Third Coast Midstream (AMID) 10-K 10 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Jun. 30, 2014	Mar. 06, 2015
Entity Registrant Name	American Midstream Partners, LP
Entity Central Index Key	1513965
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float		$294,650,782
Limited Partner Common Units
Entity Common Stock, Shares Outstanding			22,753,974
Series A
Entity Common Stock, Shares Outstanding			5,909,349
Series B
Entity Common Stock, Shares Outstanding			1,277,772

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets
Cash and cash equivalents	$499	$393
Accounts receivable	4,924	6,822
Unbilled revenue	24,619	23,001
Risk management assets	688	473
Other current assets	15,502	7,497
Current deferred tax asset	3,086	0
Current assets held for sale	52	272
Total current assets	49,370	38,458
Property, plant and equipment, net	582,182	312,701
Goodwill	142,236	16,447
Intangible assets, net	106,306	3,682
Investment in unconsolidated affiliates	22,252	0
Other assets, net	13,117	9,064
Noncurrent assets held for sale, net	1,181	1,723
Total assets	916,644	382,075
Current liabilities
Accounts payable	20,326	3,261
Accrued gas purchases	14,326	17,386
Accrued expenses and other current liabilities	25,788	15,058
Current portion of long-term debt	2,908	2,048
Risk management liabilities	215	423
Current liabilities held for sale	12	114
Total current liabilities	63,575	38,290
Risk management liabilities	0	101
Asset retirement cost	34,645	34,636
Other liabilities	126	191
Long-term debt	372,950	130,735
Deferred Tax Liabilities	8,199	4,749
Liabilities of Disposal Group, Including Discontinued Operation, Noncurrent	0	95
Total liabilities	479,495	208,797
Commitments and contingencies (see Note 19)
Series A convertible preferred units (5,745 thousand and 5,279 thousand units issued and outstanding as of December 31, 2014 and 2013, respectively)	107,965	94,811
Equity and partners' capital
General Partner Interests (392 thousand and 185 thousand units issued and outstanding as of December 31, 2014 and 2013, respectively)	-2,450	2,696
Accumulated other comprehensive income	2	104
Total partners’ capital	324,467	73,839
Noncontrolling interests	4,717	4,628
Total equity and partners' capital	329,184	78,467
Total liabilities, equity and partners' capital	916,644	382,075
Limited Partner Common Units [Member]
Equity and partners' capital
Limited Partners' Capital Account	294,695	71,039
Limited Partner Series B Convertible Units [Member]
Equity and partners' capital
Limited Partners' Capital Account	$32,220	$0

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical)	Dec. 31, 2014	Dec. 31, 2013
General partners' interest units issued	392,000	185,000
General partners' interest units outstanding	392,000	185,000
Limited partners, units issued	22,670,000	7,414,000
Limited partners, units outstanding	22,670,000	7,414,000
Series A
Preferred units issued	5,745,000	5,279,000
Preferred units outstanding	5,745,000	5,279,000
Series B
Preferred units issued	1,255,000	0
Preferred units outstanding	1,255,000	0

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Document Fiscal Year Focus	2014
Revenue	$307,309	$294,051	$204,868
Gain (loss) on commodity derivatives, net	1,091	28	3,400
Total revenue	308,400	294,079	208,268
Operating expenses:
Purchases of natural gas, NGLs and condensate	197,952	215,053	154,472
Direct operating expenses	45,702	32,236	17,183
Selling, general and administrative expenses	23,103	19,079	14,309
Equity compensation expense	1,536	2,094	1,783
Depreciation, amortization and accretion expense	28,832	30,002	21,287
Total operating expenses	297,125	298,464	209,034
Gain (loss) on involuntary conversion of property, plant and equipment	0	343	-1,021
Gain (loss) on sale of assets, net	-122	0	123
Loss on impairment of property, plant and equipment	-99,892	-18,155	0
Operating income (loss)	-88,739	-22,197	-1,664
Other income (expenses):
Interest expense	-7,577	-9,291	-4,570
Other expense	-670	0	0
Earnings in unconsolidated affiliates	348	0	0
Net income (loss) before income tax benefit	-96,638	-31,488	-6,234
Income Tax Expense (Benefit), Continuing Operations	557	-495	0
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	-97,195	-30,993	-6,234
Discontinued operations
Gain (loss) from operations of disposal groups, net of tax	-611	-2,413	-18
Net income (loss)	-97,806	-33,406	-6,252
Less: Comprehensive income (loss) attributable to noncontrolling interests	214	633	256
Net income (loss) attributable to the Partnership	-98,020	-34,039	-6,508
Distribution declared per common unit (a)	$1.85	$1.75	$1.73
Basic and diluted:
Income (Loss) from Continuing Operations, Per Outstanding Limited Partnership Unit, Basic	($8.54)	($7.15)	($0.70)
Limited partners' net income (loss) from discontinued operations per unit (basic and diluted)	($0.04)	($0.27)	$0
Limited partners’ net income (loss) per unit (basic and diluted)	($8.58)	($7.42)	($0.70)
Weighted Average Number of Shares Outstanding, Diluted [Abstract]
Basic and diluted	13,472	7,525	9,113
Total Partners Capital
Discontinued operations
Net income (loss) attributable to the Partnership	-98,020	-34,039	-6,508
General Partner Interest
Discontinued operations
General Partner's Interest in net income (loss)	-1,279	-1,405	-129
Limited Partner [Member]
Discontinued operations
Limited Partners' Interest in net income (loss)	-96,741	-32,634	-6,379
Terminals [Member]
Revenue		9,831
Gain (loss) on commodity derivatives, net	0	0
Total revenue	15,504
Operating expenses:
Purchases of natural gas, NGLs and condensate	0	0
Direct operating expenses	$6,342	$4,403

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net income (loss)	($97,806)	($33,406)	($6,252)
Other Comprehensive Income (Loss), Net of Tax	-102	-247	-64
Comprehensive income (loss)	-97,908	-33,653	-6,316
Less: Comprehensive income (loss) attributable to noncontrolling interests	214	633	256
Comprehensive income (loss) attributable to Partnership	($98,122)	($34,286)	($6,572)

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Partners' Capital and Noncontrolling Interest (USD $)	Total	General Partner Interest	Limited Partner Interest	Series B	Accumulated Other Comprehensive Income	Total Partners Capital	Noncontrolling Interest	Blackwater [Member]	Blackwater [Member]	Blackwater [Member]	Series B	Series B	Series B	Series B	Series B
In Thousands									General Partner Interest	Total Partners Capital			Accumulated Other Comprehensive Income	Total Partners Capital	Noncontrolling Interest
Beginning Balance at Dec. 31, 2011		$1,091	$99,890		$415	$101,396
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	0						7,407
General Partner's Interest in net income (loss)		-129
Limited Partners' Interest in net income (loss)			-6,379
Net income (loss)	-6,508					-6,508
Net Income (loss) attributable to noncontrolling interests	256						256
Issuance of common units, net of offering costs	0										0
Unit holder contributions		13				13
Unitholder distributions	-16,070	-322	-15,748			-16,070		0			0
Fair value of Series A Units in excess of net assets received	0
Net distributions to noncontrolling interest owners							-225
LTIP vesting		-1,888	1,888
Tax netting repurchase	385		385			385
Unit based compensation		1,783				1,783
Other comprehensive income (loss)	-64				-64	-64
Ending Balance at Dec. 31, 2012		548	79,266		351	80,165	7,438
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	752	-37	-1,993			-2,030	-2,782
General Partner's Interest in net income (loss)		-1,405
Limited Partners' Interest in net income (loss)			-32,634
Net income (loss)	-34,039					-34,039
Net Income (loss) attributable to noncontrolling interests	633						633
Issuance of common units, net of offering costs	54,853		54,853			54,853					0
Unit holder contributions		12,500	0		0	12,500			22,696	22,696
Unitholder distributions	-16,120	-623	-21,628			-22,251		-27,650	-30,702		0
Fair value of Series A Units in excess of net assets received	-15,612	-312	-15,300			-15,612
Net distributions to noncontrolling interest owners		0	0		0	0	-661
LTIP vesting		-2,067	2,067
Tax netting repurchase	630		630			630
Unit based compensation		2,024				2,024
Other comprehensive income (loss)	-247				-247	-247
Ending Balance at Dec. 31, 2013	73,839	2,696	71,039		104	73,839	4,628
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	8	0	-21	0	0	-21	189
General Partner's Interest in net income (loss)		-1,279
Limited Partners' Interest in net income (loss)			-96,741
Net income (loss)	-98,020					-98,020
Net Income (loss) attributable to noncontrolling interests	214						214
Issuance of common units, net of offering costs	204,255	0	351,551	0	0		0				-30,000
Issuance of Series B Units			0									32,220	0	32,220	0
Unit holder contributions		5,678	0	0		5,678	0
Unitholder distributions	-28,009	-2,913	-39,150			-42,063		0			-2,220
Fair value of Series A Units in excess of net assets received	0
Issuance and exercise of warrants		7,164	7,164
Net distributions to noncontrolling interest owners		0	0	0	0	0	-314
LTIP vesting		-824	1,067			243
Tax netting repurchase	256		256	0		256
Unit based compensation		1,356	0	0	0	1,356	0
Other comprehensive income (loss)	-102				-102	-102
Ending Balance at Dec. 31, 2014	$324,467	($2,450)	$294,695	$32,220	$2	$324,467	$4,717

