Third Coast Midstream (AMID) 8-K 18 Sep 17 2016 FY Other Events Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2016
Entity Registrant Name	American Midstream Partners, LP
Entity Central Index Key	1,513,965
Document Type	8-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
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

Consolidated Balance Sheets

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 $1,871 and $1,217 as of December 31, 2016 and December 31, 2015, respectively	27,769	23,831
Unbilled revenue	55,646	55,428
Inventory	6,776	5,241
Other current assets	27,667	25,526
Total current assets	123,524	112,013
Risk management assets - long term	10,664	0
Property, plant and equipment, net	1,145,003	1,071,514
Restricted cash - long term	323,564	5,037
Investment in unconsolidated affiliates	291,987	63,704
Intangible assets, net	225,283	247,281
Goodwill	217,498	232,954
Other assets, net	11,798	19,386
Total assets	2,349,321	1,751,889
Current liabilities
Accounts payable	45,278	48,526
Accrued gas purchases	7,891	7,281
Accrued expenses and other current liabilities	81,284	46,751
Current portion of debt	5,485	2,899
Total current liabilities	139,938	105,457
Noncurrent asset retirement obligation	44,363	28,549
Other liabilities	2,030	2,857
Revolving credit agreements	1,235,538	687,840
Deferred tax liability	8,205	6,173
Total liabilities	1,430,074	830,136
Commitments and contingencies (see Note 19)
Convertible preferred units	334,090	169,712
Equity and partners' capital
General Partner Interests (680 thousand and 536 thousand units issued and outstanding as of December 31, 2016 and December 31, 2015, respectively)	(47,645)	(47,091)
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

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Allowance for doubtful accounts	$ 1,871	$ 1,217
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%

Consolidated Statements of Oper

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	$ 568,527	$ 772,857	$ 909,765
Services	158,850	142,762	123,698
Losses on commodity derivatives, net	(455)	(1,732)	(12,671)
Total revenue	726,922	913,887	1,020,792
Operating expenses:
Cost of sales	443,023	630,303	789,872
Direct operating expenses	123,372	127,480	109,543
Corporate expenses	99,430	77,835	72,744
Depreciation, amortization and accretion	106,818	98,596	72,527
Loss on sale of assets, net	2,870	3,920	5,080
Loss on impairment of property, plant and equipment	697	0	21,344
Loss on impairment of goodwill	15,456	148,488	0
Total operating expenses	791,666	1,086,622	1,071,110
Operating loss	(64,744)	(172,735)	(50,318)
Other income (expense):
Interest expense	(21,469)	(20,120)	(16,558)
Loss on extinguishment of debt	0	0	(1,634)
Other income (expense)	628	1,732	(662)
Earnings in unconsolidated affiliates	40,158	8,201	348
Loss from continuing operations before income taxes	(45,427)	(182,922)	(68,824)
Income tax expense	(2,578)	(1,888)	(857)
Loss from continuing operations	(48,005)	(184,810)	(69,681)
Loss from discontinued operations, net of tax	(539)	(15,031)	(9,886)
Net loss	(48,544)	(199,841)	(79,567)
Net income (loss) attributable to noncontrolling interests	2,766	(13)	3,993
Net loss attributable to the Partnership	$ (51,310)	$ (199,828)	$ (83,560)
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)	(1.59)	(4.59)	(3.28)
Loss from discontinued operations, basic and diluted (in usd per share)	(0.01)	(0.33)	(0.01)
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 loss	$ (233)	$ (1,823)	$ (398)
Weighted average number of common units outstanding:
Net Income (Loss) Allocated to General Partners	(233)
Limited Partner
Other income (expense):
Net loss	(51,077)	(198,005)	(83,162)
Limited Partners' interest in net loss	$ (51,077)	$ (198,005)	$ (83,162)

Consolidated Statements of Comp

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)

Consolidated Statements of Chan

Consolidated Statements of Changes in Partners' Capital and Noncontrolling Interests - USD ($) $ in Thousands	Total	Accumulated Other Comprehensive Income	Total Partners Capital	Noncontrolling Interest	BlackwaterTotal Partners Capital	BlackwaterNoncontrolling Interest	Series B	Series BTotal Partners Capital	Delta HouseTotal Partners Capital	BPTotal Partners Capital	General Partner	General PartnerDelta House	General PartnerBP	Limited Partner	Limited PartnerBlackwater
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)	3,993							(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)	(13)							(1,823)			(198,005)
Issuance of units			85,465				1,373	$ 1,373						85,465
Unitholder contributions			1,996								1,996
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

Consolidated Statements of Cash

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	(13)	3,993
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

Consolidated Statements of Cas8

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%

Organization and Basis of Prese

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 six reportable segments, (1) gas gathering and processing services, (2) liquid pipelines and services, (3) natural gas transportation services, (4) offshore pipelines and services, (5) terminalling services and (6) propane marketing services, we engage in the business of gathering, treating, processing, and transporting natural gas; gathering, transporting, storing, treating and fractionating NGLs; gathering, storing and transporting crude oil and condensates; storing specialty chemical products; and distributing and selling propane and refined products. Most of our cash flow is generated from fee-based and fixed-margin compensation for gathering, processing, transporting and treating natural gas and crude oil, firm capacity reservation charges, interruptible transportation charges, guaranteed firm storage contracts, throughput fees and other optional charges associated with ancillary services. Our primary assets are strategically located in some of the most prolific onshore and offshore producing regions and key demand markets in the United States. Our gathering and processing assets are primarily located in (i) the Permian Basin of West Texas, (ii) the Cotton Valley/Haynesville Shale of East Texas, (iii) the Eagle Ford Shale of South Texas, (iv) the Bakken Shale of North Dakota, and (v) offshore in the Gulf of Mexico. Our transmission and terminal assets are in key demand markets in Oklahoma, Alabama, Arkansas, Louisiana, Mississippi and Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia. Our propane marketing services include commercial and retail operations across 46 of the lower 48 states. Basis of presentation As discussed in Note 2, we acquired JP Energy Partners, LP ("JPE") in a unit-for-unit exchange on March 8, 2017. As both the Partnership and JPE were controlled by ArcLight, the acquisition represents a transaction among entities under common control and has been accounted for as a common control transaction in a manner similar to a pooling of interests. Although the Partnership is the legal acquirer, JPE is considered to be the acquirer for accounting purposes as ArcLight obtained control of JPE before it obtained control the Partnership. The accompanying financial statements represent the JPE historical cost basis financial statements retrospectively adjusted to reflect its acquisition of the Partnership at ArcLight’s historical cost basis effective April 15, 2013, the date on which ArcLight obtained control of the Partnership. As the Partnership was the legal acquirer, unit amounts included in the accompanying financial statements represent the Partnership’s historical unit amounts plus the JPE unit amounts adjusted by the applicable exchange ratios. Transactions between entities under common control We may enter into transactions with ArcLight affiliates whereby we receive midstream assets or other businesses in exchange for cash or Partnership equity. We account for the net assets acquired at the affiliate's historical cost basis as the transactions are between entities under common control. In certain cases, our historical financial statements will be revised to include the results attributable to the assets acquired from the later of April 15, 2013 (the date Arclight affiliates obtained control of our General Partner) or the date the ArcLight affiliate obtained control of the assets acquired. Consolidation policy The accompanying consolidated financial statements include accounts of American Midstream Partners, LP, and its controlled subsidiaries. All significant inter-company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements. Use of estimates When preparing consolidated financial statements in conformity with accounting principles generally accepted in the United States of America ("GAAP"), management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and assumptions are based on information available at the time such estimates and assumptions are made. Adjustments made with respect to the use of these estimates and assumptions often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates and assumptions are used in, among other things, i) estimating unbilled revenues, product purchases and operating and general and administrative costs, ii) developing fair value assumptions, including estimates of future cash flows and discount rates, iii) analyzing long-lived assets, goodwill and intangible assets for possible impairment, iv) estimating the useful lives of assets and v) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts. Cash, cash equivalents and restricted cash We consider all highly liquid investments with an original maturity of three months or less at the date of purchase to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments. From time to time we are required to maintain cash in separate accounts the use of which is restricted by the terms of our debt agreements or asset retirement obligations. Such amounts are included in Restricted cash in our consolidated balance sheets. Inventory Inventory is mainly comprised of crude oil, NGLs, and refined products for resale, as well as propane cylinders expected to be sold to customers. Inventory is stated at the lower of cost or market. The cost of crude oil, NGL, and refined products is determined using the first-in, first-out (FIFO) method while the cost of propane cylinders is determined using the weighted average cost method. Allowance for doubtful accounts We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. We recorded allowances for doubtful accounts of $1.9 million and $ 1.2 million , respectively, as of December 31, 2016 and December 31, 2015. Bad debt expense for the years ended December 31, 2016, 2015 and 2014 was $1.0 million , $1.2 million and $0.8 million , respectively. Derivative financial instruments Our net income (loss) and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt, commodity prices and fractionation margins (the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas purchases). In an effort to manage the risks to unitholders, we use a variety of derivative financial instruments including swaps, collars and interest rate caps to create offsetting positions to specific commodity or interest rate exposures. We record all derivative financial instruments in our consolidated balance sheets at fair value as current and long-term assets or liabilities on a net basis by counterparty. We record changes in the fair value of our commodity derivatives in Gains (losses) on commodity 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 propane and crude oil purchase and sales contracts with counterparties. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for the normal purchase and normal sales exception because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold. As a result, these contracts are not recorded in our consolidated financial statements until they are settled. Fair value measurements We apply the authoritative accounting provisions for measuring the fair value of our derivative financial instruments and disclosures associated with our outstanding indebtedness. We define fair value as an exit price representing the expected amount we would receive when selling an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date. We use various assumptions and methods in estimating the fair values of our financial instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value due to the short-term maturity of these instruments. We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below: • Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities; • Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets that are either directly or indirectly observable; and • Level 3 – Inputs are unobservable and considered significant to fair value measurement. We utilize a mid-market pricing convention, or the "market approach," for valuation for assigning fair value to our derivative assets and liabilities. Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations. Property, plant and equipment We capitalize expenditures related to property, plant and equipment that have a useful life greater than one year. We also capitalize expenditures that improve or extend the useful life of an asset. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred. We record property, plant, and equipment at cost and recognize depreciation expense on a straight-line basis over the related estimated useful lives of the assets which range from 3 to 40 years. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We record depreciation using the group method of depreciation, which is commonly used by pipelines, utilities and similar assets. We classify long-lived assets to be disposed of through sales that meet specific criteria as held for sale. We cease depreciating those assets effective on the date the asset is classified as held for sale. We record those assets at the lower of their carrying value or the estimated fair value less the cost to sell. Until the assets are disposed of, our estimate of fair value is re-determined when related events or circumstances change. Impairment of long lived Assets We evaluate the recoverability of our property, plant and equipment and intangible assets with definite lives when events or circumstances indicate we may not recover the carrying amount of the assets. We continually monitor our operations, the market, and business environment to identify indicators that could suggest an asset or asset group may not be recoverable. We evaluate the asset or asset group for recoverability by estimating the undiscounted future cash flows expected to be derived from their use 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 antic

