Edgar Filing: American Midstream Partners, LP

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Smaller reporting company

2013 10-K/A

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A



x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2013



o	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.)
1400 16th Street, Suite 310 Denver, CO		80202
(Address of principal executive offices)		(Zip code)

(720) 457-6060

(Registrant’s telephone number, including area code)

Securities registered pursuant to section 12(b) of the Act:



Title of Each Class		Name of Each Exchange on Which Registered
Common Units Representing Limited Partnership Interests		New York Stock Exchange

Securities registered pursuant to section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

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. Yes x No o

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). Yes x No o

Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained in, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K/A or any amendment to this Form 10-K/A. o

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.

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

The aggregate market value of common units held by non-affiliates of the registrant on June 28, 2013, was $83,928,303. The aggregate market value was computed by reference to the last sale price of the registrant’s common units on the New York Stock Exchange on June 28, 2013.

There were 11,097,144 common units, 5,353,970 Series A Units and 1,168,225 Series B PIK Units of American Midstream Partners, LP outstanding as of March 7, 2014. Our common units trade on the New York Stock Exchange under the ticker symbol “AMID.”

Documents Incorporated by Reference

None.

EXPLANATORY PARAGRAPH

This Amendment No. 1 on Form 10-K/A (this "Amendment") amends the Registrant's Annual Report on Form 10-K for the year ended December 31, 2013, which the Registrant previously filed with the Securities and Exchange Commission on March 11, 2014 (the "Original Filing"). The Registrant is filing this Amendment solely to reflect the revisions to Part II, Items 6 and 8, and Part IV, Item 15 of the Original Filing described below. All other items of the Original Filing are unaffected by this Amendment and such items have not been included in this Amendment. This Amendment No. 1 does not reflect events occurring after the filing date of the Original Filing or modify or update disclosures in the Original Filing except to correct the calculation of net loss per unit contained in Part II, Items 6 and 8, and Part IV, Item 15.

Subsequent to the filing of the Original Filing, it was determined that the weighted average units outstanding used in the net loss per unit calculation for the year ended December 31, 2013 contained a calculation error. Through this Amendment, we are correcting the calculation error in our weighted average units outstanding used in the net loss per unit computation for the year ended December 31, 2013 which was previously presented in the Original Filing. Management does not believe that the revision is material to its consolidated statement of operations for the year ended December 31, 2013 or net income (loss) per limited partner unit for such period. This revision has no impact on the Partnership’s reported consolidated balance sheet or consolidated cash flow statement as of and for the year ended December 31, 2013.

TABLE OF CONTENTS




PART II
Item
6	SELECTED FINANCIAL DATA	4
8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	6

PART IV
15	EXHIBITS AND SIGNATURES	6

PART II

Item 6. Selected Historical Financial and Operating Data

The following table presents selected historical consolidated financial and operating data for the periods and as of the dates indicated. We derived this information from our historical consolidated financial statements, historical combined Predecessor financial statements and accompanying notes. This information should be read together with, and is qualified in its entirety, by reference to those financial statements and notes, which for the years 2013, 2012, and 2011 begin on F-1 to this Annual Report.

We acquired Blackwater Midstream Holdings, LLC ("Blackwater"), effective December 17, 2013, which is accounted for as a transaction under common control therefore these consolidated financial statements include Blackwater presented from the period April 15, 2013 through December 31, 2013. We acquired the Predecessor assets effective November 1, 2009. During the period from our inception, on August 20, 2009, to October 31, 2009, we had no operations although we incurred certain fees and expenses of approximately $6.4 million associated with our formation and the acquisition of our assets from Enbridge, which are reflected in the “Transaction costs” line item of our consolidated financial data for the period from August 20, 2009 through December 31, 2009.

We corrected a calculation error in our weighted average units outstanding used in the net loss per unit computation for the year ended December 31, 2013 which was previously presented in our Annual Report on Form 10-K for the year ended December 31, 2013. The correction resulted in a decrease of 456,000 weighted average units outstanding as of December 31, 2013. Management notes that the calculation error impacted the fourth quarter 2013 weighted average units outstanding thereby resulting in a change to the limited partners’ net loss per common unit of $7.00 to $7.42, a difference of $0.42 or 6 percent compared to the net loss per unit for the year ended December 31, 2013 disclosed in the previously filed Form 10-K. Management does not believe that the revision is material to the Company's consolidated statement of operations data or the limited partners’ net loss per unit for the year ended December 31, 2013 disclosed in the previously filed 10-K. The Partnership has revised the weighted average units outstanding utilized in the net loss per unit calculation herein. This revision has no impact on the Partnership’s reported consolidated balance sheet or consolidated cash flow statement as of and for the year ended December 31, 2013.

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



	American Midstream Partners, LP and Subsidiaries (Successor)												American Midstream Partners (Predecessor)
	Year Ended December 31, 2013		Year Ended December 31, 2012		Year Ended December 31, 2011			Year Ended December 31, 2010			Period from August 20, 2009 (Inception Date) to December 31, 2009		10 Months Ended October 31, 2009
			(in thousands, except per unit and operating data)
Statement of Operations Data:
Revenue	$	292,626	$	194,843	$	233,169		$	195,087		$	29,892	$	129,614
Realized loss in early termination of commodity derivatives	—		—		(2,998		)	—			—		—
Gain (loss) on commodity derivatives	28		3,400		(2,452		)	(308		)	—		—
Total revenue	292,654		198,243		227,719			194,779			29,892		129,614
Operating expenses:
Purchases of natural gas, NGLs and condensate	214,149		145,172		187,398			157,682			23,864		100,613
Direct operating expenses	29,553		16,798		11,419			10,944			1,477		9,328
Selling, general and administrative expenses	21,402		14,309		11,082			7,120			1,196		8,577
Advisory services agreement termination fee	—		—		2,500			—			—		—
Transaction expenses	—		—		—			303			6,404		—
Equity compensation expense (a)	2,094		1,783		3,357			1,734			150		—
Depreciation expense	29,999		21,284		20,449			19,904			2,962		12,540



Total operating expenses	297,197			199,346			236,205			197,687			36,053			131,058
Gain on acquisition of assets	—			—			565			—			—			—
Gain (loss) on involuntary conversion of property, plant and equipment	343			(1,021		)	—			—			—			—
(Loss) gain on sale of assets, net	—			123			399			—			—			—
Loss on impairment of property, plant and equipment	(18,155		)	—			—
Operating loss	(22,355		)	(2,001		)	(7,522		)	(2,908		)	(6,161		)	(1,444		)
Other income (expense)
Interest expense	(9,291		)	(4,570		)	(4,508		)	(5,406		)	(910		)	(3,728		)
Other income	—			—			—			—			—			24
Net loss before income tax benefit	(31,646		)	(6,571		)	(12,030		)	(8,314		)	(7,071		)	(5,148		)
Income tax benefit	495			—			—			—			—			—
Net loss from continuing operations	(31,151		)	(6,571		)	(12,030		)	(8,314		)	(7,071		)	(5,148		)
Discontinued operations
(Loss) income from operations of disposal groups, net of tax	(2,255		)	319			332			(330		)	79			(189		)
Net loss	(33,406		)	(6,252		)	(11,698		)	(8,644		)	(6,992		)	(5,337		)
Net income attributable to non-controlling interests	633			256			—			—			—			—
Net loss attributable to the Partnership	$	(34,039	)	$	(6,508	)	$	(11,698	)	$	(8,644	)	$	(6,992	)	$	(5,337	)
General partner’s interest in net loss	$	(1,405	)	$	(129	)	$	(233	)	$	(173	)	$	(140	)
Limited partners’ interest in net loss	$	(32,634	)	$	(6,379	)	$	(11,465	)	$	(8,471	)	$	(6,852	)

Limited partners' net loss per common unit (f):
Basic and diluted:
Loss from continuing operations	$	(7.17	)	$	(0.73	)	$	(1.68	)	$	(1.60	)
(Loss) income from discontinued operations	(0.25		)	0.03			0.04			(0.06		)
Net loss	$	(7.42	)	$	(0.70	)	$	(1.64	)	$	(1.66	)	$	(3.13	)
Weighted average number of common units outstanding:
Basic and diluted (b)	7,525			9,113			6,997			5,099			2,187
Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	17,223		$	18,348		$	10,432		$	13,791		$	(6,531	)	$	14,589
Investing activities	(28,214		)	(62,427		)	(41,744		)	(10,268		)	(151,976		)	(853		)
Financing activities	10,816			43,784			32,120			(4,609		)	159,656			(14,088		)
Other Financial Data:
Adjusted EBITDA (c)	$	31,904		$	18,847		$	20,785		$	18,154		$	3,434		$	10,931
Gross margin (d)	76,623			48,706			43,860			37,097			6,028			29,001
Cash distribution declared per common unit	1.75			1.73			0.70
Segment gross margin:
Gathering and Processing	36,464			35,393			30,123			23,573			3,486			19,120
Transmission	32,408			13,313			13,737			13,524			2,542			9,881
Terminals	7,751			—			—			—			—			—
Balance Sheet Data (At Period End):
Cash and cash equivalents	$	393		$	576		$	871		$	63		$	1,149		$	149



Accounts receivable and unbilled revenue	28,827		23,470	20,963	22,850	19,776	8,756
Property, plant and equipment, net	312,510		223,819	170,231	146,808	146,226	205,126
Total assets	382,075		256,696	199,551	173,229	174,470	250,162
Current portion of long-term debt	2,048		—	—	6,000	—	—
Long-term debt	130,735		128,285	66,270	50,370	61,000	—
Operating Data:
Gathering and processing segment:
Throughput (MMcf/d)	277.2		291.2	250.9	175.6	169.7	211.8
Plant inlet volume (MMcf/d) (e)	117.3		116.1	36.7	9.9	11.4	11.7
Gross NGL production (Mgal/d)(e)	52.0		49.9	54.5	34.1	38.2	39.3
Gross condensate production (Mgal/d) (e)	46.2		22.6	22.6	—	—	—
Transmission segment:
Throughput (MMcf/d)	644.7		398.5	381.1	350.2	381.3	357.6
Firm transportation capacity reservation (MMcf/d)	640.7		703.6	702.2	677.6	701.0	613.2
Interruptible transportation throughput (MMcf/d)	389.2		86.6	69.0	80.9	118.0	121.0
Terminals segment:
Storage utilization	96.2	%	—	—	—	—	—


(a)	Represents cash and non-cash costs related to our Long-Term Incentive Plan ("LTIP"). Of these amounts, $2.1 million, $1.8 million and $1.6 million, for the years ended December 31, 2013, 2012 and 2011, respectively, were non-cash expenses.


(b)	Includes unvested phantom units with DERs, which are considered participating securities, of 205,864 and 175,236 as of December 31, 2010 and 2009, respectively. The DERs were eliminated on June 9, 2011. There were no such unvested phantom units with DERs at December 31, 2011, or subsequent.


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


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


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


(f)	The amounts in this section for the year ended December 31, 2013 have been updated by this Amendment.

Item 8. Financial Statements and Supplementary Data

Our consolidated financial statements, together with the reports of our independent registered public accounting firm, begin on F-1 of this Annual Report.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)(1) Financial Statements

Our consolidated financial statements are included under Part II, Item 8 of the Annual Report. For a listing of these items and accompanying footnotes, see “Index to Financial Statements: Page F-1 of this Annual Report.

(a)(2) Financial Statement Schedules

All other schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto or will be filed within the required timeframe.

(a)(3) Exhibits



2.1		Agreement and Plan of Merger by and among AL Blackwater, LLC, Blackwater Midstream Holdings LLC, American Midstream Partners, LP, and Blackwater Merger Sub, LLC, dated as of December 10, 2013 (incorporated by reference to Exhibit 2.1 to American Midstream Partners, LP, Form 8-K filed December 10, 2013 (File No. 001-35257)

2.2		Limited Liability Company Unit Purchase and Sale Agreement by and between American Midstream, LLC, and ArcLight Energy Partners Fund V, L.P., dated January 22, 2014 (incorporated by reference to Exhibit 2.1 to American Midstream Partners, LP Form 8-K filed January 22, 2014 [File No. 001-35257])

3.1		Certificate of Limited Partnership of American Midstream Partners, LP, (incorporated by reference to Exhibit 3.1 to American Midstream Partners, LP, Form S-1 filed March 31, 2011 [File No. 333-173191])

3.2		Fourth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to American Midstream Partners, LP, Form 8-K filed August 15, 2013 [File No 001-35257])

3.3		First Amendment to Fourth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, (incorporated by reference to Exhibit 3.1 to American Midstream Partners, LP, Form 8-K filed November 1, 2013 [File No. 001-35257])

3.4		Amendment No. 2 to Fourth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP. (incorporated by reference to Exhibit 3.1 to American Midstream Partners, LP, Form 8-K filed February 4, 2014 (File No. 001-35257)

3.5		Certificate of Formation of American Midstream GP, LLC (incorporated by reference to Exhibit 3.4 to American Midstream Partners, LP, Form S-1 filed March 31, 2011 [File No. 333-173191])

3.6		Second Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC (incorporated by reference to Exhibit 3.2 to American Midstream Partners, LP Form 8-K filed April 19, 2013 [File No. 000-35257])

3.7		Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC (incorporated by reference to Exhibit 3.1 to American Midstream Partners, LP Form 8-K filed February 10, 2014 [File No.001-35257])
4.1		Warrant to Purchase Common Units of American Midstream Partners, LP, dated February 5, 2014 (incorporated by reference to Exhibit 10.1 to American Midstream Partners, LP, Form 8-K filed February 10, 2014 [File No. 001-35257])

10.1		Credit Agreement dated as of August 1, 2011 between American Midstream, LLC, American Midstream Partners, LP, Bank of America, N.A., Comerica Bank and BBVA Compass Pass (incorporated by reference to Exhibit 10.1 to American Midstream Partners, LP, Form 8-K filed August 4, 2011 [File No. 001-35257])

10.2		First Amendment to Credit Agreement, dated as of November 15, 2011

10.3		Second Amendment to Credit Agreement, dated June 27, 2012 (incorporated by reference to Exhibit 10.1 to American Midstream Partners, LP, Form 8-K filed July 2, 2012 [File No. 001-35257])

10.4		Third Amendment and Waiver to Credit Agreement, dated as of December 26, 2012 (incorporated by reference to Exhibit 10.1 to American Midstream Partners, LP, Form 8-K filed January 2, 2013 [File No. 001-35257])