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities
Net income (loss)	($97,806)	($33,406)	($6,252)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion expense	28,832	29,999	21,414
Amortization of deferred financing costs	2,212	1,334	716
Amortization of weather derivative premium	1,035	662	0
Unrealized (gain) loss on derivative contracts, net	-595	1,505	-992
Non-cash compensation	1,626	2,094	1,783
Postretirement expense (benefit)	-45	-73	-88
(Gain) loss on involuntary conversion of property, plant and equipment	0	-343	1,021
(Gain) loss on sale of assets, net	207	75	-128
Loss on impairment of property, plant and equipment	99,892	18,155	0
Loss on impairment of noncurrent assets held for sale	673	2,400	0
Deferred tax expense (benefit)	213	-847	0
Changes in operating assets and liabilities, net of effects of assets acquired and liabilities assumed:
Accounts receivable	13,067	-790	-740
Unbilled revenue	2,272	-226	2,768
Risk management assets and liabilities	-809	-1,147	-156
Other current assets	-7,533	-1,614	984
Other assets, net	6,049	-823	-57
Accounts payable	-12,026	-845	1,197
Accrued gas purchases	-5,540	462	-1,711
Accrued expenses and other current liabilities	-9,149	769	-943
Asset retirement obligations	-1,030	0	0
Other liabilities	-67	-118	-468
Net cash provided by operating activities	21,478	17,223	18,348
Net cash provided by operating activities
Cost of acquisitions, net of cash acquired	-362,316	0	-51,377
Additions to property, plant and equipment	-96,998	-27,196	-11,705
Proceeds from disposal of property, plant and equipment	6,323	500	128
Insurance proceeds from involuntary conversion of property, plant and equipment	0	482	527
Investment in unconsolidated affiliate	-12,000	0	0
Proceeds from equity method investment, return of capital	1,632	0	0
Restricted cash	-8,511	-2,000	0
Net cash used in investing activities	-471,870	-28,214	-62,427
Cash flows from financing activities
Proceeds from issuance of common units to public, net of offering costs	204,255	54,853	0
Unitholder contributions	5,588	13,075	13
Unitholder distributions	-28,009	-16,120	-16,070
Issuance of Series A Units	0	14,393	0
Acquisition of noncontrolling interests	-8	-752	0
LTIP tax netting unit repurchase	-256	-630	-385
Deferred financing costs	-3,841	-2,113	-1,564
Payments on other debt	-2,589	-2,640	0
Borrowings on other debt	3,449	3,795	0
Payments on loan to affiliate	0	-20,000	0
Payments on bank loans	0	-34,730	0
Borrowings on bank loans	0	27,546	0
Payments on long-term debt	-250,870	-131,571	-59,230
Borrowings on long-term debt	493,085	134,021	121,245
Net cash provided by financing activities	450,490	10,816	43,784
Net increase (decrease) in cash and cash equivalents	98	-175	-295
Cash and cash equivalents
Beginning of period	401	576	871
End of period	499	401	576
Supplemental cash flow information
Interest payments, net	6,726	6,416	3,185
Supplemental non-cash information
(Decrease) increase in accrued property, plant and equipment	31,390	-5,181	6,968
Receivable for reimbursable construction in progress projects	0	0	141
Fair value of Series A Units in excess of net assets received	0	15,612	0
Accrued and in-kind unitholder distribution for Series A Units	13,154	4,811	0
In-kind unitholder distribution for Series B Units	2,220	0	0
Blackwater [Member]
Cash flows from financing activities
Unitholder distributions	0	-27,650	0
Supplemental non-cash information
Noncash or Part Noncash Acquisition, Net Nonmonetary Assets Acquired (Liabilities Assumed)	0	22,121	0
Common unit issuance related to Acquisition		3,100
ArcLight [Member]
Supplemental non-cash information
Noncash or Part Noncash Acquisition, Net Nonmonetary Assets Acquired (Liabilities Assumed)	0	59,995	0
Noncontrolling Interest
Cash flows from financing activities
Proceeds from issuance of common units to public, net of offering costs	0
Acquisition of noncontrolling interests	-189	2,782	-7,407
Net distributions to noncontrolling interests	-314	-661	-225
Series B
Cash flows from financing activities
Proceeds from issuance of common units to public, net of offering costs	-30,000	0	0
Unitholder distributions	($2,220)	$0	$0

