $5.3 million in the three months ended September 30, 2012. This increase of $2.4 million was primarily due to: (i) $0.9 million of additional salaries, wages and benefits associated with the contributed High Point System; (ii) $1.0 million of costs associated with our property and casualty insurance; and (iii) $0.6 million associated with additional aerial inspections of our Transmission Segment.

Selling, General and Administrative Expenses ("SG&A"). SG&A expenses for the three months ended September 30, 2013 were $4.0 million compared to $3.2 million for the three months ended September 30, 2012. This increase of $0.8 million was primarily due to (i) higher transaction costs of $0.4 million associated with the Equity Restructuring; (ii) incremental costs of $0.2 million associated with our High Point System; (iii) higher salaries and wages of $0.3 million partially offset by (iv) lower consulting and advisory services of $0.3 million.

Equity Compensation Expense. Compensation expense related to our LTIP for the three months ended September 30, 2013 was $0.4 million compared to $0.5 million for the three months ended September 30, 2012. This decrease of $0.1 million was primarily due to the acceleration of additional unit based awards granted in 2012.

Depreciation and Accretion Expense. Depreciation expense for the three months ended September 30, 2013 was $6.5 million compared to $5.5 million for the three months ended September 30, 2012. This increase of $1.0 million was due to depreciation associated with (i) the contributed assets of the High Point System; and (ii) other capital projects placed into service during the period.

Interest Expense. Interest expense for the three months ended September 30, 2013 was $2.1 million compared to $1.5 million for the three months ended September 30, 2012. This increase of $0.6 million was primarily due to the increase in borrowings under our credit facility and an increase to our weighted average interest rate of 0.23% as a result of the Fourth Amendment to our Credit Agreement.

Nine months ended September 30, 2013 Compared to Nine months ended September 30, 2012

Revenue. Our revenue for the nine months ended September 30, 2013 was $210.2 million compared to $138.4 million for the nine months ended September 30, 2012. This increase of $71.8 million was primarily due to the following:


•	Natural gas revenues increased $35.2 million as a result of higher realized natural gas prices of $3.97/Mcf, an increase of $1.23/Mcf or 44.9% period over period, and an increase in natural gas sales volumes of 9.2% period over period;


•	Condensate revenues increased $18.8 million as a result of higher condensate production of 26.7 Mgal/d due to the Chatom System acquired in July 2012, period over period, and due to higher realized condensate prices of $2.35/gal, an increase of $0.02/gal period over period;


•	Transmission revenues from the transportation of natural gas increased $18.7 million primarily as a result of i) incremental revenue of $10.5 million associated with our High Point System, and ii) higher realized natural gas prices on our fixed margin contracts of $3.84/Mcf amounting to $10.7 million; offset by


•	NGL revenues increased $0.8 million as a result of slightly higher gross NGL production volumes at our owned processing plants of 1.2 Mgal/d and higher NGL production associated with our elective processing agreement in our Gathering and Processing Segment, offset by lower realized NGL prices of $0.86/gal, a decrease of $0.26/gal period over period.

Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate for the nine months ended September 30, 2013 were $162.7 million compared to $100.1 million for the nine months ended September 30, 2012. This increase of $62.6 million was primarily due to higher purchase costs associated with natural gas and condensate due to higher realized natural gas prices, higher natural gas purchase volumes and higher condensate production related to POP contracts associated with owned processing plants in our Gathering and Processing Segment, partially offset by lower realized NGL prices.

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Gross Margin. Gross margin for the nine months ended September 30, 2013 was $47.8 million compared to $36.8 million for the nine months ended September 30, 2012. This increase of $11.0 million was primarily due to (i) higher gross margin in our Transmission Segment of $9.8 million as a result of incremental gross margin associated with our High Point System of $11.5 million and by (ii) higher gross margin in our Gathering and Processing Segment of $1.1 million due to our Chatom System amounting to $5.4 million and volumes of 48.5 MMcf/d or 15.2% partially offset by lower margins associated with our POP and elective processing agreements in the segment.

