8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): December 6, 2017

AMERICAN MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)

Delaware	001-35257	27-0855785
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification No.)
2103 CityWest Blvd., Bldg. 4, Suite 800		77042
Houston, TX		(Zip Code)
(Address of principal executive offices)

Registrant’s telephone number, including area code: (346) 241-3400

Not applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the Registrant under any of the following provisions:

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

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

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

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

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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Item 8.01 Other Events.

On September 1, 2017, American Midstream Partners, LP (“AMID”) completed the disposition of the Propane Marketing Services business (the "Propane Business”) to SHV Energy N. V. (“SHV Energy”) for an aggregate purchase price of $170 million plus balance sheet cash at closing, less the repayment of all indebtedness and transaction costs, and subject to working capital adjustments (the “Transaction”), pursuant to that certain Membership Interest Purchase Agreement dated July 21, 2017 (the “Purchase Agreement”), between AMID Merger LP, a wholly-owned subsidiary of AMID, and SHV Energy. As a result of the disposition of the Propane Business, AMID classified the results of operations of the Propane Business as discontinued operations. Accordingly, AMID has recast its financial statements to retrospectively reflect this change in classification of the Propane Business to discontinued operations for all periods presented.

AMID’s Form 10-K for the year ended December 31, 2016 (the “2016 Form 10-K”) as filed with the U.S. Securities and Exchange Commission (the “SEC”) on March 28, 2017, Part II, Item 6, Part II, Item 7 and Part II, Item 8, all of which have been superseded by recast information filed with the SEC on a Current Report on Form 8-K on September 18, 2017, is hereby recast by this Current Report on Form 8-K as follows:

• Selected Financial Data included herein as Exhibit 99.1 supersedes Exhibit 99.1 in the Current Report on Form 8-K filed on September 18, 2017;

• Management’s Discussion and Analysis of Financial Condition and Results of Operations included herein as Exhibit 99.2 supersedes Exhibit 99.2 in the Current Report on Form 8-K filed on September 18, 2017; and

• Financial Statements and Supplementary Data included herein as Exhibit 99.3 supersedes Exhibit 99.3 in the Current Report on Form 8-K filed on September 18, 2017.

There have been no revisions or updates to the 2016 Form 10-K other than the revisions noted above. This Current Report on Form 8-K should be read in conjunction with the 2016 Form 10-K.

Item 9.01 Financial Statements and Exhibits

(d) Exhibits.

Exhibit Number	Description
23.1	Consent of Independent Registered Public Accounting Firm.
99.1	Selected Financial Data
99.2	Management's Discussion and Analysis of Financial Condition and Results of Operations
99.3	Financial Statements and Supplementary Data.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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CAUTIONARY STATEMENTS

Disclosures in this Form 8-K and the exhibits filed herewith contain certain “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

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

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Examples of these risks and uncertainties, many of which are beyond our control, include, but are not limited to, the risks set forth in “Item 1A. Risk Factors” in the 2016 Form 10-K as well as the following risks and uncertainties:

• our ability to generate sufficient cash from operations to pay distributions to unitholders;

• our ability to maintain compliance with financial covenants and ratios in our Credit Facility (as defined in the 2016 Form 10-K);

• our ability to timely and successfully identify, consummate and integrate our recent, pending and future acquisitions and complete strategic dispositions, including the realization of all anticipated benefits of any such transaction, which otherwise could negatively impact our future financial performance;

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

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

• severe weather and other natural phenomena, including their potential impact on demand for the commodities we sell and the operation of company-owned and third party-owned infrastructure;

• the level of creditworthiness of counterparties to transactions;

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

• the volumes of natural gas and crude oil that we gather, process, transport and store, the throughput volume at our refined products terminals and our NGL sales volumes;

• the fees that we receive for the natural gas, crude oil, refined products and NGL products we handle;

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

• changes in laws and regulations, particularly with regard to taxes, safety, regulation of over-the-counter derivatives market and entities, and protection of the environment;

• our failure or our counterparties’ failure to perform on obligations under commodity derivative and financial derivative contracts;

• the performance of certain of our current and future projects and unconsolidated affiliates that we do not control;

• the demand for natural gas, crude oil, NGL and refined products by the petrochemical, refining or other industries;

• our dependence on a relatively small number of customers for a significant portion of our gross margin;

• general economic, market and business conditions, including industry changes and the impact of consolidations and changes in competition;

• our ability to renew our gathering, processing, transportation and terminal contracts;

• our ability to successfully balance our purchases and sales of natural gas;

• leaks or releases of hydrocarbons into the environment that result in significant costs and liabilities;

• the adequacy of insurance to cover our losses;

• our ability to grow through contributions from affiliates, acquisitions or internal growth projects;

• our management's history and experience with certain aspects of our business and our ability to hire as well as retain qualified personnel to execute our business strategy;

• the cost and effectiveness of our remediation efforts with respect to the material weakness discussed in “Part II. Item 9A. Controls and Procedures” in the 2016 Form 10-K;

• volatility in the price of our common units;

• security threats such as military campaigns, terrorist attacks, and cybersecurity breaches, against, or otherwise

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impacting, our facilities and systems; and

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

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Current Report on Form 8-K and the exhibits filed herewith will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in “Item 1A. Risk Factors” in the 2016 Form 10-K and in our other filings with the SEC. Statements in this Current Report on Form 8-K speak as of the date of this report. Except as may be required by applicable securities laws, we undertake no obligation to publicly update or advise investors of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

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SIGNATURES

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

	American Midstream Partners, LP
	By: American Midstream GP, LLC,
	its General Partner
Date:
December 6, 2017	By:	/s/ Eric T. Kalamaras
	Name:	Eric T. Kalamaras
	Title:	Senior Vice President & Chief Financial Officer

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EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S‑3 (Nos. 333-198888, 333-201434 and 333-201436) and on Form S‑8 (Nos. 333-216585, 333-176438, 333-183290 and 333-209614) of American Midstream Partners, LP of our report dated 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 which is discussed in Note 2, as to which the date is September 15, 2017, and except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of discontinued operations discussed in Note 3, as to which the date is December 6, 2017 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Current Report on Form 8‑K dated December 6, 2017.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

December 6, 2017

EX-99.1

EXHIBIT 99.1

Item 6. Selected Historical Financial and Operating Data

The following table presents selected historical consolidated financial and operating data for the periods and as of the dates indicated. We derived this information from our historical consolidated financial statements and accompanying notes. This information should be read together with, and is qualified in its entirety, by reference to those consolidated financial statements and notes, which for the years 2016, 2015, and 2014 begin on F-1 included in Exhibit 99.3 to our Current Report on Form 8-K filed on December 6, 2017 (the "Recast Form 8-K dated December 6, 2017").

On March 8, 2017 we acquired JP Energy Partners, LP ("JPE") in a unit-for-unit exchange. 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 following selected historical financial information represent JPE’s historical cost basis financial information recast to reflect the acquisition of the Partnership at ArcLight’s historical cost basis effective April 15, 2013, the date on which ArcLight obtained control of the Partnership.

On September 1, 2017, the Partnership completed the disposition of JPE's propane marketing services business ("the Propane Business"). Through the transaction, we divested Pinnacle Propane’s 40 service locations; Pinnacle Propane Express’ cylinder exchange business and related logistic assets; and the Alliant Gas utility system. Prior to the sale, we moved the trucking business from the Propane Marketing Services segment to the Liquid Pipelines and Services segment for all periods presented. In connection with the transaction, the Partnership received $170.0 million in cash and recorded a gain on the sale of $46.5 million, net of $2.5 million transaction costs. As a result of the disposition of the Propane Business, the Partnership has classified the accounts and the results of operations of the Propane Business as discontinued operations.

For a detailed discussion of the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in Exhibit 99.2 to the Recast Form 8-K dated December 6, 2017.

EXHIBIT 99.1

	Years ended December 31,
	2016 (1)			2015 (1)			2014 (1)			2013 (1)			2012 (6)
	(in thousands, except per unit and operating data)
Statements of Operations Data:
Revenues:
Total operating revenue	$	589,026		$	750,304		$	838,949		$	436,021		$	77,717
Operating expenses:
Cost of sales	393,351			567,682			672,948			331,831			72,520
Direct operating expenses	71,544			71,729			58,048			33,962			5,080
Corporate expenses	89,438			65,327			60,465			51,193			10,747
Depreciation, amortization and accretion	90,882			81,335			57,818			43,458			4,790
Loss (gain) on sale of assets, net	688			2,860			4,087			(17		)	2
Loss on impairment of property, plant and equipment	697			—			21,344			8,830			—
Loss on impairment of goodwill	2,654			148,488			—			—			—
Total operating expenses	649,254			937,421			874,710			469,257			93,139
Operating loss	(60,228		)	(187,117		)	(35,761		)	(33,236		)	(15,422		)
Other income (expense):
Interest expense	(21,433		)	(20,077		)	(16,497		)	(15,418		)	(3,167		)
Other income (expense)	254			1,460			(1,096		)	544			13
Loss on extinguishment of debt	—			—			(1,634		)	—			(497		)
Earnings in unconsolidated affiliates	40,158			8,201			348			—			—
Loss from continuing operations before income taxes	(41,249		)	(197,533		)	(54,640		)	(48,110		)	(19,073		)
Income tax (expense) benefit	(2,580		)	(1,885		)	(856		)	212			(185		)
Loss from continuing operations	(43,829		)	(199,418		)	(55,496		)	(47,898		)	(19,258		)
Discontinued operations:
Income (loss) from discontinued operations	(4,715		)	(423		)	(24,071		)	13,446			10,870
Net loss	(48,544		)	(199,841		)	(79,567		)	(34,452		)	(8,388		)
Net income (loss) attributable to non-controlling interests	2,766			(13		)	3,993			705			—
Net loss attributable to the Partnership	$	(51,310	)	$	(199,828	)	$	(83,560	)	$	(35,157	)	$	(8,388	)
General Partner's Interest in net loss	$	(233	)	$	(1,823	)	$	(398	)	$	(864	)	$	—
Limited Partners' Interest in net loss	$	(51,077	)	$	(198,005	)	$	(83,162	)	$	(34,293	)	$	(8,388	)
Limited Partners' net (loss) per common unit:
Basic and diluted:
Loss from continuing operations	$	(1.51	)	$	(4.91	)	$	(2.77	)	$	(3.21	)	$	(1.19	)
Income (loss) from discontinued operations	(0.09		)	(0.01		)	(0.52		)	(0.07		)	0.61
Net loss	$	(1.60	)	$	(4.92	)	$	(3.29	)	$	(3.28	)	$	(0.58	)
Weighted average number of common units outstanding:
Basic and diluted (2)	51,176			45,050			27,524			18,931			12,069

EXHIBIT 99.1

Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	90,639		$	86,978		$	51,635		$	29,500		$	(6,990	)
Investing activities	(564,504		)	(250,769		)	(518,023		)	(115,173		)	(292,334		)
Financing activities	477,544			161,954			466,577			79,156			304,991
Other Financial Data:
Adjusted EBITDA (3)	$	137,132		$	78,152		$	32,243		$	43,255		$	7,877
Total segment gross margin (4)	223,635			179,856			153,524			96,809			5,197
Cash distribution declared per common unit	3.01			3.17			1.85			1.75			—
Segment gross margin:
Gathering and Processing	48,245			65,692			51,213			5,673			—
Liquid Pipelines and Services	31,556			26,399			25,038			5,420			3,465
Natural Gas Transportation Services	18,616			18,073			13,691			13,150			—
Offshore Pipeline and Services	82,346			33,613			29,089			36,318			—
Terminalling Services	42,872			36,079			34,493			36,248			1,732
Balance Sheet Data (at period end):
Cash and cash equivalents	$	5,666		$	1,987		$	3,824		$	3,627		$	10,099
Accounts receivable and unbilled revenue	67,625			61,016			116,676			129,724			59,721
Property, plant and equipment, net	1,066,608			981,321			887,045			537,304			103,954
Total assets	2,349,321			1,751,889			1,865,210			1,292,695			562,124
Current portion of long-term debt	5,438			2,758			3,141			3,141			2,694
Long-term debt	1,235,538			687,100			456,965			314,764			164,429
Operating Data:
Gas Gathering and Processing Services:
Average throughput (MMcf/d)	220.6			240.0			155.8			129.5			—
Average plant inlet volume (MMcf/d) (5)	102.1			120.9			89.1			125.7			—
Average gross NGL production (Mgal/d) (5)	192.9			231.1			64.2			50.4			—
Average gross condensate production (Mgal/d) (5)	82.9			97.1			70.8			45.5			—
Liquid Pipelines and Services:
Average throughput Pipeline (Bbl/d)	32,257			34,946			20,868			13,738			—
Average throughput Truck (Bbl/d)	1,628			—			—			—			—
Natural Gas Transportation Services:
Average throughput (MMcf/d)	389.9			364.1			373.3			364.9			—
Average firm transportation - capacity reservation (MMcf/d)	634.7			637.2			567.9			592.5			—
Average interruptible transportation - throughput (MMcf/d)	65.3			70.2			65.3			106.4			—
Offshore Pipelines and Services:
Average throughput (MMcf/d)	466.4			442.8			524.6			498.9			—
Average gross condensate production (Mgal/d) (5)	3.6			2.7			4.4			1.2			—
Average firm transportation - capacity reservation (MMcf/d)	53.4			16.6			10.0			—			—
Average interruptible transportation - throughput (MMcf/d)	288.7			340.1			403.7			361.6			—

EXHIBIT 99.1

Terminalling Services:
Storage Capacity (Bbls)	5,011,133		4,487,542		4,247,058		4,114,792		3,000,000
Design Capacity (Bbls)	5,173,717		4,688,950		4,363,817		4,165,600		3,000,000
Storage utilization	96.9	%	95.7	%	97.3	%	99.0	%	100.0	%
Terminalling and Storage throughput (Bbls/d)	56,741		62,075		63,859		69,071		57,143

(1) The following transactions affect comparability between years: i) in October 2016 and April 2016 we acquired 6.2% and 1% non-operated interests in Delta House Class A Units,which we account for as equity method investments and are included in our Offshore Pipelines and Services segment; ii) in April 2016, we acquired membership interests in Destin (49.7%), Tri-States (16.7%), Okeanos (66.7%), and Wilprise (25.3%), which we account for as equity method investments and are included in our Liquid Pipelines and Services and Offshore Pipelines and Services segments; iii) in April 2016 we acquired a 60% interest in American Panther which we consolidate for financial reporting purposes and is included in our Offshore Pipelines and Services segment; iv) in September 2015, we acquired a non-operated 12.9% indirect interest in Delta House Class A Units, which we account for as an equity method investment and is included in our Offshore Pipelines and Services segment; v) in October 2014 and January 2014, we acquired the Costar and Lavaca systems, respectively, both of which are included in our Gas Gathering and Processing Services segment; vi) in June 2014, we completed the sale of our crude oil logistics operations which was included in our Liquids Pipelines and Services segment; vii) in December 2013, we acquired Blackwater, which is included in our Terminals segment; and viii) in April 2013, we acquired the High Point System, which is included in Transmission segment.

(2) Includes unvested phantom units with distribution equivalent rights ("DERs"), which are considered participating securities, of 200,000 at December 31, 2016 and 2015.

(3) For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Item 7. Management's Discussion and Analysis — How We Evaluate Our Operations" included in Exhibit 99.2 to the Recast Form 8-K dated December 6, 2017.

(4) For a definition of Total segment 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 Total segment gross margin to evaluate our operating performance, please read "Item 7. Management's Discussion and Analysis — How We Evaluate Our Operations" included in Exhibit 99.2 to the Recast Form 8-K dated December 6, 2017.

(5) Excludes volumes and gross production under our elective processing arrangements. For a description of our elective processing arrangements, please read "Item 7. Management's Discussion and Analysis — Our Operations - Gathering and Processing Segment" included in Exhibit 99.2 to the Recast Form 8-K dated December 6, 2017.

(6) The 2012 selected financial data represents JPE financial activity only, given the common control was April 15, 2013; as mentioned above.

EX-99.2

EXHIBIT 99.2

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements and the related notes thereto included elsewhere in Exhibit 99.3 to the Current Report on Form 8-K filed by American Midstream Partners, LP (along with its consolidated subsidiaries, “we,” “us,” “our,” or the “Partnership”) on December 6, 2017 (the “Recast Form 8-K dated December 6, 2017”). This discussion contains forward-looking statements that reflect management’s current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements or as a result of certain factors such as those set forth under the caption “Cautionary Statement About Forward-Looking Statements” included in our Current Report on Form 8-K (the "Recast Form 8-K") as of and for the year ended December 31, 2016 as filed with the U.S. Securities and Exchange Commission (the “SEC”) on September 18, 2017.

On March 8, 2017, the Partnership completed the acquisition of JP Energy Partners, LP ("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, recast 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. See Item 8. Financial Statements and Supplementary Data - Note 2 in Exhibit 99.3 to the Recast Form 8-K dated December 6, 2017 for more information on the JPE Merger.

On September 1, 2017, the Partnership completed the disposition of JPE's propane marketing services business (the "Propane Business"). Through the transaction, we divested Pinnacle Propane’s 40 service locations; Pinnacle Propane Express’ cylinder exchange business and related logistic assets; and the Alliant Gas utility system. Prior to the sale, we moved the trucking business from the Propane Marketing Services segment to the Liquid Pipelines and Services segment for all periods presented. In connection with the transaction, the Partnership received $170.0 million in cash and recorded a gain on the sale of $46.5 million, net of $2.5 million transaction costs. As a result of the disposition of the Propane Business, the Partnership has classified the accounts and the results of operations of the Propane Business as discontinued operations.

As previously reported in Part II, Item 9A of our 2016 Form 10-K management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2016, based on criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation of internal control over financial reporting, management concluded that as of December 31, 2016, the Partnership did not maintain a sufficient complement of resources with an appropriate level of accounting knowledge, expertise and training commensurate with its financial reporting requirements. Specifically, individuals within the Partnership’s financial accounting and reporting functions did not have the appropriate level of expertise to ensure that complex, non-routine transactions of the Partnership were recorded appropriately. This control deficiency resulted in out-of-period adjustments recorded to the consolidated statement of operations in the fourth quarter of 2016 and a revision to the 2015 consolidated balance sheet and consolidated statement of cash flows. Management concluded that this deficiency in internal control over financial reporting could result in material misstatements of the Partnership’s annual or interim consolidated financial statements that would not be prevented or detected on a timely basis. Accordingly, in connection with the assessment of the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2016, management concluded that this control deficiency constituted a material weakness. Because of this material weakness in internal control over financial reporting, management concluded that the Partnership’s internal control over financial reporting was not effective as of December 31, 2016. Management has not undertaken, and is not required to have undertaken, an assessment of the effectiveness of the Partnership’s internal control over financial reporting since the assessment of the Partnership’s internal control over financial reporting as of December 31, 2016, as described above.

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EXHIBIT 99.2

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 the Partnership’s internal controls over financial reporting as of December 31, 2016 or in PricewaterhouseCoopers, LLP’s audit of such controls. Effective March 8, 2017, JPE is a wholly-owned subsidiary of the Partnership whose total assets and total revenue represented 28.7% and 68.0%, respectively, of the recast consolidated financial statement amounts as of and for the year ended December 31, 2016 included in Exhibit 99.3 to the Recast Form 8-K dated December 6, 2017.

Overview

We are a growth-oriented Delaware limited partnership that was formed in August 2009 to own, operate, develop and acquire a diversified portfolio of midstream energy assets. We 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 five financial reporting segments, (i) gas gathering and processing services, (ii) liquids pipelines and services, (iii) natural gas transportation services, (iv) offshore pipelines and services and (v) terminalling 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 selling refined products.

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, and (iv) offshore in the Gulf of Mexico. Our liquids pipelines, natural gas transportation and offshore pipelines and terminal assets are located in prolific producing regions and key demand markets in Alabama, Louisiana, Mississippi, North Dakota, Texas, Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia.

We own or have ownership interests in more than 3,800 miles of onshore and offshore natural gas, crude oil, NGL and saltwater pipelines across 16 gathering systems, six interstate pipelines and nine intrastate pipelines; eight natural gas processing plants; four fractionation facilities; an offshore semisubmersible floating production system with nameplate processing capacity of 80 MMBbl/d of crude oil and 200 MMcf/d of natural gas; and six marine terminal sites with approximately 6.7 MMBbls of above-ground aggregate storage capacity for petroleum products, distillates, chemicals and agricultural products; and 97 transportation trucks.

A portion of our cash flow is derived from our investments in unconsolidated affiliates including a 49.7% operated interest in Destin, a natural gas pipeline; a 20.1% non-operated interest in the Class A Units of Delta House, which is a floating production system platform and related pipeline infrastructure; a 16.7% non-operated interest in Tri-States, an NGL pipeline; a 66.7% operated interest in Okeanos, a natural gas pipeline; a 25.3% non-operated interest in Wilprise, a NGL pipeline; and a 66.7% non-operated interest in MPOG, a crude oil gathering and processing system.

Significant financial highlights during the year ended December 31, 2016, include the following:

• Net loss attributable to the Partnership decreased by $148.5 million for the year ended December 31, 2016 as compared to the same period in 2015, primarily due to a decrease of $133.0 million in goodwill impairment charges, an increase in earnings in unconsolidated affiliates of $32.0 million primarily from our investments in Delta House and the entities underlying the Emerald Transactions, offset by an increase in corporate expense of $21.6 million due to our corporate relocation and JPE Merger expenses;

• Total segment gross margin increased by $43.8 million, or 24.3%, as compared to the same period in 2015 primarily attributable to an increase in our Offshore Pipelines and Services segment gross margin of $48.7 million as a result of increased revenues received by the Partnership due to the Pascagoula plant shutdown. The Pascagoula plant is not controlled or owned by the Partnership. As a result of the Pascagoula plant shutdown, volumes were redirected to our High Point system. Additionally, the incremental earnings from our equity method investees increased by $32.0 million, of which $29.9 million was attributable to our Offshore Pipelines and Services segment;

• Adjusted EBITDA increased by $59.0 million, or 75.5%, as compared to the same period in 2015 primarily due to distributions from our investments in Delta House and entities underlying the Emerald Transactions; and

• We distributed $112.1 million to our common unitholders;

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EXHIBIT 99.2

• On February 1, 2016, we sold certain trucking and marketing assets in the Mid-Continent area (the "Mid-Continent Business"), in connection with JP Development's, an affiliated entity, sale of its GSPP pipeline assets to a third party buyer. The sales price related to the Mid-Continent Business was $9.7 million; which included certain adjustments related to inventory and working capital items. We recognized a loss on the disposal of approximately $12.9 million during the year ended December 31, 2015. Prior to the classification of discontinued operations, we reported the Mid-Continent Business in our Liquid Pipelines and Services segment. We continue to retain our crude oil storage operations in the Mid-Continent area of Oklahoma;

• On April 25, 2016 and April 27, 2016, we acquired a 16.7% interest in Tri-States, an NGL pipeline; a 66.7% interest in Okeanos, a natural gas pipeline, a 49.7% interest in Destin, a natural gas pipeline, and a 25.3% interest Wilprise, an NGL pipeline for $211.0 million. We funded the aggregate purchase price with the issuance of 8,571,429 Series C Convertible Preferred Units and a warrant to purchase up to 800,000 of our common units at an exercise price of $7.25 per common unit with a combined value of approximately $120.0 million, plus additional borrowings of $91.0 million under our revolving credit agreement;

• 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, which owned 1.0% of Delta House Class A Units in exchange for approximately $9.9 million;

• On September 30, 2016, we completed the issuance of the 3.77% Senior Notes, which provided net proceeds of approximately $57.7 million after deducting related issuance costs;

• On October 23, 2016, we announced the acquisition of JPE. The transaction closed on March 8, 2017 and resulted in a larger and more diversified midstream business;

• On October 31, 2016, we acquired an additional 6.2% non-operated direct interest in Delta House Class A Units for a purchase price of approximately $48.8 million, which was funded with net proceeds of $34.5 million from the issuance of 2,333,333 Series D Convertible Preferred Units plus $14.3 million of additional borrowings under our revolving credit agreement. If any Series D Units remain outstanding on June 30, 2017, the Partnership will issue the Series D unitholders a warrant to purchase up to 700,000 common units at an exercise price of $22.00 per common unit;

• On December 28, 2016, we completed the issuance of the 8.50% Senior Notes which provided net proceeds of approximately $291.3 million after deducting issuances costs;

Significant operational highlights during the year ended December 31, 2016, include the following:

• The percentage of gross margin generated from fee-based, fixed-margin, firm and interruptible transportation contracts and firm storage contracts was 91.4% representing a 2.8% increase compared to 2015;

• Average gross condensate production totaled 86.6 Mgal/d, representing a 13.2 Mgal/d or 13.2%decrease compared to 2015 due to lower condensate prices of 10.9% and 22.1% in our Gas Gathering and Processing Services and Offshore Pipelines and Services segments, respectively;

• Throughput volumes attributable to the Partnership totaled 1,076.9 MMcf/d, representing a 2.9%increase compared to 2015 due to the Pascagoula plant shutdown, which redirected volumes to our High Point system;

• Pipelines throughput volumes attributable to our Liquid Pipelines and Services segment totaled 32,257 Bbls/d, representing a 14.2% increase compared to 2015 due to an increase in activity around our Silver Dollar Pipeline system;

• Contracted capacity for our Terminals segment averaged 5,011,233 barrels, representing a 11.7% increase compared to 2015 due to the expansion efforts at our Harvey terminal; and

• Average gross NGL production totaled 192.9 Mgal/d, representing a 38.2 Mgal/d or 16.5%decrease compared to 2015.

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EXHIBIT 99.2

Our Operations

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

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

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

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

• Offshore Pipelines and Services. Our Offshore Pipelines and Services segment gathers and transports natural gas and crude oil from various receipt points to other pipeline interconnects, onshore facilities and other delivery points.

• Terminalling Services. Our Terminalling Services segment 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, Oklahoma and refined products terminals in Texas and Arkansas.

Gas Gathering and Processing Services Segment

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

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

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

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

Gross margin earned under fee-based and fixed-margin arrangements is directly related to the volume of natural gas and crude oil that flows through our systems and is not directly dependent on commodity prices. However, a sustained decline in commodity prices could result in a decline in throughput volumes from producers and, thus, a decrease in our fee-based and fixed-margin gross margin. These arrangements provide stable cash flows, but upside in higher commodity-price environments is limited to an increase in throughput volumes from producers. Under our typical POP arrangement, our gross margin is directly impacted by the

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EXHIBIT 99.2

commodity prices we realize on our share of natural gas and NGLs received as compensation for processing raw natural gas. However, our POP arrangements also often contain a fee-based component, which helps to mitigate the degree of commodity-price volatility we could experience under these arrangements. We further seek to mitigate our exposure to commodity price risk through our hedging program.

Liquid Pipelines and Services Segment

Results of operations from the Liquid Pipelines and Services segment are determined by the volumes of crude oil transported on the interstate and intrastate pipelines we own. Tariffs associated with our Bakken system are regulated by FERC for volumes gathered via pipeline and trucked to the AMID Truck facility in Watford City, North Dakota. Volumes transported on our Silver Dollar system are underpinned by long-term, fee-based contracts. Our transportation arrangements are further described below:

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

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

• Fee-Based Arrangements. Under these arrangements our operations are underpinned by long-term, fee-based contracts with leading producers in the Midland Basin. Some of these contracts also have minimum volume commitments as well as some have acreage dedications.

Natural Gas Transportation Services Segment

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

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

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

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

Offshore Pipelines and Services Segment

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

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EXHIBIT 99.2

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

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

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

Terminalling Services Segment

Our Terminalling Services segment provides above-ground leasable storage services at our marine terminals that support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products, including petroleum products, distillates, chemicals and agricultural products. We generally receive fee-based compensation on guaranteed firm storage contracts, throughput fees charged to our customers when their products are either received or disbursed and other fee-based charges associated with ancillary services provided to our customers, such as excess throughput and truck weighing. Our firm storage contracts are typically multi-year contracts with renewal options.

How We Evaluate Our Operations

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

Throughput Volumes

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

In our Liquid Pipelines and Services segment, the amount of revenue we generate from our crude oil pipelines business depends primarily on throughput volumes. We generate a portion of our crude oil pipeline revenues through long-term contracts containing acreage dedications or minimum volume commitments. Throughput volumes on our pipeline system are affected primarily by the supply of crude oil in the market served by our assets. The revenue generated from our crude oil supply and logistics business depends on the volume of crude oil we purchase from producers, aggregators and traders and then sell to producers, traders and refiners as well as the volumes of crude oil that we gather and transport. The volume of our crude oil supply and logistics activities and the volumes transported by our crude oil gathering and transportation trucks are affected by the supply of crude oil in the markets served directly or indirectly by our assets. Accordingly, we actively monitor producer activity in the areas served by our crude oil supply and logistics business and other producing areas in the United States to compete for volumes from crude oil producers. Revenues in this business are also impacted by changes in the market price of commodities that we pass through to our customers.

In our Natural Gas Transportation Services and Offshore Pipelines and Services segments, the majority of our segment gross margin is generated by firm capacity reservation charges and interruptible transportation services from throughput volumes on our interstate and intrastate pipelines. Substantially all of the segment gross margin is generated under contracts with shippers,

6

EXHIBIT 99.2

including producers, industrial companies, LDCs and marketers, for firm and interruptible natural gas transportation on our pipelines. We routinely monitor natural gas market activities in the areas served by our transmission systems to maintain current throughput volumes and pursue new shipper opportunities.

In our Terminalling Services segment, we generally receive fee-based compensation on guaranteed firm storage contracts, throughput fees charged to our customers when their products are either received or disbursed, and other operational charges associated with ancillary services provided to our customers, such as excess throughput, steam heating and truck weighing at our marine terminals. The amount of revenue we generate from our refined products terminals depends primarily on the volume of refined products that we handle. These volumes are affected primarily by the supple of and demand for refined products in the markets served directly or indirectly by our refined products terminals. The volume of crude oil stored at our crude oil storage facility in Cushing, Oklahoma has no impact on the revenue generated by our crude oil storage business because we receive a fixed monthly fee per barrel of shell capacity that is not contingent on the usage of our storage tanks.

Storage Utilization

Storage utilization is a metric that we use to evaluate the performance of our Terminalling Services segment. We define storage utilization as the percentage of the contracted capacity in barrels compared to the design capacity of the tank.

Segment Gross Margin and Total Segment Gross Margin

We define segment gross margin in our Gas Gathering and Processing Services segment as total revenue plus unconsolidated affiliate earnings less unrealized gains (losses) on commodity derivatives, construction and operating management agreement income and cost of sales.

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

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

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

We define segment gross margin in our Terminalling Services segment as total revenue less the cost of sales utilized in our blending and injection of additives less direct operating expense.

Total segment gross margin is a supplemental non-GAAP financial measure that we use to evaluate our performance. We define total segment gross margin as the sum of the segment gross margins. The GAAP measure most directly comparable to total segment gross margin is Net income (loss) attributable to the Partnership. For a reconciliation of total segment gross margin to Net income (loss) attributable to the Partnership, please see “- Note About Non-GAAP Financial Measures” below.

Operating Margin

Operating margin is a supplemental non-GAAP financial measure that we use to evaluate our performance. We define operating margin as total segment gross margin less direct operating expenses. The GAAP measure most directly comparable to operating margin is net income (loss) attributable to the Partnership. For a reconciliation of Operating Margin to net income (loss), please see “- Note About Non-GAAP Financial Measures” below.