Organization_and_Basis_of_Pres

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Basis of Presentation	Organization and Basis of Presentation
	General
	American Midstream Partners, LP (the "Partnership"), was formed on August 20, 2009 as a Delaware limited partnership for the purpose of operating, developing and acquiring a diversified portfolio of midstream energy assets. The Partnership's general partner, American Midstream GP, LLC (the "General Partner"), is 95% owned by High Point Infrastructure Partners, LLC ("HPIP") and 5% owned by AIM Midstream Holdings, LLC. We hold our assets in a series of wholly owned limited liability companies, a limited partnership and a corporation. Our capital accounts consist of notional general partner units and limited partner interests.
	Nature of business
	We are engaged in the business of gathering, treating, processing, and transporting natural gas, fractionating NGLs and storing specialty chemical products through our ownership and operation of twelve gathering systems, five processing facilities, three fractionation facilities, four marine terminal sites, three interstate pipelines and five intrastate pipelines. We also own a 66.7% non-operating interest in Main Pass Oil Gathering, LP ("MPOG"), a crude oil gathering and processing system, as well as a 50% undivided, non-operating interest in the Burns Point Plant, a natural gas processing plant. Our primary assets, which are strategically located in Alabama, Georgia, Louisiana, Maryland, Mississippi, North Dakota, Tennessee and Texas, provide critical infrastructure that links producer of natural gas, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets. We currently operate more than 3,000 miles of pipelines that gather and transport over 1 Bcf/d of natural gas and operate approximately 1.7 million barrels of storage capacity across four marine terminal sites.
	Basis of presentation
	The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2014 and 2013, and results of operations, comprehensive income, changes in partners' capital and noncontrolling interest, and cash flows for the years ended December 31, 2014, 2013 and 2012.
	We have prepared the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP"). We have made reclassifications to amounts reported in prior period consolidated financial statements to conform with current year presentation. These reclassifications did not have an impact on net income for the period previously reported.
	The financial results for the years ended December 31, 2013 and 2012 have been reclassified to present an asset group previously presented as held for sale as held and used.
	The results of operations for acquisitions accounted for as business combinations have been included in the consolidated financial statements since their respective acquisition dates. See Note 3 "Acquisitions" for further information.
	Transactions Between Entities Under Common Control
	We may enter into transactions with our General Partner and affiliates whereby we receive a contribution of midstream assets or subsidiaries in exchange for consideration from the Partnership. We account for the net assets received using the historical book value of the asset or subsidiary being contributed or transferred as these are transactions between entities under common control. Our historical financial statements may be revised to include the results attributable to the assets contributed from our General Partner as if we owned such assets for all periods presented by the Partnership since either the change in control of our General Partner, effective April 15, 2013 or later.
	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. We hold a 50% undivided interest in the Burns Point gas processing facility in which we are responsible for our proportionate share of the costs and expenses of the facility. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of this undivided interest. In July 2012, the Partnership acquired an 87.4% undivided interest in the Chatom Processing and Fractionation facility (the "Chatom System"). In the fourth quarter of 2013, the Partnership acquired an additional 4.8% undivided interest in the Chatom System. Our consolidated financial statements reflect the accounts of the Chatom System since acquisition. The interests in the Chatom System held by non-affiliated working interest owners are reflected as noncontrolling interests in the Partnership's consolidated financial statements.
	The Partnership accounts for its 66.7% non-operated interest in MPOG as an equity method investments under ASC 323, as the Partnership exercises significant influence but does not control nor is the primary beneficiary of MPOG.
	Use of estimates
	When preparing consolidated financial statements in conformity with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and assumptions are based on information available at the time such estimates and assumptions are made. Adjustments made with respect to the use of these estimates and assumptions often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates and assumptions are used in, among other things, i) estimating unbilled revenues, product purchases and operating and general and administrative costs, ii) developing fair value assumptions, including estimates of future cash flows and discount rates, iii) analyzing long-lived assets, goodwill and intangible assets for possible impairment, iv) estimating the useful lives of assets and v) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.
	Cash and cash equivalents
	We consider all highly liquid investments with an original maturity of three months or less at the date of purchase to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.
	Allowance for doubtful accounts
	We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of December 31, 2014 and 2013, the Partnership recorded no allowances for losses on accounts receivable.
	Inventory
	Inventory includes natural gas liquids ("NGLs") product inventory. The Partnership records all product inventories at the lower of cost or market with a cost basis determined on a weighted average basis. Product inventories are included within Other current assets on the consolidated balance sheets.
	Operational balancing agreements and natural gas imbalances
	To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through future receipt or delivery of natural gas. Natural gas imbalances are recorded as gas imbalances and classified within Other current assets or Other current liabilities on our consolidated balance sheets at cost which approximates fair value.
	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. In accordance with the authoritative accounting guidance, 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 derivative financial instruments in our consolidated statements of operations as follows:
	•	Commodity-based derivatives: "Total revenue"
	•	Corporate interest rate derivatives: "Interest expense"
	Our formal hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to the approval and monitoring by the board of directors of our General Partner. We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction, and we do not use derivative financial instruments for speculative or trading purposes.
	The price assumptions we use to value our derivative financial instruments can affect net income (loss) for each period. We use published market price information where available, or quotations from over-the-counter, or OTC, market makers to find executable bids and offers. The valuations also reflect the potential impact of conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
	Fair value measurements
	We apply the authoritative accounting provisions for measuring fair value of our derivative instruments and disclosures associated with our outstanding indebtedness. We define fair value as an exit price representing the expected amount we would receive when selling an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.
	We use various assumptions and methods in estimating the fair values of our financial instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of our various credit facilities approximate fair value, because the interest rates on these facilities are variable.
	We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:
	•	Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities;
	•	Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets that are either directly or indirectly observable; and
	•	Level 3 – Inputs are unobservable and considered significant to fair value measurement.
	We utilize a mid-market pricing convention, or the "market approach," for valuation for assigning fair value to our derivative assets and liabilities. Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.
	Property, plant and equipment
	We capitalize expenditures related to property, plant and equipment that have a useful life greater than one year for assets purchased or constructed; existing assets that are replaced, improved, or the useful lives of which have been extended; and all land, regardless of cost. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.
	We record property, plant, and equipment at its original cost, which we depreciate on a straight-line basis over its estimated useful life. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We record depreciation using the group method of depreciation, which is commonly used by pipelines, utilities and similar assets.
	We classify long-lived assets to be disposed of through sales that meet specific criteria as held for sale. We cease depreciating those assets effective on the date the asset is classified as held for sale. We record those assets at the lower of their carrying value or the estimated fair value less the cost to sell. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.
	Impairment of long lived Assets
	We evaluate the recoverability of our property, plant and equipment 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 for recoverability by estimating the undiscounted future cash flows expected to be derived from the asset as a going concern. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of 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 not amortized but is reviewed for impairment at least annually or more frequently if an event or change in circumstance indicates that an impairment may have occurred. We first assess qualitative factors to evaluate whether it is more likely than not that an impairment has occurred and it is therefore necessary to perform the two-step goodwill impairment test. If the two-step goodwill impairment test indicates that the goodwill is impaired, an impairment loss is recorded.
	We record the estimated fair value of acquired customer contracts, 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 months and thirty 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.
	Deferred financing costs
	Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchase and debt extinguishment include any associated unamortized deferred financing costs.
	Asset retirement obligations ("AROs")
	AROs are legal obligations associated with the retirement of tangible long-lived assets that result from the asset's acquisition, construction, development and 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 a minority of our offshore right-of-way agreements due to requirements or landowner options to compel us to remove the pipe at final abandonment. Sufficient data exists with certain onshore pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement of estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management's experience, or the asset's estimated economic life. The useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to reasonably estimate potential settlement dates and methods.
	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 either probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.
	Noncontrolling interests