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures JP Energy Partners On March 8, 2017, the Partnership completed the acquisition of JPE, an entity controlled by ArcLight affiliates, in a unit-for-unit exchange. In connection with the transaction, each JPE common or subordinated unit held by investors not affiliated with ArcLight was converted into the right to receive 0.5775 of a Partnership common unit, and each JPE common or subordinated unit held by ArcLight affiliates was converted into the right to receive 0.5225 of a Partnership common unit. The Partnership issued a total of 20.2 million of its common units to complete the acquisition, including 9.8 million common units to ArcLight affiliates. Based upon the closing price for our common units on March 8, 2017, the units issued in the exchange had an estimated fair value of $322.2 million . JPE owns, operates and develops a diversified portfolio of midstream energy assets with three business segments (i) crude oil pipelines and storage, (ii) refined products terminals and storage and (iii) NGL distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs, in the United States. As both the Partnership and JPE were controlled by ArcLight, the acquisition represents a transaction among entities under common control and is accounted for as a common control transaction in a manner similar to a pooling of interests. Although the Partnership is the legal acquirer, JPE is considered to be the acquirer for accounting purposes as ArcLight obtained control of JPE before it obtained control the Partnership. The accompanying financial statements represent the JPE historical cost basis financial statements, retrospectively adjusted to reflect its acquisition of the Partnership at ArcLight’s historical cost basis effective April 15, 2013, the date on which ArcLight obtained control of the Partnership. Delta House Investment On September 18, 2015, the Partnership acquired a 26.3% interest in Pinto Offshore Holdings, LLC ("Pinto"), an entity that owns 49% of the Class A Units of Delta House FPS LLC and of Delta House Oil and Gas Lateral LLC (collectively referred to herein as "Delta House"), a floating production system platform with associated crude oil and gas export pipelines, located in the Mississippi Canyon region of the deepwater Gulf of Mexico ("Delta House"). We acquired our 26.3% non-operated interest in Pinto in exchange for $ 162.0 million in cash, funded by the proceeds of a public offering of 7.5 million of the Partnership's common units and with borrowings under the Partnership’s Amended and Restated Credit Agreement (the "Credit Agreement"). As a result, we own a minority interest in Pinto, which represents an indirect interest in 12.9% of Delta House's Class A Units. Pursuant to the Pinto LLC Agreement, we have no management control or authority over the day-to-day operations. Our interest in Pinto is accounted for as an equity method investment in the consolidated financial statements. Because our interest in Delta House was previously owned by an ArcLight affiliate, we recorded our investment at the affiliate's historical cost basis of $65.7 million in Investments in unconsolidated affiliates in our consolidated balance sheets and as an investing activity within the related consolidated statements of cash flows. The amount by which the total consideration exceeded affiliate's historical cost basis was $96.3 million and is recorded as a distribution within the consolidated statements of changes in equity, partners’ capital and noncontrolling interests and as a financing activity in the consolidated statements of cash flows. On April 25, 2016, the Partnership increased its investment in Delta House through the purchase of 100% of the outstanding membership interests in D-Day Offshore Holdings, LLC (“D-Day”), an Arclight affiliate which owned 1.0% of Delta House Class A Units in exchange for approximately $9.9 million in cash funded with borrowings under our revolving credit agreement. 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 and Services segment, specifically the acceleration of our entry into the Houston, Texas market, as well as expansion of our industrial, non-seasonal customers. The total purchase price of $16.3 million consisted of a $12.5 million cash payment that was paid on the acquisition date, and which was funded through the use of borrowings from our revolving credit facility, a $0.1 million cash payment to the seller as the final working capital adjustment, the issuance of 266,951 common units valued at $3.4 million and a contingent earn-out liability with an acquisition date fair. The gross profit targets were not achieved and the remaining $0.2 million liability was released to income in 2016. The $16.3 million purchase price was allocated to customer relationship intangible assets $6.2 million , goodwill $5.8 million , property, plant and equipment $3.0 million , accounts receivable $1.0 million and other intangible assets $0.3 million . Goodwill associated with the acquisition principally results from synergies expected from integrated operations. The fair values of the acquired intangible assets were estimated by applying the income approach which is based on significant inputs that are not observable in the market and represents a Level 3 measurement. The customer relationship assets are being amortized over a weighted average useful life of 12 years. Costar Acquisition On October 14, 2014, the Partnership acquired 100% of the membership interests of Costar Midstream, L.L.C. ("Costar") from Energy Spectrum Partners VI LP and Costar Midstream Energy, LLC, in exchange for cash and common units with an aggregate value of $405.3 million . Costar is an onshore gathering and processing company with its primary gathering, processing, fractionation, and off-spec condensate treating and stabilization assets in East Texas and the Permian basin, with a significant crude oil gathering system project in the Bakken oil play. The Costar acquisition was accounted for using the acquisition method of accounting and as a result, the purchase price was allocated to the assets acquired and liabilities assumed based on their respective fair values as of the acquisition date. The excess of the aggregate purchase price of the fair values of the assets acquired, liabilities assumed and the noncontrolling interest was 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.

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	Discontinued Operations Mid-Continent On February 1, 2016, we sold certain trucking and marketing assets in the Mid-Continent area (the “Mid-Continent Business”) to JP Development for $9.7 million in cash. We recognized a loss on the disposal of approximately $12.9 million during the year ended December 31, 2015, which primarily related to goodwill and long-lived asset impairment charges. Prior to the classification as discontinued operations, we reported the Mid-Continent Business in our Liquid Pipelines and Services segment. Financial information for the Mid-Continent Business which is included in Loss from discontinued operations, net of tax in the consolidated statement of operations is summarized below: Year Ended December 31, 2016 2015 2014 (in thousands) Revenues Total revenues $ 11,495 $ 429,784 $ 967,480 Costs and Expenses Costs of sales 11,687 426,886 961,428 Direct operating expenses 203 2,269 2,866 Loss on impairment of goodwill and assets held for sale — 12,909 — Depreciation, amortization and accretion 211 2,281 2,258 (Gain) loss on sale of assets, net (114 ) 119 229 Total expenses 11,987 444,464 966,781 Operating (loss) income (492 ) (14,680 ) 699 Other income (expense) (47 ) (271 ) (366 ) (Loss) income from discontinued operations before income tax expense (539 ) (14,951 ) 333 Income tax expense — — — Net (loss) income from discontinued operations $ (539 ) $ (14,951 ) $ 333 Bakken Business On June 30, 2014, we sold our trucking and related assets in North Dakota, Montana and Wyoming (the “Bakken Business”) to Gold Spur Trucking, LLC for $9.1 million . We recognized a loss on this sale of approximately $7.3 million during the second quarter of 2014, which primarily related to the write-off of a related customer contract. We also recognized a $2.0 million goodwill impairment charge in connection with the transaction Financial information for the Bakken Business which is included in Loss from discontinued operations, net of tax in the consolidated statement of operations is summarized below: Year Ended December 31, 2014 (in thousands) Total revenues $ 7,865 Net loss from discontinued operations, including loss on disposal of $7,288 (9,608 ) Blackwater On December 17, 2013, we acquired Blackwater Midstream Holdings LLC ("Blackwater") from an ArcLight affiliate. As part of the Blackwater acquisition, we acquired certain long-lived terminal assets which were immediately classified as held for sale. Due to deteriorating market conditions, the Partnership recognized an impairment charge on these assets of $0.7 million in 2014. These assets were sold during the third quarter of 2015 at a nominal loss. Financial information for the portion of the Blackwater business sold which is included in Loss from discontinued operations, net of tax in the consolidated statement of operations is summarized below: Years Ended December 31, 2015 2014 (in thousands) Total revenues $ 74 $ 474 Loss from discontinued operations, net of tax (80 ) (611 ) Due to immateriality, we elected to not separately present the cash flows from operating, investing and financing activities related to the discontinued operations described above in our consolidated statements of cash flows.

Concentration of Credit Risk

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 17% and 10% , respectively, of our consolidated revenue. In 2015, we had one such customer who accounted for 28% of our consolidated revenue. In 2014, we had one such customer who accounted for 16% of our consolidated revenue. We are party to various commercial netting agreements that allow us and contractual counterparties to net receivable and payable obligations. These agreements are customary and the terms follow standard industry practice. In the opinion of management, these agreements reduce the overall counterparty risk exposure.

Inventory

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 3,482 2,638 Refined products 291 463 Materials, supplies and equipment 1,787 1,654 Total inventory $ 6,776 $ 5,241

Other Current Assets

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 2,895 115 Other receivables 2,998 2,688 Due from related parties 4,805 8,688 Risk management assets 964 365 Other assets 6,303 5,753 Discontinued operations, current assets — 2,730 Total other current assets $ 27,667 $ 25,526

Risk Management Activities

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. In August 2015, we paid approximately $8.7 million to settle all of our then-outstanding propane financial swap contracts that were scheduled to mature at various dates through April 2017. We simultaneously executed new propane financial swap contracts at the then current forward market prices for the purpose of economically hedging a substantial majority of our fixed price propane sales contracts through July 2017. The following table summarizes the net notional volume buy (sell) of our outstanding commodity-related derivatives, excluding those derivatives that qualified for the normal purchase normal sale exception as of December 31, 2016 and 2015, none of which were designated as hedges for accounting purposes. December 31, 2016 December 31, 2015 Notional Volume Maturity Notional Volume Maturity Commodity Swaps: Propane Fixed Price (Gallons) 4,364,880 Jan 2017 - Nov 2018 8,614,631 Jan 2016 - July 2017 Crude Oil Fixed Price (Barrels) — — (93,000) Jan 2016 Crude Oil Basis (Barrels) 180,000 Jan 2017 - Mar 2017 — — Interest Rate Swaps To manage the impact of the interest rate risk associated with our Credit Agreement, we enter into interest rate swaps from time to time, effectively converting a portion of the cash flows related to our long-term variable rate debt into fixed rate cash flows. Notional Amount Term Fair Value (in thousands) (in thousands) $200,000 January 3, 2017 thru September 3, 2019 $ 1,912 $100,000 January 1, 2017 thru December 31, 2017 (71 ) $100,000 January 1, 2018 thru January 31, 2019 226 $100,000 January 1, 2018 thru December 31, 2021 3,090 $150,000 January 1, 2018 thru December 31, 2022 5,219 $ 10,376 The fair value of our interest rate swaps was estimated using a valuation methodology based upon forward interest rate and volatility curves as well as other relevant economic measures, if necessary. Discount factors may be utilized to extrapolate a forecast of future cash flows associated with long dated transactions or illiquid market points. The inputs, which represent Level 2 inputs in the valuation hierarchy, are obtained from independent pricing services and we have made no adjustments to those prices. Weather Derivative In the second quarters of 2016 and 2015, we entered into weather derivatives to mitigate the impact of potential unfavorable weather to our operations under which we could receive payments totaling up to $30.0 million in the event that a hurricane or hurricanes of certain strength pass through the area as identified in the related agreement. The weather derivatives, which are accounted for using the intrinsic value method, were entered into with a single counterparty and we were not required to post collateral. We paid premiums of $1.0 million and $0.9 million in 2016 and 2015, respectively, which are amortized to Direct operating expenses on a straight-line basis over the 1 year term of the contract. Unamortized amounts associated with weather derivatives were approximately $0.4 million at December 31, 2016 and 2015 , and are included in Other current assets on the consolidated balance sheets. Our interest rate swaps, commodity swaps and weather derivatives were recorded in our consolidated balance sheets, under the following captions: Gross Risk Management Position Netting Adjustment Net Risk Management Position Balance Sheet Classification December 31, 2016 December 31, 2015 December 31, 2016 December 31, 2015 December 31, 2016 December 31, 2015 (in thousands) Other current assets $ 1,036 $ 457 $ (72 ) $ (92 ) $ 964 $ 365 Risk management assets - long term 10,665 — (1 ) — 10,664 — Total assets $ 11,701 $ 457 $ (73 ) $ (92 ) $ 11,628 $ 365 Accrued expenses and other current liabilities $ (253 ) $ (450 ) $ 72 $ 92 $ (181 ) $ (358 ) Other liabilities (1 ) (24 ) 1 — — (24 ) Total liabilities $ (254 ) $ (474 ) $ 73 $ 92 $ (181 ) $ (382 ) For the years ended December 31, 2016 , 2015 and 2014 , the realized and unrealized gains (losses) associated with our commodity, interest rate and weather derivative instruments were recorded in our consolidated statements of operations, under the following captions: Realized Unrealized (in thousands) 2016 Losses on commodity derivatives, net $ (1,480 ) $ 1,025 Interest expense (144 ) 10,375 Direct operating expenses (966 ) — Total $ (2,590 ) $ 11,400 2015 Losses on commodity derivatives, net $ (13,209 ) $ 11,477 Interest expense (425 ) 373 Direct operating expenses (913 ) — Total $ (14,547 ) $ 11,850 2014 Losses on commodity derivatives, net $ (337 ) $ (12,334 ) Interest expense (707 ) 284 Direct operating expenses (1,035 ) — Total $ (2,079 ) $ (12,050 )

