UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 8-K
 
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): August 11, 2014
 
AMERICAN MIDSTREAM PARTNERS, LP
(Exact name of registrant as specified in its charter)

	

Delaware	 	001-35257	 	27-0855785	
(State or other jurisdiction
of incorporation)	 	(Commission
File Number)	 	(I.R.S. Employer
Identification No.)	
 	 	
1400 16th Street, Suite 310
Denver, Colorado	 	80202	
(Address of principal executive offices)	 	(Zip Code)	

Registrant’s telephone number, including area code: (720) 457-6060
Not applicable
(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

		
¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)	

		
¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)	

		
¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))	

		
¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))	

 
Item 2.02 Results of Operations and Financial Condition

On August 11, 2014 , American Midstream Partners, LP issued a press release announcing its financial results for the three and six months ended June 30, 2014 . A copy of the press release covering such announcement and certain other matters is attached hereto as Exhibit 99.1. The press release contains financial measures that are not presented in accordance with accounting principles generally accepted in the United States of America, or GAAP, for the applicable periods presented, including gross margin, adjusted EBITDA, distributable cash flow, and segment gross margin. The most directly comparable GAAP financial measures to gross margin, adjusted EBITDA, distributable cash flow, and segment gross margin is net income attributable to the Partnership, which is presented in the attached press release and prominently below for the applicable periods presented.

AMERICAN MIDSTREAM PARTNERS, LP
GAAP FINANCIAL MEASURES
(Unaudited, in thousands)

	
																
 	Three months ended June 30,	 	Six months ended June 30,	
 	2014	 	2013	 	2014	 	2013	
Net loss attributable to the Partnership	$	(1,667	)	 	$	(22,114	)	 	$	(1,267	)	 	$	(25,667	)	

The information in this report, including the Exhibit attached hereto, shall not be deemed “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 (the “Exchange Act”) nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933, or the Exchange Act, except as specifically identified therein as being incorporated by reference.

Item 9.01 Financial Statements and Exhibits
(d) Exhibits.

See “Index to Exhibits” attached to this Current Report on Form 8-K, which is incorporated by reference herein.

SIGNATURES

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

	
					
 	 	American Midstream Partners, LP	
 	 	
 	 	By: American Midstream GP, LLC,	
 	 	its General Partner	
Date:	 	 	
August 11, 2014	 	By:	 	/s/ Daniel C. Campbell	
 	 	Name:	 	Daniel C. Campbell	
 	 	Title:	 	Senior Vice President and Chief Financial Officer	

Exhibit Index

	
					
Exhibit Number	  	Description	 	
99.1	 	  	American Midstream Partners, LP press release dated	August 11, 2014	

American Midstream Reports Second Quarter 2014 Financial Results
Partnership Provides Update to 2014 Guidance

DENVER, CO – August 11, 2014 - American Midstream Partners, LP (NYSE: AMID) ("Partnership") today reported financial results for the three and six months ended June 30, 2014 .

Gross margin (a non-GAAP measure) for the second quarter of 2014 was $22.2 million , an increase of $3.9 million , or 21.3 percent, compared to $18.3 million in the prior year period. For the six months ended June 30, 2014 , gross margin was $45.2 million compared to $31.0 million in the prior year period, an increase of $14.2 million, or 45.8 percent. The increase in gross margin for the three and six months ended June 30, 2014 was primarily due to higher gross margin in the Partnership's Gathering and Processing segment attributable to the January 2014 acquisition of the Lavaca System from Penn Virginia Corporation ("Penn Virginia") in the Eagle Ford Shale in Texas, higher gross margin in the Partnership's Transmission segment as a result of increased throughput from the April 2013 acquisition of the High Point System, and incremental gross margin from the Terminals segment associated with the December 2013 acquisition of Blackwater Midstream.

The Partnership reported Adjusted EBITDA (a non-GAAP measure) for the three and six months ended June 30, 2014 of $6.8 million and $17.4 million , respectively, compared to $7.5 million and $12.7 million for the same periods in 2013. The decrease in Adjusted EBITDA for the three months ended June 30, 2014 was primarily attributable to increased direct operating expenses related to maintenance on two processing plants during the second quarter 2014, increased costs associated with leased compression to support accelerated drilling activity by the producer customer on the Lavaca System, and increased selling, general, and administrative expenses to support the significant recent and near-term growth of the Partnership. The increase in Adjusted EBITDA for the six months ended June 30, 2014 was primarily attributable to the above-mentioned acquisitions, partially offset by increased direct operating expenses to support the associated growth.

Distributable cash flow ("DCF") (a non-GAAP measure) for the three and six months ended June 30, 2014 was $4.2 million and $10.7 million , respectively, representing a coverage ratio of 0.73 and 1.08 , respectively. The second quarter 2014 distribution of $5.8 million , or $0.4625 per common unit, an increase of 6.9 percent per unit over the second quarter 2013 distribution, will be paid on August 14, 2014 to unitholders of record as of August 7, 2014.

Reconciliations of the non-GAAP measures gross margin, Adjusted EBITDA, and DCF to Net income (loss) attributable to the Partnership, the most directly comparable GAAP measure, are provided at the end of this press release.

Net loss attributable to the Partnership for the three and six months ended June 30, 2014 was $1.7 million and $1.3 million , respectively, compared to net loss of $22.1 million and $25.7 million for the same periods in 2013. The net loss attributable to the Partnership for the three and six months ended June 30, 2013 was primarily a result of non-cash impairment charges on certain non-strategic gathering assets of $15.2 million in the second quarter of 2013. Excluding the impact of these impairments, the increase in net income for the three and six months ended June 30, 2014 was primarily attributable to the same reasons for the increase in gross margin discussed above.