	Noncontrolling interests represent the noncontrolling interest holders' proportionate share of the equity of the respective systems. Noncontrolling interest is adjusted for the noncontrolling interest holders' proportionate share of the earnings or losses. Management reports noncontrolling interest in the Chatom system in the financial statements pursuant to paragraph ASC 810-10-65-1. The 7.8% noncontrolling interest is held by non-affiliated working interest owners.
	Revenue recognition and the estimation of revenues and cost of purchases
	We recognize revenue when all of the following criteria are met: i) persuasive evidence of an exchange arrangement exists, ii) delivery has occurred or services have been rendered, iii) the price is fixed or determinable, and iv) collectability is reasonably assured. We record revenue and cost of product sold on a gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that are purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating, transportation or storage, we record those fees separately in revenues. We have the following arrangements:
	Fee-based
	Under these arrangements, we generally are paid a fixed fee for gathering and transporting natural gas. Fee-based revenues are recorded when services have been provided, and collectability of the revenue is reasonably assured.
	Percent-of-proceeds, or POP
	Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas and NGLs at market prices. Where we provide processing services at the processing plants that we own, or obtain processing service for our own account under our own elective processing arrangements we typically retain and sell a percentage of the residue natural gas and resulting NGLs. We recognize percent-of-proceeds contract revenue when the natural gas, NGLs or condensate is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.
Fixed-margin
Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. We recognize revenue from fixed-margin contracts when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.
Firm transportation
Under arrangements to provide firm transportation service, we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not they utilize the capacity. In most cases, the shipper also pays a variable-use charge with respect to quantities actually transported by us. Firm transportation revenue is recorded when products are delivered, services have been provided, and collectability of the revenue is reasonably assured.
Interruptible transportation
Under arrangements to provide interruptible transportation service, we are only obligated to transport natural gas nominated by the shipper to the extent we have available capacity. For this service, the shipper pays no reservation charge but pays a variable-use charge for quantities actually shipped. Interruptible transportation revenue is recorded when products are delivered, services have been provided, and collectability of revenue is reasonably assured.
Interest in the Burns Point Plant
We account for our interest in the Burns Point Plant using the proportionate consolidation method. Under this method, we include in our consolidated statement of operations our value of plant revenues taken in-kind and plant expenses reimbursed to the operator.
Terminal revenue and services
Revenues for our terminals include storage tank lease fees, whereby a customer agrees to pay for a certain amount of tank storage over a certain period of time; and throughput fees, whereby a customer pays a fee based on volumes moving through the terminal. At our terminals, we also offer and provide packaging, blending, handling, filtering and certain other ancillary services. Revenue from firm storage contracts is recognized ratably, which is typically monthly, over the term of the lease. Occasionally, customers pay for tank lease fees in advance. Fees received in advance are deferred until the period earned. Revenue from throughput fees and ancillary fees are recognized as services are provided to the customer and collectability is reasonably assured.
Equity-based compensation
We award equity-based compensation to management, non-management employees and directors in the form of phantom units, which are deemed to be equity awards. Compensation expense on phantom units is measured by the fair value of the award at the date of grant as determined by management. Compensation expense is recognized in Equity compensation expense over the requisite service period of each award.
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 taxable C-Corporation consolidated return group which is a taxable entity. We account for income taxes of that subsidiary using an asset and liability approach for financial accounting and reporting of income taxes. If it is more than likely that a deferred tax asset will not be realized, a valuation allowance is recognized.
Certain tax expense results from the enactment of laws by the State of Texas that apply to entities organized as partnerships and is included in Income tax (expense) benefit in the consolidated statements of operations. The Texas margin tax is computed on our taxable margin apportioned to Texas annually.
Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) allocable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirement under our Partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner's tax attributes in us is not available.
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. We have no dilutive securities, therefore basic and diluted net income per unit are the same.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Acquisitions	Acquisitions
	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 $265.4 million in cash and 6.9 million of the Partnership's limited partner common units ("Costar Acquisition"). Costar Midstream 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 underway in the Bakken oil play.
	The Costar Acquisition was accounted for using the acquisition method of accounting and as a result, the aggregate purchase price was allocated to the assets acquired, liabilities assumed and a noncontrolling interest in a Costar subsidiary 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 is attributable to future prospective customer agreements from the acquisition. Costar has been included in the Partnership’s Gathering and Processing Segment from the acquisition date.
	The following table summarizes the fair value of consideration transferred to acquire Costar and the preliminary allocation of that amount to the assets acquired, liabilities assumed and the noncontrolling interest based upon their respective fair values as of the acquisition date. Such allocation will be finalized once the Partnership negotiates a final settlement of working capital amounts with the sellers with any resulting adjustment being recorded to goodwill.
	Fair value of consideration transferred (in thousands):
	Cash	$	265,383
	Limited partner common units	147,296
	Total fair value of consideration	$	412,679
	Fair Value of assets acquired, liabilities assumed and noncontrolling interest (in thousands):
	Working capital	$	8,152
	Property, plant and equipment:
	Processing plants	$	48,357
	Pipelines	128,799
	Land	1,244
	Buildings	682
	Equipment	9,827
	Construction in progress	16,146
	Total property, plant and equipment	205,055
	Investment in unconsolidated affiliate	11,884
	Intangible assets:
	Customer relationships	53,400
	Dedicated acreage	32,000
	Goodwill	102,407
	Noncontrolling interest	(219		)
		$	412,679
	The fair value of the limited partner common units of $147.3 million differs from the amount determined using the market price of such units on the date of the acquisition as a result of restrictions which require the sellers to hold the units for specified periods of time. The fair value of limited partner units issued in the transaction was determined using an option pricing model and the following key assumptions: i) the closing unit market price on the day of the acquisition, ii) the contractual holding periods, iii) historical unit price volatility for the Partnership and its peers, and iv) a risk-free rate of return.
	The fair value of property, plant and equipment was determined using both the cost and market approaches which required significant Level 3 inputs. Key assumptions included i) estimated replacement costs for individual assets or asset groups, ii) estimated remaining useful lives for the acquired assets, and iii) recent market transactions for similar assets. The fair value of intangible assets was determined using the income approach which also required significant Level 3 inputs. Key assumptions included i) estimated throughput volumes, ii) forward market prices for natural gas and NGLS as of the acquisition date, iii) estimated future operating and development cash flows, and iv) discount rates ranging from 11.0% to 16.0%.
	The intangible assets acquired relate to existing customer relationships which Costar had at the time of the acquisition, as well as agreements with two producers under which Costar agreed to construct and operate gathering and processing facilities in exchange for the producers’ agreements to dedicate certain acreage and related production to those facilities. Working capital includes $11.2 million of accounts receivable, all of which were subsequently collected.
	Costar contributed revenue of $19.9 million and operating income of $0.3 million for the period October 14, 2014 through December 31, 2014, attributable to the Partnership's Gathering and Processing segment. Additionally, the Partnership incurred $0.5 million of transaction costs related to the acquisition which are included in Selling, general and administrative expenses in the consolidated statement of operations for the year ended December 31, 2014. The following unaudited pro forma summary presents consolidated financial information for the Partnership as if the Costar acquisition had occurred on January 1, 2013 (in thousands):
		Year Ended December 31,
		2014			2013
	Revenue	$	435,133		$	448,748
	Net loss	(101,237		)	(30,672		)
	Limited partners' net loss per unit	(6.15		)	(3.82		)
	These pro forma amounts have been calculated after applying the Partnership’s accounting policies to Costar’s historical results and making adjustments to reflect additional interest expense that would have been incurred and additional depreciation and amortization expense that would have been recognized had the acquisition occurred as of January 1, 2013. The unaudited pro forma adjustments are based on available information and certain assumptions we believe are reasonable.
	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"). 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 acquisitions 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.
	The following table summarizes the preliminary allocation of the purchase price to the assets acquired based upon their respective fair values as of the acquisition date. Such allocation will be finalized once the Partnership negotiates a final settlement of property, plant and equipment expenditures with the sellers, with any resulting adjustment being recorded to goodwill (in thousands):
	Property, plant and equipment:
	Land	$	2
	Pipelines	58,737
	Equipment	753
	Total property, plant and equipment	59,492
	Intangible assets	21,350
	Goodwill	23,567
	Total cash consideration	$	104,409
	During the fourth quarter of 2014, errors were identified in the spreadsheets used to determine the preliminary purchase price allocation for the Lavaca Acquisition, which resulted in a $23.6 million overstatement of the previously reported amount allocated to intangible assets with an offsetting understatement of goodwill. These errors also resulted in a $0.5 million overstatement of amortization expense for the first nine months of 2014. The preliminary purchase price allocation as summarized above has been revised to correct these errors. Additionally, an adjustment was recorded during the fourth quarter of 2014 to correct the overstatement of amortization expense which occurred during the first nine months of the year.
	The fair value of property, plant and equipment was determined using the cost approach which required significant Level 3 inputs. Key assumptions included i) estimated replacement costs for individual assets or asset groups and ii) estimated remaining useful lives for the acquired assets. The fair value of intangible assets was determined using the income approach which also required significant Level 3 inputs. Key assumptions included i) estimated throughput volumes, ii) future operating and development cash flows, and iii) a discount rate of 10.5%.