10.5		Second Waiver to Credit Agreement, dated as of January 24, 2013 (incorporated by reference to Exhibit 10.1 to American Midstream Partners LP, Form 8-K filed January 29, 2013 [File No. 001-35257])

10.6		Third Waiver to Credit Agreement, dated as of March 29, 2013 (incorporated by reference to Exhibit 10.1 to American Midstream Partners LP, Form 8-K filed April 1, 2013 [File No. 001-35257])



10.7		Fourth Amendment to Credit Agreement, dated as of April 15, 2013 (incorporated by reference to Exhibit 10.2 to American Midstream Partners, LP, Form 8-K filed April 19, 2013 [File No. 001-35257])

10.8		Fifth Amendment to Credit Agreement, dated as of December 17, 2013 (incorporated by reference to Exhibit 10.1 to American Midstream Partners, LP, Form 8-K filed December 19, 2013 [File No. 001-35257])

10.9+		Second Amended and Restated American Midstream GP, LLC, Long-Term Incentive Plan (incorporated by reference to Exhibit 10.10 to American Midstream Partners, LP, Form 8-K filed July 17, 2012 [File No. 001-35257])

10.10+		Form of American Midstream Partners, LP Long-Term Incentive Plan Grant of Phantom Units (incorporated by reference to Exhibit 10.8 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.11		Gas Processing Agreement between American Midstream (Louisiana Intrastate), LLC, and Enterprise Gas Processing, LLC, dated June 1, 2011 (incorporated by reference to Exhibit 10.9 to American Midstream Partners, LP Form S-1/A filed July 15, 2011 [File No. 333-173191])

10.12		Firm Gas Gathering Agreement Between American Midstream (Seacrest) LP, and Contango Resources Company (incorporated by reference to Exhibit 10.10 to American Midstream Partners, LP, Form S-1/A filed June 2, 2011 [File No. 333-173191])



10.13		Amendment to Firm Gas Gathering Agreement between American Midstream Offshore (Seacrest) LP (formerly Enbridge Offshore Pipelines [Seacrest[ L.P.), and Contango Operators, Inc. (formerly Contango Resources Company) dated as of August 1, 2008 (incorporated by reference to Exhibit 10.11 to American Midstream Partners, LP, Form S-1/A filed June 2, 2011 [File No. 333-173191])

10.14		Base Contract for Sale and Purchase of Natural Gas Between Exxon Gas & Power Marketing Company and Mid Louisiana Gas Transmission, LLC (incorporated by reference to Exhibit 10.12 to American Midstream Partners, LP, Form S-1/A filed June 2, 2011 [File No. 333-173191])

10.15		Gas Processing Agreement Between American Midstream (Mississippi) LLC and Venture Oil and Gas, Inc. (incorporated by reference to Exhibit 10.13 to American Midstream Partners, LP, Form S-1/A filed June 2, 2011 [File No. 333-173191])

10.16		Gas Transportation Contract between Midcoast Interstate Transmission, Inc. and City of Decatur Utilities (incorporated by reference to Exhibit 10.14 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.17		Amendment No. 1 to Gas Transportation Contract between Enbridge Pipelines (AlaTenn) Inc. and the City of Decatur, Alabama (incorporated by reference to Exhibit 10.15 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.18		Natural Gas Pipeline Construction and Transportation Agreement between Bamagas Company and Calpine Energy Services, L.P. (incorporated by reference to Exhibit 10.16 to American Midstream Partners, LP Form S-1/A filed June 9, 2011 (File No. 333-173191))

10.19		First Amendment to Natural Gas Pipeline Construction and Transportation Agreement dated June 28, 2000 between Bamagas Company and Calpine Energy Services, L.P. (incorporated by reference to Exhibit 10.17 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.20		Natural Gas Pipeline Transportation Agreement between Bamagas Company and Calpine Energy Services, L.P. (incorporated by reference to Exhibit 10.18 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])



10.21		First Amendment to Natural Gas Pipeline Transportation Agreement dated June 28, 2000 between Bamagas Company and Calpine Energy Services, L.P. (incorporated by reference to Exhibit 10.19 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.22		Gas Transport Contract between Enbridge Pipelines (AlaTenn), L.L.C., and the City of Huntsville (incorporated by reference to Exhibit 10.20 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.23		Service Agreement between Enbridge Pipelines (Midla), L.L.C., and Enbridge Marketing (US), LP, dated September 1, 2008 (incorporated by reference to Exhibit 10.21 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.24		Service Agreement between Enbridge Pipelines (Midla), L.L.C., and Enbridge Marketing (US), LP, dated September 1, 2008 (incorporated by reference to Exhibit 10.22 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.25		Gas Processing Agreement TOCA Gas Processing Plant between American Midstream, LLC, and Enterprise Gas Processing, LLC, dated July 1, 2010 (incorporated by reference to Exhibit 10.23 to American Midstream Partners, LP Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.26		Gas Processing Agreement TOCA Gas Processing Plant between American Midstream, LLC, and Enterprise Gas Processing, LLC, dated November 1, 2010 (incorporated by reference to Exhibit 10.24 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.27		Gas Processing Agreement TOCA Gas Processing Plant between American Midstream, LLC, and Enterprise Gas Processing, LLC, dated April 1, 2011 (incorporated by reference to Exhibit 10.25 to American Midstream Partners, LP, Form S-1/A filed June 30, 2011 [File No. 333-173191])

10.28+		Employment Agreement by and between William B. Mathews and American Midstream GP, LLC (incorporated by reference to Exhibit 10.27 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.29+		Form of Amendment of Grant of Phantom Units Under the American Midstream Partners, LP, Long-Term Incentive Plan (incorporated by reference to Exhibit 10.28 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.30+		Employment Agreement by and between Brian F. Bierbach and American Midstream GP, LLC (incorporated by reference to Exhibit 10.4 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.31+		Employment Agreement by and between American Midstream GP, LLC, and Daniel C. Campbell (incorporated by reference to Exhibit 10.1 to American Midstream Partners, LP, Form 8-K filed April 16, 2012 [File No. 001-35257]).

10.32+		Employment Agreement by and between Marty W. Patterson and American Midstream GP, LLC (incorporated by reference to Exhibit 10.5 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.33		Purchase and Sale Agreement, dated May 25, 2012, by and between Quantum Resources A1, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC, collectively as Seller and Quantum Resources Management, LLC, and American Midstream Chatom Unit 1, LLC, American Midstream Chatom Unit 2, LLC, collectively as Buyer (incorporated by reference to Exhibit 10.3 to American Midstream Partners, LP, Amendment No. 1 to Form 10-Q filed November 13, 2012 [File No. 001-35257]).

10.34		Contribution Agreement by and between High Point Infrastructure Partners, LLC, and American Midstream Partners, LP, dated April 15, 2013 (incorporated by reference to Exhibit 10.1 to American Midstream Partners, LP, Form 8-K filed April 19, 2013 [File No. 001-35257])




10.35		Equity Restructuring Agreement by and among American Midstream Partners, LP, American Midstream GP, LLC, and High Point Infrastructure Partners, LLC, dated August 9, 2013 (incorporated by reference to Exhibit 10.1 to American Midstream Partners, LP, Form 8-K filed August 15, 2013 [File No. 001-35257])

10.36+		Employment Agreement between Matthew W. Rowland and American Midstream GP, LLC, dated August 22, 2013 (incorporated by reference to Exhibit 10.1 to American Midstream Partners, LP, Form 8-K filed August 28, 2013 [File No. 001-35257])

10.37		Series B PIK Unit Purchase Agreement by and among American Midstream Partners, LP, American Midstream GP, LLC, and High Point Infrastructure Partners, LLC, dated January 22, 2014 (incorporated by reference to Exhibit 10.1 to American Midstream Partners, LP, Form 8-K filed January 22, 2014 [File No. 001-35257])

10.38		First Amendment to Series B PIK Unit Purchase Agreement by and among American Midstream Partners, LP, American Midstream GP, LLC, and High Point Infrastructure Partners, LLC, dated January 22, 2014 (incorporated by reference to Exhibit 10.2 to American Midstream Partners, LP, Form 8-K filed February 4, 2014 [File No. 001-35257])

10.39		Construction and Field Gathering Agreement by and between HPIP Lavaca, LLC, and Penn Virginia Oil & Gas, L.P., dated January 31, 2014 (incorporated by reference to Exhibit 10.1 to American Midstream Partners, LP, Form 8-K filed February 4, 2014 [File No. 001-35257])

10.40+		Employment Agreement by and between John J. Connor II and American Midstream GP, LLC (incorporated by reference to Exhibit 10.6 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

10.41+		Employment Agreement by and between Sandra M. Flower and American Midstream GP, LLC (incorporated by reference to Exhibit 10.26 to American Midstream Partners, LP, Form S-1/A filed June 9, 2011 [File No. 333-173191])

21.1		American Midstream Partners, LP, List of Subsidiaries (incorporated by reference to Exhibit 21.1 to American Midstream Partners, LP, Form S-1 filed March 31, 2011 [File No. 333-173191])

23.1*		Consent of Independent Registered Public Accounting Firm

31.1*		Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934




31.2*		Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934

32.1*		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2*		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted 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



+	Management contract or compensatory plan arrangement



**	Submitted electronically herewith.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.




American Midstream Partners, LP
(Registrant)

By:		/s/ Daniel C. Campbell

		Daniel C. Campbell
		Senior Vice President & Chief Financial Officer
		(Principal Financial Officer)

Date: May 12, 2014

Pursuant to the requirements of the Securities Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on May 12, 2014.




Signatures		Title

/s/ Stephen W. Bergstrom		Executive Chairman, President and Chief Executive Officer of American Midstream Partners, LP (Principal Executive Officer)
Stephen W. Bergstrom

/s/ Daniel C. Campbell		Senior Vice President and Chief Financial Officer (Principal Financial Officer)
Daniel C. Campbell

/s/ Tom L. Brock		Vice President, Chief Accounting Officer and Corporate Controller of American Midstream Partners, LP (Principal Accounting Officer)
Tom L. Brock

/s/ John F. Erhard		Director, American Midstream GP, LLC
John F. Erhard

/s/ Donald R. Kendall Jr.		Director, American Midstream GP, LLC
Donald R. Kendall Jr.

/s/ Daniel R. Revers		Director, American Midstream GP, LLC
Daniel R. Revers

/s/ Joseph W. Sutton		Director, American Midstream GP, LLC
Joseph W. Sutton

/s/ Lucius H. Taylor		Director, American Midstream GP, LLC
Lucius H. Taylor

/s/ Gerald A. Tywoniuk		Director, American Midstream GP, LLC
Gerald A. Tywoniuk

AMERICAN MIDSTREAM PARTNERS, LP

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



Report of Independent Registered Public Accounting Firm	F-2

Consolidated Balance Sheets as of December 31, 2013 and 2012	F-3

Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011	F-4

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012 and 2011	F-5

Consolidated Statements of Changes in Partners’ Equity and Noncontrolling Interest for the Years Ended December 31, 2013, 2012 and 2011	F-6

Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011	F-7

Notes to Consolidated Financial Statements	F-9

F-1

Report of Independent Registered Public Accounting Firm

To the Partners of American Midstream Partners, LP

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income, of changes in partners’ capital and noncontrolling interest and of cash flows present fairly, in all material respects, the financial position of American Midstream Partners, LP and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Annual Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our audits (which was an integrated audit in 2013). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 1 “Organization and Basis of Presentation” and Note 23 “Liquidity” to the consolidated financial statements, in 2013, the control of the general partner changed and the Partnership entered into a contribution agreement, amended and restated its agreement of limited partnership and amended its credit facility.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As described in Management’s Annual Report on Internal Control over Financial Reporting, management has excluded the High Point System and the Blackwater Terminals from its assessment of internal control over financial reporting as of December 31, 2013, because they were acquired by the Partnership during 2013. We have also excluded the High Point System and the Blackwater Terminals, both 100% owned subsidiaries, from our audit of internal control over financial reporting. The High Point System total assets and total revenues represent 11% and 10%, respectively, and the Blackwater Terminals total assets and total revenues represent 18% and 3%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2013.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

March 11, 2014

F-2

American Midstream Partners, LP, and Subsidiaries

Consolidated Balance Sheets

(In thousands, except unit amounts)



	December 31,
	2013		2012
Assets
Current assets
Cash and cash equivalents	$	393	$	576
Accounts receivable	6,822		1,958
Unbilled revenue	22,005		21,512
Risk management assets	473		969
Other current assets	7,497		3,226
Current assets held for sale	1,268		—
Total current assets	38,458		28,241
Property, plant and equipment, net	312,510		223,819
Goodwill	16,447		—
Intangible assets, net	3,682		—
Other assets, net	9,064		4,636
Noncurrent assets held for sale, net	1,914		—
Total assets	$	382,075	$	256,696
Liabilities and Partners’ Capital
Current liabilities
Accounts payable	$	3,261	$	5,527
Accrued gas purchases	16,394		17,034
Accrued expenses and other current liabilities	15,058		9,619
Current portion of long-term debt	2,048		—
Risk management liabilities	423		—
Current liabilities held for sale	1,106		—
Total current liabilities	38,290		32,180
Risk management liabilities	101		—
Asset retirement obligation	34,636		8,319
Other liabilities	191		309
Long-term debt	130,735		128,285
Deferred tax liability	4,749		—
Noncurrent liabilities held for sale, net	95		—
Total liabilities	208,797		169,093
Commitments and contingencies (see Note 18)
Convertible preferred units
Series A convertible preferred units (5,279 thousand units issued and outstanding as of December 31, 2013)	94,811		—
Equity and partners’ capital
General partner interest (185 thousand units issued and outstanding as of December 31, 2013, and December 31, 2012)	2,696		548
Limited partner interest (7,414 and 9,165 thousand units issued and outstanding as of December 31, 2013, and December 31, 2012, respectively)	71,039		79,266
Accumulated other comprehensive income	104		351
Total partners’ capital	73,839		80,165
Noncontrolling interest	4,628		7,438
Total equity and partners' capital	78,467		87,603
Total liabilities, equity and partners' capital	$	382,075	$	256,696

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

F-3

American Midstream Partners, LP, and Subsidiaries

Consolidated Statements of Operations

(In thousands, except per unit amounts)