Property, Plant and Equipment,

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, December 31, (in thousands) Land N/A $ 23,520 $ 18,902 Construction in progress N/A 131,448 58,146 Transportation Equipment 5 to 15 44,060 46,582 Buildings and improvements 4 to 40 24,225 22,398 Processing and treating plants 8 to 40 120,977 102,111 Pipelines and compressors 3 to 40 804,815 775,486 Storage 3 to 40 210,579 210,208 Equipment 5 to 20 102,409 78,131 Total property, plant and equipment 1,462,033 1,311,964 Less accumulated depreciation (317,030 ) (240,450 ) Property, plant and equipment, net $ 1,145,003 $ 1,071,514 At December 31, 2016 and 2015 , gross property, plant and equipment included $291.1 million and $228.9 million , respectively, related to our FERC regulated interstate and intrastate assets. Depreciation expense totaled $82.8 million , $75.0 million and $50.9 million for the years ended December 31, 2016 , 2015 and 2014 , respectively, which is included in the depreciation, amortization and accretion expense in the consolidated statements of operations. Depreciation expense amounts have been adjusted by $0.1 million , $1.1 million , and $1.7 million for the years ended December 31, 2016, 2015 and 2014, respectively, to present the Mid-Continent and Bakken Business's operations as discontinued operations. Capitalized interest was $2.7 million , $1.9 million and $0.8 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. 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.

Goodwill and Intangible Assets,

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 forecasted commodity prices and contracted rates used. As a result of our step one analysis in the fourth quarter of 2015, we determined that the estimated fair value of certain reporting units within our Gas Gathering and Processing Services, Liquid Pipelines and Services and Propane Marketing Services reportable segments were less than their respective carrying amounts, primarily due to changes in assumptions related to commodity prices, the timing of estimated drilling by producers, and discount rates. These assumptions were adversely impacted by the continuing decline in market conditions within the energy sector at the time. The second step of the goodwill impairment test involved allocating the estimated fair value of each reporting unit among the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. The results of the hypothetical purchase price allocation indicated there was no fair value attributable to goodwill of the reporting units within our Gas Gathering and Processing Services reportable segment and we recognized an impairment charge of $118.6 million which consisted of $95.0 million and $23.6 million related to the Costar and Lavaca acquisitions, respectively. In addition, we recognized a $23.6 million impairment charge in our Liquid Pipelines and Services reportable segment relating to our Crude Oil Supply and Logistics business, and a $6.3 million impairment charge in our Propane Marketing Services reportable segment related to JP Liquids. As a result, we recognized total goodwill impairment charges of $148.5 million during the year ended December 31, 2015. In 2016, we recognized additional goodwill impairment charges totaling $15.5 million in our Propane Marketing Services reportable segment, which consisted of $12.8 million and $2.7 million related to our Pinnacle Propane Express and JP Liquids businesses, respectively. Given the market condition trend surrounding Pinnacle Propane Express and JP Liquids, we may recognize further impairments related to those assets in the future. The following table presents activity in the Partnership's goodwill balance: Gas Gathering and Processing Services Liquid Pipelines and Services Terminalling Services Propane Marketing Services Total (in thousands) Balance at January 1, 2015 $ 125,974 $ 137,243 $ 88,466 $ 31,335 $ 383,018 Goodwill acquired during the year — — — 5,806 5,806 Return of purchase price (7,382 ) — — — (7,382 ) Impairment charges (118,592 ) (23,574 ) — (6,322 ) (148,488 ) Balance at December 31, 2015 — 113,669 88,466 30,819 232,954 Impairment charges — — (15,456 ) (15,456 ) Balance at December 31, 2016 $ — $ 113,669 $ 88,466 $ 15,363 $ 217,498 Intangible assets, net, consists of customer relationships, customer contracts, dedicated acreage agreements, and collaborative arrangements as acquired in connection with business combinations. These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging from approximately 5 years to 30 years. Intangible assets, net, consist of the following: December 31, 2016 2015 (in thousands) Gross carrying amount: Customer relationships $ 133,503 $ 136,030 Customer contracts 95,594 95,594 Dedicated acreage 53,350 53,350 Collaborative arrangements 11,884 11,884 Noncompete agreements 3,423 3,575 Other 751 751 $ 298,505 $ 301,184 Accumulated amortization: Customer relationships $ (31,471 ) $ (23,885 ) Customer contracts (33,414 ) (24,538 ) Dedicated acreage (4,439 ) (2,661 ) Collaborative arrangements (601 ) — Noncompete agreements (3,086 ) (2,664 ) Other (211 ) (155 ) $ (73,222 ) $ (53,903 ) Net carrying amount: Customer relationships $ 102,032 $ 112,145 Customer contracts 62,180 71,056 Dedicated acreage 48,911 50,689 Collaborative arrangements 11,283 11,884 Noncompete agreements 337 911 Other 540 596 $ 225,283 $ 247,281 In connection with the sale of the Mid-Continent Business we recorded an impairment charge of $0.7 million related to customer relationships during the year ended December 31, 2015, which is included in net loss from discontinued operations, net of tax in the consolidated statement of operations. In addition, as a result of the sale of the Bakken Business, we wrote-off $8.1 million in customer contracts during the year ended December 31, 2014. For the years ended December 31, 2016 , 2015 and 2014 , amortization expense on our intangible assets totaled $22.0 million , $22.8 million and $20.8 million , respectively, which is included depreciation, amortization and accretion in the consolidated statements of operations. Amortization expense of $0.1 million , $1.2 million and $2.0 million for the years ended December 31 2016, 2015 and 2014, respectively, relating to the Mid-Continent Business and Bakken Business is included in the net loss from discontinued operations, net of tax, in the consolidated statement of operations. Estimated amortization expense for each of the next five years ranges from $14.3 million to $19.9 million , with an aggregate $138.1 million to be recognized in subsequent years. The storage tank capacity in our crude oil storage facility in Cushing, Oklahoma is dedicated to one customer pursuant to a long-term contract with an initial expiration date of August 3, 2017 and an optional two year renewal term. We did not receive a notice of the customer's intent to renew this contract by the required date of February 3, 2017. While we continue to be in discussions with the customer and other parties about renting the storage capacity, we began to accelerate the remaining amortization of the related customer relationship intangible of $10.0 million over the remaining term of the original agreement.

Investment in Unconsolidated Af

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.

Accrued Expenses and Other Curr

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

Asset Retirement Obligations

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 .

Convertible Preferred Units

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 .

Debt Obligations

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 $ 3,809 $ 1,252,059 Less unamortized deferred financing costs and discount — — (8,691 ) (2,345 ) — (11,036 ) Subtotal 711,250 177,000 291,309 57,655 3,809 1,241,023 Less current portion — — — (1,676 ) (3,809 ) (5,485 ) Non-current portion $ 711,250 $ 177,000 $ 291,309 $ 55,979 $ — $ 1,235,538 Our outstanding debt consists of the following as of December 31, 2015: AMID JPE Revolving Credit Revolving Credit Other Agreement (1) Agreement (1) Debt Total (in thousands) Balance $ 525,100 $ 162,000 $ 3,639 $ 690,739 Less current portion — — (2,899 ) (2,899 ) Non-current portion $ 525,100 $ 162,000 $ 740 $ 687,840 ______________________ (1) Unamortized deferred financing costs related to the Credit Agreement are included in Other assets, net. AMID Credit Agreement Effective as of April 25, 2016, the Partnership entered into the Second Amendment to the Amended and Restated Credit Agreement (as amended, the "Credit Agreement"), which provides for maximum borrowings up to $750.0 million , with the ability to further increase the borrowing capacity to $900.0 million subject to lender approval. We can elect to have loans under our Credit Agreement bear interest either at a Eurodollar-based rate, plus a margin ranging from 2.00% to 3.25% depending on our total leverage ratio 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.

Partners' Capital

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 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, 201 7. 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.

Net Income (Loss) per Limited P

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

Long-Term Incentive Plan

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.

Income Taxes

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 (2,057 ) (1,240 ) (711 ) Effective income tax rate 5.7 % 1.0 % 1.2 % A reconciliation of our expected income tax (expense) benefit calculated at the U.S. federal statutory rate of 34% to our actual tax (expense) for the years ended December 31, 2016, 2015 and 2014 is as follows: Years Ended December 31, 2016 2015 2014 Net income (loss) before income tax expense $ (45,427 ) $ (182,922 ) $ (68,824 ) US Federal statutory tax rate 34 % 34 % 34 % Federal income tax (expense) benefit at statutory rate 15,445 62,193 23,400 Reconciling items: Partnership loss not subject to income tax (benefit) (17,218 ) (63,083 ) (23,759 ) State and local tax expense (800 ) (857 ) (459 ) Other (5 ) (141 ) (39 ) Income tax expense $ (2,578 ) $ (1,888 ) $ (857 ) The Partnership’s deferred tax assets and liabilities as of December 31, 2016 and 2015 are summarized below: 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.

Commitments and Contingencies

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 our consolidated statements of operations. At December 31, 2016 , payments under the plan had been completed. Commitments and contractual obligations The Partnership had the following non-cancelable contractual commitments as of December 31, 2016 : Revolving Credit Agreements 3.77% Senior Notes 8.50% Senior Notes (1) Asset Retirement Obligation (2) Other Total (in thousands) 2017 $ — $ 1,677 $ — $ 6,499 $ 9,869 $ 18,045 2018 — 806 — — 6,331 7,137 2019 888,250 2,233 — — 5,079 895,562 2020 — 2,299 — — 2,905 5,204 2021 — 4,430 300,000 — 2,253 306,683 Thereafter — 48,555 — 44,363 17,991 110,909 $ 888,250 $ 60,000 $ 300,000 $ 50,862 $ 44,428 $ 1,343,540 (1) Upon closing of the JPE Merger, the proceeds from the 8.50% Senior Notes were used to repay the JPE Credit Agreement. (2) In some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for purposes of estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management's experience, or the asset's estimated economic life. For the years ended December 31, 2016 , 2015 and 2014 , total rental expenses were $19.5 million , $17.7 million , and $10.6 million , respectively.