	The intangible assets acquired relate to a 25-year gas gathering agreement under which PVA will dedicate certain acreage and related production to the acquired facilities.
	Lavaca contributed revenue of $16.8 million and net income of $7.6 million for the period from January 31, 2014 through December 31, 2014, attributable to the Partnership's Gathering and Processing segment. The Partnership incurred $0.1 million of transaction costs related to the acquisition, which are included in Selling, general and administrative expenses in the consolidated statement of operations for the year ended December 31, 2014.
	Pro forma financial results are not presented as it is impractical to obtain the necessary information. The seller did not operate the acquired assets as a standalone business and, therefore, historical financial information that is consistent with the operations under the current agreement is not available.
	Other Acquisitions
	Investment in Unconsolidated Affiliate
	On August 11, 2014, the Partnership acquired a 66.7% non-operated interest in MPOG, an offshore oil gathering system, for a net purchase price of $12.0 million, which was financed with borrowings from the Partnership's credit facility. Although the Partnership owns a majority interest in MPOG, the ownership structure requires unanimous approval of all owners on decisions impacting the operation of the assets and any changes in ownership structure. Therefore, the Partnership's voting rights are not proportional to its obligation to absorb losses or receive returns. The Partnership accounts for its 66.7% interest using the equity method. The Partnership recorded $0.3 million in earnings from unconsolidated affiliate, and received cash distributions of $2.0 million for the year ended December 31, 2014. The excess of the cash distributions received over the earnings recorded from MPOG is classified as a return of capital within the investing section of our consolidated statement of cash flows.
	Williams Pipeline Acquisition
	In the first quarter of 2014, the Partnership acquired natural gas pipeline facilities that are contiguous to and connect with our High Point System in offshore Louisiana from Transcontinental Gas Pipe Line Company, LLC ("Transco"), a subsidiary of Williams Partners, LP for $6.5 million  in cash (the "Williams Pipeline Acquisition"). The acquisition was subject to FERC approval of the seller's application to abandon by sale to us the pipeline facilities and to permit the facilities to serve a gathering function, exempt from FERC's jurisdiction. The FERC granted approval of the application during the first quarter of 2014, and the purchase and sale agreement closed on March 14, 2014. The purchase price was allocated to pipelines using the income approach which required certain Level 3 inputs.
	Blackwater Terminals Acquisition
	On December 17, 2013, the Partnership acquired Blackwater Midstream Holdings LLC ("Blackwater"), a Delaware limited liability company and other related subsidiaries from an affiliate of HPIP. Blackwater operated 1.3 million barrels of storage capacity across four marine terminal sites located in Westwego, Louisiana; Brunswick, Georgia; Harvey, Louisiana; and Salisbury, Maryland.
	The Partnership distributed consideration of $63.9 million, of which $27.7 million was accounted for as a cash distribution to the General Partner. The consideration also included 125,500 limited partner units which were accounted for as a non-cash distribution to the General Partner at a fair value of $3.1 million. The fair value of the units issued was determined using level one inputs based upon the Partnership's closing unit price on December 17, 2013.
	The remaining consideration was utilized to settle all of the Blackwater's outstanding debt at December 17, 2013.
	The acquisition of Blackwater represents a transaction between entities under common control and a change in reporting entity. Transfers of net assets or exchanges of shares between entities under common control are accounted for as if the transfer occurred at the beginning of the period or date of common control. Therefore, net assets received were recorded at their historical book value of $22.7 million as of the date common control was established, which is April 15, 2013.
	For the period from April 15, 2013 to December 31, 2013, our Terminals segment contributed $9.8 million of revenue and $0.8 million of net loss attributable to the Partnership's Terminals segment, which are included in the consolidated statement of operations.
High Point System
Effective April 15, 2013, our General Partner contributed the High Point System, consisting of 100% of the limited liability company interests in High Point Gas Transmission, LLC, and High Point Gas Gathering, LLC. The High Point System consists of approximately 700 miles of natural gas and liquids pipeline assets located in southeast Louisiana, in the Plaquemines and St. Bernard parishes, and the shallow water and deep shelf Gulf of Mexico, including the Mississippi Canyon, Viosca Knoll, West Delta, Main Pass, South Pass and Breton Sound zones. Natural gas is collected at more than 75 receipt points that connect hundreds of wells with an emphasis on oil and liquids-rich reservoirs.
The High Point System, along with $15.0 million in cash, was contributed to us by HPIP in exchange for 5,142,857 Series A Units. Of the cash consideration paid by HPIP, approximately $2.5 million was used to pay certain transaction expenses of HPIP, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's former credit facility. The contribution of the High Point System occurred concurrently with HPIP's acquisition of 90% of our General Partner and all of our subordinated units, which resulted in HPIP gaining control of our General Partner and a majority of our outstanding limited partner interests.
The fair value of the Series A Units on April 15, 2013, was $17.50 per unit, or a total of $90.0 million, and was issued by the Partnership in exchange for net cash of approximately $12.5 million and net assets of $61.9 million contributed to the Partnership by our General Partner. The contribution of net assets of the High Point System was accounted for as a transaction between entities under common control whereby the High Point System was recorded at historical book value. As such, the value of the Series A Units in excess of the net assets contributed by our General Partner amounted to $15.6 million and was allocated pro-rata to our General Partner and existing limited partners' interest based on their ownership interests.
The fair value measurement was based on significant inputs not observable in the market and thus represents a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimate was based on i) present value of estimated future contracted distributions, ii) an assumed discount rate of 18.0%, and iii) an assumed distribution growth rate of 1.0% in 2014 and thereafter.
The fair value of the additional Series A Units in an amount equal to the cash portion of the distribution was $19.67 per unit, or a total distribution of $13.2 million for the year ended December 31, 2014. Primarily using the market and income approach, the fair value estimate was based on i) present value of estimated future contracted distributions, ii) an option value of $3.32 per unit using a Black-Scholes model, iii) an assumed discount rate of 10.0%, and iv) an assumed distribution growth rate of 1.0% in 2014 and thereafter.
The contribution was treated as a transaction between entities under common control, under which the net assets received are recorded at their historical book value as of date of transfer. The following table presents the carrying value of the identified assets received and liabilities assumed at the acquisition date (in thousands):
Cash and cash equivalents	$	1,935
Accounts receivable	3,629
Unbilled revenue	1,446
Other current assets	2,049
Property, plant and equipment, net	82,615
Other assets	1,000
Accounts payable	(11		)
Accrued expenses and other current liabilities	(4,077		)
Current portion of long-term debt	(893		)
Asset retirement obligation liability	(25,763		)
Total identifiable net assets	$	61,930
Subsequent to the contribution, for the year ended December 31, 2013, the High Point System contributed $30.4 million of revenue and $7.2 million of net income attributable to the Partnership's Transmission segment, which are included in the consolidated statement of operations.
Chatom Gathering, Processing and Fractionation Plant
Effective July 1, 2012, we acquired an 87.4% undivided interest in the Chatom system from affiliates of Quantum Resources Management, LLC. The acquisition fair value consideration of $51.4 million includes a credit associated with the cash flow the Chatom system generated between January 1, 2012, and the effective date of July 1, 2012. The consideration paid by the Partnership consisted of cash, which was funded under borrowings under our revolving credit facility.
The Chatom system is located in Washington County, Alabama, approximately 15 miles from our Bazor Ridge processing plant in Wayne County, Mississippi, and consists of a 25 MMcf/d cryogenic processing plant, a 1,900 Bbl/d fractionation unit, a 160 long-ton per day sulfur recovery unit, and a 24 mile gas gathering system. We believe the fractionating services provide flexibility to the Partnership's product and service offerings.
The following table presents the fair value of consideration transferred to acquire the Chatom system and the amounts of identified assets acquired and liabilities assumed at the acquisition date, as well as the fair value of the 12.6% noncontrolling interest in the Chatom system at the acquisition date (in thousands):
Cash consideration:	$	51,377
Recognized amounts of identifiable assets acquired and liabilities assumed:
Unbilled revenue	$	4,535
Property, plant and equipment	58,279
Asset retirement cost	452
Accounts payable	(399		)
Accrued gas purchases	(3,631		)
Asset retirement obligations	(452		)
Noncontrolling interest	(7,407		)
Total identifiable net assets:	$	51,377
The fair value of the property, plant and equipment and noncontrolling interests were estimated by applying a combination of the market and income approaches. These fair value measurements are based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimates are based on i) an assumed cost of capital of 9.25%, ii) an assumed terminal value based on the present value of estimated EBITDA, iii) an inflationary cost increase of 2.5%, iv) forward market prices as of July 2012 for natural gas and crude oil, v) a Federal tax rate of 35% and a state tax rate of 6.5%, and vi) an increase in processed and fractionated volumes in 2013, declining thereafter. Working capital was estimated using net realizable value. Accrued revenue was deemed to be fully collectible at July 1, 2012.
During the fourth quarter of 2013 we offered to purchase the noncontrolling interest in Chatom from all holders of the noncontrolling interest. As of December 31, 2013, 38% of the noncontrolling interest was purchased by us (a 4.8% overall interest), increasing our total ownership to 92.2% and reducing the noncontrolling interest to 7.8%.
Subsequent to the initial 87.4% acquisition, our undivided interest in the Chatom system contributed $25.4 million of revenue and $1.8 million of net income attributable to the Partnership, which are included in the consolidated statement of operations for the year ended December 31, 2012.
Madison Divestiture
On March 31, 2014, the Partnership completed the sale of certain gathering and processing assets in Madison County, Texas. We received $6.1 million in cash proceeds related to the sale. The Partnership recognized a $3.0 million impairment charge related to these assets for the year ended December 31, 2013, which wrote down the assets to a carrying value of $6.1 million as of December 31, 2013.

