Third Coast Midstream (AMID) 8-K 2016 FY Other Events

EXHIBIT 99.3

AMERICAN MIDSTREAM PARTNERS, LP

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets as of December 31, 2016 and 2015	F-3
Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014	F-4
Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2016, 2015 and 2014	F-5
Consolidated Statements of Changes in Equity, Partners' Capital and Noncontrolling Interests for the Years Ended December 31, 2016, 2015 and 2014	F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014	F-7
Notes to Consolidated Financial Statements	F-9

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 (loss), of changes in equity, partners’ capital and noncontrolling interests, and of cash flows present fairly, in all material respects, the financial position of American Midstream Partners, LP and its subsidiaries ("the Partnership") at December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) because a material weakness in internal control over financial reporting existed as of that date related to the Partnership not maintaining a sufficient complement of resources with an appropriate level of accounting knowledge, expertise and training commensurate with its financial reporting requirements. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness referred to above is described in Management’s Annual Report on Internal Control over Financial Reporting (not presented herein) appearing under Item 9A of the Partnership’s 2016 Annual Report on Form 10-K. We considered this material weakness in determining the nature, timing and extent of audit tests applied in our audit of the 2016 consolidated financial statements, and our opinion regarding the effectiveness of the Partnership’s internal control over financial reporting does not affect our opinion on those consolidated financial statements. 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 report referred to above. Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our audits. 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.

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 discussed in Note 2 to the consolidated financial statements, the Partnership acquired JP Energy Partners, LP (“JPE”) on March 8, 2017 in a transaction between entities under common control as both the Partnership and JPE are controlled by affiliates of ArcLight Capital Partners, LLC (“ArcLight”). Although the Partnership is the legal acquirer, JPE is considered to be the acquirer for accounting purposes as ArcLight obtained control of JPE before it obtained control of the Partnership. The accompanying financial statements represent JPE’s historical cost basis financial statements, retrospectively adjusted to reflect the acquisition of the Partnership at ArcLight’s historical cost basis on April 15, 2013. The controls of JPE were not part of the Partnership’s internal control over financial reporting as of December 31, 2016. Accordingly, the controls operated at JPE were not included in either management’s assessment of internal control over financial reporting or in our audit of the Partnership’s internal control over financial reporting as of December 31, 2016. JPE is a wholly-owned subsidiary of the Partnership whose total assets and total revenue represent 28.7% and 68.0%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2016.

F-1

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 24, 2017, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of the acquisition of JP Energy Partners, LP discussed in Note 2 to the consolidated financial statements and to the third paragraph of Note 24, as to which the date is September 15, 2017.

F-2

American Midstream Partners, LP, and Subsidiaries

Consolidated Balance Sheets

(In thousands, except unit amounts)

	December 31,
	2016			2015
Assets
Current assets
Cash and cash equivalents	$	5,666		$	1,987
Accounts receivable, net of allowance for doubtful accounts of $1,871 and $1,217 as of December 31, 2016 and December 31, 2015, respectively	27,769			23,831
Unbilled revenue	55,646			55,428
Inventory	6,776			5,241
Other current assets	27,667			25,526
Total current assets	123,524			112,013
Risk management assets - long term	10,664			—
Property, plant and equipment, net	1,145,003			1,071,514
Restricted cash - long term	323,564			5,037
Investment in unconsolidated affiliates	291,987			63,704
Intangible assets, net	225,283			247,281
Goodwill	217,498			232,954
Other assets, net	11,798			19,386
Total assets	$	2,349,321		$	1,751,889
Liabilities, Convertible Preferred Units, Equity and Partners' Capital
Current liabilities
Accounts payable	$	45,278		$	48,526
Accrued gas purchases	7,891			7,281
Accrued expenses and other current liabilities	81,284			46,751
Current portion of debt	5,485			2,899
Total current liabilities	139,938			105,457
Asset retirement obligations	44,363			28,549
Other liabilities	2,030			2,857
3.77% Senior notes (Non-Recourse)	55,979			—
8.50% Senior notes	291,309			—
Revolving credit agreements	888,250			687,100
Deferred tax liability	8,205			6,173
Total liabilities	1,430,074			830,136
Commitments and contingencies (see Note 19)
Convertible preferred units	334,090			169,712
Equity and partners' capital
General Partner Interests (680 thousand and 536 thousand units issued and outstanding as of December 31, 2016 and December 31, 2015, respectively)	(47,645		)	(47,091		)
Limited Partner Interests (51,351 thousand and 50,504 thousand units issued and outstanding as of December 31, 2016 and December 31, 2015, respectively)	616,087			753,388
Series B convertible units (1,350 thousand units issued and outstanding as of December 31, 2015)	—			33,593
Accumulated other comprehensive income (loss)	(40		)	40
Total partners' capital	568,402			739,930
Noncontrolling interests	16,755			12,111
Total equity and partners' capital	585,157			752,041
Total liabilities, convertible preferred units, equity and partners' capital	$	2,349,321		$	1,751,889

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)

	Years Ended December 31,
	2016			2015			2014
Revenues:
Commodity sales	$	568,527		$	772,857		$	909,765
Services	158,850			142,762			123,698
Losses on commodity derivatives, net	(455		)	(1,732		)	(12,671		)
Total revenue	726,922			913,887			1,020,792
Operating expenses:
Cost of sales	443,023			630,303			789,872
Direct operating expenses	123,372			127,480			109,543
Corporate expenses	99,430			77,835			72,744
Depreciation, amortization and accretion	106,818			98,596			72,527
Loss on sale of assets, net	2,870			3,920			5,080
Loss on impairment of property, plant and equipment	697			—			21,344
Loss on impairment of goodwill	15,456			148,488			—
Total operating expenses	791,666			1,086,622			1,071,110
Operating loss	(64,744		)	(172,735		)	(50,318		)
Other income (expense):
Interest expense	(21,469		)	(20,120		)	(16,558		)
Loss on extinguishment of debt	—			—			(1,634		)
Other income (expense)	628			1,732			(662		)
Earnings in unconsolidated affiliates	40,158			8,201			348
Loss from continuing operations before income taxes	(45,427		)	(182,922		)	(68,824		)
Income tax expense	(2,578		)	(1,888		)	(857		)
Loss from continuing operations	(48,005		)	(184,810		)	(69,681		)
Loss from discontinued operations, net of tax	(539		)	(15,031		)	(9,886		)
Net loss	(48,544		)	(199,841		)	(79,567		)
Net income (loss) attributable to noncontrolling interests	2,766			(13		)	3,993
Net loss attributable to the Partnership	$	(51,310	)	$	(199,828	)	$	(83,560	)
General Partner's interest in net loss	$	(233	)	$	(1,823	)	$	(398	)
Limited Partners' interest in net loss	$	(51,077	)	$	(198,005	)	$	(83,162	)
Distribution declared per common unit (1)	$	3.01		$	3.17		$	1.85
Limited Partners' net income (loss) per common unit (See Note 16):
Basic and diluted:
Loss from continuing operations	$	(1.59	)	$	(4.59	)	$	(3.28	)
Loss from discontinued operations	(0.01		)	(0.33		)	(0.01		)
Net loss	$	(1.60	)	$	(4.92	)	$	(3.29	)
Weighted average number of common units outstanding:
Basic and diluted	51,176			45,050			27,524

(1) Declared and paid during the years ended December 31, 2016, 2015 and 2014.

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

F-4

American Midstream Partners, LP, and Subsidiaries

Consolidated Statements of Comprehensive Loss

(In thousands)

	Years Ended December 31,
	2016			2015			2014
Net loss	$	(48,544	)	$	(199,841	)	$	(79,567	)
Unrealized gain (loss) relating to postretirement benefit plan	(80		)	38			(102		)
Comprehensive loss	$	(48,624	)	$	(199,803	)	$	(79,669	)
Less: Comprehensive income (loss) attributable to noncontrolling interests	2,766			(13		)	3,993
Comprehensive loss attributable to Partnership	$	(51,390	)	$	(199,790	)	$	(83,662	)

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 Equity, Partners' Capital and Noncontrolling Interest

(In thousands)

	General Partner Interest			Limited Partner Interests			Series B Convertible Units			Accumulated Other Comprehensive Income (loss)			Total Partners' Capital			Non-controlling Interests
Balances at December 31, 2013	$	59,754		$	611,335		$	—		$	104		$	671,193		$	7,884
Net income (loss)	(398		)	(83,162		)	—			—			(83,560		)	3,993
Issuance of common units, net of offering costs	—			609,707			—			—			609,707			—
Issuance of Series B Units	—			—			32,220			—			32,220
Unitholder contributions	5,678			—			—			—			5,678			—
Unitholder distributions	(2,913		)	(131,106		)	—			—			(134,019		)	—
Issuance and exercise of warrants	(7,164		)	7,164			—			—			—			—
Contributions from noncontrolling interest owners	—			21			—			—			21			189
Distributions to noncontrolling interest owners	—			—			—			—			—			(314		)
LTIP vesting	(823		)	1,067			—			—			244			—
Tax netting repurchases	—			(256		)	—			—			(256		)	—
Equity compensation expense	1,356			1,789			—			—			3,145			—
Postretirement benefit plan	—			—			—			(102		)	(102		)	—
Unitholder distribution for JP Development Transaction	—			(47,678		)	—			—			(47,678		)	—
Balances at December 31, 2014	$	55,490		$	968,881		$	32,220		$	2		$	1,056,593		$	11,752
Net loss	(1,823		)	(198,005		)	—			—			(199,828		)	(13		)
Issuance of common units, net of offering costs	—			85,465			—			—			85,465			—
Issuance of Series B Units	—			—			1,373			—			1,373			—
Unitholder contributions	1,996						—			—			1,996			—
Unitholder distributions	(7,023		)	(111,740		)	—			—			(118,763		)	—
Unitholder distribution for Delta House Transaction	(96,297		)	—			—			—			(96,297		)	—
Contributions from noncontrolling interest owners	—			—			—			—			—			739
Distributions to noncontrolling interest owners	—			(20		)	—			—			(20		)	(367		)
LTIP vesting	(2,490		)	2,686			—			—			196			—
Tax netting repurchases	—			(756		)	—			—			(756		)	—
Equity compensation expense	3,056			1,309			—			—			4,365			—
Contributions from general partner	—			5,568			—			—			5,568			—
Postretirement benefit plan	—			—			—			38			38			—
Balances at December 31, 2015	$	(47,091	)	$	753,388		$	33,593		$	40		$	739,930		$	12,111
Net income (loss)	(233		)	(51,077		)	—			—			(51,310		)	2,766
Cancellation of escrow units	—			(6,817		)	—			—			(6,817		)	—
Conversion of Series B Units	—			33,593			(33,593		)	—			—			—
Contributions from general partner				9,900									9,900
Issuance of warrants	4,481			—			—			—			4,481			—
Issuance of common units, net of offering costs	—			2,697			—			—			2,697			—
Unitholder contributions	1,998			—			—			—			1,998			—
Unitholder distributions	(7,938		)	(130,761		)	—			—			(138,699		)	—
General Partner's contribution for acquisition	990			—			—			—			990			—
Contributions from noncontrolling interest owners	—			—			—			—			—			3,366
Distributions to noncontrolling interest owners	—			—			—			—			—			(1,488		)
LTIP vesting	(3,486		)	3,486			—			—			—			—
Tax netting repurchases	—			(346		)	—			—			(346		)	—
Equity compensation expense	3,634			2,024			—			—			5,658			—
Postretirement benefit plan	—			—			—			(80		)	(80		)	—
Balances at December 31, 2016	$	(47,645	)	$	616,087		$	—		$	(40	)	$	568,402		$	16,755

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)

	Years Ended December 31,
	2016			2015			2014
Cash flows from operating activities
Net loss	$	(48,544	)	$	(199,841	)	$	(79,567	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, amortization and accretion	107,029			100,877			76,219
Amortization of deferred financing costs	3,236			2,391			3,118
Amortization of weather derivative premium	966			912			1,035
Unrealized (gain) loss on derivative contracts, net	(11,400		)	(11,269		)	12,050
Non-cash compensation expense	5,658			5,172			3,415
Postretirement benefit plan benefit	(17		)	(14		)	(45		)
Loss on sale of assets, net	2,756			4,189			12,443
Loss on impairment of property, plant and equipment	697			4,970			23,328
Loss on impairment of noncurrent assets held for sale	—			—			673
Loss on impairment of goodwill	15,456			156,427			—
Loss on extinguishment of debt	—			—			1,634
Other non-cash items	(469		)	(1,256		)	656
Earnings in unconsolidated affiliates	(40,158		)	(8,201		)	(348		)
Distributions from unconsolidated affiliates	40,158			8,201			348
Deferred tax expense	2,057			953			213
Allowance for bad debts	1,038			1,212			820
Changes in operating assets and liabilities, net of effects of assets acquired and liabilities assumed:
Accounts receivable	(5,430		)	5,609			79,804
Inventory	(1,909		)	13,095			17,716
Unbilled revenue	(219		)	53,120			(51,158		)
Risk management assets and liabilities	(1,030		)	(875		)	(809		)
Other current assets	(795		)	1,948			(16,099		)
Other assets, net	682			(80		)	6,068
Accounts payable	(2,242		)	(50,885		)	(28,732		)
Accrued gas purchases	610			(7,045		)	(5,540		)
Accrued expenses and other current liabilities	15,384			3,623			(4,657		)
Asset retirement obligations	(858		)	(90		)	(1,030		)
Other liabilities	483			835			80
Corporate overhead support from General Partner	7,500			3,000			—
Net cash provided by operating activities	90,639			86,978			51,635
Cash flows from investing activities
Cost of acquisitions, net of cash acquired and settlements	(2,676		)	(5,200		)	(362,316		)
Investments in unconsolidated affiliates	(150,179		)	(65,701		)	(12,000		)
Additions to property, plant and equipment	(147,796		)	(208,040		)	(153,876		)
Proceeds from disposal of property, plant and equipment	11,788			8,730			17,648
Distributions from unconsolidated affiliates, return of capital	42,886			12,367			1,632
Restricted cash	(318,527		)	7,075			(9,111		)
Net cash used in investing activities	(564,504		)	(250,769		)	(518,023		)

F-7

Cash flows from financing activities
Proceeds from issuance of common units, net of offering costs	2,825			82,488			466,893
Unitholder contributions	1,998			1,905			5,588
Unitholder distributions	(112,136		)	(100,411		)	(119,965		)
Issuance of convertible preferred units, net of offering costs	34,413			44,768			—
Issuance of Series B Units	—			—			30,000
Issuance of Series D preferred units - JPE	—			—			40,000
Redemption of Series D preferred units - JPE	—			—			(42,436		)
Unitholder distributions for common control transactions	—			(96,297		)	(52,000		)
Contributions from noncontrolling interest owners	3,366			584			—
Distributions to noncontrolling interest owners	(1,488		)	(114		)	(322		)
LTIP tax netting unit repurchases	(521		)	(1,045		)	(610		)
Payment of financing costs	(5,327		)	(2,244		)	(7,034		)
Proceeds from 3.77% Senior Notes	60,000			—			—
Proceeds from 8.50% Senior Notes	294,000			—			—
Payments on other debt	(3,136		)	(4,069		)	(7,621		)
Other	—			(688		)	(1,344		)
Borrowings on other debt	—			4,709			3,449
Payments on revolving credit agreements	(223,950		)	(240,150		)	(736,227		)
Borrowings on revolving credit agreements	425,100			471,300			883,885
Contributions from the predecessor	2,400			1,218			4,321
Net cash provided by financing activities	477,544			161,954			466,577
Net increase (decrease) in cash and cash equivalents	3,679			(1,837		)	189
Cash and cash equivalents
Beginning of period	1,987			3,824			3,635
End of period	$	5,666		$	1,987		$	3,824

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, Basis of Presentation and Summary of Significant Accounting Policies

General

American Midstream Partners, LP (the “Partnership”, “we”, “us”, or “our”) is a growth-oriented Delaware limited partnership that was formed on August 20, 2009 to own, operate, develop and acquire a diversified portfolio of midstream energy assets. The Partnership’s general partner, American Midstream GP, LLC (the “General Partner”), is 77% owned by High Point Infrastructure Partners, LLC (“HPIP”) and 23% owned by Magnolia Infrastructure Holdings, LLC, both of which are affiliates of ArcLight Capital Partners, LLC ("ArcLight"). Our capital accounts consist of notional General Partner units and units representing limited partner interests.