Direct Operating Expenses

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

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EXHIBIT 99.2

Adjusted EBITDA

Adjusted EBITDA is a supplemental non-GAAP financial measure used by our management and external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess: the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash flow to make cash distributions to our unitholders and our General Partner; our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

We define Adjusted EBITDA as net income (loss) attributable to the Partnership, plus interest expense, income tax expense, depreciation, amortization and accretion, debt issuance costs paid during the period, distributions from investments in unconsolidated affiliates, transaction expenses primarily associated with our JPE Merger and Delta House investments, certain non-cash charges such as non-cash equity compensation expense, unrealized (gains) losses on derivatives and selected charges that are unusual, less construction and operating management agreement income, post-retirement benefit plan expense, earnings in unconsolidated affiliates, gains (losses) on the sale of assets, net, and selected other gains (losses) that are unusual. The GAAP measure most directly comparable to our performance measure Adjusted EBITDA is net income (loss) attributable to the Partnership. For a reconciliation of Adjusted EBITDA to net loss attributable to the Partnership, please see “- Note About Non-GAAP Financial Measures” below.

Note about Non-GAAP Financial Measures

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

You should not consider total segment gross margin, operating margin, or Adjusted EBITDA in isolation or as a substitute for, or more meaningful than analysis of, our results as reported under GAAP. Total segment gross margin, operating margin and Adjusted EBITDA may be defined differently by other companies in our industry. Our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

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EXHIBIT 99.2

The following tables reconcile the non-GAAP financial measures of total segment gross margin, operating margin and Adjusted EBITDA used by management to Net income (loss) attributable to the Partnership, their most directly comparable GAAP measure, for the years ended December 31, 2016, 2015 and 2014, respectively:

	Years Ended December 31,
	2016 (1)			2015 (1)			2014 (1)
				(In thousands)
Reconciliation of Total Segment Gross Margin to Net loss attributable to the Partnership
Gas Gathering and Processing Services	$	48,245		$	65,692		$	51,213
Liquid Pipelines and Services	31,556			26,399			25,038
Natural Gas Transportation Services	18,616			18,073			13,691
Offshore Pipelines and Services	82,346			33,613			29,089
Terminalling Services	42,872			36,079			34,493
Total Segment Gross Margin	223,635			179,856			153,524
Less:
Direct operating expenses (2)	60,762			61,315			46,523
Operating margin	162,873			118,541			107,001
Add:
Gains (losses) on commodity derivatives, net	(1,617		)	1,345			1,091
Deduct:
Corporate expenses	89,438			65,327			60,465
Depreciation, amortization and accretion	90,882			81,335			57,818
Loss on sale of assets, net	688			2,860			4,087
Loss on impairment of property, plant and equipment	697			—			21,344
Loss on impairment of goodwill	2,654			148,488			—
Loss on extinguishment of debt	—			—			1,634
Interest expense	21,433			20,077			16,497
Other (income) expense	(254		)	(1,460		)	1,096
Other, net (3)	(3,033		)	792			(209		)
Income tax expense	2,580			1,885			856
Loss from discontinued operations	4,715			423			24,071
Net income (loss) attributable to noncontrolling interest	2,766			(13		)	3,993
Net loss attributable to the Partnership	$	(51,310	)	$	(199,828	)	$	(83,560	)

_______________________

(1) During these years, we had the following transactions that affect comparability: i) in October 2016 and April 2016 we acquired 6.2% and 1% non-operated interests in Delta House Class A Units which we account for as equity method investments and are included in our Offshore Pipelines and Services segment; ii) in April 2016, we acquired membership interests in Destin (49.7%), Tri-States (16.7%), Okeanos (66.7%), and Wilprise (25.3%), which we account for as equity method investments and are included in our Liquid Pipelines and Services and Offshore Pipelines and Services segments; iii) in April 2016 we acquired a 60% interest in American Panther which we consolidate for financial reporting purposes and is included in our Offshore Pipelines and Services segment; iv) in September 2015, we acquired a non-operated 12.9% indirect interest in Delta House, which we account for as an equity method investment and is included in our Offshore Pipelines and Services segment; and v) in October 2014 and January 2014, we acquired the Costar and Lavaca systems, respectively, both of which are included in our Gas Gathering and Processing Services segment.

(2) Direct operating expenses includes Gas Gathering and Processing Services segment direct operating expenses of $33.8 million, $35.3 million, and $21.2 million, respectively, Liquid Pipelines and Services segment direct operating expenses of $10.1 million, $9.9 million, and $7.2 million, respectively, Natural Gas Transportation Services segment direct operating expenses of $5.9 million, $6.7 million, and $7.0 million, respectively and Offshore Pipelines and Services segment direct operating

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EXHIBIT 99.2

expenses of $10.9 million, $9.4 million, and $11.1 million, respectively. Direct operating expenses exclude amounts related to the Terminalling segment as those costs are included in segment gross margin for Terminalling.

(3) Other, net includes realized gain (loss) on commodity derivatives of $(1.6) million, $1.6 million and $0.7 million and COMA income of $1.5 million, $0.8 million and $0.9 million, respectively, for each of the years ended December 31, 2016, 2015, and 2014, respectively.

	Years Ended December 31,
	2016			2015			2014
Reconciliation of Net loss attributable to the Partnership to Adjusted EBITDA:
Net loss attributable to the Partnership	$	(51,310	)	$	(199,828	)	$	(83,560	)
Add:
Depreciation, amortization and accretion	90,882			81,335			57,818
Interest expense	18,197			17,686			13,379
Debt issuance costs paid	5,328			2,244			7,034
Unrealized (gain) loss on derivatives, net	(10,328		)	495			(641		)
Non-cash equity compensation expense	5,658			5,172			3,415
Corporate office relocation	9,096			—			—
Transaction expenses (1)	14,084			3,303			5,560
Income tax expense	2,580			1,885			856
Loss on impairment of property, plant and equipment	697			—			21,344
Loss on impairment of noncurrent assets held for sale	—			—			673
Loss on impairment of goodwill	2,654			148,488			—
Loss on extinguishment of debt	—			—			1,634
Distributions from unconsolidated affiliates	83,046			20,568			1,980
General Partner contribution for cost reimbursement	7,500			3,000			—
Deduct:
Earnings in unconsolidated affiliates	40,158			8,201			348
Construction and operating management agreement income	1,465			841			943
Other post-employment benefits plan net periodic benefit	17			14			45
Loss on sale of assets, net	(688		)	(2,860		)	(4,087		)
Adjusted EBITDA	$	137,132		$	78,152		$	32,243

_______________________

(1) Transaction expenses for the year ended December 31, 2016 included JPE Merger costs of $7.2 million. The JPE Merger closed on March 8, 2017.

General Trends and Outlook

During 2017, our business objectives will continue to focus on maintaining stable cash flows from our existing assets and executing on growth opportunities to increase our long-term cash flows. We believe the key elements to stable cash flows are the diversity of our asset portfolio and our fee-based business which represents a significant portion of our expected gross margins.

We anticipate maintenance capital expenditures between $8.2 million and $10.2 million, and approved expenditures for expansion capital between $100.5 million and $110.5 million, for the year ending December 31, 2017. Forecasted growth capital expenditures include East Texas Processing consolidation, expansion of the Harvey terminal, continued build-out of the Bakken system, continued development of the Silver Dollar System and other organic growth projects.

We expect to continue to pursue a multi-faceted growth strategy, which includes maximizing drop down opportunities provided by our relationship with ArcLight, capitalizing on organic expansion and pursuing strategic third-party acquisitions in order to grow our cash flows. We expect commodity prices in 2017 to continue within the same range as 2016 and as a result we expect producer and supplier activities to be impacted, which may increase the growth rate of our Gas Gathering and Processing Services and Natural Gas Transportation Services segments.

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EXHIBIT 99.2

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

Gas Gathering and Processing Services Segment. Except for our fee-based contracts, which may be impacted by throughput volumes, the profitability of our Gas Gathering and Processing Services segment is dependent upon commodity prices, natural gas supply, and demand for natural gas, NGLs and condensate.

Liquid Pipelines and Services Segment. Profitability of our Liquid Pipelines and Services segment is dependent upon the price of crude oil. Throughput volumes could decline should crude oil prices remain low resulting in decreased production in our areas of operation.

Natural Gas Transportation Services and Offshore Pipelines and Services Segments. Profitability of our Natural Gas Transportation Services and Offshore Pipelines and Services segments are dependent upon the demand to transport natural gas pursuant under our firm and interruptible transportation contracts. Throughput volumes could decline should natural gas prices and drilling levels decline.

Terminalling Services Segment. Profitability of our Terminalling Services segment is dependent upon the demand from our customers to store their products, which is generally not tied to the crude oil and natural gas commodity markets. Currently, we have not experienced deterioration of terminal gross margin in connection with the volatility of the natural gas, crude oil, NGL or condensate markets. Further, the terms of our firm storage contracts are multiple years, with renewal options.

Average daily prices for NYMEX West Texas Intermediate crude oil ranged from a high of $54.45 per barrel to a low of $26.21 per barrel from January 1, 2016 through July 7, 2017. Average daily prices for NYMEX Henry Hub natural gas ranged from a high of $3.80 per MMBtu to a low of $1.49 per MMBtu from January 1, 2016 through July 7, 2017. We are unable to predict future potential movements in the market price for natural gas, crude oil and NGLs and thus, cannot predict the ultimate impact of prices on our operations. If commodity prices decline, this could lead to reduced profitability and may impact our liquidity, compliance with financial covenants in our revolving credit agreement, and our ability to maintain our current distribution levels. Our long-term view is that as economic conditions improve, commodity prices should reach levels that will support continued natural gas and crude oil production in the United States. Reduced profitability may result in future potential non-cash impairments of long-lived assets, goodwill, or intangible assets.

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. The amount of our cash distributions on our units principally depends upon the amount of cash we generate from our operations, which could be adversely impacted by market conditions and factors outside of our control. The Partnership Agreement allows us to reduce or eliminate quarterly distributions, if required to maintain ongoing operations.

Capital Markets. Volatility in the capital markets may impact our operations in multiple ways, including limiting our producers' ability to finance their drilling and workover programs and limiting our ability to fund drop downs, organic growth projects and acquisitions.

Impact of Inflation on Direct Operating Expenses. Inflation has been relatively low in the United States in recent years. However, the inflation rates impacting our operations fluctuate throughout the broad economic and energy business cycles. Consequently, our costs for chemicals, utilities, materials and supplies, labor and major equipment purchases may increase during periods of general business inflation or periods of relatively high-energy commodity prices.

Results of Operations

Net loss attributable to the Partnership decreased by $148.5 million for the year ended December 31, 2016 as compared to 2015 primarily due to the loss on impairment of goodwill of $148.5 million recognized in 2015 and an increase in earnings from unconsolidated affiliates of $32.0 million from our investments in Delta House and the entities underlying the Emerald Transactions, offset by an increase in corporate expense of $21.6 million due to corporate relocation and JPE Merger expenses.

Total segment gross margin increased by $43.7 million, or 25.1%, for the year ended to December 31, 2016 to $219.6 million as compared to the same period in 2015. The increase in total segment gross margin was primarily due to an increase in our Offshore Pipelines and Services segment gross margin of $48.7 million as a result of increased revenues received by the Partnership due

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EXHIBIT 99.2

to the Pascagoula plant shutdown. The Pascagoula plant is not controlled or owned by the Partnership, and the shutdown required volumes to be directed to our High Point system.

For the year ended December 31, 2016, Adjusted EBITDA increased by $59.0 million, or 75.5% compared to 2015. The increase is primarily related to higher distributions from our unconsolidated affiliates of $62.5 million largely due to our investments in Delta House and the entities underlying the Emerald Transactions.

We distributed $112.1 million and $100.4 million to holders of our common units during the year ended December 31, 2016 and 2015, respectively.

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EXHIBIT 99.2

The following table and discussion presents certain of our historical consolidated financial data for the periods indicated.

The results of operations by segment are discussed in further detail following this combined overview (in thousands):

	For the Years Ended December 31,
	2016			2015			2014
Statements of Operations Data:
Revenues:
Commodity sales	$	439,412		$	613,241		$	721,663
Services	151,231			135,718			116,195
Gains (losses) on commodity derivatives, net	(1,617		)	1,345			1,091
Total revenue	589,026			750,304			838,949
Operating expenses:
Cost of sales	393,351			567,682			672,948
Direct operating expenses	71,544			71,729			58,048
Corporate expenses	89,438			65,327			60,465
Depreciation, amortization and accretion	90,882			81,335			57,818
Loss on sale of assets, net	688			2,860			4,087
Loss on impairment of property, plant and equipment	697			—			21,344
Loss on impairment of goodwill	2,654			148,488			—
Total operating expenses	649,254			937,421			874,710
Operating loss	(60,228		)	(187,117		)	(35,761		)
Other income (expenses):
Interest expense	(21,433		)	(20,077		)	(16,497		)
Loss on extinguishment of debt	—			—			(1,634		)
Other expense	254			1,460			(1,096		)
Earnings in unconsolidated affiliates	40,158			8,201			348
Income (loss) from continuing operations before income taxes	(41,249		)	(197,533		)	(54,640		)
Income tax expense	(2,580		)	(1,885		)	(856		)
Loss from continuing operations	(43,829		)	(199,418		)	(55,496		)
Loss from discontinued operations	(4,715		)	(423		)	(24,071		)
Net income (loss)	(48,544		)	(199,841		)	(79,567		)
Net income (loss) attributable to noncontrolling interests	2,766			(13		)	3,993
Net income (loss) attributable to the Partnership	$	(51,310	)	$	(199,828	)	$	(83,560	)
Other Financial Data (1):
Total segment gross margin	223,635			179,856			153,524
Adjusted EBITDA	$	137,132		$	78,152		$	32,243

_______________________

(1) For definitions of Total segment gross margin and Adjusted EBITDA and reconciliations to their most directly comparable financial measure calculated and presented in accordance with GAAP, and a discussion of how we use Total segment gross margin and Adjusted EBITDA to evaluate our operating performance, please read the information in this Item under the caption “How We Evaluate Our Operations.”

Year ended December 31, 2016, compared to year ended December 31, 2015

Commodity Sales. Commodity sales revenue for the year ended December 31, 2016 were $439.4 million compared to $613.2 million for the year ended December 31, 2015. This decrease of $173.8 million was primarily due to the following:

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EXHIBIT 99.2

• a decrease in crude oil sales revenue of $152.9 million due to a decrease in sales volumes of 15,830 (bbls/day) from an overall reduction in our customer crude oil production volumes in our areas of operation;

• a decrease in natural gas revenue of $10.7 million primarily due to lower realized natural gas prices of $2.51/Mcf, which is a decrease of $0.40/Mcf or 13.7% period over period;

• a decrease in condensate revenues of $6.7 million due to lower realized condensate prices of $0.11/gal or 11.3% period over period;

• a decrease in NGL revenues of $6.3 million due to lower gross NGL production volumes of 38.2 Mgal/d from our Gas Gathering and Processing Services segment and lower realized NGL prices of $0.57/gal, which is a decrease of $0.01/gal period over period; and

• these decreases were partially offset by an increase in crude oil gathering fee-based revenues of $4.7 million.

Service Revenue. Our service revenue for the year ended December 31, 2016 was $151.2 million compared to $135.7 million for the year ended December 31, 2015. This increase of $15.5 million was primarily due to the following:

• an increase in firm and interruptible transportation of $8.5 million primarily as a result of the Pascagoula plant shutdown and additional revenue associated with our Gulf of Mexico Pipeline which we acquired in April 2016. The Pascagoula plant is not controlled or owned by the Partnership, and the shutdown required volumes to be redirected to our High Point system; and

• an increase in Terminalling Services segment revenue of $9.8 million as a result of incremental storage utilization and ancillary increases.

Cost of sales. Cost of sales for the year ended December 31, 2016, were $393.4 million compared to $567.7 million in the year ended December 31, 2015. This decrease of $174.3 million was due to lower natural gas purchases of $10.4 million. There was also a decrease in crude oil purchases of $162.8 million which was driven by the 2016 reduction in crude sales volumes and overall reduction in crude prices. The NGL purchases decrease was primarily due to the reduction in NGL sales volumes. NGL sales volumes decreased 30,000/gallons per day in 2016 compared to 2015 due to a decline in volumes associated with oilfield services as a result of lower exploration and production activity and overall warmer than normal temperatures.

Total Segment Gross Margin. Total segment gross margin for the year ended December 31, 2016, was $223.6 million compared to $179.9 million for the year ended December 31, 2015. This increase of $43.7 million was primarily due to our increased Offshore Pipelines and Services segment gross margin of $8.5 million as a result of increased revenues received by the Partnership due to the Pascagoula plant shutdown. The Pascagoula plant is not controlled or owned by the Partnership, and the shutdown required volumes to be directed to our High Point system. Additionally, the incremental earnings from our equity method investees increased by $32.0 million, of which $29.9 million was attributable to our Offshore Pipelines and Services segment.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2016, were $71.5 million compared to $71.7 million for the year ended December 31, 2015. This decrease of $0.2 million was primarily due to a decrease of contract services and labor costs.

Corporate Expenses. Corporate expenses for the year ended December 31, 2016, were $89.4 million compared to $65.3 million for the year ended December 31, 2015. This increase of $24.1 million was primarily due to corporate relocation expenses of $9.1 million, JPE Merger expenses of $7.2 million, and increases in salaries, wages and benefits of $2.6 million due to increased employee expenses as we transitioned our corporate headquarters from Denver to Houston, information and technology maintenance costs of $1.1 million primarily related to systems and licenses that were implemented in the prior year, contract services of $1.0 million, and legal and regulatory compliance fees of $0.7 million in support of corporate activities.

Depreciation, Amortization and Accretion. Depreciation, amortization and accretion for the year ended December 31, 2016, was $90.9 million compared to $81.3 million for the year ended December 31, 2015. This increase of $9.6 million was primarily due to incremental depreciation of fixed assets related to our Gulf of Mexico Pipeline acquisition in April 2016, our Mesquite joint venture which began operations in April 2016, and our Bakken system which began operations in October 2015.

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EXHIBIT 99.2

Loss on Impairment of Goodwill. Goodwill impairment expense for the year ended December 31, 2015 was $148.5 million compared to $2.7 million for the year ended December 31, 2016. The 2015 impairment charges were comprised of $95.0 million and $23.6 million related to the Costar and Lavaca acquisitions, respectively, and $29.9 million in our Liquid Pipelines and Services reportable segment relating to our Crude Oil Supply and Logistics business. In 2016, we recognized goodwill impairment charges totaling $2.7 million related to our JP Liquids business. Given the market condition trend surrounding JP Liquids, we may recognize further impairments related to those assets in the future. Additionally, we recorded a goodwill impairment charge of $12.8 million during the year ended December 31, 2016 related to our Pinnacle Propane Express business which is classified in net loss from discontinued operations in the consolidated statement of operations.

Interest Expense. Interest expense for the year ended December 31, 2016, was $21.4 million compared to $20.1 million for the year ended December 31, 2015. This increase of $1.3 million was primarily due to higher outstanding borrowings under our revolving credit agreements, and an increase in our weighted average interest rate, offset by $10.4 million of unrealized gains on our interest rate swaps.

Earnings in Unconsolidated Affiliates.Earnings in unconsolidated affiliates for the year ended December 31, 2016 were $40.2 million compared to $8.2 million for the year ended December 31, 2015. This increase of $32.0 million was primarily due to incremental earnings of $22.8 million related to our investment in Delta House and $9.7 million related to the interests in the entities underlying the Emerald Transactions which were acquired in April 2016.

Discontinued Operations. Loss from discontinued operations for the year ended December 31, 2016 was $4.7 million compared to $0.4 million for the year ended December 31, 2015. The increase in loss from discontinued operations of $4.3 million was primarily due to a decrease in gross margin of $1.9 million and $3.1 million associated with our Propane Business and Mid-Continent Business, respectively. The decrease in our Propane Business was primarily attributable to a reduction in NGL and refined product sales driven by a decline in volumes associated with oilfield services and overall warmer than normal temperatures sustained in the year ended December 31, 2016. The decrease in our Mid-Continent Business was primarily due to a decrease in crude oil sales volumes which was driven by a decline in oilfield services. Additionally, unrealized gains associated with the Propane commodity swaps decreased $10.7 million to $1.1 million as of December 31, 2016 from $11.8 million as of December 31, 2015, and loss on sale of assets related to the Propane Business increased $1.1 million for the year ended December 31, 2016. These increases in loss from discontinued operations are partially offset by a decrease of $12 million related to direct operating expenses, corporate expenses, and depreciation and amortization.

Year ended December 31, 2015, compared to year ended December 31, 2014

Commodity Sales. Commodity sales for the year ended December 31, 2015 was $613.2 million compared to $721.7 million for the year ended December 31, 2014. This decrease of $108.5 million was primarily due to the following:

• a decrease of $47.0 million due to converting fixed-margin contracts in our Natural Gas Transportation Services segment to firm or interruptible transportation contracts;

• a decrease of $46.7 due to the following:

◦ lower realized natural gas prices of $2.91/Mcf, which is a decrease of $2.01/Mcf, or 40.9%, period over period,

◦ lower realized NGL prices of $0.58 gal, which is a decrease of $0.33/gal., or 36.3%, period over period, offset by higher gross NGL production volumes of 166.9 Mgal/d, or 260%, period over period, and

◦ lower realized condensate prices of $0.97/gal, which is a decrease of $0.65/gal, or 40.1%, period over period, offset by higher gross condensate production volumes of 24.6 Mgal/d, or 32.7%, period over period; and

• a $12.9 million decrease due to a 48% reduction in crude prices from a 2014 WTI average of $93.26/bbl to a 2015 average of $0.46/gal.

Services Revenue. Our service revenue for the year ended December 31, 2015 was $135.7 million compared to $116.2 million for the year ended December 31, 2014. This increase of $19.5 million was primarily due an increase in the Terminalling Services segment revenue of $2.3 million as a result of increased storage utilization from acquiring new customers and contractual storage rate escalations.

Cost of Sales. Cost of sales for the year ended December 31, 2015 were $567.7 million compared to $672.9 million in the year ended December 31, 2014. This decrease of $105.3 million was due to lower natural gas purchases of $94.3 million primarily as a result of lower natural gas prices and lower natural gas volumes related to our elective processing arrangements in our Gas Gathering and Processing segment, as well as the conversion of certain fixed-margin contracts to interruptible transportation contracts in our Natural Gas Transportation Services segment as mentioned above. Crude purchases decreased by $14.0 million due to a 48% reduction in crude prices from a 2014 WTI average of $93.26/bbl to a 2015 average of $0.46/gal. The price decline

15

EXHIBIT 99.2

is slightly offset by increases in crude sales (24,643 bbls/day) and throughput volumes (7,378 bbls/day) due to expansions on our Silver Dollar Pipeline.

This decrease was partially offset by incremental NGL, crude oil and condensate purchases of $2.2 million primarily associated with the gathering and processing systems acquired in the Costar Acquisition.

Total Segment Gross Margin. Total segment gross margin for the year ended December 31, 2015 was $179.9 million compared to $153.5 million for the year ended December 31, 2014. This increase of $26.4 million was primarily due to an increase in our Gas Gathering and Processing Services segment gross margin of $14.5 million as a result of higher NGL and condensate production of 166.9 Mgal/d and 24.6 Mgal/d, respectively, and higher throughput volumes of 63.4 MMcf/d.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2015 were $71.7 million compared to $58.0 million in the year ended December 31, 2014. This increase of $13.7 million was primarily due to $13.4 million of incremental operating costs, including costs related to direct labor and benefits, associated with the gathering and processing systems acquired from Costar in October 2014, and an increase of $2.1 million in operating costs associated with compression rentals used at our Lavaca System.

Corporate Expenses. Corporate expenses for the year ended December 31, 2015 were $65.3 million compared to $60.5 million for the year ended December 31, 2014. This increase of $4.9 million was primarily due to personnel costs incurred to manage and integrate our recent acquisitions and support continuing growth.

Depreciation, Amortization and Accretion. Depreciation, amortization and accretion for the year ended December 31, 2015 was $81.3 million compared to $57.8 million for the year ended December 31, 2014. This increase of $23.5 million was primarily due to incremental depreciation of fixed assets and amortization of certain intangible assets associated with the Costar Acquisition and the continuing capital expansion of the Lavaca System.

Loss on Impairment of Property, Plant and Equipment. 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 has led to a corresponding decrease in crude oil and natural gas production and is impacting the volume of natural and NGLs we gather and process on certain assets. As a result, asset impairment charges of $21.3 million related to certain gathering and processing assets were recorded during the fourth quarter of 2014.

Loss on Impairment of Goodwill. During the fourth quarter of 2015, management performed the Partnership's annual goodwill impairment test. As a result of the continuing decline in commodity prices, as well as the decline in the market price for the Partnership's common units during the fourth quarter, key assumptions relating to expected producer volumes and commodity prices used in management's impairment testing cash flow models were updated. The updated assumptions resulted in the estimated fair value of the Costar and Lavaca reporting units being less than their respective carrying values, indicating that the related goodwill was impaired. After completing an allocation of the estimated fair value of each reporting unit to the associated assets and liabilities, management determined that the goodwill of the Costar and Lavaca reporting units had a nominal fair value and that impairment charges of $118.6 million were required. We also recorded a goodwill impairment charge of $29.9 million during the year ended December 31, 2015 related to the JP Energy Crude Oil Supply and Logistics and JP Liquids reporting units.

Interest Expense. Interest expense for the year ended December 31, 2015, was $20.1 million compared to $16.5 million for the year ended December 31, 2014. This increase of $3.6 million was primarily due to higher outstanding borrowings under our revolving credit agreements primarily to fund our capital growth projects and the Costar acquisition and Delta House investment.

Earnings in Unconsolidated Affiliates.Earnings in unconsolidated affiliates for the year ended December 31, 2015 were $8.2 million compared to $0.3 million for the year ended December 31, 2015. This increase of $7.9 million was due to incremental earnings of $7.5 million related to Delta House, and higher earnings from MPOG of $0.4 million.

Discontinued Operations. Loss from discontinued operations for the year ended December 31, 2015 was $0.4 million compared to $24.1 million for the year ended December 31, 2015. The decrease in loss from discontinued operations of $23.6 million was primarily due to an increase in gross margin of $9.5 million associated with our Propane Business, primarily driven by more favorable propane hedge positions, offset by a decrease of $3.2 million in gross margin of the Mid-Continent Business which was driven by lower crude oil prices per barrel. Additionally, unrealized gains associated with our Propane commodity swaps increased $24.5 million to a $11.8 million unrealized gain as of December 31, 2015 from an unrealized loss position of $12.7 million as of December 31, 2014. We also had an incremental decrease of $9.6 million in loss from discontinued operations related to the sale of the Bakken Business in June 2014. These changes were partially offset by goodwill impairments of $12.9 million associated

16

EXHIBIT 99.2

with our Mid-Continent Business for the year ended December 31, 2015, and an increase of $6.5 million related to direct operating expenses, corporate expenses, depreciation and amortization.

17

EXHIBIT 99.2

Results of Operations — Segment Results

Gas Gathering and Processing Services Segment

The table below contains key segment performance indicators related to our Gas Gathering and Processing Services segment (in thousands except operating and pricing data).

	For the Years Ended December 31,
	2016			2015		2014
Segment Financial and Operating Data:
Gas Gathering and Processing Services Segment
Financial data:
Commodity Sales	$	91,444		$	107,680	$	148,198
Services	22,558			30,196		15,248
Revenue from operations	114,002			137,876		163,446
Gain (loss) on commodity derivatives, net	(833		)	1,240		1,050
Segment revenue	$	113,169		$	139,116	$	164,496
Cost of sales	63,832			72,960		112,719
Direct operating expenses	33,802			35,250		21,197
Other financial data:
Segment gross margin	$	48,245		$	65,692	$	51,213
Operating data:
Average throughput (MMcf/d)	220.6			240.0		155.8
Average plant inlet volume (MMcf/d) (1)	102.1			120.9		89.1
Average gross NGL production (Mgal/d) (1)	192.9			231.1		64.2
Average gross condensate production (Mgal/d) (1)	82.9			97.1		70.8
Average realized prices:
Natural gas ($/Mcf)	$	2.06		$	2.68	$	4.57
NGLs ($/gal)	$	0.57		$	0.58	$	0.91
Condensate ($/gal)	$	0.87		$	0.98	$	1.60

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

Year Ended December 31, 2016, Compared to Year Ended December 31, 2015

Commodity Sales. Commodity sales for the year ended December 31, 2016 were $91.4 million compared to $107.7 million for the year ended December 31, 2015. This decrease of $16.3 million was primarily due to the following:

• lower realized natural gas, NGL, and condensate prices of 23.2%, 1.9%, and 10.9%, respectively; and

• lower average NGL and condensate production of 38.2 Mgal/d and 14.1 Mgal/d, respectively, primarily due to a decrease in volumes at our Longview system.

Services Revenue. Services revenue for the year ended December 31, 2016 were $22.6 million compared to $30.2 million for the year ended December 31, 2015. This decrease of $7.6 million was primarily due to lower average throughput and plant inlet volumes of 19.4 MMcf/d and 18.8 MMcf/d, respectively.

Cost of Sales. Cost of sales for the year ended December 31, 2016 were $63.8 million compared to $73.0 million for the year ended December 31, 2015. This decrease of $9.2 million was primarily due to lower realized commodity prices as well as lower NGL and condensate purchased volumes at our Longview system.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2016 was $48.2 million compared to $65.7 million for the year ended December 31, 2015. This decrease of $17.5 million was primarily due to lower production on our Longview and Lavaca systems.

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EXHIBIT 99.2

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2016 were $33.8 million compared to $35.3 million for the year ended December 31, 2015. This decrease of $1.5 million was primarily due to lower compressor rentals due to ongoing cost cutting efforts.

Year Ended December 31, 2015, Compared to Year Ended December 31, 2014

Commodity Sales. Commodity sales for the year ended December 31, 2015 were $107.7 million compared to $148.2 million for the year ended December 31, 2014. This decrease of $40.5 million was primarily due to the following:

• lower realized natural gas, NGL, and condensate prices of 41.4%, 36.6%, and 39%, respectively; and

• these decreases were partially offset by an increase in NGL and condensate production of 166.9 Mgal/d and 26.2 Mgal/d, respectively.

Services Revenue. Services revenue for the year ended December 31, 2015 were $30.2 million compared to $15.2 million for the year ended December 31, 2014. This increase of $15.0 million was primarily due to higher throughput volumes of 84.2 MMcf/d related to the Costar and Lavaca acquisitions which occurred in 2014.

Cost of Sales. Cost of sales for the year ended December 31, 2015 were $73.0 million compared to $112.7 million for the year ended December 31, 2014. This decrease of $39.7 million was primarily due to lower purchase costs associated with natural gas and NGLs due to lower realized natural gas and NGL prices and lower natural gas volumes associated with our elective processing arrangements. These decreases were partially offset by incremental purchases associated with off-spec NGL and condensate throughput volumes related to the Longview system.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2015 was $65.7 million compared to $51.2 million for the year ended December 31, 2014. This increase of $14.5 million was primarily due to incremental gross margin of $24.0 million on our Longview, Chapel Hill, Danville, and Yellow Rose systems and higher gross margin of $4.8 million at our Lavaca system. These increases were partially offset by lower NGL and condensate production associated with our elective processing arrangements.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2015 were $35.3 million compared to $21.2 million for the year ended December 31, 2014. This increase of $14.1 million was primarily due to incremental operating costs associated with the gathering and processing systems acquired in the Costar and Lavaca acquisitions, partially offset by the timing of activities related to our integrity management and plant repair and maintenance programs.

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EXHIBIT 99.2

Liquid Pipelines and Services Segment

The table below contains key segment performance indicators related to our Liquid Pipelines and Services segment (in thousands except operating data).