	Year Ended December 31,
	2013			2012			2011
Revenue	$	292,626		$	194,843		$	233,169
Realized loss on early termination of commodity derivatives	—			—			(2,998		)
Gain (loss) on commodity derivatives	28			3,400			(2,452		)
Total revenue	292,654			198,243			227,719
Operating expenses:
Purchases of natural gas, NGLs and condensate	214,149			145,172			187,398
Direct operating expenses	29,553			16,798			11,419
Selling, general and administrative expenses	21,402			14,309			11,082
Advisory services agreement termination fee	—			—			2,500
Equity compensation expense	2,094			1,783			3,357
Depreciation, amortization and accretion expense	29,999			21,284			20,449
Total operating expense	297,197			199,346			236,205
Gain on acquisition of assets	—			—			565
Gain (loss) on involuntary conversion of property, plant and equipment	343			(1,021		)	—
Gain on sale of assets, net	—			123			399
Loss on impairment of property, plant and equipment	(18,155		)	—			—
Operating loss	(22,355		)	(2,001		)	(7,522		)
Other expense:
Interest expense	(9,291		)	(4,570		)	(4,508		)
Net loss before income tax benefit	(31,646		)	(6,571		)	(12,030		)
Income tax benefit	495			—			—
Net loss from continuing operations	(31,151		)	(6,571		)	(12,030		)
Discontinued operations
(Loss) income from operations of disposal groups, net of tax	(2,255		)	319			332
Net loss	(33,406		)	(6,252		)	(11,698		)
Net income attributable to noncontrolling interests	633			256			—
Net loss attributable to the Partnership	$	(34,039	)	$	(6,508	)	$	(11,698	)

General partner's interest in net loss	$	(1,405	)	$	(129	)	$	(233	)
Limited partners’ interest in net loss	$	(32,634	)	$	(6,379	)	$	(11,465	)

Limited partners' net loss per common unit (See Note 3 and Note 14):
Basic and diluted:
Loss from continuing operations	$	(7.17	)	$	(0.73	)	$	(1.68	)
(Loss) income from operations of disposal groups	(0.25		)	0.03			0.04
Net loss	$	(7.42	)	$	(0.70	)	$	(1.64	)
Weighted average number of common units outstanding:
Basic and diluted	7,525			9,113			6,997

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

F-4

American Midstream Partners, LP, and Subsidiaries

Consolidated Statements of Comprehensive Income

(In thousands)



	Year Ended December 31,
	2013			2012			2011
Net loss	$	(33,406	)	$	(6,252	)	$	(11,698	)
Unrealized (loss) gain on post retirement benefit plan assets and liabilities	(247		)	(64		)	359
Comprehensive loss	$	(33,653	)	$	(6,316	)	$	(11,339	)
Less: Comprehensive income attributable to noncontrolling interests	633			$	256		$	—
Comprehensive loss attributable to Partnership	$	(34,286	)	$	(6,572	)	$	(11,339	)

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

F-5

American Midstream Partners, LP, and Subsidiaries

Consolidated Statements of Changes in Partners’ Capital and

Noncontrolling Interest

(In thousands)



	Limited Partner Interest			General Partner Interest			Accumulated Other Comprehensive Income			Total Partners' Capital			Noncontrolling Interest
Balances at December 31, 2010	$	83,624		$	2,124		$	56		$	85,804		$	—
Net loss	(11,465		)	(233		)	—			(11,698		)	—
Issuance of common units to public, net of offering costs	69,085			—			—			69,085			—
Unitholder distributions	(42,682		)	(864		)	—			(43,546		)	—
LTIP vesting	1,286			(1,286		)	—			—			—
Tax netting repurchase	(215		)	—			—			(215		)	—
Unit based compensation	257			1,350			—			1,607			—
Other comprehensive income	—			—			359			359			—
Balances at December 31, 2011	$	99,890		$	1,091		$	415		$	101,396		$	—
Acquisition of noncontrolling interest	—			—			—			—			7,407
Net (loss) income	(6,379		)	(129		)	—			(6,508		)	256
Contributions by General Partner	—			13			—			13			—
Unitholder distributions	(15,748		)	(322		)	—			(16,070		)	—
Net distributions to noncontrolling owners	—			—			—			—			(225		)
LTIP vesting	1,888			(1,888		)	—			—			—
Tax netting repurchase	(385		)	—			—			(385		)	—
Unit based compensation	—			1,783			—			1,783			—
Other comprehensive loss	—			—			(64		)	(64		)	—
Balances at December 31, 2012	$	79,266		$	548		$	351		$	80,165		$	7,438
Net (loss) income	(32,634		)	(1,405		)	—			(34,039		)	633
Issuance of common units to public, net of offering costs	54,853			—			—			54,853			—
Unitholder contributions	—			12,500			—			12,500			—
Unitholder distributions	(21,628		)	(623		)	—			(22,251		)	—
Unitholder distribution for acquisition of Blackwater	3,052			(30,702		)	—			(27,650		)	—
Unitholder contribution of Blackwater net assets	—			22,696			—			22,696			—
Fair value of Series A in excess of net assets received	(15,300		)	(312		)	—			(15,612		)	—
Net distributions to noncontrolling owners	—			—			—			—			(661		)
Acquisition of noncontrolling interest	1,993			37			—			2,030			(2,782		)
LTIP vesting	2,067			(2,067		)	—			—			—
Tax netting repurchase	(630		)	—			—			(630		)	—
Unit based compensation	—			2,024			—			2,024			—
Other comprehensive loss	—			—			(247		)	(247		)	—
Balances at December 31, 2013	$	71,039		$	2,696		$	104		$	73,839		$	4,628

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

F-6

American Midstream Partners, LP, and Subsidiaries

Consolidated Statements of Cash Flows

(In thousands)



	Year Ended December 31,
	2013			2012			2011
Cash flows from operating activities
Net loss	$	(33,406	)	$	(6,252	)	$	(11,698	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, amortization and accretion expense	29,999			21,414			20,705
Amortization of deferred financing costs	1,334			716			1,262
Amortization of weather derivative premium	662			—			—
Unrealized loss (gain) on derivative contracts	1,505			(992		)	849
Unit based compensation	2,094			1,783			1,607
OPEB plan net periodic cost (benefit)	(73		)	(88		)	(82		)
Gain on acquisition of assets	—			—			(565		)
(Gain) loss on involuntary conversion of property, plant and equipment	(343		)	1,021			—
Loss (gain) on sale of assets	75			(128		)	(399		)
Loss on impairment of property, plant and equipment	18,155			—			—
Loss on impairment of noncurrent assets held for sale	2,400			—			—
Deferred tax benefit	(847		)	—			—
Changes in operating assets and liabilities, net of effects of assets acquired and liabilities assumed:
Accounts receivable	(790		)	(740		)	(562		)
Unbilled revenue	(226		)	2,768			2,449
Risk management assets and liabilities	(1,147		)	(156		)	(670		)
Other current assets	(1,614		)	984			(1,800		)
Other assets, net	(823		)	(57		)	(54		)
Accounts payable	(845		)	1,197			(218		)
Accrued gas purchases	462			(1,711		)	(3,991		)
Accrued expenses and other current liabilities	769			(943		)	4,410
Other liabilities	(118		)	(468		)	(811		)
Net cash provided by operating activities	17,223			18,348			10,432
Cash flows from investing activities
Cost of acquisitions, net of cash acquired	—			(51,377		)	(35,500		)
Additions to property, plant and equipment	(27,196		)	(11,705		)	(6,369		)
Proceeds from disposal of property, plant and equipment	500			128			125
Insurance proceeds from involuntary conversion of property, plant and equipment	482			527			—
Restricted cash	(2,000		)	—			—
Net cash used in investing activities	(28,214		)	(62,427		)	(41,744		)
Cash flows from financing activities
Proceeds from issuance of common units to public, net of offering costs	54,853			—			69,085
Unit holder contributions	13,075			13			—
Unit holder distributions	(16,120		)	(16,070		)	(43,546		)
Issuance of Series A Convertible Preferred Units	14,393			—			—
Unitholder distributions for Blackwater Acquisition	(27,650		)	—			—
Acquisition of noncontrolling interest	(752		)	—			—

F-7



Net distributions to noncontrolling interest owners	(661		)	(225		)	—
LTIP tax netting unit repurchase	(630		)	(385		)	(215		)
Deferred debt issuance costs	(2,113		)	(1,564		)	(2,489		)
Payments on other debt	(2,640		)	—			(615		)
Borrowings on other debt	3,795			—			—
Payments on loan to affiliate	(20,000		)	—			—
Payments on bank loans	(34,730		)	—			—
Borrowings on bank loans	27,546			—			—
Payments on long-term debt	(131,571		)	(59,230		)	(120,670		)
Borrowings on long-term debt	134,021			121,245			130,570
Net cash provided by financing activities	10,816			43,784			32,120
Net increase (decrease) in cash and cash equivalents	(175		)	(295		)	808
Cash and cash equivalents
Beginning of period	576			871			63
End of period	$	401		$	576		$	871
Supplemental cash flow information
Interest payments, net	$	6,416		$	3,185		$	3,349
Supplemental non-cash information
(Decrease) increase in accrued property, plant and equipment	$	(5,181	)	$	6,968		$	75
Receivable for reimbursable construction in progress projects	—			141			872
Net assets contributed in the Blackwater Acquisition (See Note 2)	22,121			—			—
Net assets contributed in exchange for the issuance of Series A convertible preferred units (see Note 2)	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	4,811			—			—

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

F-8

American Midstream Partners, LP, and Subsidiaries

Notes to Consolidated Financial Statements

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 operating, developing and acquiring a diversified portfolio of midstream energy assets. 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, two processing facilities, one fractionation facility, four terminal sites, three interstate pipelines and five intrastate pipelines. We also own a 50% undivided, non-operating interest in a processing plant located in southern Louisiana. Recently, we became an owner, developer and operator of petroleum, agricultural, and chemical liquid terminal storage facilities.

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


•	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 Midstream Holdings"), 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 Midstream Holdings 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 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 parishes, Louisiana. 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 2 "Acquisitions" for further information.

Equity Restructuring

F-9

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).

Following the announcement of the Equity Restructuring Agreement, AIM Midstream Holdings filed an action in Delaware Chancery Court against HPIP and our General Partner seeking either rescission of the Equity Restructuring Agreement or, in the alternative, monetary damages. As a result of the action filed by AIM Midstream Holdings, the warrants that were issued by the Partnership, in conjunction with the Equity Restructuring, to our general partner for subsequent conveyance to AIM Midstream Holdings were cancelled effective August 29, 2013. In addition to the action filed by AIM Midstream Holdings, the escrowed funds of $12.5 million were not released to us. Accordingly, HPIP contributed $12.5 million in cash to us, which was used to satisfy obligations under our credit agreement and was accounted for as a contribution from our general partner.

On February 5, 2014, we, HPIP and our general partner entered into a settlement (the “Settlement”) with AIM Midstream Holdings regarding the action filed in Delaware Chancery Court by AIM Midstream Holdings. Under the Settlement, among other things:

· HPIP and AIM Midstream Holdings amended the limited liability company agreement of our General Partner ("LLC Amendment") to, among other things, amend the Sharing Percentages (as defined therein) such that HPIP’s sharing percentage thereafter is 95% and AIM Midstream Holdings’s Sharing Percentage is 5%;

· HPIP transferred all of the 85.02% of our outstanding new IDRs held by HPIP to our General Partner such that our General Partner owns 100% of the outstanding new IDRs; and

· we issued to AIM Midstream Holdings a warrant to purchase up to 300,000 common units of the Partnership at an exercise price of $0.01 per common unit (the “Warrant”), which Warrant, among other terms, (i) is exercisable at any time on or after February 8, 2014 until the tenth anniversary of February 5, 2014, (ii) contains cashless exercise provisions and (iii) contains customary anti-dilution and other protections. The Warrant was exercised on February 21, 2014.

Blackwater Terminals

On December 17, 2013, the Partnership completed the Blackwater Acquisition, an owner, developer and operator of petroleum, agricultural, and chemical liquid terminal storage facilities. Blackwater operates 1.3 million barrels of storage capacity across four marine terminal sites located in Westwego, Louisiana; Brunswick, Georgia; Harvey, Louisiana; and Salisbury, Maryland. See Note 2 "Acquisitions" for further information.

Basis of presentation

The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2013 and 2012, and results of operations, comprehensive income, changes in partners' capital and noncontrolling interest, and cash flows for the years ended December 31, 2013, 2012 and 2011.

We have prepared the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The accompanying consolidated financial statements include accounts of American Midstream Partners, LP, and its controlled subsidiaries. All significant inter-company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements. We have made reclassifications to amounts reported in prior period consolidated financial statements to conform with current year presentation. These reclassifications did not have an impact on net income for the period previously reported.

The results of operations for acquisitions accounted for as business combinations have been included in the consolidated financial statements since their respective acquisition dates. See Note 2 "Acquisitions" for further information.

Effective December 17, 2013, Blackwater was acquired by the Partnership, in the form of the Acquisition described above, from ArcLight. However, as of April 15, 2013, an affiliate of ArcLight acquired controlling interest of the Partnership, also described above, at which time Blackwater was also an affiliate of ArcLight. As Blackwater and the Partnership were both affiliates of ArcLight as of April 15, 2013, these financial statements include the effect of Blackwater's operations starting as of the date of the establishment of common control. Therefore, these consolidated financial statements include Blackwater, which had a fiscal year end of March 31, 2013, and were presented from the period April 15, 2013 through December 31, 2013. Please see Note 20 "Reporting Segments" for financial information of Blackwater as presented in our Terminals segment.

Transactions Between Entities Under Common Control

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We may enter into transactions with our General Partner and affiliates 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.

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 an 87.4% undivided interest in the Chatom Processing and Fractionation facility (the "Chatom System"). In October 2013, the Partnership acquired an additional 4.8% undivided interest in the Chatom System. Our consolidated financial statements reflect the accounts of the Chatom System since acquisition. 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

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, goodwill and intangible 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.

Cash and cash equivalents

We consider all highly liquid investments with an original maturity of three months or less at the date of purchase to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.

Allowance for doubtful accounts

We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of December 31, 2013 and 2012, the Partnership recorded no allowances for losses on accounts receivable.