Direct Operating Expenses. Direct operating expenses for the nine months ended September 30, 2013 were $19.6 million compared to $11.6 million in the nine months ended September 30, 2012. This increase of $8.0 million was primarily due to (i) $2.7 million of additional salaries, wages and benefits associated with the contributed High Point System; (ii) $1.9 million of costs associated with our property and casualty insurance; (iii) $1.0 million associated with additional aerial inspections of our Transmission Segment; and (iv) $0.9 million associated with higher rents and property taxes.

Selling, General and Administrative Expenses ("SG&A"). SG&A expenses for the nine months ended September 30, 2013 were $12.0 million compared to $10.1 million for the nine months ended September 30, 2012. This increase of $1.9 million was primarily due to (i) higher transaction costs of $1.9 million associated with the Arclight Transactions and Equity Restructuring; (ii) higher salaries and wages of $0.2 million partially offset by (iii) lower consulting and advisory services of $0.3 million.

Equity Compensation Expense. Compensation expense related our LTIP for the nine months ended September 30, 2013 was $1.9 million compared to $1.3 million for the nine months ended September 30, 2012. This increase of $0.6 million was primarily due to the amortization of additional unit based awards granted in 2013 and 2012.

Depreciation and Accretion Expense. Depreciation expense for the nine months ended September 30, 2013 was $18.8 million compared to $15.7 million for the nine months ended September 30, 2012. This increase of $3.1 million was due to depreciation associated with (i) the contributed assets of the High Point System; (ii) the Chatom System acquired in July 2012; and (iii) other capital projects placed into service during the period.

Loss on impairment of property, plant and equipment. During the second quarter of 2013, management determined to change its commercial approach towards certain non-strategic gathering and processing assets. As a result, an asset impairment charge of $15.2 million was recorded for the nine months ended September 30, 2013. There was no impairment charge necessary in the comparative periods presented.

Interest Expense. Interest expense for the nine months ended September 30, 2013 was $6.0 million compared to $3.1 million for the nine months ended September 30, 2012. This increase of $2.9 million was primarily due to the increase in borrowings under our credit facility and an increase to our weighted average interest rate of 0.41% as a result of the Fourth Amendment to our Credit Agreement.

Results of Operations — Segment Results

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

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	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013		2012
	(in thousands except operating and pricing data)
Segment Financial and Operating Data:
Gathering and Processing Segment
Financial data:
Revenue	$	48,873		$	41,637		$	144,658	$	101,307
(Loss) gain on commodity derivatives, net	(499		)	(946		)	110		3,157
Total revenue	48,374			40,691			144,768		104,464
Purchases of natural gas, NGLs and condensate	38,162			32,105			116,568		74,776
Direct operating expenses	3,720			3,567			10,694		7,531
Other financial data:
Segment gross margin	$	10,688		$	10,310		$	28,454	$	27,321
Operating data:
Average throughput (MMcf/d)	303.9			245.4			270.1		318.6
Average plant inlet volume (MMcf/d) (a) (b)	134.4			99.8			114.5		130.4
Average gross NGL production (Mgal/d) (a) (c)	49.5			56.0			56.0		54.8
Average gross condensate production (Mgal/d) (a) (c)	48.1			45.1			45.9		19.2
Average realized prices:
Natural gas ($/MMcf)	$	3.80		$	3.08		$	3.97	$	2.74
NGLs ($/gal)	0.91			0.94			0.86		1.12
Condensate ($/gal)	2.40			2.27			2.35		2.33
Transmission Segment
Financial data:
Total revenue	$	27,704		$	12,710		$	65,532	$	37,116
Purchases of natural gas, NGLs and condensate	19,811			9,260			46,103		25,300
Direct operating expenses	3,994			1,762			8,943		4,019
Other financial data:
Segment gross margin	$	7,864		$	2,668		$	19,296	$	9,472
Operating data:
Average throughput (MMcf/d)	698.5			427.8			611.3		409.7
Average firm transportation - capacity reservation (MMcf/d)	262.9			327.8			987.5		1,039.0
Average interruptible transportation - throughput (MMcf/d)	102.2			98.5			113.8		77.6


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


(b)	Includes gross plant inlet volume associated with our interest in the Burns Point processing plant.