Nature of business

We provide critical midstream infrastructure that links producers of natural gas, crude oil, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets. Through our six reportable segments, (1) gas gathering and processing services, (2) liquid pipelines and services, (3) natural gas transportation services, (4) offshore pipelines and services, (5) terminalling services and (6) propane marketing services, we engage in the business of gathering, treating, processing, and transporting natural gas; gathering, transporting, storing, treating and fractionating NGLs; gathering, storing and transporting crude oil and condensates; storing specialty chemical products; and distributing and selling propane and refined products. Most of our cash flow is generated from fee-based and fixed-margin compensation for gathering, processing, transporting and treating natural gas and crude oil, firm capacity reservation charges, interruptible transportation charges, guaranteed firm storage contracts, throughput fees and other optional charges associated with ancillary services.

Our primary assets are strategically located in some of the most prolific onshore and offshore producing regions and key demand markets in the United States. Our gathering and processing assets are primarily located in (i) the Permian Basin of West Texas, (ii) the Cotton Valley/Haynesville Shale of East Texas, (iii) the Eagle Ford Shale of South Texas, (iv) the Bakken Shale of North Dakota, and (v) offshore in the Gulf of Mexico. Our transmission and terminal assets are in key demand markets in Oklahoma, Alabama, Arkansas, Louisiana, Mississippi and Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia. Our propane marketing services include commercial and retail operations across 46 of the lower 48 states.

Basis of presentation

As discussed in Note 2, we acquired JP Energy Partners, LP ("JPE") in a unit-for-unit exchange on March 8, 2017. As both the Partnership and JPE were controlled by ArcLight, the acquisition represents a transaction among entities under common control and has been accounted for as a common control transaction in a manner similar to a pooling of interests. Although the Partnership is the legal acquirer, JPE is considered to be the acquirer for accounting purposes as ArcLight obtained control of JPE before it obtained control the Partnership. The accompanying financial statements represent the JPE historical cost basis financial statements retrospectively adjusted to reflect its acquisition of the Partnership at ArcLight’s historical cost basis effective April 15, 2013, the date on which ArcLight obtained control of the Partnership. As the Partnership was the legal acquirer, unit amounts included in the accompanying financial statements represent the Partnership’s historical unit amounts plus the JPE unit amounts adjusted by the applicable exchange ratios.

Transactions between entities under common control

We may enter into transactions with ArcLight affiliates whereby we receive midstream assets or other businesses in exchange for cash or Partnership equity. We account for the net assets acquired at the affiliate's historical cost basis as the transactions are between entities under common control. In certain cases, our historical financial statements will be revised to include the results attributable to the assets acquired from the later of April 15, 2013 (the date Arclight affiliates obtained control of our General Partner) or the date the ArcLight affiliate obtained control of the assets acquired.

Consolidation policy

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.

F-9

Use of estimates

When preparing consolidated financial statements in conformity with accounting principles generally accepted in the United States of America ("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 assumptions are based on information available at the time such estimates and assumptions are made. Adjustments made with respect to the use of these estimates and assumptions often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates and assumptions 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, cash equivalents and restricted cash

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.

From time to time we are required to maintain cash in separate accounts the use of which is restricted by the terms of our debt agreements or asset retirement obligations. Such amounts are included in Restricted cash in our consolidated balance sheets.

Inventory

Inventory is mainly comprised of crude oil, NGLs, and refined products for resale, as well as propane cylinders expected to be sold to customers. Inventory is stated at the lower of cost or market. The cost of crude oil, NGL, and refined products is determined using the first-in, first-out (FIFO) method while the cost of propane cylinders is determined using the weighted average cost method.

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. We recorded allowances for doubtful accounts of $1.9 million and $1.2 million, respectively, as of December 31, 2016 and December 31, 2015. Bad debt expense for the years ended December 31, 2016, 2015 and 2014 was $1.0 million, $1.2 million and $0.8 million, respectively.

Derivative financial instruments

Our net income (loss) 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. We record all derivative financial instruments in our consolidated balance sheets at fair value as current and long-term assets or liabilities on a net basis by counterparty. We record changes in the fair value of our commodity derivatives in Gains (losses) oncommodity derivatives, net while changes in the fair value of our interest rate swaps are included in Interest expense in our consolidated statements of operations.

Our 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 our net income (loss) each period. We use published market price information where available, or quotations from over-the-counter, market makers to find executable bids and offers. The valuations also reflect the potential impact of related conditions, including credit risk of our counterparties. The

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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.

We are also a party to a number of contracts that have elements of a derivative instrument. These contracts are primarily forward propane and crude oil purchase and sales contracts with counterparties. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for the normal purchase and normal sales exception because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold. As a result, these contracts are not recorded in our consolidated financial statements until they are settled.

Fair value measurements

We apply the authoritative accounting provisions for measuring the fair value of our derivative financial 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.

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. We also capitalize expenditures that improve or extend the useful life of an asset. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.

We record property, plant, and equipment at cost and recognize depreciation expense on a straight-line basis over the related estimated useful lives of the assets which range from 3 to 40 years. 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.

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, our estimate of fair value is re-determined when related events or circumstances change.

Impairment of long lived Assets

We evaluate the recoverability of our property, plant and equipment and intangible assets with definite lives when events or circumstances indicate we may not recover the carrying amount of the assets. We continually monitor our operations, the market, and business environment to identify indicators that could suggest an asset or asset group may not be recoverable. We evaluate the asset or asset group for recoverability by estimating the undiscounted future cash flows expected to be derived from their use

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and disposition. 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. An asset or asset group is considered impaired when the estimated undiscounted cash flows are less than the carrying amount. In that event, an impairment loss is recognized to the extent that the carrying amount of the asset or asset group exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of fair values 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 operations.

Goodwill and intangible assets

We record goodwill for the excess of the cost of an acquisition over the fair value of the net assets of the acquired business. Goodwill 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, relationships and dedicated acreage agreements as intangible assets. These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging between 5 years and 30 years. We assess intangible assets for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

Investment in unconsolidated affiliates

We hold membership interests in entities that own and operate natural gas pipeline systems and NGL and crude oil pipelines in and around Louisiana, Alabama, Mississippi and the Gulf of Mexico. While we have significant influence over these entities, we do not control them and therefore, they are accounted for using the equity method and are reported in Investment in unconsolidated affiliates in the consolidated balance sheets. We evaluate the recoverability of these investments on a regular basis and recognize impairment write downs if we determine a loss in value represents an other than temporary decline.

Deferred financing costs

Costs incurred in connection with our revolving credit agreements are deferred and charged to interest expense over the term of the related credit arrangement. Such amounts are included in Other assets, net in our consolidated balance sheets. Costs incurred in connection with our 8.50% Senior Notes and 3.77% Senior Notes are also deferred and charged to interest expense over the respective term of the agreements; however, these amounts are reflected as a reduction of the related obligation. Gains or losses on debt repurchases or extinguishment include any associated unamortized deferred financing costs.

Asset retirement obligations

Asset retirement obligations ("ARO") are legal obligations associated with the retirement of tangible long-lived assets that result from the asset's acquisition, construction, development and operation. An ARO is initially measured at its estimated fair value. Upon initial recognition, we also record an increase to the carrying amount of the related long-lived asset. We depreciate the asset using the straight-line method over the period during which it is expected to provide benefits. After initial recognition, we revise the ARO to reflect the passage of time and for changes in the estimated amount or timing of cash flows.

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 certain 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 for purposes 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.

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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 periods 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.

We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liability has been incurred and the amount of 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.

Noncontrolling interests

Noncontrolling interests represent the minority interest holders' proportionate share of the equity in certain of our consolidated subsidiaries and are adjusted for the minority interest holders' proportionate share of the subsidiaries' earnings or losses each period.

Revenue recognition

We recognize revenue from the sale of commodities (e.g., natural gas, crude oil, NGLs or condensate) as well as from the provision of gathering, processing, transportation or storage services 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 recognize revenue from the sale of commodities and the related cost of product sold on a gross basis for those transactions where we act as the principal and take title to commodities that are purchased for resale.

Cost of sales

Cost of sales represent the cost of commodities purchased for resale or obtained in connection with certain of our customer revenue arrangements. These costs do not include an allocation of depreciation expense or direct operating costs.

Corporate expenses

Corporate expenses include compensation costs for executives and administrative personnel, professional service fees, rent expense and other general and administrative expenses and are recognized as incurred.

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 in Other current assets or Accrued expenses and other current liabilities on our consolidated balance sheets at cost which approximates fair value.

Equity-based compensation

We award equity-based compensation to management, non-management employees and directors under our long-term incentive plans, which provide for the issuance of options, unit appreciation rights, restricted units, phantom units, other unit-based awards, unit awards or replacement awards, as well as tandem distribution equivalent rights ("DERs"). Compensation expense is measured by the fair value of the award at the date of grant as determined by management. Compensation expense is recognized in Corporate expenses and Direct operating expenses over the requisite service period of each award.

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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 are generally borne by our unitholders through the allocation of taxable income. American Midstream Blackwater, LLC, a subsidiary of the Partnership, owns a subsidiary that has operations which are subject to both federal and state income taxes. We account for income taxes of that subsidiary using the asset and liability approach. If it is more than likely that a deferred tax asset will not be realized, a valuation allowance is recognized.

Margin tax expense results from the enactment of laws by the State of Texas that apply to entities organized as partnerships and is included in Income tax expense in our consolidated statements of operations. The Texas margin tax is computed on the portion of our taxable margin which is apportioned to Texas.

Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) allocable to unitholders as a result of differences between the financial reporting and income tax bases of our 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.

Accumulated other comprehensive income (loss)

Accumulated other comprehensive income (loss) is comprised solely of adjustments related to the Partnership's postretirement benefit plan.

Limited partners' net income (loss) per unit

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

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

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New Accounting Pronouncements

Recently Adopted Accounting Standards

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for fiscal years beginning after December 15, 2015, including interim periods therein, and is applied retrospectively. Early adoption is permitted for financial statements that have not been previously issued. ASU 2015-15, Presentation and Subsequent Measurement of Debt Issue Costs Associated with Line of Credit Arrangements, was subsequently issued to address the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements and states that the Securities and Exchange Commission ("SEC") staff will not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement.

The Partnership adopted the requirements of ASU No. 2015-03 effective January 1, 2016 and classifies the debt issuance costs applicable to its 8.50% Senior Notes and 3.77% Senior Notes as a reduction of the related debt obligation. Additionally, the Partnership continues to classify the debt issuance costs relating to its Credit Agreement within Other assets, net as allowed by ASU No. 2015-15.

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805). This update requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The Partnership adopted the updated guidance effective January 1, 2016 without impact to its financial statements.

Accounting Standards Issued Not Yet Adopted

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which amends the existing accounting guidance for revenue recognition. The update requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2015-14 was subsequently issued and deferred the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that period. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations, as further clarification on principal versus agent considerations. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing as further clarification on identifying performance obligations and the licensing implementation guidance. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, as clarifying guidance on specific narrow scope improvements and practical expedients. We are in the process of reviewing our various customer arrangements in order to determine the impact that these updates will have on our consolidated financial statements and related disclosures. We have engaged a third-party consultant to assist with our review, which we currently expect to complete in the third quarter of 2017.

In February 2016, the FASB issued ASU No. 2016-02 (Topic 842) "Leases" which supersedes the lease recognition requirements in Accounting Standards Codification Topic 840, "Leases". Under ASU No. 2016-02 lessees are required to recognize assets and liabilities on the balance sheet for most leases and provide enhanced disclosures. Leases will continue to be classified as either finance or operating. ASU No. 2016-02 is effective for annual reporting periods, and interim periods within those years beginning after December 15, 2018. Entities are required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements, and there are certain optional practical expedients that an entity may elect to apply. Full retrospective application is prohibited and early adoption by public entities is permitted. Based upon our evaluation to date, we anticipate that the adoption of ASU 2016-02 will have a material effect on our consolidated financial statements as we will be required to reflect our various lease obligations and associated asset use rights on our consolidated balance sheets. The adoption may also impact our debt covenant compliance and may require us to modify or replace certain of our existing information systems. We have not yet determined the timing or manner in which we will implement the updated guidance.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 320): Classification of Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity of presentation and classification in the statement of cash flows. ASU No. 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal periods. Early adoption is permitted, but only if all aspects are adopted in the same

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period. The Partnership is currently evaluating the impact this update will have on its consolidated statements of cash flows and related disclosures.

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, which aims to improve the disclosure of the change during the period in total cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statement of cash flows. The update is effective beginning first quarter of 2018. Early adoption is permitted, but it must occur in the first interim period. Any adjustments required in early adoption of this update should be reflected as of the beginning of the fiscal year that includes the interim period and should be applied using a retrospective transition method to each period. The Partnership is evaluating the impact that this update will have on our consolidated statement of cash flows and related disclosures.

2. Acquisitions and Divestitures

JP Energy Partners

On March 8, 2017, the Partnership completed the acquisition of JPE, an entity controlled by ArcLight affiliates, in a unit-for-unit exchange. In connection with the transaction, each JPE common or subordinated unit held by investors not affiliated with ArcLight was converted into the right to receive 0.5775 of a Partnership common unit, and each JPE common or subordinated unit held by ArcLight affiliates was converted into the right to receive 0.5225 of a Partnership common unit. The Partnership issued a total of 20.2 million of its common units to complete the acquisition, including 9.8 million common units to ArcLight affiliates. Based upon the closing price for our common units on March 8, 2017, the units issued in the exchange had an estimated fair value of $322.2 million.

JPE owns, operates and develops a diversified portfolio of midstream energy assets with three business segments (i) crude oil pipelines and storage, (ii) refined products terminals and storage and (iii) NGL distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs, in the United States.

As both the Partnership and JPE were controlled by ArcLight, the acquisition represents a transaction among entities under common control and is accounted for as a common control transaction in a manner similar to a pooling of interests. Although the Partnership is the legal acquirer, JPE is considered to be the acquirer for accounting purposes as ArcLight obtained control of JPE before it obtained control the Partnership. The accompanying financial statements represent the JPE historical cost basis financial statements, retrospectively adjusted to reflect its acquisition of the Partnership at ArcLight’s historical cost basis effective April 15, 2013, the date on which ArcLight obtained control of the Partnership.

Delta House Investment

On September 18, 2015, the Partnership acquired a 26.3% interest in Pinto Offshore Holdings, LLC ("Pinto"), an entity that owns 49% of the Class A Units of Delta House FPS LLC and of Delta House Oil and Gas Lateral LLC (collectively referred to herein as "Delta House"), a floating production system platform with associated crude oil and gas export pipelines, located in the Mississippi Canyon region of the deepwater Gulf of Mexico ("Delta House").

We acquired our 26.3% non-operated interest in Pinto in exchange for $162.0 million in cash, funded by the proceeds of a public offering of 7.5 million of the Partnership's common units and with borrowings under the Partnership’s Amended and Restated Credit Agreement (the "Credit Agreement"). As a result, we own a minority interest in Pinto, which represents an indirect interest in 12.9% of Delta House's Class A Units. Pursuant to the Pinto LLC Agreement, we have no management control or authority over the day-to-day operations. Our interest in Pinto is accounted for as an equity method investment in the consolidated financial statements.

Because our interest in Delta House was previously owned by an ArcLight affiliate, we recorded our investment at the affiliate's historical cost basis of $65.7 million in Investments in unconsolidated affiliates in our consolidated balance sheets and as an investing activity within the related consolidated statements of cash flows. The amount by which the total consideration exceeded affiliate's historical cost basis was $96.3 million and is recorded as a distribution within the consolidated statements of changes in equity, partners’ capital and noncontrolling interests and as a financing activity in the consolidated statements of cash flows.

On April 25, 2016, the Partnership increased its investment in Delta House through the purchase of 100% of the outstanding membership interests in D-Day Offshore Holdings, LLC (“D-Day”), an Arclight affiliate which owned 1.0% of Delta House Class A Units in exchange for approximately $9.9 million in cash funded with borrowings under our revolving credit agreement.

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Because the additional investment in Delta House was previously owned by an ArcLight affiliate, we recorded our investment in D-Day at the affiliate’s historical cost basis of $9.9 million in Investments in unconsolidated affiliates on our consolidated balance sheets and as an investing activity within our condensed consolidated statements of cash flows.

On October 31, 2016, D-Day acquired an additional 6.2% direct interest in Delta House Class A Units from unrelated parties for approximately $48.8 million which was funded with $34.5 million in net proceeds from the issuance of 2,333,333 Series D convertible preferred units ("Series D Preferred Units") to an ArcLight affiliate, plus $14.3 million in cash funded with borrowings under our Credit Agreement. Our share of Delta House earnings is included in the Offshore Pipelines and Services segment gross margin.