Inventory

Inventory includes NGL product inventory. The Partnership records all product inventories at the lower of cost or market (“LCM”), which is determined on a weighted average basis and included within Other current assets on the consolidated balance sheets. For the years ended December 31, 2013 and 2012, we recorded no lower-of-cost-or-market write-downs on our NGL inventory.

Operational balancing agreements and natural gas imbalances

To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through future receipt or delivery of natural gas. Natural gas imbalances are recorded as gas imbalances and classified within other current assets or other current liabilities on our consolidated balance sheets based on the market value.

Derivative financial instruments

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Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt, commodity prices and fractionation margins (the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas purchases). In an effort to manage the risks to unitholders, we use a variety of derivative financial instruments including swaps, collars and interest rate caps to create offsetting positions to specific commodity or interest rate exposures. In accordance with the authoritative accounting guidance, we record all derivative financial instruments in our consolidated balance sheets at fair market value. We record the fair market value of our derivative financial instruments in the consolidated balance sheet as current and long-term assets or liabilities on a net basis by counterparty. We record changes in the fair value of our derivative financial instruments in our consolidated statements of operations as follows:


•	Commodity-based derivatives: “Total revenue”


•	Corporate interest rate derivatives: “Interest expense”

Our formal hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to the approval and monitoring by the board of directors of our general partner. We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction, and we do not use derivative financial instruments for speculative or trading purposes.

The price assumptions we use to value our derivative financial instruments can affect net income for each period. We use published market price information where available, or quotations from over-the-counter, or OTC, market makers to find executable bids and offers. The valuations also reflect the potential impact of conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

Our earnings are affected by use of mark-to-market method of accounting as required under GAAP for derivative financial instruments. The use of mark-to-market accounting for derivative financial instruments can cause noncash earnings volatility resulting from changes in the underlying indices, primarily commodity prices.

Fair value measurements

We apply the authoritative accounting provisions for measuring fair value of our derivative instruments and disclosures associated with our outstanding indebtedness. We define fair value as an exit price representing the expected amount we would receive when selling an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.

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

We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:


•	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.

We utilize a mid-market pricing convention, or the “market approach”, for valuation for assigning fair value to our derivative assets and liabilities. Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.

Property, plant and equipment

We capitalize expenditures related to property, plant and equipment that have a useful life greater than one year for (1) assets purchased or constructed; (2) existing assets that are replaced, improved, or the useful lives of which have been extended; and (3) all land, regardless of cost. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.

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We record property, plant, and equipment at its original cost, which we depreciate on a straight-line basis over its estimated useful life. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We record depreciation using the group method of depreciation, which is commonly used by pipelines, utilities and similar assets.

Impairment of long lived Assets

We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our business, the market, and business environment to identify indicators that could suggest an asset may not be recoverable. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of income. We recorded impairments of long-lived assets of $18.2 million for the year ended December 31, 2013. No impairment losses were recognized during the years ended December 31, 2012 and 2011.

Goodwill and intangible assets

We record goodwill as the excess of the cost of an acquisition over the fair value of the net assets of the acquired business. Goodwill is not amortized but is reviewed for impairment at least annually or more frequently if an event or change in circumstance indicates that an impairment may have occurred. We first assess qualitative factors to evaluate whether it is more likely than not that an impairment has occurred and it is therefore necessary to perform the two-step goodwill impairment test. If the two-step goodwill impairment test indicates that the goodwill is impaired, an impairment loss is recorded.

We record the estimated fair value of acquired customer contracts as intangible assets. The intangible assets are amortized over the remaining periods of the customer contracts, which range between 5 months and thirty-five months.

Debt issuance costs

Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchase and debt extinguishment include any associated unamortized debt issue costs.

Asset retirement obligations (“AROs”)

AROs are legal obligations associated with the retirement of tangible long-lived assets that result from the asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. We depreciate the capitalized ARO using the straight-line method over the period during which the related long-lived asset is expected to provide benefits. After the initial period of ARO recognition, we revise the ARO to reflect the passage of time or revisions to the amount of estimated cash flows or their timing.

Commitments, contingencies and environmental liabilities

We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense amounts we incur from the remediation of existing environmental contamination caused by past operations that do not benefit future period by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulation taking into consideration the likely effects of inflation and other factors. These amounts also take into account our prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new information. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record an asset separately from the associated liability in our consolidated financial statements.

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We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.

We have legal obligations requiring us to decommission our offshore pipeline systems at retirement. In certain rate jurisdictions, we are permitted to include annual charges for removal costs in the regulated cost of service rates we charge our customers. Additionally, legal obligations exist for a minority of our offshore right-of-way agreements due to requirements or landowner options to compel us to remove the pipe at final abandonment. Sufficient data exists with certain onshore pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement of estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management’s experience, or the asset’s estimated economic life. The useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to reasonably estimate potential settlement dates and methods.

Convertible preferred units

We record the issuance of our Series A Preferred Units at fair value and separately classify 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 ("ASC")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.

Noncontrolling interest

Noncontrolling interest represents the noncontrolling interest holders' proportionate share of the equity of the Chatom system. Noncontrolling interest is adjusted for the noncontrolling interest holders' proportionate share of the earnings or losses. Management reports noncontrolling interest in the Chatom system in the financial statements pursuant to paragraph ASC No. 810-10-65-1. The 7.8% noncontrolling interest is held by non-affiliated working interest owners.

Revenue recognition and the estimation of revenues and cost of purchases

We recognize revenue when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable, and (iv) collectability is reasonably assured. We record revenue and cost of product sold on a gross basis for those transactions where we act as the principal and take title to natural gas, natural gas liquids ("NGLs") or condensates that are purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating, transportation or storage, we record those fees separately in revenues. We have the following arrangements:

Fee-based

Under these arrangements, we generally are paid a fixed fee for gathering and transporting natural gas. Fee-based revenues, which are included in sales of natural gas, NGLs and condensate, are recorded when services have been provided, and collectability of the revenue is reasonably assured.

Percent-of-proceeds, or POP

Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas and NGLs at market prices. Where we provide processing services at the processing plants that we own, or obtain processing service for our own account under our own elective processing arrangements we typically retain and sell a percentage of the residue natural gas and resulting NGLs. We recognize percent-of-proceeds contract revenue, which is included in sales of natural gas, NGLs and condensate, when the natural gas, NGLs or condensate is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.

Fixed-margin

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Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. We recognize revenue from fixed-margin contracts, which is included in sales of natural gas, NGLs and condensate, when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred and collectability of the revenue is reasonably assured.

Firm transportation

Under arrangements to provide firm transportation service, 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 they utilize the capacity. In most cases, the shipper also pays a variable-use charge with respect to quantities actually transported by us. Firm transportation revenue is recorded when products are delivered, services have been provided and collectability of the revenue is reasonably assured.

Interruptible transportation

Under arrangements to provide interruptible transportation service, we are only obligated to transport natural gas nominated by the shipper to the extent we have available capacity. For this service the shipper pays no reservation charge but pays a variable-use charge for quantities actually shipped. Interruptible transportation revenue is recorded when products are delivered, services have been provided and collectability of revenue is reasonably assured.

Interest in the Burns Point Plant

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

Terminal revenue and services

Revenues for our terminals include storage tank lease fees, whereby a customer agrees to pay for a certain amount of tank storage over a certain period of time; and throughput fees, whereby a customer pays a fee based on volumes moving through the terminal. At our terminals, we also offer and provide packaging, blending, handling, filtering and certain other ancillary services. Revenue from firm storage contracts is recognized ratably, which is typically monthly, over the term of the lease. Occasionally, customers pay for tank lease fees in advance. Fees received in advance are deferred until the period they are earned. Revenue from throughput fees and ancillary fees are recognized as services are provided to the customer and when the fees are realizable.

Unit-based employee compensation

We award unit-based compensation to management, non-management employees and directors in the form of phantom units, which are deemed to be equity awards. Compensation expense on phantom units is measured by the fair value of the award at the date of grant as determined by management. Compensation expense is recognized in equity compensation expense over the requisite service period of each award. See Note 15 "Long-Term Incentive Plan".

Income taxes

The Partnership is not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. However, Blackwater is a taxable entity. We account for income taxes using an asset and liability approach for financial accounting and reporting of income taxes. If it is more than likely that a deferred tax asset will not be realized, a valuation allowance is recognized.

Certain tax expense results from the enactment of state income tax laws by the State of Texas that apply to entities organized as partnerships and is included in selling, general and administrative expenses in the consolidated statements of operations. The Texas margin tax is computed on our modified gross margin and was not significant for each of the years ended December 31, 2013, 2012 and 2011.

Net income for financial statement purposes may differ significantly from taxable income allocable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirement under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available.

Comprehensive income (loss)

The Partnership’s other comprehensive income (loss) is comprised of adjustments to other post-retirement plan assets and liabilities. See Note 16 "Post-Employment Benefits".

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Limited partners’ net income (loss) per unit

We compute limited partners’ net income (loss) per unit by dividing our limited partners’ interest in net income (loss) by the weighted average number of units outstanding during the period. The overall computation, presentation and disclosure of our limited partners’ net income (loss) per unit are made in accordance with the FASB Accounting Standards Codification (ASC) Topic 260 “Earnings per Share”.

Accounting for regulated operations

Certain of our natural gas pipelines are subject to regulations by FERC. FERC exercises statutory authority over matters such as construction, transportation rates we charge and our underlying accounting practices and ratemaking agreements with customers. Accordingly, we record costs that are allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a non-regulated entity. Also, we record assets and liabilities that result from the regulated ratemaking process that would be recorded under GAAP for our regulated entities. As of December 31, 2013 and 2012, we had no such material regulatory assets or liabilities.

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.

In July 2013, the FASB issued ASC No. 2013-11, Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (a consensus of the FASB Emerging Issues Task Force). This guidance was issued related to the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. The updated guidance requires an entity to net its unrecognized tax benefits against the deferred tax assets for all same jurisdiction net operating loss carryforward, a similar tax loss, or tax credit carryforwards. A gross presentation will be required only if such carryforwards are not available or would not be used by the entity to settle any additional income taxes resulting from disallowance of the uncertain tax position. The update is effective prospectively for the Partnership’s fiscal year beginning January 1, 2014 and we are currently evaluating the financial impact.

2. Acquisitions

Blackwater Terminals

Effective December 17, 2013, we acquired Blackwater, consisting of AL Blackwater, LLC ("ALB"), a Delaware limited liability company, Blackwater Midstream Holdings LLC, a Delaware limited liability company and a majority owned subsidiary of ALB, and Blackwater Merger Sub, LLC, a Delaware limited liability company and wholly owned subsidiary of the Partnership. Blackwater operates 1.3 million barrels of storage capacity across four marine terminal sites located in Westwego, Louisiana; Brunswick, Georgia; Harvey, Louisiana; and Salisbury, Maryland.

The Partnership distributed consideration of $63.9 million, of which $27.7 million was accounted for as a cash distribution to the general partner. The consideration also included 125,500 limited partner units which were accounted for as a non-cash distribution to the general partner at a fair value of $3.1 million. The fair value of the units issued was determined using level one inputs based upon the Partnership's closing unit price on December 17, 2013.

The remaining consideration was utilized to settle all of the Blackwater's outstanding debt at December 17, 2013.

The acquisition of Blackwater represents a transaction between entities under common control and a change in reporting entity. Transfers of net assets or exchanges of shares between entities under common control are accounted for as if the transfer occurred

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at the beginning of the period or date of common control. Therefore, net assets received were recorded at their historical book value of $22.7 million as of the date common control was established, which is April 15, 2013.

On July 10, 2013, Blackwater acquired and purchased from Chemtura Corporation approximately 56 acres of property and improvements located in Harvey, Louisiana for $2.5 million (the "Harvey assets"). The land is adjacent to the Mississippi River and the assets include dormant storage tanks, unoccupied buildings, a barge dock and other improvements.

The Harvey assets when purchased did not include any employees, customer contracts, permits, licenses, offices, procedures, systems, or processes that had the ability to produce outputs; thus this asset purchase did not meet the definition of a business under the accounting guidance.

For the period from April 15, 2013 to December 31, 2013, Blackwater contributed $9.8 million of revenue and $0.8 million of net loss attributable to the Partnership's Terminals segment, which are included in the consolidated statement of operations.

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 consists of approximately 700 miles of natural gas and liquids pipeline assets located in southeast Louisiana, in the Plaquemines and St. Bernard 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 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 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 year ended December 31, 2013, the High Point System contributed $30.4 million of revenue and $7.2 million of net income attributable to the Partnership's Transmission segment, which are included in the consolidated statement of operations.

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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 under borrowings under our revolving 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 cryogenic 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):



Cash consideration:	$	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 are based on significant inputs not observable in the market and thus represents a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimates are 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.

During the fourth quarter of 2013 we offered to purchase the noncontrolling interest in Chatom from all holders of the noncontrolling interest. As of December 31, 2013, 38% of the noncontrolling interest was purchased by us (a 4.8% overall interest), increasing our total ownership to 92.2% and reducing the noncontrolling interest to 7.8%.

Subsequent to the initial 87.4% acquisition, our undivided interest in the Chatom system contributed $25.4 million of revenue and $1.8 million of net income attributable to the Partnership, which are included in the consolidated statement of operations for the year ended December 31, 2012. For the year ended December 31, 2013, our interest in the Chatom system contributed $56.5 million of revenue and $5.4 million of net income attributable to the Partnership.

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 (in thousands, except per unit amounts):



	Year Ended December 31,
	2012			2011
Revenue	$	246,342		$	296,387
Net loss	(4,319		)	(10,411		)
Limited partners’ net loss per unit	(0.49		)	(1.53		)

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equipment, and (ii) recording pro forma interest expense on debt that would have been incurred to acquire the Chatom system as of January 1, 2012 and 2011, respectively. The unaudited pro forma adjustments are based on available information and certain assumptions we believe are reasonable.

Burns Point Plant Interest

On December 1, 2011, we acquired a 50% undivided interest in the Burns Point Plant from Marathon Oil Company (“Marathon”) for total cash consideration of $35.5 million. No liabilities of Marathon were assumed. The purchase was effective November 1, 2011 with our assumption of insurable risks, operating liabilities and entitlement to in-kind revenues as of that date. The remaining 50% undivided interest is owned by the Burns Point Plant operator, Enterprise Gas Processing, LLC (“Enterprise”). The Burns Point Plant, which is an unincorporated venture, is governed by a construction and operating agreement (“Agreement”).