Related-Party Transactions

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 liabilities and 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 expenses in 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 expenses in the consolidated statements of operations by $0.1 million , $0.6 million and $0.6 million for the years ended December 31, 2016, 2015 and 2014, respectively. During the years ended December 31, 2016 and 2015, our General Partner agreed to absorb certain of our corporate expenses. We received reimbursements for these expenses in the quarter subsequent to when they were incurred. We received reimbursements totaling $7.5 million and $3.0 million for the years ended December 31, 2016 and 2015, respectively. In the first quarter of 2015, certain executive bonuses related to the year ended December 31, 2014 were paid on our behalf by ArcLight. In addition, ArcLight reimbursed us for expenses we incurred for the years ended December 31, 2016 and 2015. The total amounts paid on our behalf or reimbursed to us were $2.4 million and $2.6 million for the years ended December 31, 2016 and 2015, respectively, and were treated as deemed contributions from ArcLight. An ArcLight affiliate provided crude oil pipeline transportation services to our discontinued Mid-Continent Business. During the years ended December 31, 2016, 2015 and 2014, we incurred related pipeline transportation fees of $0.4 million , $6.0 million and $8.9 million , respectively, which have been included in net loss from discontinued operations, net of tax in the consolidated statements of operations. As of December 31, 2015, we had a net receivable of $7.9 million from this affiliate, primarily as the result of the prepayments made in 2014 for the crude oil pipeline transportation services to be provided. The Partnership acquired Blackwater Midstream Holdings, LLC (“Blackwater”) from affiliates of ArcLight in December 2013. The acquisition agreement included a provision whereby an ArcLight affiliate would be entitled to an additional $5.0 million of merger consideration based on Blackwater meeting certain operating targets. During the third quarter of 2016, the Partnership determined that it was probable the operating targets would be met in early 2017 and recorded a $5.0 million accrued distribution to the ArcLight affiliate which is included in Accrued expenses and other current liabilities in the accompanying consolidated balance sheets at December 31, 2016 . American Panther, LLC ("American Panther") is a 60% -owned subsidiary of the Partnership which is consolidated for financial reporting purposes. Pursuant to a related agreement which began in the second quarter of 2016, an affiliate of the non-controlling interest holder provides services to American Panther in exchange for related fees, which in 2016 totaled $1.2 million of which $0.8 million is included in Direct operating expenses and $0.4 million is included in Corporate expenses in the consolidated statement of operations. On November 1, 2016, the Partnership became operator of the Destin and Okeanos pipelines and entered into operating and administrative management agreements under which the affiliates pay a monthly fee for general and administrative services provided by the Partnership. In addition, the affiliates reimbursed the Partnership for certain transition related expenses. For the year ended December 31, 2016 , the Partnership recognized $0.4 million of management fee income and $1.0 million as reimbursement of transition related expenses in Corporate expenses in the consolidated statements of operations. During the second quarter of 2015, we began performing administrative, crude transportation and marketing services for an ArcLight affiliate. We charged $3.2 million and $3.0 million for the years ended December 31, 2016 and 2015, respectively, for these services of which $3.2 million and $2.2 million was included in Services for the years ended December 31, 2016 and 2015, respectively, and $0.8 million was included in Commodity sales for the year ended December 31, 2015 on the consolidated statements of operations. As of December 31, 2016 and 2015, we had receivables due from this affiliate of $2.1 million and $0.7 million , respectively, which are included in other current assets in the consolidated balance sheets. The Partnership enters into purchases and sales of natural gas and crude oil with a company whose chief financial officer is the brother of one of our executive officers. During the years ended December 31, 2016 , 2015 , and 2014 , the Partnership recognized related revenue of $3.6 million , $6.2 million and $10.1 million , respectively, while purchases from the company totaled $4.3 million , $5.9 million , and $3.7 million , respectively.

Supplemental Cash Flow Informat

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 — —

Reportable Segments

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, Terminalling Services, and Propane Marketing Services. These segments, are described below, have been identified based on the differing products and services, regulatory environments and the expertise required for these operations. Gas Gathering and Processing Services provides “wellhead-to-market” services to producers of natural gas and crude oil, which include transporting raw natural gas and crude oil from various receipt points through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs from the natural gas, fractionating NGLs, and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems. Liquid Pipelines and Services provides transportation, purchase and sales of crude oil from various receipt points including lease automatic custody transfer ("LACT") facilities and delivering to various markets. Natural Gas Transportation Services transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, which include local distribution companies (“LDCs”), utilities and industrial, commercial and power generation customers. Offshore Pipelines and Services gathers and transports natural gas from various receipt points to other pipeline interconnects, onshore facilities and other delivery points. Terminalling Services provides above-ground leasable storage operations at our marine terminals that support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products and also includes crude oil storage in Cushing, OK and refined products terminals in Texas and Arkansas. Propane Marketing Services gathers, transports and sells natural gas liquids (NGLs). This is accomplished through cylinder tank exchange, sales through retail, commercial and wholesale distribution and through a fleet of trucks operating in the Eagle Ford and Permian basin areas. Our Chief Executive Officer serves as our Chief Operating Decision Maker and evaluates the performance of our reportable segments primarily on the basis of segment gross margin, which is our segment measure of profitability. We define segment gross margin for each segment as summarized below: Gas Gathering and Processing Services - total revenue plus unconsolidated affiliate earnings less unrealized gains (losses) on commodity derivatives, construction and operating management agreement income and the cost of sales. Liquid Pipelines and Services - total revenue plus unconsolidated affiliate earnings less unrealized gains (losses) on commodity derivatives and the cost of sales. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk. Natural Gas Transportation Services - total revenue plus unconsolidated affiliate earnings less the cost of sales. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk. Offshore Pipelines and Services - total revenue plus unconsolidated affiliate earnings less the cost of sales. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk. Terminalling Services - total revenue less direct operating expense which includes direct labor, general materials and supplies and direct overhead. Propane Marketing Services - total revenue less cost of sales excluding non-cash charges such as non-cash unrealized gain (losses) on commodity derivatives. The following tables set forth our segment financial information for the periods indicated: December 31, 2016 Gas Gathering and Processing Services Liquid Pipelines and Services Natural Gas Transportation Services Offshore Pipelines and Services Terminalling Services Propane Marketing Services Total (in thousands) Commodity sales $ 91,444 $ 304,501 $ 21,999 $ 6,812 $ 14,655 $ 129,116 $ 568,527 Services 22,558 12,146 18,109 40,502 50,999 14,536 158,850 Gains (losses) on commodity derivatives, net (833 ) (341 ) — (7 ) (436 ) 1,162 (455 ) Total Revenue 113,169 316,306 40,108 47,307 65,218 144,814 726,922 Cost of sales 63,832 288,496 21,288 3,049 11,564 54,794 443,023 Direct operating expenses 33,802 8,383 5,923 10,945 10,783 53,536 123,372 Corporate expenses 99,430 Depreciation, amortization, and accretion 106,818 Loss on sale of assets, net 2,870 Loss on impairment of plant, property and equipment 697 Loss on impairment of goodwill 15,456 Interest expense 21,469 Earnings in unconsolidated affiliates (40,158 ) Other (income) expense (628 ) Income tax expense 2,578 Income (loss) from continuing operations (48,005 ) Loss from discontinuing operations, net of tax (539 ) Net income (loss) (48,544 ) Net income (loss) attributable to non-controlling interest 2,766 Net income (loss) attributable to partnership $ (51,310 ) Segment gross margin $ 48,245 $ 29,760 $ 18,616 $ 82,346 $ 42,872 $ 88,948 December 31, 2015 Gas Gathering and Processing Services Liquid Pipelines and Services Natural Gas Transportation Services Offshore Pipelines and Services Terminalling Services Propane Marketing Services Total (in thousands) Commodity sales $ 107,680 $ 457,390 $ 23,972 $ 13,798 $ 10,343 $ 159,674 $ 772,857 Services 30,196 12,895 16,035 21,457 45,022 17,157 142,762 Gains (losses) on commodity derivatives, net 1,240 — — 84 21 (3,077 ) (1,732 ) Total Revenue 139,116 470,285 40,007 35,339 55,386 173,754 913,887 Cost of sales 72,960 446,125 21,858 9,914 8,893 70,553 630,303 Direct operating expenses 35,250 8,310 6,728 9,425 10,414 57,353 127,480 Corporate expenses 77,835 Depreciation, amortization, and accretion 98,596 Loss on sale of assets, net 3,920 Loss on impairment of goodwill 148,488 Interest expense 20,120 Earnings in unconsolidated affiliates (8,201 ) Other (income) expense (1,732 ) Income tax expense 1,888 Income (loss) from continuing operations (184,810 ) Loss from discontinuing operations, net of tax (15,031 ) Net income (loss) (199,841 ) Net income (loss) attributable to non-controlling interest (13 ) Net income (loss) attributable to partnership $ (199,828 ) Segment gross margin $ 65,692 $ 24,160 $ 18,073 $ 33,613 $ 36,079 $ 91,437 December 31, 2014 Gas Gathering and Processing Services Liquid Pipelines and Services Natural Gas Transportation Services Offshore Pipelines and Services Terminalling Services Propane Marketing Services Total (in thousands) Commodity sales $ 148,198 $ 470,336 $ 70,964 $ 20,044 $ 11,521 $ 188,702 $ 909,765 Services 15,248 11,548 12,925 24,426 41,357 18,194 123,698 Gains (losses) on commodity derivatives, net 1,050 — — 41 — (13,762 ) (12,671 ) Total Revenue 164,496 481,884 83,889 44,511 52,878 193,134 1,020,792 Cost of dales 112,719 459,319 70,100 15,133 6,859 125,742 789,872 Direct operating expenses 21,197 5,819 6,975 11,142 11,525 52,885 109,543 Corporate expenses 72,744 Depreciation, amortization, and accretion 72,527 Loss on sale of assets, net 5,080 Loss on impairment of plant, property and equipment 21,344 Interest expense 16,558 Earnings in unconsolidated affiliates (348 ) Other (income) expense 662 Loss on extinguishment of debt 1,634 Income tax expense 857 Income (loss) from continuing operations (69,681 ) Loss from discontinuing operations, net of tax (9,886 ) Net income (loss) (79,567 ) Net income (loss) attributable to non-controlling interest 3,993 Net income (loss) attributable to partnership $ (83,560 ) Segment gross margin $ 51,213 $ 22,564 $ 13,691 $ 29,089 $ 34,493 $ 80,083 A reconciliation of total assets by segment to the amounts included in the consolidated balance sheets is as follows: December 31, 2016 2015 Segment assets: (in thousands) Gas Gathering and Processing Services $ 530,889 $ 496,014 Liquid Pipelines and Services 422,636 426,854 Natural Gas Transportation Services 221,604 146,927 Offshore Pipelines and Services 400,193 190,271 Terminalling Services 299,534 291,130 Propane Marketing Services 140,864 173,558 Other (1) 333,601 27,135 Total assets $ 2,349,321 $ 1,751,889 _______________________ (1) Other assets not allocable to segments consist of investment in unconsolidated affiliates, restricted cash and other assets.