Our investments in D-Day and Pinto result in our holding a 20.1% non-operated direct and indirect interests in the Class A units of Delta House as of December 31, 2016. Such interests include a 20.1% interest in Class A Units of Delta House FPS, which are currently entitled to receive 100% of the distributions from Delta House FPS until a certain payout threshold is met. Once the payout threshold is met, approximately 7% of distributions from Delta House FPS will be paid to the Class B membership interests in Delta House FPS.

Emerald Transactions

On April 25, 2016 and April 27, 2016, American Midstream Emerald, LLC (“Emerald”), a wholly-owned subsidiary of the Partnership, entered into two purchase and sale agreements with Emerald Midstream, LLC, an ArcLight affiliate, for the purchase of membership interests in certain midstream entities.

On April 25, 2016, Emerald entered into the first purchase and sale agreement for the purchase of membership interests in entities that own and operate natural gas pipeline systems and NGL pipelines in and around Louisiana, Alabama, Mississippi, and the Gulf of Mexico (the “Pipeline Purchase Agreement”). Pursuant to the Pipeline Purchase Agreement, Emerald acquired (i) 49.7% of the issued and outstanding membership interests of in Destin Pipeline Company, L.L.C. (“Destin”), (ii) 16.7% of the issued and outstanding membership interests of Tri-States NGL Pipeline, L.L.C. ("Tri-States"), and (iii) 25.3% of the issued and outstanding membership interests of Wilprise Pipeline Company, L.L.C. (“Wilprise”), in exchange for approximately $183.6 million (the “Pipeline Transaction”).

The Destin pipeline is a FERC-regulated, 255-mile natural gas transportation system with total capacity of 1.2 Bcf/d. The system originates offshore in the Gulf of Mexico and includes connections with four producing platforms and six producer-operated laterals, including Delta House. The 120-mile offshore portion of the Destin system terminates at the Pascagoula processing plant, which is owned by Enterprise Products Partners, LP, and is the single source of raw natural gas to the plant. The onshore portion of Destin is the sole delivery point for merchant-quality gas from the Pascagoula processing plant and extends 135 miles north in Mississippi. Destin currently serves as the primary transfer of gas flows from the Barnett and Haynesville shale plays to Florida markets through interconnections with major interstate pipelines. Contracted volumes on the Destin pipeline are based on life-of-field dedications, dedicated volumes over a given period, or interruptible volumes as capacity permits. We became the operator of the Destin pipeline on November 1, 2016. The Tri-States pipeline is a FERC-regulated, 161-mile NGL pipeline and sole form of transport to Louisiana-based fractionators for NGLs produced at the Pascagoula plant served by Destin and other facilities. The Wilprise pipeline is a FERC-regulated, approximately 30-mile NGL pipeline that originates at the Kenner Junction and terminates in Sorrento, Louisiana, where volumes flow via pipeline to a Baton Rouge fractionator.

On April 27, 2016, Emerald entered into a second purchase and sale agreement for the purchase of 66.7% of the issued and outstanding membership interests of Okeanos Gas Gathering Company, LLC ("Okeanos"), in exchange for a cash purchase price of approximately $27.4 million (such Purchase and Sale Agreement, the “Okeanos Purchase Agreement,” and such transaction, the “Okeanos Transaction,” and together with the Pipeline Transaction, the “Emerald Transactions”). The Okeanos pipeline is a 100-mile natural gas gathering system located in the Gulf of Mexico with a total capacity of 1.0 Bcf/d. The Okeanos pipeline connects two platforms and one lateral, terminating at the Destin Main Pass 260 platform in the Mississippi Canyon region of the Gulf of Mexico. Contracted volumes on the Okeanos pipeline are based on life-of-field dedication. We became the operator of the Okeanos pipeline on November 1, 2016.

The Partnership funded the aggregate purchase price for the Emerald Transactions with the issuance of 8,571,429 Series C convertible preferred units (the “Series C Units”) representing limited partnership interests in the Partnership and a warrant (the “ Series C Warrant”) to purchase up to 800,000 common units representing limited partnership interests in the Partnership (“common units”) at an exercise price of $7.25 per common unit amounting to a combined value of approximately $120.0 million, plus additional borrowings of $91.0 million under our Credit Agreement. ArcLight affiliates hold and participate in distributions on our Series C Units with such distributions being made in paid-in-kind Series C Units, cash or a combination thereof at the election

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of the Board of Directors of our General Partner. Our share of earnings of the entities underlying the Emerald transaction is included in the Liquid Pipelines and Services segment gross margin.

Because our interests in the entities underlying the Emerald Transactions were previously owned by an ArcLight affiliate, we recorded our investments at the affiliate’s historical cost basis of $212.0 million, in Investment in unconsolidated affiliates in our consolidated balance sheets, and as an investing activity of $100.9 million within the consolidated statements of cash flows. The amount by which the affiliate's historical basis exceeded total consideration paid was $1.0 million and is recorded as a contribution from our General Partner in the consolidated statements of changes in partners’ capital and noncontrolling interests.

Gulf of Mexico Pipeline

On April 15, 2016, American Panther LLC, ("American Panther"), a 60%-owned subsidiary of the Partnership, acquired approximately 200 miles of crude oil, natural gas, and salt water onshore and offshore Gulf of Mexico pipelines (“Gulf of Mexico Pipeline”) from Chevron Pipeline Company and Chevron Midstream Pipeline, LLC for approximately $2.7 million in cash and the assumption of certain asset retirement obligations. The Partnership controls American Panther and therefore consolidates it for financial reporting purposes.

The American Panther acquisition was accounted for using the acquisition method of accounting and as a result, the purchase price was allocated to the assets acquired and liabilities assumed based on their respective estimated fair values as of the acquisition date. The purchase price allocation included $16.6 million in pipelines, $0.4 million in land, $14.3 million in asset retirement obligations, and $1.8 million in noncontrolling interests.

American Panther contributed revenue of $13.2 million and operating income of $7.4 million to the Partnership for the year ended December 31, 2016. Such amounts are included in the Partnership’s Offshore Pipelines and Services segment. During the year ended December 31, 2016, the Partnership incurred $0.3 million of transaction costs related to the American Panther acquisition which are included in Corporate expenses in our consolidated statements of operations for the periods.

Unaudited pro forma financial information depicting what the Partnership's revenue, net income and per unit amounts would have been had the American Panther acquisition occurred on January 1, 2016, is not available because Chevron Pipeline Company and Chevron Midstream Pipeline, LLC did not historically operate the acquired assets as a standalone business.

Southern Propane Inc.

On May 8, 2015, we acquired substantially all of the assets of Southern Propane Inc. (“Southern”), a Houston-based industrial and commercial propane distribution and logistics company. The acquisition expanded the asset base and market share of our Propane Marketing and Services segment, specifically the acceleration of our entry into the Houston, Texas market, as well as expansion of our industrial, non-seasonal customers. The total purchase price of $16.3 million consisted of a $12.5 million cash payment that was paid on the acquisition date, and which was funded through the use of borrowings from our revolving credit facility, a $0.1 million cash payment to the seller as the final working capital adjustment, the issuance of 266,951 common units valued at $3.4 million and a contingent earn-out liability with an acquisition date fair. The gross profit targets were not achieved and the remaining $0.2 million liability was released to income in 2016.

The $16.3 million purchase price was allocated to customer relationship intangible assets $6.2 million, goodwill $5.8 million, property, plant and equipment $3.0 million, accounts receivable $1.0 million and other intangible assets $0.3 million. Goodwill associated with the acquisition principally results from synergies expected from integrated operations. The fair values of the acquired intangible assets were estimated by applying the income approach which is based on significant inputs that are not observable in the market and represents a Level 3 measurement. The customer relationship assets are being amortized over a weighted average useful life of 12 years.

Costar Acquisition

On October 14, 2014, the Partnership acquired 100% of the membership interests of Costar Midstream, L.L.C. ("Costar") from Energy Spectrum Partners VI LP and Costar Midstream Energy, LLC, in exchange for cash and common units with an aggregate value of $405.3 million. Costar is an onshore gathering and processing company with its primary gathering, processing, fractionation, and off-spec condensate treating and stabilization assets in East Texas and the Permian basin, with a significant crude oil gathering system project in the Bakken oil play.

The Costar acquisition was accounted for using the acquisition method of accounting and as a result, the purchase price was allocated to the assets acquired and liabilities assumed based on their respective fair values as of the acquisition date. The excess of the aggregate purchase price of the fair values of the assets acquired, liabilities assumed and the noncontrolling interest was

F-18

classified as goodwill, which was attributable to future prospective customer agreements expected to be obtained as a result of the acquisition. The operating systems acquired have been included in the Partnership’s Gathering and Processing segment from the acquisition date.

During 2015, the Partnership reached agreements with the Costar sellers regarding certain matters which resulted in a return of $7.4 million of cash to the Partnership and related reductions in the goodwill initially recorded. Additionally, in February 2016, the Partnership reached a settlement of certain indemnification claims with the Costar sellers whereby 1,034,483 common units held in escrow with a fair value of $6.8 million were returned to the Partnership, while the Partnership agreed to pay the Costar sellers an additional $0.3 million. The net impact of this settlement was recorded as a reduction in property, plant and equipment in the first quarter of 2016. The Partnership recognized a $95.0 million impairment of the remaining Costar goodwill in fourth quarter of 2015.

Lavaca Acquisition

On January 31, 2014, the Partnership acquired approximately 120 miles of high- and low-pressure pipelines and associated facilities located in the Eagle Ford shale in Gonzales and Lavaca Counties, Texas from Penn Virginia Corporation (NYSE: PVA) ("PVA") for $104.4 million in cash. The Lavaca acquisition was financed with proceeds from the Partnership's January 2014 equity offering and from the issuance of Series B Units to our General Partner.

The Lavaca acquisition was accounted for using the acquisition method of accounting and, as a result, the purchase price was allocated to the assets acquired upon their respective fair values as of the acquisition date. The excess of the purchase price over the fair value of the assets acquired was classified as goodwill, which was attributable to future prospective customer agreements expected to be obtained as a result of the acquisition. The operating systems acquired have been included in the Partnership’s Gathering and Processing segment from the acquisition date. The Partnership recognized a $23.6 million impairment of the remaining Lavaca goodwill in the fourth quarter of 2015.

JP Development

On February 12, 2014, JPE acquired a variety of midstream assets from JP Energy Development, LP (“JP Development”), an entity controlled by ArcLight, for $319.1 million, comprised of 5,841,205 of JPE Class A Common Units and $52.0 million in cash funded by borrowings under JPE’s revolving credit facility. As both JPE and JP Development were controlled by ArcLight, the acquisition represented a transaction among entities under common control and was accounted for as a common control transaction in a manner similar to a pooling of interests. In connection with the acquisition, ArcLight forgave related amounts receivable totaling $4.3 million. The cash portion of the purchase less the receivable forgiven has been reflected as a unitholder distribution for the JP Development transaction in the consolidated statement of equity and partners’ capital for the year ended December 31, 2014.

3. Discontinued Operations

Mid-Continent

On February 1, 2016, we sold certain trucking and marketing assets in the Mid-Continent area (the “Mid-Continent Business”) to JP Development for $9.7 million in cash. We recognized a loss on the disposal of approximately $12.9 million during the year ended December 31, 2015, which primarily related to goodwill and long-lived asset impairment charges. Prior to the classification as discontinued operations, we reported the Mid-Continent Business in our Liquid Pipelines and Services segment.

Financial information for the Mid-Continent Business which is included in Loss from discontinued operations, net of tax in the consolidated statement of operations is summarized below:

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	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Revenues
Total revenues	$	11,495		$	429,784		$	967,480
Costs and Expenses
Costs of sales	11,687			426,886			961,428
Direct operating expenses	203			2,269			2,866
Loss on impairment of goodwill and assets held for sale	—			12,909			—
Depreciation, amortization and accretion	211			2,281			2,258
(Gain) loss on sale of assets, net	(114		)	119			229
Total expenses	11,987			444,464			966,781
Operating (loss) income	(492		)	(14,680		)	699
Other income (expense)	(47		)	(271		)	(366		)
(Loss) income from discontinued operations before income tax expense	(539		)	(14,951		)	333
Income tax expense	—			—			—
Net (loss) income from discontinued operations	$	(539	)	$	(14,951	)	$	333

Bakken Business

On June 30, 2014, we sold our trucking and related assets in North Dakota, Montana and Wyoming (the “Bakken Business”) to Gold Spur Trucking, LLC for $9.1 million. We recognized a loss on this sale of approximately $7.3 million during the second quarter of 2014, which primarily related to the write-off of a related customer contract. We also recognized a $2.0 million goodwill impairment charge in connection with the transaction

Financial information for the Bakken Business which is included in Loss from discontinued operations, net of tax in the consolidated statement of operations is summarized below:

	Year Ended December 31, 2014
	(in thousands)
Total revenues	$	7,865
Net loss from discontinued operations, including loss on disposal of $7,288	(9,608		)

Blackwater

On December 17, 2013, we acquired Blackwater Midstream Holdings LLC ("Blackwater") from an ArcLight affiliate. As part of the Blackwater acquisition, we acquired certain long-lived terminal assets which were immediately classified as held for sale. Due to deteriorating market conditions, the Partnership recognized an impairment charge on these assets of $0.7 million in 2014. These assets were sold during the third quarter of 2015 at a nominal loss.

Financial information for the portion of the Blackwater business sold which is included in Loss from discontinued operations, net of tax in the consolidated statement of operations is summarized below:

	Years Ended December 31,
	2015			2014
	(in thousands)
Total revenues	$	74		$	474
Loss from discontinued operations, net of tax	(80		)	(611		)

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Due to immateriality, we elected to not separately present the cash flows from operating, investing and financing activities related to the discontinued operations described above in our consolidated statements of cash flows.

4. Concentration of Credit Risk

Significant customers are defined as those who represent 10% of more of our consolidated revenue during the year. In 2016, we had two such customers who accounted for 17% and 10%, respectively, of our consolidated revenue. In 2015, we had one such customer who accounted for 28% of our consolidated revenue. In 2014, we had one such customer who accounted for 16% of our consolidated revenue.

We are party to various commercial netting agreements that allow us and contractual counterparties to net receivable and payable obligations. These agreements are customary and the terms follow standard industry practice. In the opinion of management, these agreements reduce the overall counterparty risk exposure.

5. Inventory

Inventory consists of the following:

	December 31,
	2016		2015
	(in thousands)
Crude oil	$	1,216	$	486
NGLs	3,482		2,638
Refined products	291		463
Materials, supplies and equipment	1,787		1,654
Total inventory	$	6,776	$	5,241

6. Other Current Assets

Other current assets consists of the following:

	December 31,
	2016		2015
	(in thousands)
Prepaid insurance	$	9,702	$	5,187
Insurance receivables	2,895		115
Other receivables	2,998		2,688
Due from related parties	4,805		8,688
Risk management assets	964		365
Other assets	6,303		5,753
Discontinued operations, current assets	—		2,730
Total other current assets	$	27,667	$	25,526

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7. Risk Management Activities

Commodity Derivatives

To limit the effect of commodity price changes and maintain our cash flow and the economics of our development plans, we enter into commodity derivative contracts from time to time. The terms of the contracts depend on various factors, including management's view of future commodity prices, economics on purchased assets and future financial commitments. This hedging program is designed to mitigate the effect of commodity price declines while allowing us to participate to some extent in commodity price increases. Management regularly monitors the commodity markets and our 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.

To meet this objective, we use a combination of fixed price swaps, basis swaps and forward contracts. We enter into commodity contracts with multiple counterparties, and in some cases, may be required to post collateral with our counterparties in connection with our derivative positions. The counterparties are not required to post collateral with us in connection with their derivative positions. Netting agreements are in place that permit us to offset our commodity derivative asset and liability positions with our counterparties. At times, we may also terminate or unwind hedges or portions of hedges in order to meet cash flow objectives or when the expected future volumes do not support the level of hedges. Our forward contracts that qualify for the normal purchase normal sale exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction no longer meets the exception, the fair value of the related contract is recorded on the consolidated balance sheets and immediately recognized through earnings.

In August 2015, we paid approximately $8.7 million to settle all of our then-outstanding propane financial swap contracts that were scheduled to mature at various dates through April 2017. We simultaneously executed new propane financial swap contracts at the then current forward market prices for the purpose of economically hedging a substantial majority of our fixed price propane sales contracts through July 2017.

The following table summarizes the net notional volume buy (sell) of our outstanding commodity-related derivatives, excluding those derivatives that qualified for the normal purchase normal sale exception as of December 31, 2016 and 2015, none of which were designated as hedges for accounting purposes.