(c)	Includes net NGL and condensate production associated with our interest in the Burns Point processing plant.

Three months ended September 30, 2013 Compared to Three months ended September 30, 2012

Gathering and Processing Segment

Revenue. Segment total revenue in the three months ended September 30, 2013 was $48.4 million compared to $40.7 million in the three months ended September 30, 2012. This increase of $7.7 million was primarily due to the following:


•	Higher realized natural gas prices of 23.4% and realized condensate prices of 5.7% offset by lower realized NGL prices of 3.2% period over period as a result of variable commodity prices;


•	Higher average gross condensate production amounting to 3.0 Mgal/d, or an increase of 6.7% period over period as a result of our increased production at our Bazor Ridge System;

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•	Higher average natural gas throughput volumes amounting to 58.5 MMcf/d or 23.8% period over period primarily as a result of higher natural gas throughput volumes of 16.7 MMcf/d and 39.3 MMCf/d on our Quivira system and into our Burns Point plant, respectively;


•	Higher NGL volume associated with our elective processing agreement offset by lower average gross NGL production amounting to 6.5 Mgal/d, or a net decrease of 11.6% period over period, as a result of our reduced production of 8.6 Mgal/d on our Bazor Ridge System; and


•	A decrease in realized gains on commodity derivatives, net of $0.6 million period over period on our commodity derivatives which was comprised of financial swaps, collars and option contracts used to mitigate commodity price risk that settled in 2013. For a discussion of our commodity derivative positions, please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk.”

Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate for the three months ended September 30, 2013 were $38.2 million compared to $32.1 million for the three months ended September 30, 2012. This increase of $6.1 million was primarily due to higher purchase costs associated with natural gas and condensate due to higher realized natural gas and condensate prices, higher natural gas purchase volumes and higher condensate production related to POP contracts associated with owned processing plants, offset by lower realized NGL prices.

Segment Gross Margin. Segment gross margin for the three months ended September 30, 2013 was $10.7 million compared to $10.3 million for the three months ended September 30, 2012. This increase of $0.4 million was primarily due to the following:


•	Higher segment gross margin of $0.8 million related to our elective processing agreement on our Gloria System and higher volumes on the Burns Point and Quivera Systems; offset by


•	Lower segment gross margin of $0.5 million associated with lower NGL sales volumes and NGL prices on our Bazor Ridge System and lower realized NGL prices related to our elective processing agreement on our Gloria system;


•	Lower segment gross margins of $0.3 million associated with lower NGL sales volumes and NGL prices on our Chatom System; and


•	A decrease in realized gains of $0.6 million period over period on our commodity derivatives which was comprised of financial swaps, collars and option contracts which were used to mitigate commodity price risk that settled in 2013.

Direct Operating Expenses. Direct operating expenses for the three months ended September 30, 2013 were $3.7 million compared to $3.6 million for the three months ended September 30, 2012. This increase of $0.1 million was primarily due to the incremental operating costs associated with salaries and wages of our field personnel.

Transmission Segment

Revenue. Segment total revenue for the three months ended September 30, 2013 was $27.7 million compared to $12.7 million for the three months ended September 30, 2012. This increase of $15.0 million in segment revenue was primarily due to:


•	Higher realized natural gas prices on our fixed margin contracts of $0.76/Mcf amounting to $3.4 million; and


•	Total natural gas throughput volumes on our transmission systems were 698.5 MMcf/d for the three months ended September 30, 2013 compared to 427.8 MMcf/d for the three months ended September 30, 2012 representing a 63.3% increase period over period primarily due to the contribution of the High Point System amounting to $11.5 million.

Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for the three months ended September 30, 2013 were $19.8 million compared to $9.3 million for the three months ended September 30, 2012. This increase of $10.5 million was primarily due to (i) higher realized natural gas prices, which resulted in higher natural gas purchase costs associated with our fixed margin agreements on MLGT and Midla amounting to $3.0 million, and (ii) incremental natural gas costs associated with imbalances and cash-outs in connection with our High Point System of $5.7 million.