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BUSINESS HIGHLIGHTS

Acquisition of DCP Assets

The Partnership announced today that it completed the acquisition of entities holding offshore oil gathering assets from an affiliate of DCP Midstream, LLC (“DCP”).

On July 14, 2014, the Partnership announced the execution of a Purchase and Sale Agreement (“PSA”) for the acquisition from DCP of entities holding onshore natural gas processing and offshore natural gas gathering and transportation and oil gathering assets for consideration of approximately $115 million.  The assets to be acquired included the Mobile Bay gas processing plant (“Mobile Bay”), Dauphin Island gathering and transmission system (“DIGP”), and DCP’s interest in the Main Pass Oil Gathering System (“MPOG”)

Subsequent to execution of the PSA, DCP notified the Partnership that a material customer would be moving its production from DIGP and Mobile Bay. The loss of such customer’s production constituted a Material Adverse Effect (as defined in the PSA) with respect to such entities. As a result, on August 11, 2014, the PSA was amended to exclude the Mobile Bay and DIGP assets and to include only the acquisition of DCP’s interest in MPOG. In addition, the purchase price was revised to $13.5 million. The acquisition closed on August 11, 2014. Total consideration for the MPOG assets equates to an Adjusted EBITDA multiple of approximately 5.0x to 6.0x for the next twelve months and full-year 2015.

In conjunction with the DCP acquisition and anticipated growth in the Partnership in 2015, management intends to recommend to the Board of Directors of the General Partner of the Partnership an increase of approximately three percent to the quarterly distribution for the fourth quarter 2014 distribution payable in February 2015. The DCP acquisition was funded through borrowings on the Partnership’s revolving credit facility.

On July 14, 2014, the Partnership entered into a common unit purchase agreement with certain institutional investors to sell approximately 7.6 million common units representing limited partner interests in the Partnership in a private placement (the "PIPE Offering") for aggregate consideration of approximately $200.0 million. A portion of the net proceeds from the PIPE Offering were intended to fund the acquisition of assets from DCP described herein. As of August 11, 2014, not all of the closing conditions have been satisfied, and the PIPE Offering has not funded or closed.

Gonzales County Full-Well-Stream Gathering System

On August 4, 2014, the Board of Directors of the General Partner of the Partnership approved the Partnership’s right-of-first-offer to acquire the Gonzales County full-well-stream gathering system in the Eagle Ford Shale for total consideration not to exceed $110 million. Construction on the system commenced in the second quarter of 2014 at an estimated total capital expenditure of approximately $100 million incurred by an affiliate of the General Partner. The initial phase of the project is expected to commence operations in the fourth quarter of 2014, and full-system operations are expected in the first quarter of 2015. The Partnership anticipates the drop-down of the system will be completed in late 2014 or early 2015.

The system is expected to include saltwater disposal capabilities as well as full-well-stream gathering and treating infrastructure to manage oil, gas, and water production. Total design capacity is approximately 95,000 barrels per day of crude oil / water and 15 million cubic feet per day of natural gas. Following the consummation of the transaction as currently contemplated, the Partnership would provide midstream services under a long-term, fee-based agreement with Forest Oil Corporation.

Republic Midstream Crude Oil System

On August 5, 2014, the Partnership executed an option agreement providing the Partnership with the right to acquire a 50 percent interest in Republic Midstream, LLC (“Republic Midstream”) from an affiliate of ArcLight Capital

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Partners, LLC ("ArcLight"), which controls the General Partner of the Partnership. Republic Midstream, a newly formed ArcLight portfolio company, executed an agreement with Penn Virginia in July 2014 to construct and operate a crude oil gathering system, central delivery terminal complex, and an intermediate takeaway pipeline to serve Penn Virginia’s acreage position in the Eagle Ford Shale. ArcLight has committed $400 million to Republic Midstream for construction of the crude oil system. In accordance with the terms of the option agreement, the Partnership will have the right to acquire 50 percent of Republic Midstream for approximately $200 million upon commencement of operations, which is expected in the first half of 2015.

Pursuant to the terms of its agreement with Penn Virginia, Republic Midstream will provide midstream services to Penn Virginia under a long-term, fee-based transportation agreement, supported by minimum volume commitments and dedicated acreage in the area served by the gathering system. The gathering system is expected to include 180 miles of gathering and trunk lines located in north central Gonzales and Lavaca counties that will deliver gathered volumes to a 144-acre storage and blending crude oil terminal in western Lavaca County. The intermediate system is expected to consist of a 12-inch, 30-mile takeaway pipeline with initial capacity of 80,000 barrels per day. Prior to and after the acquisition of the 50 percent interest described above, the Partnership will provide construction, operations, and general management services for Republic Midstream.

Series A Unit Distributions Amendment

The Partnership executed an amendment to the Partnership agreement related to its Series A Units, which became effective July 24, 2014. As a result of the Amendment, distributions on Series A Units will be made with paid-in-kind Series A Units, cash or a combination thereof, at the discretion of the Board of Directors, beginning with the distribution for the three months ended June 30, 2014 and the subsequent three fiscal quarters. Prior to the Amendment, the Partnership was required to pay distributions on the Series A Units with a combination of paid-in-kind units and cash. The Board of Directors of the General Partner of the Partnership approved a distribution of paid-in-kind Series A Units for the three months ended June 30, 2014 payable in the third quarter of 2014. As of June 30, 2014, there were approximately 5.4 million Series A Units outstanding.