	December 31, 2016		December 31, 2015
	Notional Volume	Maturity	Notional Volume	Maturity
Commodity Swaps:
Propane Fixed Price (Gallons)	4,364,880	Jan 2017 - Nov 2018	8,614,631	Jan 2016 - July 2017
Crude Oil Fixed Price (Barrels)	—	—	(93,000)	Jan 2016
Crude Oil Basis (Barrels)	180,000	Jan 2017 - Mar 2017	—	—

Interest Rate Swaps

To manage the impact of the interest rate risk associated with our Credit Agreement, we enter into interest rate swaps from time to time, effectively converting a portion of the cash flows related to our long-term variable rate debt into fixed rate cash flows.

Notional Amount	Term	Fair Value
(in thousands)		(in thousands)
$200,000	January 3, 2017 thru September 3, 2019	$	1,912
$100,000	January 1, 2017 thru December 31, 2017	(71		)
$100,000	January 1, 2018 thru January 31, 2019	226
$100,000	January 1, 2018 thru December 31, 2021	3,090
$150,000	January 1, 2018 thru December 31, 2022	5,219
		$	10,376

The fair value of our interest rate swaps was estimated using a valuation methodology based upon forward interest rate and volatility curves as well as other relevant economic measures, if necessary. Discount factors may be utilized to extrapolate a forecast of

F-22

future cash flows associated with long dated transactions or illiquid market points. The inputs, which represent Level 2 inputs in the valuation hierarchy, are obtained from independent pricing services and we have made no adjustments to those prices.

Weather Derivative

In the second quarters of 2016 and 2015, we entered into weather derivatives to mitigate the impact of potential unfavorable weather to our operations under which we could receive payments totaling up to $30.0 million in the event that a hurricane or hurricanes of certain strength pass through the area as identified in the related agreement. The weather derivatives, which are accounted for using the intrinsic value method, were entered into with a single counterparty and we were not required to post collateral.

We paid premiums of $1.0 million and $0.9 million in 2016 and 2015, respectively, which are amortized to Direct operating expenses on a straight-line basis over the 1 year term of the contract. Unamortized amounts associated with weather derivatives were approximately $0.4 million at December 31, 2016 and 2015, and are included in Other current assets on the consolidated balance sheets.

Our interest rate swaps, commodity swaps and weather derivatives were recorded in our consolidated balance sheets, under the following captions:

	Gross Risk Management Position						Netting Adjustment						Net Risk Management Position
Balance Sheet Classification	December 31, 2016			December 31, 2015			December 31, 2016			December 31, 2015			December 31, 2016			December 31, 2015
	(in thousands)
Other current assets	$	1,036		$	457		$	(72	)	$	(92	)	$	964		$	365
Risk management assets - long term	10,665			—			(1		)	—			10,664			—
Total assets	$	11,701		$	457		$	(73	)	$	(92	)	$	11,628		$	365
Accrued expenses and other current liabilities	$	(253	)	$	(450	)	$	72		$	92		$	(181	)	$	(358	)
Other liabilities	(1		)	(24		)	1			—			—			(24		)
Total liabilities	$	(254	)	$	(474	)	$	73		$	92		$	(181	)	$	(382	)

F-23

For the years ended December 31, 2016, 2015 and 2014, 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 following captions:

	Realized			Unrealized
	(in thousands)
2016
Losses on commodity derivatives, net	$	(1,480	)	$	1,025
Interest expense	(144		)	10,375
Direct operating expenses	(966		)	—
Total	$	(2,590	)	$	11,400
2015
Losses on commodity derivatives, net	$	(13,209	)	$	11,477
Interest expense	(425		)	373
Direct operating expenses	(913		)	—
Total	$	(14,547	)	$	11,850
2014
Losses on commodity derivatives, net	$	(337	)	$	(12,334	)
Interest expense	(707		)	284
Direct operating expenses	(1,035		)	—
Total	$	(2,079	)	$	(12,050	)

8. Property, Plant and Equipment, Net

Property, plant and equipment, net. consists of the following:

	Useful Life (in years)	December 31, 2016			December 31, 2015
		(in thousands)
Land	N/A	$	23,520		$	18,902
Construction in progress	N/A	131,448			58,146
Transportation Equipment	5 to 15	44,060			46,582
Buildings and improvements	4 to 40	24,225			22,398
Processing and treating plants	8 to 40	120,977			102,111
Pipelines and compressors	3 to 40	804,815			775,486
Storage	3 to 40	210,579			210,208
Equipment	5 to 20	102,409			78,131
Total property, plant and equipment		1,462,033			1,311,964
Less accumulated depreciation		(317,030		)	(240,450		)
Property, plant and equipment, net		$	1,145,003		$	1,071,514

At December 31, 2016 and 2015, gross property, plant and equipment included $291.1 million and $228.9 million, respectively, related to our FERC regulated interstate and intrastate assets.

Depreciation expense totaled $82.8 million, $75.0 million and $50.9 million for the years ended December 31, 2016, 2015 and 2014, respectively, which is included in the depreciation, amortization and accretion expense in the consolidated statements of operations. Depreciation expense amounts have been adjusted by $0.1 million, $1.1 million, and $1.7 million for the years ended December 31, 2016, 2015 and 2014, respectively, to present the Mid-Continent and Bakken Business's operations as discontinued operations. Capitalized interest was $2.7 million, $1.9 million and $0.8 million for the years ended December 31, 2016, 2015 and 2014, respectively.

F-24

During the fourth quarter of 2014, management noted the declining commodity markets and related impact on producers and shippers to whom we provide gathering and processing services. The decline in the market price of crude oil led to a corresponding decrease in natural gas and crude oil production impacting the volume of natural gas and NGLs we gather and process on certain assets. As a result, an asset impairment charge of $21.3 million was recorded to reduce the carrying value of the impacted assets to their estimated fair value. The related fair value measurements were based on significant inputs not observable in the market and thus represented Level 3 measurements. Primarily using the income approach, the fair value estimates were based on i) present value of estimated EBITDA, ii) an assumed discount rate of 9.5%, and iii) the expected remaining useful life of the asset groups.

9. Goodwill and Intangible Assets, Net

Management performs an annual goodwill assessment at the reporting unit level. We first assess qualitative factors to evaluate whether it is more likely than not that an impairment has occurred and if it is then necessary to perform the two-step goodwill impairment test. The two-step goodwill impairment test involves fair value measurements that are based on significant inputs not observable in the market and thus represent Level 3 measurements. In the two-step assessment, management primarily uses a discounted cash flow analysis, supplemented by a market approach analysis. Key assumptions in the discounted cash flow analysis include an appropriate discount rate, estimated volumes, storage utilization, terminal year multiples, operating costs and maintenance capital expenditures. In estimating cash flows, management incorporates current market information, as well as historical and other factors into the forecasted commodity prices and contracted rates used.

As a result of our step one analysis in the fourth quarter of 2015, we determined that the estimated fair value of certain reporting units within our Gas Gathering and Processing Services, Liquid Pipelines and Services and Propane Marketing Services reportable segments were less than their respective carrying amounts, primarily due to changes in assumptions related to commodity prices, the timing of estimated drilling by producers, and discount rates. These assumptions were adversely impacted by the continuing decline in market conditions within the energy sector at the time.

The second step of the goodwill impairment test involved allocating the estimated fair value of each reporting unit among the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. The results of the hypothetical purchase price allocation indicated there was no fair value attributable to goodwill of the reporting units within our Gas Gathering and Processing Services reportable segment and we recognized an impairment charge of $118.6 million which consisted of $95.0 million and $23.6 million related to the Costar and Lavaca acquisitions, respectively. In addition, we recognized a $23.6 million impairment charge in our Liquid Pipelines and Services reportable segment relating to our Crude Oil Supply and Logistics business, and a $6.3 million impairment charge in our Propane Marketing Services reportable segment related to JP Liquids. As a result, we recognized total goodwill impairment charges of $148.5 million during the year ended December 31, 2015. In 2016, we recognized additional goodwill impairment charges totaling $15.5 million in our Propane Marketing Services reportable segment, which consisted of $12.8 million and $2.7 million related to our Pinnacle Propane Express and JP Liquids businesses, respectively. Given the market condition trend surrounding Pinnacle Propane Express and JP Liquids, we may recognize further impairments related to those assets in the future.

The following table presents activity in the Partnership's goodwill balance:

	Gas Gathering and Processing Services			Liquid Pipelines and Services			Terminalling Services		Propane Marketing Services			Total
	(in thousands)
Balance at January 1, 2015	$	125,974		$	137,243		$	88,466	$	31,335		$	383,018
Goodwill acquired during the year	—			—			—		5,806			5,806
Return of purchase price	(7,382		)	—			—		—			(7,382		)
Impairment charges	(118,592		)	(23,574		)	—		(6,322		)	(148,488		)
Balance at December 31, 2015	—			113,669			88,466		30,819			232,954
Impairment charges				—			—		(15,456		)	(15,456		)
Balance at December 31, 2016	$	—		$	113,669		$	88,466	$	15,363		$	217,498

Intangible assets, net, consists of customer relationships, customer contracts, dedicated acreage agreements, and collaborative arrangements as acquired in connection with business combinations. These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging from approximately 5 years to 30 years. Intangible assets, net, consist of the following:

F-25

	December 31,
	2016			2015
	(in thousands)
Gross carrying amount:
Customer relationships	$	133,503		$	136,030
Customer contracts	95,594			95,594
Dedicated acreage	53,350			53,350
Collaborative arrangements	11,884			11,884
Noncompete agreements	3,423			3,575
Other	751			751
	$	298,505		$	301,184
Accumulated amortization:
Customer relationships	$	(31,471	)	$	(23,885	)
Customer contracts	(33,414		)	(24,538		)
Dedicated acreage	(4,439		)	(2,661		)
Collaborative arrangements	(601		)	—
Noncompete agreements	(3,086		)	(2,664		)
Other	(211		)	(155		)
	$	(73,222	)	$	(53,903	)
Net carrying amount:
Customer relationships	$	102,032		$	112,145
Customer contracts	62,180			71,056
Dedicated acreage	48,911			50,689
Collaborative arrangements	11,283			11,884
Noncompete agreements	337			911
Other	540			596
	$	225,283		$	247,281

In connection with the sale of the Mid-Continent Business we recorded an impairment charge of $0.7 million related to customer relationships during the year ended December 31, 2015, which is included in net loss from discontinued operations, net of tax in the consolidated statement of operations. In addition, as a result of the sale of the Bakken Business, we wrote-off $8.1 million in customer contracts during the year ended December 31, 2014.

For the years ended December 31, 2016, 2015 and 2014, amortization expense on our intangible assets totaled $22.0 million, $22.8 million and $20.8 million, respectively, which is included depreciation, amortization and accretion in the consolidated statements of operations. Amortization expense of $0.1 million, $1.2 million and $2.0 million for the years ended December 31 2016, 2015 and 2014, respectively, relating to the Mid-Continent Business and Bakken Business is included in the net loss from discontinued operations, net of tax, in the consolidated statement of operations.

Estimated amortization expense for each of the next five years ranges from $14.3 million to $19.9 million, with an aggregate $138.1 million to be recognized in subsequent years.

The storage tank capacity in our crude oil storage facility in Cushing, Oklahoma is dedicated to one customer pursuant to a long-term contract with an initial expiration date of August 3, 2017 and an optional two year renewal term. We did not receive a notice of the customer's intent to renew this contract by the required date of February 3, 2017. While we continue to be in discussions with the customer and other parties about renting the storage capacity, we began to accelerate the remaining amortization of the related customer relationship intangible of $10.0 million over the remaining term of the original agreement.

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10. Investment in Unconsolidated Affiliates

The following table presents activity in the Partnership's investments in unconsolidated affiliates:

		Delta House (1)						Emerald Transactions
		FPS			OGL			Destin			Tri-States			Okeanos			Wilprise			MPOG			Total
								(in thousands)
Ownership % at December 31, 2016		20.1		%	20.1		%	49.7		%	16.7		%	66.7		%	25.3		%	66.7		%
Balance at December 31, 2013		$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—
	Investments	—			—			—			—			—			—			12,000			12,000
	Earnings in unconsolidated affiliates	—			—			—			—			—			—			348			348
	Contributions	—			—			—			—			—			—			—			—
	Distributions	—			—			—			—			—			—			(1,980		)	(1,980		)
Balance at December 31, 2014		—			—			—			—			—			—			10,368			10,368
	Investments	40,559			25,144			—			—			—			—			—			65,703
	Earnings in unconsolidated affiliates	5,457			2,013			—			—			—			—			731			8,201
	Contributions	—			—			—			—			—			—			—			—
	Distributions	(12,551		)	(4,097		)	—			—			—			—			(3,920		)	(20,568		)
Balance at December 31, 2015		33,465			23,060			—			—			—			—			7,179			63,704
	Investments	55,461			3,255			122,830			56,681			27,451			5,064			—			270,742
	Earnings in unconsolidated affiliates	21,022			9,260			3,946			1,633			3,642			437			218			40,158
	Contributions	—			—			—			—			—			—			429			429
	Distributions	(45,465		)	(10,125		)	(15,894		)	(3,292		)	(4,034		)	(557		)	(3,679		)	(83,046		)
Balance at December 31, 2016		$	64,483		$	25,450		$	110,882		$	55,022		$	27,059		$	4,944		$	4,147		$	291,987

(1) Represents direct and indirect ownership interests in Class A Units.

The following tables include summarized data for the entities underlying our equity method investments:

	December 31,
	2016		2015
	(in thousands)
Current assets	$	120,167	$	182,264
Non-current assets	1,369,492		1,418,299
Current liabilities	133,085		146,490
Non-current liabilities	541,312		419,215

	Years ended December 31,
	2016		2015		2014
	(in thousands)
Revenue	$	370,263	$	235,041	$	102,290
Operating expenses	99,084		90,453		72,775
Net income	261,200		135,083		28,173

Our investments in the unconsolidated affiliates underlying the Emerald Transactions were acquired in late April 2016. The following table presents information for each of these affiliates for the portion of 2016 that we held the related investments:

F-27

	Emerald Transactions
	Destin			Tri-States			Okeanos			Wilprise
Revenues	$	34,360		$	25,557		$	10,453		$	3,306
Net income	8,272			15,983			1,911			2,028
Partnership ownership %	49.7		%	16.7		%	66.7		%	25.3		%
Partnership share of investee net income	4,109			2,664			1,274			513
Basis difference amortization	(163		)	(1,031		)	2,368			(76		)
Earnings in unconsolidated affiliates	3,946			1,633			3,642			437

The unconsolidated affiliates were determined to be variable interest entities due to disproportionate economic interests and decision making rights. In each case, the Partnership lacks the power to direct the activities that most significantly impact the unconsolidated affiliate's economic performance. As the Partnership does not hold a controlling financial interest in these affiliates, the Partnership accounts for its related investments using the equity method. Additionally, the Partnership’s maximum exposure to loss related to each entity is limited to its equity investment as presented on the consolidated balance sheets, as it is not obligated to absorb losses greater than its proportional ownership percentages indicated above. The Partnership’s right to receive residual returns is not limited to any amount less than the ownership percentages indicated above.

11. Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consists of the following (in thousands):

	December 31,
	2016		2015
Capital expenditures	$	14,499	$	7,780
Employee compensation	10,804		7,870
Convertible preferred unit distributions	7,103		—
Current portion of asset retirement obligation	6,499		6,822
Accrued interest	5,743		1,838
Additional Blackwater acquisition consideration	5,000		—
Due to related parties	4,072		3,894
Royalties payable	3,926		4,163
Transaction costs	3,000		—
Customer deposits	3,080		3,742
Deferred financing costs	2,743		—
Taxes payable	1,688		1,563
Recoverable gas costs	1,126		1,337
Gas imbalances payable	1,098		413
Other	10,903		7,329
Total accrued expenses and other current liabilities	$	81,284	$	46,751

12. Asset Retirement Obligations

The following table presents activity in the Partnership's asset retirement obligations (in thousands):

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	Years Ended December 31,
	2016			2015
Beginning balance	$	35,371		$	34,645
Liabilities assumed (1)	14,542			—
Revision in estimate	230			—
Expenditures	(858		)	(91		)
Accretion expense	1,577			817
Ending balance	50,862			35,371
Less: current portion	6,499			6,822
Noncurrent asset retirement obligation	$	44,363		$	28,549

(1) Includes $14.3 million assumed in connection with the Gulf of Mexico Pipeline acquisition described in Note 2.