	For the Years Ended December 31,
	2016			2015		2014
Segment Financial and Operating Data:
Liquid Pipelines & Services
Financial data:
Commodity sales	$	304,502		$	457,448	$	470,936
Services	19,063			23,008		22,239
Revenue from operations	323,565			480,456		493,175
Gains (losses) on commodity derivatives (net)	(341		)	—		—
Earnings in unconsolidated affiliates	2,070			—		—
Segment revenue	$	325,294		$	480,456	$	493,175
Cost of sales	293,618			454,057		468,137
Direct operating expense	10,091			9,912		7,209
Other financial data:
Segment gross margin	$	31,556		$	26,399	$	25,038
Operating data:
Average throughput Pipeline (Bbls/d)	32,257			34,946		20,868
Average throughput Trucking (Bbls/d)	1,628			—		—

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.

Commodity Sales. Commodity sales for the year ended December 31, 2016 were $304.5 million compared to $457.4 million for the year ended December 31, 2015. This decrease of $152.9 million was primarily due to a decrease in crude oil sales volumes to 24,425 barrels per day for the year ended December 31, 2016 from 40,255 barrels per day for the year ended December 31, 2015. These decreases are primarily due to an overall reduction in our customer crude oil production volumes in our areas of operation.

Services Revenue. Services revenue for the year ended December 31, 2016 were $19.1 million compared to $23.0 million for the year ended December 31, 2015. This decrease of $3.9 million was primarily due to a reduction in NGL revenue from lower NGL trucking volumes driven by a decline in volumes associated with oilfield services and overall warmer than normal temperatures sustained in the year ended December 31, 2016. There was also a decrease in crude oil throughput volumes to 32,257 barrels per day for the year ended December 31, 2016 from 34,946 barrels per day for the year ended December 31, 2015. These decreases are due to an overall reduction in our customer crude oil production volumes in our area of operation. However, producer activity around our Silver Dollar Pipeline has recently increased, resulting in average pipeline throughput volumes of approximately 31,000 barrels per day in the quarter ended December 31, 2016.

Cost of Sales. Cost of sales for the year ended December 31, 2016 were $293.6 million compared to $454.1 million for the year ended December 31, 2015. This decrease of $160.5 million was primarily due to a decrease in crude oil sales volumes resulting from an overall reduction in our customer crude oil production volumes, as described above.

Earnings in Unconsolidated Affiliates. Earning in unconsolidated affiliates for the year ended December 31, 2016 increased $2.1 million. This change was driven by the Emerald transaction that occurred on April 2016 adding interests in the Wilprise and Tri-States entities that own and operate pipeline systems.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2016 was $31.6 million compared to $26.4 million for the year ended December 31, 2015. This increase of $5.2 million was primarily due to an increase in crude oil sales margin of $10.0 million due to the capturing of more favorable margins associated with previously stored inventory during contango market conditions as well as more favorable regional pricing spreads on bulk purchased crude oil. This increase is partially offset by a decrease in crude oil sales and throughput volumes of $6.9 million and $0.7 million, respectively.

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EXHIBIT 99.2

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2016 were $10.1 million compared to $9.9 million for the year ended December 31, 2015. This increase of $0.2 million was primarily due to the incremental expenses associated with our Bakken system, partially offset by reductions in personnel costs from lower headcount.

Year Ended December 31, 2015, Compared to Year Ended December 31, 2014.

Commodity Sales. Commodity sales for the year ended December 31, 2015 were $457.4 million compared to $470.9 million for the year ended December 31, 2014. This decrease of $13.5 million was primarily due to the impact of the current lower priced crude oil market per barrel and the lack of any market dislocation opportunities for the year ended December 31, 2015. This decrease is partially offset by a $4.7 million increase in crude oil sales volumes, as sales volumes increased to 40,255 barrels per day for the year ended December 31, 2015 from 15,612 barrels per day for the year ended December 31, 2014 due to the expansions of the Silver Dollar Pipeline System in the third quarter of 2014 throughout 2015.

Services Revenue. Services revenue for the year ended December 31, 2015 were $23 million compared to $22.2 million for the year ended December 31, 2014. This increase of $0.7 million was primarily due to the incremental revenue from our Bakken system which commenced operations in 2015.

Cost of Sales. Cost of sales for the year ended December 31, 2015 were $454.1 million compared to $468.1 million for the year ended December 31, 2014. This decrease of $14.0 million was primarily due to the impact of the current lower priced crude oil market per barrel, as described above.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2015 was $26.4 million compared to $25 million for the year ended December 31, 2014. This increase of $1.4 million was primarily due to an increase in production from the Bakken system which commenced operations in 2015.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2015 were $9.9 million compared to $7.2 million for the year ended December 31, 2014. This increase of $2.7 million was primarily due to increases in insurance premiums of $0.8 million, property tax expenses of $0.2 million, and repairs and maintenance expenses of $0.2 million in 2015.

Natural Gas Transportation Services Segment

The table below contains key segment performance indicators related to our Natural Gas Transportation Services segment (in thousands except operating and pricing data).

	For the Years Ended December 31,
	2016		2015		2014
Segment Financial and Operating Data:
Natural Gas Transportation Services
Financial data:
Commodity Sales	$	21,999	$	23,972	$	70,964
Services	18,109		16,035		12,925
Segment revenue	$	40,108	$	40,007	$	83,889
Cost of sales	21,288		21,858		70,100
Direct operating expenses	5,923		6,728		6,975
Other financial data:
Segment gross margin	$	18,616	$	18,073	$	13,691
Operating data:
Average throughput (MMcf/d)	389.9		364.1		373.3
Average firm transportation - capacity reservation (MMcf/d)	634.7		637.2		567.9
Average interruptible transportation - throughput (MMcf/d)	65.3		70.2		65.3
Average realized prices:
Natural gas ($/Mcf)	$2.57		$2.86		$4.60

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EXHIBIT 99.2

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.

Commodity Sales. Commodity sales for the year ended December 31, 2016 were $22.0 million compared to $24.0 million for the year ended December 31, 2015. This decrease of $2.0 million was primarily due to lower realized natural gas prices of 10.1%.

Services Revenue. Services revenue for the year ended December 31, 2016 were $18.1 million compared to $16.0 million for the year ended December 31, 2015. This increase of $2.1 million was primarily due to higher average throughput volumes of 26 MMcf/d from new firm transportation contracts associated with our MLGT pipeline.

Cost of Sales. Cost of sales for the year ended December 31, 2016 were $21.3 million compared to $21.9 million for the year ended December 31, 2015. This decrease of $0.6 million was primarily due to a decline in realized natural gas prices, as described above.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2016 was $18.6 million compared to $18.1 million for the year ended December 31, 2015. This increase of $0.5 million was primarily due to higher average throughput volumes offset by lower realized natural gas prices.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2016 were $5.9 million compared to $6.7 million for the year ended December 31, 2015. This decrease of $0.8 million was primarily due to lower employee costs.

Year Ended December 31, 2015, Compared to Year Ended December 31, 2014.

Commodity Sales. Commodity sales for the year ended December 31, 2015 were $24.0 million compared to $71.0 million for the year ended December 31, 2014. This decrease of $47.0 million was primarily due to converting certain fixed-margin arrangements to interruptible and firm transportation agreements during the first quarter of 2015, which substantially reduced the sales of natural gas throughput volumes and also the need for us to purchase such volumes.

Services Revenue. Services revenue for the year ended December 31, 2015 were $16.0 million compared to $12.9 million for the year ended December 31, 2014. This increase of $3.1 million was primarily due to an increase in firm transportation capacity commitments of 69 MMcf/d.

Cost of Sales. Cost of sales for the year ended December 31, 2015 were $21.9 million compared to $70.1 million for the year ended December 31, 2014. This decrease of $48.2 million was primarily due to converting certain fixed-margin arrangements to interruptible and firm transportation agreements during the first quarter of 2015, and therefore substantially reducing our need to purchase natural gas.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2015 was $18.1 million compared to $13.7 million for the year ended December 31, 2014. This increase of $4.4 million was primarily due to an increase in firm transportation capacity and the incremental increase resulting from converting fixed-margin arrangements to interruptible and firm transportation agreements, as described above.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2015 were $6.7 million compared to $7.0 million for the year ended December 31, 2014. This decrease of $0.3 million was primarily due to an ongoing cost cutting effort to reduce operating expenses.

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EXHIBIT 99.2

Offshore Pipelines and Services Segment

The table below contains key segment performance indicators related to our Offshore Pipelines and Services segment (in thousands except operating data).

	For the Years Ended December 31,
	2016			2015		2014
Segment Financial and Operating Data:
Offshore Pipelines & Services
Financial data:
Commodity sales	$	6,812		$	13,798	$	20,044
Services	40,502			21,457		24,426
Revenue from operations	47,314			35,255		44,470
Gains (losses) on commodity derivatives, net	(7		)	84		41
Earnings in unconsolidated affiliates	38,088			8,201		348
Segment revenue	$	85,395		$	43,540	$	44,859
Cost of sales	3,049			9,914		15,133
Direct operating expense	10,945			9,425		11,142
Other financial data:
Segment gross margin	$	82,346		$	33,613	$	29,089
Operating data:
Average throughput (MMcf/d)	466.4			442.8		524.6
Gross condensate production (Mgal/d)	3.6			2.7		4.4
Average firm transportation - capacity reservation (MMcf/d)	53.4			16.6		10.0
Average interruptible transportation - throughput (MMcf/d)	288.7			340.1		403.7
Average realized prices:
Natural gas ($/Mcf)	$	2.63		$	2.97	$	5.09
NGLs ($/gal)	$	—		$	0.42	$	0.88
Condensate ($/gal)	$	0.72		$	0.92	$	1.89

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.

Commodity Sales. Commodity sales for the year ended December 31, 2016 were $6.8 million compared to $13.8 million for the year ended December 31, 2015. This decrease of $7.0 million was primarily due to a reduction in the average realized prices for natural gas and condensate of 11.4% and 22.1%, respectively.

Services Revenue. Services revenue for the year ended December 31, 2016 were $40.5 million compared to $21.5 million for the year ended December 31, 2015. This increase of $19.0 million was primarily due to the Pascagoula plant shutdown which required volumes to be redirected to our High Point system, and increased fees associated with our acquisition of the Gulf of Mexico Pipeline. The Pascagoula plant is not controlled or owned by the Partnership.

Cost of Sales. Cost of sales for the year ended December 31, 2016 were $3.0 million compared to $9.9 million for the year ended December 31, 2015. This decrease of $6.9 million was primarily due to lower realized commodity prices, as described above.

Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the year ended December 31, 2016 were $38.1 million compared to $8.2 million for the year ended December 31, 2015. This increase of $29.9 was primarily due to the incremental investments in the Delta House entities in 2016, as well as the Emerald transaction that occurred in April 2016.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2016 was $82.3 million compared to $33.6 million for the year ended December 31, 2015. This increase of $48.7 million was primarily due to increased revenues for our Highpoint system of $7.1 million as a result of the shutdown of the Pascagoula plant, increased fees associated with our acquisition

23

EXHIBIT 99.2

of the Gulf of Mexico Pipeline of $12.5 million, incremental earnings of $22.8 million related to our investment in Delta House and $8.4 million associated with the offshore interests acquired in the Emerald transaction, partially offset by decrease in commodity realized prices.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2016 were $10.9 million compared to $9.4 million for the year ended December 31, 2015. This increase of $1.5 million was primarily due to the incremental expenses associated with our acquisition of the Gulf of Mexico Pipeline, partially offset by lower employee costs.

Year Ended December 31, 2015, Compared to Year Ended December 31, 2014.

Commodity Sales. Commodity sales for the year ended December 31, 2015 were $13.8 million compared to $20.0 million for the year ended December 31, 2014. This decrease of $6.2 million was primarily due to a reduction in the average realized prices for natural gas, NGLs, and condensate of 41.7%, 52.0%, and 51.3%, respectively.

Services Revenue. Service revenues for the year ended December 31, 2015 were $21.5 million compared to $24.4 million for the year ended December 31, 2014. This decrease of $2.9 million was primarily due to a decrease in average throughput and interruptible transportation throughput of 82 MMcf/d and 64 MMcf/d, respectively.

Cost of Sales. Cost of sales for the year ended December 31, 2015 were $9.9 million compared to $15.1 million for the year ended December 31, 2014. This decrease of $5.2 million was primarily due to lower realized commodity prices, as described above.

Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the year ended December 31, 2015 were $8.2 million compared to $0.3 million for the year ended December 31, 2014. This increase of $7.9 was primarily due to the Delta House investment that occurred in September 2015.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2015 was $33.6 million compared to $29.1 million for the year ended December 31, 2014. This increase of $4.5 million was primarily due to incremental earnings of $7.5 million associated with our investment in Delta House and higher earnings of $0.4 million from our investment in MPOG, partially offset by a decrease in average throughput volumes described above.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2015 were $9.4 million compared to $11.1 million for the year ended December 31, 2014. This decrease of $1.7 million was primarily due to an ongoing effort to reduce operating expenses.

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EXHIBIT 99.2

Terminalling Services Segment

The table below contains key segment performance indicators related to our Terminalling Services segment (in thousands except operating data).

	For the Years Ended December 31,
	2016			2015			2014
Segment Financial and Operating Data:
Terminalling Services
Financial data:
Commodity sales	$	14,655		$	10,343		$	11,521
Services	50,999			45,022			41,357
Revenue from operations	65,654			55,365			52,878
Gains (losses) on commodity derivatives, net	(436		)	21			—
Segment revenue	$	65,218		$	55,386		$	52,878
Cost of sales	11,564			8,893			6,859
Direct operating expense	10,783			10,414			11,525
Other financial data:
Segment gross margin	$	42,872		$	36,079		$	34,493
Operating data:
Contracted Capacity (Bbls)	5,011,133			4,487,542			4,247,058
Design Capacity (Bbls) (2)	5,173,717			4,688,950			4,363,817
Storage Utilization (1)	96.9		%	95.7		%	97.3		%
Terminalling and storage throughput (Bbls/d)	56,741			62,075			63,859

(1) Excludes storage utilization associated with our discontinued operations.

(2) Excludes 1.2M Bbls at our North Little Rock and Caddo Mills locations.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.

Commodity Sales. Commodity sales for the year ended December 31, 2016 were $14.7 million compared to $10.3 million for the year ended December 31, 2015. The increase of $4.4 million was attributable to an increase in refined products sales related to the addition of butane blending capabilities at our North Little Rock Terminal in the second quarter of 2015.

Services Revenue. Services revenue for the year ended December 31, 2016, were $51.0 million compared to $45.0 million for the year ended December 31, 2015. The increase of $6.0 million was primarily attributable to increases in contracted storage capacity due to the expansion efforts at our Harvey terminal of $5.1 million and $0.7 million from increased refined product storage due to additional blending and injection of additives.

Cost of Sales. Cost of sales for the year ended December 31, 2016 were $11.6 million compared to $8.9 million for the year ended December 31, 2015. The increase of $2.7 million was primarily due to an increase in butane blending sales volume.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2016 was $42.9 million compared to $36.1 million for the year ended December 31, 2015. The increase of $6.8 million was primarily attributable to an increase in storage revenue and to a lesser extent margins from refined product sales.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2016 were $10.8 million compared to $10.4 million for the year ended December 31, 2015. The increase of $0.4 million was related to liability classified unit-based compensation.

Year Ended December 31, 2015, Compared to Year Ended December 31, 2014.

Commodity Sales. Commodity sales for the year ended December 31, 2015 were $10.3 million compared to $11.5 million for the year ended December 31, 2014. The decrease of $1.2 million was attributable to a decrease in commodity prices of $4.1 million,

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EXHIBIT 99.2

partially offset by an increase in refined product sales volume of $3.0 million due to the addition of butane blending capabilities at our North Little Rock Terminal in the second quarter of 2015.

Services Revenue. Services revenue for the year ended December 31, 2015 were $45.0 million compared to $41.4 million for the year ended December 31, 2014. The increase of $3.6 million was primarily attributable to increases in contracted storage capacity due to the expansion efforts at the Harvey terminal.

Cost of Sales. Cost of sales for the year ended December 31, 2015 were $8.9 million compared to $6.9 million for the year ended December 31, 2014. The increase of $2.0 million was primarily due to an increase in refined products sales volume.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2015 was $36.1 million compared to $34.5 million for the year ended December 31, 2014. The increase of $1.6 million was primarily attributable to an increase in storage revenue while managing direct labor costs associated with providing ancillary services.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2015 were $10.4 million compared to $11.5 million for the year ended December 31, 2014. The decrease of $1.1 million is primarily attributable to managing direct labor associated with providing ancillary services.

Liquidity and Capital Resources

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

Our principal sources of liquidity include cash from operating activities, borrowings under our revolving credit agreements, issuance of equity in the capital markets or through private transactions, and financial support from ArcLight, who controls our General Partner. In addition, we may continue to seek to raise capital through the issuance of secured and unsecured senior notes. Given our historical success in accessing various sources of liquidity, we believe that the sources of liquidity described above will be sufficient to meet our short-term working capital requirements, medium-term maintenance capital expenditure requirements, and quarterly cash distributions for at least the next twelve months. In the event these sources are not sufficient, we would pursue other sources of cash funding, including, but not limited to, additional forms of debt or equity financing.  In addition, we would reduce non-essential capital expenditures, controllable direct operating expenses and corporate expenses, as necessary. Our Partnership Agreement also allows us to reduce or eliminate quarterly distributions, if required to maintain ongoing operations.

Our liquidity for the year ended December 31, 2016 was impacted by the following:

• The issuance in April 2016 of 8,571,429 Series C Units along with warrants to purchase up to 800,000 common units at an exercise price of $7.25 per common unit with a combined issuance date fair value of approximately $120.0 million, proceeds of which were used to partially fund the purchase our membership interests in the entities underlying the Emerald Transactions.

• The issuance in October of 2,333,333 Series D Units with a value of $34.5 million, the proceeds of which were used to partially fund the purchase of additional Delta House Class A Units. We also agreed to grant the Series D unitholders a warrant to purchase up to 700,000 common units at an exercise price of $22.00 per common unit if the Series D Units are still outstanding at June 30, 2017.

• Revolving credit agreements borrowings of $425.1 million and repayments of $224.0 million.

• Issuance of the 3.77% Senior Notes resulting in net proceeds of approximately $57.7 million.

• Issuance of 8.50% Senior Notes resulting in net proceeds of approximately $291.3 million.

Changes in natural gas, crude oil, NGL and condensate prices and the terms of our customer contracts have a direct impact on our generation and use of cash from operations due to their impact on net income (loss), along with the resulting changes in working capital. During 2016, we mitigated a portion of our anticipated commodity price risk associated with the volumes from our gathering and processing activities with fixed price commodity swaps. For additional information regarding our derivative activities, please read Item 7A, "Quantitative and Qualitative Disclosures about Market Risk" included in the 2016 Form 10-K.

The counterparties to our commodity swap contracts are investment-grade rated financial institutions. Under these contracts, we may be required to provide collateral to the counterparties in the event that our potential payment exposure exceeds a predetermined collateral threshold. Collateral thresholds are set by us and each counterparty, as applicable, in the master contract that governs

26

EXHIBIT 99.2

our financial transactions based on our respective assessments of creditworthiness. The assessment of our position with respect to the collateral thresholds is determined on a counterparty by counterparty basis, and is impacted by the representative forward price curves and notional quantities under our swap contracts. Due to the interrelation between the representative natural gas and crude oil forward price curves, it is not practical to determine a single pricing point at which our swap contracts will meet the collateral thresholds as we may transact multiple commodities with the same counterparty. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis. As of December 31, 2016, we are not required to post collateral with our counterparties.

At-The-Market (“ATM”) Offering

On October 18, 2015, we filed a prospectus supplement related to the offer and sale from time to time of up to $100.0 million of our common units through an at-the-market offering program. For the year ended December 31, 2016, we sold 248,561 common units resulting in net proceeds of $2.9 million, after deducting offering costs of $0.3 million. The net proceeds were used to repay amounts outstanding under the Partnership Credit Agreement. As of December 31, 2016, approximately $96.8 million remained available for sale under the program.

AMID Credit Agreement

Effective as of April 25, 2016, the Partnership entered into the Second Amendment to the Amended and Restated Credit Agreement, which provided 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.

On September 30, 2016 and in connection with entering into the 3.77% Note Purchase Agreement, the Partnership entered into the Limited Waiver and Third Amendment to the Amended and Restated Credit Agreement, which among other things, (i) allowed Midla Holdings, 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 covenants thereunder, (ii) released the lien granted under the Credit Agreement related to D-Day’s equity interests in Delta FPS, LLC and (iii) deemed the equity interests in Delta House FPS, LLC to be excluded property under the Amended and Restated Credit Agreement.

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

Effective with the closing of the JPE Merger 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.

Our obligations under the Second Amended and Restated Credit Agreement are secured by a lien on substantially all of our assets. Advances made under the Second Amended and Restated 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 Second Amended and Restated Credit Agreement include covenants that restrict our ability to make cash distributions and acquisitions in some circumstances. The remaining principal balance of loans and any accrued and unpaid interest will be due and payable in full at maturity on September 5, 2019.

The Second Amended and Restated Credit Agreement contains certain financial covenants, including (i) a consolidated total leverage ratio that requires our consolidated total indebtedness not to exceed 5.00 times adjusted consolidated EBITDA (as defined in the Second Amended and Restated Credit Agreement) for the prior twelve month period, adjusted in accordance with the Second Amended and Restated Credit Agreement (except for the current and up to the subsequent two quarters after the consummation of a permitted acquisition, at which time the covenant may be increased to 5.50 times adjusted consolidated EBITDA), (ii) a minimum interest coverage ratio that requires our adjusted consolidated EBITDA to exceed consolidated interest charges by at least 2.50 times for the prior twelve month period, and (iii) a consolidated secured leverage ratio that requires our consolidated secured indebtedness not to exceed 3.50 times adjusted consolidated EBITDA for the prior twelve month period. The financial covenants in the Second Amended and Restated Credit Agreement may limit the amount available to us for borrowing to less than $900.0 million. We can elect to have loans under the Second Amended and Restated 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 then in effect, or a base

27

EXHIBIT 99.2

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 ranging between 0.375% to 0.50% per annum, depending on our total leverage ratio then in effect, on the undrawn portion of the revolving loan.

The Second Amended and Restated 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).

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, 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, we had approximately $711.3 million of borrowings and $7.4 million in letters of credit outstanding under the $750.0 million Amended and Restated Credit Agreement leaving $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 Second Amended and Restated 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.

JPE Credit Agreement

On February 12, 2014, JPE 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.

8.50% Senior Notes

On December 28, 2016, the Partnership and American Midstream Finance Corporation, our wholly owned subsidiary (together with the Partnership, the “Issuers”) completed the issuance and sale of the 8.50% Senior Notes. The 8.50% Senior Notes were issued at par and provided approximately $294.0 million in proceeds, after deducting 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 sheet 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.

Under the terms of the escrow agreement governing the disbursement of the net proceeds, upon the closing of the JPE Merger and the satisfaction of the other conditions contained therein, the restricted cash was released from escrow and was used to repay and terminate JPE Credit Facility and reduce borrowings under the Partnership’s Credit Agreement.

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

At any time prior to December 15, 2018, the Issuers may on one or more occasions 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:

28

EXHIBIT 99.2

• 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 to the applicable redemption date, 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%

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.

3.77% Senior Notes

On September 30, 2016, Midla Financing, Midla, and MLGT entered into the 3.77% Senior Note Purchase Agreement with the Purchasers. Pursuant to the 3.77% Senior Note Purchase Agreement, Midla Financing sold $60.0 million in aggregate principal amount of 3.77% Senior Notes. 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.

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 his 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.

29

EXHIBIT 99.2

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

Working Capital

Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received from our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors. Our working capital deficit was $16.4 million at December 31, 2016 compared to a surplus of $6.6 million at December 31, 2015 with the $23.0 million increase in the deficit due primarily to capital expenditures in connection with the Midla-Natchez Line and convertible preferred unit distributions which were included in Accrued expenses and other current liabilities at December 31, 2016. The Partnership plans to utilize the increase in the Second Amended and Restated Credit Agreement of $150.0 million to cover any working capital requirements.

Cash Flows

The following table reflects cash flows for the applicable periods (in thousands):

	For the Years Ended December 31,
	2016			2015			2014
Net cash provided by (used in):
Operating activities	$	90,639		$	86,978		$	51,635
Investing activities	(564,504		)	(250,769		)	(518,023		)
Financing activities	477,544			161,954			466,577

Year Ended December 31, 2016, Compared to Year Ended December 31, 2015

Operating Activities. Net cash provided by operating activities was $90.6 million for the year ended December 31, 2016, compared to $87.0 million for the year ended December 31, 2015. Net cash provided by operating activities for the year ended December 31, 2016, compared to December 31, 2015increased by $3.6 million mainly driven by a reduction in net loss of $18.3 million, excluding the $148.5 million goodwill impairment charge recorded in 2015, offset by a decrease in the change in operating assets and liabilities of $10.1 million.

Investing Activities. Net cash used in investing activities was $564.5 million for the year ended December 31, 2016, compared to $250.8 million for the year ended December 31, 2015. Cash used in investing activities for the year ended December 31, 2016 increased by $313.7 million period over period primarily due to the change in restricted cash of $325.6 million as a result of the issuance of our 8.50% Senior Notes and our 3.77% Senior Notes and an increase in investments in unconsolidated affiliates specifically for our interests in the Emerald Transactions and additional interests in Delta House Investment of $84.5 million.

These increases were partially offset by a $60.2 million decrease in capital expenditures and $30.5 million of higher cash distributions received from investments in unconsolidated affiliates as a return of capital.

Financing Activities. Net cash provided by financing activities was $477.5 million for the year ended December 31, 2016, compared to net cash provided by financing activities of $162.0 million for the year ended December 31, 2015. Cash provided by financing activities for the year ended December 31, 2016 increased by $315.5 million period over period primarily due proceeds from the 8.50% Senior Notes of $294.0 million, proceeds from the 3.77% Senior Notes of $60.0 million, partially offset by lower borrowings primarily on our revolving credit agreements of $46.2 million.

30

EXHIBIT 99.2

Year Ended December 31, 2015, Compared to Year Ended December 31, 2014

Operating Activities. Net cash provided by operating activities was $87.0 million for the year ended December 31, 2015, compared to $51.6 million for the year ended December 31, 2014. Net cash provided by operating activities for the year ended December 31, 2015, increased by $35.3 million period over period mainly driven by a decrease in net loss of $28.2 million, excluding the $148.5 million goodwill impairment charge recorded in 2015.

Investing Activities. Net cash used in investing activities was $250.8 million for the year ended December 31, 2015, compared to $518.0 million for the year ended December 31, 2014. Cash used in investing activities for the year ended December 31, 2015 decreased by $267.2 million period over period primarily due to a decrease in cost of acquisitions of $357.1 million, return of restricted cash of $16.2 million, and higher cash disbursements received from unconsolidated affiliates in excess of cumulative earnings of $10.7 million. These increases were offset by higher capital expenditures of $54.2 million primarily related to the Lavaca and Bakken Systems, and higher acquisitions of unconsolidated affiliates of $53.7 million related to equity method investments primarily related to the Delta House Investment.

Financing Activities. Net cash provided by financing activities was $162.0 million for the year ended December 31, 2015, compared to $466.6 million for the year ended December 31, 2014. Cash provided by financing activities for the year ended December 31, 2014 decreased by $304.6 million primarily due to lower proceeds from the issuance of common units to the public of $384.4 million, offset by higher net borrowings on debt of $83.5 million.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. At December 31, 2016, our material off-balance sheet arrangements and transactions included operating lease arrangements and service contracts. Please see "Contractual Obligations" for more information. There are no other transactions, arrangements, or other relationships associated with our investments in unconsolidated affiliates or related parties that are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

Capital Requirements

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

• maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets) made to maintain our operating income or operating capacity; or

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

Historically, our maintenance capital expenditures have not included all capital expenditures required to maintain volumes on our systems. It is customary in the regions in which we operate for producers to bear the cost of well connections, but we cannot be assured that this will be the case in the future. For the year ended December 31, 2016, capital expenditures totaled $147.8 million including expansion capital expenditures of $137.3 million, maintenance capital expenditures of $6.8 million and reimbursable project expenditures (capital expenditures for which we expect to be reimbursed for all or part of the expenditures by a third party) of $3.7 million. Although we classified our capital expenditures as expansion and maintenance, we believe those classifications approximate, but do not necessarily correspond to, the definitions of estimated maintenance capital expenditures and expansion capital expenditures under our Partnership Agreement. We anticipate maintenance capital expenditures related to the Partnership between $8.2 million and $10.2 million and expansion capital expenditures between $100.5 million and $110.5 million for the year ending December 31, 2017. Forecasted growth capital expenditures include East Texas Processing consolidation, expansion of the Harvey terminal, continued build-out of the Bakken system, continued development of the Silver Dollar System, and other organic growth projects.

We intend to make cash distributions to our unitholders, convertible preferred unitholders and our General Partner and expect that we will distribute most of the cash generated by our operations.

As a result, we expect to fund acquisitions and future capital expenditures with funds generated from our operations, borrowings under our revolving credit agreements, and additional debt and equity issuances. If these sources are not sufficient, we may pursue the divestiture of non-core assets or reduce discretionary spending.

31

EXHIBIT 99.2

Integrity Management

Certain operating assets require an ongoing integrity management program under regulations of the U.S. Department of Transportation, or DOT. These regulations require transportation pipeline operators to implement continuous integrity management programs over a seven-year cycle. Our total program addresses approximately 106 high consequence areas that require on-going testing pursuant to DOT regulations. Over the course of the seven-year cycle, we expect to incur up to $7.2 million in integrity management testing expenses.

Distributions

We intend to pay a quarterly distribution for the foreseeable future although we do not have a legal obligation to make distributions except as provided in our Partnership Agreement.

On January 26, 2017, we announced that the Board of Directors of our General Partner declared a quarterly cash a distribution of $0.4125 per American Midstream common unit for the fourth quarter ended December 31, 2016, or $1.65 per common unit on an annualized basis. The cash distribution was paid on February 13, 2017, to unitholders of record as of the close of business on February, 6 2017. A distribution of $0.3250 per JPE common unit and subordinated unit for the three months ended December 31, 2016 was declared on January 24, 2017 and paid on February 14, 2017 to unitholders of record as of February 7, 2017.

Contractual Obligations

The table below summarizes our contractual obligations and other commitments as of December 31, 2016 (in thousands):

	Total		Revolving Credit Agreements		3.77% Senior Notes		8.50% Senior Notes		Asset Retirement Obligation (1)		Other
Less Than 1 Year	$	15,604	$	—	$	1,677	$	—	$	6,499	$	7,428
1 - 3 Years	900,185		888,250		3,039		—		—		8,896
3 - 5 Years	311,643		—		6,729		300,000		—		4,914
More Than 5 Years	110,909		—		48,555		—		44,363		17,991
Total	$	1,338,341	$	888,250	$	60,000	$	300,000	$	50,862	$	39,229

(1) 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.

Impact of Seasonality

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

The volume of product that is handled, transported, throughput or stored in our refined products terminals is directly affected by the level of supply and demand in the wholesale markets served by our terminals. Overall supply of refined products in the wholesale markets is influenced by the absolute prices of the products, the availability of capacity on delivering pipelines and vessels, fluctuating refinery margins and the market’s perception of future product prices. Although demand for gasoline typically peaks during the summer driving season, which extends from April to September, and declines during the fall and winter months, most of the revenues generated at our refined products terminals do not experience any effects from such seasonality. However, the butane blending operations at our refined products terminals are affected by seasonality because of federal regulations governing seasonal gasoline vapor pressure specifications. Accordingly, we expect that the revenues we generate from butane blending will be highest in the winter months and lowest in the summer months.

32

EXHIBIT 99.2

The butane blending operations at our refined products terminals are affected by seasonality because of federal regulations governing seasonal gasoline vapor pressure specifications. Accordingly, we expect that the revenues we generate from butane blending will be highest in the winter months and lowest in the summer months.