Harvey Terminal

The Harvey terminal ("Harvey") is a brownfield terminal site acquired in the December 2013 Blackwater acquisition. Terminal storage operations at Harvey commenced in July 2014, adding 250,000 barrels in incremental storage capacity and increasing the Partnership's total storage capacity to approximately 1.7 million barrels. Construction of a deep-water ship dock at Harvey is currently underway with completion expected in the first quarter of 2015. Upon completion, Harvey is expected to be a full-service storage site, providing rail, truck, barge, and deep-water service. Harvey has the potential for up to two million barrels of capacity when fully developed, which would increase the Partnership's total storage capacity by more than 100 percent.

2014 FORECAST UPDATE

The Partnership updated its 2014 forecast to incorporate the August 2014 closing of the DCP acquisition and the recently executed amendment to the Partnership agreement in relation to the outstanding Series A Units. The updated 2014 forecast also includes assumptions for costs associated with the DCP acquisition integration and near-term company growth, and does not include other acquisitions, drop downs, or asset development projects the Partnership is pursuing.

	
				
2014 Forecast (millions)	Current	Original	% Change	
Adjusted EBITDA	$42 - $45	$41 - $44	2.4%	
Distributable Cash Flow	$27 - $30	$21 - $24	26.7%	
Expansion Capital Expenditures	$65 - $70	$55 - $60	17.4%	

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The increases to forecasted Adjusted EBITDA and Distributable Cash Flow of 2.4 percent and 26.7 percent, respectively, are primarily attributable to contributions from the DCP acquisition and the amendment to the Series A Unit distributions. Forecasted expansion capital expenditures, which exclude capital for maintenance, increased 17.4 percent compared to the original 2014 forecast to account for accelerated capital costs to accommodate faster drilling and higher throughput for the producer customer on the Lavaca natural gas gathering system expansion that is under construction.

EXECUTIVE COMMENTARY

“We continue to deliver strong operational and financial performance, including the completion of three accretive acquisitions over the past eight months,” stated Steve Bergstrom, Executive Chairman, President and Chief Executive Officer. “The oil gathering assets we acquired from DCP are complementary to our High Point system, and will enable us to compete for expanding shallow-water and deep-water production in the eastern region of the Gulf of Mexico. The Lavaca System in the Eagle Ford is operating above expectations with volumes significantly higher than anticipated. As a result, we increased our 2014 capital expenditure forecast to accommodate Penn Virginia’s accelerated development of their Eagle Ford acreage position. In addition, we recently executed an agreement to add a new third-party producer to the Lavaca System and anticipate adding additional producers by year-end."

“We are also excited about the successful build out of Blackwater’s Harvey terminal and the recent commencement of operations. Based on continued interest in the Harvey site, we have the opportunity to more than double the Partnership’s total storage capacity over the next 24 to 36 months."

“We are on track to meet our revised 2014 guidance, and we remain committed to delivering long-term sustainable distribution growth. To that end, and as previously announced, we intend to recommend to our Board of Directors distribution increases of approximately two percent for the third quarter 2014 in conjunction with the Lavaca acquisition and approximately three percent for the fourth quarter 2014 related to the DCP acquisition and additional growth in the Partnership we expect 2015."

“As we look forward, we are focused on integrating the DCP assets, further expanding the Harvey terminal, and continuing to execute strategic development projects in the Eagle Ford, including existing Lavaca operations, the anticipated drop-down of the Gonzales County assets from our General Partner, and the recently announced Republic Midstream crude oil agreement that we initiated. Third-party acquisitions, in addition to drop-down opportunities in growing regions like the Eagle Ford, will remain a core component of our growth strategy. As a result of the above-mentioned deals, we believe our 2015 Adjusted EBITDA will more than double compared to our 2014 forecast.”

SEGMENT PERFORMANCE

																	
Gross Margin (thousands)	Three months ended June 30,	Six months ended June 30,	% Change	
	2014	2013	2014	2013	QTD	YTD	
Gathering and Processing	$	10,481		$	9,077		$	20,610		$	17,784		15.5	%	15.9	%	
Transmission	$	9,350		$	7,583		$	20,363		$	11,581		23.3	%	75.8	%	
Terminals	$	2,336		$	1,657		$	4,275		$	1,657		41.0	%	158.0	%	

Gathering and Processing - The Gathering and Processing segment includes natural gas transportation, gathering, treating, processing, fractionation, and selling or delivering natural gas and natural gas liquids ("NGLs") to various markets and pipeline systems.

4

Segment gross margin for the Gathering and Processing segment was $10.5 million and $20.6 million for the three and six months ended June 30, 2014 , respectively, compared to $9.1 million and $17.8 million for the same periods in 2013. The increase in gross margin was attributable to incremental gross margin from the Lavaca System acquisition. The increase was partially offset by lower average gross NGL production on the Gloria System, lower NGL sales on the Bazor Ridge System, and lower condensate production at Chatom as a result of decreased throughput.