We are required to establish security against potential obligations relating to the abandonment of certain transmission assets that may be imposed on the previous owner by applicable regulatory authorities. We have deposited $5.0 million with a third party to secure our performance on these potential obligations. These deposits are included in Restricted cash in our consolidated balance sheets as of December 31, 2016 and 2015.

13. Debt Obligations

Our outstanding debt consists of the following as of December 31, 2016:

	AMID		JPE		8.5% Senior			3.77% Senior
	Revolving Credit		Revolving Credit		Notes due			Notes due			Other
	Agreement (1)		Agreement (1)		2021			2031			Debt			Total
	(in thousands)
Balance	$	711,250	$	177,000	$	300,000		$	60,000		$	3,809		$	1,252,059
Less unamortized deferred financing costs and discount	—		—		(8,691		)	(2,345		)	—			(11,036		)
Subtotal	711,250		177,000		291,309			57,655			3,809			1,241,023
Less current portion	—		—		—			(1,676		)	(3,809		)	(5,485		)
Non-current portion	$	711,250	$	177,000	$	291,309		$	55,979		$	—		$	1,235,538

Our outstanding debt consists of the following as of December 31, 2015:

	AMID		JPE
	Revolving Credit		Revolving Credit		Other
	Agreement (1)		Agreement (1)		Debt			Total
	(in thousands)
Balance	$	525,100	$	162,000	$	3,639		$	690,739
Less current portion	—		—		(2,899		)	(2,899		)
Non-current portion	$	525,100	$	162,000	$	740		$	687,840

______________________

(1) Unamortized deferred financing costs related to the Credit Agreement are included in Other assets, net.

AMID Credit Agreement

Effective as of April 25, 2016, the Partnership entered into the Second Amendment to the Amended and Restated Credit Agreement (as amended, the "Credit Agreement"), which provides for maximum borrowings up to $750.0 million, with the ability to further increase the borrowing capacity to $900.0 million subject to lender approval. We can elect to have loans under our Credit Agreement bear interest either at a Eurodollar-based rate, plus a margin ranging from 2.00% to 3.25% depending on our total leverage ratio

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then in effect, or a base rate which is a fluctuating rate per annum equal to the highest of (i) the Federal Funds Rate plus 0.50%, (ii) 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 (iii) the Eurodollar Rate plus 1.00% plus a margin ranging from 1.00% to 2.25% depending on the total leverage ratio then in effect. We also pay a commitment fee of 0.50% per annum on the undrawn portion of the revolving loan under the Credit Agreement.

Our obligations under the Credit Agreement are secured by a lien on substantially all of our assets. Advances made under the Credit Agreement are guaranteed on a senior unsecured basis by certain of our subsidiaries (the “Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors. The terms of the Credit Agreement include covenants that restrict our ability to make cash distributions and acquisitions in some circumstances. The remaining principal balance and any accrued and unpaid interest will be due and payable in full at maturity, on September 5, 2019.

On September 30, 2016, in connection with the 3.77% Senior Note Purchase Agreement described, the Partnership entered into the Limited Waiver and Third Amendment to the Credit Agreement, which among other things, (i) allows Midla Holdings (as defined below), for so long as the 3.77% Senior Notes are outstanding, to be excluded from guaranteeing the obligations under the Credit Agreement and being subject to certain convents thereunder, (ii) releases the lien granted under the original credit agreement on D-Day’s equity interests in Delta House FPS, LLC, and (iii) deems the equity interests in Delta House FPS, LLC to be excluded property under the Credit Agreement. All other terms under the Credit Agreement remain the same.

On November 18, 2016, the Partnership entered into the Fourth Amendment to the Amended and Restated Credit Agreement. The Fourth Amendment (i) modifies certain investment covenants to reflect the recently completed incremental acquisition of additional interests in Delta House Class A Units (ii) permits JPE’s existing credit facility (the “JPE Credit Facility”) to remain in place during the time period between (a) the consummation of the JPE Merger and (b) the payoff of the JPE Credit Facility, (iii) permits the joining of JPE and its subsidiaries as guarantors under the Credit Agreement, and (iv) permits the integration of JPE and its subsidiaries into the Partnership’s ownership structure.

The Credit Agreement contains certain financial covenants, including a consolidated total leverage ratio which requires our indebtedness not to exceed 4.75 times adjusted consolidated EBITDA for the prior twelve month period adjusted in accordance with the Credit Agreement (except for the current and subsequent two quarters after the consummation of a permitted acquisition, at which time the covenant is increased to 5.25 times adjusted consolidated EBITDA) and a minimum interest coverage ratio that requires our adjusted consolidated EBITDA to exceed consolidated interest charges by not less than 2.50 times. The financial covenants in our Credit Agreement may limit the amount available to us for borrowing to less than $750.0 million. In addition to the financial covenants described above, the Credit Agreement 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).

For the years ended December 31, 2016, 2015 and 2014, the weighted average interest rate on borrowings under our Credit Agreement was approximately 4.29%, 3.67%, and 3.80%, respectively.

As of December 31, 2016, our consolidated total leverage ratio was 4.07 and our interest coverage ratio was 7.43, which were both in compliance with the related requirements of our Credit Agreement. At December 31, 2016 and 2015, letters of credit outstanding under the Credit Agreement were $7.4 million and $1.8 million, respectively. As of December 31, 2016, we had approximately $711.3 million of borrowings and $7.4 million of letters of credit outstanding under the Credit Agreement resulting in $31.3 million of available borrowing capacity.

As of December 31, 2016, we were in compliance with the covenants included in the Credit Agreement. Our ability to maintain compliance with the leverage and interest coverage ratios included in the Credit Agreement may be subject to, among other things, the timing and success of initiatives we are pursuing, which may include expansion capital projects, acquisitions, or drop down transactions, as well as the associated financing for such initiatives.  

The carrying value of amounts outstanding under the Credit Agreement approximates the related fair value, as interest charges vary with market rates conditions. On March 8, 2017, the Partnership entered into the Second Amended and Restated Credit Agreement, which increased our borrowing capacity from $750.0 million to $900.0 million and provided for an accordion feature that will permit, subject to the customary conditions, the borrowing capacity under the facility to be increased to a maximum of $1.1 billion.

JPE Credit Agreement

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On February 12, 2014, we entered into the JPE Credit Agreement with Bank of America, N.A, which was available for refinancing and repayment of certain existing indebtedness, working capital, capital expenditures, permitted acquisitions and other general partnership purposes. The JPE Credit Agreement consisted of a $275.0 million revolving loan, which included a sub-limit of up to $100.0 million for letters of credit. The JPE Credit Agreement was scheduled to mature on February 12, 2019, but was paid off and terminated on March 8, 2017 in connection with the Partnership's acquisition of JPE.

Borrowings under the JPE Credit Agreement bore interest at a rate per annum equal to, at out option, either (a) a base rate determined by reference to the highest of (1) the federal funds effective rate plus 0.5%, (2) the prime rate of Bank of America, and (3) LIBOR, subject to certain adjustments, plus 1.00% or (b) LIBOR, in each case plus an applicable rate. The applicable rate was (a) 1.25% for prime rate borrowing and 2.25% for LIBOR borrowings. The commitment fee was subject to an adjustment each quarter based in the Consolidated Net Total Leverage Ratio, as defined in the related agreement. The carrying value of amounts outstanding under the JPE Credit Agreement approximates the related fair value, as interest charges vary with market rates conditions.

8.50% Senior Notes

On December 28, 2016, the Partnership and American Midstream Finance Corporation, our wholly-owned subsidiary (the “Co-Issuer” and together with the Partnership, the “Issuers”), completed the issuance and sale of the 8.50% Senior Notes. The 8.50% Senior Notes are jointly and severally guaranteed by the Partnership’s existing direct and indirect wholly owned subsidiaries (other than the Co-Issuer) and certain of the Partnership’s future subsidiaries (the “Guarantors”). The 8.50% Senior Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right of payment to any future subordinated indebtedness of the Issuers. The 8.50% Senior Notes were issued at par and provided approximately $294.0 million in proceeds, after deducting the initial purchasers' discount of $6.0 million. This amount was deposited into escrow pending completion of the JPE Merger and is included in Restricted cash on our consolidated balance sheets as of December 31, 2016. The Partnership also incurred $2.7 million of direct issuance costs resulting in net proceeds related to the 8.50% Senior Notes of $291.3 million.

Upon the closing of the JPE Merger and the satisfaction of other conditions related thereto, the restricted cash was released from escrow and was used to repay the JPE Credit Facility and to reduce borrowings under the Partnership’s Credit Agreement.

The 8.50% Senior Notes will mature on December 15, 2021 with interest payable in arrears on June 15 and December 15, commencing June 15, 2017.

At any time prior to December 15, 2018, the Issuers may redeem up to 35% of the aggregate principal amount of 8.50% Senior Notes, at a redemption price of 108.50% of the principal amount, plus accrued and unpaid interest to the redemption date, in an amount not greater than the net cash proceeds of one or more equity offerings by the Partnership, provided that:

• at least 65% of the aggregate principal amount of the 8.50% Senior Notes remains outstanding immediately after such redemption (excluding 8.50% Senior Notes held by the Partnership and its subsidiaries); and

• the redemption occurs within 180 days of the closing of each such equity offering.

Prior to December 15, 2018, the Issuers may redeem all or part of the 8.50% Senior Notes, at a redemption price equal to the sum of:

• the principal amount thereof, plus

• the make whole premium (as defined in the Indenture) at the redemption date, plus

• accrued and unpaid interest, to the redemption date.

On and after December 15, 2018, the Issuers may redeem all or a part of the 8.50% Senior Notes, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if redeemed during the twelve-month period beginning on December 15 of the years indicated below:

Year	Percentage
2018	104.250%
2019	102.125%
2020 and thereafter	100.000%

F-31

The Indenture restricts the Partnership’s ability and the ability of certain of its subsidiaries to, among other things: (i) incur, assume or guarantee additional indebtedness, issue any disqualified stock or issue preferred units, (ii) create liens to secure indebtedness, (iii) pay distributions on equity securities, redeem or repurchase equity securities or redeem or repurchase subordinated securities, (iv) make investments, (v) restrict distributions, loans or other asset transfers from restricted subsidiaries, (vi) consolidate with or merge with or into, or sell substantially all of its properties to, another person, (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries, (viii) enter into transactions with affiliates, (ix) engage in certain business activities and (x) enter into sale and leaseback transactions. These covenants are subject to a number of important exceptions and qualifications. If at any time the 8.50% Senior Notes are rated investment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no Default or Event of Default (as each are defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and the Partnership and its subsidiaries will cease to be subject to such covenants.

The carrying value of the 8.50% Senior Notes as of December 31, 2016 approximates the related fair value as of that date as the Senior Notes were issued on December 28, 2016.

3.77% Senior Notes

On September 30, 2016, Midla Financing, LLC ("Midla Financing"), American Midstream (Midla), LLC (“Midla”), and Mid Louisiana Gas Transmission LLC ("MLGT" and together with Midla, the "Note Guarantors") entered into a Note Purchase and Guaranty Agreement with certain institutional investors (the “Purchasers”) whereby Midla Financing issued $60.0 million in aggregate principal amount of 3.77% Senior Notes due June 30, 2031. Principal and interest on the 3.77% Senior Notes is payable in installments on the last business day of each quarter beginning June 30, 2017 with the remaining balance payable in full on June 30, 2031. The average quarterly principal payment is approximately $1.1 million. The 3.77% Senior Notes were issued at par and provided net proceeds of approximately $57.7 million after deducting related issuance costs of $2.3 million.

Net proceeds from the 3.77% Senior Notes are restricted and will be used to fund project costs incurred in connection with the construction of the Midla-Natchez Line, the retirement of Midla’s existing 1920’s pipeline, the move of our Baton Rouge operations to the MLGT system, and the reconfiguration of the DeSiard compression system and all related ancillary facilities. These proceeds can also be used to pay costs incurred in connection with the issuance of the 3.77% Senior Notes, and for general corporate purposes of Midla Financing. As of December 31, 2016, Restricted cash includes $24.5 million from the issuance of the 3.77% Senior Notes.

The Note Purchase Agreement includes customary representations and warranties, affirmative and negative covenants (including financial covenants), and events of default that are customary for a transaction of this type. Midla Financing must maintain a debt service reserve account containing six months of principal and interest payments, and Midla Financing and the Note Guarantors (including any entities that become guarantors under the terms of the 3.77% Senior Note Purchase Agreement) are restricted from making distributions until June 30, 2017, unless the debt service coverage ratio is not less than, and is not projected to be for the following 12 calendar months less than, 1.20:1.00, and unless certain other requirements are met.

In connection with the 3.77% Senior Note Purchase Agreement, the Note Guarantors guaranteed the payment in full of all Midla Financing’s related obligations. Also, Midla Financing and the Note Guarantors granted a security interest in substantially all of their tangible and intangible personal assets, including the membership interests in each Note Guarantor held by Midla Financing, and Midla Holdings pledged the membership interests in Midla Financing to the Collateral Agent.

As of December 31, 2016, the fair value of the 3.77% Senior Notes was $54.6 million. This estimate was based on similar private placement transactions along with changes in market interest rates which represent a Level 2 measurement.

14. Convertible Preferred Units

Our convertible preferred units consist of the following:

F-32

	Series A			��	Series C			Series D
	Units	$			Units	$		Units	$
	(in thousands)
December 31, 2013	5,279	$	94,811		—	$	—	—	$	—
Issuance of units	—	—			—	—		—	—
Paid in kind unit distributions	466	13,154			—	—		—	—
December 31, 2014	5,745	107,965			—	—		—	—
Issuance of units	2,571	44,769			—	—		—	—
Paid in kind unit distributions	894	16,978			—	—		—	—
December 31, 2015	9,210	169,712			—	—		—	—
Issuance of units	—	—			8,571	115,457		2,333	34,475
Paid in kind unit distributions	897	11,674			221	2,772		—	—
December 31, 2016	10,107	$	181,386		8,792	$	118,229	2,333	$	34,475

Affiliates of our General Partner hold and participate in quarterly distributions on our convertible preferred units, with such distributions being made in cash, paid-in-kind units or a combination thereof, at the election of the Board of Directors of our General Partner, although quarterly distribution on our Series D Units will only be paid in cash. The convertible preferred unitholders have the right to receive cumulative distributions in the same priority and prior to any other distributions made in respect of any other partnership interests.

To the extent that any portion of a quarterly distribution on our convertible preferred units to be paid in cash exceeds the amount of cash available for such distribution, the amount of cash available will be paid to our convertible preferred unitholders on a pro rata basis while the difference between the distribution and the available cash will become arrearages and accrue interest until paid.

Series A-1 Convertible Preferred Units

On April 15, 2013, the Partnership, our General Partner and AIM Midstream Holdings entered into agreements with HPIP, pursuant to which HPIP acquired 90% of our General Partner and all of our subordinated units from AIM Midstream Holdings and contributed the High Point System and $15.0 million in cash to us in exchange for 5,142,857 of our Series A-1 Units.

The Series A-1 Units receive distributions prior to distributions to our common unitholders. The distributions on the Series A-1 Units are equal to the greater of $0.50 per unit or the declared distribution to common unitholders. The Series A-1 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. As of December 31, 2016, the conversion price is $15.87.

Upon any liquidation and winding up of the Partnership or the sale of substantially all of its assets, the holders of Series A-1 Units will generally be entitled to receive, in preference to the holders of any of the Partnership's other equity securities, but in parity with all convertible preferred units, an amount equal to the sum of $15.87 multiplied by the number of Series A-1 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-1 Units for a per unit price payable in cash as described in the Partnership Agreement.

Upon receipt of such a redemption offer from us, each holder of Series A-1 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 Partnership Agreement with respect to the Series A-1 Units without material abridgement.

Except as provided in the Partnership Agreement, the Series A-1 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-1 Unit entitled to one vote for each common unit into which such Series A-1 Unit is convertible.

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As conversion is at the option of the holder and redemption is contingent upon a future event which is outside the control of the Partnership, the Series A-1 Units have been classified as mezzanine equity in the consolidated balance sheets.

Under the Partnership Agreement, distributions on Series A-1 Units were made with paid-in-kind Series A-1 Units, cash or a combination thereof, at the discretion of the Board of Directors, through the distribution for the quarter ended March 31, 2016. The Partnership was previously required to pay distributions on the Series A-1 Units with a combination of paid-in-kind units and cash. The sale of the Series A-1 Units was exempt from registration under Securities Act pursuant to Rule 4(a)(2) under the Securities Act.