Critical Accounting Policies and Estimates

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

Use of Estimates.When preparing consolidated financial statements in conformity with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and 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.

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

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

Impairment of Long-Lived Assets. We 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 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.

Impairment of Goodwill. We evaluate goodwill for impairment annually in the fourth quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We determine fair value using widely accepted valuation techniques, namely discounted cash flow and market multiple analyses. These techniques are also used when allocating the purchase price to acquired assets and liabilities. These types of analyses require us to make assumptions and estimates regarding industry and economic factors and the profitability of future business strategies. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations.

33

EXHIBIT 99.2

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.

Environmental Remediation. We recognize a liability and expense associated with environmental remediation if the existence of a liability is probable and the amount can be reasonably estimated. If governmental regulations change, we could be required to incur remediation costs that may have a material impact on our profitability.

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.

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 the gross basis for those transactions where we act as the principal and take title to commodities that are purchased for resale. Revenue from firm storage contracts is recognized ratably, which is typically monthly, over the term of the lease. Revenue from throughput fees and ancillary fees are recognized as services are provided to the customer.

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

We used mark-to-market accounting for our commodity hedges and interest rate swaps. We record monthly realized gains and losses on hedge instruments based upon cash settlements information. The settlement amounts vary due to the volatility in the commodity market prices throughout each month. We also record unrealized gains and losses for the net change in the mark-to-market valuation of the hedges.

34

EXHIBIT 99.2

Recent Accounting Pronouncements.

For information regarding new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements, please refer to Note 1 "Organization, Basis of Presentation and Summary of Significant Accounting Policies" in Part II, Item 8 of our 2016 10-K, which is incorporated herein by reference.

35

EX-99.3

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.

F-1

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.

/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, as to which the date is September 15, 2017, and except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of discontinued operations discussed in Note 3, as to which the date is December 6, 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 $630 and $0 as of December 31, 2016 and 2015, respectively	14,715			9,094
Unbilled revenue	52,910			51,922
Inventory	1,990			1,295
Other current assets	25,516			22,346
Current assets of discontinued operations	22,727			25,369
Total current assets	123,524			112,013
Risk management assets - long term	10,627			—
Property, plant and equipment, net	1,066,608			981,321
Restricted cash - long term	323,564			5,037
Investment in unconsolidated affiliates	291,987			63,704
Intangible assets, net	205,071			224,239
Goodwill	202,135			204,789
Other assets, net	11,773			12,719
Non-current assets of discontinued operations	114,032			148,067
Total assets	$	2,349,321		$	1,751,889
Liabilities, Convertible Preferred Units, Equity and Partners' Capital
Current liabilities
Accounts payable	$	39,569		$	45,377
Accrued gas purchases	7,891			7,281
Accrued expenses and other current liabilities	72,721			37,260
Current portion of debt	5,438			2,758
Current liabilities of discontinued operations	14,319			12,781
Total current liabilities	139,938			105,457
Asset retirement obligations	44,363			28,549
Other liabilities	1,858			2,482
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
Non-current liabilities of discontinued operations	172			375
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	$	439,412		$	613,241		$	721,663
Services	151,231			135,718			116,195
Gains (losses) on commodity derivatives, net	(1,617		)	1,345			1,091
Total revenue	589,026			750,304			838,949
Operating expenses:
Cost of sales	393,351			567,682			672,948
Direct operating expenses	71,544			71,729			58,048
Corporate expenses	89,438			65,327			60,465
Depreciation, amortization and accretion	90,882			81,335			57,818
Loss on sale of assets, net	688			2,860			4,087
Loss on impairment of property, plant and equipment	697			—			21,344
Loss on impairment of goodwill	2,654			148,488			—
Total operating expenses	649,254			937,421			874,710
Operating loss	(60,228		)	(187,117		)	(35,761		)
Other income (expense):
Interest expense	(21,433		)	(20,077		)	(16,497		)
Loss on extinguishment of debt	—			—			(1,634		)
Other income (expense)	254			1,460			(1,096		)
Earnings in unconsolidated affiliates	40,158			8,201			348
Loss from continuing operations, before income taxes	(41,249		)	(197,533		)	(54,640		)
Income tax expense	(2,580		)	(1,885		)	(856		)
Loss from continuing operations	(43,829		)	(199,418		)	(55,496		)
Loss from discontinued operations	(4,715		)	(423		)	(24,071		)
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	$	(1.51	)	$	(4.91	)	$	(2.77	)
Loss from discontinued operations	(0.09		)	(0.01		)	(0.52		)
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 five reportable segments, (1) gas gathering and processing services, (2) liquid pipelines and services, (3) natural gas transportation services, (4) offshore pipelines and services, and (5) terminalling 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 and storing specialty chemical products and selling 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.

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.

Discontinued Operations

On September 1, 2017, we completed the disposition of the Propane Marketing Services business (the "Propane Business") pursuant to the Membership Interest Purchase Agreement dated July 21, 2017, between AMID Merger LP, a wholy owned subsidiary of the Partnership and SHV Energy N.V. Through the transaction, we divested Pinnacle Propane’s 40 service locations; Pinnacle Propane Express’ cylinder exchange business and related logistic assets; and the Alliant Gas utility system. Prior to the sale, we moved the trucking business from the Propane Marketing Services segment to the Liquid Pipelines and Services segment for all periods presented. During the years ended December 31, 2016, 2015, and 2014, the trucking business had revenues of $6.9 million, $10.3 million, and $11.3 million, respectively, which represent 5%, 6%, and 6% of total Propane Business revenue, respectively. Additionally, for the years ended December 31, 2016, 2015, and 2014, the trucking business had inter-segment revenues of $2.0 million, $2.1 million, and $3.7 million with the Propane Business that were previously eliminated in consolidation, and are now included in the total trucking business revenue, with the offsetting expenses included in discontinued operations.

F-9

In connection with the transaction, we received $170.0 million in cash and recorded a gain on the sale of $46.5 million, net of $2.5 million transaction costs. As a result of the disposition of the Propane Business, we have classified the accounts and the results of operations of the Propane Business as discontinued operations. See Note 3 for additional details.

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.

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. Inventory is stated at the lower of cost or market. The cost of crude oil, NGLs, and refined products is determined using the first-in, first-out (FIFO) 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.

F-10

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 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 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.

F-11

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 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.

F-12

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.

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.

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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.

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

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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.

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

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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 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

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.

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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.

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.

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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 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 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 value of $0.3 million. 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 of $6.2 million, goodwill of $5.8 million, property, plant and equipment of $3.0 million, accounts receivable of $1.0 million and other intangible assets of $0.3 million. Goodwill associated with the acquisition principally results from synergies expected from integrated operations. The fair values

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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. The Southern acquisition is part of the Propane Business that was sold in September 2017, see Note 3 for additional information regarding the sale of the Propane Business.

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 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.

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3. Discontinued Operations

Propane Business

On September 1, 2017, we completed the disposition of the Propane Business pursuant to the Membership Interest Purchase Agreement dated July 21, 2017, between AMID Merger LP, a wholly owned subsidiary of the Partnership, and SHV Energy N.V. Through the transaction, we divested Pinnacle Propane’s 40 service locations; Pinnacle Propane Express’ cylinder exchange business and related logistic assets; and the Alliant Gas utility system. Prior to the sale, we moved the trucking business from the Propane Marketing Services segment to the Liquid Pipelines and Services segment. With the disposition of the Propane Business, we eliminated the Propane Marketing Services segment.

In connection with the transaction, we received approximately $170 million in cash, net of customary closing adjustments, and recorded a gain of approximately $46.5 million, net of $2.5 million of transaction costs. We have reported the accounts and the results of our Propane Business as discontinued operations in our consolidated financial statements for all periods presented. The following tables summarize the financial information related to the Propane Business for the corresponding years.

Consolidated Statements of Operations

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Total revenues	$	137,896		$	163,583		$	181,843
Costs and Expenses
Costs of sales	49,672			62,621			116,924
Direct operating expenses	51,828			55,751			51,495
Corporate expenses	9,992			12,508			12,279
Depreciation, amortization and accretion	15,936			17,261			14,709
Loss on sale of assets, net	2,182			1,060			993
Loss on impairment of goodwill	12,802			—			—
Total expenses	142,412			149,201			196,400
Operating (loss) income	(4,516		)	14,382			(14,557		)
Other Income(expense)
Interest expense	(36		)	(43		)	(61		)
Other income	374			272			434
Income (loss) from discontinued operations before income tax benefit (expense)	(4,178		)	14,611			(14,184		)
Income tax benefit (expense)	2			(3		)	(1		)
Net income (loss) from discontinued operations	$	(4,176	)	$	14,608		$	(14,185	)

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Consolidated Balance Sheets

The current and non-current assets and liabilities of the Propane Business are as follows:

	December 31,
	2016		2015
	(in thousands)
ASSETS
Current assets
Accounts receivable, net	$	13,055	$	14,736
Unbilled revenue	2,736		3,506
Inventory	4,785		3,946
Other current assets	2,151		451
Total current assets of discontinued operations	22,727		22,639
Non-current assets
Property, plant and equipment, net	78,395		90,194
Goodwill	15,361		28,162
Intangible assets, net	20,212		23,041
Risk management assets	37		—
Other assets, net	27		26
Total non-current assets of discontinued operations	114,032		141,423
Total assets	$	136,759	$	164,062
LIABILITIES
Current liabilities
Accounts payable	$	5,709	$	3,148
Accrued expenses and other current liabilities	8,563		8,852
Current portion of long-term debt	47		141
Total current liabilities of discontinued operations	14,319		12,141
Non-current liabilities
Other liabilities	172		375
Total non-current liabilities of discontinued operations	172		375
Total liabilities	$	14,491	$	12,516

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The following table summarizes other selected financial information related to the Propane Business:

	Year ended December 31,
	2016			2015			2014
	(in thousands)
Depreciation	$	13,108		$	14,455		$	12,298
Amortization	2,828			2,806			2,411
Capital expenditures	6,549			17,503			16,398
Other operating non-cash items
Impairment of goodwill	12,802			—			—
Loss on sale of assets	2,182			1,060			993
Unrealized (gain) loss on derivative contracts, net	(1,072		)	(11,764		)	12,691

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 in the consolidated statement of operations is summarized below:

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
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		)
Income (loss) from discontinued operations before income tax expense	(539		)	(14,951		)	333
Income tax expense	—			—			—
Net income (loss) from discontinued operations	$	(539	)	$	(14,951	)	$	333

F-22

The current and non-current assets and liabilities of the Mid-Continent Business are as follows:

	December 31,
	2015
ASSETS
Current assets
Inventory	$	2,692
Other current assets	38
Total current assets of discontinued operations	2,730
Non-current assets
Property, plant and equipment, net	5,203
Intangible assets, net	1,138
Other assets, net	303
Total non-current assets of discontinued operations	6,644
Total assets	$	9,374
LIABILITIES
Current liabilities
Accrued expenses and other current liabilities	$	640
Total current assets of discontinued operations	640
Total liabilities	$	640

F-23

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
Costs and Expenses
Cost of sales	5,254
Direct operating expenses	1,324
Corporate expenses	448
Depreciation, amortization and accretion	1,433
Loss on sale of assets, net	9,032
Total expenses	17,491
Operating loss	(9,626		)
Interest expense	(4		)
Other income	22
Loss from discontinued operations before income tax expense	$	(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.

Selected 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
Expenses	(196		)	(658		)
Impairment	—			(673		)
Loss on sale of assets	(150		)	(87		)
Income tax benefit	192			333
Loss from discontinued operations	$	(80	)	$	(611	)

We have 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.

F-24

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 21% and 13%, respectively, of our consolidated revenue. In 2015, we had one such customer who accounted for 34% of our consolidated revenue. In 2014, we had two such customers who accounted for 20% and 11%, respectively, 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.

F-25

5. Inventory

Inventory consists of the following:

	December 31,
	2016		2015
	(in thousands)
Crude oil	$	1,216	$	486
NGLs	288		274
Refined products	—		232
Materials, supplies and equipment	486		303
Total inventory	$	1,990	$	1,295

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	1,624		84
Other receivables	2,997		2,680
Due from related parties	4,833		8,749
Risk management assets	469		365
Other assets	5,891		5,281
Total other current assets	$	25,516	$	22,346

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.

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.

F-26

	December 31, 2016		December 31, 2015
	Notional Volume	Maturity	Notional Volume	Maturity
Commodity Swaps:
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 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.

F-27

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	$	541		$	457		$	(72	)	$	(92	)	$	469		$	365
Risk management assets - long term	10,628			—			(1		)	—			10,627			—
Total assets	$	11,169		$	457		$	(73	)	$	(92	)	$	11,096		$	365
Accrued expenses and other current liabilities	$	(253	)	$	(92	)	$	72		$	92		$	(181	)	$	—
Other liabilities	(1		)	—			1			—			—			—
Total liabilities	$	(254	)	$	(92	)	$	73		$	92		$	(181	)	$	—

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	$	(1,569	)	$	(48	)
Interest expense	(144		)	10,375
Direct operating expenses	(966		)	—
Total	$	(2,679	)	$	10,327
2015
Gains (losses) on commodity derivatives, net	$	1,632		$	(287	)
Interest expense	(425		)	373
Direct operating expenses	(913		)	—
Total	$	294		$	86
2014
Gains on commodity derivatives, net	$	734		$	357
Interest expense	(707		)	284
Direct operating expenses	(1,035		)	—
Total	$	(1,008	)	$	641

F-28

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	$	18,861		$	14,118
Construction in progress	N/A	128,519			56,134
Transportation equipment	5 to 15	20,010			22,125
Buildings and improvements	4 to 40	13,762			12,121
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	146,408			144,780
Equipment	5 to 20	77,978			53,097
Total property, plant and equipment		1,331,330			1,179,972
Less accumulated depreciation		(264,722		)	(198,651		)
Property, plant and equipment, net		$	1,066,608		$	981,321

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 $69.7 million, $60.6 million and $38.6 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 $13.2 million, $15.5 million, and $14.0 million for the years ended December 31, 2016, 2015 and 2014, respectively, to present the Mid-Continent, Bakken Business and Propane 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.

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 forecast 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 reportable segment and Liquid Pipelines and Services reportable segment 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.

F-29

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 $29.9 million impairment charge in our Liquid Pipelines and Services reportable segment relating to our Crude Oil Supply and Logistics business and 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 $2.7 million related to our JP Liquids business in our Liquid Pipelines and Services reportable segment. Given the market condition trend surrounding JP Liquids, we may recognize further impairments related to those assets in the future. Additionally, we recorded a goodwill impairment charge of $12.8 million in 2016 related to our Pinnacle Propane Express business which is included in net loss from discontinued operations in the consolidated statement of operations.

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

	Gas Gathering and Processing Services			Liquid Pipelines and Services			Terminalling Services		Total
	(in thousands)
Balance at January 1, 2015	$	125,974		$	146,219		$	88,466	$	360,659
Goodwill acquired during the year	—			—			—		—
Return of purchase price	(7,382		)	—			—		(7,382		)
Impairment charges	(118,592		)	(29,896		)	—		(148,488		)
Balance at December 31, 2015	—			116,323			88,466		204,789
Impairment charges	—			(2,654		)	—		(2,654		)
Balance at December 31, 2016	$	—		$	113,669		$	88,466	$	202,135

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:

	December 31,
	2016		2015		2016			2015			2016		2015
	Gross carrying amount				Accumulated amortization						Net carrying amount
	(in thousands)
Customer relationships	$	106,417	$	106,417	$	(23,245	)	$	(15,535	)	$	83,172	$	90,882
Customer contracts	94,692		94,692		(33,228		)	(24,388		)	61,464		70,304
Dedicated acreage	53,350		53,350		(4,439		)	(2,661		)	48,911		50,689
Collaborative arrangements	11,884		11,884		(601		)	—			11,283		11,884
Noncompete agreements	1,063		1,063		(1,000		)	(765		)	63		298
Other	198		198		(20		)	(16		)	178		182
	$	267,604	$	267,604	$	(62,533	)	$	(43,365	)	$	205,071	$	224,239

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 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 $19.2 million, $20.0 million and $18.4 million, respectively, which is included depreciation, amortization and accretion in the consolidated statements of operations. Amortization expense of $2.9 million, $4.0 million and $4.4 million for the years ended December 31 2016, 2015 and 2014, respectively, relating to the Mid-Continent Business, Bakken Business and Propane Business is included in the net loss from discontinued operations, net of tax, in the consolidated statement of operations.

F-30

Estimated amortization expense for each of the next five years ranges from $10.0 million to $15.6 million, with an aggregate $116.5 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.

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

F-31

	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:

	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	$	14,274	$	7,139
Employee compensation	8,438		6,198
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	148		1
Deferred financing costs	2,743		—
Taxes payable	1,186		1,146
Gas imbalances payable	1,098		413
Other	9,491		5,646
Total accrued expenses and other current liabilities	$	72,721	$	37,260

F-32

12. Asset Retirement Obligations

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

	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		$	3,762		$	1,252,012
Less unamortized deferred financing costs and discount	—		—		(8,691		)	(2,345		)	—			(11,036		)
Subtotal	711,250		177,000		291,309			57,655			3,762			1,240,976
Less current portion	—		—		—			(1,676		)	(3,762		)	(5,438		)
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	$	3,498		$	690,598
Less current portion	—		—		(2,758		)	(2,758		)
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.

F-33

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 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

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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

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:

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

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.

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14. Convertible Preferred Units

Our convertible preferred units consist of the following:

	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.

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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.

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.

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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.

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.

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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.

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	$	(43,829	)	$	(199,418	)	$	(55,496	)
Less: Net income (loss) attributable to noncontrolling interests	2,766			(13		)	3,993
Net loss from continuing operations attributable to the Partnership	(46,595		)	(199,405		)	(59,489		)
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	(1,691		)	(3,498		)	(1,325		)
Net loss from continuing operations attributable to Limited Partners	(77,042		)	(221,048		)	(76,212		)
Net loss from discontinued operations attributable to Limited Partners	(4,715		)	(423		)	(14,545		)
Net loss attributable to Limited Partners	$	(81,757	)	$	(221,471	)	$	(90,757	)
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)	$	(1.51	)	$	(4.91	)	$	(2.77	)
Limited Partners' net loss from discontinued operations per unit (basic and diluted)	(0.09		)	(0.01		)	(0.52		)
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. Although our General Partner has the option to settle vested phantom units in cash, our General Partner has not historically settled

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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.

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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.

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

	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	(2,059		)	(1,237		)	(710		)
Effective income tax rate	6.3		%	1.0		%	1.6		%

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	$	(41,249	)	$	(197,533	)	$	(54,640	)
US Federal statutory tax rate	34		%	34		%	34		%
Federal income tax (expense) benefit at statutory rate	14,025			67,161			18,578
Reconciling items:
Partnership loss not subject to income tax (benefit)	(15,800		)	(68,048		)	(18,936		)
State and local tax expense	(800		)	(857		)	(459		)
Other	(5		)	(141		)	(39		)
Income tax expense	$	(2,580	)	$	(1,885	)	$	(856	)

F-48

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

	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

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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 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	$	7,428	$	15,604
2018	—		806		—		—		4,507		5,313
2019	888,250		2,233		—		—		4,389		894,872
2020	—		2,299		—		—		2,670		4,969
2021	—		4,430		300,000		—		2,244		306,674
Thereafter	—		48,555		—		44,363		17,991		110,909
	$	888,250	$	60,000	$	300,000	$	50,862	$	39,229	$	1,338,341

(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 endedDecember 31, 2016, 2015 and 2014, total rental expenses were $15.9 million, $14.4 million, and $7.9 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 sheet 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.

F-51

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, and Terminalling 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.

F-52

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.

F-53

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			Total
	(in thousands)
Commodity sales	$	91,444		$	304,502		$	21,999	$	6,812		$	14,655		$	439,412
Services	22,558			19,063			18,109		40,502			50,999			151,231
Gains (losses) on commodity derivatives, net	(833		)	(341		)	—		(7		)	(436		)	(1,617		)
Total Revenue	113,169			323,224			40,108		47,307			65,218			589,026
Cost of sales	63,832			293,618			21,288		3,049			11,564			393,351
Direct operating expenses	33,802			10,091			5,923		10,945			10,783			71,544
Corporate expenses															89,438
Depreciation, amortization, and accretion															90,882
Loss on sale of assets, net															688
Loss on impairment of plant, property and equipment															697
Loss on impairment of goodwill															2,654
Interest expense															21,433
Earnings in unconsolidated affiliates															(40,158		)
Other (income) expense															(254		)
Income tax expense															2,580
Income (loss) from continuing operations															(43,829		)
Loss from discontinuing operations, net of tax															(4,715		)
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		$	31,556		$	18,616	$	82,346		$	42,872

F-54

	December 31, 2015
	Gas Gathering and Processing Services		Liquid Pipelines and Services		Natural Gas Transportation Services		Offshore Pipelines and Services		Terminalling Services		Total
	(in thousands)
Commodity sales	$	107,680	$	457,448	$	23,972	$	13,798	$	10,343	$	613,241
Services	30,196		23,008		16,035		21,457		45,022		135,718
Gains (losses) on commodity derivatives, net	1,240		—		—		84		21		1,345
Total Revenue	139,116		480,456		40,007		35,339		55,386		750,304
Cost of sales	72,960		454,057		21,858		9,914		8,893		567,682
Direct operating expenses	35,250		9,912		6,728		9,425		10,414		71,729
Corporate expenses											65,327
Depreciation, amortization, and accretion											81,335
Loss on sale of assets, net											2,860
Loss on impairment of goodwill											148,488
Interest expense											20,077
Earnings in unconsolidated affiliates											(8,201		)
Other (income) expense											(1,460		)
Income tax expense											1,885
Income (loss) from continuing operations											(199,418		)
Loss from discontinuing operations, net of tax											(423		)
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	$	26,399	$	18,073	$	33,613	$	36,079

F-55

	December 31, 2014
	Gas Gathering and Processing Services		Liquid Pipelines and Services		Natural Gas Transportation Services		Offshore Pipelines and Services		Terminalling Services		Total
	(in thousands)
Commodity sales	$	148,198	$	470,936	$	70,964	$	20,044	$	11,521	$	721,663
Services	15,248		22,239		12,925		24,426		41,357		116,195
Gains (losses) on commodity derivatives, net	1,050		—		—		41		—		1,091
Total Revenue	164,496		493,175		83,889		44,511		52,878		838,949
Cost of sales	112,719		468,137		70,100		15,133		6,859		672,948
Direct operating expenses	21,197		7,209		6,975		11,142		11,525		58,048
Corporate expenses											60,465
Depreciation, amortization, and accretion											57,818
Loss on sale of assets, net											4,087
Loss on impairment of plant, property and equipment											21,344
Interest expense											16,497
Earnings in unconsolidated affiliates											(348		)
Other (income) expense											1,096
Loss on extinguishment of debt											1,634
Income tax expense											856
Income (loss) from continuing operations											(55,496		)
Loss from discontinuing operations, net of tax											(24,071		)
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	$	25,038	$	13,691	$	29,089	$	34,493

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	425,389		434,395
Natural Gas Transportation Services	221,604		146,927
Offshore Pipelines and Services	400,193		190,271
Terminalling Services	299,534		291,130
Other (1)	334,953		19,716
Discontinued operations	136,759		$	173,436
Total assets	$	2,349,321	$	1,751,889

F-56

_______________________

(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	$	100,998		$	152,253		$	159,903		$	175,872
Total segment gross margin (1)	46,430			59,016			58,793			59,396
Operating loss	(16,097		)	(12,790		)	(9,724		)	(21,617		)
Net loss from continuing operations	(17,772		)	(12,156		)	(5,488		)	(8,413		)
Income (loss) from discontinued operations	7,169			2,675			(2,310		)	(12,249		)
Net income (loss) attributable to noncontrolling interest	(3		)	954			1,241			574
Net income (loss) attributable to the Partnership	(10,600		)	(10,435		)	(9,039		)	(21,236		)
General Partner's Interest in net income (loss)	(97		)	(107		)	(31		)	2
Limited Partners' Interest in net loss	$	(10,503	)	$	(10,328	)	$	(9,008	)	$	(21,238	)
Limited Partners' income (loss) per unit:
Loss from continuing operations	$	(0.49	)	$	(0.40	)	$	(0.29	)	$	(0.33	)
Income (loss) from discontinued operations	0.16			0.07			(0.05		)	$	(0.27	)
Net loss	$	(0.33	)	$	(0.33	)	$	(0.34	)	$	(0.60	)
Year Ended December 31, 2015
Total revenues	$	184,937		$	227,693		$	174,848		$	162,826
Total segment gross margin (1)	45,314			44,921			41,445			48,176
Operating loss	(8,785		)	(6,815		)	(11,114		)	(160,403		)
Net loss from continuing operations	(12,523		)	(11,977		)	(15,607		)	(159,311		)
Income (loss) from discontinued operations	10,596			1,575			(900		)	(11,694		)
Net income (loss) attributable to noncontrolling interest	4			22			24			(63		)
Net loss attributable to the Partnership	(1,932		)	(10,425		)	(16,532		)	(170,939		)
General Partner's Interest in net loss	(32		)	(66		)	(104		)	(1,621		)
Limited Partners' Interest in net loss	$	(1,900	)	$	(10,358	)	$	(16,428	)	$	(169,319	)
Limited Partners' income (loss) per unit:
Loss from continuing operations	$	(0.41	)	$	(0.41	)	$	(0.51	)	$	(3.58	)
Income (loss) from discontinued operations, net of tax	0.25			0.03			(0.02		)	(0.27		)
Net loss	$	(0.16	)	$	(0.38	)	$	(0.53	)	$	(3.85	)

(1) For a definition of total segment 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 $2.7 million and $148.5 million in the fourth quarters of 2016 and 2015, respectively.

F-57

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.

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.

F-58

XML

Document and Entity Information	12 Months Ended
	Dec. 31, 2016
Entity Registrant Name	American Midstream Partners, LP
Entity Central Index Key	0001513965
Document Type	8-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 5,666	$ 1,987
Accounts receivable, net of allowance for doubtful accounts of $630 as of December 31, 2016	14,715	9,094
Unbilled revenue	52,910	51,922
Inventory	1,990	1,295
Other current assets	25,516	22,346
Current assets of discontinued operations	22,727	25,369
Total current assets	123,524	112,013
Risk management assets - long term	10,627	0
Property, plant and equipment, net	1,066,608	981,321
Restricted cash - long term	323,564	5,037
Investment in unconsolidated affiliates	291,987	63,704
Intangible assets, net	205,071	224,239
Goodwill	202,135	204,789
Other assets, net	11,773	12,719
Non-current assets of discontinued operations	114,032	148,067
Total assets	2,349,321	1,751,889
Current liabilities
Accounts payable	39,569	45,377
Accrued gas purchases	7,891	7,281
Accrued expenses and other current liabilities	72,721	37,260
Current portion of debt	5,438	2,758
Current liabilities of discontinued operations	14,319	12,781
Total current liabilities	139,938	105,457
Noncurrent asset retirement obligation	44,363	28,549
Other liabilities	1,858	2,482
Revolving credit agreements	1,235,538	687,840
Deferred tax liability	8,205	6,173
Non-current liabilities of discontinued operations	172	375
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)
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
Limited Partner Common Units
Equity and partners' capital
Limited Partners' Capital Account	616,087	753,388
Limited Partner Series B Convertible Units
Equity and partners' capital
Limited Partners' Capital Account	0	33,593
3.77% Senior Notes, due 2031
Current liabilities
Senior Notes	55,979	0
8.50% Senior Notes, due 2021
Current liabilities
Senior Notes	291,309	0
Revolving Credit Agreements
Current liabilities
Revolving credit agreements	$ 888,250	$ 687,100

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Allowance for doubtful accounts	$ 630
General partners' interest units issued (in shares)	680,000	536,000
General partners' interest units outstanding (in shares)	680,000	536,000
Limited partners, units issued (in shares)	51,351,000	50,504,000
Limited partners, units outstanding (in shares)	51,351,000	50,504,000
Limited Partner Series B Convertible Units
Limited partners, units issued (in shares)		1,350,000
Limited partners, units outstanding (in shares)		1,350,000
3.77% Senior Notes, due 2031 | Senior Notes
Debt instrument, interest rate (percent)	3.77%
8.50% Senior Notes, due 2021 | Senior Notes
Debt instrument, interest rate (percent)	8.50%

XML

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Commodity sales	$ 439,412	$ 613,241	$ 721,663
Services	151,231	135,718	116,195
Losses on commodity derivatives, net	(1,617)	1,345	1,091
Total revenue	589,026	750,304	838,949
Operating expenses:
Cost of sales	393,351	567,682	672,948
Direct operating expenses	71,544	71,729	58,048
Corporate expenses	89,438	65,327	60,465
Depreciation, amortization and accretion	90,882	81,335	57,818
Loss on sale of assets, net	688	2,860	4,087
Loss on impairment of property, plant and equipment	697	0	21,344
Loss on impairment of goodwill	2,654	148,488	0
Total operating expenses	649,254	937,421	874,710
Operating loss	(60,228)	(187,117)	(35,761)
Other income (expense):
Interest expense	(21,433)	(20,077)	(16,497)
Loss on extinguishment of debt	0	0	(1,634)
Other income (expense)	254	1,460	(1,096)
Earnings in unconsolidated affiliates	40,158	8,201	348
Loss from continuing operations, before income taxes	(41,249)	(197,533)	(54,640)
Income tax expense	(2,580)	(1,885)	(856)
Loss from continuing operations	(43,829)	(199,418)	(55,496)
Loss from discontinued operations, net of tax	(4,715)	(423)	(24,071)
Net income (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)
Distribution declared per common unit (in dollars per share)	$ 3.01	$ 3.17	$ 1.85
Basic and diluted:
Loss from continuing operations, basic and diluted (in usd per share)	(1.51)	(4.91)	(2.77)
Loss from discontinued operations, basic and diluted (in usd per share)	(0.09)	(0.01)	(0.52)
Net loss, basic and diluted (in usd per share)	$ (1.60)	$ (4.92)	$ (3.29)
Weighted average number of common units outstanding:
Basic and diluted (in shares)	51,176	45,050	27,524
General Partner
Other income (expense):
Net income (loss)	$ (233)	$ (1,823)	$ (398)
General Partner's interest in net loss	(233)	(1,823)	(398)
Limited Partner
Other income (expense):
Net income (loss)	(51,077)	(198,005)	(83,162)
Limited Partners' interest in net loss	$ (51,077)	$ (198,005)	$ (83,162)

XML

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
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: Net income (loss) attributable to noncontrolling interests	2,766	(13)	3,993
Comprehensive loss attributable to Partnership	$ (51,390)	$ (199,790)	$ (83,662)

XML

Consolidated Statements of Changes in Partners' Capital and Noncontrolling Interests - USD ($) $ in Thousands	Total	Accumulated Other Comprehensive Income	Total Partners Capital	Noncontrolling Interest	Blackwater Total Partners Capital	Blackwater Noncontrolling Interest	Series B	Series B Total Partners Capital	Delta House Total Partners Capital	BP Total Partners Capital	General Partner	General Partner Delta House	General Partner BP	Limited Partner	Limited Partner Blackwater
Beginning Balance at Dec. 31, 2013		$ 104	$ 671,193	$ 7,884							$ 59,754			$ 611,335
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss)	$ (79,567)		(83,560)								(398)			(83,162)
Issuance of units			609,707				$ 32,220	$ 32,220						609,707
Unitholder contributions			5,678								5,678
Unitholder distributions			(134,019)								(2,913)			(131,106)
Contributions from general partner			(47,678)											(47,678)
Issuance and exercise of warrants			0								(7,164)			7,164
Contributions from noncontrolling interest owners					$ 21	$ 189									$ 21
Distributions to noncontrolling interest owners			0	(314)
LTIP vesting			244								(823)			1,067
Tax netting repurchases	610		(256)											(256)
Equity compensation expense			3,145								1,356			1,789
Other comprehensive income (loss)	(102)	(102)	(102)
Ending Balance at Dec. 31, 2014		2	1,056,593	11,752			32,220				55,490			968,881
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss)	(199,841)		(199,828)								(1,823)			(198,005)
Issuance of units			85,465				1,373	$ 1,373						85,465
Unitholder contributions			1,996								1,996			0
Unitholder distributions			(118,763)								(7,023)			(111,740)
Contributions from general partner			5,568											5,568
Contributions from noncontrolling interest owners			0	739
Unitholder distribution for Delta House Transaction									$ (96,297)			$ (96,297)
Distributions to noncontrolling interest owners			(20)	(367)										(20)
LTIP vesting			196								(2,490)			2,686
Tax netting repurchases	1,045		(756)											(756)
Equity compensation expense			4,365								3,056			1,309
Other comprehensive income (loss)	38	38	38
Ending Balance at Dec. 31, 2015	739,930	40	739,930	12,111			33,593				(47,091)			753,388
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss)	(48,544)		(51,310)	2,766							(233)			(51,077)
Unitholder contributions			1,998								1,998
Unitholder distributions			(138,699)								(7,938)			(130,761)
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 and exercise of warrants			4,481								4,481
Issuance of common units, net of offering costs			2,697											2,697
Contributions from noncontrolling interest owners			0	3,366
Unitholder distribution for Delta House Transaction											(96,300)
General Partner's contribution for acquisition										$ 990			$ 990
Distributions to noncontrolling interest owners			0	(1,488)
LTIP vesting			0								(3,486)			3,486
Tax netting repurchases	521		(346)											(346)
Equity compensation expense			5,658								3,634			2,024
Other comprehensive income (loss)	(80)	(80)	(80)
Ending Balance at Dec. 31, 2016	$ 568,402	$ (40)	$ 568,402	$ 16,755			$ 0				$ (47,645)			$ 616,087

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 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 expense	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	0	0	673
Loss on impairment of goodwill	15,456	156,427	0
Loss on extinguishment of debt	0	0	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	0
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)
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)
Redemption of Series D preferred units - JPE	0	0	(42,436)
Contributions from noncontrolling interest owners	3,366	584	0
LTIP tax netting unit repurchases	(521)	(1,045)	(610)
Payment of financing costs	(5,327)	(2,244)	(7,034)
Proceeds from debt	425,100	471,300	883,885
Payments on revolving credit agreements	(223,950)	(240,150)	(736,227)
Payments on other debt	(3,136)	(4,069)	(7,621)
Other	0	(688)	(1,344)
Borrowings on other debt	0	4,709	3,449
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
Blackwater
Cash flows from financing activities
Unitholder distributions for common control transactions	0	(96,297)	(52,000)
Noncontrolling Interest
Cash flows from operating activities
Net loss	2,766
Cash flows from financing activities
Distributions to noncontrolling interest owners	(1,488)	(114)	(322)
Series A Preferred Stock
Cash flows from financing activities
Issuance of units	34,413	44,768	0
Limited Partner Series B Convertible Units
Cash flows from financing activities
Issuance of units	0	0	30,000
Series D
Cash flows from financing activities
Issuance of units	0	0	40,000
3.77% Senior Notes, due 2031
Cash flows from financing activities
Proceeds from debt	60,000	0	0
8.50% Senior Notes, due 2021
Cash flows from financing activities
Proceeds from debt	$ 294,000	$ 0	$ 0

XML

Consolidated Statements of Cash Flows (Parenthical) - Senior Notes	Dec. 31, 2016	Dec. 28, 2016	Sep. 30, 2016
3.77% Senior Notes, due 2031
Debt instrument, interest rate (percent)	3.77%		3.77%
8.50% Senior Notes, due 2021
Debt instrument, interest rate (percent)	8.50%	8.50%

XML

Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Basis of Presentation

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 five reportable segments, (1) gas gathering and processing services, (2) liquid pipelines and services, (3) natural gas transportation services, (4) offshore pipelines and services, and (5) terminalling 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 and storing specialty chemical products and selling 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.