Natural gas throughput volumes averaged 266.3 million cubic feet per day ("MMcf/d") and 275.2 MMcf/d for the three and six months ended June 30, 2014 , respectively, compared to 261.2 MMcf/d and 253.0 MMcf/d for the same periods in 2013. Processed NGLs averaged 37.2 thousand gallons per day ("Mgal/d") and 37.7 Mgal/d for the three and six months ended June 30, 2014 , respectively, compared to 43.6 Mgal/d and 51.4 Mgal/d for the same periods in 2013. The increase in throughput was attributable to incremental volumes from the Lavaca System acquisition, partially offset by lower throughput on the Gloria and Burns Point Systems. Processed NGLs decreased primarily as a result of lower production at the Bazor Ridge Plant due to lower throughputs and longer-than-anticipated maintenance downtime in the second quarter.

Transmission - The Transmission segment transports and delivers natural gas from producing wells, receipt points, or pipeline interconnects to pipeline or end-use markets.

Segment gross margin for the Transmission segment was $9.4 million and $20.4 million for the three and six months ended June 30, 2014 , respectively, compared to $7.6 million and $11.6 million for the same periods in 2013. The increase in gross margin was attributable to the High Point System that was acquired in April 2013.

Total natural gas throughput volumes averaged 765.9 MMcf/d and 814.8 MMcf/d for the three and six months ended June 30, 2014 , respectively, compared to 689.9 MMcf/d and 567.0 MMcf/d for the same periods in 2013. The increase in throughput volume was primarily due to the additional volumes contributed by the above mentioned High Point System.

Terminals - The Terminals segment provides above-ground storage services at the Partnership's 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.

Segment gross margin for the Terminals segment was $2.3 million and $4.3 million for the three and six months ended June 30, 2014 , respectively, compared to $1.7 million for the three months ended June 30, 2013. The Partnership did not have a Terminals segment for the three months ended March 31, 2013.
 
BALANCE SHEET

As of June 30, 2014, the Partnership had $3.0 million of cash on hand, and $140.8 million outstanding under its senior secured revolving credit facility with $59.2 million of available borrowing capacity. For the three months ended June 30, 2014, capital expenditures totaled $9.3 million , which includes $0.3 million for maintenance capital.

DERIVATIVES

The Partnership enters into derivative agreements to hedge exposure to commodity prices associated with natural gas, NGLs, and crude oil. As of June 30, 2014, approximately 18 percent of the Partnership's exposure to NGL prices and approximately 60 percent of the Partnership's exposure to oil prices are hedged through the end of 2014. In addition, approximately 6 percent of the Partnership's expected exposure to NGL prices and 60 percent of expected exposure to oil prices are hedged for the first six months of 2015. Details regarding the Partnership's hedge program are found in its quarterly report.

CONFERENCE CALL INFORMATION

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The Partnership will host a conference call at 10:00 a.m. ET on Tuesday, August 12, 2014 to discuss results. The call will be webcast and archived on the Partnership’s website for a limited time.

Dial-In Numbers:    (877) 280-4956 (Domestic toll free)
(857) 244-7313 (International)
Passcode:        37585875
		
Webcast URL:	www.AmericanMidstream.com under Investor Relations	

Non-GAAP Financial Measures

This press release and the accompanying tables, include financial measures in accordance with U.S. generally accepted accounting principles, or GAAP, as well as non-GAAP financial measures, including “ Adjusted EBITDA, ” “ Gross Margin, ” and “ Distributable Cash Flow. ” The tables included in this press release include reconciliations of these non-GAAP financial measures to the nearest GAAP financial measures. In addition, an “Explanation of Non-GAAP Financial Measures” is set forth in Appendix A attached to this press release.

About American Midstream Partners, LP

Denver-based American Midstream Partners is a growth-oriented limited partnership formed to own, operate, develop and acquire a diversified portfolio of midstream energy assets. The Partnership provides midstream services in the Texas, Gulf Coast and Southeast regions of the United States. For more information about American Midstream Partners, LP, visit www.AmericanMidstream.com .

Investor Contact
Allysa Howell, 303-942-2359
AHowell@Americanmidstream.com
Investor Relations Manager

Forward-Looking Statements

This press release includes forward-looking statements. These statements relate to, among other things, projections of operational volumetrics and improvements, growth projects, cash flows and capital expenditures. We have used the words "anticipate," "believe," "could," "estimate," "expect," "intend," "may," "plan," "predict," "project," "should," "will," "potential," and similar terms and phrases to identify forward-looking statements in this press release. Although we believe the assumptions upon which these forward-looking statements are based are reasonable, any of these assumptions could prove to be inaccurate and the forward-looking statements based on these assumptions could be incorrect. Our operations and future growth involve risks and uncertainties, many of which are outside our control, and any one of which, or a combination of which, could materially affect our results of operations and whether the forward-looking statements ultimately prove to be correct. Actual results and trends in the future may differ materially from those suggested or implied by the forward-looking statements depending on a variety of factors which are described in greater detail in our filings with the SEC. The closing of the Republic Midstream and Gonzales County acquisitions described in this press release are subject to negotiation of definitive acquisition agreements and other conditions beyond our control. The construction of the projects described is subject to risks beyond our control including cost overruns and delays resulting from numerous factors.  In addition, we face risks associated with the integration of acquired businesses, decreased liquidity, increased interest and other expenses, assumption of potential liabilities, diversion of management’s attention, and other risks associated with acquisitions and growth, including the recently announced acquisition of assets from DCP described in this press release and either or both of the Republic Midstream and Gonzales County acquisitions, if consummated. Please see our Risk Factor disclosures included in our Annual Report on Form 10-K for the year ended December 31, 2013, filed on March 11, 2014 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 filed on August 11, 2014. All future written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the previous statements. The forward-looking statements herein speak as of the date of this press release. We undertake no obligation to update any

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information contained herein or to publicly release the results of any revisions to any forward-looking statements that may be made to reflect events or circumstances that occur, or that we become aware of, after the date of this press release.