Segment Gross Margin. Segment gross margin for the three months ended September 30, 2013 was $7.9 million compared to $2.7 million for the three months ended September 30, 2012. This increase of $5.2 million was primarily due to incremental gross margin on our High Point System of $5.8 million.

Direct Operating Expenses. Direct operating expenses for the three months ended September 30, 2013 were $4.0 million compared to $1.8 million for the three months ended September 30, 2012. This increase of $2.2 million is primarily due to the incremental expense of our High Point System amounting $2.5 million.

Nine months ended September 30, 2013 Compared to Nine months ended September 30, 2012

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Gathering and Processing Segment

Revenue. Segment total revenue in the nine months ended September 30, 2013 was $144.8 million compared to $104.5 million in the nine months ended September 30, 2012. This increase of $40.3 million was primarily due to the following:


•	Higher realized natural gas prices of 44.9% and realized condensate prices of 0.9% offset by lower realized NGL prices of 23.2% period over period as a result of variable commodity prices;


•	Higher average gross condensate production amounting to 26.7 Mgal/d, or an increase of 139.1% period over period, as a result of our increased production at our Chatom System;


•	Higher NGL volume associated with our elective processing agreement and slightly higher average gross NGL production amounting to 1.2 Mgal/d, or an increase of 2.2% period over period, as a result of our acquisition of the Chatom System in July 2012 offset by lower production on our Bazor Ridge system and Burns Point Plant; partially offset by


•	Lower average natural gas throughput volumes amounting to 48.5 MMcf/d or a decrease of 15.2% period over period, as a result of lower volumes at our Burns Point plant and Quivira system; and


•	A decrease in realized gains on commodity derivatives, net of $0.6 million period over period on our commodity derivatives which was comprised of financial swaps, collars and option contracts used to mitigate commodity price risk that will settled in 2013. For a discussion of our commodity derivative positions, please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk.”

Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate for the nine months ended September 30, 2013 were $116.6 million compared to $74.8 million for the nine months ended September 30, 2012. This increase of $41.8 million was primarily due to (i) higher purchase costs associated with natural gas and condensate due to higher realized natural gas and condensate prices, (ii) higher natural gas purchase volumes and (iii) higher condensate production related to POP contracts associated with owned processing plants, offset by lower realized NGL prices.

Segment Gross Margin. Segment gross margin for the nine months ended September 30, 2013 was $28.5 million compared to $27.3 million for the nine months ended September 30, 2012. This increase of $1.2 million was primarily due to the following:


•	Incremental segment gross margin of $5.4 million associated with the POP and fee based contracts associated with the Chatom System, acquired effective July 1, 2012; offset by


•	Lower segment gross margins of $2.7 million associated with our Burns Point Plant and Quivira system as a result of lower level of volumes on one of its offshore pipeline systems;


•	Lower segment gross margin of $1.2 million associated with lower NGL sales volumes and NGL prices on our Bazor Ridge system and lower realized NGL prices related to our elective processing agreement on our Gloria system; and


•	A decrease in realized gains on commodity derivatives, net of $0.6 million period over period on our commodity derivatives which were comprised of financial swaps, collars and option contracts which were used to mitigate commodity price risk that settled in 2013.

Direct Operating Expenses. Direct operating expenses for the nine months ended September 30, 2013 were $10.7 million compared to $7.5 million for the nine months ended September 30, 2012. This increase of $3.2 million was primarily due to incremental operating costs associated with our 87.4% undivided interest in the Chatom System acquired July 2012 amounting to $3.4 million.

Transmission Segment

Revenue. Segment total revenue for the nine months ended September 30, 2013 was $65.5 million compared to $37.1 million for the nine months ended September 30, 2012. This increase of $28.4 million in segment revenue was primarily due to:


•	Higher realized natural gas prices on our fixed margin contracts of $1.10/Mcf amounting to $10.7 million; and


•	Total natural gas throughput volumes on our Transmission systems for the nine months ended September 30, 2013 was 611.3 MMcf/d compared to 409.7 MMcf/d for the nine months ended September 30, 2012 representing a 49.2% increase period over period primarily due to the contribution of the High Point System, effective April 15, 2013, amounting to $19.7 million.