Series A-2 Convertible Preferred Units

On March 30, 2015 and June 30, 2015, we entered into two Series A-2 Convertible Preferred Unit Purchase Agreements with Magnolia Infrastructure Partners ("Magnolia") an affiliate of HPIP pursuant to which the Partnership issued, in separate private placements, newly-designated Series A-2 Units (the “Series A-2 Units”) representing limited partnership interests in the Partnership. As a result, the Partnership issued a total of 2,571,430 Series A-2 Units for approximately $45.0 million in aggregate proceeds during the year ended December 31, 2015. The Series A-2 Units will participate in distributions of the Partnership along with common units in a manner identical to the existing Series A-1 Units (together with the Series A-2 Units, the "Series A Units"), with such distributions being made in cash or with paid-in-kind Series A Units at the election of the Board of Directors of our General Partner.

On July 27, 2015, we amended our Partnership Agreement to grant us the right (the “Call Right”) to require the holders of the Series A-2 Units to sell, assign and transfer all or a portion of the then outstanding Series A-2 Units to us for a purchase price of $17.50 per Series A-2 Unit (subject to appropriate adjustment for any equity distribution, subdivision or combination of equity interests in the Partnership). We may exercise the Call Right at any time, in connection with our or our affiliate’s acquisition of assets or equity from ArcLight Energy Partners Fund V, L.P., or one of its affiliates, for a purchase price in excess of $100 million. We may not exercise the Call Right with respect to any Series A-2 Units that a holder has elected to convert into common units on or prior to the date we have provided notice of our intent to exercise the Call Right, and we may also not exercise the Call Right if doing so would result in a default under any of our or our affiliates’ financing agreements or obligations. As of December 31, 2016, the conversion price is $15.87. The sale of the Series A-2 Units was exempt from registration under Securities Act pursuant to Rule 4(a)(2) under the Securities Act.

Series C Convertible Preferred Units

On April 25, 2016, the Partnership issued 8,571,429 of its Series C Units to an ArcLight affiliate in connection with the Emerald Transactions described in Note 2.

The Series C 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 on an as converted basis, with each Series C Unit initially entitled to one vote for each common unit into which such Series C Unit is convertible. The Series C Units also have separate class voting rights on any matter, including a merger, consolidation or business combination, that adversely affects, amends or modifies any of the rights, preferences, privileges or terms of the Series C Units. The Series C Units are convertible in whole or in part into common units at any time. The number of common units into which a Series C Unit is convertible will be an amount equal to the sum of $14.00 plus all accrued and accumulated but unpaid distributions, divided by the conversion price. The sale of the Series C Units was exempt from registration under Securities Act pursuant to Rule 4(a)(2) under the Securities Act.

In the event that the Partnership issues, sells or grants any common units or convertible securities at an indicative per common unit price that is less than $14.00 per common unit (subject to customary anti-dilution adjustments), then the conversion price will be adjusted according to a formula to provide for an increase in the number of common units into which Series C Units are convertible. As of December 31, 2016, the conversion price is $13.95.

Prior to consummating 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, we are obligated to make an irrevocable written offer, subject to consummating the Partnership Event, to the holders of Series C Units to redeem all (but not less than all) of the Series C Units for a price per Series C Unit payable in cash as described in the Partnership Agreement.

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

F-34

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 C Units generally will be entitled to receive, in preference to the holders of any of the Partnership's other equity securities but in parity with all convertible preferred units, an amount equal to the sum of the $14.00 multiplied by the number of Series C Units owned by such holders, plus all accrued but unpaid distributions.

At any time prior to April 25, 2017, the Partnership has the right (the “Series C Call Right”) to require the holders of the Series C Units to sell, assign and transfer all or a portion of the then outstanding Series C Units for a purchase price of $14.00 per Series C Unit (subject to customary anti-dilution adjustments), plus all accrued but unpaid distributions on each Series C Unit.

The Partnership may not exercise the Series C Call Right if the holder has elected to convert it into common units on or prior to the date the Partnership has provided notice of its intent to exercise its Series C Call Right, and may not exercise the Series C Call Right if doing so would violate applicable law or result in a default under any financing agreement or obligation of the Partnership or its affiliates.

In connection with the issuance of the Series C Units, the Partnership issued the holders a warrant to purchase up to 800,000 common units at an exercise price of $7.25 per common unit (the "Series C Warrant"). The Series C Warrant is subject to standard anti-dilution adjustments and is exercisable for a period of seven years.

On April 25, 2017, the number of common units that may be purchased pursuant to the exercise of the Series C Warrant will be adjusted by an amount, rounded to the nearest whole common unit, equal to the product obtained by the following calculation: (i) 400,000 multiplied by (ii) (A) the Series C Issue Price multiplied by the number of Series C Units then outstanding less $45.0 million divided by (B) the Series C Issue Price multiplied by the number of Series C Units issued, less $45.0 million.

Any Series C Units issued in-kind as a distribution to holders of Series C Units (“Series C PIK Units”) will increase the number of common units that can be purchased upon exercise of the Series C Warrant by an amount, rounded to the nearest whole common unit, equal to the product obtained by the following calculation: (i) the total number of common units into which each Series C Warrant may be exercised immediately prior to the most recent issuance of the Series C PIK Units multiplied by (ii) (A) the total number of outstanding Series C Units immediately after the most recent issuance of Series C PIK Units divided by (B) the total number of outstanding Series C Units immediately prior to the most recent issuance of Series C PIK Units.

The fair value of the Series C Warrant was determined using a market approach that utilized significant inputs which are not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. The estimated fair value of $4.41 per warrant unit was determined using a Black-Scholes model and the following significant assumptions: i) a dividend yield of 18%, ii) common unit volatility of 42% and iii) the seven-year term of the warrant to arrive at an aggregate fair value of $4.5 million.

Series D Convertible Preferred Units

On October 31, 2016, Partnership issued 2,333,333 shares of its newly-designated Series D Units to an ArcLight affiliate at a price of $15.00 per unit, less a 1.5% closing fee, in connection with the Delta House transaction described in Note 2. The related agreement provides that if any of the Series D Units remain outstanding on June 30, 2017, the Partnership will issue the holder of the Series D Units a warrant (the “Series D Warrant”) to purchase 700,000 common units representing limited partnership interests with an exercise price of $22.00 per common unit. The fair value of the conditional Series D Warrant at the time of issuance was immaterial.

The Series D Units are entitled to quarterly distributions payable in arrears equal to the greater of $0.4125 and the cash distribution that the Series D Units would have received if they had been converted to common units immediately prior to the beginning of the quarter. The Series D Units also have separate class voting rights on any matter, including a merger, consolidation or business combination, that adversely affects, amends or modifies any of the rights, preferences, privileges or terms of the Series D Units. The Series D Units are convertible in whole or in part into common units at the election of the holder of the Series D Unit at any time after June 30, 2017. As of the date of issuance, the conversion rate for each Series D Unit was one -to-one (the “Conversion Rate”). As of December 31, 2016, the conversion price is $14.98.

In the event that the Partnership issues, sells or grants any common units or securities convertible into common units at an indicative per common unit price that is less than $15.00 per unit (subject to customary anti-dilution adjustments), then the Conversion Rate will be adjusted according to a formula to provide for an increase in the number of common units into which Series D Units are convertible.

F-35

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”), the Partnership is obligated to make an irrevocable written offer, subject to consummation of the Partnership Event, to the holders of Series D Units to redeem all (but not less than all) of the Series D Units for a price per Series D Unit payable in cash as described in the Partnership Agreement. The sale of the Series D Units was exempt from registration under Securities Act pursuant to Rule 4(a)(2) under the Securities Act.

Upon receipt of a redemption offer, each holder of Series D Units may elect to receive the cash amount or a preferred security issued by the person surviving or resulting from the Partnership Event.

Upon any liquidation and winding up of the Partnership or the sale of substantially all of the assets of the Partnership, the holders of Series D Units generally will be entitled to receive, in preference to the holders of any of the Partnership's other equity securities but in parity with all convertible preferred units, an amount equal to the sum of the $15.00 multiplied by the number of Series D Units owned by such holders, plus all accrued but unpaid distributions.

At any time prior to June 30, 2017, the Partnership has the right (the “Series D Call Right”) to redeem the Series D Units for the product of (i) the sum of $15.00 and all accrued and accumulated but unpaid distributions for each Series D Unit (including a proportionate amount of the distribution on each Series D Unit that has accrued for the quarter in which the redemption occurs); and (ii) 1.03.

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15. Partners' Capital

American Midstream Outstanding Units

The following table presents unit activity (in thousands):

	General Partner Interest	Limited Partner Interest		Series B Convertible Units		JPE Series D Units
Balances at December 31, 2013	185	13,394		—		—
Initial issuance of Series B Units	—	—		1,168
Issuance of Series B Units	—	—		87
Issuance of JPE Series D Units	—	—		—		1,008
Redemption of JPE Series D Units	—	—		—		(1,008	)
LTIP vesting	—	80		—
Issuance of GP units	207	—		—
Exercise of warrants	—	300		—
Issuance of common units in JP Development transaction	—	5,841		—
Issuance of common units	—	23,025		—
Balances at December 31, 2014	392	42,640		1,255		—
Issuance of Series B Units	—	—		95		—
LTIP vesting	—	58		—		—
Exercise of unit options	—	152		—		—
Issuance of GP units	144	—		—		—
Issuance of common units	—	7,654		—		—
Balances at December 31, 2015	536	50,504		1,350		—
Conversion of Series B Units	—	1,350		(1,350	)	—
Return of escrow units	—	(1,034	)	—		—
LTIP vesting	—	283		—		—
Issuance of GP units	144	—		—		—
Issuance of common units	—	248		—		—
Balances at December 31, 2016	680	51,351		—		—

Our capital accounts are comprised of approximately 1.3% notional General Partner interest and 98.7% limited partner interests as of December 31, 2016. 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 incentive distribution rights that are non-voting limited partner interests held by our General Partner. Pursuant to our Partnership Agreement, our General Partner participates in losses and distributions based on its interest. The General Partner's participation in the allocation of losses and distributions is not limited and therefore, such participation can result in a deficit to its respective capital account. As such, allocation of losses and distributions for previous transactions between entities under common control have resulted in a deficit to the General Partner's capital account included in our consolidated balance sheets.

Series B Convertible Preferred Units

Effective January 31, 2014, the Partnership issued 1,168,225 Series B Units to its General Partner in exchange for approximately $30.0 million to fund a portion of the Lavaca acquisition described in Note 2. The Series B Units participated in distributions of the Board of Directors of our General Partner along with common units, with such distributions being made in cash distributions or with paid-in-kind Series B Units at the election of the Partnership. The Series B Units were issued in a private placement in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(a)(2) thereof and the safe harbor provided by Rule 506 of Regulation D promulgated thereunder. On February 1, 2016, all outstanding Series B Units were converted on a one-for-one basis into common units.

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The Board of Directors of our General Partner elected to pay the Series B distributions using paid-in-kind Series B Units. For the years ended December 31, 2015 and 2014, the Partnership issued 94,923 and 86,461, respectively, of paid-in-kind Series B Units with a fair value of $1.4 million and $2.2 million, respectively.

Equity Offerings

In October 2015, the Partnership and certain of its affiliates entered into an agreement with a group of investment banks under which it may issue up to $100.0 million of its common units in at the market (“ATM”) offerings. During 2016, the Partnership issued 248,561 common units under this program resulting in net proceeds of $2.9 million after deducting related offering costs of $0.3 million. The net proceeds were used to repay amounts outstanding under the Credit Agreement. At December 31, 2016, $96.8 million remained available under the ATM program.

In September 2015, the Partnership sold 7,500,000 of its common units in a public offering at a price to the public of $11.31 per common unit. The net proceeds of approximately $81.0 million were used to fund a portion of the Delta House investment described in Note 2. In October 2016, the Partnership issued an additional 151,937 common units at a price of $11.31 per unit pursuant to the partial exercise of the underwriters' overallotment option, resulting in net proceeds of approximately $1.7 million.

In October 2014, the Partnership acquired Costar from Energy Spectrum Partners VI LP and Costar Midstream Energy, LLC which was funded, in part, with 6,892,931 of common units with an estimated fair value of $147.3 million issued directly to Energy Spectrum and Costar Midstream Energy LLC. In February 2016, the Partnership reached a settlement of certain indemnification claims with the Costar sellers whereby approximately 1,034,483 common units held in escrow were returned to the Partnership.

On October 7, 2014, JPE issued 7,940,625 common units at a price of $34.63 per unit in its initial public offering ("IPO") resulting in net proceeds of $252.7 million. Immediately prior to the IPO, JPE was recapitalized and common units were issued for each previously outstanding class of equity, resulting in 11,848,735 outstanding common units immediately prior to the IPO.

On August 15, 2014, the Partnership sold 4,622,352 of its common units representing limited partner interests to institutional investors at a price of $25.8075 per common unit resulting in net proceeds of $119.3 million.

On February 12, 2014, we issued 190,000 Class A Common Units to an affiliate for net proceeds of $8.0 million.

On March 28, 2014, we issued 1,008,000 Series D Preferred Units to an affiliate resulting in net proceeds of $40.0 million. On October 7, 2014, we redeemed all of the outstanding Series D Preferred Units for $42.4 million.

In January 2014, the Partnership sold 3,400,000 of its common units in a public offering at a price of $26.75 per common unit. The Partnership used the net proceeds of $86.9 million to fund a portion of the Lavaca acquisition described in Note 2.

General Partner Units

In order to maintain its ownership percentage, we received proceeds of $2.0 million from our General Partner as consideration for the issuance of 143,900 additional notional general partner units for the year ended December 31, 2016, proceeds of $1.9 million for the issuance of 143,517 additional notional general partner units for the year ended December 31, 2015 and proceeds of $5.7 million for the issuance of 206,810 additional notional general partner units for the year ended December 31, 2014.

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Distributions

We made the following distributions (in thousands):

	Years Ended December 31,
	2016		2015		2014
Series A Units
Cash:
Paid	$	4,935	$	—	$	2,658
Accrued	2,514		—		—
Paid-in-kind units	11,674		16,978		13,154
Total	19,123		16,978		15,812
Series B Units
Paid-in-kind units	—		1,373		2,220
Total	—		1,373		2,220
Series C Units
Cash:
Paid	3,089		—		—
Accrued	3,626		—		—
Paid-in-kind units	2,772		—		—
Total	9,487		—		—
Series D Units
AMID Series D Units Accrued	963		—		—
JPE Series D Units Paid-in-kind units	—		—		2,436
Total	963		—		2,436
Limited Partner Units
Cash:
Paid	101,561		93,622		114,612
Accrued	—		—		—
Total	101,561		93,622		114,612
General Partner Units
Cash:
Paid	2,551		6,789		2,695
Accrued	—		—		—
Additional Blackwater acquisition consideration	5,000		—		—
Total	7,551		6,789		2,695
Summary
Cash
Paid	112,136		100,411		119,965
Accrued	7,103		—		—
Paid-in-kind units	14,446		18,351		17,810
Additional Blackwater acquisition consideration	5,000		—		—
Total	$	138,685	$	118,762	$	137,775

On January 26, 2017, the Board of Directors of our General Partner declared a quarterly cash distribution of $0.4125 per common unit or $1.65 per common unit on an annualized basis. The distribution was paid on February 13, 2017, to unitholders of record as of the close of business on February 6, 2017. Accrued cash distributions on our preferred convertible units were also paid in February 2017.

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The fair value of the paid-in-kind distributions was determined using the market and income approaches, requiring significant inputs which are not observable in the market and thus represent a Level 3 measurements as defined by ASC 820. Under the income approach, the fair value estimates for all years presented were based on i) present value of estimated future contracted distributions, ii) option values ranging from $0.02 per unit to $9.68 per unit using a Black-Scholes model, iii) assumed discount rates ranging from 5.57% to 10.0% and iv) assumed growth rates of 1.0%.

The Fourth Amended and Restated Agreement of Limited Partnership provides that the General Partner may, in its sole discretion, make cash distributions, but there is no requirement that we make any cash distributions.

16. Net Income (Loss) per Limited 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 our convertible preferred units and General Partner units, including incentive distribution rights. Unvested unit-based compensation 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 limited partners' net income (loss) per common unit. Basic and diluted limited partners' net income (loss) per common 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.

As of December 31, 2016, JPE had approximately 36.7 million common and subordinated units outstanding. Additionally, as of that date, ArcLight owned approximately 18.7 million, or 50.9%, of those units while other unitholders owned approximately 18.0 million or 49.1% of those units. In order to affect the JPE Merger, the Partnership issued .5225 of a Partnership common unit for each JPE unit held by ArcLight Capital or approximately 9.8 million units and .5775 of a Partnership common unit for each JPE unit held by other unitholders or approximately 10.4 million units. The Partnership issued a total of 20.2 million units to affect the JPE Merger.