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American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Balance Sheets
(Unaudited, in thousands)

								
 	June 30,
2014	 	December 31,
2013	
Assets	 	 	 	
Current assets	 	 	 	
Cash and cash equivalents	$	3,007		 	$	393		
Accounts receivable	7,337		 	6,822		
Unbilled revenue	25,202		 	23,001		
Risk management assets	885		 	473		
Other current assets	5,996		 	7,497		
Current assets held for sale	121		 	272		
Total current assets	42,548		 	38,458		
Property, plant and equipment, net	381,318		 	312,701		
Goodwill	16,253		 	16,447		
Intangible assets, net	49,522		 	3,682		
Other assets, net	8,418		 	9,064		
Noncurrent assets held for sale, net	1,148		 	1,723		
Total assets	$	499,207		 	$	382,075		
Liabilities, Equity and Partners’ Capital	 	 	 	
Current liabilities	 	 	 	
Accounts payable	$	10,538		 	$	3,261		
Accrued gas purchases	17,256		 	17,386		
Accrued expenses and other current liabilities	15,697		 	15,058		
Current portion of long-term debt	574		 	2,048		
Risk management liabilities	602		 	423		
Current liabilities held for sale	54		 	114		
Total current liabilities	44,721		 	38,290		
Risk management liabilities	36		 	101		
Asset retirement obligations	34,648		 	34,636		
Other liabilities	229		 	191		
Long-term debt	136,500		 	130,735		
Deferred tax liability	4,694		 	4,749		
Noncurrent liabilities held for sale, net	—		 	95		
Total liabilities	220,828		 	208,797		
Commitments and contingencies	 	 	 	
Convertible preferred units	 	 	 	
Series A convertible preferred units (5,430 thousand and 5,279 thousand units issued and outstanding as of June 30, 2014, and December 31, 2013, respectively)	100,571		 	94,811		
Equity and partners’ capital	 	 	 	
General partner interest (235 thousand and 185 thousand units issued and outstanding as of June 30, 2014, and December 31, 2013, respectively)	(4,212	)	 	2,696		
Limited partner interest (11,140 thousand and 7,414 thousand units issued and outstanding as of June 30, 2014, and December 31, 2013, respectively)	146,271		 	71,039		
Series B convertible units (1,210 thousand and zero units issued and outstanding as of June 30, 2014, and December 31, 2013, respectively)	31,052		 	—		
Accumulated other comprehensive income	150		 	104		

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Total partners’ capital	173,261		 	73,839		
Noncontrolling interests	4,547		 	4,628		
Total equity and partners' capital	177,808		 	78,467		
Total liabilities, equity and partners' capital	$	499,207		 	$	382,075		

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American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Operations
(Unaudited, in thousands, except for per unit amounts)

	
																
 	Three months ended June 30,	 	Six months ended June 30,	
 	2014	 	2013	 	2014	 	2013	
Revenue	$	77,873		 	$	76,277		 	$	158,241		 	$	139,181		
(Loss) gain on commodity derivatives, net	(193	)	 	914		 	(323	)	 	609		
Total revenue	77,680		 	77,191		 	157,918		 	139,790		
Operating expenses:	 	 	 	 	 	 	 	
Purchases of natural gas, NGLs and condensate	53,818		 	56,965		 	109,039		 	107,234		
Direct operating expenses	11,044		 	8,402		 	20,005		 	13,277		
Selling, general and administrative expenses	5,637		 	4,588		 	11,230		 	8,013		
Equity compensation expense	435		 	1,097		 	795		 	1,485		
Depreciation, amortization and accretion expense	6,012		 	8,748		 	13,644		 	14,394		
Total operating expenses	76,946		 	79,800		 	154,713		 	144,403		
Gain on involuntary conversion of property, plant and equipment	—		 	—		 	—		 	343		
Loss on sale of assets, net	—		 	—		 	(21	)	 	—		
Loss on impairment of property, plant and equipment	—		 	(15,232	)	 	—		 	(15,232	)	
Operating income (loss)	734		 	(17,841	)	 	3,184		 	(19,502	)	
Other expense:	 	 	 	 	 	 	 	
Interest expense	(1,680	)	 	(2,591	)	 	(3,583	)	 	(4,322	)	
Net loss before income tax benefit	(946	)	 	(20,432	)	 	(399	)	 	(23,824	)	
Income tax (expense) benefit	(149	)	 	375		 	(138	)	 	375		
Net loss from continuing operations	(1,095	)	 	(20,057	)	 	(537	)	 	(23,449	)	
Discontinued operations:	 	 	 	 	 	 	 	
Loss from operations of disposal groups, net of tax	(506	)	 	(1,869	)	 	(556	)	 	(1,875	)	
Net loss	(1,601	)	 	(21,926	)	 	(1,093	)	 	(25,324	)	
Net income attributable to noncontrolling interests	66		 	188		 	174		 	343		
Net loss attributable to the Partnership	$	(1,667	)	 	$	(22,114	)	 	$	(1,267	)	 	$	(25,667	)	
 	 	 	 	 	 	 	 	