Recent_Accounting_Pronouncemen

Recent Accounting Pronouncements (Notes)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	Recent Accounting Pronouncements
	In April 2014, the FASB issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This guidance amends the requirements for reporting discontinued operations and requires expanded disclosures for individually significant components of an entity that either have been disposed of or are classified as held for sale, but do not qualify for discontinued operations reporting. Only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity's operations and financial results will be reported as discontinued operations in the financial statements. ASU 2014-08 is effective for annual periods, and interim periods within those years, beginning on or after December 15, 2014 and is applied prospectively. Early adoption is permitted, but only for disposals or classifications as held for sale that have not been reported in financial statements previously issued or available for issuance. The update was early adopted by the Partnership as of April 1, 2014 and did not have a material impact on its consolidated financial statements.
	In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which amends the existing accounting standards for revenue recognition. The standard 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. The guidance in ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods therein. Early adoption is not permitted. The Partnership is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.
	In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements-Going Concern (Topic 205-40): Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. This guidance provides additional information to guide management's evaluation of whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern within one year after the date that the financial statements are issued. The update is effective for annual periods beginning on or after December 15, 2016. The Partnership has evaluated the impact of this standard on its financial statements and determined it will not have a material impact.

Discontinued_Operations_Notes

Discontinued Operations (Notes)	12 Months Ended
	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	Discontinued Operations
	During 2013, the board of directors of our General Partner approved a plan to sell certain non-strategic gathering and processing assets which meet specific criteria, qualifying them as held for sale. During the year ended December 31, 2013, certain gathering and processing assets were written down by $1.8 million to the estimated fair value less cost to sell. These fair value measurements are based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimates were based on i) present value of estimated EBITDA, ii) an assumed discount rate of 10%, and iii) a decline in throughput volumes of 2.5% in 2013 and thereafter.
	During the second quarter of 2014, the Partnership’s management resolved not to sell a portion of the assets that had previously been reclassified to discontinued operations and assets held for sale in the second quarter of 2013. In accordance with ASC 360, the Partnership reclassified the assets as held and used at the carrying value of the assets before they were classified as held for sale, adjusted for depreciation expense that would have been recorded. The Partnership has reclassified the amounts recorded in discontinued operations related to the assets for all prior periods presented, as well as reclassified the assets to held and used on the comparative December 31, 2013 balance sheet.
	The Partnership continues to classify the terminal in Salisbury, Maryland as held for sale as we are continuing negotiations for the sale of those assets, contingent upon the purchaser’s completion of funding requirements. The Partnership recognized an additional impairment on these assets of $0.7 million ($0.4 million, net of tax) for the year ended December 31, 2014, due to deteriorating market conditions. The impairment was the result of an analysis of the carrying value of the assets relative to their estimated fair value using a market based approach less costs to sell.
	The net book value of the assets and liabilities attributable to the terminal assets are presented separately on the consolidated balance sheet and comprise $0.1 million of Current assets held for sale, $1.2 million of Noncurrent assets held for sale, net, and less than $0.1 million of Current liabilities held for sale as of December 31, 2014.
	As a result of the planned divestiture of these non-strategic midstream assets, we have classified these disposal groups as discontinued operations within our consolidated statement of operations. Accordingly, we reclassified and excluded the disposal groups' results of operations from our results of continuing operations and reported the disposal groups' results of operations as Gain (loss) from operations of disposal groups, net of tax in our accompanying consolidated statement of operations for all periods presented. We did not, however, elect to present separately the operating, investing and financing cash flows related to the disposal groups in our accompanying consolidated statement of cash flows as this activity was immaterial for all periods presented. The following table presents the revenue, expense and (loss) gain from operations of disposal groups associated with the assets classified as held for sale for the years ended December 31, 2014, 2013, and 2012 (in thousands, except per unit amounts):
		Year Ended December 31,
		2014			2013			2012
	Revenue	$	474		$	2,084		$	2,318
	Expense	(658		)	(2,361		)	(2,336		)
	Impairment	(673		)	(2,400		)	—
	Loss on sale of assets	(87		)	(75		)	—
	Income tax benefit	333			339			—
	Gain (loss) from operations of disposal groups, net of tax	$	(611	)	$	(2,413	)	$	(18	)
	Limited partners' net income (loss) per unit from discontinued operations (basic and diluted)	$	(0.04	)	$	(0.27	)	$	—

Concentration_of_Credit_Risk_a

Concentration of Credit Risk and Trade Accounts Receivable	12 Months Ended
	Dec. 31, 2014
Receivables [Abstract]
Concentration Risk Disclosure [Text Block]	Concentration of Credit Risk and Trade Accounts Receivable
	Our primary market areas are located in the United States along the Gulf Coast and in the Southeast. We have a concentration of trade receivable balances due from companies engaged in the production, trading, distribution and marketing of natural gas and NGL products. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. Our customers' historical financial and operating information is analyzed prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. We maintain allowances for potentially uncollectible accounts receivable; however, for the years ended December 31, 2014, 2013 and 2012, no allowances on or significant write-offs of accounts receivable were recorded.
	The following table summarizes the percentage of revenue earned from those customers that exceed 10% of the Partnership's consolidated revenue in the consolidated statement of operations for the each of the years presented below:
		Year Ended December 31,
		2014		2013		2012
	Customer A	22	%	28	%	30	%
	Customer B	—	%	13	%	—	%
	Customer C	12	%	12	%	13	%
	Customer D	10	%	10	%	14	%
	Other	56	%	37	%	43	%
	Total	100	%	100	%	100	%