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Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for the nine months ended September 30, 2013 were $46.1 million compared to $25.3 million for the nine months ended September 30, 2012. This increase of $20.8 million was primarily due to higher realized natural gas prices, which resulted in higher natural gas purchase costs associated with our fixed margin agreements on MLGT and Midla amounting to $8.6 million and (ii) incremental natural gas costs associated with imbalances and cash-outs in connection with our High Point System of $8.6 million.

Segment Gross Margin. Segment gross margin for the nine months ended September 30, 2013 was $19.3 million compared to $9.5 million for the nine months ended September 30, 2012. This increase of $9.8 million was primarily due to incremental gross margin on our High Point System of $11.5 million offset by lower gross margin on our remaining assets of $1.7 million.

Direct Operating Expenses. Direct operating expenses for the nine months ended September 30, 2013 were $8.9 million compared to $4.0 million for the nine months ended September 30, 2012. This increase of $4.9 million is primarily due to our High Point System amounting $4.8 million.

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.

Our Credit Facility

On June 27, 2012, we amended our credit facility to increase the commitments from an aggregate principal amount of $100 million to an aggregate principal amount of $200 million. For the nine months ended September 30, 2013 and 2012, the weighted average interest rate on borrowings under our credit facility was approximately 4.50% and 4.09%, respectively.

Our obligations under our credit facility are secured by a first mortgage in favor of the lenders in our real property. Advances made under our 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 our 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.

Our 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 our credit facility are a total leverage ratio and a minimum interest coverage ratio.

As of December 31, 2012, the Consolidated Total Leverage Ratio, one of the primary financial covenants that we were required to maintain under our 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 ended 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 our 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 5.70 to 1.00. Prior to the Fourth Amendment to our credit agreement, the maximum value permitted under our credit agreement for that ratio could not exceed 4.5 to 1.0. As of March 31, 2013, outstanding debt under our 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 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 credit agreement and entered into the Fourth Amendment to our 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. Until June 30, 2013, we were not required to meet a

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Consolidated Leverage Ratio under our credit facility. We expect that we will have continued availability under our credit facility and be able to meet the Fourth Amendment's Consolidated Leverage Ratio, 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.

The principal indicators of our liquidity at September 30, 2013 were our cash on hand and availability under our credit facility as it exists under the Fourth Amendment. As of September 30, 2013, our available liquidity was $40.3 million, comprised of cash on hand of $1.1 million and $39.2 million available under our credit facility. As of October 31, 2013, our available liquidity was $33.1 million.

In the near term, we expect our sources of liquidity to include cash generated from operations, asset sales, borrowings under our credit facility and issuances of debt and equity securities. As a result of the contribution of the High Point System to the Partnership (with the resultant expected increase in the Partnership's EBITDA for the trailing twelve months), the Fourth Amendment, and the PIK Distribution on the Series A Units and the Preferred Unit Distribution Waiver, we expect to generate sufficient cash flow from operations and borrowings under our 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 Units (“Series A PIK Units”), less the Preferred Unit Distribution Waiver;


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


•	meet our requirements for working capital and capital expenditures, in each case until at least April 16, 2014.

We depend on our 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 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 credit agreement as it existed prior to the Fourth Amendment during the quarters ended December 31, 2012 and March 31, 2013, but we were able to obtain waivers from the lenders for these covenant breaches. On April 15, 2013, we entered into the Fourth Amendment 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 ended June 30, 2013 and then gradually lowering to 4.50 to 1.00 commencing with the quarter ended March 31, 2015. The Partnership believes that the consummation of the ArcLight Transactions will allow it to comply with the Consolidated Total Leverage to EBTIDA ratio in the Fourth Amendment until at least April 16, 2014. However, while we were in compliance with financial covenants of the Fourth Amendment as of September 30, 2013, no assurances can be given that the ArcLight Transactions or any other transaction into which may enter will achieve the necessary ratios or that the contributed business can yield the necessary cash flows.