Quarterly Financial Data (Unaud

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 $ 143,376 $ 185,836 $ 187,659 $ 210,051 Gross margin (1) 74,045 81,072 76,427 79,243 Operating loss (8,401 ) (10,368 ) (12,125 ) (33,850 ) Net income (loss) (10,603 ) (9,481 ) (7,797 ) (20,663 ) Net income (loss) attributable to the Partnership (10,600 ) (10,435 ) (8,993 ) (21,282 ) General Partner's Interest in net income (loss) (97 ) (107 ) (26 ) (3 ) Limited Partners' Interest in net income (loss) $ (10,503 ) $ (10,328 ) $ (8,967 ) $ (21,279 ) Limited Partners' income (loss) per unit: Loss from continuing operations $ (0.32 ) $ (0.33 ) $ (0.33 ) $ (0.61 ) Net income (loss) $ (0.33 ) $ (0.33 ) $ (0.33 ) $ (0.61 ) Year Ended December 31, 2015 Total revenues $ 238,035 $ 265,703 $ 209,416 $ 200,733 Gross margin (1) 73,088 66,757 56,829 72,380 Operating income (loss) 2,187 (5,769 ) (10,831 ) (158,322 ) Net income (loss) from continuing operations (1,525 ) (10,913 ) (15,207 ) (157,165 ) Income (loss) from discontinued operations, net of tax (402 ) 511 (1,300 ) (13,840 ) Net income (loss) attributable to noncontrolling interest 4 22 24 (63 ) Net income (loss) attributable to the Partnership (1,932 ) (10,425 ) (16,532 ) (170,939 ) General Partner's Interest in net income (loss) (32 ) (66 ) (104 ) (1,621 ) Limited Partners' Interest in net income (loss) $ (1,900 ) $ (10,358 ) $ (16,428 ) $ (169,319 ) Limited Partners' income (loss) per unit: Loss from continuing operations $ (0.15 ) $ (0.39 ) $ (0.50 ) $ (3.55 ) Net loss $ (0.16 ) $ (0.38 ) $ (0.53 ) $ (3.85 ) (1) For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use gross margin to evaluate our operating performance, please read Item 7. "Management's Discussion and Analysis, How We Evaluate Our Operations." (2) We recognized goodwill impairment charges of $15.4 million and $148.5 million in the fourth quarters of 2016 and 2015, respectively.

Subsequent Event

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

Organization and Basis of Pre33

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 six reportable segments, (1) gas gathering and processing services, (2) liquid pipelines and services, (3) natural gas transportation services, (4) offshore pipelines and services, (5) terminalling services and (6) propane marketing services, we engage in the business of gathering, treating, processing, and transporting natural gas; gathering, transporting, storing, treating and fractionating NGLs; gathering, storing and transporting crude oil and condensates; storing specialty chemical products; and distributing and selling propane and refined products. Most of our cash flow is generated from fee-based and fixed-margin compensation for gathering, processing, transporting and treating natural gas and crude oil, firm capacity reservation charges, interruptible transportation charges, guaranteed firm storage contracts, throughput fees and other optional charges associated with ancillary services. Our primary assets are strategically located in some of the most prolific onshore and offshore producing regions and key demand markets in the United States. Our gathering and processing assets are primarily located in (i) the Permian Basin of West Texas, (ii) the Cotton Valley/Haynesville Shale of East Texas, (iii) the Eagle Ford Shale of South Texas, (iv) the Bakken Shale of North Dakota, and (v) offshore in the Gulf of Mexico. Our transmission and terminal assets are in key demand markets in Oklahoma, Alabama, Arkansas, Louisiana, Mississippi and Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia. Our propane marketing services include commercial and retail operations across 46 of the lower 48 states.
Basis of presentation	Basis of presentation As discussed in Note 2, we acquired JP Energy Partners, LP ("JPE") in a unit-for-unit exchange on March 8, 2017. As both the Partnership and JPE were controlled by ArcLight, the acquisition represents a transaction among entities under common control and has been accounted for as a common control transaction in a manner similar to a pooling of interests. Although the Partnership is the legal acquirer, JPE is considered to be the acquirer for accounting purposes as ArcLight obtained control of JPE before it obtained control the Partnership. The accompanying financial statements represent the JPE historical cost basis financial statements retrospectively adjusted to reflect its acquisition of the Partnership at ArcLight’s historical cost basis effective April 15, 2013, the date on which ArcLight obtained control of the Partnership. As the Partnership was the legal acquirer, unit amounts included in the accompanying financial statements represent the Partnership’s historical unit amounts plus the JPE unit amounts adjusted by the applicable exchange ratios.
Transactions between entities under common control	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, as well as propane cylinders expected to be sold to customers. Inventory is stated at the lower of cost or market. The cost of crude oil, NGL, and refined products is determined using the first-in, first-out (FIFO) method while the cost of propane cylinders is determined using the weighted average cost method.
Allowance for doubtful accounts	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) on commodity 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 propane and crude oil purchase and sales contracts with counterparties. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for the normal purchase and normal sales exception because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold. As a result, these contracts are not recorded in our consolidated financial statements until they are settled.
Fair value measurements	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.

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
Schedule of disposal groups	Financial information for the portion of the Blackwater business sold which is included in Loss from discontinued operations, net of tax in the consolidated statement of operations is summarized below: Years Ended December 31, 2015 2014 (in thousands) Total revenues $ 74 $ 474 Loss from discontinued operations, net of tax (80 ) (611 ) Due to immateriality, we elected to not separately present the cash flows from operating, investing and financing activities related to the discontinued operations described above in our consolidated statements of cash flows. Financial information for the Bakken Business which is included in Loss from discontinued operations, net of tax in the consolidated statement of operations is summarized below: Year Ended December 31, 2014 (in thousands) Total revenues $ 7,865 Net loss from discontinued operations, including loss on disposal of $7,288 (9,608 ) Blackwater Financial information for the Mid-Continent Business which is included in Loss from discontinued operations, net of tax in the consolidated statement of operations is summarized below: Year Ended December 31, 2016 2015 2014 (in thousands) Revenues Total revenues $ 11,495 $ 429,784 $ 967,480 Costs and Expenses Costs of sales 11,687 426,886 961,428 Direct operating expenses 203 2,269 2,866 Loss on impairment of goodwill and assets held for sale — 12,909 — Depreciation, amortization and accretion 211 2,281 2,258 (Gain) loss on sale of assets, net (114 ) 119 229 Total expenses 11,987 444,464 966,781 Operating (loss) income (492 ) (14,680 ) 699 Other income (expense) (47 ) (271 ) (366 ) (Loss) income from discontinued operations before income tax expense (539 ) (14,951 ) 333 Income tax expense — — — Net (loss) income from discontinued operations $ (539 ) $ (14,951 ) $ 333

Inventory (Tables)

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 3,482 2,638 Refined products 291 463 Materials, supplies and equipment 1,787 1,654 Total inventory $ 6,776 $ 5,241

Detail of Certain Asset Account

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 2,895 115 Other receivables 2,998 2,688 Due from related parties 4,805 8,688 Risk management assets 964 365 Other assets 6,303 5,753 Discontinued operations, current assets — 2,730 Total other current assets $ 27,667 $ 25,526

Risk Management Activities (Tab

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: Propane Fixed Price (Gallons) 4,364,880 Jan 2017 - Nov 2018 8,614,631 Jan 2016 - July 2017 Crude Oil Fixed Price (Barrels) — — (93,000) Jan 2016 Crude Oil Basis (Barrels) 180,000 Jan 2017 - Mar 2017 — —
Derivatives and fair value	December 31, 2016 December 31, 2015 Notional Volume Maturity Notional Volume Maturity Commodity Swaps: Propane Fixed Price (Gallons) 4,364,880 Jan 2017 - Nov 2018 8,614,631 Jan 2016 - July 2017 Crude Oil Fixed Price (Barrels) — — (93,000) Jan 2016 Crude Oil Basis (Barrels) 180,000 Jan 2017 - Mar 2017 — — Interest Rate Swaps To manage the impact of the interest rate risk associated with our Credit Agreement, we enter into interest rate swaps from time to time, effectively converting a portion of the cash flows related to our long-term variable rate debt into fixed rate cash flows. Notional Amount Term Fair Value (in thousands) (in thousands) $200,000 January 3, 2017 thru September 3, 2019 $ 1,912 $100,000 January 1, 2017 thru December 31, 2017 (71 ) $100,000 January 1, 2018 thru January 31, 2019 226 $100,000 January 1, 2018 thru December 31, 2021 3,090 $150,000 January 1, 2018 thru December 31, 2022 5,219 $ 10,376
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 $ 1,036 $ 457 $ (72 ) $ (92 ) $ 964 $ 365 Risk management assets - long term 10,665 — (1 ) — 10,664 — Total assets $ 11,701 $ 457 $ (73 ) $ (92 ) $ 11,628 $ 365 Accrued expenses and other current liabilities $ (253 ) $ (450 ) $ 72 $ 92 $ (181 ) $ (358 ) Other liabilities (1 ) (24 ) 1 — — (24 ) Total liabilities $ (254 ) $ (474 ) $ 73 $ 92 $ (181 ) $ (382 )
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 $ (1,480 ) $ 1,025 Interest expense (144 ) 10,375 Direct operating expenses (966 ) — Total $ (2,590 ) $ 11,400 2015 Losses on commodity derivatives, net $ (13,209 ) $ 11,477 Interest expense (425 ) 373 Direct operating expenses (913 ) — Total $ (14,547 ) $ 11,850 2014 Losses on commodity derivatives, net $ (337 ) $ (12,334 ) Interest expense (707 ) 284 Direct operating expenses (1,035 ) — Total $ (2,079 ) $ (12,050 )

Property, Plant and Equipment38

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

Goodwill and Intangible Asset39

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 Propane Marketing Services Total (in thousands) Balance at January 1, 2015 $ 125,974 $ 137,243 $ 88,466 $ 31,335 $ 383,018 Goodwill acquired during the year — — — 5,806 5,806 Return of purchase price (7,382 ) — — — (7,382 ) Impairment charges (118,592 ) (23,574 ) — (6,322 ) (148,488 ) Balance at December 31, 2015 — 113,669 88,466 30,819 232,954 Impairment charges — — (15,456 ) (15,456 ) Balance at December 31, 2016 $ — $ 113,669 $ 88,466 $ 15,363 $ 217,498
Schedule of finite-jived intangible assets	Intangible assets, net, consist of the following: December 31, 2016 2015 (in thousands) Gross carrying amount: Customer relationships $ 133,503 $ 136,030 Customer contracts 95,594 95,594 Dedicated acreage 53,350 53,350 Collaborative arrangements 11,884 11,884 Noncompete agreements 3,423 3,575 Other 751 751 $ 298,505 $ 301,184 Accumulated amortization: Customer relationships $ (31,471 ) $ (23,885 ) Customer contracts (33,414 ) (24,538 ) Dedicated acreage (4,439 ) (2,661 ) Collaborative arrangements (601 ) — Noncompete agreements (3,086 ) (2,664 ) Other (211 ) (155 ) $ (73,222 ) $ (53,903 ) Net carrying amount: Customer relationships $ 102,032 $ 112,145 Customer contracts 62,180 71,056 Dedicated acreage 48,911 50,689 Collaborative arrangements 11,283 11,884 Noncompete agreements 337 911 Other 540 596 $ 225,283 $ 247,281

Investment in Unconsolidated 40

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

Accrued Expenses and Other Cu41

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

Asset Retirement Obligations (T

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.

Convertible Preferred Units (Ta

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

Debt Obligations (Tables)

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 $ 3,809 $ 1,252,059 Less unamortized deferred financing costs and discount — — (8,691 ) (2,345 ) — (11,036 ) Subtotal 711,250 177,000 291,309 57,655 3,809 1,241,023 Less current portion — — — (1,676 ) (3,809 ) (5,485 ) Non-current portion $ 711,250 $ 177,000 $ 291,309 $ 55,979 $ — $ 1,235,538 Our outstanding debt consists of the following as of December 31, 2015: AMID JPE Revolving Credit Revolving Credit Other Agreement (1) Agreement (1) Debt Total (in thousands) Balance $ 525,100 $ 162,000 $ 3,639 $ 690,739 Less current portion — — (2,899 ) (2,899 ) Non-current portion $ 525,100 $ 162,000 $ 740 $ 687,840 ______________________ (1) Unamortized deferred financing costs related to the Credit Agreement are included in Other assets, net.
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%

Partners' Capital (Tables)

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 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

Net Income (Loss) per Limited46

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

Long-Term Incentive Plan (Table

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.