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.

Discontinued Operations

On September 1, 2017, we completed the disposition of the Propane Marketing Services business (the "Propane Business") pursuant to the Membership Interest Purchase Agreement dated July 21, 2017, between AMID Merger LP, a wholy owned subsidiary of the Partnership and SHV Energy N.V. Through the transaction, we divested Pinnacle Propane’s 40 service locations; Pinnacle Propane Express’ cylinder exchange business and related logistic assets; and the Alliant Gas utility system. Prior to the sale, we moved the trucking business from the Propane Marketing Services segment to the Liquid Pipelines and Services segment for all periods presented. During the years ended December 31, 2016, 2015, and 2014, the trucking business had revenues of $6.9 million, $10.3 million, and $11.3 million, respectively, which represent 5%, 6%, and 6% of total Propane Business revenue, respectively. Additionally, for the years ended December 31, 2016, 2015, and 2014, the trucking business had inter-segment revenues of $2.0 million, $2.1 million, and $3.7 million with the Propane Business that were previously eliminated in consolidation, and are now included in the total trucking business revenue, with the offsetting expenses included in discontinued operations.

In connection with the transaction, we received $170.0 million in cash and recorded a gain on the sale of $46.5 million, net of $2.5 million transaction costs. As a result of the disposition of the Propane Business, we have classified the accounts and the results of operations of the Propane Business as discontinued operations. See Note 3 for additional details.

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.

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. Inventory is stated at the lower of cost or market. The cost of crude oil, NGLs, and refined products is determined using the first-in, first-out (FIFO) 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.

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 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 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 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.

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.

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.

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 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.

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

Acquisitions and Divestitures

Acquisitions

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.

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 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 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 value of $0.3 million. 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 of $6.2 million, goodwill of $5.8 million, property, plant and equipment of $3.0 million, accounts receivable of $1.0 million and other intangible assets of $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. The Southern acquisition is part of the Propane Business that was sold in September 2017, see Note 3 for additional information regarding the sale of the Propane Business.

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 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.

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Discontinued Operations

12 Months Ended

Dec. 31, 2016

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

Discontinued Operations

Propane Business

On September 1, 2017, we completed the disposition of the Propane Business pursuant to the Membership Interest Purchase Agreement dated July 21, 2017, between AMID Merger LP, a wholly owned subsidiary of the Partnership, and SHV Energy N.V. Through the transaction, we divested Pinnacle Propane’s 40 service locations; Pinnacle Propane Express’ cylinder exchange business and related logistic assets; and the Alliant Gas utility system. Prior to the sale, we moved the trucking business from the Propane Marketing Services segment to the Liquid Pipelines and Services segment. With the disposition of the Propane Business, we eliminated the Propane Marketing Services segment.

In connection with the transaction, we received approximately $170 million in cash, net of customary closing adjustments, and recorded a gain of approximately $46.5 million, net of $2.5 million of transaction costs. We have reported the accounts and the results of our Propane Business as discontinued operations in our consolidated financial statements for all periods presented. The following tables summarize the financial information related to the Propane Business for the corresponding years.

Consolidated Statements of Operations

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Total revenues	$	137,896		$	163,583		$	181,843
Costs and Expenses
Costs of sales	49,672			62,621			116,924
Direct operating expenses	51,828			55,751			51,495
Corporate expenses	9,992			12,508			12,279
Depreciation, amortization and accretion	15,936			17,261			14,709
Loss on sale of assets, net	2,182			1,060			993
Loss on impairment of goodwill	12,802			—			—
Total expenses	142,412			149,201			196,400
Operating (loss) income	(4,516		)	14,382			(14,557		)
Other Income(expense)
Interest expense	(36		)	(43		)	(61		)
Other income	374			272			434
Income (loss) from discontinued operations before income tax benefit (expense)	(4,178		)	14,611			(14,184		)
Income tax benefit (expense)	2			(3		)	(1		)
Net income (loss) from discontinued operations	$	(4,176	)	$	14,608		$	(14,185	)

Consolidated Balance Sheets

The current and non-current assets and liabilities of the Propane Business are as follows:

	December 31,
	2016		2015
	(in thousands)
ASSETS
Current assets
Accounts receivable, net	$	13,055	$	14,736
Unbilled revenue	2,736		3,506
Inventory	4,785		3,946
Other current assets	2,151		451
Total current assets of discontinued operations	22,727		22,639
Non-current assets
Property, plant and equipment, net	78,395		90,194
Goodwill	15,361		28,162
Intangible assets, net	20,212		23,041
Risk management assets	37		—
Other assets, net	27		26
Total non-current assets of discontinued operations	114,032		141,423
Total assets	$	136,759	$	164,062
LIABILITIES
Current liabilities
Accounts payable	$	5,709	$	3,148
Accrued expenses and other current liabilities	8,563		8,852
Current portion of long-term debt	47		141
Total current liabilities of discontinued operations	14,319		12,141
Non-current liabilities
Other liabilities	172		375
Total non-current liabilities of discontinued operations	172		375
Total liabilities	$	14,491	$	12,516

The following table summarizes other selected financial information related to the Propane Business:

	Year ended December 31,
	2016			2015			2014
	(in thousands)
Depreciation	$	13,108		$	14,455		$	12,298
Amortization	2,828			2,806			2,411
Capital expenditures	6,549			17,503			16,398
Other operating non-cash items
Impairment of goodwill	12,802			—			—
Loss on sale of assets	2,182			1,060			993
Unrealized (gain) loss on derivative contracts, net	(1,072		)	(11,764		)	12,691

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 in the consolidated statement of operations is summarized below:

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
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		)
Income (loss) from discontinued operations before income tax expense	(539		)	(14,951		)	333
Income tax expense	—			—			—
Net income (loss) from discontinued operations	$	(539	)	$	(14,951	)	$	333

The current and non-current assets and liabilities of the Mid-Continent Business are as follows:

	December 31,
	2015
ASSETS
Current assets
Inventory	$	2,692
Other current assets	38
Total current assets of discontinued operations	2,730
Non-current assets
Property, plant and equipment, net	5,203
Intangible assets, net	1,138
Other assets, net	303
Total non-current assets of discontinued operations	6,644
Total assets	$	9,374
LIABILITIES
Current liabilities
Accrued expenses and other current liabilities	$	640
Total current assets of discontinued operations	640
Total liabilities	$	640

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
Costs and Expenses
Cost of sales	5,254
Direct operating expenses	1,324
Corporate expenses	448
Depreciation, amortization and accretion	1,433
Loss on sale of assets, net	9,032
Total expenses	17,491
Operating loss	(9,626		)
Interest expense	(4		)
Other income	22
Loss from discontinued operations before income tax expense	$	(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.

Selected 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
Expenses	(196		)	(658		)
Impairment	—			(673		)
Loss on sale of assets	(150		)	(87		)
Income tax benefit	192			333
Loss from discontinued operations	$	(80	)	$	(611	)

We have 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.

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Concentration of Credit Risk

12 Months Ended

Dec. 31, 2016

Receivables [Abstract]

Concentration of Credit Risk

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 21% and 13%, respectively, of our consolidated revenue. In 2015, we had one such customer who accounted for 34% of our consolidated revenue. In 2014, we had two such customers who accounted for 20% and 11%, respectively, 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.

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Inventory

12 Months Ended

Dec. 31, 2016

Inventory Disclosure [Abstract]

Inventory

Inventory

Inventory consists of the following:

	December 31,
	2016		2015
	(in thousands)
Crude oil	$	1,216	$	486
NGLs	288		274
Refined products	—		232
Materials, supplies and equipment	486		303
Total inventory	$	1,990	$	1,295

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Other Current Assets

12 Months Ended

Dec. 31, 2016

Other Current Assets [Abstract]

Other Current Assets

Other Current Assets

Other current assets consists of the following:

	December 31,
	2016		2015
	(in thousands)
Prepaid insurance	$	9,702	$	5,187
Insurance receivables	1,624		84
Other receivables	2,997		2,680
Due from related parties	4,833		8,749
Risk management assets	469		365
Other assets	5,891		5,281
Total other current assets	$	25,516	$	22,346

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Risk Management Activities

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management Activities

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.

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:
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 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	$	541		$	457		$	(72	)	$	(92	)	$	469		$	365
Risk management assets - long term	10,628			—			(1		)	—			10,627			—
Total assets	$	11,169		$	457		$	(73	)	$	(92	)	$	11,096		$	365
Accrued expenses and other current liabilities	$	(253	)	$	(92	)	$	72		$	92		$	(181	)	$	—
Other liabilities	(1		)	—			1			—			—			—
Total liabilities	$	(254	)	$	(92	)	$	73		$	92		$	(181	)	$	—

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	$	(1,569	)	$	(48	)
Interest expense	(144		)	10,375
Direct operating expenses	(966		)	—
Total	$	(2,679	)	$	10,327
2015
Gains (losses) on commodity derivatives, net	$	1,632		$	(287	)
Interest expense	(425		)	373
Direct operating expenses	(913		)	—
Total	$	294		$	86
2014
Gains on commodity derivatives, net	$	734		$	357
Interest expense	(707		)	284
Direct operating expenses	(1,035		)	—
Total	$	(1,008	)	$	641

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Property, Plant and Equipment, Net

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net

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	$	18,861		$	14,118
Construction in progress	N/A	128,519			56,134
Transportation equipment	5 to 15	20,010			22,125
Buildings and improvements	4 to 40	13,762			12,121
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	146,408			144,780
Equipment	5 to 20	77,978			53,097
Total property, plant and equipment		1,331,330			1,179,972
Less accumulated depreciation		(264,722		)	(198,651		)
Property, plant and equipment, net		$	1,066,608		$	981,321

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 $69.7 million, $60.6 million and $38.6 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 $13.2 million, $15.5 million, and $14.0 million for the years ended December 31, 2016, 2015 and 2014, respectively, to present the Mid-Continent, Bakken Business and Propane 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.

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.

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Goodwill and Intangible Assets, Net

12 Months Ended

Dec. 31, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets, Net

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 forecast 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 reportable segment and Liquid Pipelines and Services reportable segment 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 $29.9 million impairment charge in our Liquid Pipelines and Services reportable segment relating to our Crude Oil Supply and Logistics business and 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 $2.7 million related to our JP Liquids business in our Liquid Pipelines and Services reportable segment. Given the market condition trend surrounding JP Liquids, we may recognize further impairments related to those assets in the future. Additionally, we recorded a goodwill impairment charge of $12.8 million in 2016 related to our Pinnacle Propane Express business which is included in net loss from discontinued operations in the consolidated statement of operations.

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

	Gas Gathering and Processing Services			Liquid Pipelines and Services			Terminalling Services		Total
	(in thousands)
Balance at January 1, 2015	$	125,974		$	146,219		$	88,466	$	360,659
Goodwill acquired during the year	—			—			—		—
Return of purchase price	(7,382		)	—			—		(7,382		)
Impairment charges	(118,592		)	(29,896		)	—		(148,488		)
Balance at December 31, 2015	—			116,323			88,466		204,789
Impairment charges	—			(2,654		)	—		(2,654		)
Balance at December 31, 2016	$	—		$	113,669		$	88,466	$	202,135

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:

	December 31,
	2016		2015		2016			2015			2016		2015
	Gross carrying amount				Accumulated amortization						Net carrying amount
	(in thousands)
Customer relationships	$	106,417	$	106,417	$	(23,245	)	$	(15,535	)	$	83,172	$	90,882
Customer contracts	94,692		94,692		(33,228		)	(24,388		)	61,464		70,304
Dedicated acreage	53,350		53,350		(4,439		)	(2,661		)	48,911		50,689
Collaborative arrangements	11,884		11,884		(601		)	—			11,283		11,884
Noncompete agreements	1,063		1,063		(1,000		)	(765		)	63		298
Other	198		198		(20		)	(16		)	178		182
	$	267,604	$	267,604	$	(62,533	)	$	(43,365	)	$	205,071	$	224,239

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 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 $19.2 million, $20.0 million and $18.4 million, respectively, which is included depreciation, amortization and accretion in the consolidated statements of operations. Amortization expense of $2.9 million, $4.0 million and $4.4 million for the years ended December 31 2016, 2015 and 2014, respectively, relating to the Mid-Continent Business, Bakken Business and Propane 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 $10.0 million to $15.6 million, with an aggregate $116.5 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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Investment in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Investment in Unconsolidated Affiliates

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:

	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.

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Accrued Expenses and Other Current Liabilities

12 Months Ended

Dec. 31, 2016

Payables and Accruals [Abstract]

Accounts Expenses and Other Current Liabilities

Accrued Expenses and Other Current Liabilities

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

	December 31,
	2016		2015
Capital expenditures	$	14,274	$	7,139
Employee compensation	8,438		6,198
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	148		1
Deferred financing costs	2,743		—
Taxes payable	1,186		1,146
Gas imbalances payable	1,098		413
Other	9,491		5,646
Total accrued expenses and other current liabilities	$	72,721	$	37,260

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

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

	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.

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Convertible Preferred Units

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Convertible Preferred Units

Convertible Preferred Units

Our convertible preferred units consist of the following:

	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.

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.

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.

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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Debt Obligations

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Debt Obligations

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		$	3,762		$	1,252,012
Less unamortized deferred financing costs and discount	—		—		(8,691		)	(2,345		)	—			(11,036		)
Subtotal	711,250		177,000		291,309			57,655			3,762			1,240,976
Less current portion	—		—		—			(1,676		)	(3,762		)	(5,438		)
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	$	3,498		$	690,598
Less current portion	—		—		(2,758		)	(2,758		)
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 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

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%

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.

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Partners' Capital

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Partners' Capital

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.

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.

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.

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.

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Net Income (Loss) per Limited Partner Unit

12 Months Ended

Dec. 31, 2016

Earnings Per Share [Abstract]

Net Income (Loss) per Limited Partner Unit

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):

	Years Ended December 31,
	2016			2015			2014
Net loss from continuing operations	$	(43,829	)	$	(199,418	)	$	(55,496	)
Less: Net income (loss) attributable to noncontrolling interests	2,766			(13		)	3,993
Net loss from continuing operations attributable to the Partnership	(46,595		)	(199,405		)	(59,489		)
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	(1,691		)	(3,498		)	(1,325		)
Net loss from continuing operations attributable to Limited Partners	(77,042		)	(221,048		)	(76,212		)
Net loss from discontinued operations attributable to Limited Partners	(4,715		)	(423		)	(14,545		)
Net loss attributable to Limited Partners	$	(81,757	)	$	(221,471	)	$	(90,757	)
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)	$	(1.51	)	$	(4.91	)	$	(2.77	)
Limited Partners' net loss from discontinued operations per unit (basic and diluted)	(0.09		)	(0.01		)	(0.52		)
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.

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Long-Term Incentive Plan

12 Months Ended

Dec. 31, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Long-Term Incentive Plan

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. 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.

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: 

	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.

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Income Taxes

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income Taxes

 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	(2,059		)	(1,237		)	(710		)
Effective income tax rate	6.3		%	1.0		%	1.6		%

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	$	(41,249	)	$	(197,533	)	$	(54,640	)
US Federal statutory tax rate	34		%	34		%	34		%
Federal income tax (expense) benefit at statutory rate	14,025			67,161			18,578
Reconciling items:
Partnership loss not subject to income tax (benefit)	(15,800		)	(68,048		)	(18,936		)
State and local tax expense	(800		)	(857		)	(459		)
Other	(5		)	(141		)	(39		)
Income tax expense	$	(2,580	)	$	(1,885	)	$	(856	)

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

	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.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 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	$	7,428	$	15,604
2018	—		806		—		—		4,507		5,313
2019	888,250		2,233		—		—		4,389		894,872
2020	—		2,299		—		—		2,670		4,969
2021	—		4,430		300,000		—		2,244		306,674
Thereafter	—		48,555		—		44,363		17,991		110,909
	$	888,250	$	60,000	$	300,000	$	50,862	$	39,229	$	1,338,341

(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 endedDecember 31, 2016, 2015 and 2014, total rental expenses were $15.9 million, $14.4 million, and $7.9 million, respectively.

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Related-Party Transactions

12 Months Ended

Dec. 31, 2016

Related Party Transactions [Abstract]

Related-Party Transactions

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 sheet 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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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2016

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

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		—			—

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Reportable Segments

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Reportable Segments

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, and Terminalling 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.

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.

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			Total
	(in thousands)
Commodity sales	$	91,444		$	304,502		$	21,999	$	6,812		$	14,655		$	439,412
Services	22,558			19,063			18,109		40,502			50,999			151,231
Gains (losses) on commodity derivatives, net	(833		)	(341		)	—		(7		)	(436		)	(1,617		)
Total Revenue	113,169			323,224			40,108		47,307			65,218			589,026
Cost of sales	63,832			293,618			21,288		3,049			11,564			393,351
Direct operating expenses	33,802			10,091			5,923		10,945			10,783			71,544
Corporate expenses															89,438
Depreciation, amortization, and accretion															90,882
Loss on sale of assets, net															688
Loss on impairment of plant, property and equipment															697
Loss on impairment of goodwill															2,654
Interest expense															21,433
Earnings in unconsolidated affiliates															(40,158		)
Other (income) expense															(254		)
Income tax expense															2,580
Income (loss) from continuing operations															(43,829		)
Loss from discontinuing operations, net of tax															(4,715		)
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		$	31,556		$	18,616	$	82,346		$	42,872

	December 31, 2015
	Gas Gathering and Processing Services		Liquid Pipelines and Services		Natural Gas Transportation Services		Offshore Pipelines and Services		Terminalling Services		Total
	(in thousands)
Commodity sales	$	107,680	$	457,448	$	23,972	$	13,798	$	10,343	$	613,241
Services	30,196		23,008		16,035		21,457		45,022		135,718
Gains (losses) on commodity derivatives, net	1,240		—		—		84		21		1,345
Total Revenue	139,116		480,456		40,007		35,339		55,386		750,304
Cost of sales	72,960		454,057		21,858		9,914		8,893		567,682
Direct operating expenses	35,250		9,912		6,728		9,425		10,414		71,729
Corporate expenses											65,327
Depreciation, amortization, and accretion											81,335
Loss on sale of assets, net											2,860
Loss on impairment of goodwill											148,488
Interest expense											20,077
Earnings in unconsolidated affiliates											(8,201		)
Other (income) expense											(1,460		)
Income tax expense											1,885
Income (loss) from continuing operations											(199,418		)
Loss from discontinuing operations, net of tax											(423		)
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	$	26,399	$	18,073	$	33,613	$	36,079

	December 31, 2014
	Gas Gathering and Processing Services		Liquid Pipelines and Services		Natural Gas Transportation Services		Offshore Pipelines and Services		Terminalling Services		Total
	(in thousands)
Commodity sales	$	148,198	$	470,936	$	70,964	$	20,044	$	11,521	$	721,663
Services	15,248		22,239		12,925		24,426		41,357		116,195
Gains (losses) on commodity derivatives, net	1,050		—		—		41		—		1,091
Total Revenue	164,496		493,175		83,889		44,511		52,878		838,949
Cost of sales	112,719		468,137		70,100		15,133		6,859		672,948
Direct operating expenses	21,197		7,209		6,975		11,142		11,525		58,048
Corporate expenses											60,465
Depreciation, amortization, and accretion											57,818
Loss on sale of assets, net											4,087
Loss on impairment of plant, property and equipment											21,344
Interest expense											16,497
Earnings in unconsolidated affiliates											(348		)
Other (income) expense											1,096
Loss on extinguishment of debt											1,634
Income tax expense											856
Income (loss) from continuing operations											(55,496		)
Loss from discontinuing operations, net of tax											(24,071		)
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	$	25,038	$	13,691	$	29,089	$	34,493

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	425,389		434,395
Natural Gas Transportation Services	221,604		146,927
Offshore Pipelines and Services	400,193		190,271
Terminalling Services	299,534		291,130
Other (1)	334,953		19,716
Discontinued operations	136,759		$	173,436
Total assets	$	2,349,321	$	1,751,889

_______________________

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

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Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

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	$	100,998		$	152,253		$	159,903		$	175,872
Total segment gross margin (1)	46,430			59,016			58,793			59,396
Operating loss	(16,097		)	(12,790		)	(9,724		)	(21,617		)
Net loss from continuing operations	(17,772		)	(12,156		)	(5,488		)	(8,413		)
Income (loss) from discontinued operations	7,169			2,675			(2,310		)	(12,249		)
Net income (loss) attributable to noncontrolling interest	(3		)	954			1,241			574
Net income (loss) attributable to the Partnership	(10,600		)	(10,435		)	(9,039		)	(21,236		)
General Partner's Interest in net income (loss)	(97		)	(107		)	(31		)	2
Limited Partners' Interest in net loss	$	(10,503	)	$	(10,328	)	$	(9,008	)	$	(21,238	)
Limited Partners' income (loss) per unit:
Loss from continuing operations	$	(0.49	)	$	(0.40	)	$	(0.29	)	$	(0.33	)
Income (loss) from discontinued operations	0.16			0.07			(0.05		)	$	(0.27	)
Net loss	$	(0.33	)	$	(0.33	)	$	(0.34	)	$	(0.60	)
Year Ended December 31, 2015
Total revenues	$	184,937		$	227,693		$	174,848		$	162,826
Total segment gross margin (1)	45,314			44,921			41,445			48,176
Operating loss	(8,785		)	(6,815		)	(11,114		)	(160,403		)
Net loss from continuing operations	(12,523		)	(11,977		)	(15,607		)	(159,311		)
Income (loss) from discontinued operations	10,596			1,575			(900		)	(11,694		)
Net income (loss) attributable to noncontrolling interest	4			22			24			(63		)
Net loss attributable to the Partnership	(1,932		)	(10,425		)	(16,532		)	(170,939		)
General Partner's Interest in net loss	(32		)	(66		)	(104		)	(1,621		)
Limited Partners' Interest in net loss	$	(1,900	)	$	(10,358	)	$	(16,428	)	$	(169,319	)
Limited Partners' income (loss) per unit:
Loss from continuing operations	$	(0.41	)	$	(0.41	)	$	(0.51	)	$	(3.58	)
Income (loss) from discontinued operations, net of tax	0.25			0.03			(0.02		)	(0.27		)
Net loss	$	(0.16	)	$	(0.38	)	$	(0.53	)	$	(3.85	)

(1) For a definition of total segment 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 $2.7 million and $148.5 million in the fourth quarters of 2016 and 2015, respectively.

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Subsequent Event

12 Months Ended

Dec. 31, 2016

Subsequent Events [Abstract]

Subsequent Event

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.

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.

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Organization and Basis of Presentation (Policies)

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of business

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 five reportable segments, (1) gas gathering and processing services, (2) liquid pipelines and services, (3) natural gas transportation services, (4) offshore pipelines and services, and (5) terminalling 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 and storing specialty chemical products and selling 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.

Basis of presentation

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.

Discontinued Operations

On September 1, 2017, we completed the disposition of the Propane Marketing Services business (the "Propane Business") pursuant to the Membership Interest Purchase Agreement dated July 21, 2017, between AMID Merger LP, a wholy owned subsidiary of the Partnership and SHV Energy N.V. Through the transaction, we divested Pinnacle Propane’s 40 service locations; Pinnacle Propane Express’ cylinder exchange business and related logistic assets; and the Alliant Gas utility system. Prior to the sale, we moved the trucking business from the Propane Marketing Services segment to the Liquid Pipelines and Services segment for all periods presented. During the years ended December 31, 2016, 2015, and 2014, the trucking business had revenues of $6.9 million, $10.3 million, and $11.3 million, respectively, which represent 5%, 6%, and 6% of total Propane Business revenue, respectively. Additionally, for the years ended December 31, 2016, 2015, and 2014, the trucking business had inter-segment revenues of $2.0 million, $2.1 million, and $3.7 million with the Propane Business that were previously eliminated in consolidation, and are now included in the total trucking business revenue, with the offsetting expenses included in discontinued operations.

In connection with the transaction, we received $170.0 million in cash and recorded a gain on the sale of $46.5 million, net of $2.5 million transaction costs. As a result of the disposition of the Propane Business, we have classified the accounts and the results of operations of the Propane Business as discontinued operations. See Note 3 for additional details.

Transactions between entities under common control

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

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.

Use of estimates

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

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

Inventory is mainly comprised of crude oil, NGLs and refined products for resale. Inventory is stated at the lower of cost or market. The cost of crude oil, NGLs, and refined products is determined using the first-in, first-out (FIFO) method.

Allowance for doubtful accounts

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.

Derivative financial instruments

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 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 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

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

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

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 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

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

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

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

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.

Commitments, contingencies and environmental liabilities

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

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

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

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

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

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.

Income taxes

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)

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

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.

New accounting pronouncements

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 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.

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Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2016

Discontinued Operations and Disposal Groups [Abstract]

Schedule of disposal groups

The following tables summarize the financial information related to the Propane Business for the corresponding years.

Consolidated Statements of Operations

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Total revenues	$	137,896		$	163,583		$	181,843
Costs and Expenses
Costs of sales	49,672			62,621			116,924
Direct operating expenses	51,828			55,751			51,495
Corporate expenses	9,992			12,508			12,279
Depreciation, amortization and accretion	15,936			17,261			14,709
Loss on sale of assets, net	2,182			1,060			993
Loss on impairment of goodwill	12,802			—			—
Total expenses	142,412			149,201			196,400
Operating (loss) income	(4,516		)	14,382			(14,557		)
Other Income(expense)
Interest expense	(36		)	(43		)	(61		)
Other income	374			272			434
Income (loss) from discontinued operations before income tax benefit (expense)	(4,178		)	14,611			(14,184		)
Income tax benefit (expense)	2			(3		)	(1		)
Net income (loss) from discontinued operations	$	(4,176	)	$	14,608		$	(14,185	)

Consolidated Balance Sheets

The current and non-current assets and liabilities of the Propane Business are as follows:

	December 31,
	2016		2015
	(in thousands)
ASSETS
Current assets
Accounts receivable, net	$	13,055	$	14,736
Unbilled revenue	2,736		3,506
Inventory	4,785		3,946
Other current assets	2,151		451
Total current assets of discontinued operations	22,727		22,639
Non-current assets
Property, plant and equipment, net	78,395		90,194
Goodwill	15,361		28,162
Intangible assets, net	20,212		23,041
Risk management assets	37		—
Other assets, net	27		26
Total non-current assets of discontinued operations	114,032		141,423
Total assets	$	136,759	$	164,062
LIABILITIES
Current liabilities
Accounts payable	$	5,709	$	3,148
Accrued expenses and other current liabilities	8,563		8,852
Current portion of long-term debt	47		141
Total current liabilities of discontinued operations	14,319		12,141
Non-current liabilities
Other liabilities	172		375
Total non-current liabilities of discontinued operations	172		375
Total liabilities	$	14,491	$	12,516

The following table summarizes other selected financial information related to the Propane Business:

	Year ended December 31,
	2016			2015			2014
	(in thousands)
Depreciation	$	13,108		$	14,455		$	12,298
Amortization	2,828			2,806			2,411
Capital expenditures	6,549			17,503			16,398
Other operating non-cash items
Impairment of goodwill	12,802			—			—
Loss on sale of assets	2,182			1,060			993
Unrealized (gain) loss on derivative contracts, net	(1,072		)	(11,764		)	12,691

Selected 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
Expenses	(196		)	(658		)
Impairment	—			(673		)
Loss on sale of assets	(150		)	(87		)
Income tax benefit	192			333
Loss from discontinued operations	$	(80	)	$	(611	)

We have 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.