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 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 was $2.5 million at September 30, 2013.

Cash Flows

The following table reflects cash flows for the applicable periods:

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	Nine months ended September 30,
	2013			2012
	(in thousands)
Net cash provided by (used in):
Operating activities	$	12,816		$	16,476
Investing activities	(16,285		)	(55,716		)
Financing activities	3,969			38,866

Nine months ended September 30, 2013 Compared to Nine months ended September 30, 2012

Operating Activities. Net cash provided by operating activities was $12.8 million for the nine months ended September 30, 2013 compared to $16.5 million for the nine months ended September 30, 2012. Net cash provided by operating activities for the nine months ended September 30, 2013 decreased period over period primarily due to (i) $4.8 million of additional direct operating expenses associated with the contributed High Point System and $1.9 million of additional costs associated with our property and casualty insurance; (ii) incremental transaction costs and interest payments of $1.9 million and $4.6 million, respectively; and (iii) a decrease in proceeds received from the settlement of risk management assets and liabilities of $1.1 million; partially offset by incremental gross margin associated with our High Point System of $11.5 million and our gathering and processing segment of $1.1 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 are 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 $16.3 million for the nine months ended September 30, 2013 compared to $55.7 million for the nine months ended September 30, 2012. Cash used in investing activities for the nine months ended September 30, 2013 decreased period over period primarily due to (i) $10.5 million used to fund the development of our Madison County system and (ii) $5.3 million used to fund maintenance capital primarily associated improvements at our Bazor Ridge and other systems, as compared to $51.4 million used to fund the acquisition of the Chatom System in July 2012.

Financing Activities. Net cash provided by financing activities was $4.0 million for the nine months ended September 30, 2013 compared to $38.9 million for the nine months ended September 30, 2012. Cash provided by financing activities for the nine months ended September 30, 2013 decreased period over period primarily due to (i) a decrease of $7.3 million in net borrowings from our credit facility as result of contributions from our General Partner; (ii) the issuance of the Series A Units amounting to $14.4 million; offset by (iii) distribution payments of $12.5 million; as compared to higher net borrowings of $52.4 million associated with the acquisition of the Chatom System in July 2012 for the nine months ended September 30, 2012.

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 made to maintain our long-term operating income or operating capacity (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); 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 nine months ended September 30, 2013, capital expenditures totaled $16.8 million including growth capital expenditures of $10.5 million, maintenance capital expenditures of $5.3 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 $1.0 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.

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Integrity Management

Certain operating assets require an ongoing integrity management program 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 total program addresses approximately 91 high consequence areas that require on-going testing pursuant to DOT regulations. Over the course of the seven-year cycle, we expect to incur approximately $4.5 million in integrity management testing expenses.

Distributions

We intend to pay a quarterly distribution though we do not have a legal obligation to make distributions except as provided in our partnership agreement.

Contractual Obligations

The table below summarizes our obligations and other commitments as of September 30, 2013 (in thousands):



	Payments Due by Period
	Total		2013		2014		2015		2016		2017		Thereafter
Operating leases and service contracts (a)	$	4,282	$	154	$	793	$	762	$	531	$	506	$	1,536
Asset retirement obligations	34,440		—		—		—		7,867		—		26,573
Total	$	38,722	$	154	$	793	$	762	$	8,398	$	506	$	28,109

(a) Operating leases and service contracts have been reduced by total minimum sublease rentals of less than $0.1 million due in the future under non-cancelable subleases.

Critical Accounting Policies

There were no changes to our significant accounting policies from those disclosed in the Annual Report.

Recent Accounting Pronouncements

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 have provided additional disclosures regarding the gross amounts of derivative assets and liabilities in Note 6 "Derivatives" in accordance with these new standards updates.