Income Taxes (Tables)

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 (2,057 ) (1,240 ) (711 ) Effective income tax rate 5.7 % 1.0 % 1.2 %
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 $ (45,427 ) $ (182,922 ) $ (68,824 ) US Federal statutory tax rate 34 % 34 % 34 % Federal income tax (expense) benefit at statutory rate 15,445 62,193 23,400 Reconciling items: Partnership loss not subject to income tax (benefit) (17,218 ) (63,083 ) (23,759 ) State and local tax expense (800 ) (857 ) (459 ) Other (5 ) (141 ) (39 ) Income tax expense $ (2,578 ) $ (1,888 ) $ (857 )
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 )

Commitments and Contingencies (

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 $ 9,869 $ 18,045 2018 — 806 — — 6,331 7,137 2019 888,250 2,233 — — 5,079 895,562 2020 — 2,299 — — 2,905 5,204 2021 — 4,430 300,000 — 2,253 306,683 Thereafter — 48,555 — 44,363 17,991 110,909 $ 888,250 $ 60,000 $ 300,000 $ 50,862 $ 44,428 $ 1,343,540 (1) Upon closing of the JPE Merger, the proceeds from the 8.50% Senior Notes were used to repay the JPE Credit Agreement. (2) In some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for purposes of estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management's experience, or the asset's estimated economic life.

Supplemental Cash Flow Inform50

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 — —

Reportable Segments (Tables)

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 Propane Marketing Services Total (in thousands) Commodity sales $ 91,444 $ 304,501 $ 21,999 $ 6,812 $ 14,655 $ 129,116 $ 568,527 Services 22,558 12,146 18,109 40,502 50,999 14,536 158,850 Gains (losses) on commodity derivatives, net (833 ) (341 ) — (7 ) (436 ) 1,162 (455 ) Total Revenue 113,169 316,306 40,108 47,307 65,218 144,814 726,922 Cost of sales 63,832 288,496 21,288 3,049 11,564 54,794 443,023 Direct operating expenses 33,802 8,383 5,923 10,945 10,783 53,536 123,372 Corporate expenses 99,430 Depreciation, amortization, and accretion 106,818 Loss on sale of assets, net 2,870 Loss on impairment of plant, property and equipment 697 Loss on impairment of goodwill 15,456 Interest expense 21,469 Earnings in unconsolidated affiliates (40,158 ) Other (income) expense (628 ) Income tax expense 2,578 Income (loss) from continuing operations (48,005 ) Loss from discontinuing operations, net of tax (539 ) Net income (loss) (48,544 ) Net income (loss) attributable to non-controlling interest 2,766 Net income (loss) attributable to partnership $ (51,310 ) Segment gross margin $ 48,245 $ 29,760 $ 18,616 $ 82,346 $ 42,872 $ 88,948 December 31, 2015 Gas Gathering and Processing Services Liquid Pipelines and Services Natural Gas Transportation Services Offshore Pipelines and Services Terminalling Services Propane Marketing Services Total (in thousands) Commodity sales $ 107,680 $ 457,390 $ 23,972 $ 13,798 $ 10,343 $ 159,674 $ 772,857 Services 30,196 12,895 16,035 21,457 45,022 17,157 142,762 Gains (losses) on commodity derivatives, net 1,240 — — 84 21 (3,077 ) (1,732 ) Total Revenue 139,116 470,285 40,007 35,339 55,386 173,754 913,887 Cost of sales 72,960 446,125 21,858 9,914 8,893 70,553 630,303 Direct operating expenses 35,250 8,310 6,728 9,425 10,414 57,353 127,480 Corporate expenses 77,835 Depreciation, amortization, and accretion 98,596 Loss on sale of assets, net 3,920 Loss on impairment of goodwill 148,488 Interest expense 20,120 Earnings in unconsolidated affiliates (8,201 ) Other (income) expense (1,732 ) Income tax expense 1,888 Income (loss) from continuing operations (184,810 ) Loss from discontinuing operations, net of tax (15,031 ) Net income (loss) (199,841 ) Net income (loss) attributable to non-controlling interest (13 ) Net income (loss) attributable to partnership $ (199,828 ) Segment gross margin $ 65,692 $ 24,160 $ 18,073 $ 33,613 $ 36,079 $ 91,437 December 31, 2014 Gas Gathering and Processing Services Liquid Pipelines and Services Natural Gas Transportation Services Offshore Pipelines and Services Terminalling Services Propane Marketing Services Total (in thousands) Commodity sales $ 148,198 $ 470,336 $ 70,964 $ 20,044 $ 11,521 $ 188,702 $ 909,765 Services 15,248 11,548 12,925 24,426 41,357 18,194 123,698 Gains (losses) on commodity derivatives, net 1,050 — — 41 — (13,762 ) (12,671 ) Total Revenue 164,496 481,884 83,889 44,511 52,878 193,134 1,020,792 Cost of dales 112,719 459,319 70,100 15,133 6,859 125,742 789,872 Direct operating expenses 21,197 5,819 6,975 11,142 11,525 52,885 109,543 Corporate expenses 72,744 Depreciation, amortization, and accretion 72,527 Loss on sale of assets, net 5,080 Loss on impairment of plant, property and equipment 21,344 Interest expense 16,558 Earnings in unconsolidated affiliates (348 ) Other (income) expense 662 Loss on extinguishment of debt 1,634 Income tax expense 857 Income (loss) from continuing operations (69,681 ) Loss from discontinuing operations, net of tax (9,886 ) Net income (loss) (79,567 ) Net income (loss) attributable to non-controlling interest 3,993 Net income (loss) attributable to partnership $ (83,560 ) Segment gross margin $ 51,213 $ 22,564 $ 13,691 $ 29,089 $ 34,493 $ 80,083
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 422,636 426,854 Natural Gas Transportation Services 221,604 146,927 Offshore Pipelines and Services 400,193 190,271 Terminalling Services 299,534 291,130 Propane Marketing Services 140,864 173,558 Other (1) 333,601 27,135 Total assets $ 2,349,321 $ 1,751,889 _______________________ (1) Other assets not allocable to segments consist of investment in unconsolidated affiliates, restricted cash and other assets.

Quarterly Financial Data (Una52

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 $ 143,376 $ 185,836 $ 187,659 $ 210,051 Gross margin (1) 74,045 81,072 76,427 79,243 Operating loss (8,401 ) (10,368 ) (12,125 ) (33,850 ) Net income (loss) (10,603 ) (9,481 ) (7,797 ) (20,663 ) Net income (loss) attributable to the Partnership (10,600 ) (10,435 ) (8,993 ) (21,282 ) General Partner's Interest in net income (loss) (97 ) (107 ) (26 ) (3 ) Limited Partners' Interest in net income (loss) $ (10,503 ) $ (10,328 ) $ (8,967 ) $ (21,279 ) Limited Partners' income (loss) per unit: Loss from continuing operations $ (0.32 ) $ (0.33 ) $ (0.33 ) $ (0.61 ) Net income (loss) $ (0.33 ) $ (0.33 ) $ (0.33 ) $ (0.61 ) Year Ended December 31, 2015 Total revenues $ 238,035 $ 265,703 $ 209,416 $ 200,733 Gross margin (1) 73,088 66,757 56,829 72,380 Operating income (loss) 2,187 (5,769 ) (10,831 ) (158,322 ) Net income (loss) from continuing operations (1,525 ) (10,913 ) (15,207 ) (157,165 ) Income (loss) from discontinued operations, net of tax (402 ) 511 (1,300 ) (13,840 ) Net income (loss) attributable to noncontrolling interest 4 22 24 (63 ) Net income (loss) attributable to the Partnership (1,932 ) (10,425 ) (16,532 ) (170,939 ) General Partner's Interest in net income (loss) (32 ) (66 ) (104 ) (1,621 ) Limited Partners' Interest in net income (loss) $ (1,900 ) $ (10,358 ) $ (16,428 ) $ (169,319 ) Limited Partners' income (loss) per unit: Loss from continuing operations $ (0.15 ) $ (0.39 ) $ (0.50 ) $ (3.55 ) Net loss $ (0.16 ) $ (0.38 ) $ (0.53 ) $ (3.85 ) (1) For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use gross margin to evaluate our operating performance, please read Item 7. "Management's Discussion and Analysis, How We Evaluate Our Operations." (2) We recognized goodwill impairment charges of $15.4 million and $148.5 million in the fourth quarters of 2016 and 2015, respectively.

Organization and Basis of Pre53

Organization and Basis of Presentation (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)state	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	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%
Number of states in which entity operates | state	46
Services	$ 158,850	$ 142,762	$ 123,698
Depreciation, amortization and accretion expense	106,818	98,596	72,527
Earnings in unconsolidated affiliates	(40,158)	(8,201)	(348)
Net loss	(48,544)	(199,841)	(79,567)
Intangible assets, net	225,283	247,281
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
Allowance for doubtful accounts receivable	1,900	1,200
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%

Acquisitions and Divestitures J

Acquisitions and Divestitures JP Energy Partners Merger (Details) $ in Millions	Mar. 08, 2017USD ($)business_segmentshares	Dec. 31, 2016shares	Dec. 31, 2015shares	Dec. 31, 2014shares
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

Acquisitions and Divestitures D

Acquisitions and Divestitures Delta House Investment (Details) - USD ($) $ in Thousands	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%

Acquisitions and Divestitures E

Acquisitions and Divestitures Emerald Transactions (Details) $ / shares in Units, $ in Thousands	Apr. 27, 2016USD ($)MMcf / dlateralagreementplatformmi	Apr. 25, 2016USD ($)MMcf / dlateralplatformmi$ / sharesshares	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
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

Acquisitions and Divestitures G

Acquisitions and Divestitures Gulf of Mexico Pipeline Narrative (Details) $ in Thousands	Apr. 15, 2016USD ($)mi	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Total revenue		$ 210,051	$ 187,659	$ 185,836	$ 143,376	$ 200,733	$ 209,416	$ 265,703	$ 238,035	$ 726,922	$ 913,887	$ 1,020,792
Operating loss		(33,850)	$ (12,125)	$ (10,368)	$ (8,401)	$ (158,322)	$ (10,831)	$ (5,769)	$ 2,187	(64,744)	$ (172,735)	$ (50,318)
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

Acquisitions and Divestitures S

Acquisitions and Divestitures Southern Propane Inc. (Details) - USD ($) $ in Thousands	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		$ 217,498	$ 232,954	$ 383,018
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

Acquisitions and Divestitures C

Acquisitions and Divestitures Costar Acquisition Narrative (Details) - USD ($) $ in Thousands	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			$ 15,400	$ 148,500	$ 15,456	$ 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

Acquisitions and Divestitures L

Acquisitions and Divestitures Lavaca Acquisition Narrative (Details) $ in Thousands	Jan. 31, 2014USD ($)mi	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Loss on impairment of goodwill		$ 15,400	$ 148,500	$ 15,456	$ 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

Acquisitions and Divestitures61

Acquisitions and Divestitures JP Development (Details) - Common Control Acquisition $ in Millions	Feb. 12, 2014USD ($)shares
Business Acquisition [Line Items]
Consideration transferred	$ 319.1
Common units issued (shares) | shares	5,841,205
Cash	$ 52
Related amounts receivable forgiven by ArcLight	$ 4.3