In order to determine the weighted average number of units outstanding for purposes of calculating limited partner earnings per unit in the consolidated statements of operations, the Partnership’s historical weighted average number of units outstanding for each year was added to an assumed weighted average number of JPE units outstanding after applying the applicable exchange ratios mentioned previously. JPE’s common units were not publicly traded until October 7, 2014, when it completed its IPO. Concurrent with its IPO, JPE completed an equity restructuring whereby it converted its previously outstanding equity interests into approximately 22.7 million common and subordinated units.

For the year ended December 31, 2014, the applicable exchange ratios were applied to the 22.7 million of JPE common and subordinated units resulting from the previously mentioned equity restructuring as if such units were outstanding for the entire year, plus the 13.8 million common units issued in connection with JPE’s IPO on October 7, 2014 as if such units were outstanding for approximately 25% of the year. The aggregate amount was then added to the Partnership’s actual weighted average number of units outstanding for the year to arrive at the weighted average number of units outstanding for the year.

For the years ended December 31, 2015 and 2016, the applicable exchange ratios were applied to JPE’s actual weighted average number of units outstanding for the respective periods and such amounts were added to the Partnership’s actual weighted average number of units outstanding for the respective periods to arrive at the weighted average number of units outstanding for the respective periods.

The calculation of basic and diluted limited partners' net loss per common unit is summarized below (in thousands, except per unit amounts):

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	Years Ended December 31,
	2016			2015			2014
Net loss from continuing operations	$	(48,005	)	$	(184,810	)	$	(69,681	)
Less: Net income (loss) attributable to noncontrolling interests	2,766			(13		)	3,993
Net loss from continuing operations attributable to the Partnership	(50,771		)	(184,797		)	(73,674		)
Less:
Distributions on Series A Units	19,138			16,978			14,492
Distributions on Series C Units	9,487			—			—
Distributions on Series D Units	963			—			—
Distributions on Series B Units	—			1,373			2,220
Net income (loss) from continuing operations attributable to JPE preferred units	—			—			656
Net income (loss) from continuing operations attributable to predecessor capital	—			—			(2,014		)
General partner's distributions	2,550			6,790			2,694
General partner's share in undistributed loss	(1,745		)	(3,309		)	(1,510		)
Net loss from continuing operations attributable to Limited Partners	(81,164		)	(206,629		)	(90,212		)
Net loss from discontinued operations attributable to Limited Partners	(532		)	(15,031		)	(269		)
Net loss attributable to Limited Partners	$	(81,696	)	$	(221,660	)	$	(90,481	)
Weighted average number of common units used in computation of Limited Partners' net loss per common unit - basic and diluted	51,176			45,050			27,524
Limited Partners' net loss from continuing operations per unit (basic and diluted)	$	(1.59	)	$	(4.59	)	$	(3.28	)
Limited Partners' net loss from discontinued operations per unit (basic and diluted)	(0.01		)	(0.33		)	(0.01		)
Limited Partners' net loss per common unit - basic and diluted (1)	$	(1.60	)	$	(4.92	)	$	(3.29	)

_______________________

(1) Potential common unit equivalents are antidilutive for all periods and, as a result, have been excluded from the determination of diluted limited partners' net income (loss) per common unit.

17. Long-Term Incentive Plan

AMID Unit-Based Compensation

Our General Partner manages our operations and activities and employs the personnel who provide support to our operations. On November 19, 2015, the Board of Directors of our General Partner approved the Third Amended and Restated Long-Term Incentive Plan to, among other things, increase the number of common units authorized for issuance by 6,000,000 common units. On February 11, 2016, the unitholders approved the Third Amended and Restated Long-Term Incentive Plan (as amended and as currently in effect as of the date hereof, the "LTIP"). At December 31, 2016, 2015 and 2014, there were 5,017,528, 15,484 and 688,976 common units, respectively, available for future grant under the LTIP.

All equity-based awards issued under the LTIP consist of phantom units, distribution equivalent rights ("DER") or option grants. DERs and options have been granted on a limited basis. Future awards may be granted at the discretion of the Compensation Committee and subject to approval by the Board of Directors of our General Partner.

Phantom Unit Awards. Ownership in the phantom unit awards is subject to forfeiture until the vesting date. The LTIP is administered by the Compensation Committee of the Board of Directors of our General Partner, which at its discretion, may elect to settle such vested phantom units with a number of common units equivalent to the fair market value at the date of vesting in lieu of cash.

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Although our General Partner has the option to settle vested phantom units in cash, our General Partner has not historically settled these awards in cash. Under the LTIP, phantom units typically vest in increments of 25% on each grant anniversary date and do not contain any vesting requirements other than continued employment.

In December 2015, the Board of Directors of our General Partner approved a grant of 200,000 phantom units under the LTIP which contain DERs to the extent the Partnership’s Series A Preferred Unitholders receive distributions in cash. These units will vest on the three year anniversary of the date of grant, subject to acceleration in certain circumstances.

The following table summarizes activity in our phantom unit-based awards for the years ended December 31, 2016, 2015 and 2014:

	Units		Weighted-Average Grant Date Fair Value Per Unit			Aggregate Intrinsic Value (1) (In thousands)
Outstanding units at December 2013	75,529		$	17.62		$	2,045
Granted	188,946		20.80
Forfeited	(12,009	)	(18.28		)
Vested	(51,334	)	(20.89		)
Outstanding units at December 2014	201,132		$	19.85		$	3,964
Granted	546,329		12.25
Forfeited	(31,298	)	(15.62		)
Vested	(146,404	)	(18.47		)
Outstanding units at December 2015	569,759		$	13.15		$	4,609
Granted	1,374,226		2.14
Forfeited	(411,794	)	(2.60		)
Vested	(286,348	)	(12.18		)
Outstanding units at December 2016	1,245,843		$	4.72		$	22,674

(1) The intrinsic value of phantom units was calculated by multiplying the closing market price of our underlying stock on December 31, 2016, 2015 and 2014 by the number of phantom units.

The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our common units at the grant date. Compensation expense related to these awards for the years ended December 31, 2016, 2015, and 2014 was $3.6 million, $3.8 million and $1.5 million, respectively, and is included in Corporate expenses and Direct operating expenses in our consolidated statements of operations and the equity compensation expense in our consolidated statements of changes in partners' capital and noncontrolling interests.

The total fair value of units at the time of vesting was $2.4 million, $2.6 million, and $1.4 million for the years ended December 31, 2016, 2015, and 2014, respectively.

Equity compensation expense related to unvested phantom awards not yet recognized at December 31, 2016 was $4.2 million and the weighted average period over which this expense is expected to be recognized as of December 31, 2016 is approximately 2.2 years.

Performance and Service Condition Awards. In November 2015, the Board of Directors of our General Partner modified awards that introduced certain performance and service conditions that were probable of being achieved, amounting to $2.0 million payable to certain employees. During the third quarter of 2016, we settled $1.0 million of the obligation in cash while in the fourth quarter of 2016, forfeitures reduced the total payable amount from $2.0 million to $1.5 million. These awards are accounted for as liability classified awards. Compensation expense related to these awards for the years ended December 31, 2016 and 2015 was $0.9 million and $0.5 million, respectively, and is included in Direct operating expenses in our consolidated statements of operations. Compensation expense related to unvested awards not yet recognized at December 31, 2016 was $0.1 million.

Option to Purchase Common Units. In December 2015, the Board of Directors of our General Partner approved the grant of an option to purchase 200,000 common units at an exercise price per unit equal to $7.50. The grant will vest on January 1, 2019, subject to acceleration in certain circumstances, and will expire on March 15th of the calendar year following the calendar year in which it vests.

F-42

In August 2016, the Board of Directors of our General Partner approved the grant of an option to purchase 30,000 common units at an exercise price per unit equal to $12.00. The grant will vest on July 31, 2019, subject to continued employment, and will expire on July 31st of the calendar year following the calendar year in which it vests.

In September 2016, the Board of Directors of our General Partner approved the grant of an option to purchase 45,000 common units of the Partnership at an exercise price per unit equal to $13.88. The options will vest at a rate of 25% per year. The options will expire on September 30th of the calendar year following the calendar year in which it vests.

The Black-Scholes pricing model was used to determine the fair value of our options grants using the following assumptions:

	Years Ended December 31,
	2016		2015
Weighted average common unit price volatility	61.1	%	47.0	%
Expected distribution yield	12.6	%	26.3	%
Weighted average expected term (in years)	4.10		3.5
Weighted average risk-free rate	1.1	%	1.3	%

The weighted average unit price volatility was based upon the historical volatility of our common units. The expected distribution yield was based on an annualized distribution divided by the closing unit price on the date of grant. The risk-free rate was based on the U.S. Treasury yield curve in effect on the date of grant.

Compensation expense related to these awards was not material for the years ended December 31, 2016 and 2015. Compensation cost related to unvested awards not yet recognized at December 31, 2016 was $0.2 million.

The following table summarizes our option activity for the years ended December 31, 2016 and 2015:

	Units	Weighted-Average Exercise Price		Weighted-Average Grant Date Fair Value per Unit		Aggregate Intrinsic Value (1) (In thousands)		Weighted Average Remaining Contractual Life (Years)
Outstanding at December 31, 2014	—	$	—	$	—	$	—	—
Granted	200,000	7.50		0.33		—		—
Vested	—	—				—		—
Forfeited	—	—				—		—
Outstanding at December 31, 2015	200,000	$	7.50	$	0.33	$	118	4.2
Granted	75,000	13.13		2.65		—		—
Vested	—	—				—		—
Forfeited	—	—				—		—
Outstanding at December 31, 2016	275,000	$	9.03	$	0.96	$	2,522	5.0

(1) The intrinsic value of the stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option.

JPE Unit-Based Compensation

Long-Term Incentive Plan and Phantom Units. The JPE 2014 Long-Term Incentive Plan (“JPE LTIP”) authorized grants of up to 3,642,700 common units. Phantom units issued under the JPE LTIP were primarily composed of two types of grants: (1) service condition grants with vesting over three years in equal annual installments; and (2) service condition grants with cliff vesting on April 1, 2018. Distributions related to these unvested phantom units are paid concurrent with our distribution for common units. The fair value of phantom units issued under the JPE LTIP was determined by utilizing the market value of our common units on the respective grant date.

The following table presents phantom units activity for the years ended December 31, 2016 and 2015: 

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	Units		Weighted Average Grant date Fair Value
Outstanding units at December 2014	—		$	—
Granted	287,750		22.25
Vested	(4,766	)	22.34
Forfeited	(56,005	)	21.23
Outstanding units at December 2015	226,979		$	22.5
Granted	209,507		9.23
Vested	(55,778	)	19.51
Forfeited	(67,716	)	18.74
Outstanding units at December 2016	312,992		$	14.96

Total unit-based compensation expense related to JPE phantom units was $1.7 million and $0.8 million for the years ended December 31, 2016 and 2015, respectively, which was recorded in corporate expenses in the consolidated statements of operations.

18. Income Taxes

With the exception of certain subsidiaries in our Terminals Segment, the Partnership is not subject to U.S. federal or state income taxes as such income taxes are generally borne by our unitholders through the allocation of our taxable income (loss) to them. The State of Texas does impose a franchise tax that is assessed on the portion of our taxable margin which is apportioned to Texas.

Income tax (expense) benefit for the years ended December 31, 2016, 2015 and 2014 is as follows:

	Years Ended December 31,
	2016			2015			2014
Current income tax expense	$	(521	)	$	(648	)	$	(146	)
Deferred income tax expense	(2,057		)	(1,240		)	(711		)
Effective income tax rate	5.7		%	1.0		%	1.2		%

A reconciliation of our expected income tax (expense) benefit calculated at the U.S. federal statutory rate of 34% to our actual tax (expense) for the years ended December 31, 2016, 2015 and 2014 is as follows:

	Years Ended December 31,
	2016			2015			2014
Net income (loss) before income tax expense	$	(45,427	)	$	(182,922	)	$	(68,824	)
US Federal statutory tax rate	34		%	34		%	34		%
Federal income tax (expense) benefit at statutory rate	15,445			62,193			23,400
Reconciling items:
Partnership loss not subject to income tax (benefit)	(17,218		)	(63,083		)	(23,759		)
State and local tax expense	(800		)	(857		)	(459		)
Other	(5		)	(141		)	(39		)
Income tax expense	$	(2,578	)	$	(1,888	)	$	(857	)

The Partnership’s deferred tax assets and liabilities as of December 31, 2016 and 2015 are summarized below:

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	December 31,
	2016			2015
Deferred tax assets:
Net operating loss carryforwards	$	6,300		$	7,570
Other	577			493
Total deferred tax assets	6,877			8,063
Deferred tax liabilities:
Property, plant and equipment	(15,082		)	(14,236		)
Deferred income tax liability, net	$	(8,205	)	$	(6,173	)

As of December 31, 2016, certain subsidiaries in our Terminals Segment had net operating loss carryforwards for federal income tax purposes of approximately $16.1 million which begin to expire in 2028.

We recognize the tax benefits from uncertain tax positions if it is more likely than not that the position will be sustained on examination by the taxing authorities. As of December 31, 2016, we have not recognized tax benefits relating to uncertain tax positions.

The preparation of our income tax returns requires the use of management's estimates and interpretations which may be subjected to review by the respective taxing authorities and may result in an assessment of additional taxes, penalties and interest. Tax years subsequent to 2010 remain subject to examination by federal and state taxing authorities.

19. Commitments and Contingencies

Legal proceedings

We are not currently party to any pending litigation or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate impact of any proceedings cannot be predicted with certainly, our management believes that the resolution of any of our pending proceeds will not have a material adverse effect on our financial condition or results of operations.

Environmental matters

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent in our 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.

Regulatory matters

On October 8, 2014, American Midstream (Midla), LLC ("Midla") reached an agreement in principle with its customers regarding the interstate pipeline that traverses Louisiana and Mississippi in order to provide continued service to its customers while addressing safety concerns with the existing pipeline.

On April 16, 2015, FERC approved the stipulation and agreement (the “Midla Agreement”) relating to the October 8, 2014 regulatory matter and allowing Midla to retire the existing 1920’s pipeline and replace it with the Midla-Natchez Line to serve existing residential, commercial, and industrial customers. Under the Midla Agreement, customers not served by the new Midla-Natchez Line will be connected to other interstate or intrastate pipelines, other gas distribution systems, or offered conversion to propane service. On June 29, 2015, the Partnership filed with FERC for authorization to construct the Midla-Natchez pipeline, which was approved on December 17, 2015. Construction commenced in the second quarter of 2016 with service expected to begin in the first six months of 2017. Under the Midla Agreement, Midla plans to execute long-term agreements seeking to recover its investment in the Midla-Natchez Line.

Exit and disposal costs

On March 9, 2016, management committed to a corporate headquarters relocation plan and communicated that plan to the impacted employees. The plan included relocation assistance or one-time termination benefits for employees who rendered service until

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their respective termination dates. Charges associated with these termination benefits, which totaled $9.1 million were recognized ratably over the requisite service period and are presented in Corporate expenses in ourconsolidated statements of operations. At December 31, 2016, payments under the plan had been completed.

Commitments and contractual obligations

The Partnership had the following non-cancelable contractual commitments as of December 31, 2016:

	Revolving Credit Agreements		3.77% Senior Notes		8.50% Senior Notes (1)		Asset Retirement Obligation (2)		Other		Total
	(in thousands)
2017	$	—	$	1,677	$	—	$	6,499	$	9,869	$	18,045
2018	—		806		—		—		6,331		7,137
2019	888,250		2,233		—		—		5,079		895,562
2020	—		2,299		—		—		2,905		5,204
2021	—		4,430		300,000		—		2,253		306,683
Thereafter	—		48,555		—		44,363		17,991		110,909
	$	888,250	$	60,000	$	300,000	$	50,862	$	44,428	$	1,343,540

(1) Upon closing of the JPE Merger, the proceeds from the 8.50% Senior Notes were used to repay the JPE Credit Agreement.

(2) In some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for purposes 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.

For the years ended December 31, 2016, 2015 and 2014, total rental expenses were $19.5 million, $17.7 million, and $10.6 million, respectively.