The fair value of the assets calculated under the market participant approach was in excess of cash consideration paid resulting in a $0.6 million bargain purchase gain.

The following table presents unaudited pro forma consolidated information of the Partnership, adjusted for the acquisition of the Interest in the Plant, as if the acquisition had occurred on January 1, 2011 (in thousands, except per unit amounts):



	Year Ended
	December 31, 2011
Revenue	$	249,908
Net loss	(11,741		)
Limited partners’ net loss per unit	(1.65		)

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 our interest in the Plant, and (iii) elimination of the bargain purchase gain as of January 1, 2011. The unaudited pro forma adjustments are based on available information and certain assumptions we believe are reasonable.

The unaudited pro forma consolidated financial information is for informational purposes only and is not intended to represent or be indicative of the consolidated results of operations or financial position that we would have reported had these acquisitions been completed on the date indicated and should not be taken as representative of its future consolidated results of operations or financial position. Further, the unaudited pro forma consolidated statement of operations is not indicative of the operations going forward because it necessarily excludes various operating expenses.

3. 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. During the year ended December 31, 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 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%, and iii) a decline in throughput volumes of 2.5% in 2013 and thereafter.

The net book value of the non-strategic gathering and processing assets classified as held for sale comprise $1.2 million of Current assets held for sale, $0.3 million of Noncurrent assets held for sale, net, and $1.1 million of Current liabilities held for sale on the consolidated balance sheet as of December 31, 2013.

As part of the Blackwater Acquisition, we acquired long-lived terminal assets classified as held for sale. As of December 31, 2013, certain long-lived terminal assets were written down by $0.6 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. Using a combination of the market and cost approaches, the fair value estimates are based on (i) sales price per barrel of recent transactions as well as replacement cost estimates that include an economic obsolescence factor.

The net book value of the assets and liabilities attributable to the terminal assets are presented separately on the consolidated balance sheet and comprise $0.1 million of Current assets held for sale, $1.6 million of Noncurrent assets held for sale, net, less than $0.1 million of Current liabilities held for sale and all of the Noncurrent liabilities held for sale, net as of December 31, 2013.

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 and Terminal segments. 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 (Loss) income from operations of disposal groups, net of tax in our accompanying 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 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 years ended December 31, 2013, 2012, and 2011 (in thousands, except per unit amounts):



	Year Ended December 31,
	2013			2012			2011
Revenue	$	14,845		$	12,343		$	17,024
Expense	(14,964		)	(12,024		)	(16,692		)
Impairment	(2,400		)	—			—
Loss on sale of assets	(75		)	—			—
Income tax benefit	339			—			—
(Loss) income from operations of disposal groups, net of tax	$	(2,255	)	$	319		$	332
Limited partners' net (loss) income per unit from discontinued operations (basic and diluted)	$	(0.25	)	$	0.03		$	0.04

4. Concentration of Credit Risk and Trade Accounts Receivable

Our primary market areas are located in the United States along the Gulf Coast and in the Southeast. We have as concentration of trade receivable balances due from companies engaged in the production, trading, distribution and marketing of natural gas and NGL products. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. Our customers’ historical financial and operating information is analyzed prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. We maintain allowances for potentially uncollectible accounts receivable; however, for the years ended December 31, 2013, 2012 and 2011, no allowances on or write-offs of accounts receivable were recorded.

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



	Year Ended December 31,
	2013		2012		2011
Customer A	28	%	30	%	41	%
Customer B	13	%	—		—
Customer C	12	%	13	%	15	%
Customer D	10	%	14	%	18	%
Other	37	%	43	%	26	%
Total	100	%	100	%	100	%

5. Other Current Assets

Other current assets consists of the following (in thousands):

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	December 31,
	2013		2012
Prepaid insurance	$	3,166	$	458
Other current assets	4,331		2,768
	$	7,497	$	3,226

6. Derivatives

Commodity Derivatives

To minimize the effect of commodity prices and maintain our cash flow and the economics of our development plans, we enter into commodity hedge contracts from time to time. The terms of the contracts depend on various factors, including management’s view of future commodity prices, acquisition economics on purchased assets and future financial commitments. This hedging program is designed to mitigate the effect of commodity price downturns while allowing us to participate in some commodity price upside. Management regularly monitors the commodity markets and financial commitments to determine if, when, and at what level commodity hedging is appropriate in accordance with policies that are established by the board of directors of our general partner. Currently, the commodity derivatives are in the form of swaps and collars. As of December 31, 2013, the aggregate notional volume of our commodity derivatives was 2.9 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 December 31, 2013, we have not posted collateral with our counterparties. The counterparties are not required to post collateral with us in connection with their derivative positions. Netting agreements are in place with our counterparties that permit us to offset our commodity derivative asset and liability positions.

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

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 December 31, 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 consolidated balance sheet and is being amortized to Direct operating expenses on a straight-line basis over the term of the contract of 12 months. As of December 31, 2013, the unamortized amount of the risk management asset was approximately $0.5 million.

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

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	Gross Risk Management Assets				Gross Risk Management Liabilities						Net Risk Management Assets (Liabilities)
Balance Sheet Classification	December 31, 2013		December 31, 2012		December 31, 2013			December 31, 2012			December 31, 2013			December 31, 2012
Current	$	473	$	1,889	$	—		$	(920	)	$	473		$	969
Noncurrent	—		—		—			—			—			—
Total assets	$	473	$	1,889	$	—		$	(920	)	$	473		$	969

Current	$	27	$	—	$	(450	)	$	—		$	(423	)	$	—
Noncurrent	—		—		(101		)	—			(101		)	—
Total liabilities	$	27	$	—	$	(551	)	$	—		$	(524	)	$	—

For the years ended December 31, 2013, 2012 and 2011, the realized and unrealized gains (losses) associated with our commodity, interest rate and weather derivative instruments were recorded in our consolidated statements of operations, under the captions as follows (in thousands):



	Realized			Unrealized
2013
Gain (loss) on commodity derivatives	$	1,069		$	(1,041	)
Interest expense	(207		)	(454		)
Direct operating expenses	(662		)	—
Total	$	200		$	(1,495	)
2012
Gain (loss) on commodity derivatives	$	2,408		$	992
Total	$	2,408		$	992
2011
Gain (loss) on commodity derivatives	$	(1,911	)	$	(541	)
Realized loss on early termination of commodity derivatives	(2,998		)	—
Total	$	(4,909	)	$	(541	)

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 recorded amounts of impairments of long-lived assets utilize fair value measurements based on significant inputs not observable in the market and thus represent a Level 3 measurement. Primarily using the income approach, the fair value estimates are based on (i) present value of estimated EBITDA, (ii) an assumed discount rate and (iii) a rate of decline in throughput volumes.

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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 will 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 year ended December 31, 2013.

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 December 31, 2013 and 2012 (in thousands):



	Carrying Amount			Estimated Fair Value of the Asset (Liability)
	Carrying Amount			Level 1		Level 2			Level 3		Total
Commodity derivative instruments, net
December 31, 2013	$	(70	)	$	—	$	(70	)	$	—	$	(70	)
December 31, 2012	969			—		969			—		969
Interest rate swap
December 31, 2013	$	(454	)	$	—	$	(454	)	$	—	$	(454	)
December 31, 2012	—			—		—			—		—

The unamortized portion of 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 December 31, 2013 and 2012, were as follows (in thousands):



	Useful Life (in years)	December 31, 2013			December 31, 2012
Land	N/A	$	6,015		$	2,254
Construction in progress	N/A	6,443			5,053
Base gas	N/A	1,108			—
Buildings and improvements	4 to 40	5,109			1,432
Processing and treating plants	8 to 40	97,106			98,106
Pipelines	5 to 40	239,826			163,447
Compressors	4 to 20	11,793			8,957
Dock	20 to 40	7,942			—
Tanks, truck rack and piping	20 to 40	22,432			—
Equipment	8 to 20	6,293			4,785
Computer software	5	3,531			1,950
Total property, plant and equipment		407,598			285,984
Accumulated depreciation		(95,088		)	(62,165		)
Property, plant and equipment, net		$	312,510		$	223,819

Of the gross property, plant and equipment balances at December 31, 2013 and 2012 include $100.5 million and $26.1 million, respectively, were related to AlaTenn, Midla and High Point Gas Transmission, our FERC regulated interstate and intrastate assets.

Capitalized interest was $0.2 million and zero for the years ended December 31, 2013 and 2012, respectively.

Depreciation expense was $25.9 million and $21.4 million for the years ended December 31, 2013 and 2012, respectively.

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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%, 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. As part of the Blackwater Acquisition, we acquired long-lived terminal assets classified as held for sale. As of December 31, 2013, certain long-lived terminal assets were written down by $0.6 million to the estimated fair value less cost to sell. See Note 3 "Discontinued Operations".

During the first quarter of 2014, the board of directors of our General Partner gave approval to the management team to pursue the sale of certain gathering and processing assets for an amount less than the carrying value of the assets. As a result, these gathering and processing assets were written down by $3.0 million in the fourth quarter of 2013.

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 year ended December 31, 2013, we collected $1.1 million 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 consolidated statement of operations.

9. Goodwill and Intangible Assets, Net

Goodwill of $16.4 million was contributed to the Partnership as part of the Blackwater Acquisition. Goodwill is not amortized and is assessed for impairment annually or more frequently if an event or circumstance indicates that an impairment may have occurred. Goodwill was recorded as a result of the excess of the investment by ArcLight in Blackwater over the fair market value of the identifiable net assets and customer contracts acquired in 2012.

Intangible assets, net, consist of customer contracts contributed to the Partnership as part of the Blackwater acquisition. The intangible assets are amortized on a straight-line basis over the economic lives of the customer contracts, currently ranging from 5 months to thirty-five months. Intangible assets, net, consist of the following as of December 31, 2013 (in thousands):



	December 31, 2013
Customer contracts	$	12,101
Accumulated amortization	(8,419		)
Intangible assets, net	$	3,682

Amortization expense was $3.7 million for the period from April 15, 2013 to December 31, 2013.

Future amortization of the intangible assets, net will be $2.7 million in 2014 and $1.0 million in 2015.

10. Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities were as follows (in thousands):

F-24



	December 31,
	2013		2012
Accrued expenses	$	5,906	$	6,519
Gas imbalances payable	4,305		971
Other accrued expenses and other current liabilities	4,847		2,129
	$	15,058	$	9,619

11. 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.

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.

No assets were legally restricted for purposes of settling our ARO liabilities during the years ended December 31, 2013 and 2012. The following table is a reconciliation of the asset retirement obligations (in thousands):



	Year Ended December 31,
	2013		2012
Beginning asset retirement obligation	$	8,319	$	8,093
Liabilities assumed	25,763		452
Expenditures	—		(258		)
Accretion expense	554		32
Ending asset retirement obligation	$	34,636	$	8,319

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 $3.0 million and is presented in Other assets, net in our consolidated balance sheet as of December 31, 2013.

12. Debt Obligations

As of December 31, 2013, the Partnership's Credit Agreement (the "Credit Agreement") provides for a maximum borrowing equal to $200 million or subject to, among other restrictions, the requirement that our indebtedness not exceed 5.75 times adjusted consolidated EBITDA. We can elect to have loans under the our credit facility bear interest either at a Eurodollar-based rate plus a margin ranging from 1.50% to 3.75% depending on our total leverage ratio then in effect, or a base rate which is a fluctuating rate per annum equal to the highest of (a) the Federal Funds Rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its “prime rate”, or (c) the Eurodollar Rate plus 1.00% plus a margin ranging from 2.50% to 4.75% depending on the total leverage ratio then in effect. We also paid a commitment fee of 0.50% per annum on the undrawn portion of the revolving loan.

Our obligations under the credit facility are secured by a first mortgage in favor of the lenders in our real property. Advances made under the credit facility are guaranteed on a senior unsecured basis by certain of our subsidiaries (“Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors. The terms of the new credit facility include covenants that restrict our ability to make cash distributions and acquisitions in some circumstances. The remaining principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date, August 1, 2016.

The 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

F-25

covenants contained in the credit facility are (i) a total consolidated leverage ratio test (not to exceed 5.75 times) and (ii) a minimum interest coverage ratio test (not less than 2.50).

Please see Note 23 "Liquidity" for more details on our amendments to the Credit Agreement during the year ended December 31, 2013.

On April 15, 2013, we repaid approximately $12.5 million in outstanding borrowings in connection with the ArcLight Transactions. 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 13 "Partners' Capital" for more details.

For the years ended December 31, 2013, 2012 and 2011, the weighted average interest rate on borrowings under our credit facilities was approximately 4.53%, 4.09%, and 6.71%, respectively.

As of December 31, 2013 our consolidated total leverage was 3.70, which was in compliance with the consolidated total leverage ratio test in accordance with the leverage covenants as modified in the Fifth Amendment to the credit facility executed on December 17, 2013. As of December 31, 2013, we had approximately $130.7 million of outstanding borrowings under our credit facility and approximately $64.5 million of available borrowing capacity.

Other debt

Other debt represents insurance premium financing in the original amount of $2.3 million bearing interest at 3.95% per annum, which is repayable in equal monthly installments of approximately $0.3 million through the third quarter of 2014.

Our outstanding borrowings under the credit facility at December 31, 2013 and 2012, respectively, were (in thousands):



	December 31,
	2013		2012
Revolving credit facility	$	130,735	$	128,285
Other debt	2,048		—
Total debt	132,783		128,285
Less: current portion	2,048		—
Long-term debt	$	130,735	$	128,285

At December 31, 2013 and 2012, respectively, letters of credit outstanding under the credit facility were $4.8 million and $2.6 million, respectively.

In connection with our credit facility and amendments thereto, we have incurred $6.4 million in cumulative debt issuance costs through December 31, 2013, which are being amortized on a straight-line basis over the term of the credit facility.

13. Partners’ Capital

Our capital accounts are comprised of approximately 2% general partner interest and 98% limited partner interests. Our limited partners have limited rights of ownership as provided for under our partnership agreement and 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.

Series A Convertible Preferred Units

On April 15, 2013, the Partnership, our General Partner and AIM Midstream Holdings 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) 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 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.

F-26

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 to each Series A Unit will be the greater of the distribution to be made on a per unit basis to common unitholders or approximately $0.4125 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 $25.17 per unit, or a total distribution of $4.8 million for the year ended December 31, 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 $7.27 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.