General partner's interest in net loss	$	(22	)	 	$	(905	)	 	$	(15	)	 	$	(974	)	
Limited partners' interest in net loss	$	(1,645	)	 	$	(21,209	)	 	$	(1,252	)	 	$	(24,693	)	
 	 	 	 	 	 	 	 	
Distribution declared per common unit (a)	$	0.4625		 	$	0.4325		 	$	0.9150		 	$	0.8650		
Limited partners' net loss per common unit:	 	 	 	 	
Basic and diluted:	 	 	 	 	 	 	 	
Loss from continuing operations	$	(0.55	)	 	$	(4.01	)	 	$	(0.92	)	 	$	(4.39	)	
Loss from discontinued operations	(0.04	)	 	(0.20	)	 	(0.05	)	 	(0.19	)	
Net loss	$	(0.59	)	 	$	(4.21	)	 	$	(0.97	)	 	$	(4.58	)	
Weighted average number of common units outstanding:	 	 	 	 	
Basic and diluted	11,139		 	9,198		 	10,496		 	9,183		

(a) Declared and paid in the quarter(s) during the three and six months ended June 30, 2014 and 2013 related to prior quarter earnings.

10

American Midstream Partners, LP and Subsidiaries
Condensed Consolidated Statements of Cash Flows
(Unaudited, in thousands)

								
	Six months ended June 30,	
 	2014		2013	
Cash flows from operating activities				
Net loss	$	(1,093	)		$	(25,324	)	
Adjustments to reconcile net loss to net cash provided by operating activities:				
Depreciation, amortization and accretion expense	13,644			14,431		
Amortization of deferred financing costs	847			614		
Amortization of weather derivative premium	554			95		
Unrealized loss on commodity derivatives	113			245		
Equity based compensation	730			1,460		
OPEB plan net periodic benefit	(23	)		(37	)	
Gain on involuntary conversion of property, plant and equipment	—			(343	)	
Loss on sale of assets	106			—		
Loss on impairment of property, plant and equipment	—			15,232		
Loss on impairment of noncurrent assets held for sale	673			1,807		
Deferred tax benefit	(161	)		(414	)	
Changes in operating assets and liabilities, net:			
Accounts receivable	(556	)		1,976		
Unbilled revenue	(2,083	)		(2,522	)	
Risk management assets and liabilities	(965	)		(1,134	)	
Other current assets	1,547			(315	)	
Other assets, net	22			(62	)	
Accounts payable	(851	)		3,648		
Accrued gas purchases	(188	)		2,347		
Accrued expenses and other current liabilities	680			856		
Asset retirement obligations	(623	)	 	—		
Other liabilities	38			(142	)	
Net cash provided by operating activities	12,411			12,418		
Cash flows from investing activities				
Cost of acquisitions	(110,909	)		—		
Additions to property, plant and equipment	(13,229	)		(13,606	)	
Proceeds from disposals of property, plant and equipment	6,202			—		
Insurance proceeds from involuntary conversion of property, plant and equipment	—			482		
Net cash used in investing activities	(117,936	)		(13,124	)	
Cash flows from financing activities				
Proceeds from issuance of common units to public, net of offering costs	86,904			—		
Unitholder contributions	1,276			575		
Unitholder distributions	(13,793	)		(7,805	)	
Issuance of Series A convertible preferred units, net	—			14,393		
Issuance of Series B Units	30,000			—		
Acquisition of noncontrolling interest	(8	)		—		
Net distributions to noncontrolling interest owners	(226	)		(443	)	
LTIP tax netting unit repurchase	(151	)		(339	)	
Payments of deferred debt issuance costs	(154	)		(1,315	)	

11

	
								
Payments on other debt	(1,644	)		(1,139	)	
Borrowings on other debt	170			1,495		
Payments on loan to affiliate	—			(489	)	
Payments on bank loans	—			1,274		
Payments on long-term debt	(75,220	)		(56,546	)	
Borrowings on long-term debt	80,985			51,921		
Net cash provided by financing activities	108,139			1,582		
Net increase in cash and cash equivalents	2,614			876		
Cash and cash equivalents				
Beginning of period	393			576		
End of period	$	3,007			$	1,452		
Supplemental cash flow information				
Interest payments, net	$	2,718			$	3,049		
Supplemental non-cash information				
Increase (decrease) in accrued property, plant and equipment	$	9,501			$	(6,023	)	
Net assets contributed in the Blackwater Acquisition	—			22,129		
Net assets contributed in exchange for the issuance of Series A convertible preferred units	—			59,994		
Fair value of Series A Units in excess of net assets received	—			15,612		
Accrued and in-kind unitholder distribution for Series A Units	5,760			2,146		
In-kind unitholder distribution for Series B Units	1,052			—		

12

American Midstream Partners, LP and Subsidiaries
Reconciliation of Net income (loss) attributable to the Partnership
to Adjusted EBITDA to Distributable Cash Flow
(Unaudited, in thousands)

	
																