20. Related-Party Transactions

Employees of our General Partner are assigned to work for the Partnership or other ArcLight affiliates. Where directly attributable, all compensation and related expenses for these employees are charged directly by our General Partner to American Midstream, LLC, which, in turn, charges the appropriate subsidiary or affiliate. Our General Partner does not record any profit or margin on the expenses charged to us. During the years ended December 31, 2016, 2015, and 2014, related expenses of $89.8 million, $98.3 million, and $95.5 million respectively, were charged to the Partnership by our General Partner. As of December 31, 2016, and 2015, the Partnership had $3.9 million and $3.8 million, respectively, due to our General Partner, which has been recorded in Accrued expenses and other current liabilitiesand relates primarily to compensation. This payable is generally settled on a quarterly basis related to the foregoing transactions.

During the second quarter of 2014, the Partnership and an ArcLight affiliate entered into an agreement under which the affiliate pays a monthly fee to reimburse the Partnership for administrative expenses incurred on the affiliate’s behalf. For the years ended December 31, 2016, 2015, and 2014, the Partnership recognized related management fee income of $0.8 million, $1.4 million and $0.9 million respectively, under this agreement and recorded such amounts as a reduction of Corporate expensesin the consolidated statements of operations.

We also performed certain management services for another ArcLight affiliate for which we received a monthly fee of $50,000 through January 2016. The monthly fee reduced Corporate expensesin the consolidated statements of operations by $0.1 million, $0.6 million and $0.6 million for the years ended December 31, 2016, 2015 and 2014, respectively.

During the years ended December 31, 2016 and 2015, our General Partner agreed to absorb certain of our corporate expenses. We received reimbursements for these expenses in the quarter subsequent to when they were incurred. We received reimbursements totaling $7.5 million and $3.0 million for the years ended December 31, 2016 and 2015, respectively. In the first quarter of 2015, certain executive bonuses related to the year ended December 31, 2014 were paid on our behalf by ArcLight. In addition, ArcLight reimbursed us for expenses we incurred for the years ended December 31, 2016 and 2015. The total amounts paid on our behalf or reimbursed to us were $2.4 million and $2.6 million for the years ended December 31, 2016 and 2015, respectively, and were treated as deemed contributions from ArcLight.

An ArcLight affiliate provided crude oil pipeline transportation services to our discontinued Mid-Continent Business. During the years ended December 31, 2016, 2015 and 2014, we incurred related pipeline transportation fees of $0.4 million, $6.0 million and

$8.9 million, respectively, which have been included in net loss from discontinued operations, net of tax in the consolidated statements of operations. As of December 31, 2015, we had a net receivable of $7.9 million from this affiliate, primarily as the result of the prepayments made in 2014 for the crude oil pipeline transportation services to be provided.

The Partnership acquired Blackwater Midstream Holdings, LLC (“Blackwater”) from affiliates of ArcLight in December 2013. The acquisition agreement included a provision whereby an ArcLight affiliate would be entitled to an additional $5.0 million of merger consideration based on Blackwater meeting certain operating targets. During the third quarter of 2016, the Partnership determined that it was probable the operating targets would be met in early 2017 and recorded a $5.0 million accrued distribution to the ArcLight affiliate which is included in Accrued expenses and other current liabilities in the accompanying consolidated balance sheets at December 31, 2016.

American Panther, LLC ("American Panther") is a 60%-owned subsidiary of the Partnership which is consolidated for financial reporting purposes. Pursuant to a related agreement which began in the second quarter of 2016, an affiliate of the non-controlling interest holder provides services to American Panther in exchange for related fees, which in 2016 totaled $1.2 million of which $0.8 million is included in Direct operating expenses and $0.4 million is included in Corporate expenses in the consolidated statement of operations.

On November 1, 2016, the Partnership became operator of the Destin and Okeanos pipelines and entered into operating and administrative management agreements under which the affiliates pay a monthly fee for general and administrative services provided by the Partnership. In addition, the affiliates reimbursed the Partnership for certain transition related expenses. For the year ended December 31, 2016, the Partnership recognized $0.4 million of management fee income and $1.0 million as reimbursement of transition related expenses in Corporate expenses in the consolidated statements of operations.

During the second quarter of 2015, we began performing administrative, crude transportation and marketing services for an ArcLight affiliate. We charged $3.2 million and $3.0 million for the years ended December 31, 2016 and 2015, respectively, for these services of which $3.2 million and $2.2 million was included in Services for the years ended December 31, 2016 and 2015, respectively, and $0.8 million was included in Commodity sales for the year ended December 31, 2015 on the consolidated statements of operations. As of December 31, 2016 and 2015, we had receivables due from this affiliate of $2.1 million and $0.7 million, respectively, which are included in other current assets in the consolidated balance sheets.

The Partnership enters into purchases and sales of natural gas and crude oil with a company whose chief financial officer is the brother of one of our executive officers. During the years ended December 31, 2016, 2015, and 2014, the Partnership recognized related revenue of $3.6 million, $6.2 million and $10.1 million, respectively, while purchases from the company totaled $4.3 million, $5.9 million, and $3.7 million, respectively.

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21. Supplemental Cash Flow Information

Supplemental cash flows and non-cash transactions consists of the following (in thousands):

	Years Ended December 31,
	2016		2015			2014
Supplemental cash flow information
Interest payments, net of capitalized interest	$	22,303	$	16,540		$	13,905
Cash paid for taxes	530		450			108
Supplemental non-cash information
Increase (decrease) in accrued property, plant and equipment purchases	$	8,533	$	(21,841	)	$	35,018
Contributions from general partner	7,500		4,350			—
Acquisitions partially funded by the issuance of common units	—		3,442			414,396
Assets acquired under capital lease	139		—			177
Issuance of Series C Units and Warrant in connection with the Emerald Transactions	120,000		—			—
Accrued cash distributions on convertible preferred units	7,103		—			—
Paid-in-kind distributions on convertible preferred units	14,446		16,978			13,154
Paid-in-kind distributions on Series B Units	—		1,373			2,220
Paid-in-kind distributions on JPE Series D units	—		—			2,436
Cancellation of escrow units	6,817		—			—
Additional Blackwater acquisition consideration	5,000		—			—

22. Reportable Segments

Our operations are located in the United States and are organized into the following reportable segments: Gas Gathering and Processing Services, Liquid Pipelines and Services, Natural Gas Transportation Services, Offshore Pipeline and Services, Terminalling Services, and Propane Marketing Services. These segments, are described below, have been identified based on the differing products and services, regulatory environments and the expertise required for these operations.

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

Liquid Pipelines and Services provides transportation, purchase and sales of crude oil from various receipt points including lease automatic custody transfer ("LACT") facilities and delivering to various markets.

Natural Gas Transportation Services transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, which include local distribution companies (“LDCs”), utilities and industrial, commercial and power generation customers.

Offshore Pipelines and Servicesgathers and transports natural gas from various receipt points to other pipeline interconnects, onshore facilities and other delivery points.

Terminalling Services provides above-ground leasable storage operations at our marine terminals that support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products and also includes crude oil storage in Cushing, OK and refined products terminals in Texas and Arkansas.

Propane Marketing Services gathers, transports and sells natural gas liquids (NGLs). This is accomplished through cylinder tank exchange, sales through retail, commercial and wholesale distribution and through a fleet of trucks operating in the Eagle Ford and Permian basin areas.

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Our Chief Executive Officer serves as our Chief Operating Decision Maker and evaluates the performance of our reportable segments primarily on the basis of segment gross margin, which is our segment measure of profitability. We define segment gross margin for each segment as summarized below:

Gas Gathering and Processing Services - total revenue plus unconsolidated affiliate earnings less unrealized gains (losses) on commodity derivatives, construction and operating management agreement income and the cost of sales.

Liquid Pipelines and Services - total revenue plus unconsolidated affiliate earnings less unrealized gains (losses) on commodity derivatives and the cost of sales. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.

Natural Gas Transportation Services - total revenue plus unconsolidated affiliate earnings less the cost of sales. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.

Offshore Pipelines and Services - total revenue plus unconsolidated affiliate earnings less the cost of sales. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.

Terminalling Services - total revenue less direct operating expense which includes direct labor, general materials and supplies and direct overhead.

Propane Marketing Services - total revenue less cost of sales excluding non-cash charges such as non-cash unrealized gain (losses) on commodity derivatives.

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

	December 31, 2016
	Gas Gathering and Processing Services			Liquid Pipelines and Services			Natural Gas Transportation Services		Offshore Pipelines and Services			Terminalling Services			Propane Marketing Services		Total
	(in thousands)
Commodity sales	$	91,444		$	304,501		$	21,999	$	6,812		$	14,655		$	129,116	$	568,527
Services	22,558			12,146			18,109		40,502			50,999			14,536		158,850
Gains (losses) on commodity derivatives, net	(833		)	(341		)	—		(7		)	(436		)	1,162		(455		)
Total Revenue	113,169			316,306			40,108		47,307			65,218			144,814		726,922
Cost of sales	63,832			288,496			21,288		3,049			11,564			54,794		443,023
Direct operating expenses	33,802			8,383			5,923		10,945			10,783			53,536		123,372
Corporate expenses																	99,430
Depreciation, amortization, and accretion																	106,818
Loss on sale of assets, net																	2,870
Loss on impairment of plant, property and equipment																	697
Loss on impairment of goodwill																	15,456
Interest expense																	21,469
Earnings in unconsolidated affiliates																	(40,158		)
Other (income) expense																	(628		)
Income tax expense																	2,578
Income (loss) from continuing operations																	(48,005		)
Loss from discontinuing operations, net of tax																	(539		)
Net income (loss)																	(48,544		)
Net income (loss) attributable to non-controlling interest																	2,766
Net income (loss) attributable to partnership																	$	(51,310	)
Segment gross margin	$	48,245		$	29,760		$	18,616	$	82,346		$	42,872		$	88,948

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	December 31, 2015
	Gas Gathering and Processing Services		Liquid Pipelines and Services		Natural Gas Transportation Services		Offshore Pipelines and Services		Terminalling Services		Propane Marketing Services			Total
	(in thousands)
Commodity sales	$	107,680	$	457,390	$	23,972	$	13,798	$	10,343	$	159,674		$	772,857
Services	30,196		12,895		16,035		21,457		45,022		17,157			142,762
Gains (losses) on commodity derivatives, net	1,240		—		—		84		21		(3,077		)	(1,732		)
Total Revenue	139,116		470,285		40,007		35,339		55,386		173,754			913,887
Cost of sales	72,960		446,125		21,858		9,914		8,893		70,553			630,303
Direct operating expenses	35,250		8,310		6,728		9,425		10,414		57,353			127,480
Corporate expenses														77,835
Depreciation, amortization, and accretion														98,596
Loss on sale of assets, net														3,920
Loss on impairment of goodwill														148,488
Interest expense														20,120
Earnings in unconsolidated affiliates														(8,201		)
Other (income) expense														(1,732		)
Income tax expense														1,888
Income (loss) from continuing operations														(184,810		)
Loss from discontinuing operations, net of tax														(15,031		)
Net income (loss)														(199,841		)
Net income (loss) attributable to non-controlling interest														(13		)
Net income (loss) attributable to partnership														$	(199,828	)
Segment gross margin	$	65,692	$	24,160	$	18,073	$	33,613	$	36,079	$	91,437

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	December 31, 2014
	Gas Gathering and Processing Services		Liquid Pipelines and Services		Natural Gas Transportation Services		Offshore Pipelines and Services		Terminalling Services		Propane Marketing Services			Total
	(in thousands)
Commodity sales	$	148,198	$	470,336	$	70,964	$	20,044	$	11,521	$	188,702		$	909,765
Services	15,248		11,548		12,925		24,426		41,357		18,194			123,698
Gains (losses) on commodity derivatives, net	1,050		—		—		41		—		(13,762		)	(12,671		)
Total Revenue	164,496		481,884		83,889		44,511		52,878		193,134			1,020,792
Cost of dales	112,719		459,319		70,100		15,133		6,859		125,742			789,872
Direct operating expenses	21,197		5,819		6,975		11,142		11,525		52,885			109,543
Corporate expenses														72,744
Depreciation, amortization, and accretion														72,527
Loss on sale of assets, net														5,080
Loss on impairment of plant, property and equipment														21,344
Interest expense														16,558
Earnings in unconsolidated affiliates														(348		)
Other (income) expense														662
Loss on extinguishment of debt														1,634
Income tax expense														857
Income (loss) from continuing operations														(69,681		)
Loss from discontinuing operations, net of tax														(9,886		)
Net income (loss)														(79,567		)
Net income (loss) attributable to non-controlling interest														3,993
Net income (loss) attributable to partnership														$	(83,560	)
Segment gross margin	$	51,213	$	22,564	$	13,691	$	29,089	$	34,493	$	80,083

A reconciliation of total assets by segment to the amounts included in the consolidated balance sheets is as follows:

	December 31,
	2016		2015
Segment assets:	(in thousands)
Gas Gathering and Processing Services	$	530,889	$	496,014
Liquid Pipelines and Services	422,636		426,854
Natural Gas Transportation Services	221,604		146,927
Offshore Pipelines and Services	400,193		190,271
Terminalling Services	299,534		291,130
Propane Marketing Services	140,864		173,558
Other (1)	333,601		27,135
Total assets	$	2,349,321	$	1,751,889

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_______________________

(1) Other assets not allocable to segments consist of investment in unconsolidated affiliates, restricted cash and other assets.

23. Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2016 and 2015 are as follows (in thousands, except per unit amounts):

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter (2)
Year Ended December 31, 2016
Total revenues	$	143,376		$	185,836		$	187,659		$	210,051
Gross margin (1)	74,045			81,072			76,427			79,243
Operating loss	(8,401		)	(10,368		)	(12,125		)	(33,850		)
Net income (loss)	(10,603		)	(9,481		)	(7,797		)	(20,663		)
Net income (loss) attributable to the Partnership	(10,600		)	(10,435		)	(8,993		)	(21,282		)
General Partner's Interest in net income (loss)	(97		)	(107		)	(26		)	(3		)
Limited Partners' Interest in net income (loss)	$	(10,503	)	$	(10,328	)	$	(8,967	)	$	(21,279	)
Limited Partners' income (loss) per unit:
Loss from continuing operations	$	(0.32	)	$	(0.33	)	$	(0.33	)	$	(0.61	)
Net income (loss)	$	(0.33	)	$	(0.33	)	$	(0.33	)	$	(0.61	)
Year Ended December 31, 2015
Total revenues	$	238,035		$	265,703		$	209,416		$	200,733
Gross margin (1)	73,088			66,757			56,829			72,380
Operating income (loss)	2,187			(5,769		)	(10,831		)	(158,322		)
Net income (loss) from continuing operations	(1,525		)	(10,913		)	(15,207		)	(157,165		)
Income (loss) from discontinued operations, net of tax	(402		)	511			(1,300		)	(13,840		)
Net income (loss) attributable to noncontrolling interest	4			22			24			(63		)
Net income (loss) attributable to the Partnership	(1,932		)	(10,425		)	(16,532		)	(170,939		)
General Partner's Interest in net income (loss)	(32		)	(66		)	(104		)	(1,621		)
Limited Partners' Interest in net income (loss)	$	(1,900	)	$	(10,358	)	$	(16,428	)	$	(169,319	)
Limited Partners' income (loss) per unit:
Loss from continuing operations	$	(0.15	)	$	(0.39	)	$	(0.50	)	$	(3.55	)
Net loss	$	(0.16	)	$	(0.38	)	$	(0.53	)	$	(3.85	)

(1) 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."

(2) We recognized goodwill impairment charges of $15.4 million and $148.5 million in the fourth quarters of 2016 and 2015, respectively.

24. Subsequent Event

Distribution

On January 26, 2017, we announced that the Board of Directors of our General Partner declared a quarterly cash distribution of

$0.4125 per common unit for the fourth quarter ended December 31, 2017, or $1.65 per common unit on an annualized basis. The distribution is expected to be paid on February 13, 2017, to unitholders of record as of the close of business February 6, 2017.

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Dakota Access Connection Agreement

On March 1, 2017, the Partnership announced it has entered a connection agreement with Dakota Access Pipeline (“DAPL”), the 1,172-mile pipeline that extends from the Partnership’s Bakken formation production area in North Dakota to Patoka, Illinois. The new DAPL interconnect will tie into the Partnership’s Bakken crude oil gathering system which consists of interstate pipelines with capacity to transport up to approximately 40,000 barrels per day of crude oil.

Sale of Propane Marketing Services Business

On July 21, 2017, the Partnership entered into an agreement to sell its Propane Marketing Services business to SHV Energy, N.V. for $170.0 million in cash. The transaction closed on September 1, 2017. The underlying agreement contemplates working capital and other adjustments which have not yet been determined.     

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