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 were 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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· HPIP and AIM Midstream Holdings amended the LLC Amendment to, among other things, amend the Sharing Percentages (as defined therein) such that HPIP’s sharing percentage thereafter is 95% and AIM Midstream Holdings’s Sharing Percentage is 5%;

· HPIP transferred all of the 85.02% of our outstanding new IDRs held by HPIP to our General Partner such that our General Partner owns 100% of the outstanding new IDRs; and

Equity Offering

On December 11, 2013, the Partnership and certain of its affiliates entered into an underwriting agreement (the “Underwriting Agreement”) with Barclays Capital Inc. (the “Underwriter”), providing for the issuance and sale by the Partnership, and the purchase by the Underwriter, of 2,568,712 common units representing limited partner interests in the Partnership at a price to the public of $22.47 per common unit. The Partnership used the net proceeds of $54.9 million to fund a portion of the purchase price for Blackwater.

Outstanding Units

The numbers of units outstanding as of December 31, 2013, 2012 and 2011, respectively, were as follows (in thousands):



	December 31,
	2013	2012	2011
Series A convertible preferred units	5,279	—	—
Limited partner common units	7,414	4,639	4,561
Limited partner subordinated units	—	4,526	4,526
General partner units	185	185	185

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

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

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

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

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

We determined basic and diluted net income (loss) per general partner unit and limited partner unit as follows, (in thousands, except per unit amounts):



	Year Ended December 31,
	2013			2012			2011
Net loss from continuing operations	$	(31,151	)	$	(6,571	)	$	(12,030	)
Net income attributable to noncontrolling interests	633			256			—
Net loss from continuing operations attributable to the Partnership	(31,784		)	(6,827		)	(12,030		)
Less:
Distributions on Series A Preferred Units	24,117			—			—
General partner's distributions	464			322			864
General partner's share in undistributed loss	(1,708		)	(458		)	(1,112		)
Blackwater net loss from continuing operations	(716		)	—			—
Net loss from continuing operations available to limited partners	(53,941		)	(6,691		)	(11,782		)
Net (loss) income from discontinued operations available to limited partners	(1,893		)	313			325
Net loss available to limited partners	$	(55,834	)	$	(6,378	)	$	(11,457	)

Weighted average number of units used in computation of limited partners’ net loss per unit (basic and diluted)	7,525			9,113			6,997

Limited partners’ net loss from continuing operations per unit (basic and diluted)	$	(7.17	)	$	(0.73	)	$	(1.68	)
Limited partners’ net loss (income) from discontinued operations per unit (basic and diluted)	(0.25		)	0.03			0.04
Limited partners’ net loss per unit (basic and diluted)	$	(7.42	)	$	(0.70	)	$	(1.64	)

We corrected a calculation error in our weighted average units outstanding used in the net loss per unit computation for the year ended December 31, 2013 which was previously presented in our Annual Report on Form 10-K for the year ended December 31, 2013. Management notes that the calculation error impacted the fourth quarter 2013 weighted average units outstanding thereby resulting in a change to the limited partners’ net loss per common unit from $7.00 to $7.42, a difference of $0.42 or 6 percent, disclosed within the consolidated statement of operations for the year ended December 31, 2013 in the previously filed Form 10-K. Management does not believe that the revision is material to the 2013 consolidated statement of operations or the net income (loss) per limited partner unit and quarterly financial information (unaudited) footnote disclosures. The Partnership has revised the weighted average units outstanding utilized in the net loss per unit calculation herein. This revision has no impact on the Partnership’s reported consolidated balance sheet or consolidated cash flow statement as of and for the year ended December 31, 2013.

15. Long-Term Incentive Plan

Our general partner manages our operations and activities and employs the personnel who provide support to our operations. On November 2, 2009, the board of directors of our general partner adopted an LTIP for its employees, consultants and directors who perform services for it or its affiliates. On May 25, 2010, the board of directors of our general partner adopted an amended and restated LTIP. On July 11, 2012, the board of directors of our general partner adopted a second amended and restated long-term incentive plan that effectively increased available awards by 871,750 units. At December 31, 2013, 2012 and 2011, there were 855,089, 920,193 and 54,827 units, respectively, available for future grant under the LTIP.

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

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

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

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



	Year Ended December 31,
	2013		2012		2011
Outstanding at beginning of period	90,938		162,860		205,864
Granted	114,336		38,595		19,414
Forfeited	(18,320	)	(12,517	)	—
Vested	(111,425	)	(98,000	)	(62,418	)
Outstanding at end of period	75,529		90,938		162,860
Fair value per unit	$13.36 to $25.60		$14.70 to $21.40		$14.70 to $19.69

The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our units at the grant date. Compensation costs related to these awards including amortization, modification costs, DER payments and the cost of the DER buyout for the years ended December 31, 2011, was $3.4 million, which is classified as equity compensation expense in the consolidated statement of operations and the non-cash portion in partners’ capital on the consolidated balance sheet. There were no remaining DERs as of or for the year ended December 31, 2013.

In June 2011, certain existing LTIP grant agreements were modified to exclude the DER provision in exchange for a cash payment of $1.5 million, which has been included in equity compensation expense in the consolidated statement of operations.

The total fair value of vesting units at the time of vesting was $2.2 million, $1.9 million, and $1.2 million for the years ended December 31, 2013, 2012, and 2011, respectively.

The total compensation cost related to unvested awards not yet recognized at December 31, 2013, 2012, and 2011 was $0.9 million, $1.4 million, and $2.7 million, respectively, and the weighted average period over which this cost is expected to be recognized as of December 31, 2013, is approximately 1.9 years.

16. Post-Employment Benefits

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

The tables below detail the changes in the benefit obligation, the fair value of the plan assets and the recorded asset or liability of the OPEB Plan using the accrual method (in thousands):

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	Year Ended December 31,
	2013			2012			2011
Change in benefit obligation
Benefit obligation, beginning of period	$	472		$	466		$	869
Service cost	5			4			3
Interest cost	15			18			22
Actuarial (gain) loss	(29		)	22			(367		)
Plan amendments	126			—			—
Benefits paid	(57		)	(38		)	(61		)
Benefit obligation, end of period	$	532		$	472		$	466
Change in plan assets
Fair value of plan assets, beginning of period	$	1,552		$	1,432		$	1,319
Actual return on plan assets	(53		)	84			99
Employer’s contributions	90			90			90
Benefits paid	(61		)	(54		)	(76		)
Fair value of plan assets, end of period	$	1,528		$	1,552		$	1,432
Funded status
Funded status	$	996		$	1,080		$	966

The amounts of plan assets recognized in our consolidated balance sheets were as follows (in thousands):



	December 31,
	2013		2012		2011
Other assets	$	996	$	1,080	$	966

The amounts included in accumulated other comprehensive income at December 31, 2013, 2012 and 2011 that have not been recognized as components of net periodic benefit expenses are $(0.1) million, $(0.1) million and $0.4 million, respectively, which relate to net gains (losses).

Components of Net Periodic (Benefit) Cost and Other amounts Recognized in Other Comprehensive Income (in thousands):



	Year Ended December 31,
	2013			2012			2011
Net Periodic (Benefit) Cost
Service cost	$	5		$	4		$	3
Interest cost	15			18			22
Expected return on plan assets	(70		)	(67		)	(60		)
Amortization of net (gain) loss	(23		)	(43		)	(47		)
Net periodic (benefit) cost	$	(73	)	$	(88	)	$	(82	)
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
Net loss (gain)	$	247		$	64		$	(359	)
Total recognized in other comprehensive income	247			64			(359		)
Total recognized in net periodic benefit cost and other comprehensive income	$	174		$	(24	)	$	(441	)

The estimated net gain that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year is less than $0.1 million.

Economic assumptions

The assumptions made in measurement of the projected benefit obligations or assets of the OPEB Plan were as follows:

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	Year Ended December 31,
	2013		2012		2011
Discount rate	4.57	%	3.42	%	3.96	%
Expected return on plan assets	4.50	%	4.50	%	4.50	%
Health care trend rate	4.50	%	3.00	%	3.00	%

A one percent increase in the assumed medical and dental care trend rate would result in an increase of less than $0.1 million in the accumulated post-employment benefit obligations. A one percent decrease in the assumed medical and dental care trend rate would result in a decrease of less than $0.1 million in the accumulated post-employment benefit obligations.

The above table reflects the expected long-term rates of return on assets of the OPEB Plan on a weighted-average basis. The overall expected rates of return are based on the asset allocation targets with estimates for returns on equity and debt securities based on long-term expectations. We believe this rate approximates the return we will achieve over the long-term on the assets of our plans. Historically, we have used a discount rate that corresponds to one or more high quality corporate bond indices as an estimate of our expected long-term rate of return on plan assets for our OPEB Plan assets. For 2013, 2012 and 2011 we selected the discount rate using the Citigroup Pension Discount Curve, or CPDC. The CPDC spot rates represent the equivalent yield on high-quality, zero-coupon bonds for specific maturities. These rates are used to develop a single, equivalent discount rate based on the OPEB Plan’s expected future cash flows.

Expected future benefit payments

The following table presents the benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five years thereafter by the OPEB Plan (in thousands):



For the year ending
2014	$	28
2015	29
2016	28
2017	27
2018	27
Five years thereafter	157

The expected future benefit payments are based upon the same assumptions used to measure the projected benefit obligations of the OPEB Plan including benefits associated with future employee service.

Future contributions to the Plans

We expect to make contributions of $0.1 million to the OPEB Plan for the year ending December 31, 2014.

Plan assets

The weighted average asset allocation of our OPEB Plan at the measurement date by asset category, which are all classified as Level 1 investments, are as follows:



	December 31,
	2013		2012		2011
Fixed income (a)	70.1	%	72.2	%	72.1	%
Cash and short term assets (b)	29.9	%	27.8	%	27.9	%
Total	100.0	%	100.0	%	100.0	%


(a)	United States government securities, municipal corporate bonds and notes and asset backed securities


(b)	Cash and securities with maturities of one year or less

17. Income Taxes

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is a taxable entity. The Partnership follows the provisions of ASC 740 “Accounting For Income Taxes,” which provides for recognition of deferred tax assets and liabilities for deductible temporary timing differences, operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards net of a valuation allowance for any asset for which it is more likely than not will not be realized in the Partnership’s tax return. An analysis of the Partnership’s deferred taxes is as follows (in thousands):



	December 31, 2013
Deferred tax assets:
Net operating loss carryforwards	$	5,455
Other	182
Total deferred tax assets	5,637
Deferred tax liabilities:
Property, plant and equipment	9,022
Intangible assets	1,364
Total deferred tax liabilities	10,386
Deferred income tax liability, net	$	(4,749	)

At December 31, 2013, we had approximately $14.0 million of operating loss carryforwards. The net operating loss carryforwards would begin to expire in 2028. Some of our net operating losses may be limited by section 382 of the Internal Revenue Code due to the change in control that occurred in December 2013 and another change in control that occurred in October 2012.

Management assessed its various income tax positions and this assessment resulted in no adjustment to the tax asset or liability. The preparation of our various tax returns requires the use of estimates for federal and state income tax purposes. These estimates may be subjected to review by the respective taxing authorities. A revision, if any, to an estimate may result in an assessment of additional taxes, penalties and interest. At this time, a range in which our estimates may change is not quantifiable and a change, if any, is not expected to be material. We will account for interest and penalties relating to uncertain tax provisions in the current period statement of operations, as necessary. We have not recorded any adjustment to our financial statements as a result of this interpretation. We have tax years 2009 through 2012 remaining subject to examination by various federal and state tax jurisdictions, as applicable.

The provision for taxes is only attributable to the activities of certain affiliates of Blackwater. The details of the provision for taxes on income for the year ended December 31, 2013, are as follows (in thousands):



	Year Ended December 31, 2013
Net loss before income tax benefit	(31,646		)
Federal statutory rate	34		%
Federal income tax benefit at statutory rate	10,760
Reconciling items:
Partnership loss not subject to income tax	(10,350		)
Income not subject to corporate-level tax	222
State and local tax benefit	71
Return to provision true-ups	(175		)
Other	(33		)
Income tax benefit	$	495

The income tax provision related to continuing operations consist of the following (in thousands):

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	Year Ended December 31, 2013
Current income tax	$	—
Deferred income tax benefit	495

Effective income tax rate	1.6		%

The effective tax rate for the year ended December 31, 2013, was less than the statutory rate primarily due to the inclusion of income (loss) of the Partnership, which is not taxed at the subsidiary level that is subject to corporate income tax.

18. Commitments and Contingencies

Environmental matters

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to natural gas pipeline, NGL and crude pipelines and operations, as well as terminal 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 December 31, 2013, are presented below (in thousands):



	Payments Due by Period
	Total		2014		2015		2016		2017		2018		Thereafter
Operating leases and service contracts	$	6,149	$	959	$	1,012	$	814	$	810	$	584	$	1,970
ARO	34,636		—		—		7,867		—		—		26,769
Total	$	40,785	$	959	$	1,012	$	8,681	$	810	$	584	$	28,739

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



	Year Ended December 31,
	2013		2012		2011
Operating leases	$	1,051	$	941	$	803
ARO	554		32		1,393
	$	1,605	$	973	$	2,196

Gloria System Matter

We have been named in a lawsuit in the District Court of Jefferson Parish, Louisiana related to right of way maintenance and damages on our Louisiana Intrastate (Gloria) pipeline system related to a servitude agreement entered into by a predecessor in 1956. The landowner has sued us claiming that we have failed to maintain the pipeline right-of-way, allegedly causing erosion of the pipeline canal, erosion of levees, and deterioration of the adjacent marshland. The landowner seeks damages for the cost to narrow the pipeline canal, rebuild the pipeline levees, and restore the damaged marsh.

While we cannot predict the ultimate outcome of this litigation, we disagree with the damage claims asserted in the lawsuit and we are vigorously defending ourselves.

Bazor Ridge Emissions Matter

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

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

19. 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 years ended December 31, 2013, 2012, and 2011 administrative and operational services expenses of $14.2 million, $12.5 million and $9.6 million, respectively, were charged to us by our general partner. For the year ended December 31, 2013, 2012 and 2011, our general partner incurred approximately $1.8 million, $0.4 million and zero of costs associated with certain business development activities, respectively. 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.