Other_Current_Assets

Other Current Assets	12 Months Ended
	Dec. 31, 2014
Other Current Assets [Abstract]
Other Current Assets	Other Current Assets
	Other current assets consists of the following (in thousands):
		December 31,
		2014		2013
	Prepaid insurance	$	4,162	$	3,166
	Restricted cash	6,475		—
	Other current assets	4,865		4,331
		$	15,502	$	7,497
	Restricted cash of $6.5 million is a cash-backed letter of credit related to Costar Midstream operations that the Partnership was contractually obligated to maintain after the Costar Acquisition. The Partnership was released of this obligation in January 2015.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives
	Commodity Derivatives
	To minimize the effect of commodity prices changes and maintain our cash flow and the economics of our development plans, we enter into commodity hedge contracts from time to time. The terms of the contracts depend on various factors, including management's view of future commodity prices, 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 in some commodity price upside. Management regularly monitors the commodity markets and financial commitments to determine if, when, and at what level commodity hedging is appropriate in accordance with policies that are established by the board of directors of our General Partner. Currently, the commodity derivatives are in the form of swaps and collars. As of December 31, 2014, the aggregate notional volume of our commodity derivatives was 0.5 million gallons.
	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. As of December 31, 2014, we have not posted collateral with our counterparties. The counterparties are not required to post collateral with us in connection with their derivative positions. Netting agreements are in place that permit us to offset our commodity derivative asset and liability positions with our counterparties .
	We did not designate any of our commodity derivatives as hedges for accounting purposes. As a result, our commodity derivatives are accounted for at fair value in our consolidated balance sheets with changes in fair value recognized currently in earnings.
	Interest Rate Swap
	We entered into an interest rate swap to manage the impact of the interest rate risk associated with our credit facility, effectively converting a portion of the cash flows related to our long-term variable rate debt into fixed rate cash flows. As of December 31, 2014, the notional amount of our interest rate swap was $100.0 million. The interest rate swap was entered into with a single counterparty and we were not required to post collateral. The interest rate swap will expire August 1, 2015.
	Weather Derivative
	In the second quarter of 2014 and 2013, 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 $10.0 million in the event that a hurricane or hurricanes of certain strength pass through the area as identified in the derivative agreement. The weather derivatives are accounted for using the intrinsic value method, under which the fair value of the contract was zero and any amounts received are recognized as gains during the period received. The weather derivatives were entered into with a single counterparty and we were not required to post collateral.
	We paid premiums of $1.0 million and $1.1 million in 2014 and 2013, respectively, which are recorded as current Risk management assets on the consolidated balance sheet and are amortized to Direct operating expenses on a straight-line basis over the term of the contract of 1 year. Unamortized amounts associated with weather derivatives were approximately $0.4 million and $0.5 million as of December 31, 2014 and 2013, respectively.
	As of December 31, 2014 and 2013, the value associated with our commodity derivatives, interest rate swap and weather derivative were recorded in our consolidated balance sheets, under the captions as follows (in thousands):
		Gross Risk Management Assets						Gross Risk Management Liabilities						Net Risk Management Assets (Liabilities)
	Balance Sheet Classification	December 31, 2014			December 31, 2013			December 31, 2014			December 31, 2013			December 31, 2014			December 31, 2013
	Current	$	688		$	473		$	—		$	—		$	688		$	473
	Noncurrent	—			—			—			—			—			—
	Total assets	$	688		$	473		$	—		$	—		$	688		$	473
	Current	$	—		$	27		$	(215	)	$	(450	)	$	(215	)	$	(423	)
	Noncurrent	—			—			—			(101		)	—			(101		)
	Total liabilities	$	—		$	27		$	(215	)	$	(551	)	$	(215	)	$	(524	)
	For the years ended December 31, 2014, 2013 and 2012, the realized and unrealized gains (losses) associated with our commodity, interest rate and weather derivative instruments were recorded in our consolidated statements of operations, under the captions as follows (in thousands):
		Realized			Unrealized
	2014
	Gain (loss) on commodity derivatives, net	$	735		$	356
	Interest expense	(433		)	239
	Direct operating expenses	(1,035		)	—
	Total	$	(733	)	$	595
	2013
	Gain (loss) on commodity derivatives, net	$	1,069		$	(1,041	)
	Interest expense	(207		)	(454		)
	Direct operating expenses	(662		)	—
	Total	$	200		$	(1,495	)
	2012
	Gain (loss) on commodity derivatives, net	$	2,408		$	992
	Total	$	2,408		$	992

Fair_Value_Measurement

Fair Value Measurement	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Measurement	Fair Value Measurement
	We believe the carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of the short-term maturity of these instruments.
	The recorded value of the amounts outstanding under the credit facility approximates its fair value, as interest rates are variable, based on prevailing market rates and the short-term nature of borrowings and repayments under the credit facility.
	The fair value of all derivatives instruments is estimated using a market valuation methodology based upon forward commodity price curves, volatility curves as well as other relevant economic measures, if necessary. Discount factors may be utilized to extrapolate a forecast of future cash flows associated with long dated transactions or illiquid market points. The inputs are obtained from independent pricing services, and we have made no adjustments to the obtained prices.
	We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivatives contracts held. We will recognize transfers between levels at the end of the reporting period for which the transfer has occurred. There were no such transfers for the years ended December 31, 2014 and 2013.
	Fair Value of Financial Instruments
	The following table sets forth by level within the fair value hierarchy, our commodity derivative instruments and interest rate swap, included as part of Risk management assets and Risk management liabilities within the consolidated balance sheet, that were measured at fair value on a recurring basis as of December 31, 2014 and 2013 (in thousands):
		Carrying			Estimated Fair Value of the Asset (Liability)
		Amount			Level 1		Level 2			Level 3		Total
	Commodity derivative instruments, net
	31-Dec-14	$	286		$	—	$	286		$	—	$	286
	31-Dec-13	(70		)	—		(70		)	—		(70		)
	Interest rate swap
	31-Dec-14	$	(215	)	$	—	$	(215	)	$	—	$	(215	)
	31-Dec-13	(454		)	—		(454		)	—		(454		)
	The unamortized portion of the premium paid to enter the weather derivative described in Note 7 "Derivatives," is included within Risk management assets on the consolidated balance sheet but is not included in the above table as it is recorded at amortized cost, not fair value.

Property_Plant_and_Equipment_N

Property, Plant and Equipment, Net	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Net	Property, Plant and Equipment, Net
	Property, plant and equipment, net, as of December 31, 2014 and 2013, were as follows (in thousands):
		Useful Life	December 31,			December 31,
		(in years)	2014			2013
	Land	N/A	$	5,282		$	6,015
	Construction in progress	N/A	77,551			6,443
	Base gas	N/A	1,108			1,108
	Buildings and improvements	4 to 40	6,905			5,109
	Processing and treating plants	8 to 40	80,141			97,106
	Pipelines	5 to 40	452,180			239,865
	Compressors	4 to 20	24,227			11,955
	Dock	20 to 40	8,072			7,942
	Tanks, truck rack and piping	20 to 40	30,079			22,432
	Equipment	8 to 20	8,952			6,294
	Computer software	5	3,520			3,531
	Total property, plant and equipment		698,017			407,800
	Accumulated depreciation		(115,835		)	(95,099		)
	Property, plant and equipment, net		$	582,182		$	312,701
	Of the gross property, plant and equipment balances at December 31, 2014 and 2013, $101.9 million and $100.5 million, respectively, were related to AlaTenn, Midla and High Point Gas Transmission, our FERC regulated interstate and intrastate assets.
	Capitalized interest was $0.8 million and $0.2 million for the years ended December 31, 2014 and 2013, respectively.
	Depreciation expense was $23.9 million and $25.9 million for the years ended December 31, 2014 and 2013, respectively.
	Asset Impairments
	2014 Impairments
	During the fourth quarter of 2014, management noted the declining commodity markets and related impact on producers and shippers to whom we provide gathering and processing services. The decline in the market price of crude oil has led to a corresponding decrease in oil and natural gas production and is impacting the volume of natural and NGLs we gather and process on certain assets. As a result, an asset impairment charge of $99.9 million was recorded in the three months ended December 31, 2014. These fair value measurements are based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimates are based on i) present value of estimated EBITDA, ii) an assumed discount rate of 9.5%, and iii) the expected remaining useful life of the asset or asset group.
	The Partnership continues to classify the terminal in Salisbury, Maryland as held for sale as we are continuing negotiations for the sale of those assets, contingent upon the purchaser’s completion of funding requirements. The Partnership recognized an additional impairment on these assets of $0.7 million ($0.4 million, net of tax) for the year ended December 31, 2014, due to deteriorating market conditions. The impairment was the result of an analysis of the carrying value of the assets relative to their estimated fair value using a market based approach less costs to sell.
	2013 Impairments
	During 2013, management determined to change its commercial approach towards certain non-strategic gathering and processing assets. As a result, an asset impairment charge of $15.2 million was recorded in the three months ended June 30, 2013. These fair value measurements are based on significant inputs not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Primarily using the income approach, the fair value estimates are based on i) present value of estimated EBITDA, ii) an assumed discount rate of 10%, and iii) a decline in throughput volumes of 2.5% in 2013 and thereafter.
	During 2013, the board of directors of our General Partner approved a plan to sell certain non-strategic gathering and processing assets which meet specific criteria, qualifying them as held for sale. As a result, certain gathering and processing assets were written down by $1.8 million to the estimated fair value less cost to sell. As part of the Blackwater Acquisition, we acquired long-lived terminal assets classified as held for sale. As of December 31, 2013, certain long-lived terminal assets were written down by $0.6 million to the estimated fair value less cost to sell. See Note 4 "Discontinued Operations."
	During the first quarter of 2014, the board of directors of our General Partner gave approval to the management team to pursue the sale of certain gathering and processing assets for an amount less than the carrying value of the assets. As a result, these gathering and processing assets were written down by $3.0 million in the fourth quarter of 2013.
	Insurance proceeds
	Involuntary conversions result from the loss of an asset because of some unforeseen event (e.g., destruction due to hurricanes). Some of these events are insurable, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. During the year ended December 31, 2013, we collected $1.1 million of nonrefundable cash proceeds from our insurance carrier. During the first quarter of 2013, $0.5 million of nonrefundable cash proceeds were recognized as an offset to property, plant and equipment write-downs of $0.1 million and presented as $0.4 million under the caption Gain (loss) on involuntary conversion of property, plant and equipment. During the second quarter of 2013, $0.6 million of nonrefundable cash proceeds were associated with business interruption insurance and recorded to Revenue in the consolidated statement of operations.