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

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
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		)
Income (loss) from discontinued operations before income tax expense	(539		)	(14,951		)	333
Income tax expense	—			—			—
Net income (loss) from discontinued operations	$	(539	)	$	(14,951	)	$	333

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
Costs and Expenses
Cost of sales	5,254
Direct operating expenses	1,324
Corporate expenses	448
Depreciation, amortization and accretion	1,433
Loss on sale of assets, net	9,032
Total expenses	17,491
Operating loss	(9,626		)
Interest expense	(4		)
Other income	22
Loss from discontinued operations before income tax expense	$	(9,608	)

Blackwater

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Inventory (Tables)

12 Months Ended

Dec. 31, 2016

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventory consists of the following:

	December 31,
	2016		2015
	(in thousands)
Crude oil	$	1,216	$	486
NGLs	288		274
Refined products	—		232
Materials, supplies and equipment	486		303
Total inventory	$	1,990	$	1,295

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Detail of Certain Asset Accounts (Tables)

12 Months Ended

Dec. 31, 2016

Other Current Assets [Abstract]

Schedule of Other Current Assets

Other current assets consists of the following:

	December 31,
	2016		2015
	(in thousands)
Prepaid insurance	$	9,702	$	5,187
Insurance receivables	1,624		84
Other receivables	2,997		2,680
Due from related parties	4,833		8,749
Risk management assets	469		365
Other assets	5,891		5,281
Total other current assets	$	25,516	$	22,346

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Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

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:
Crude Oil Fixed Price (Barrels)	—	—	(93,000)	Jan 2016
Crude Oil Basis (Barrels)	180,000	Jan 2017 - Mar 2017	—	—

Derivatives and fair value

	December 31, 2016		December 31, 2015
	Notional Volume	Maturity	Notional Volume	Maturity
Commodity Swaps:
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

Fair value associated with commodity derivative instruments

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	$	541		$	457		$	(72	)	$	(92	)	$	469		$	365
Risk management assets - long term	10,628			—			(1		)	—			10,627			—
Total assets	$	11,169		$	457		$	(73	)	$	(92	)	$	11,096		$	365
Accrued expenses and other current liabilities	$	(253	)	$	(92	)	$	72		$	92		$	(181	)	$	—
Other liabilities	(1		)	—			1			—			—			—
Total liabilities	$	(254	)	$	(92	)	$	73		$	92		$	(181	)	$	—

Realized and unrealized gains (losses) with commodity and interest rate derivative instruments

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	$	(1,569	)	$	(48	)
Interest expense	(144		)	10,375
Direct operating expenses	(966		)	—
Total	$	(2,679	)	$	10,327
2015
Gains (losses) on commodity derivatives, net	$	1,632		$	(287	)
Interest expense	(425		)	373
Direct operating expenses	(913		)	—
Total	$	294		$	86
2014
Gains on commodity derivatives, net	$	734		$	357
Interest expense	(707		)	284
Direct operating expenses	(1,035		)	—
Total	$	(1,008	)	$	641

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Property, Plant and Equipment, Net (Tables)

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

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	$	18,861		$	14,118
Construction in progress	N/A	128,519			56,134
Transportation equipment	5 to 15	20,010			22,125
Buildings and improvements	4 to 40	13,762			12,121
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	146,408			144,780
Equipment	5 to 20	77,978			53,097
Total property, plant and equipment		1,331,330			1,179,972
Less accumulated depreciation		(264,722		)	(198,651		)
Property, plant and equipment, net		$	1,066,608		$	981,321

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Goodwill and Intangible Assets, Net (Tables)

12 Months Ended

Dec. 31, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

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

	Gas Gathering and Processing Services			Liquid Pipelines and Services			Terminalling Services		Total
	(in thousands)
Balance at January 1, 2015	$	125,974		$	146,219		$	88,466	$	360,659
Goodwill acquired during the year	—			—			—		—
Return of purchase price	(7,382		)	—			—		(7,382		)
Impairment charges	(118,592		)	(29,896		)	—		(148,488		)
Balance at December 31, 2015	—			116,323			88,466		204,789
Impairment charges	—			(2,654		)	—		(2,654		)
Balance at December 31, 2016	$	—		$	113,669		$	88,466	$	202,135

Schedule of finite-jived intangible assets

Intangible assets, net, consist of the following:

	December 31,
	2016		2015		2016			2015			2016		2015
	Gross carrying amount				Accumulated amortization						Net carrying amount
	(in thousands)
Customer relationships	$	106,417	$	106,417	$	(23,245	)	$	(15,535	)	$	83,172	$	90,882
Customer contracts	94,692		94,692		(33,228		)	(24,388		)	61,464		70,304
Dedicated acreage	53,350		53,350		(4,439		)	(2,661		)	48,911		50,689
Collaborative arrangements	11,884		11,884		(601		)	—			11,283		11,884
Noncompete agreements	1,063		1,063		(1,000		)	(765		)	63		298
Other	198		198		(20		)	(16		)	178		182
	$	267,604	$	267,604	$	(62,533	)	$	(43,365	)	$	205,071	$	224,239

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Investment in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Investments in and Advances to 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.

Schedule of Investments

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:

	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

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Accrued Expenses and Other Current Liabilities (Tables)

12 Months Ended

Dec. 31, 2016

Payables and Accruals [Abstract]

Schedule of accrued expenses and other current liabilities

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

	December 31,
	2016		2015
Capital expenditures	$	14,274	$	7,139
Employee compensation	8,438		6,198
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	148		1
Deferred financing costs	2,743		—
Taxes payable	1,186		1,146
Gas imbalances payable	1,098		413
Other	9,491		5,646
Total accrued expenses and other current liabilities	$	72,721	$	37,260

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Schedule of reconciliation of the beginning and ending aggregate carrying amount of ARO liabilities

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

	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.

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Convertible Preferred Units (Tables)

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Schedule of preferred units

Our convertible preferred units consist of the following:

	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

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Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Outstanding borrowings

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		$	3,762		$	1,252,012
Less unamortized deferred financing costs and discount	—		—		(8,691		)	(2,345		)	—			(11,036		)
Subtotal	711,250		177,000		291,309			57,655			3,762			1,240,976
Less current portion	—		—		—			(1,676		)	(3,762		)	(5,438		)
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	$	3,498		$	690,598
Less current portion	—		—		(2,758		)	(2,758		)
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.

Debt instrument redemption

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%

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Partners' Capital (Tables)

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Schedule for number of units outstanding

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		—		—

Distributions Made to Limited Partner, by Distribution

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

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Net Income (Loss) per Limited Partner Unit (Tables)

12 Months Ended

Dec. 31, 2016

Earnings Per Share [Abstract]

Schedule of earnings per share

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

	Years Ended December 31,
	2016			2015			2014
Net loss from continuing operations	$	(43,829	)	$	(199,418	)	$	(55,496	)
Less: Net income (loss) attributable to noncontrolling interests	2,766			(13		)	3,993
Net loss from continuing operations attributable to the Partnership	(46,595		)	(199,405		)	(59,489		)
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	(1,691		)	(3,498		)	(1,325		)
Net loss from continuing operations attributable to Limited Partners	(77,042		)	(221,048		)	(76,212		)
Net loss from discontinued operations attributable to Limited Partners	(4,715		)	(423		)	(14,545		)
Net loss attributable to Limited Partners	$	(81,757	)	$	(221,471	)	$	(90,757	)
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)	$	(1.51	)	$	(4.91	)	$	(2.77	)
Limited Partners' net loss from discontinued operations per unit (basic and diluted)	(0.09		)	(0.01		)	(0.52		)
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.

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Long-Term Incentive Plan (Tables)

12 Months Ended

Dec. 31, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of restricted stock and restricted stock units activity

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

	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

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.

Schedule of stock options, valuation assumptions

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	%

Options, grants in period, weighted average grant date fair value

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.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Schedule of components of income tax (expense) benefit

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	(2,059		)	(1,237		)	(710		)
Effective income tax rate	6.3		%	1.0		%	1.6		%

Schedule of effective income tax rate reconciliation

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	$	(41,249	)	$	(197,533	)	$	(54,640	)
US Federal statutory tax rate	34		%	34		%	34		%
Federal income tax (expense) benefit at statutory rate	14,025			67,161			18,578
Reconciling items:
Partnership loss not subject to income tax (benefit)	(15,800		)	(68,048		)	(18,936		)
State and local tax expense	(800		)	(857		)	(459		)
Other	(5		)	(141		)	(39		)
Income tax expense	$	(2,580	)	$	(1,885	)	$	(856	)

Schedule of deferred tax assets and liabilities

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

	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	)

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Future non-cancelable commitments related to certain 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	$	7,428	$	15,604
2018	—		806		—		—		4,507		5,313
2019	888,250		2,233		—		—		4,389		894,872
2020	—		2,299		—		—		2,670		4,969
2021	—		4,430		300,000		—		2,244		306,674
Thereafter	—		48,555		—		44,363		17,991		110,909
	$	888,250	$	60,000	$	300,000	$	50,862	$	39,229	$	1,338,341

(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.

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2016

Supplemental Cash Flow Elements [Abstract]

Schedule of cash flow, supplemental disclosures

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		—			—

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Reportable Segments (Tables)

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Segment information for the periods

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			Total
	(in thousands)
Commodity sales	$	91,444		$	304,502		$	21,999	$	6,812		$	14,655		$	439,412
Services	22,558			19,063			18,109		40,502			50,999			151,231
Gains (losses) on commodity derivatives, net	(833		)	(341		)	—		(7		)	(436		)	(1,617		)
Total Revenue	113,169			323,224			40,108		47,307			65,218			589,026
Cost of sales	63,832			293,618			21,288		3,049			11,564			393,351
Direct operating expenses	33,802			10,091			5,923		10,945			10,783			71,544
Corporate expenses															89,438
Depreciation, amortization, and accretion															90,882
Loss on sale of assets, net															688
Loss on impairment of plant, property and equipment															697
Loss on impairment of goodwill															2,654
Interest expense															21,433
Earnings in unconsolidated affiliates															(40,158		)
Other (income) expense															(254		)
Income tax expense															2,580
Income (loss) from continuing operations															(43,829		)
Loss from discontinuing operations, net of tax															(4,715		)
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		$	31,556		$	18,616	$	82,346		$	42,872

	December 31, 2015
	Gas Gathering and Processing Services		Liquid Pipelines and Services		Natural Gas Transportation Services		Offshore Pipelines and Services		Terminalling Services		Total
	(in thousands)
Commodity sales	$	107,680	$	457,448	$	23,972	$	13,798	$	10,343	$	613,241
Services	30,196		23,008		16,035		21,457		45,022		135,718
Gains (losses) on commodity derivatives, net	1,240		—		—		84		21		1,345
Total Revenue	139,116		480,456		40,007		35,339		55,386		750,304
Cost of sales	72,960		454,057		21,858		9,914		8,893		567,682
Direct operating expenses	35,250		9,912		6,728		9,425		10,414		71,729
Corporate expenses											65,327
Depreciation, amortization, and accretion											81,335
Loss on sale of assets, net											2,860
Loss on impairment of goodwill											148,488
Interest expense											20,077
Earnings in unconsolidated affiliates											(8,201		)
Other (income) expense											(1,460		)
Income tax expense											1,885
Income (loss) from continuing operations											(199,418		)
Loss from discontinuing operations, net of tax											(423		)
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	$	26,399	$	18,073	$	33,613	$	36,079

	December 31, 2014
	Gas Gathering and Processing Services		Liquid Pipelines and Services		Natural Gas Transportation Services		Offshore Pipelines and Services		Terminalling Services		Total
	(in thousands)
Commodity sales	$	148,198	$	470,936	$	70,964	$	20,044	$	11,521	$	721,663
Services	15,248		22,239		12,925		24,426		41,357		116,195
Gains (losses) on commodity derivatives, net	1,050		—		—		41		—		1,091
Total Revenue	164,496		493,175		83,889		44,511		52,878		838,949
Cost of sales	112,719		468,137		70,100		15,133		6,859		672,948
Direct operating expenses	21,197		7,209		6,975		11,142		11,525		58,048
Corporate expenses											60,465
Depreciation, amortization, and accretion											57,818
Loss on sale of assets, net											4,087
Loss on impairment of plant, property and equipment											21,344
Interest expense											16,497
Earnings in unconsolidated affiliates											(348		)
Other (income) expense											1,096
Loss on extinguishment of debt											1,634
Income tax expense											856
Income (loss) from continuing operations											(55,496		)
Loss from discontinuing operations, net of tax											(24,071		)
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	$	25,038	$	13,691	$	29,089	$	34,493

Reconciliation of assets from segment to consolidated

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	425,389		434,395
Natural Gas Transportation Services	221,604		146,927
Offshore Pipelines and Services	400,193		190,271
Terminalling Services	299,534		291,130
Other (1)	334,953		19,716
Discontinued operations	136,759		$	173,436
Total assets	$	2,349,321	$	1,751,889

_______________________

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

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Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Schedule of quarterly financial information

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	$	100,998		$	152,253		$	159,903		$	175,872
Total segment gross margin (1)	46,430			59,016			58,793			59,396
Operating loss	(16,097		)	(12,790		)	(9,724		)	(21,617		)
Net loss from continuing operations	(17,772		)	(12,156		)	(5,488		)	(8,413		)
Income (loss) from discontinued operations	7,169			2,675			(2,310		)	(12,249		)
Net income (loss) attributable to noncontrolling interest	(3		)	954			1,241			574
Net income (loss) attributable to the Partnership	(10,600		)	(10,435		)	(9,039		)	(21,236		)
General Partner's Interest in net income (loss)	(97		)	(107		)	(31		)	2
Limited Partners' Interest in net loss	$	(10,503	)	$	(10,328	)	$	(9,008	)	$	(21,238	)
Limited Partners' income (loss) per unit:
Loss from continuing operations	$	(0.49	)	$	(0.40	)	$	(0.29	)	$	(0.33	)
Income (loss) from discontinued operations	0.16			0.07			(0.05		)	$	(0.27	)
Net loss	$	(0.33	)	$	(0.33	)	$	(0.34	)	$	(0.60	)
Year Ended December 31, 2015
Total revenues	$	184,937		$	227,693		$	174,848		$	162,826
Total segment gross margin (1)	45,314			44,921			41,445			48,176
Operating loss	(8,785		)	(6,815		)	(11,114		)	(160,403		)
Net loss from continuing operations	(12,523		)	(11,977		)	(15,607		)	(159,311		)
Income (loss) from discontinued operations	10,596			1,575			(900		)	(11,694		)
Net income (loss) attributable to noncontrolling interest	4			22			24			(63		)
Net loss attributable to the Partnership	(1,932		)	(10,425		)	(16,532		)	(170,939		)
General Partner's Interest in net loss	(32		)	(66		)	(104		)	(1,621		)
Limited Partners' Interest in net loss	$	(1,900	)	$	(10,358	)	$	(16,428	)	$	(169,319	)
Limited Partners' income (loss) per unit:
Loss from continuing operations	$	(0.41	)	$	(0.41	)	$	(0.51	)	$	(3.58	)
Income (loss) from discontinued operations, net of tax	0.25			0.03			(0.02		)	(0.27		)
Net loss	$	(0.16	)	$	(0.38	)	$	(0.53	)	$	(3.85	)

(1) For a definition of total segment 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 $2.7 million and $148.5 million in the fourth quarters of 2016 and 2015, respectively.

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Organization and Basis of Presentation (Details) $ in Thousands			12 Months Ended
	Sep. 01, 2017 USD ($) location	Mar. 01, 2017 mi	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 28, 2016	Sep. 30, 2016
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
General partners' capital account, percentage			77.00%
Limited partners' capital account, percentage			23.00%
Services			$ 151,231	$ 135,718	$ 116,195
Depreciation, amortization and accretion expense			90,882	81,335	57,818
Earnings in unconsolidated affiliates			(40,158)	(8,201)	(348)
Net loss			(48,544)	(199,841)	(79,567)
Intangible assets, net			205,071	224,239
Investment in unconsolidated affiliates			(291,987)	(63,704)
Noncontrolling interests			16,755	12,111
Additions to property, plant and equipment			147,796	208,040	153,876
Investments in unconsolidated affiliates			(150,179)	(65,701)	(12,000)
Contributions from noncontrolling interest owners			3,366	584	0
Business exit costs			9,100
Bad debt expense			$ 1,038	$ 1,212	$ 820
Minimum
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
Useful Life (in years)			3 years
Useful life			5 years
Maximum
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
Useful Life (in years)			40 years
Useful life			30 years
8.50% Senior Notes, due 2021 | Senior Notes
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
Debt instrument, interest rate (percent)			8.50%			8.50%
3.77% Senior Notes, due 2031 | Senior Notes
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
Debt instrument, interest rate (percent)			3.77%				3.77%
Subsequent Event
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
Gathering pipeline (miles) | mi		1,172
Discontinued Operations, Disposed of by Sale [Member] | Propane Marketing Services | Subsequent Event
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
Percentage of business divested (percent)	100.00%
Cash received upon disposal	$ 170,000
Gain on sale of business	46,600
Business exit costs	$ 2,500
Propane Business [Member] | Discontinued Operations, Disposed of by Sale [Member] | Propane Marketing Services | Subsequent Event
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
Number of business locations sold | location	40

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Acquisitions and Divestitures JP Energy Partners Merger (Details) $ in Millions	Mar. 08, 2017 USD ($) business_segment shares	Dec. 31, 2016 shares	Dec. 31, 2015 shares	Dec. 31, 2014 shares
Business Acquisition [Line Items]
General partners' interest units issued (in shares)		680,000	536,000
Subsequent Event | Affiliated Holders
Business Acquisition [Line Items]
Merger agreement, conversion ratio	0.5775
Subsequent Event | Public Unit Consideration
Business Acquisition [Line Items]
Merger agreement, conversion ratio	0.5225
JPE Energy Partners | Subsequent Event
Business Acquisition [Line Items]
Number of businesses segments acquired | business_segment	3
General Partner
Business Acquisition [Line Items]
General partners' interest units issued (in shares)		143,900	143,517	206,810
General Partner | Subsequent Event
Business Acquisition [Line Items]
General partners' interest units issued (in shares)	20,200,000
Estimated fair value of common units issued | $	$ 322.2
Affiliated Entity | General Partner | Subsequent Event
Business Acquisition [Line Items]
General partners' interest units issued (in shares)	9,800,000

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Acquisitions and Divestitures Delta House Investment (Details) - USD ($) $ in Thousands				12 Months Ended
	Oct. 31, 2016	Apr. 25, 2016	Sep. 18, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Oct. 08, 2015	Sep. 15, 2015	Aug. 15, 2014	Jan. 29, 2014
Business Acquisition [Line Items]
Payments to acquire equity method investments				$ 150,179	$ 65,701	$ 12,000
Limited partners, units issued (in shares)			7,500,000	51,351,000	50,504,000		151,937	7,500,000	4,622,352	3,400,000
Investments				$ 270,742	$ 65,703	12,000
General partners' interest units issued (in shares)				680,000	536,000
Proceeds from lines of credit	$ 14,300
Pinto Offshore Holdings LLC
Business Acquisition [Line Items]
Percentage ownership			26.30%
FPS
Business Acquisition [Line Items]
Percentage ownership			49.00%	20.10%
Investments				$ 55,461	$ 40,559	0
Delta House
Business Acquisition [Line Items]
Percentage ownership				20.10%
Payments to acquire equity method investments			$ 162,000
Investments	$ 48,800	$ 9,900		$ 65,700
Acquired interest (percent)	6.20%
D-Day Offshore Holdings
Business Acquisition [Line Items]
Percentage ownership		100.00%
Pinto Offshore Holdings LLC | Delta House
Business Acquisition [Line Items]
Percentage ownership			12.90%
Arclight Affiliate | D-Day Offshore Holdings
Business Acquisition [Line Items]
Percentage ownership		1.00%
Series D
Business Acquisition [Line Items]
Issuance of units	$ 34,500			0	$ 0	$ 40,000
General partners' interest units issued (in shares)	2,333,333
General Partner
Business Acquisition [Line Items]
Partners capital account distributions, delta house				$ (96,300)
General partners' interest units issued (in shares)				143,900	143,517	206,810
Class A Units
Business Acquisition [Line Items]
Equity method investment, distribution percentage				100.00%
Class B Units
Business Acquisition [Line Items]
Equity method investment, distribution percentage				7.00%

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Acquisitions and Divestitures Emerald Transactions (Details) $ / shares in Units, $ in Thousands			12 Months Ended
	Apr. 27, 2016 USD ($) MMcf / d lateral agreement platform mi	Apr. 25, 2016 USD ($) MMcf / d lateral platform mi $ / shares shares	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Business Acquisition [Line Items]
Number of agreements | agreement	2
Payments to acquire equity method investments			$ 150,179	$ 65,701	$ 12,000
Number of platforms | platform	2	4
Number of laterals | lateral	1	6
Number of securities called by warrants (in shares) | shares		800,000
Exercise price of warrants (in dollars per share) | $ / shares		$ 7.25
Issuance of Series C Units and Warrant in connection with the Emerald Transactions		$ 120,000	120,000	0	0
Borrowings to acquire equity method investments	$ 91,000
Investments			$ 270,742	65,703	12,000
Destin
Business Acquisition [Line Items]
Ownership % at December 31, 2016		49.70%	49.70%
Length of pipeline | mi		255
Volume of natural gas, operating amount | MMcf / d		1,200
Length of offshore pipeline | mi		120
Length of onshore pipeline | mi		135
Investments			$ 122,830	0	0
Tri-States
Business Acquisition [Line Items]
Ownership % at December 31, 2016		16.70%	16.70%
Length of pipeline | mi		161
Investments			$ 56,681	0	0
Wilprise
Business Acquisition [Line Items]
Ownership % at December 31, 2016		25.30%	25.30%
Length of pipeline | mi		30
Investments			$ 5,064	0	0
Okeanos
Business Acquisition [Line Items]
Ownership % at December 31, 2016	66.70%		66.70%
Length of pipeline | mi	100
Volume of natural gas, operating amount, production | MMcf / d	1,000
Investments			$ 27,451	$ 0	$ 0
BP
Business Acquisition [Line Items]
Payments to acquire equity method investments	$ 27,400	$ 183,600
Investments	212,000
Series C Preferred Stock
Business Acquisition [Line Items]
Temporary equity, shares issued (in shares) | shares		8,571,429
BP
Business Acquisition [Line Items]
Payments to acquire equity method investments	100,900
Limited Partner
Business Acquisition [Line Items]
Partners capital account contributions, emerald	$ 1,000

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Acquisitions and Divestitures Gulf of Mexico Pipeline Narrative (Details) $ in Thousands		3 Months Ended								12 Months Ended
	Apr. 15, 2016 USD ($) mi	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Business Acquisition [Line Items]
Total revenue		$ 175,872	$ 159,903	$ 152,253	$ 100,998	$ 162,826	$ 174,848	$ 227,693	$ 184,937	$ 589,026	$ 750,304	$ 838,949
Operating loss		(21,617)	$ (9,724)	$ (12,790)	$ (16,097)	$ (160,403)	$ (11,114)	$ (6,815)	$ (8,785)	(60,228)	$ (187,117)	$ (35,761)
American Panther
Business Acquisition [Line Items]
Noncontrolling interest, ownership percentage by parent (percent)	60.00%
Length of pipeline | mi	200
Cash	$ 2,700
Pipelines	16,600
Land	400
ARO	14,300
Noncontrolling interest	$ 1,800
Total revenue										13,200
Operating loss										7,400
Transaction costs		$ 300								$ 300

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Acquisitions and Divestitures Southern Propane Inc. (Details) - USD ($) $ in Thousands		12 Months Ended
	May 08, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Acquisitions partially funded by the issuance of common units		$ 0	$ 3,442	$ 414,396
Goodwill		$ 202,135	$ 204,789	$ 360,659
Southern Propane Inc.
Business Acquisition [Line Items]
Consideration transferred	$ 16,300
Cash	12,500
Payment for final working capital adjustment	$ 100
Common units issued (shares)	266,951
Acquisitions partially funded by the issuance of common units	$ 3,400
Remaining contingent liability released in 2016	200
Goodwill	5,800
Property, plant and equipment acquired	3,000
Accounts receivable acquired	1,000
Customer relationships | Southern Propane Inc.
Business Acquisition [Line Items]
Intangible assets acquired	$ 6,200
Weighted average useful life	12 years
Other | Southern Propane Inc.
Business Acquisition [Line Items]
Intangible assets acquired	$ 300

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Acquisitions and Divestitures Costar Acquisition Narrative (Details) - USD ($) $ in Thousands		1 Months Ended	3 Months Ended		12 Months Ended
	Oct. 14, 2014	Feb. 29, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Acquisition working capital adjustment						$ 7,400
Loss on impairment of goodwill			$ 2,700	$ 148,500	$ 2,654	$ 148,488	$ 0
Costar Midstream, L.L.C.
Business Acquisition [Line Items]
Acquired interest (percent)	100.00%
Consideration transferred	$ 405,300
Loss on impairment of goodwill				$ 95,000
Interest rate swap
Business Acquisition [Line Items]
Acquisition working capital adjustment		$ 6,800
Escrowed units returned to partnership (in shares)		1,034,483
Payments for previous acquisition		$ 300

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Acquisitions and Divestitures Lavaca Acquisition Narrative (Details) $ in Thousands		3 Months Ended		12 Months Ended
	Jan. 31, 2014 USD ($) mi	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Business Acquisition [Line Items]
Loss on impairment of goodwill		$ 2,700	$ 148,500	$ 2,654	$ 148,488	$ 0
Lavaca
Business Acquisition [Line Items]
Length of pipeline | mi	120
Cash	$ 104,400
Crude Oil Supply and Logistics Business
Business Acquisition [Line Items]
Loss on impairment of goodwill			118,600
Crude Oil Supply and Logistics Business | Lavaca
Business Acquisition [Line Items]
Loss on impairment of goodwill			$ 23,600

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Acquisitions and Divestitures JP Development (Details) - Common Control Acquisition $ in Millions	Feb. 12, 2014 USD ($) shares
Business Acquisition [Line Items]
Consideration transferred	$ 319.1
Common units issued (shares) | shares	5,841,205
Cash	$ 52.0
Related amounts receivable forgiven by ArcLight	$ 4.3

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Discontinued Operations - Narrative (Details) $ in Thousands			3 Months Ended	12 Months Ended
	Sep. 01, 2017 USD ($) location	Feb. 12, 2016 USD ($)	Jun. 30, 2014 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on impairment of noncurrent assets held for sale				$ 0	$ 0	$ 673
Business exit costs				9,100
Propane Marketing Services | Discontinued Operations, Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on sale of assets				2,182	1,060	993
Impairment of goodwill				12,802	0	0
Mid-Continental
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from divestiture of business		$ 9,700
Loss on sale of assets					(12,900)
Impairment of goodwill				$ 0	$ 12,909	0
Bakken Business
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase price of disposal group			$ 9,100
Loss on sale of assets			(7,300)			7,288
Impairment of goodwill			$ 2,000
Blackwater
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on impairment of noncurrent assets held for sale						$ 700
Subsequent Event | Propane Marketing Services
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from divestiture of business	$ 170,000
Subsequent Event | Propane Marketing Services | Discontinued Operations, Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of business divested (percent)	100.00%
Cash received upon disposal	$ 170,000
Gain on sale of business	46,600
Business exit costs	$ 2,500
Subsequent Event | Propane Business [Member] | Propane Marketing Services | Discontinued Operations, Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of business locations sold | location	40

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Discontinued Operations - Income Statement (Details) - USD ($) $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
(Loss) income from discontinued operations before income tax expense	$ (12,249)	$ (2,310)	$ 2,675	$ 7,169	$ (11,694)	$ (900)	$ 1,575	$ 10,596		$ (4,715)	$ (423)	$ (24,071)
Mid-Continental
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues										11,495	429,784	967,480
Costs of sales										11,687	426,886	961,428
Direct operating expenses										203	2,269	2,866
Depreciation, amortization and accretion										211	2,281	2,258
(Gain) loss on sale of assets, net										(114)	119	229
Loss on impairment of goodwill and assets held for sale										0	(12,909)	0
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										0	0	0
Net (loss) income from discontinued operations										(539)	(14,951)	333
Bakken Business
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues												7,865
Loss on impairment of goodwill and assets held for sale									$ (2,000)
(Loss) income from discontinued operations before income tax expense												(9,608)
Blackwater
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues											74	474
(Loss) income from discontinued operations before income tax expense											(80)	(611)
Discontinued Operations, Disposed of by Sale [Member] | Propane Marketing Services
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues										137,896	163,583	181,843
Costs of sales										49,672	62,621	116,924
Direct operating expenses										51,828	55,751	51,495
Corporate expenses										9,992	12,508	12,279
Depreciation, amortization and accretion										15,936	17,261	14,709
(Gain) loss on sale of assets, net										2,182	1,060	993
Loss on impairment of goodwill and assets held for sale										(12,802)	0	0
Total expenses										142,412	149,201	196,400
Operating (loss) income										(4,516)	14,382	(14,557)
Interest expense										(36)	(43)	(61)
Other income (expense)										374	272	434
(Loss) income from discontinued operations before income tax expense										(4,178)	14,611	(14,184)
Income tax expense										2	(3)	(1)
Net (loss) income from discontinued operations										$ (4,176)	$ 14,608	$ (14,185)

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Discontinued Operations - Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total current assets of discontinued operations	$ 22,727	$ 25,369
Total non-current assets of discontinued operations	114,032	148,067
Total current liabilities of discontinued operations	14,319	12,781
Total non-current liabilities of discontinued operations	172	375
Propane Marketing Services | Discontinued Operations, Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable, net	13,055	14,736
Unbilled revenue	2,736	3,506
Inventory	4,785	3,946
Other current assets	2,151	451
Total current assets of discontinued operations	22,727	22,639
Property, plant and equipment, net	78,395	90,194
Goodwill	15,361	28,162
Intangible assets, net	20,212	23,041
Risk management assets	37	0
Other assets, net	27	26
Total non-current assets of discontinued operations	114,032	141,423
Accounts payable	5,709	3,148
Accrued expenses and other current liabilities	8,563	8,852
Current portion of long-term debt	47	141
Total current liabilities of discontinued operations	14,319	12,141
Other liabilities	172	375
Total non-current liabilities of discontinued operations	$ 172	$ 375

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Discontinued Operations - Selected Financial Information (Details) - Propane Marketing Services - Discontinued Operations, Disposed of by Sale [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Depreciation	$ 13,108	$ 14,455	$ 12,298
Amortization	2,828	2,806	2,411
Capital expenditures	6,549	17,503	16,398
Impairment of goodwill	12,802	0	0
Loss on sale of assets	2,182	1,060	993
Unrealized (gain) loss on derivative contracts, net	$ (1,072)	$ (11,764)	$ 12,691

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Concentration of Credit Risk (Details) - Sales Revenue, Net - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Customer A
Revenue, Major Customer
Entity-wide revenue by major customer, percentage	21.00%
Customer B
Revenue, Major Customer
Entity-wide revenue by major customer, percentage	13.00%
Customer C
Revenue, Major Customer
Entity-wide revenue by major customer, percentage		34.00%
Customer D
Revenue, Major Customer
Entity-wide revenue by major customer, percentage			20.00%
Customer E [Member]
Revenue, Major Customer
Entity-wide revenue by major customer, percentage			11.00%

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Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Crude oil	$ 1,216	$ 486
NGLs	288	274
Refined products	0	232
Materials, supplies and equipment	486	303
Total inventory	$ 1,990	$ 1,295

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Detail of Certain Asset Accounts (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Other current assets
Prepaid insurance	$ 9,702	$ 5,187
Insurance receivables	1,624	84
Other receivables	2,997	2,680
Due from related parties	4,833	8,749
Risk management assets	469	365
Other assets	5,891	5,281
Total Other current assets	$ 25,516	$ 22,346

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Risk Management Activities (Commodity Derivatives) (Details) - Crude Oil - Commodity Contract - bbl	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative notional volume	180,000,000	0
Fixed Price
Derivative [Line Items]
Derivative notional volume	0	(93,000,000)