In connection with the Blackwater Acquisition, our General Partner contributed the net assets of Blackwater which were recorded at their historical book value of $22.7 million for consideration of $63.9 million, of which $27.7 million was accounted for as a cash distribution to the general partner. The consideration also included 125,500 limited partner units which were accounted for as a non-cash distribution to the general partner at a fair value of $3.1 million. See read Note 2. "Acquisitions" for more information.

On October 9, 2012, Blackwater entered into a Convertible Promissory Note (the “BWHD Note”) with ArcLight Energy Partners Fund V, L.P. (“AL Fund V”), in the amount of $20.0 million. AL Fund V is a related party to the Partnership. The BWHD Note was paid off during the fourth quarter of 2013 as part of the Blackwater Acquisition.

Prior to our IPO, we had entered into an advisory services agreement with the former 100% interest owner of General Partner, American Infrastructure MLP Management, L.L.C., American Infrastructure MLP PE Management, L.L.C., and American Infrastructure MLP Associates Management, L.L.C., as the advisors. The agreement provided for the payment of $0.3 million in 2010 and annual fees of $0.3 million plus annual increases in proportion to the increase in budgeted gross revenues thereafter. In exchange, the advisors agreed to provide us services in obtaining equity, debt, lease and acquisition financing, as well as providing other financial, advisory and consulting services. Under this agreement, $0.2 million had been recorded to selling, general and administrative expenses for the year ended December 31, 2011.

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

20. Reporting Segments

Our operations are located in the United States and are organized into three reporting segments: (i) Gathering and Processing, (ii) Transmission, and (iii) Terminals.

Gathering and Processing

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

Transmission

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

Terminals

Our Terminals segment provides above-ground storage services at our marine terminals that support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products, including crude oil, bunker fuel, distillates, chemicals and agricultural products.

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

The following tables set forth our segment information for the periods indicated (in thousands):



	Year Ended December 31, 2013
	Gathering and Processing			Transmission			Terminals (a)		Total
Total revenue	$	192,446		$	90,377		$	9,831	$	292,654
Less:
COMA Income	689			154			—		843
Unrealized loss on commodity derivatives	(1,041		)	—			—		(1,041		)
Purchases of natural gas, NGL's and condensate	156,334			57,815			—		214,149
Direct operating expenses	—			—			2,080		2,080
Segment gross margin (a)	36,464			32,408			7,751		76,623
Direct operating expenses	(14,214		)	(13,259		)	—		(27,473		)
COMA Income									843
Unrealized loss on commodity derivatives									(1,041		)
Selling, general and administrative expenses									(21,402		)
Equity compensation expense									(2,094		)
Depreciation, amortization and accretion expense									(29,999		)
Gain on involuntary conversion of property, plant and equipment									343
Loss on impairment of property, plant and equipment									(18,155		)
Interest expense									(9,291		)
Income tax benefit									495
Loss from operations of disposal groups, net of tax									(2,255		)
Net loss									(33,406		)
Less: Net income attributable to non-controlling interests									633
Net loss attributable to the Partnership									$	(34,039	)


(a)	Terminals segment amounts are for the period from April 15, 2013 to December 31, 2013.

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	Year Ended December 31, 2012
	Gathering and Processing			Transmission			Total
Total revenue	$	145,714		$	52,529		$	198,243
Less:
COMA Income	673			2,700			3,373
Unrealized gain on commodity derivatives	992			—			992
Purchases of natural gas, NGL's and condensate	108,656			36,516			145,172
Segment gross margin (a)	35,393			13,313			48,706
Direct operating expenses	(11,767		)	(5,031		)	(16,798		)
COMA Income							3,373
Unrealized gain on commodity derivatives							992
Selling, general and administrative expenses							(14,309		)
Equity compensation expense							(1,783		)
Depreciation, amortization and accretion expense							(21,284		)
Loss on involuntary conversion of property, plant and equipment							(1,021		)
Gain on sale of assets, net							123
Interest expense							(4,570		)
Income from operations of disposal groups							319
Net loss							(6,252		)
Less: Net income attributable to non-controlling interests							256
Net loss attributable to the Partnership							$	(6,508	)



	Year Ended December 31, 2011
	Gathering and Processing			Transmission			Total
Total revenue	$	160,953		$	66,766		$	227,719
Less:
Realized loss on early termination of commodity derivatives	(2,998		)	—			(2,998		)
Unrealized loss on commodity derivatives	(541		)	—			(541		)
Purchases of natural gas, NGL's and condensate	134,369			53,029			187,398
Segment gross margin (a)	30,123			13,737			43,860
Direct operating expenses	(6,199		)	(5,220		)	(11,419		)
Realized loss on early termination of commodity derivatives							(2,998		)
Unrealized loss on commodity derivatives							(541		)
Selling, general and administrative expenses							(11,082		)
Advisory services agreement termination fee							(2,500		)
Transaction expenses							—
Equity compensation expense							(3,357		)
Depreciation, amortization and accretion expense							(20,449		)
Gain on acquisition of assets							565
Loss on sale of assets, net							399
Interest expense							(4,508		)
Income from operations of disposal groups							332
Net loss attributable to the Partnership							$	(11,698	)

F-37

(a)

Segment gross margin for our Gathering and Processing segment consists of revenue less purchases of natural gas, NGLs and condensate and COMA. Segment gross margin for our Transmission segment consists of revenue, less purchases of natural gas and COMA. Segment gross margin for our Terminals segment consists of revenue, less direct operating expenses. 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 construction, operating and maintenance agreement (“COMA”) income. Effective January 1, 2011, we changed our segment gross margin measure to exclude unrealized non-cash mark-to-market adjustments related to our commodity derivatives. Effective April 1, 2011, we changed our segment gross margin measure to exclude realized early termination costs on commodity derivatives.

For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use gross margin to evaluate our operating performance, please read Item 7. "Management's Discussion and Analysis, How We Evaluate Our Operations”.

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

The following table summarizes the percentage of revenue earned from those customers in each segment that exceed 10% or greater of the Partnership's consolidated segment revenue for the each of the periods presented below:



	Year Ended December 31,
	2013		2012		2011
Gathering and Processing:
Customer A	43	%	40	%	55	%
Customer B	19	%	11	%	—
Customer D	—		12	%	16	%
Other	38	%	37	%	29	%
Total	100	%	100	%	100	%
Transmission:
Customer C	39	%	50	%	57	%
Customer D	16	%	22	%	22	%
Customer E	—		10	%	—
Other	45	%	18	%	21	%
Total	100	%	100	%	100	%
Terminals:
Customer F	20	%	—		—
Customer B	17	%	—		—
Customer G	16	%	—		—
Customer H	13	%	—		—
Other	34	%	—		—
Total	100	%	—		—

21. Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2013 and 2012 are as follows (in thousands, except per unit amounts):

F-38



	First Quarter (a)			Second Quarter			Third Quarter			Fourth Quarter
Year Ended December 31, 2013
Total revenues	$	59,402		$	77,608		$	79,536		$	76,108
Gross margin (b)	12,476			19,158			21,380			23,609
Operating (loss) income	(1,740		)	(17,780		)	(210		)	(2,625		)
Net loss from continuing operations	(3,471		)	(19,996		)	(2,632		)	(5,052		)
Income (loss) from operations of disposal groups	73			(1,930		)	91			(489		)
Net income attributable to noncontrolling interest	155			188			190			100
Net loss attributable to the Partnership	(3,553		)	(22,114		)	(2,731		)	(5,641		)
General partner’s interest in net loss	(70		)	(905		)	(221		)	(209		)
Limited partners’ interest in net loss	$	(3,483	)	$	(21,209	)	$	(2,510	)	$	(5,432	)

Limited partners’ (loss) income per unit:
Loss from continuing operations	$	(0.39	)	$	(4.00	)	$	(0.82	)	$	(1.43	)
Income (loss) from discontinued operations	0.01			(0.20		)	0.02			—
Net loss (c)	$	(0.38	)	$	(4.20	)	$	(0.80	)	$	(1.43	)
Year Ended December 31, 2012
Total revenues	$	44,857		$	43,322		$	53,401		$	56,663
Gross margin (b)	12,560			11,253			12,979			11,914
Operating income (loss)	2,417			3,077			(2,513		)	(4,982		)
Net income (loss) from continuing operations	1,660			2,252			(4,014		)	(6,469		)
Income (loss) from operations of disposal groups	31			75			(12		)	225
Net income (loss) attributable to noncontrolling interest	—			—			249			7
Net income (loss) attributable to the Partnership	1,691			2,327			(4,275		)	(6,251		)
General partner’s interest in net income (loss)	34			46			(85		)	(124		)
Limited partners’ interest in net income (loss)	$	1,657		$	2,281		$	(4,190	)	$	(6,127	)

Limited partners’ income (loss) per unit:
Income (loss) from continuing operations	$	0.18		$	0.24		$	(0.46	)	$	(0.69	)
Income (loss) from discontinued operations	—			0.01			—			0.02
Net income (loss)	$	0.18		$	0.25		$	(0.46	)	$	(0.67	)

(a)

During the fourth quarter of 2012, we identified revenues in the amount of $0.3 million associated with proceeds received in connection with COMA reimbursable projects that were incorrectly recognized in the first quarter of 2012 that should have been recognized ratably during each of the succeeding quarters of 2012 for approximately $0.1 million per quarter. In addition, we recorded in the first quarter of 2012 and for the year ended December 31, 2012, out-of-period adjustments amounting to $0.1 million for the correction of immaterial errors associated with additional depreciation expense and selling, general and administrative expense. Based upon our evaluation of relevant factors, we concluded that these errors were not material to any previously issued and current consolidated financial statements.


(b)	For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use gross margin to evaluate our operating performance, please read Item 7. "Management's Discussion and Analysis, How We Evaluate Our Operations”.

(c)

F-39

information (unaudited) footnote disclosure. The Partnership has revised the weighted average units outstanding utilized in the net loss per unit calculation herein.

22. Subsidiary Guarantors

The Partnership filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities, which was effective in the fourth quarter of 2012. The subsidiaries of the Partnership (the "Subsidiaries") are co-registrants with the Partnership, and the registration statement registers 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. As of December 31, 2013, the Subsidiaries have an investment in the non-guarantor subsidiaries equal to a 92.2% 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 provide 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 condensed consolidating financial information, the Partnership's investments in its Subsidiaries and the guarantor subsidiaries' investment in its 92.2% 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 December 31, 2013 and 2012, and for those years ended is as follows (in thousands):

F-40



	Consolidating Balance Sheet
	December 31, 2013
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
Assets
Current assets
Cash and cash equivalents	$	1	$	392	$	—	$	—		$	393
Accounts receivable	—		4,461		2,361		—			6,822
Unbilled revenue	—		17,325		4,680		—			22,005
Risk management assets	—		473		—		—			473
Other current assets	84		6,942		555		(84		)	7,497
Current assets held for sale	—		1,268		—		—			1,268
Total current assets	85		30,861		7,596		(84		)	38,458
Property, plant and equipment, net	—		254,465		58,045		—			312,510
Note receivable	27,315		—		—		(27,315		)	—
Goodwill	—		16,447		—		—			16,447
Intangible assets, net	—		3,682		—		—			3,682
Other assets, net	—		8,321		743		—			9,064
Noncurrent assets held for sale, net	—		1,914		—		—			1,914
Investment in subsidiaries	142,758		57,750		—		(200,508		)	—
Total assets	$	170,158	$	373,440	$	66,384	$	(227,907	)	$	382,075

Liabilities and Partners’ Capital
Current liabilities
Accounts payable	$	30	$	2,902	$	329	$	—		$	3,261
Accrued gas purchases	—		13,290		3,104		—			16,394
Accrued expenses and other current liabilities	1,478		13,563		101		(84		)	15,058
Current portion of long-term debt	—		2,048		—		—			2,048
Risk management liabilities	—		423		—		—			423
Current liabilities held for sale	—		1,106		—		—			1,106
Total current liabilities	1,508		33,332		3,534		(84		)	38,290
Risk management liabilities - long term	—		101		—		—			101
Asset retirement obligation	—		34,164		472		—			34,636
Other liabilities	—		191		—		—			191
Long-term debt	—		158,050		—		(27,315		)	130,735
Deferred tax liability	—		4,749		—		—			4,749
Noncurrent liabilities held for sale	—		95		—		—			95
Total liabilities	1,508		230,682		4,006		(27,399		)	208,797
Convertible preferred units
Series A convertible preferred units	94,811		—		—		—			94,811
Total partners' capital	73,839		142,758		57,750		(200,508		)	73,839
Noncontrolling interest	—		—		4,628		—			4,628
Total equity	73,839		142,758		62,378		(200,508		)	78,467
Total liabilities and partners' capital	$	170,158	$	373,440	$	66,384	$	(227,907	)	$	382,075

F-41



	Consolidating Balance Sheet
	December 31, 2012
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		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 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
Partners' capital
Total partners' capital	80,165		80,164		51,613		(131,777		)	80,165
Noncontrolling interest	—		—		7,438		—			7,438
Total equity	80,165		80,164		59,051		(131,777		)	87,603
Total liabilities and partners' capital	$	80,165	$	245,475	$	62,833	$	(131,777	)	$	256,696

F-42



	Consolidating Statements of Operations
	Year ended December 31, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
Revenue	$	—		$	242,395		$	56,080	$	(5,849	)	$	292,626
Unrealized gain on commodity derivatives	—			(369		)	397		—			28
Total revenue	—			242,026			56,477		(5,849		)	292,654
Operating expenses:
Purchases of natural gas, NGLs and condensate	—			175,551			44,447		(5,849		)	214,149
Direct operating expenses	—			25,180			4,373		—			29,553
Selling, general and administrative expenses	—			21,402			—		—			21,402
Equity compensation expense	—			2,094			—		—			2,094
Depreciation, amortization and accretion expense	—			28,338			1,661		—			29,999
Total operating expenses	—			252,565			50,481		(5,849		)	297,197
Gain on involuntary conversion of property, plant and equipment	—			343			—		—			343
Loss on impairment of property, plant and equipment	—			(18,155		)	—		—			(18,155		)
Operating (loss) income	—			(28,351		)	5,996		—			(22,355		)
Other (expenses) income:
Earnings from consolidated affiliates	(34,123		)	5,363			—		28,760			—
Interest income (expense)	84			(9,375		)	—		—			(9,291		)
Net (loss) income before income tax benefit	(34,039		)	(32,363		)	5,996		28,760			(31,646		)
Income tax benefit	—			495			—		—			495
Net (loss) income from continuing operations	(34,039		)	(31,868		)	5,996		28,760			(31,151		)
Discontinued operations, net of tax	—			(2,255		)	—		—			(2,255		)
Net (loss) income	(34,039		)	(34,123		)	5,996		28,760			(33,406		)
Net income attributable to noncontrolling interests	—			—			633		—			633
Net (loss) income attributable to the Partnership	$	(34,039	)	$	(34,123	)	$	5,363	$	28,760		$	(34,039	)