 	Three months ended June 30,	 	Six months ended June 30,	
 	2014	 	2013	 	2014	 	2013	
Reconciliation of Net loss attributable to the Partnership to Adjusted EBITDA	 	 	 	 	 	 	 	
Net loss attributable to the Partnership	$	(1,667	)	 	$	(22,114	)	 	$	(1,267	)	 	$	(25,667	)	
Add:	 	 	 	 	 	 	 	
Depreciation, amortization and accretion expense	6,012		 	8,780		 	13,644		 	14,458		
Interest expense	1,351		 	2,010		 	2,844		 	3,509		
Debt issuance costs	11		 	403		 	155		 	1,315		
Unrealized loss (gain) on derivatives, net	75		 	(236	)	 	113		 	245		
Non-cash equity compensation expense	435		 	1,097		 	795		 	1,485		
Transaction expenses	226		 	1,080		 	1,038		 	1,422		
Income tax benefit	(135	)	 	(414	)	 	(161	)	 	(414	)	
Impairment of property, plant and equipment	—		 	15,232		 	—		 	15,232		
Impairment of noncurrent assets held for sale	673		 	1,807		 	673		 	1,807		
Deduct:	 	 	 	 	 	 	 	
COMA income	246		 	146		 	535		 	252		
Straight-line amortization of put costs (a)	—		 	30		 	—		 	57		
OPEB plan net periodic benefit	12		 	18		 	23		 	37		
Gain on involuntary conversion of property, plant and equipment	—		 	—		 	—		 	343		
Loss on sale of assets, net	(63	)	 	—		 	(106	)	 	—		
Adjusted EBITDA	$	6,786		 	$	7,451		 	$	17,382		 	$	12,703		

	
												
Deduct:	 	 	 	 	 	 	 	
Cash interest expense (b)	1,299		 	1,557		 	2,763		 	3,039		
Normalized maintenance capital (c)	1,300		 	1,104		 	2,600		 	2,145		
Normalized integrity management (d)	—		 	370		 	—		 	544		
Series A Convertible Preferred Payment (e)	—		 	1,074		 	1,338		 	1,074		
Distributable Cash Flow	4,187		 	3,346		 	10,681		 	5,901		
(a)    Amounts noted represent the straight-line amortization of the cost of commodity put contracts over the life of the contract.
(b)    Excludes amortization of debt issuance costs and mark-to-market adjustments related to interest rate derivatives.
(c)    Represents estimated annual maintenance capital expenditures of $5.2 million, which is what the Partnership expects to be required to maintain assets over the long term.
(d)    Represents estimated integrity management costs over the seven year mandatory testing cycle net of integrity management costs that are expensed in direct operating expenses.
(e)    Calculated on a pro-rata basis for the number of days the Series A units were outstanding during the given periods.

13

American Midstream Partners, LP and Subsidiaries
Reconciliation of Gross Margin to Net income (loss) attributable to the Partnership
(Unaudited, in thousands)

	
																
	Three months ended June 30,		Six months ended June 30,	
	2014		2013		2014		2013	
Reconciliation of gross margin to Net loss attributable to the Partnership:												
Gathering and processing segment gross margin	$	10,481			$	9,077			$	20,610			$	17,784		
Transmission segment gross margin	9,350			7,583			20,363			11,581		
Terminals segment gross margin	2,336			1,657			4,275			1,657		
Total gross margin	22,167			18,317			45,248			31,022		
Plus:								
(Loss) gain on commodity derivatives, net	(193	)		914			(323	)		609		
Less:								
Direct operating expenses (a)	9,482			7,193			16,768			12,068		
Selling, general and administrative expenses	5,637			4,588			11,230			8,013		
Equity compensation expense	435			1,097			795			1,485		
Depreciation, amortization and accretion expense	6,012			8,748			13,644			14,394		
Gain on involuntary conversion of property, plant and equipment	—			—			—			(343	)	
Loss on sale of assets, net	—			—			21			—		
Loss on impairment of property, plant and equipment	—			15,232			—			15,232		
Interest expense	1,680			2,591			3,583			4,322		
Other, net (b)	(326	)		214			(717	)		284		
Income tax expense (benefit)	149			(375	)		138			(375	)	
Loss from operations of disposal groups, net of tax	506			1,869			556			1,875		
Net income attributable to noncontrolling interest	66			188			174			343		
Net loss attributable to the Partnership	$	(1,667	)		$	(22,114	)		$	(1,267	)		$	(25,667	)	

(a)	Direct operating expenses includes Gathering and Processing segment direct operating expenses of $5.7 million and $3.6 million , respectively, and Transmission segment direct operating expenses of $3.7 million and $3.6 million , respectively, for the three months ended June 30, 2014 and 2013 . Direct operating expenses related to our Terminals segment of $1.6 million and $1.2 million , respectively, for the three months ended June 30, 2014 and 2013 are included within the calculation of Terminals segment gross margin.	
Direct operating expenses includes Gathering and Processing segment direct operating expenses of $9.9 million and $7.1 million , respectively, and Transmission segment direct operating expenses of $6.9 million and $4.9 million , respectively, for the six months ended June 30, 2014 and 2013 . Direct operating expenses related to our Terminals segment of $3.2 million and $1.2 million , respectively, for the six months ended June 30, 2014 and 2013 are included within the calculation of Terminals segment gross margin.
		
(b)	Other, net includes realized (loss) gain on commodity derivatives of $(0.1) million and $0.4 million and COMA income of $0.2 million and $0.1 million for the three months ended June 30, 2014 and 2013 , respectively.	
Other, net includes realized (loss) gain on commodity derivatives of $(0.2) million and $0.5 million and COMA income of $0.5 million and $0.3 million for the six months ended June 30, 2014 and 2013 , respectively.