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 which did not have a material impact on our condensed consolidated financial statements as there are currently no items reclassified from AOCI.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

The following should be read in conjunction with Quantitative and Qualitative Disclosures about Market Risk included in the Annual Report. We are exposed to market risk on our open derivative contracts of non-performance by our counterparties. We do not expect such non-performance because our contracts are with major financial institutions with investment grade credit ratings. We did not post collateral under any of these contracts, as they are secured under our credit agreement. We account for our derivative activities whereby each derivative instrument is recorded on the balance sheet as either an asset or liability measured at fair value. Refer to Note 6 "Derivatives" for further details.

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During 2012, we entered into additional commodity contracts with existing counterparties to hedge our 2013 exposure to commodity prices. As of September 30, 2013, we have hedged approximately 51% of our expected exposure to commodity prices for the remainder of 2013.

The table below sets forth certain information regarding the financial instruments used to hedge of commodity price risk as of September 30, 2013 (in thousands):



Commodity	Instrument	Volumes (a)		Weighted Average Price	Period	Fair value at September 30, 2013
Natural Gas (Mmbtu)	Swaps	(67,600	)	$3.84	Oct 2013 - Dec 2013	$	13.4
NGLs (gals)	Swaps	(949,800	)	$1.51	Oct 2013 - Dec 2013	334.1
	Puts	(211,400	)	$1.07	Oct 2013 - Dec 2013	2.5
	Collars (b)	(650,800	)	$1.11	Oct 2013 - Dec 2013	23.6
Oil (bbls)	Swaps	(19,700	)	$101.00	Oct 2013 - Dec 2013	(79.9		)
						$	293.7


(a)	Contracted and notional volumes represented as a net short financial position by instrument.


(b)	Collars contain weighted average price for floors and caps of $0.79 and $1.43, respectively.

Interest Rate Risk

During the nine months ended September 30, 2013, we had exposure to changes in interest rates on our indebtedness associated with our credit facility. During the second quarter of 2013, we entered into an interest rate swap to manage the impact of the interest rate risk associated with our credit facility, effectively converting the cash flows related to $100 million of our long-term variable rate debt into fixed rate cash flows.

The credit markets have recently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will begin to tighten, resulting in higher interest rates. Interest rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

A hypothetical increase or decrease in interest rates by 1.0% would have changed our interest expense by $1.0 million for the nine months ended September 30, 2013.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to the management of our general partner, including our general partner’s principal executive and principal financial officers (whom we refer to as the Certifying Officers), as appropriate to allow timely decisions regarding required disclosure.

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

The management of our general partner evaluated, with the participation of the Certifying Officers, the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report, pursuant to Rule 13a-15(e) and 15d-15(e) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of the end of the period covered by this report our disclosure controls and procedures were effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There were no changes in internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the period ending September 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The certifications of our General Partner’s President and Chief Executive Officer and Senior Vice President & Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this Quarterly Report on Form 10-Q as Exhibits 31.1 and 31.2. The certifications of our principal executive officer and principal financial officer pursuant to 18 U.S.C. 1350 are furnished with this Quarterly Report on Form 10-Q as Exhibits 32.1 and 32.2.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

AIM Litigation

On September 5, 2013, HPIP, our General Partner and the Partnership were named as defendants in an action filed by AIM challenging the Equity Restructuring. AIM Midstream Holdings, LLC v. High Point Infrastructure Partners, LLC, American Midstream GP, LLC and American Midstream Partners, LP (Civil Action No. 8803-VCP) was filed in the Court of Chancery of the State of Delaware. Among claims against the other parties to the litigation, the action asserts a claim of tortuous interference with contract against the Partnership and seeks either rescission of the Equity Restructuring Agreement or, in the alternative, monetary damages. While we cannot predict the ultimate outcome of this litigation, we are vigorously defending ourselves and do not believe it will be material to our operations or financial results.

We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Please read under the captions “— Regulation of Operations — Interstate Transportation Pipeline Regulation” and “— Environmental Matters” in our Annual Report for more information.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, careful consideration should be given to the risk factors discussed under the caption “Risk Factors” in the Annual Report, in subsequent filings on Form 10-Q, and as set forth below. An investment in our securities involves various risks. When considering an investment in us, you should consider carefully all of the risk factors described in our Annual Report and subsequent filings on Form 10-Q. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our consolidated results of operations, financial condition and cash flows.