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Risk Management Activities (Interest Rate Swap) (Details) - Interest rate swap $ in Thousands	Dec. 31, 2016 USD ($)
Derivative [Line Items]
Fair Value, Asset	$ 10,376
January 3, 2017 thru September 3, 2019
Derivative [Line Items]
Notional Amount	200,000
Fair Value, Asset	1,912
January 1, 2017 thru December 31, 2017
Derivative [Line Items]
Notional Amount	100,000
Fair Value, Liability	(71)
January 1, 2018 thru January 31, 2019
Derivative [Line Items]
Notional Amount	100,000
Fair Value, Asset	226
January 1, 2018 thru December 31, 2021
Derivative [Line Items]
Notional Amount	100,000
Fair Value, Asset	3,090
January 1, 2018 thru December 31, 2022
Derivative [Line Items]
Notional Amount	150,000
Fair Value, Asset	$ 5,219

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Risk Management Activities (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Amortization of weather derivative premium	$ 966	$ 912	$ 1,035
Weather Contract
Derivative [Line Items]
Derivative instruments not designated as hedging instruments, potential cash proceeds from Contract	30,000
Payments of derivative issuance costs	$ 1,000	900
Term of Contract	1 year
Amortization of weather derivative premium	$ 400	$ 400

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Risk Management Activities (Fair Value of Commodity Derivatives) (Details) - Commodity derivative instruments, net - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative asset, gross derivative asset	$ 11,169	$ 457
Derivative asset, gross derivative liabilities	(73)	(92)
Derivative asset, fair value, net	11,096	365
Derivative liability, gross derivative assets	(254)	(92)
Derivative liability, gross derivative liabilities	73	92
Derivative liability, fair value, net	(181)	0
Other current assets
Derivative [Line Items]
Derivative asset, gross derivative asset	541	457
Derivative asset, gross derivative liabilities	(72)	(92)
Derivative asset, fair value, net	469	365
Risk management assets - long term
Derivative [Line Items]
Derivative asset, gross derivative asset	10,628	0
Derivative asset, gross derivative liabilities	(1)	0
Derivative asset, fair value, net	10,627	0
Accrued expenses and other current liabilities
Derivative [Line Items]
Derivative liability, gross derivative assets	(253)	(92)
Derivative liability, gross derivative liabilities	72	92
Derivative liability, fair value, net	(181)	0
Other liabilities
Derivative [Line Items]
Derivative liability, gross derivative assets	(1)	0
Derivative liability, gross derivative liabilities	1	0
Derivative liability, fair value, net	$ 0	$ 0

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Risk Management Activities (Realized and Unrealized Gains (Losses)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Loss on commodity derivatives, net	$ (1,617)	$ 1,345	$ 1,091
Commodity derivative instruments, net
Derivatives, Fair Value [Line Items]
Loss on commodity derivatives, net	(2,679)	294	(1,008)
Gain (loss) on derivatives, unrealized	10,327	86	641
Commodity derivative instruments, net | Losses on commodity derivatives, net
Derivatives, Fair Value [Line Items]
Loss on commodity derivatives, net	(1,569)	1,632	734
Gain (loss) on derivatives, unrealized	(48)	(287)	357
Commodity derivative instruments, net | Interest expense
Derivatives, Fair Value [Line Items]
Loss on commodity derivatives, net	(144)	(425)	(707)
Gain (loss) on derivatives, unrealized	10,375	373	284
Commodity derivative instruments, net | Direct operating expenses
Derivatives, Fair Value [Line Items]
Loss on commodity derivatives, net	(966)	(913)	(1,035)
Gain (loss) on derivatives, unrealized	$ 0	$ 0	$ 0

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Fair Value Measurement (Details Textual)	Dec. 31, 2016	Sep. 30, 2016
3.77% Senior Notes, due 2031 | Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate (percent)	3.77%	3.77%

XML

Property, Plant and Equipment, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	$ 1,331,330	$ 1,179,972
Less accumulated depreciation	(264,722)	(198,651)
Property, plant and equipment, net	1,066,608	981,321
Land
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	18,861	14,118
Construction in progress
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	128,519	56,134
Transportation Equipment
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	20,010	22,125
Buildings and improvements
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	13,762	12,121
Processing and treating plants
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	120,977	102,111
Pipelines and compressors
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	804,815	775,486
Storage
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	146,408	144,780
Equipment
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	$ 77,978	53,097
Minimum
Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	3 years
Minimum | Transportation Equipment
Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	5 years
Minimum | Buildings and improvements
Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	4 years
Minimum | Processing and treating plants
Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	8 years
Minimum | Pipelines and compressors
Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	3 years
Minimum | Storage
Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	3 years
Minimum | Equipment
Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	5 years
Maximum
Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	40 years
Maximum | Transportation Equipment
Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	15 years
Maximum | Buildings and improvements
Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	40 years
Maximum | Processing and treating plants
Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	40 years
Maximum | Pipelines and compressors
Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	40 years
Maximum | Storage
Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	40 years
Maximum | Equipment
Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	20 years
Ala Tenn System
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	$ 291,100	$ 228,900

XML

Property, Plant and Equipment, Net (Asset Impairments and Insurance Proceeds) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property plant and equipment gross		$ 1,331,330	$ 1,179,972
Depreciation		69,700	60,600	$ 38,600
Interest costs capitalized		2,700	1,900	800
Loss on impairment of property, plant and equipment	$ 21,300	697	0	21,344
Discount rate	9.50%
Ala Tenn System
Property, Plant and Equipment [Line Items]
Property plant and equipment gross		291,100	228,900
Adjustment
Property, Plant and Equipment [Line Items]
Depreciation		$ 13,200	$ 15,500	$ 14,000

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Goodwill and Intangible Assets, Net (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Line Items]
Loss on impairment of goodwill	$ 2,700	$ 148,500	$ 2,654	$ 148,488	$ 0
Amortization of intangible assets			19,200	20,000	18,400
Thereafter	116,500		116,500
Net unamortized intangible asset	205,071	224,239	$ 205,071	224,239
Minimum
Goodwill [Line Items]
Useful life			5 years
2017	10,000		$ 10,000
2018	10,000		10,000
2019	10,000		10,000
2020	10,000		10,000
2021	10,000		$ 10,000
Maximum
Goodwill [Line Items]
Useful life			30 years
2017	15,600		$ 15,600
2018	15,600		15,600
2019	15,600		15,600
2020	15,600		15,600
2021	15,600		15,600
Costar Midstream, L.L.C.
Goodwill [Line Items]
Loss on impairment of goodwill		95,000
Adjustment
Goodwill [Line Items]
Amortization of intangible assets			2,900	4,000	4,400
Customer relationships
Goodwill [Line Items]
Impairment of intangible assets				700
Net unamortized intangible asset	83,172	90,882	83,172	90,882
Customer contracts
Goodwill [Line Items]
Impairment of intangible assets					$ 8,100
Net unamortized intangible asset	61,464	70,304	$ 61,464	70,304
Storage Tank Leasing Arrangement
Goodwill [Line Items]
Optional renewal term of long-term contract			2 years
Storage Tank Leasing Arrangement | Customer relationships
Goodwill [Line Items]
Net unamortized intangible asset	$ 10,000		$ 10,000
Liquid Pipelines and Services
Goodwill [Line Items]
Loss on impairment of goodwill			2,654	$ 29,896
Crude Oil Supply and Logistics Business
Goodwill [Line Items]
Loss on impairment of goodwill		118,600
Crude Oil Supply and Logistics Business | Costar Midstream, L.L.C.
Goodwill [Line Items]
Loss on impairment of goodwill		95,000
Crude Oil Supply and Logistics Business | Lavaca
Goodwill [Line Items]
Loss on impairment of goodwill		23,600
Crude Oil Supply and Logistics Business | Liquid Pipelines and Services
Goodwill [Line Items]
Loss on impairment of goodwill		$ 29,900
JP Liquids Business | Propane Marketing Services
Goodwill [Line Items]
Loss on impairment of goodwill			$ 2,700

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Goodwill and Intangible Assets, Net Schedule of Goodwill Activity (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Roll Forward]
Goodwill beginning balance			$ 204,789	$ 360,659
Goodwill acquired during the year				0
Return of purchase price				(7,382)
Impairment charges	$ (2,700)	$ (148,500)	(2,654)	(148,488)	$ 0
Goodwill ending balance	202,135	204,789	202,135	204,789	360,659
Gas Gathering and Processing Equipment [Member]
Goodwill [Roll Forward]
Goodwill beginning balance			0	125,974
Goodwill acquired during the year				0
Return of purchase price				(7,382)
Impairment charges			0	(118,592)
Goodwill ending balance	0	0	0	0	125,974
Liquid Pipelines and Services
Goodwill [Roll Forward]
Goodwill beginning balance			116,323	146,219
Goodwill acquired during the year				0
Return of purchase price				0
Impairment charges			(2,654)	(29,896)
Goodwill ending balance	113,669	116,323	113,669	116,323	146,219
Terminalling Services
Goodwill [Roll Forward]
Goodwill beginning balance			88,466	88,466
Goodwill acquired during the year				0
Return of purchase price				0
Impairment charges			0	0
Goodwill ending balance	$ 88,466	$ 88,466	$ 88,466	$ 88,466	$ 88,466

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Goodwill and Intangible Assets, Net Schedule of intangible assets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	$ 267,604	$ 267,604
Accumulated amortization	(62,533)	(43,365)
Net carrying amount	205,071	224,239
Customer relationships
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	106,417	106,417
Accumulated amortization	(23,245)	(15,535)
Net carrying amount	83,172	90,882
Customer contracts
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	94,692	94,692
Accumulated amortization	(33,228)	(24,388)
Net carrying amount	61,464	70,304
Dedicated acreage
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	53,350	53,350
Accumulated amortization	(4,439)	(2,661)
Net carrying amount	48,911	50,689
Collaborative arrangements
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	11,884	11,884
Accumulated amortization	(601)	0
Net carrying amount	11,283	11,884
Noncompete agreements
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	1,063	1,063
Accumulated amortization	(1,000)	(765)
Net carrying amount	63	298
Other
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	198	198
Accumulated amortization	(20)	(16)
Net carrying amount	$ 178	$ 182

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Investment in Unconsolidated Affiliates - Activity in Partnership's Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Thousands	8 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 27, 2016	Apr. 25, 2016	Sep. 18, 2015
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Equity method investments		$ 63,704	$ 10,368	$ 0
Investments		270,742	65,703	12,000
Earnings in unconsolidated affiliates		40,158	8,201	348
Contributions		429	0	0
Distributions		(83,046)	(20,568)	(1,980)
Equity method investments	$ 291,987	$ 291,987	63,704	10,368
FPS
Schedule of Equity Method Investments [Line Items]
Ownership % at December 31, 2016	20.10%	20.10%					49.00%
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Equity method investments		$ 33,465	0	0
Investments		55,461	40,559	0
Earnings in unconsolidated affiliates		21,022	5,457	0
Contributions		0	0	0
Distributions		(45,465)	(12,551)	0
Equity method investments	$ 64,483	$ 64,483	33,465	0
OGL
Schedule of Equity Method Investments [Line Items]
Ownership % at December 31, 2016	20.10%	20.10%
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Equity method investments		$ 23,060	0	0
Investments		3,255	25,144	0
Earnings in unconsolidated affiliates		9,260	2,013	0
Contributions		0	0	0
Distributions		(10,125)	(4,097)	0
Equity method investments	$ 25,450	$ 25,450	23,060	0
Destin
Schedule of Equity Method Investments [Line Items]
Ownership % at December 31, 2016	49.70%	49.70%				49.70%
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Equity method investments		$ 0	0	0
Investments		122,830	0	0
Earnings in unconsolidated affiliates	$ 3,946	3,946	0	0
Contributions		0	0	0
Distributions		(15,894)	0	0
Equity method investments	$ 110,882	$ 110,882	0	0
Tri-States
Schedule of Equity Method Investments [Line Items]
Ownership % at December 31, 2016	16.70%	16.70%				16.70%
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Equity method investments		$ 0	0	0
Investments		56,681	0	0
Earnings in unconsolidated affiliates	$ 1,633	1,633	0	0
Contributions		0	0	0
Distributions		(3,292)	0	0
Equity method investments	$ 55,022	$ 55,022	0	0
Okeanos
Schedule of Equity Method Investments [Line Items]
Ownership % at December 31, 2016	66.70%	66.70%			66.70%
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Equity method investments		$ 0	0	0
Investments		27,451	0	0
Earnings in unconsolidated affiliates	$ 3,642	3,642	0	0
Contributions		0	0	0
Distributions		(4,034)	0	0
Equity method investments	$ 27,059	$ 27,059	0	0
Wilprise
Schedule of Equity Method Investments [Line Items]
Ownership % at December 31, 2016	25.30%	25.30%				25.30%
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Equity method investments		$ 0	0	0
Investments		5,064	0	0
Earnings in unconsolidated affiliates	$ 437	437	0	0
Contributions		0	0	0
Distributions		(557)	0	0
Equity method investments	$ 4,944	$ 4,944	0	0
MPOG
Schedule of Equity Method Investments [Line Items]
Ownership % at December 31, 2016	66.70%	66.70%
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Equity method investments		$ 7,179	10,368	0
Investments		0	0	12,000
Earnings in unconsolidated affiliates		218	731	348
Contributions		429	0	0
Distributions		(3,679)	(3,920)	(1,980)
Equity method investments	$ 4,147	$ 4,147	$ 7,179	$ 10,368

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- Financial Information for the Partnership's Equity Investments (Balance Sheets) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
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

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Investment in Unconsolidated Affiliates - Financial Information for the Partnership's Equity Investments (Statement of Operations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Revenues	$ 370,263	$ 235,041	$ 102,290
Operating expenses	99,084	90,453	72,775
Net income	$ 261,200	$ 135,083	$ 28,173

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Investment in Unconsolidated Affiliates - Emerald transactions (Details) - USD ($) $ in Thousands	8 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 27, 2016	Apr. 25, 2016
Schedule of Equity Method Investments [Line Items]
Revenues		$ 370,263	$ 235,041	$ 102,290
Net income		261,200	135,083	28,173
Earnings in unconsolidated affiliates		$ 40,158	8,201	348
Destin
Schedule of Equity Method Investments [Line Items]
Revenues	$ 34,360
Net income	$ 8,272
Ownership % at December 31, 2016	49.70%	49.70%				49.70%
Partnership share of investee net income	$ 4,109
Basis difference amortization	(163)	$ (163)
Earnings in unconsolidated affiliates	3,946	$ 3,946	0	0
Tri-States
Schedule of Equity Method Investments [Line Items]
Revenues	25,557
Net income	$ 15,983
Ownership % at December 31, 2016	16.70%	16.70%				16.70%
Partnership share of investee net income	$ 2,664
Basis difference amortization	(1,031)	$ (1,031)
Earnings in unconsolidated affiliates	1,633	$ 1,633	0	0
Okeanos
Schedule of Equity Method Investments [Line Items]
Revenues	10,453
Net income	$ 1,911
Ownership % at December 31, 2016	66.70%	66.70%			66.70%
Partnership share of investee net income	$ 1,274
Basis difference amortization	2,368	$ 2,368
Earnings in unconsolidated affiliates	3,642	$ 3,642	0	0
Wilprise
Schedule of Equity Method Investments [Line Items]
Revenues	3,306
Net income	$ 2,028
Ownership % at December 31, 2016	25.30%	25.30%				25.30%
Partnership share of investee net income	$ 513
Basis difference amortization	(76)	$ (76)
Earnings in unconsolidated affiliates	$ 437	$ 437	$ 0	$ 0

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Accrued Expenses and Other Current Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Payables and Accruals [Abstract]
Capital expenditures	$ 14,274	$ 7,139
Employee compensation	8,438	6,198
Convertible preferred unit distributions	7,103	0
Current portion of asset retirement obligation	6,499	6,822
Accrued interest	5,743	1,838
Additional Blackwater acquisition consideration	5,000	0
Due to related parties	4,072	3,894
Royalties payable	3,926	4,163
Transaction costs	3,000	0
Customer deposits	148	1
Deferred financing costs	2,743	0
Taxes payable	1,186	1,146
Recoverable gas costs	0	0
Gas imbalances payable	1,098	413
Other	9,491	5,646
Accrued expenses and other current liabilities	$ 72,721	$ 37,260

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of period	$ 35,371	$ 34,645
Liabilities assumed	14,542	0
Revision in estimate	230	0
Expenditures	(858)	(91)
Accretion expense	1,577	817
Balance at end of period	50,862	35,371
Less: current portion	6,499	6,822
Noncurrent asset retirement obligation	44,363	28,549
Restricted cash - long term	323,564	$ 5,037
Assets Retirement Obligation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Restricted cash - long term	5,000
American Panther
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities assumed	$ 14,300

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Debt Obligations (Outstanding Borrowings) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 28, 2016	Sep. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Balance	$ 1,252,012			$ 690,598
Less unamortized deferred financing costs and discount	(11,036)
Subtotal	1,240,976
Less current portion	(5,438)			(2,758)
Non-current portion	1,235,538			687,840
Senior Notes | 8.50% Senior Notes, due 2021
Debt Instrument [Line Items]
Balance	300,000
Less unamortized deferred financing costs and discount	(8,691)
Subtotal	291,309
Less current portion	0
Non-current portion	$ 291,309
Debt instrument, interest rate (percent)	8.50%	8.50%
Senior Notes | 3.77% Senior Notes, due 2031
Debt Instrument [Line Items]
Balance	$ 60,000
Less unamortized deferred financing costs and discount	(2,345)
Subtotal	57,655
Less current portion	(1,676)
Non-current portion	$ 55,979
Debt instrument, interest rate (percent)	3.77%		3.77%
Other Debt
Debt Instrument [Line Items]
Balance	$ 3,762			3,498
Less unamortized deferred financing costs and discount	0
Subtotal	3,762
Less current portion	(3,762)			(2,758)
Non-current portion	0			740
Revolving Credit Facility | AMID Revolving Credit Agreement
Debt Instrument [Line Items]
Balance	711,250			525,100
Less unamortized deferred financing costs and discount	0
Subtotal	711,250
Less current portion	0			0
Non-current portion	711,250			525,100
Revolving Credit Facility | JPE Revolving Credit Agreement
Debt Instrument [Line Items]
Balance	177,000			162,000
Less unamortized deferred financing costs and discount	0
Subtotal	177,000
Less current portion	0			0
Non-current portion	$ 177,000			$ 162,000

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Partners' Capital (Units Outstanding) (Details) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Increase (Decrease) in Partners' Capital [Roll Forward]
Partners' capital account, beginning balance	$ 169,712
Paid in kind unit distributions	138,685	$ 118,762	$ 137,775
Partners' capital account, ending balance	$ 334,090	$ 169,712
Series A
Increase (Decrease) in Partners' Capital [Roll Forward]
Partners' capital account, beginning balance (in shares)	9,210	5,745	5,279
Partners' capital account, beginning balance	$ 169,712	$ 107,965	$ 94,811
Issuance of units (in shares)	0	2,571	0
Issuance of units	$ 0	$ 44,769	$ 0
Paid in kind unit distributions	$ 19,123	$ 16,978	$ 15,812
Partners' capital account, ending balance (in shares)	10,107	9,210	5,745
Partners' capital account, ending balance	$ 181,386	$ 169,712	$ 107,965
Series C
Increase (Decrease) in Partners' Capital [Roll Forward]
Partners' capital account, beginning balance (in shares)	0	0	0
Partners' capital account, beginning balance	$ 0	$ 0	$ 0
Issuance of units (in shares)	8,571	0	0
Issuance of units	$ 115,457	$ 0	$ 0
Paid in kind unit distributions	$ 9,487	$ 0	$ 0
Partners' capital account, ending balance (in shares)	8,792	0	0
Partners' capital account, ending balance	$ 118,229	$ 0	$ 0
Series D
Increase (Decrease) in Partners' Capital [Roll Forward]
Partners' capital account, beginning balance (in shares)	0	0	0
Partners' capital account, beginning balance	$ 0	$ 0	$ 0
Issuance of units (in shares)	2,333	0	0
Issuance of units	$ 34,475	$ 0	$ 0
Paid in kind unit distributions	$ 963	$ 0	$ 2,436
Partners' capital account, ending balance (in shares)	2,333	0	0
Partners' capital account, ending balance	$ 34,475	$ 0	$ 0
Paid-in-kind units
Increase (Decrease) in Partners' Capital [Roll Forward]
Paid in kind unit distributions	$ 14,446	$ 18,351	$ 17,810
Paid-in-kind units | Series A
Increase (Decrease) in Partners' Capital [Roll Forward]
Paid in kind unit distributions (in shares)	897	894	466
Paid in kind unit distributions	$ 11,674	$ 16,978	$ 13,154
Paid-in-kind units | Series C
Increase (Decrease) in Partners' Capital [Roll Forward]
Paid in kind unit distributions (in shares)	221	0	0
Paid in kind unit distributions	$ 2,772	$ 0	$ 0
Paid-in-kind units | Series D
Increase (Decrease) in Partners' Capital [Roll Forward]
Paid in kind unit distributions (in shares)	0	0	0
Paid in kind unit distributions	$ 0	$ 0	$ 0

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Convertible Preferred Units Series A-1 Convertible Preferred Units (Details) - USD ($) $ / shares in Units, $ in Thousands			12 Months Ended
	Dec. 31, 2016	Apr. 15, 2013	Dec. 31, 2016	Apr. 25, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Issuance of Series C Units and Warrant in connection with the Emerald Transactions	$ 120,000		$ 120,000	$ 120,000	$ 0	$ 0
Series A
Class of Stock [Line Items]
Partnership cancellation of subordinated units (percent)		90.00%
Partners' capital account (in shares)	10,107,000	5,142,857	10,107,000		9,210,000	5,745,000	5,279,000
Partners' capital account (in dollars per share)		$ 0.50
Shares issued upon conversion (in shares)		1
Investment options, exercise price (in dollars per share)	$ 15.87		$ 15.87
Series A | High Point
Class of Stock [Line Items]
Issuance of Series C Units and Warrant in connection with the Emerald Transactions		$ 15,000

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Debt Obligations Credit Agreement (Details) $ in Millions			12 Months Ended
	Apr. 25, 2016 USD ($)	Feb. 12, 2014 USD ($)	Dec. 31, 2016 USD ($)	Mar. 08, 2017 USD ($)	Sep. 30, 2016	Dec. 31, 2015 USD ($)	Dec. 31, 2014
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity	$ 750.0
Line of credit facility, maximum borrowing capacity upon increase	$ 900.0
Unused capacity, commitment fee percentage	0.50%
Ratio of indebtedness to net capital			4.07
Interest coverage ratio			7.43
Debt, weighted average interest rate			4.29%			3.67%	3.80%
Letters of credit outstanding amount			$ 7.4			$ 1.8
Revolving credit facility			711.3
Line of credit facility, remaining borrowing capacity			$ 31.3
Minimum
Debt Instrument [Line Items]
Interest coverage ratio			2.5
Maximum
Debt Instrument [Line Items]
Ratio of indebtedness to net capital			4.75
Ratio of indebtedness to net capital, after allowed acquisition			5.25
Federal Funds
Debt Instrument [Line Items]
Debt instrument, interest rate (percent)	0.50%
Eurodollar
Debt Instrument [Line Items]
Debt instrument, interest rate (percent)	1.00%
Senior Notes | 3.77% Senior Notes, due 2031
Debt Instrument [Line Items]
Debt instrument, interest rate (percent)			3.77%		3.77%
Interest coverage ratio			1.20
Fiscal Quarter Ending December 31, 2014 | Fourth Amendment | Base Rate | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate	2.00%
Fiscal Quarter Ending December 31, 2014 | Fourth Amendment | Base Rate | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate	3.25%
Fiscal Quarter Ending December 31, 2014 | Fourth Amendment | Eurodollar | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate	1.00%
Fiscal Quarter Ending December 31, 2014 | Fourth Amendment | Eurodollar | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate	2.25%
Subsequent Event
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity upon increase				$ 1,100.0
Line of credit facility, maximum borrowing capacity				$ 900.0
Revolving Credit Facility | JPE Revolving Credit Agreement
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity		$ 275.0
Revolving Credit Facility | JPE Revolving Credit Agreement | Federal Funds
Debt Instrument [Line Items]
Basis spread on variable rate		0.50%
Revolving Credit Facility | JPE Revolving Credit Agreement | Adjusted LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate		1.00%
Revolving Credit Facility | JPE Revolving Credit Agreement | Prime
Debt Instrument [Line Items]
Basis spread on variable rate		1.25%
Revolving Credit Facility | JPE Revolving Credit Agreement | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate		2.25%
Letter of Credit | JPE Revolving Credit Agreement
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity		$ 100.0

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Convertible Preferred Units Series A-2 Convertible Preferred Units (Details) - Series A-2 - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Jul. 27, 2015
Class of Stock [Line Items]
Issuance of units			$ 45.0
Investment options, exercise price (in dollars per share)	$ 15.87	$ 17.50
Call right defined acquisition, value				$ 100.0
Magnolia Infrastructure Partners, LLC | Issuance of Preferred Units
Class of Stock [Line Items]
Partners' capital account, units, sold in private placement (in shares)			2,571,430

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Debt Obligations 8.50% Senior Notes (Details) - USD ($) $ in Millions		24 Months Ended
	Dec. 28, 2016	Dec. 14, 2018	Dec. 31, 2016
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt	$ 294.0
Debt issuance costs	(6.0)
Additional debt issuance costs	$ (2.7)
Senior Notes | 8.50% Senior Notes, due 2021
Debt Instrument [Line Items]
Debt instrument, interest rate (percent)	8.50%		8.50%
Proceeds from issuance of senior long-term debt	$ 291.3
Debt instrument, redemption price, percentage	108.50%
Scenario, Forecast | Senior Notes | 8.50% Senior Notes, due 2021
Debt Instrument [Line Items]
Debt instrument, redemption price, equity offer period		180 days
Scenario, Forecast | Senior Notes | 8.50% Senior Notes, due 2021 | Maximum
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage of principal amount redeemed		35.00%
Scenario, Forecast | Senior Notes | 8.50% Senior Notes, due 2021 | Minimum
Debt Instrument [Line Items]
Debt instrument, redemption price, aggregate principal amount outstanding		65.00%

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Convertible Preferred Units Series C (Details) - USD ($) $ / shares in Units, $ in Millions			12 Months Ended
	Dec. 31, 2016	Apr. 25, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 25, 2017
Class of Stock [Line Items]
Number of securities called by warrants (in shares)		800,000
Exercise price of warrants (in dollars per share)		$ 7.25
Series C
Class of Stock [Line Items]
Issuance of units (in shares)			8,571,000	0	0
Investment options, exercise price (in dollars per share)	$ 13.95	$ 14.00
Number of securities called by warrants (in shares)		800,000
Exercise price of warrants (in dollars per share)		$ 7.25
Warrant, exercisable period		7 years	7 years
Fair value of warrant unit (in dollars per share)	$ 4.41		$ 4.41
Expected dividend rate			18.00%
Expected volatility rate			42.00%
Issuance and exercise of warrants			$ 4.5
Scenario, Forecast | Series C
Class of Stock [Line Items]
Number of units in warrant calculation (in shares)						400,000
Stipulated deduction in warrant calculation						$ 45.0
Issuance of Preferred Units | ArcLight | Series C
Class of Stock [Line Items]
Issuance of units (in shares)		8,571,429

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Debt Obligations Debt Instrument, Redemption Price (Details) - Senior Notes - 8.50% Senior Notes, due 2021	Dec. 28, 2016
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage	108.50%
2018
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage	104.25%
2019
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage	102.125%
2020 and thereafter
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage	100.00%

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Convertible Preferred Units Series D (Details) - $ / shares	Dec. 31, 2016	Oct. 31, 2016	Apr. 25, 2016	Dec. 31, 2015	Oct. 08, 2015	Sep. 18, 2015	Sep. 15, 2015	Aug. 15, 2014	Jan. 29, 2014
Class of Stock [Line Items]
Limited partners, units issued (in shares)	51,351,000			50,504,000	151,937	7,500,000	7,500,000	4,622,352	3,400,000
Number of securities called by warrants (in shares)			800,000
Exercise price of warrants (in dollars per share)			$ 7.25
Series D
Class of Stock [Line Items]
Limited partners, units issued (in shares)		2,333,333
Shares issued (in dollars per share)		$ 15.00
Units issued, closing fee		1.50%
Number of securities called by warrants (in shares)		700,000
Exercise price of warrants (in dollars per share)	$ 14.98	$ 22.00
Partners' capital account (in dollars per share)	$ 0.4125
Shares issued upon conversion (in shares)	1
Series D call right, ratio multiplier		1.03

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Debt Obligations 3.77% Senior Notes (Details)	Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 28, 2016 USD ($)
Debt Instrument [Line Items]
Debt issuance costs			$ 6,000,000
Restricted cash and investments		$ 24,500,000
Interest coverage ratio		7.43
Senior Notes | 3.77% Senior Notes, due 2031
Debt Instrument [Line Items]
Debt instrument	$ 60,000,000.0
Debt instrument, interest rate (percent)	3.77%	3.77%
Repayments, average quarterly principal payment	$ 1,100,000
Proceeds from debt	57,700,000
Debt issuance costs	$ 2,300,000
Interest coverage ratio		1.20
Debt instrument, fair value		$ 54,600,000

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Partners' Capital Outstanding Units (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
General Partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Partners' capital account, beginning balance (in shares)	536	392	185
Issuance of units (in shares)	144	144	207
Partners' capital account, ending balance (in shares)	680	536	392
Limited Partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Partners' capital account, beginning balance (in shares)	50,504	42,640	13,394
Issuance of units (in shares)	248	7,654	23,025
Redemption / return of escrow units (in shares)	(1,034)
Conversion, Exercise of units, warrants (in shares)	1,350	152	300
Issuance of common units in JP Development transaction (in shares)			5,841
Partners' capital account, ending balance (in shares)	51,351	50,504	42,640
Limited Partner | Long Term Incentive Plan
Increase (Decrease) in Partners' Capital [Roll Forward]
Issuance of units (in shares)	283	58	80
Series B
Increase (Decrease) in Partners' Capital [Roll Forward]
Partners' capital account, beginning balance (in shares)	1,350	1,255	0
Issuance of units (in shares)		95	87
Conversion, Exercise of units, warrants (in shares)	(1,350)
Partners' capital account, ending balance (in shares)	0	1,350	1,255
Series D
Increase (Decrease) in Partners' Capital [Roll Forward]
Partners' capital account, beginning balance (in shares)	0	0	0
Issuance of units (in shares)	2,333	0	0
Issuance of units (in shares)			1,008
Redemption / return of escrow units (in shares)			(1,008)
Partners' capital account, ending balance (in shares)	2,333	0	0
Okeanos
Increase (Decrease) in Partners' Capital [Roll Forward]
Issuance of units (in shares)	1,168

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Partners' Capital Textual (Details)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
General partner interest	1.30%
Limited partner interest	98.70%

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Partners' Capital Series B Units (Details) - USD ($) $ in Millions		12 Months Ended
	Jan. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Feb. 01, 2016	Oct. 08, 2015	Sep. 18, 2015	Sep. 15, 2015	Aug. 15, 2014	Jan. 29, 2014
Class of Stock [Line Items]
Limited partners, units issued (in shares)		50,504,000		51,351,000		151,937	7,500,000	7,500,000	4,622,352	3,400,000
Series B
Class of Stock [Line Items]
Limited partners, units issued (in shares)	1,168,225
Fair value, paid in kind distributions		$ 1.4	$ 2.2
Series B
Class of Stock [Line Items]
Issuance of units	$ 30.0
Shares issued upon conversion (in shares)					1
Dividend Paid | Series B
Class of Stock [Line Items]
Limited partners, units issued (in shares)		94,923	86,461