Discontinued Operations (Detail

Discontinued Operations (Details) - USD ($) $ in Thousands	Feb. 12, 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		$ (13,840)	$ (1,300)	$ 511	$ (402)		$ (539)	$ (15,031)	$ (9,886)
Loss on impairment of noncurrent assets held for sale							0	0	673
Mid-Continental
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on disposal								12,900
Cash proceeds from divestiture of business	$ 9,700
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
Loss on impairment of goodwill and assets held for sale							0	(12,909)	0
Depreciation, amortization and accretion							211	2,281	2,258
(Gain) loss on sale of assets, net							(114)	119	229
Total expenses							11,987	444,464	966,781
Operating (loss) income							(492)	(14,680)	699
Other income (expense)							(47)	(271)	(366)
(Loss) income from discontinued operations before income tax expense							(539)	(14,951)	333
Income tax expense							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]
Loss on disposal						$ 7,300			(7,288)
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)
Purchase price of disposal group						$ 9,100
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)
Loss on impairment of noncurrent assets held for sale									$ 700

Concentration of Credit Risk (D

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	17.00%
Customer B
Revenue, Major Customer
Entity-wide revenue by major customer, percentage	10.00%
Customer C
Revenue, Major Customer
Entity-wide revenue by major customer, percentage		28.00%
Customer D
Revenue, Major Customer
Entity-wide revenue by major customer, percentage			16.00%

Inventory (Details)

Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Crude oil	$ 1,216	$ 486
NGLs	3,482	2,638
Refined products	291	463
Materials, supplies and equipment	1,787	1,654
Total inventory	$ 6,776	$ 5,241

Detail of Certain Asset Accou65

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	2,895	115
Other receivables	2,998	2,688
Due from related parties	4,805	8,688
Risk management assets	964	365
Other assets	6,303	5,753
Discontinued operations, current assets	0	2,730
Total Other current assets	$ 27,667	$ 25,526

Risk Management Activities (Com

Risk Management Activities (Commodity Derivatives) (Details) - Commodity Contract	12 Months Ended
	Dec. 31, 2016galbbl	Dec. 31, 2015galbbl
Crude Oil
Derivative [Line Items]
Derivative notional volume	180,000,000	0
Fixed Price | Propane
Derivative [Line Items]
Derivative notional volume | gal	4,364,880,000	8,614,631,000
Fixed Price | Crude Oil
Derivative [Line Items]
Derivative notional volume	0	(93,000,000)

Risk Management Activities (Int

Risk Management Activities (Interest Rate Swap) (Details) - Interest rate swap $ in Thousands	Dec. 31, 2016USD ($)
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

Risk Management Activities (Det

Risk Management Activities (Details Textual) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Aug. 31, 2015	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
Propane | Commodity Contract
Derivative [Line Items]
Payments Receipts on Commodity Derivatives Settled	$ 8,700

Risk Management Activities (Fai

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	$ 11,701	$ 457
Derivative asset, gross derivative liabilities	(73)	(92)
Derivative asset, fair value, net	11,628	365
Derivative liability, gross derivative assets	(254)	(474)
Derivative liability, gross derivative liabilities	73	92
Derivative liability, fair value, net	(181)	(382)
Other current assets
Derivative [Line Items]
Derivative asset, gross derivative asset	1,036	457
Derivative asset, gross derivative liabilities	(72)	(92)
Derivative asset, fair value, net	964	365
Risk management assets - long term
Derivative [Line Items]
Derivative asset, gross derivative asset	10,665	0
Derivative asset, gross derivative liabilities	(1)	0
Derivative asset, fair value, net	10,664	0
Accrued expenses and other current liabilities
Derivative [Line Items]
Derivative liability, gross derivative assets	(253)	(450)
Derivative liability, gross derivative liabilities	72	92
Derivative liability, fair value, net	(181)	(358)
Other liabilities
Derivative [Line Items]
Derivative liability, gross derivative assets	(1)	(24)
Derivative liability, gross derivative liabilities	1	0
Derivative liability, fair value, net	$ 0	$ (24)

Risk Management Activities (Rea

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	$ (455)	$ (1,732)	$ (12,671)
Commodity derivative instruments, net
Derivatives, Fair Value [Line Items]
Loss on commodity derivatives, net	(2,590)	(14,547)	(2,079)
Gain (loss) on derivatives, unrealized	11,400	11,850	(12,050)
Commodity derivative instruments, net | Losses on commodity derivatives, net
Derivatives, Fair Value [Line Items]
Loss on commodity derivatives, net	(1,480)	(13,209)	(337)
Gain (loss) on derivatives, unrealized	1,025	11,477	(12,334)
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

Fair Value Measurement (Details

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%

Property, Plant and Equipment72

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	$ 1,462,033	$ 1,311,964
Less accumulated depreciation	(317,030)	(240,450)
Property, plant and equipment, net	1,145,003	1,071,514
Land
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	23,520	18,902
Construction in progress
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	131,448	58,146
Transportation Equipment
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	44,060	46,582
Buildings and improvements
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	24,225	22,398
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	210,579	210,208
Equipment
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross	$ 102,409	78,131
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)	20 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

Property, Plant and Equipment73

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		$ 1,462,033	$ 1,311,964
Depreciation		82,800	75,000	$ 50,900
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		$ 100	$ 1,100	$ 1,700

Goodwill and Intangible Asset74

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	$ 15,400	$ 148,500	$ 15,456	$ 148,488	$ 0
Amortization of intangible assets			22,000	22,800	20,800
Thereafter	138,100		138,100
Net unamortized intangible asset	225,283	247,281	$ 225,283	247,281
Minimum
Goodwill [Line Items]
Useful life			5 years
2,017	14,300		$ 14,300
2,018	14,300		14,300
2,019	14,300		14,300
2,020	14,300		14,300
2,021	14,300		$ 14,300
Maximum
Goodwill [Line Items]
Useful life			30 years
2,017	19,900		$ 19,900
2,018	19,900		19,900
2,019	19,900		19,900
2,020	19,900		19,900
2,021	19,900		19,900
Costar Midstream, L.L.C.
Goodwill [Line Items]
Loss on impairment of goodwill		95,000
Adjustment
Goodwill [Line Items]
Amortization of intangible assets			100	1,200	2,000
Customer relationships
Goodwill [Line Items]
Impairment of intangible assets				700
Net unamortized intangible asset	102,032	112,145	102,032	112,145
Customer contracts
Goodwill [Line Items]
Impairment of intangible assets					$ 8,100
Net unamortized intangible asset	62,180	71,056	$ 62,180	71,056
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			0	23,574
Propane Marketing Services
Goodwill [Line Items]
Loss on impairment of goodwill			15,456	$ 6,322
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		23,600
JP Liquids Business | Propane Marketing Services
Goodwill [Line Items]
Loss on impairment of goodwill		$ 6,300	2,700
Pinnacle Propane Express Business | Propane Marketing Services
Goodwill [Line Items]
Loss on impairment of goodwill			$ 12,800

Goodwill and Intangible Asset75

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			$ 232,954	$ 383,018
Goodwill acquired during the year				5,806
Return of purchase price				(7,382)
Impairment charges	$ (15,400)	$ (148,500)	(15,456)	(148,488)	$ 0
Goodwill ending balance	217,498	232,954	217,498	232,954	383,018
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				(118,592)
Goodwill ending balance	0	0	0	0	125,974
Liquid Pipelines and Services
Goodwill [Roll Forward]
Goodwill beginning balance			113,669	137,243
Goodwill acquired during the year				0
Return of purchase price				0
Impairment charges			0	(23,574)
Goodwill ending balance	113,669	113,669	113,669	113,669	137,243
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
Propane Marketing Services
Goodwill [Roll Forward]
Goodwill beginning balance			30,819	31,335
Goodwill acquired during the year				5,806
Return of purchase price				0
Impairment charges			(15,456)	(6,322)
Goodwill ending balance	$ 15,363	$ 30,819	$ 15,363	$ 30,819	$ 31,335

Goodwill and Intangible Asset76

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	$ 298,505	$ 301,184
Accumulated amortization	(73,222)	(53,903)
Net carrying amount	225,283	247,281
Customer relationships
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	133,503	136,030
Accumulated amortization	(31,471)	(23,885)
Net carrying amount	102,032	112,145
Customer contracts
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	95,594	95,594
Accumulated amortization	(33,414)	(24,538)
Net carrying amount	62,180	71,056
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	3,423	3,575
Accumulated amortization	(3,086)	(2,664)
Net carrying amount	337	911
Other
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	751	751
Accumulated amortization	(211)	(155)
Net carrying amount	$ 540	$ 596

Investment in Unconsolidated 77

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

- Financial Information for the

- 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

Investment in Unconsolidated 79

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

Investment in Unconsolidated 80

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

Accrued Expenses and Other Cu81

Accrued Expenses and Other Current Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Payables and Accruals [Abstract]
Capital expenditures	$ 14,499	$ 7,780
Employee compensation	10,804	7,870
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	3,080	3,742
Deferred financing costs	2,743	0
Taxes payable	1,688	1,563
Recoverable gas costs	1,126	1,337
Gas imbalances payable	1,098	413
Other	10,903	7,329
Accrued expenses and other current liabilities	$ 81,284	$ 46,751

Asset Retirement Obligations (D

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

Debt Obligations (Outstanding B

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	$ 1,252,059			$ 690,739
Less unamortized deferred financing costs and discount	(11,036)
Subtotal	1,241,023
Less current portion	(5,485)			(2,899)
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	$ 3,809			3,639
Less unamortized deferred financing costs and discount	0
Subtotal	3,809
Less current portion	(3,809)			(2,899)
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

Partners' Capital (Units Outsta

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

Convertible Preferred Units Ser

Convertible Preferred Units Series A-1 Convertible Preferred Units (Details) - USD ($) $ / shares in Units, $ in Thousands	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

Debt Obligations Credit Agreeme

Debt Obligations Credit Agreement (Details) $ in Millions	Apr. 25, 2016USD ($)	Feb. 12, 2014USD ($)	Dec. 31, 2016USD ($)	Mar. 08, 2017USD ($)	Sep. 30, 2016	Dec. 31, 2015USD ($)	Dec. 31, 2014
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity	$ 750
Line of credit facility, maximum borrowing capacity upon increase	$ 900
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
Line of credit facility, maximum borrowing capacity				$ 900
Revolving Credit Facility | JPE Revolving Credit Agreement
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity		$ 275
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

Convertible Preferred Units S87

Convertible Preferred Units Series A-2 Convertible Preferred Units (Details) - Series A-2 - USD ($) $ / shares in Units, $ in Millions	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Jul. 27, 2015
Class of Stock [Line Items]
Issuance of units			$ 45
Investment options, exercise price (in dollars per share)	$ 15.87	$ 17.50
Call right defined acquisition, value				$ 100
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

Debt Obligations 8.50% Senior N

Debt Obligations 8.50% Senior Notes (Details) - USD ($) $ in Millions	Dec. 28, 2016	Dec. 14, 2018	Dec. 31, 2016
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt	$ 294
Debt issuance costs	(6)
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%

Convertible Preferred Units S89

Convertible Preferred Units Series C (Details) - USD ($) $ / shares in Units, $ in Millions	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
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
Issuance of Preferred Units | ArcLight | Series C
Class of Stock [Line Items]
Issuance of units (in shares)		8,571,429

Debt Obligations Debt Instrumen

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%
2,018
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage	104.25%
2,019
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%

Convertible Preferred Units S91

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
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
Partners' capital account (in dollars per share)	$ 0.4125
Shares issued upon conversion (in shares)	1
Series D call right, ratio multiplier		1.03

Debt Obligations 3.77% Senior N

Debt Obligations 3.77% Senior Notes (Details)	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)	Dec. 28, 2016USD ($)
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
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

Partners' Capital Outstanding U

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

Partners' Capital Textual (Deta

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

Partners' Capital Series B Unit

Partners' Capital Series B Units (Details) - USD ($) $ in Millions	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
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