F-43



	Consolidating Statements of Operations
	Year ended December 31, 2012
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
Revenue	$	—		$	170,569		$	25,441	$	(1,167	)	$	194,843
Unrealized gain on commodity derivatives	—			3,400			—		—			3,400
Total revenue	—			173,969			25,441		(1,167		)	198,243
Operating expenses:
Purchases of natural gas, NGLs and condensate	—			126,649			19,690		(1,167		)	145,172
Direct operating expenses	—			13,895			2,903		—			16,798
Selling, general and administrative expenses	—			14,309			—		—			14,309
Equity compensation expense	—			1,783			—		—			1,783
Depreciation, amortization and accretion expense	—			20,474			810		—			21,284
Total operating expenses	—			177,110			23,403		(1,167		)	199,346
Loss on involuntary conversion of property, plant and equipment	—			(1,021		)	—		—			(1,021		)
Gain on sale of assets, net	—			123			—		—			123
Operating (loss) income	—			(4,039		)	2,038		—			(2,001		)
Other (expenses) income:
Earnings from consolidated affiliates	(6,508		)	1,782			—		4,726			—
Interest expense	—			(4,570		)	—		—			(4,570		)
Net income from continuing operations	(6,508		)	(6,827		)	2,038		4,726			(6,571		)
Discontinued operations	—			319			—		—			319
Net (loss) income	(6,508		)	(6,508		)	2,038		4,726			(6,252		)
Net income attributable to noncontrolling interests	—			—			256		—			256
Net (loss) income attributable to the Partnership	$	(6,508	)	$	(6,508	)	$	1,782	$	4,726		$	(6,508	)

F-44



	Consolidated Statements of Comprehensive Income
	Year ended December 31, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments		Consolidated
Net (loss) income	$	(34,039	)	$	(34,123	)	$	5,996	$	28,760	$	(33,406	)
Unrealized loss on post retirement benefit plan assets and liabilities	(247		)	(247		)	—		247		(247		)
Comprehensive (loss) income	(34,286		)	(34,370		)	5,996		29,007		(33,653		)
Less: Comprehensive income attributable to noncontrolling interests	—			—			633		—		633
Comprehensive (loss) income attributable to the Partnership	$	(34,286	)	$	(34,370	)	$	5,363	$	29,007	$	(34,286	)



	Consolidated Statements of Comprehensive Income
	Year ended December 31, 2012
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments		Consolidated
Net (loss) income	$	(6,508	)	$	(6,508	)	$	2,038	$	4,726	$	(6,252	)
Unrealized loss on post retirement benefit plan assets and liabilities	(64		)	(64		)	—		64		(64		)
Comprehensive (loss) income	(6,572		)	(6,572		)	2,038		4,790		(6,316		)
Less: Comprehensive income attributable to noncontrolling interests	—			—			256		—		$	256
Comprehensive (loss) income attributable to the Partnership	$	(6,572	)	$	(6,572	)	$	1,782	$	4,790	$	(6,572	)

F-45



	Statement of Cash Flows
	Year ended December 31, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash provided by operating activities	$	—		$	13,681		$	3,542		—			17,223
Cash flows from investing activities
Additions to property, plant and equipment	—			(26,322		)	(874		)	—			(27,196		)
Proceeds from disposals of property, plant and equipment	—			500			—			—			500
Proceeds from property damage insurance recoveries	—			482			—			—			482
Restricted cash	—			(2,000		)	—			—			(2,000		)
Net contributions from affiliates	43,770			—			—			(43,770		)	—
Net distributions to affiliates	(82,321		)	—			—			82,321			—
Net cash provided by (used in) investing activities	(38,551		)	(27,340		)	(874		)	38,551			(28,214		)
Cash flows from financing activities
Net contributions from affiliates	—			82,321			—			(82,321		)	—
Net distributions to affiliates	—			(42,515		)	(1,255		)	43,770			—
Proceeds from issuance of common units to public, net of offering costs	54,853			—			—			—			54,853
Unitholder contributions	13,075			—			—			—			13,075
Unitholder distributions	(16,120		)	—			—			—			(16,120		)
Issuance of Series A Convertible Preferred Units	14,393			—			—			—			14,393
Unitholder distributions for Blackwater transaction	(27,650		)	—			—			—			(27,650		)
Acquisition of noncontrolling interest	—			—			(752		)	—			(752		)
Net distributions to noncontrolling interest owners	—			—			(661		)	—			(661		)
LTIP tax netting unit repurchase	—			(630		)	—			—			(630		)
Deferred debt issuance costs	—			(2,113		)	—			—			(2,113		)
Payments on other loan	—			(2,640		)	—			—			(2,640		)
Payments on loans to affiliates	—			(20,000		)	—			—			(20,000		)
Borrowings on other debt	—			3,795			—			—			3,795
Payments on bank loans	—			(34,730		)	—			—			(34,730		)
Borrowings on bank loans	—			27,546			—			—			27,546
Payments on long-term debt	—			(131,571		)	—			—			(131,571		)
Borrowings on long-term debt	—			134,021			—			—			134,021
Net cash used in financing activities	$	38,551		$	13,484		$	(2,668	)	$	(38,551	)	10,816
Net decrease in cash and cash equivalents	—			(175		)	—			—			(175		)
Cash and cash equivalents
Beginning of period	1			575			—			—			576
End of period	$	1		$	400		$	—		$	—		$	401
Supplemental cash flow information
Interest payments	$	—		6,416			—			—			$	6,416
Supplemental non-cash information
Decrease in accrued property, plant and equipment	$	—		$	(5,181	)	$	—		$	—		$	(5,181	)
Net assets contributed in the Blackwater Acquisition (See Note 2)	22,121			—			—			—			22,121
Net assets contributed in exchange for the issuance of Series A convertible preferred units (see Note 2)	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	4,811			—			—			—			4,811

F-46



	Statement of Cash Flows
	Year ended December 31, 2012
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash provided by operating activities	$	—		$	16,310		$	2,038		—			18,348
Cash flows from investing activities
Cost of acquisition, net of cash acquired	—			(51,377		)	—			—			(51,377		)
Additions to property, plant and equipment	—			(10,870		)	(835		)	—			(11,705		)
Proceeds from disposals of property, plant and equipment	—			128			—			—			128
Proceeds from property damage insurance recoveries	—			527			—			—			527
Net contributions from affiliates	16,070			—			—			(16,070		)	—
Net distributions to affiliates	(13		)	—			—			13			—
Net cash provided by (used in) investing activities	16,057			(61,592		)	(835		)	(16,057		)	(62,427		)
Cash flows from financing activities
Net contributions from affiliates	—			13			—			(13		)	—
Net distributions to affiliates	—			(15,092		)	(978		)	16,070			—
Unit holder contributions	13			—			—			—			13
Unit holder distributions	(16,070		)	—			—			—			(16,070		)
Net distributions to noncontrolling interest owners	—			—			(225		)	—			(225		)
LTIP tax netting unit repurchase	—			(385		)	—			—			(385		)
Deferred debt issuance costs	—			(1,564		)	—			—			(1,564		)
Payments on long-term debt	—			(59,230		)	—			—			(59,230		)
Borrowings on long-term debt	—			121,245			—			—			121,245
Net cash (used in) provided by financing activities	$	(16,057	)	$	44,987		$	(1,203	)	$	16,057		$	43,784
Net decrease in cash and cash equivalents	—			(295		)	—			—			(295		)
Cash and cash equivalents
Beginning of period	1			870			—			—			871
End of period	$	1		$	575		$	—		$	—		$	576
Supplemental cash flow information
Interest payments	$	—		$	3,185		—			—			$	3,185
Supplemental non-cash information
Increase in accrued property, plant and equipment	$	—		$	6,968		$	—		$	—		$	6,968
Increase in receivables for reimbursable construction in progress projects	—			141			—			—			141

23. Liquidity

The principal indicators of our liquidity at December 31, 2013, were our cash on hand and availability under our credit facility. As of December 31, 2013, our available liquidity was $64.9 million, comprised of cash on hand of $0.4 million and $64.5 million available under our credit facility.

We are required to comply with certain financial covenants and ratios in our credit facility. As of December 31, 2012, the total leverage ratio test, 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 $128.3 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 the Partnership's Credit Agreement (the "Credit Agreement"), dated as of December 26, 2012, (the “Third Amendment”). The Third Amendment provided for a waiver of the Partnership's compliance with the Consolidated Total Leverage Ratio with respect to the quarter ending December 31, 2012, and subsequently extended to April 15, 2013. 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.

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On April 15, 2013, we entered into the Fourth Amendment (the “Fourth Amendment”) to the Credit Agreement. The Fourth Amendment amended the Credit Agreement to (i) allowed for the transactions contemplated under the Contribution Agreement and the issuance of additional Series A Preferred Units as paid-in-kind distributions, (ii) required the Partnership to repay borrowings under the Credit Agreement with the proceeds of certain asset sales and debt issuances, (iii) increased the maximum allowable consolidated total leverage ratio, including allowing for a higher maximum consolidated total leverage ratio for the seven fiscal quarters starting with the second quarter of 2013 and (iv) reset the applicable interest rates for borrowings based on the consolidated total leverage ratio for each quarter. In addition, the Fourth Amendment provides for a decrease in the aggregate commitments under the Credit Agreement from $200 million to $175 million if, on or prior to September 30, 2013, the Partnership has not received from AIM Midstream Holdings a $12.5 million equity contribution and used that contribution to prepay amounts outstanding under the Credit Agreement. On April 15, 2013, we repaid approximately $12.5 million in outstanding borrowings under the credit agreement in connection with the ArcLight Transactions.

On December 17, 2013, we entered into the Fifth Amendment (the “Fifth Amendment”) to the Credit Agreement. The Fifth Amendment amends the Credit Agreement to, among other things, reflect the acquisition of Blackwater and its subsidiaries pursuant to the Blackwater Merger Agreement. The Fifth Amendment (i) revised the definition of the term “Consolidated EBITDA,” which is used in the calculation of certain financial covenants in the Credit Agreement, to specify how the Consolidated EBITDA of Blackwater would be used to calculate Consolidated EBITDA through the quarter ended on June 30, 2014; (ii) provided that although the Credit Agreement would otherwise require it, Blackwater Maryland, LLC (“Blackwater Maryland”), a subsidiary of Blackwater Holdings, would not be required to deliver any mortgages or deeds of trust on any property of Blackwater Maryland, but that Blackwater Maryland would not grant to any other party any liens on its real property other than liens otherwise permitted by the Credit Agreement; (iii) permitted certain third-party liens to exist on property of Blackwater New Orleans, L.L.C., a subsidiary of Blackwater Holdings; (iv) provided that no more than $20.0 million of borrowings under the Credit Agreement could be used for the payment of the purchase price in connection with the Blackwater Transaction; and (v) required the Partnership and American Midstream, LLC to perform certain covenants after the effective date of the Fifth Amendment to ensure that Blackwater Holdings and its subsidiaries become guarantors of the obligations of the Partnership and American Midstream, LLC under the Credit Agreement and that they secure their obligations and those of the Partnership and American Midstream, LLC under the Credit Agreement with the assets of Blackwater Holdings and its subsidiaries. In addition, the Fifth Amendment removed certain provisions of the Credit Agreement to provide certain financial and operating information of the Partnership on a monthly basis for any month after 2013 in which the Consolidated Total Leverage Ratio of the Partnership is in excess of 4.00 to 1.00.

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. The Partnership believes that the consummation of the (i) Blackwater Acquisition, (ii) Equity Restructuring, (iii) Offering and (iv) ArcLight Transactions will allow it to maintain compliance with the consolidated total leverage to EBTIDA required under the facility.

24. Subsequent Events

Distribution

On January 22, 2014, we announced that the board of directors of our General Partner declared a quarterly cash distribution of $0.4525 per unit for the fourth quarter ended December 31, 2013, or $1.81 per unit on an annualized basis. The cash distribution was paid on February 14, 2014, to unitholders of record as of the close of business on February 7, 2014, together with our General Partner. The ex-dividend date was February 5, 2014.

Completion of PVA Acquisition

On January 31, 2014, the Partnership acquired, from Penn Virginia Corporation ("PVA"), approximately 120 miles of high- and low-pressure pipelines ranging from 4 to 8 inches in diameter with over 9,000 horsepower of leased compression, and associated facilities located in the Eagle Ford shale in Gonzales and Lavaca Counties, Texas. The consideration for the PVA Asset Acquisition was financed with the net proceeds of the Partnership’s January 2014 equity offering of $87.3 million and the proceeds from the issuance to our General Partner of 1,168,225 Series B PIK Units representing series B limited partnership interests in the Partnership. The Series B PIK Units have the right to share in distributions from the Partnership on a pro rata basis with holders of the Partnership’s common units and will convert into common units on a one-for-one basis on the second anniversary of the initial

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issuance The conflicts committee of our General Partner’s board of directors approved the Series B PIK Unit issuance and the transactions contemplated thereby.

Purchase and Sale Agreement

In the fourth quarter of 2013, a subsidiary of the Partnership entered into a purchase and sale agreement with Transcontinental Gas Pipe Line Company, LLC ("Transco"), a subsidiary of Williams Partners, LP, to acquire natural gas pipeline facilities for approximately $6.5 million that are contiguous to, and connect with, our High Point system in offshore Louisiana. The closing of the purchase and sale agreement was subject to FERC approval of Transco's application to abandon by sale to us the pipeline facilities and to permit the facilities to serve a gathering function, exempt from FERC's jurisdiction. The FERC granted approval of Transco's application during the first quarter of 2014, and the purchase and sale agreement is expected to close by the end of the first quarter of 2014.

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