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Partners' Capital Equity Offerings (Details) - USD ($)										3 Months Ended	12 Months Ended
	Oct. 08, 2015	Sep. 15, 2015	Oct. 14, 2014	Oct. 07, 2014	Oct. 07, 2014	Aug. 15, 2014	Mar. 28, 2014	Feb. 12, 2014	Jan. 29, 2014	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Feb. 29, 2016	Sep. 18, 2015
Class of Stock [Line Items]
Aggregate offering price											$ 100,000,000
Partners' capital account, units, sold in public offering (in shares)											248,561
Proceeds from issuance of common units, net											$ 2,900,000
Limited partners' offering costs											300,000
Authorized amount remaining											$ 96,800,000
Limited partners, units issued (in shares)	151,937	7,500,000				4,622,352			3,400,000		51,351,000	50,504,000			7,500,000
Sale of stock (in dollars per share)	$ 11.31	$ 11.31				$ 25.8074999481			$ 26.75
Issuance of common units, net of offering costs	$ 1,700,000	$ 81,000,000				$ 119,300,000			$ 86,900,000
Acquisitions partially funded by the issuance of common units											$ 0	$ 3,442,000	$ 414,396,000
Distribution declared per common unit (in dollars per share)											$ 3.01	$ 3.17	$ 1.85
Paid in kind unit distributions											$ 138,685,000	$ 118,762,000	$ 137,775,000
Limited partner interest											98.70%
Limited Partner
Class of Stock [Line Items]
Issuance of common units, net of offering costs												85,465,000	609,707,000
Paid in kind unit distributions											$ 101,561,000	$ 93,622,000	$ 114,612,000
Partners' Capital Account, Units, Converted											1,350,000	152,000	300,000
Limited Partner | Costar Midstream, L.L.C.
Class of Stock [Line Items]
Common units issued (shares)			6,892,931
Acquisitions partially funded by the issuance of common units			$ 147,300,000.0
Interest rate swap
Class of Stock [Line Items]
Escrowed units returned to partnership (in shares)														1,034,483
Common Units | IPO
Class of Stock [Line Items]
Partners' capital account, units, sold in public offering (in shares)				7,940,625						13,750,000.000
Proceeds from issuance of common units, net				$ 252,700,000
Partners' Capital Account, Sale of Units, Price per Unit				$ 34.63
Existing Common Units
Class of Stock [Line Items]
Partners Capital Units Resulting from Unit Split				22,700,000
Existing Common Units | Prior To Closing Of I P O
Class of Stock [Line Items]
Partners Capital Units Resulting from Unit Split					11,848,735
Lonestar Midstream Holdings L L C [Member] | Class A Common Unit
Class of Stock [Line Items]
Proceeds from issuance of common units, net								$ 8,000,000
Limited partners, units issued (in shares)								190,000
Preferred Units Series D
Class of Stock [Line Items]
Redemption of outstanding units				$ 42,400,000
Preferred Units Series D | Lonestar Midstream Holdings L L C [Member]
Class of Stock [Line Items]
Limited partners, units issued (in shares)							1,008,000
Proceeds from issuance of preferred units							$ 40,000,000

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Partners' Capital General Partner Units (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
General partners' capital account, period distribution amount	$ 2.0	$ 1.9	$ 5.7
General partners' interest units issued (in shares)	680,000	536,000
General Partner
Class of Stock [Line Items]
General partners' interest units issued (in shares)	143,900	143,517	206,810

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Partners' Capital Distributions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Paid in kind unit distributions	$ 138,685	$ 118,762	$ 137,775
Series A
Class of Stock [Line Items]
Paid in kind unit distributions	19,123	16,978	15,812
Series B
Class of Stock [Line Items]
Paid in kind unit distributions	0	1,373	2,220
Series C
Class of Stock [Line Items]
Paid in kind unit distributions	9,487	0	0
Series D
Class of Stock [Line Items]
Paid in kind unit distributions	963	0	2,436
Limited Partner
Class of Stock [Line Items]
Paid in kind unit distributions	101,561	93,622	114,612
General Partner
Class of Stock [Line Items]
Paid in kind unit distributions	7,551	6,789	2,695
Paid
Class of Stock [Line Items]
Paid in kind unit distributions	112,136	100,411	119,965
Paid | Series A
Class of Stock [Line Items]
Paid in kind unit distributions	4,935	0	2,658
Paid | Series C
Class of Stock [Line Items]
Paid in kind unit distributions	3,089	0	0
Paid | Limited Partner
Class of Stock [Line Items]
Paid in kind unit distributions	101,561	93,622	114,612
Paid | General Partner
Class of Stock [Line Items]
Paid in kind unit distributions	2,551	6,789	2,695
Accrued
Class of Stock [Line Items]
Paid in kind unit distributions	7,103	0	0
Accrued | Series A
Class of Stock [Line Items]
Paid in kind unit distributions	2,514	0	0
Accrued | Series C
Class of Stock [Line Items]
Paid in kind unit distributions	3,626	0	0
Accrued | Limited Partner
Class of Stock [Line Items]
Paid in kind unit distributions	0	0	0
Paid-in-kind units
Class of Stock [Line Items]
Paid in kind unit distributions	14,446	18,351	17,810
Paid-in-kind units | Series A
Class of Stock [Line Items]
Paid in kind unit distributions	11,674	16,978	13,154
Paid-in-kind units | Series B
Class of Stock [Line Items]
Paid in kind unit distributions	0	1,373	2,220
Paid-in-kind units | Series C
Class of Stock [Line Items]
Paid in kind unit distributions	2,772	0	0
Paid-in-kind units | Series D
Class of Stock [Line Items]
Paid in kind unit distributions	0	0	0
Accrued | General Partner
Class of Stock [Line Items]
Paid in kind unit distributions	0	0	0
Additional Blackwater acquisition consideration
Class of Stock [Line Items]
Paid in kind unit distributions	5,000	0	0
Additional Blackwater acquisition consideration | General Partner
Class of Stock [Line Items]
Paid in kind unit distributions	5,000	0	0
American Midstream Partners L. P. | Accrued | Series D
Class of Stock [Line Items]
Paid in kind unit distributions	963	0	0
JPE Energy Partners | Paid-in-kind units | Series D
Class of Stock [Line Items]
Paid in kind unit distributions	$ 0	$ 0	$ 2,436

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Partners' Capital Distributions Textual (Details) - $ / shares		3 Months Ended	12 Months Ended
	Jan. 26, 2017	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Distribution declared per common unit (in dollars per share)			$ 3.01	$ 3.17	$ 1.85
Discount rate		9.50%
Fair Value input, distribution growth rate			1.00%
Subsequent Event
Class of Stock [Line Items]
Distribution declared per common unit (in dollars per share)	$ 0.4125
Distribution made to limited partner (in dollars per share)	$ 1.65
Minimum
Class of Stock [Line Items]
Fair value input, option value (in dollars per share)			$ 0.02
Discount rate			5.57%
Maximum
Class of Stock [Line Items]
Fair value input, option value (in dollars per share)			$ 9.68
Discount rate			10.00%

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Net Income (Loss) per Limited Partner Unit (Details) $ / shares in Units, $ in Thousands				3 Months Ended									12 Months Ended
	Mar. 08, 2017 shares	Dec. 31, 2016 shares	Oct. 07, 2014 shares	Dec. 31, 2016 USD ($) $ / shares shares	Sep. 30, 2016 USD ($) $ / shares	Jun. 30, 2016 USD ($) $ / shares	Mar. 31, 2016 USD ($) $ / shares	Dec. 31, 2015 USD ($) $ / shares shares	Sep. 30, 2015 USD ($) $ / shares	Jun. 30, 2015 USD ($) $ / shares	Mar. 31, 2015 USD ($) $ / shares	Dec. 31, 2014 shares	Dec. 31, 2016 USD ($) $ / shares shares	Dec. 31, 2015 USD ($) $ / shares shares	Dec. 31, 2014 USD ($) $ / shares shares
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
General partners' interest units outstanding (in shares) | shares		680,000		680,000				536,000					680,000	536,000
Limited partner interest													98.70%
General partners' interest units issued (in shares) | shares		680,000		680,000				536,000					680,000	536,000
Partners' capital account, units, sold in public offering (in shares) | shares													248,561
Net loss from continuing operations				$ (8,413)	$ (5,488)	$ (12,156)	$ (17,772)	$ (159,311)	$ (15,607)	$ (11,977)	$ (12,523)		$ (43,829)	$ (199,418)	$ (55,496)
Less: Net income (loss) attributable to noncontrolling interests				$ 574	$ 1,241	$ 954	$ (3)	$ (63)	$ 24	$ 22	$ 4		2,766	(13)	3,993
Net loss from continuing operations attributable to the Partnership													(46,595)	(199,405)	(59,489)
Distributions on Units													19,138	16,978	14,492
Distributions													138,685	118,762	137,775
Net income (loss) from continuing operations attributable to JPE preferred units													0	0	656
Net income (loss) from continuing operations attributable to predecessor capital													0	0	(2,014)
General partner's share in undistributed loss													(1,691)	(3,498)	(1,325)
Net loss from continuing operations attributable to Limited Partners													(77,042)	(221,048)	(76,212)
Net income (loss) from discontinued operations attributable to Limited Partners													(4,715)	(423)	(14,545)
Net loss attributable to Limited Partners													$ (81,757)	$ (221,471)	$ (90,757)
Weighted average number of common units used in computation of Limited Partners' net loss per common unit - basic and diluted (in shares) | shares													51,176,000	45,050,000	27,524,000
Limited Partners' net loss from continuing operations per unit (basic and diluted) (in dollars per share) | $ / shares				$ (0.33)	$ (0.29)	$ (0.40)	$ (0.49)	$ (3.58)	$ (0.51)	$ (0.41)	$ (0.41)
Loss from continuing operations, basic and diluted (in usd per share) | $ / shares													$ (1.51)	$ (4.91)	$ (2.77)
Loss from discontinued operations, basic and diluted (in usd per share) | $ / shares				(0.27)	(0.05)	0.07	0.16	(0.27)	(0.02)	0.03	0.25		(0.09)	(0.01)	(0.52)
Limited partners’ net income (loss) per unit (basic and diluted) (in dollars per share) | $ / shares				$ (0.60)	$ (0.34)	$ (0.33)	$ (0.33)	$ (3.85)	$ (0.53)	$ (0.38)	$ (0.16)		$ (1.60)	$ (4.92)	$ (3.29)
Series C Preferred Stock
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Distributions on Units													$ 9,487	$ 0	$ 0
Series D
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Distributions on Units													963	0	0
Series B
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Distributions on Units													$ 0	$ 1,373	$ 2,220
General Partner
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
General partners' interest units issued (in shares) | shares		143,900		143,900				143,517				206,810	143,900	143,517	206,810
Distributions													$ 7,551	$ 6,789	$ 2,695
General Partner | Dividend Declared
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Distributions													$ 2,550	$ 6,790	$ 2,694
JPE Energy Partners
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
General partners' interest units outstanding (in shares) | shares		36,700,000		36,700,000									36,700,000
ArcLight
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
General partners' interest units outstanding (in shares) | shares		18,700,000		18,700,000									18,700,000
Limited partner interest		50.90%
Other Unitholders
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
General partners' interest units outstanding (in shares) | shares		18,000,000		18,000,000									18,000,000
Limited partner interest		49.10%
Subsequent Event
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Partners' Capital Account, Units, Converted | shares	20,200,000.0
Subsequent Event | General Partner
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
General partners' interest units issued (in shares) | shares	20,200,000
Subsequent Event | ArcLight
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Partners Capital Account Common Units Conversion Ratio	0.5225
Partners' Capital Account, Units, Converted | shares	9,800,000.0
Subsequent Event | Other Unitholders
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Partners Capital Account Common Units Conversion Ratio	0.5775
Partners' Capital Account, Units, Converted | shares	10,400,000.0
Existing Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Partners Capital Units Resulting from Unit Split | shares			22,700,000
IPO | Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Partners' capital account, units, sold in public offering (in shares) | shares			7,940,625									13,750,000.000

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Long Term Incentive Plan (Textual) (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended			3 Months Ended	12 Months Ended
	Sep. 30, 2016	Aug. 31, 2016	Dec. 31, 2015	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Feb. 11, 2016	Nov. 30, 2015	Dec. 31, 2013
Subsequent Event [Line Items]
Long-term incentive plan, increase in available awards (in shares)								6,000,000
Long term incentive plan available for future grant (in shares)			15,484		5,017,528	15,484	688,976
Grants issued under long term incentive plan					25.00%
Granted (in shares)		30,000	200,000		75,000	200,000
Award vesting period			3 years
Equity compensation expense					$ 3,600	$ 3,800	$ 1,500
Total fair value of vested units					2,400	2,600	1,400
Compensation cost not yet recognized					$ 4,200
Weighted average period cost recognized					2 years 2 months 12 days
Aggregate intrinsic value, nonvested			$ 4,609		$ 22,674	$ 4,609	$ 3,964			$ 2,045
Granted (in dollars per share)			$ 7.50		$ 13.13	$ 7.50
Options, outstanding, weighted average exercise price (in dollars per share)		$ 12.00	$ 7.50		$ 9.03	$ 7.50	$ 0.00
Compensation not yet recognized, stock options					$ 200
Performance Shares
Subsequent Event [Line Items]
Equity compensation expense					900	$ 500
Compensation cost not yet recognized					100
Aggregate intrinsic value, nonvested					$ 1,500
Operating Expense | Performance Shares
Subsequent Event [Line Items]
Equity compensation expense				$ 1,000
Aggregate intrinsic value, nonvested									$ 2,000
September 2016
Subsequent Event [Line Items]
Granted (in shares)	45,000
Options, outstanding, weighted average exercise price (in dollars per share)	$ 13.88			$ 13.88
Award vesting rights	25.00%
JPE 2014 Long-Term Incentive Plan (“JPE LTIP”) | Phantom Units
Subsequent Event [Line Items]
Long term incentive plan available for future grant (in shares)					3,642,700
Equity compensation expense					$ 1,700	$ 800

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Long-Term Incentive Plan (Unit-based Awards) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding shares (in shares)	569,759	201,132	75,529
Granted (in shares)	1,374,226	546,329	188,946
Forfeited (in shares)	(411,794)	(31,298)	(12,009)
Vested (in shares)	(286,348)	(146,404)	(51,334)
Outstanding shares (in shares)	1,245,843	569,759	201,132
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Intrinsic Value, Amount Per Share [Abstract]
Outstanding shares (in dollars per share)	$ 13.15	$ 19.85	$ 17.62
Granted (in dollars per share)	2.14	12.25	20.80
Forfeited (in dollars per share)	(2.60)	(15.62)	(18.28)
Vested (in dollars per share)	(12.18)	(18.47)	(20.89)
Outstanding shares (in dollars per share)	$ 4.72	$ 13.15	$ 19.85
Aggregate intrinsic value, nonvested	$ 22,674	$ 4,609	$ 3,964	$ 2,045
JPE 2014 Long-Term Incentive Plan (“JPE LTIP”) | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding shares (in shares)	226,979,000	0
Granted (in shares)	209,507,000	287,750,000
Forfeited (in shares)	(55,778,000)	(4,766,000)
Vested (in shares)	(67,716,000)	(56,005,000)
Outstanding shares (in shares)	312,992,000	226,979,000	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Intrinsic Value, Amount Per Share [Abstract]
Outstanding shares (in dollars per share)	$ 22.5	$ 0.00
Granted (in dollars per share)	9.23	22.25
Forfeited (in dollars per share)	(19.51)	(22.34)
Vested (in dollars per share)	(18.74)	(21.23)
Outstanding shares (in dollars per share)	$ 14.96	$ 22.5	$ 0.00

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Long-Term Incentive Plan Assumptions (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Weighted average common unit price volatility	61.10%	47.00%
Expected distribution yield	12.60%	26.30%
Weighted average expected term (in years)	4 years 1 month 6 days	3 years 6 months
Weighted average risk-free rate	1.10%	1.30%

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Long-Term Incentive Plan Option Grant Awards (Details) - USD ($) $ / shares in Units, $ in Thousands			1 Months Ended		12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Aug. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]
Outstanding beginning balance (in shares)					200,000	0
Granted (in shares)			30,000	200,000	75,000	200,000
Vested (in shares)					0	0
Forfeited (in shares)					0	0
Outstanding ending balance (in shares)	275,000	200,000		200,000	275,000	200,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Outstanding beginning balance (in dollars per share)					$ 7.50	$ 0.00
Granted (in dollars per share)				$ 7.50	13.13	7.50
Vested (in dollars per share)					0.00	0.00
Forfeited (in dollars per share)					0.00	0.00
Outstanding ending balance (in dollars per share)	$ 9.03	$ 7.50	$ 12.00	7.50	9.03	7.50
Weighted-Average Grant Date Fair Value per Unit (in dollars per share)	$ 0.96	$ 0.33		$ 0.33	0.96	0.33	$ 0.00
Weighted-Average Grant Date Fair Value per Unit (in dollars per share)					$ 2.65	$ 0.33
Aggregate Intrinsic Value	$ 2,522	$ 118		$ 118	$ 2,522	$ 118	$ 0
Weighted Average Remaining Contractual Life	4 years 11 months 23 days	4 years 2 months 12 days

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Income Taxes Income Tax (Expense) Benefit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Current income tax expense	$ (521)	$ (648)	$ (146)
Deferred income tax expense	$ (2,059)	$ (1,237)	$ (710)
Effective income tax rate	6.30%	1.00%	1.60%

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Income Taxes Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
US Federal statutory tax rate	34.00%	34.00%	34.00%
Operating Loss Carryforwards	$ 16.1

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Income Taxes Income Tax Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Net income (loss) before income tax expense	$ (41,249)	$ (197,533)	$ (54,640)
US Federal statutory tax rate	34.00%	34.00%	34.00%
Federal income tax (expense) benefit at statutory rate	$ 14,025	$ 67,161	$ 18,578
Partnership loss not subject to income tax (benefit)	(15,800)	(68,048)	(18,936)
State and local tax expense	(800)	(857)	(459)
Other	(5)	(141)	(39)
Income tax expense	$ (2,580)	$ (1,885)	$ (856)

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Income Taxes Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 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)

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Commitments and Contingencies (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Business exit costs	$ 9.1
Rental expenses	$ 15.9	$ 14.4	$ 7.9

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Commitments and Contingencies (Contractual Obligations) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 28, 2016	Sep. 30, 2016
Future Non Cancelable Commitment [Line Items]
2017	$ 15,604
2018	5,313
2019	894,872
2020	4,969
2021	306,674
Thereafter	110,909
Total	1,338,341
Asset Retirement Obligation (2)
Future Non Cancelable Commitment [Line Items]
2017	6,499
2018	0
2019	0
2020	0
2021	0
Thereafter	44,363
Total	50,862
Other
Future Non Cancelable Commitment [Line Items]
2017	7,428
2018	4,507
2019	4,389
2020	2,670
2021	2,244
Thereafter	17,991
Total	39,229
Revolving Credit Agreements
Future Non Cancelable Commitment [Line Items]
2017	0
2018	0
2019	888,250
2020	0
2021	0
Thereafter	0
Total	888,250
Senior Notes | 8.50% Senior Notes (1)
Future Non Cancelable Commitment [Line Items]
2017	0
2018	0
2019	0
2020	0
2021	300,000
Thereafter	0
Total	$ 300,000
Debt instrument, interest rate (percent)	8.50%	8.50%
Senior Notes | 3.77% Senior Notes
Future Non Cancelable Commitment [Line Items]
2017	$ 1,677
2018	806
2019	2,233
2020	2,299
2021	4,430
Thereafter	48,555
Total	$ 60,000
Debt instrument, interest rate (percent)	3.77%		3.77%

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Related- Party Transactions (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2016	Apr. 15, 2016	Dec. 31, 2013
Related Party Transaction [Line Items]
Corporate expenses	$ 89,438,000	$ 65,327,000	$ 60,465,000
Direct operating expenses	71,544,000	71,729,000	58,048,000
Proceeds from issuance of common units, net	2,900,000
American Panther
Related Party Transaction [Line Items]
Noncontrolling interest, ownership percentage by parent (percent)					60.00%
Mid Continent Business
Related Party Transaction [Line Items]
Direct operating expenses	400,000	6,000,000	8,900,000
American Midstream, LLC
Related Party Transaction [Line Items]
Administrative and operational service expenses	89,800,000	98,300,000	95,500,000
General Partner
Related Party Transaction [Line Items]
Revenue from related parties	7,500,000	3,000,000
General Partner | Accrued Expenses and Other Current Liabilities
Related Party Transaction [Line Items]
Due to related party	3,900,000	3,800,000
Affiliated Entity
Related Party Transaction [Line Items]
Management fees revenue	800,000	1,400,000	900,000
Revenue from related parties	3,200,000	3,000,000
Affiliated Entity | Services
Related Party Transaction [Line Items]
Revenue from related parties	3,200,000	2,200,000
Affiliated Entity | Commodity sales
Related Party Transaction [Line Items]
Revenue from related parties		800,000
Affiliated Entity | Other current assets
Related Party Transaction [Line Items]
Net receivable from related party	2,100,000	700,000
Affiliated Entity | American Panther
Related Party Transaction [Line Items]
Corporate expenses	400,000
Direct operating expenses	800,000
Fees incurred	$ 1,200,000
Affiliated Entity | American Panther
Related Party Transaction [Line Items]
Noncontrolling interest, ownership percentage by parent (percent)	60.00%
Affiliated Entity | Destin and Okeanos Pipelines
Related Party Transaction [Line Items]
Management fees revenue	$ 400,000
Transaction expenses	1,000,000
J P Energy Development L P
Related Party Transaction [Line Items]
Management fees revenue	100,000	600,000	600,000
Monthly fee	50,000
Net receivable from related party		7,900,000
ArcLight
Related Party Transaction [Line Items]
Related party transaction, purchases from related party	2,400,000	2,600,000
Blackwater
Related Party Transaction [Line Items]
Range of outcomes						$ 5,000,000
Accrued expenses				$ 5,000,000
Vice President | CIMA Energy Ltd
Related Party Transaction [Line Items]
Revenue from related parties	3,600,000	6,200,000	10,100,000
Related party transaction, purchases from related party	$ 4,300,000	$ 5,900,000	$ 3,700,000

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Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 25, 2016
Class of Stock [Line Items]
Interest payments, net of capitalized interest	$ 22,303	$ 16,540	$ 13,905
Cash paid for taxes	530	450	108
Increase (decrease) in accrued property, plant and equipment purchases	8,533	(21,841)	35,018
Contributions from general partner	7,500	4,350	0
Acquisitions partially funded by the issuance of common units	0	3,442	414,396
Assets acquired under capital lease	139	0	177
Issuance of Series C Units and Warrant in connection with the Emerald Transactions	120,000	0	0	$ 120,000
Accrued distributions	7,103	0	0
Series C Preferred Stock
Class of Stock [Line Items]
Accrued distributions	14,446	16,978	13,154
Limited Partner Series B Convertible Units
Class of Stock [Line Items]
Paid-in-kind distributions	0	1,373	2,220
JPE Series D Units
Class of Stock [Line Items]
Paid-in-kind distributions	0	0	2,436
Costar Midstream, L.L.C.
Class of Stock [Line Items]
Accrued distributions	5,000	0	0
Cancellation of escrow units	$ 6,817	$ 0	$ 0

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Reportable Segments (Details) - USD ($) $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment information
Commodity Sales										$ 439,412	$ 613,241	$ 721,663
Services										151,231	135,718	116,195
Loss on commodity derivatives, net										(1,617)	1,345	1,091
Total revenue	$ 175,872	$ 159,903	$ 152,253	$ 100,998	$ 162,826	$ 174,848	$ 227,693	$ 184,937		589,026	750,304	838,949
Cost of sales										393,351	567,682	672,948
Direct operating expenses										71,544	71,729	58,048
Corporate expenses										89,438	65,327	60,465
Depreciation, amortization and accretion expense										90,882	81,335	57,818
Loss on sale of assets, net										688	2,860	4,087
Loss on impairment of property, plant and equipment									$ 21,300	697	0	21,344
Loss on impairment of goodwill	2,700				148,500					2,654	148,488	0
Interest expense										21,433	20,077	16,497
Earnings in unconsolidated affiliates										(40,158)	(8,201)	(348)
Other (income) expense										(254)	(1,460)	1,096
Loss on extinguishment of debt										0	0	1,634
Income tax (expense) benefit										2,580	1,885	856
Loss from continuing operations	(8,413)	(5,488)	(12,156)	(17,772)	(159,311)	(15,607)	(11,977)	(12,523)		(43,829)	(199,418)	(55,496)
Loss from discontinued operations, net of tax	(12,249)	(2,310)	2,675	7,169	(11,694)	(900)	1,575	10,596		(4,715)	(423)	(24,071)
Net income (loss)										(48,544)	(199,841)	(79,567)
Net income (loss) attributable to noncontrolling interests	574	1,241	954	(3)	(63)	24	22	4		2,766	(13)	3,993
Net loss attributable to the Partnership	(21,236)	(9,039)	(10,435)	(10,600)	(170,939)	(16,532)	(10,425)	(1,932)		(51,310)	(199,828)	(83,560)
Gross margin	$ 59,396	$ 58,793	$ 59,016	$ 46,430	$ 48,176	$ 41,445	$ 44,921	$ 45,314
Liquid Pipelines and Services
Segment information
Loss on impairment of goodwill										2,654	29,896
Terminalling Services
Segment information
Loss on impairment of goodwill										0	0
Commodity derivative instruments, net
Segment information
Loss on commodity derivatives, net										(2,679)	294	(1,008)
Gain (loss) on derivatives, unrealized										10,327	86	641
Losses on commodity derivatives, net | Commodity derivative instruments, net
Segment information
Loss on commodity derivatives, net										(1,569)	1,632	734
Gain (loss) on derivatives, unrealized										(48)	(287)	357
Segment assets: | Gathering and Processing reporting segment [Member]
Segment information
Commodity Sales										91,444	107,680	148,198
Services										22,558	30,196	15,248
Loss on commodity derivatives, net										(833)	1,240	1,050
Total revenue										113,169	139,116	164,496
Cost of sales										63,832	72,960	112,719
Direct operating expenses										33,802	35,250	21,197
Gross margin										48,245	65,692	51,213
Segment assets: | Liquid Pipelines and Services
Segment information
Commodity Sales										304,502	457,448	470,936
Services										19,063	23,008	22,239
Loss on commodity derivatives, net										(341)	0	0
Total revenue										323,224	480,456	493,175
Cost of sales										293,618	454,057	468,137
Direct operating expenses										10,091	9,912	7,209
Gross margin										31,556	26,399	25,038
Segment assets: | Natural Gas Transportation Services
Segment information
Commodity Sales										21,999	23,972	70,964
Services										18,109	16,035	12,925
Loss on commodity derivatives, net										0	0	0
Total revenue										40,108	40,007	83,889
Cost of sales										21,288	21,858	70,100
Direct operating expenses										5,923	6,728	6,975
Gross margin										18,616	18,073	13,691
Segment assets: | Offshore Pipelines and Services
Segment information
Commodity Sales										6,812	13,798	20,044
Services										40,502	21,457	24,426
Loss on commodity derivatives, net										(7)	84	41
Total revenue										47,307	35,339	44,511
Cost of sales										3,049	9,914	15,133
Direct operating expenses										10,945	9,425	11,142
Gross margin										82,346	33,613	29,089
Segment assets: | Terminalling Services
Segment information
Commodity Sales										14,655	10,343	11,521
Services										50,999	45,022	41,357
Loss on commodity derivatives, net										(436)	21	0
Total revenue										65,218	55,386	52,878
Cost of sales										11,564	8,893	6,859
Direct operating expenses										10,783	10,414	11,525
Gross margin										$ 42,872	$ 36,079	$ 34,493

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Reportable Segments Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Total assets	$ 2,349,321	$ 1,751,889
Segment assets: | Gas Gathering and Processing Services
Segment Reporting Information [Line Items]
Total assets	530,889	496,014
Segment assets: | Liquid Pipelines and Services
Segment Reporting Information [Line Items]
Total assets	425,389	434,395
Segment assets: | Natural Gas Transportation Services
Segment Reporting Information [Line Items]
Total assets	221,604	146,927
Segment assets: | Offshore Pipelines and Services
Segment Reporting Information [Line Items]
Total assets	400,193	190,271
Segment assets: | Terminalling Services
Segment Reporting Information [Line Items]
Total assets	299,534	291,130
Other (1)
Segment Reporting Information [Line Items]
Total assets	334,953	19,716
Discontinued Operations [Member]
Segment Reporting Information [Line Items]
Total assets	$ 136,759	$ 173,436

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Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Total revenue	$ 175,872	$ 159,903	$ 152,253	$ 100,998	$ 162,826	$ 174,848	$ 227,693	$ 184,937	$ 589,026	$ 750,304	$ 838,949
Gross margin	59,396	58,793	59,016	46,430	48,176	41,445	44,921	45,314
Operating loss	(21,617)	(9,724)	(12,790)	(16,097)	(160,403)	(11,114)	(6,815)	(8,785)	(60,228)	(187,117)	(35,761)
Net loss from continuing operations	(8,413)	(5,488)	(12,156)	(17,772)	(159,311)	(15,607)	(11,977)	(12,523)	(43,829)	(199,418)	(55,496)
Income (loss) from discontinued operations, net of tax	(12,249)	(2,310)	2,675	7,169	(11,694)	(900)	1,575	10,596	(4,715)	(423)	(24,071)
Net income (loss) attributable to noncontrolling interests	574	1,241	954	(3)	(63)	24	22	4	2,766	(13)	3,993
Net income (loss) attributable to the Partnership	(21,236)	(9,039)	(10,435)	(10,600)	(170,939)	(16,532)	(10,425)	(1,932)	$ (51,310)	$ (199,828)	$ (83,560)
General Partner's Interest in net income (loss)	2	(31)	(107)	(97)	(1,621)	(104)	(66)	(32)
Limited Partners' Interest in net income (loss)	$ (21,238)	$ (9,008)	$ (10,328)	$ (10,503)	$ (169,319)	$ (16,428)	$ (10,358)	$ (1,900)
Loss from continuing operations (in dollars per share)	$ (0.33)	$ (0.29)	$ (0.40)	$ (0.49)	$ (3.58)	$ (0.51)	$ (0.41)	$ (0.41)
Income (loss) from discontinued operations, basic and diluted (in usd per share)	(0.27)	(0.05)	0.07	0.16	(0.27)	(0.02)	0.03	0.25	$ (0.09)	$ (0.01)	$ (0.52)
Limited partners’ net income (loss) per unit (basic and diluted) (in dollars per share)	$ (0.60)	$ (0.34)	$ (0.33)	$ (0.33)	$ (3.85)	$ (0.53)	$ (0.38)	$ (0.16)	$ (1.60)	$ (4.92)	$ (3.29)
Loss on impairment of goodwill	$ 2,700				$ 148,500				$ 2,654	$ 148,488	$ 0

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Subsequent Event (Details) $ / shares in Units, bbl in Thousands, $ in Millions				12 Months Ended
	Sep. 01, 2017 USD ($)	Mar. 01, 2017 mi bbl	Jan. 26, 2017 $ / shares	Dec. 31, 2016 $ / shares	Dec. 31, 2015 $ / shares	Dec. 31, 2014 $ / shares
Subsequent Event [Line Items]
Distribution declared per common unit (in dollars per share)				$ 3.01	$ 3.17	$ 1.85
Subsequent Event
Subsequent Event [Line Items]
Distribution declared per common unit (in dollars per share)			$ 0.4125
Distribution made to limited partner (in dollars per share)			$ 1.65
Length of pipeline | mi		1,172
Throughput capacity per day | bbl		40
Subsequent Event | Propane Marketing Services
Subsequent Event [Line Items]
Cash proceeds from divestiture of business | $	$ 170.0