14

American Midstream Partners, LP and Subsidiaries
Segment Operating Data
(Unaudited, in thousands, except for operating and pricing data)

																
 	Three months ended June 30,		Six months ended June 30,	
 	2014		2013		2014		2013	
Segment Financial and Operating Data:								
Gathering and Processing segment								
Financial data:								
Revenue	$	50,015			$	52,525			$	101,641			$	100,766		
Loss on commodity derivatives	(193	)		914			(323	)		609		
Total revenue	49,822			53,439			101,318			101,375		
Purchases of natural gas, NGLs and condensate	39,238			43,702			80,359			83,370		
Direct operating expenses	5,746			3,637			9,914			7,127		
Other financial data:								
Segment gross margin	$	10,481			$	9,077			$	20,610			$	17,784		
Operating data:								
Average throughput (MMcf/d)	266.3			261.2			275.2			253.0		
Average plant inlet volume (MMcf/d) (a) (b)	86.4			112.3			87.0			104.3		
Average gross NGL production (Mgal/d) (a) (c)	37.2			43.6			37.7			51.4		
Average gross condensate production (Mgal/d) (a)	43.0			45.2			42.6			44.7		
Average realized prices:								
Natural gas ($/Mcf)	$	5.15			$	4.37			$	5.40			$	4.06		
NGLs ($/gal)	$	0.97			$	0.82			$	1.02			$	0.85		
Condensate ($/gal)	$	2.24			$	2.25			$	2.22			$	2.32		
Transmission segment								
Financial data:								
Total revenue	$	23,960			$	20,886			$	49,088			$	35,549		
Purchases of natural gas, NGLs and condensate	14,580			13,263			28,680			23,864		
Direct operating expenses	3,736			3,556			6,854			4,941		
Other financial data:								
Segment gross margin	$	9,350			$	7,583			$	20,363			$	11,581		
Operating data:								
Average throughput (MMcf/d)	765.9			689.9			814.8			567.0		
Average firm transportation - capacity reservation (MMcf/d)	540.4			680.9			586.1			724.6		
Average interruptible transportation - throughput (MMcf/d)	477.0			110.3			499.8			119.7		

15

	
																
Terminals segment												
Financial data:								
Total revenue	$	3,898			$	2,866			$	7,512			$	2,866		
Direct operating expenses	1,562			1,209			3,237			1,209		
Other financial data:								
Segment gross margin	$	2,336			$	1,657			$	4,275			$	1,657		
Operating data:								
Storage Utilization	97.7	%		100	%		99.8	%		100	%	

(a)	Excludes volumes and gross production under the Partnership's elective processing arrangements.	
		
(b)	Includes gross plant inlet volume associated with the Partnership's interest in the Burns Point processing plant.	
		
(c)	Includes net NGL production associated with the Partnership's interest in the Burns Point processing plant.	

Appendix A

Note About Non-GAAP Financial Measures
Gross margin, adjusted EBITDA and distributable cash flows are all non-GAAP financial measures. Each has important limitations as an analytical tool because it excludes some, but not all, items that affect the most directly comparable GAAP financial measures. Management compensates for the limitations of these non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.
You should not consider any of gross margin, adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of the Partnership's results as reported under GAAP. Gross margin, adjusted EBITDA and distributable cash flow may be defined differently by other companies in the Partnership's industry. The Partnership's definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
We define adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation expense, certain non-cash charges such as non-cash equity compensation, unrealized losses on commodity derivative contracts and selected charges that are unusual or nonrecurring, less interest income, income tax benefit, unrealized gains on commodity derivative contracts, amortization of commodity put purchase costs, and selected gains that are unusual or nonrecurring. The GAAP measure most directly comparable to adjusted EBITDA is net income.

Distributable cash flow is a significant performance metric used by us and by external users of the Partnership's financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay the Partnership's unitholders. Using this metric, management and external users of the Partnership's financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important financial measure for the Partnership's unitholders since it serves as an indicator of the Partnership's success in providing a cash return on investment. Specifically, this financial measure may indicate to investors whether we are generating cash flow at a level that can sustain or support an increase in the Partnership's quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit's yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder). Distributable cash flow will not reflect changes in working capital balances.
We define distributable cash flow as adjusted EBITDA plus interest income, less cash paid for interest expense, normalized maintenance capital expenditures, and dividends related to the Series A convertible preferred units. The GAAP measure most comparable to distributable cash flow is net income.

16

Gross margin and segment gross margin are metrics that we use to evaluate the Partnership's performance. We define segment gross margin in the Partnership's Gathering and Processing segment as revenue generated from gathering and processing operations less the cost of natural gas, NGLs and condensate purchased. Revenue includes revenue generated from fixed fees associated with the gathering and treating of natural gas and from the sale of natural gas, NGLs and condensate resulting from gathering and processing activities under fixed-margin and percent-of-proceeds arrangements. The cost of natural gas, NGLs and condensate includes volumes of natural gas, NGLs and condensate remitted back to producers pursuant to percent-of-proceeds arrangements and the cost of natural gas purchased for the Partnership's own account, including pursuant to fixed-margin arrangements.
We define segment gross margin in the Partnership's Transmission segment as revenue generated from firm and interruptible transportation agreements and fixed-margin arrangements, plus other related fees, less the cost of natural gas purchased in connection with fixed-margin arrangements.
We define segment gross margin in the Partnership's Terminals segment as revenue generated from fee-based compensation on guaranteed storage contracts and throughput fees charged to the Partnership's customers less direct operating expenses which includes direct labor, general materials and supplies and direct overhead.
We define gross margin as the sum of the Partnership's segment gross margin for the Partnership's Gathering and Processing, Transmission and Terminals segments. The GAAP measure most comparable to gross margin is net income.

17