Partners' Capital Equity Offeri

Partners' Capital Equity Offerings (Details) - USD ($)	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
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
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

Partners' Capital General Partn

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	$ 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

Partners' Capital Distributions

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

Partners' Capital Distributio99

Partners' Capital Distributions Textual (Details) - $ / shares	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%

Net Income (Loss) per Limite100

Net Income (Loss) per Limited Partner Unit (Details) $ / shares in Units, $ in Thousands	Mar. 08, 2017shares	Dec. 31, 2016shares	Oct. 07, 2014shares	Dec. 31, 2016USD ($)$ / sharesshares	Sep. 30, 2016USD ($)$ / shares	Jun. 30, 2016USD ($)$ / shares	Mar. 31, 2016USD ($)$ / shares	Dec. 31, 2015USD ($)$ / sharesshares	Sep. 30, 2015USD ($)$ / shares	Jun. 30, 2015USD ($)$ / shares	Mar. 31, 2015USD ($)$ / shares	Dec. 31, 2014shares	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares
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				$ (20,663)	$ (7,797)	$ (9,481)	$ (10,603)	$ (157,165)	$ (15,207)	$ (10,913)	$ (1,525)		$ (48,005)	$ (184,810)	$ (69,681)
Less: Net income (loss) attributable to noncontrolling interests								$ (63)	$ 24	$ 22	$ 4		2,766	(13)	3,993
Net loss from continuing operations attributable to the Partnership													(50,771)	(184,797)	(73,674)
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													(1,745)	(3,309)	(1,510)
Net loss from continuing operations attributable to Limited Partners													(81,164)	(206,629)	(90,212)
Net loss from discontinued operations attributable to Limited Partners													(532)	(15,031)	(269)
Net loss attributable to Limited Partners													$ (81,696)	$ (221,660)	$ (90,481)
Weighted average number of common units used in computation of Limited Partners' net loss per common unit - basic and diluted (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				$ (0.61)	$ (0.33)	$ (0.33)	$ (0.32)	$ (3.55)	$ (0.50)	$ (0.39)	$ (0.15)
Loss from continuing operations, basic and diluted (in usd per share) | $ / shares													$ (1.59)	$ (4.59)	$ (3.28)
Loss from discontinued operations, basic and diluted (in usd per share) | $ / shares													(0.01)	(0.33)	(0.01)
Limited partners’ net income (loss) per unit (basic and diluted) (in dollars per share) | $ / shares				$ (0.61)	$ (0.33)	$ (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													$ 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
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
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
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

Long Term Incentive Plan (Textu

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	$ 7.50		$ 9.03	$ 7.50	$ 0
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 2,016
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

Long-Term Incentive Plan (Unit-

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
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

Long-Term Incentive Plan Assump

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%

Long-Term Incentive Plan Option

Long-Term Incentive Plan Option Grant Awards (Details) - USD ($) $ / shares in Units, $ in Thousands	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
Granted (in dollars per share)				$ 7.50	13.13	7.50
Vested (in dollars per share)					0	0
Forfeited (in dollars per share)					0	0
Outstanding ending balance (in dollars per share)	$ 9.03	$ 7.50	$ 12	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
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

Income Taxes Income Tax (Expens

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	$ (2,057)	$ (1,240)	$ (711)
Effective income tax rate	5.70%	1.00%	1.20%

Income Taxes Narrative (Details

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

Income Taxes Income Tax Expense

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	$ (45,427)	$ (182,922)	$ (68,824)
US Federal statutory tax rate	34.00%	34.00%	34.00%
Federal income tax (expense) benefit at statutory rate	$ 15,445	$ 62,193	$ 23,400
Partnership loss not subject to income tax (benefit)	(17,218)	(63,083)	(23,759)
State and local tax expense	(800)	(857)	(459)
Other	(5)	(141)	(39)
Income tax expense	$ (2,578)	$ (1,888)	$ (857)

Income Taxes Deferred Tax Asset

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)

Commitments and Contingencie109

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	$ 19.5	$ 17.7	$ 10.6

Commitments and Contingencie110

Commitments and Contingencies (Contractual Obligations) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 28, 2016	Sep. 30, 2016
Future Non Cancelable Commitment [Line Items]
2,017	$ 18,045
2,018	7,137
2,019	895,562
2,020	5,204
2,021	306,683
Thereafter	110,909
Total	1,343,540
Asset Retirement Obligation (2)
Future Non Cancelable Commitment [Line Items]
2,017	6,499
2,018	0
2,019	0
2,020	0
2,021	0
Thereafter	44,363
Total	50,862
Other
Future Non Cancelable Commitment [Line Items]
2,017	9,869
2,018	6,331
2,019	5,079
2,020	2,905
2,021	2,253
Thereafter	17,991
Total	44,428
Revolving Credit Agreements
Future Non Cancelable Commitment [Line Items]
2,017	0
2,018	0
2,019	888,250
2,020	0
2,021	0
Thereafter	0
Total	888,250
Senior Notes | 8.50% Senior Notes (1)
Future Non Cancelable Commitment [Line Items]
2,017	0
2,018	0
2,019	0
2,020	0
2,021	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]
2,017	$ 1,677
2,018	806
2,019	2,233
2,020	2,299
2,021	4,430
Thereafter	48,555
Total	$ 60,000
Debt instrument, interest rate (percent)	3.77%		3.77%

Related- Party Transactions (De

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	$ 99,430,000	$ 77,835,000	$ 72,744,000
Direct operating expenses	123,372,000	127,480,000	109,543,000
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

Supplemental Cash Flow Infor112

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

Reportable Segments Narrative (

Reportable Segments Narrative (Details)	12 Months Ended
	Dec. 31, 2015
Sales Revenue, Segment | Customer Concentration Risk | Customer B | Gas Gathering and Processing Services
Revenue, Major Customer
Entity-wide revenue by major customer, percentage	12.00%

Reportable Segments (Details)

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										$ 568,527	$ 772,857	$ 909,765
Services										158,850	142,762	123,698
Loss on commodity derivatives, net										(455)	(1,732)	(12,671)
Total revenue	$ 210,051	$ 187,659	$ 185,836	$ 143,376	$ 200,733	$ 209,416	$ 265,703	$ 238,035		726,922	913,887	1,020,792
Cost of sales										443,023	630,303	789,872
Direct operating expenses										123,372	127,480	109,543
Corporate expenses										99,430	77,835	72,744
Depreciation, amortization and accretion expense										106,818	98,596	72,527
Loss on sale of assets, net										2,870	3,920	5,080
Loss on impairment of property, plant and equipment									$ 21,300	697	0	21,344
Loss on impairment of goodwill	15,400				148,500					15,456	148,488	0
Interest expense										21,469	20,120	16,558
Earnings in unconsolidated affiliates										(40,158)	(8,201)	(348)
Other (income) expense										(628)	(1,732)	662
Loss on extinguishment of debt										0	0	1,634
Income tax (expense) benefit										2,578	1,888	857
Loss from continuing operations	(20,663)	(7,797)	(9,481)	(10,603)	(157,165)	(15,207)	(10,913)	(1,525)		(48,005)	(184,810)	(69,681)
Loss from discontinued operations, net of tax					(13,840)	(1,300)	511	(402)		(539)	(15,031)	(9,886)
Net income (loss)										(48,544)	(199,841)	(79,567)
Net income (loss) attributable to noncontrolling interests					(63)	24	22	4		2,766	(13)	3,993
Net loss attributable to the Partnership	(21,282)	(8,993)	(10,435)	(10,600)	(170,939)	(16,532)	(10,425)	(1,932)		(51,310)	(199,828)	(83,560)
Gross margin	$ 79,243	$ 76,427	$ 81,072	$ 74,045	$ 72,380	$ 56,829	$ 66,757	$ 73,088
Liquid Pipelines and Services
Segment information
Loss on impairment of goodwill										0	23,574
Terminalling Services
Segment information
Loss on impairment of goodwill										0	0
Propane Marketing Services
Segment information
Loss on impairment of goodwill										15,456	6,322
Commodity derivative instruments, net
Segment information
Loss on commodity derivatives, net										(2,590)	(14,547)	(2,079)
Gain (loss) on derivatives, unrealized										11,400	11,850	(12,050)
Losses on commodity derivatives, net | Commodity derivative instruments, net
Segment information
Loss on commodity derivatives, net										(1,480)	(13,209)	(337)
Gain (loss) on derivatives, unrealized										1,025	11,477	(12,334)
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										304,501	457,390	470,336
Services										12,146	12,895	11,548
Loss on commodity derivatives, net										(341)	0	0
Total revenue										316,306	470,285	481,884
Cost of sales										288,496	446,125	459,319
Direct operating expenses										8,383	8,310	5,819
Gross margin										29,760	24,160	22,564
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
Segment assets: | Propane Marketing Services
Segment information
Commodity Sales										129,116	159,674	188,702
Services										14,536	17,157	18,194
Loss on commodity derivatives, net										1,162	(3,077)	(13,762)
Total revenue										144,814	173,754	193,134
Cost of sales										54,794	70,553	125,742
Direct operating expenses										53,536	57,353	52,885
Gross margin										$ 88,948	$ 91,437	$ 80,083

Reportable Segments Assets (Det

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	422,636	426,854
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
Segment assets: | Propane Marketing Services
Segment Reporting Information [Line Items]
Total assets	140,864	173,558
Other
Segment Reporting Information [Line Items]
Total assets	$ 333,601	$ 27,135

Quarterly Financial Data (Un116

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	$ 210,051	$ 187,659	$ 185,836	$ 143,376	$ 200,733	$ 209,416	$ 265,703	$ 238,035	$ 726,922	$ 913,887	$ 1,020,792
Gross margin	79,243	76,427	81,072	74,045	72,380	56,829	66,757	73,088
Operating loss	(33,850)	(12,125)	(10,368)	(8,401)	(158,322)	(10,831)	(5,769)	2,187	(64,744)	(172,735)	(50,318)
Net income (loss)	(20,663)	(7,797)	(9,481)	(10,603)	(157,165)	(15,207)	(10,913)	(1,525)	(48,005)	(184,810)	(69,681)
Loss from discontinued operations, net of tax					(13,840)	(1,300)	511	(402)	(539)	(15,031)	(9,886)
Net income (loss) attributable to noncontrolling interests					(63)	24	22	4	2,766	(13)	3,993
Net income (loss) attributable to the Partnership	(21,282)	(8,993)	(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)	(3)	(26)	(107)	(97)	(1,621)	(104)	(66)	(32)
Limited Partners' Interest in net income (loss)	$ (21,279)	$ (8,967)	$ (10,328)	$ (10,503)	$ (169,319)	$ (16,428)	$ (10,358)	$ (1,900)
Loss from continuing operations (in dollars per share)	$ (0.61)	$ (0.33)	$ (0.33)	$ (0.32)	$ (3.55)	$ (0.50)	$ (0.39)	$ (0.15)
Limited partners’ net income (loss) per unit (basic and diluted) (in dollars per share)	$ (0.61)	$ (0.33)	$ (0.33)	$ (0.33)	$ (3.85)	$ (0.53)	$ (0.38)	$ (0.16)	$ (1.60)	$ (4.92)	$ (3.29)
Loss on impairment of goodwill	$ 15,400				$ 148,500				$ 15,456	$ 148,488	$ 0

Subsequent Event (Details)

Subsequent Event (Details) $ / shares in Units, bbl in Thousands, $ in Millions	Sep. 01, 2017USD ($)	Mar. 01, 2017mibbl	Jan. 26, 2017$ / 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