Litigation initiated by the former owner of 100% of our general partner could result in a change in our capital structure.

Our General Partner was previously 100% owned by AIM. Following the announcement of the Equity Restructuring, AIM filed an action in Delaware Chancery Court against HPIP, our General Partner and us seeking, either rescission of the Equity Restructuring or, in the alternative, monetary damages. In the event that a court were to require rescission of the Equity Restructuring, our outstanding equity could be altered or returned to the status prior to the Equity Restructuring.

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Item 6. Exhibits



Exhibit Number	Exhibit
3.1	Certificate of Limited Partnership of American Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
3.2	Fourth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated August 9, 2013 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on August 15, 2013).
3.3	Certificate of Formation of American Midstream GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
3.4	Second Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC, dated April 15, 2013 (Filed as Exhibit 3.2 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on April 19, 2013).
4.1	Warrant to Purchase Common Units of American Midstream Partners, LP, dated August 9, 2013 (filed as Exhibit 4.1 to the Current Report on Form 8-K (Commission File No.001-35277 ) filed on August 15, 2013).
10.1	Equity Restructuring Agreement by and among American Midstream Partners, LP, American Midstream GP, LLC, and High Point Infrastructure Partners, LLC, dated August 9, 2013 (filed as Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on August 15, 2013).
31.1*	Certification of Stephen W. Bergstrom, President and Chief Executive Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the September 30, 2013 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Daniel C. Campbell, Senior Vice President & Chief Financial Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the September 30, 2013 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Stephen W. Bergstrom, President and Chief Executive Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the September 30, 2013 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Daniel C. Campbell, Senior Vice President & Chief Financial Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the September 30, 2013 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**101.INS	XBRL Instance Document
**101.SCH	XBRL Taxonomy Extension Schema Document
**101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
**101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
**101.LAB	XBRL Taxonomy Extension Label Linkbase Document
**101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document



*	Filed herewith
**	Furnished herewith

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: November 13, 2013




AMERICAN MIDSTREAM PARTNERS, LP

By:	American Midstream GP, LLC, its general partner

By:	/s/ Stephen W. Bergstrom
Name:	Stephen W. Bergstrom
Title:	President and Chief Executive Officer
	(principal executive officer)

By:	/s/ Daniel C. Campbell
Name:	Daniel C. Campbell
Title:	Senior Vice President & Chief Financial Officer
	(principal financial officer)

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Exhibit Index



Exhibit Number	Exhibit
3.1	Certificate of Limited Partnership of American Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
3.2	Fourth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated August 9, 2013 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on August 15, 2013).
3.3	Certificate of Formation of American Midstream GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
3.4	Second Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC, dated April 15, 2013 (Filed as Exhibit 3.2 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on April 19, 2013).
4.1	Warrant to Purchase Common Units of American Midstream Partners, LP, dated August 9, 2013 (filed as Exhibit 4.1 to the Current Report on Form 8-K (Commission File No.001-35277 ) filed on August 15, 2013).
10.1	Equity Restructuring Agreement by and among American Midstream Partners, LP, American Midstream GP, LLC, and High Point Infrastructure Partners, LLC, dated August 9, 2013 (filed as Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on August 15, 2013).
31.1*	Certification of Stephen W. Bergstrom, President and Chief Executive Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the September 30, 2013 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Daniel C. Campbell, Senior Vice President & Chief Financial Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the September 30, 2013 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Stephen W. Bergstrom, President and Chief Executive Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the September 30, 2013 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Daniel C. Campbell, Senior Vice President & Chief Financial Officer of American Midstream GP, LLC, the general partner of American Midstream Partners, LP, for the September 30, 2013 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**101.INS	XBRL Instance Document
**101.SCH	XBRL Taxonomy Extension Schema Document
**101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
**101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
**101.LAB	XBRL Taxonomy Extension Label Linkbase Document
**101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document