Goodwill_and_Intangible_assets

Goodwill and Intangible assets (Notes)	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets Disclosure [Text Block]	Goodwill and Intangible Assets, Net
	The carrying value of goodwill as of December 31, 2014 and 2013, was $142.2 million and $16.4 million, respectively. Goodwill as of December 31, 2014 consisted of $125.9 million and $16.3 million related to our Gathering and Processing and Terminal Segments, respectively. Goodwill as of December 31, 2013 related entirely to the Terminals Segment.
	The goodwill associated with our Gathering and Processing segment relates to the Costar and Lavaca Acquisitions and primarily represent strategic developmental locations to grow the business within the segment. The goodwill associated with our Terminal Segment was contributed to the Partnership as part of the Blackwater Acquisition. Goodwill was recorded as a result of the excess of the investment by an affiliate of HPIP in Blackwater over the fair market value of the identifiable net assets and customer contracts acquired.
	Intangible assets, net, consists of customer contracts, relationships and dedicated acreage agreements identified as part of the Costar Acquisition, Lavaca Acquisition and Blackwater Acquisition. These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging from 5 months to thirty years. Intangible assets, net, consist of the following (in thousands):
		December 31,
		2014			2013
	Gross carrying amount:
	Customer contracts	$	12,101		$	12,101
	Customer relationships	53,400			—
	Dedicated acreage	53,350			—
		$	118,851		$	12,101
	Accumulated amortization:
	Customer contracts	$	(11,110	)	$	(8,419	)
	Customer relationships	(553		)	—
	Dedicated acreage	(882		)	—
		$	(12,545	)	$	(8,419	)
	Net carrying amount:
	Customer contracts	$	991		$	3,682
	Customer relationships	52,847			—
	Dedicated acreage	52,468			—
		$	106,306		$	3,682
	For the years ended December 31, 2014 and 2013, amortization expense on our intangible assets totaled $4.1 million and $3.7 million, respectively. Estimated amortization expense for each of the next five fiscal years (2015 – 2019) is approximately $5.3 million, $4.3 million, $4.3 million, $4.3 million and $4.3 million, respectively.

Accrued_Expenses_and_Other_Cur

Accrued Expenses and Other Current Liabilities	12 Months Ended
	Dec. 31, 2014
Payables and Accruals [Abstract]
Accounts Expenses and Other Current Liabilities	Accrued Expenses and Other Current Liabilities
	Accrued expenses and other current liabilities were as follows (in thousands):
		December 31,
		2014		2013
	Accrued capital expenditures	$	17,134	$	2,562
	Accrued expenses	7,036		5,412
	Gas imbalances payable	1,069		4,305
	Other	549		2,779
		$	25,788	$	15,058

Asset_Retirement_Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	Asset Retirement Obligations
	The following table is a reconciliation of the asset retirement obligations (in thousands):
		Year Ended December 31,
		2014			2013
	Beginning asset retirement obligation	$	34,636		$	8,319
	Liabilities assumed	248			25,763
	Expenditures	(1,030		)	—
	Accretion expense	791			554
	Ending asset retirement obligation	$	34,645		$	34,636
	We are required to establish security against any potential secondary obligations relating to the abandonment of the certain transmission assets that may be imposed on the previous owner by applicable regulatory authorities. As such, we have a restricted cash account that is established, held and maintained by a third party that amounted to $5.0 million and $3.0 million as of December 31, 2014 and 2013, respectively, and is presented in Other assets, net in our consolidated balance sheets.

Debt_Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt Obligations	Our outstanding borrowings under the credit facility were (in thousands):
		December 31,
		2014		2013
	Revolving credit facility	$	372,950	$	130,735
	Other debt	2,908		2,048
	Total debt	375,858		132,783
	Less: current portion	2,908		2,048
	Long-term debt	$	372,950	$	130,735
	On September 5, 2014, the Partnership entered into an amended and restated credit agreement (the "Credit Agreement"), which provides for a maximum borrowing equal to $500.0 million, with the ability to further increase the borrowing capacity subject to lender approval. We can elect to have loans under our credit facility 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 (a) the Federal Funds Rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its "prime rate," or (c) the Eurodollar Rate plus 1.00% plus a margin ranging from 1.00% to 2.25% depending on the total leverage ratio then in effect. We also pay a maximum commitment fee of 0.50% per annum on the undrawn portion of the revolving loan.
	Our obligations under the credit facility are secured by a first mortgage in favor of the lenders in our real property. Advances made under the Credit 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 new credit facility include covenants that restrict our ability to make cash distributions and acquisitions in some circumstances. The remaining principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date, September 5, 2019.
	The Credit Agreement contains certain financial covenants, including the requirement that our indebtedness not exceed 4.75 times adjusted consolidated EBITDA (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 test (not less than 2.50). 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, 2014, 2013 and 2012, the weighted average interest rate on borrowings under our credit facilities was approximately 3.80%, 4.53%, and 4.09%, respectively.
	As of December 31, 2014 our consolidated total leverage was 4.44 and our interest coverage ratio was 13.44, which was in compliance with the consolidated total leverage ratio and interest coverage ratio tests in accordance with the financial covenants required in our Credit Agreement. At December 31, 2014 and 2013, letters of credit outstanding under the credit facility were $1.6 million and $4.8 million, respectively. As of December 31, 2014, we had approximately $373.0 million of outstanding borrowings under our $500.0 million credit facility.
	Other debt
	Other debt represents insurance premium financing in the original amount of $3.3 million bearing interest at 3.95% per annum, which is repayable in equal monthly installments of approximately $0.4 million through the third quarter of 2015.
	In connection with our credit facility, we have incurred $10.4 million in cumulative debt issuance costs through December 31, 2014, which are being amortized on a straight-line basis over the term of the credit facility. In connection with the amendment and restatement of our Credit Agreement, discussed above, the Partnership recognized $0.7 million in extinguishment costs during the quarter ended September 30, 2014, which is included in Other expense in our consolidated statement of operations.

Partners_Capital

Partners' Capital	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Partners' Capital	Partners' Capital
	Our capital accounts are comprised of approximately 1.3% general partner interest and 98.7% limited partner interests as of December 31, 2014. 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 rights ("IDRs") that are non-voting limited partner interests held by our General Partner.
	Series B Units
	Effective January 31, 2014, the Partnership created and issued to its General Partner 1,168,225 Series B Units in exchange for cash. The Series B Units participate in distributions of the Partnership 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 are entitled to vote along with common unitholders and such units will automatically convert to common units two years after the issuance date. Proceeds from the issuance of the Series B Units were used to partially fund the Lavaca Acquisition.
	During 2014, the Partnership elected to pay the Series B distributions using paid-in-kind Series B Units. The number of paid-in-kind Series B Units is determined by the quotient of: i) the number of Series B Units outstanding at the record date multiplied by the distribution amount declared to common unit holders ("Series B Unit Distribution Amount"), and ii) the Series B Unit Distribution Amount divided by the original issue price of the Series B Units. The Partnership records the paid-in-kind Series B Units at fair value at the time of issuance. The fair value measurement uses our unit price as a significant input in the determination of the fair value and thus represents a Level 2 measurement as defined by ASC 820. For the year ended December 31, 2014, the Partnership issued 86,461 of paid-in-kind Series B Units with a fair value of $2.2 million.
	Series A 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 i) acquired 90% of our General Partner and all of our subordinated units from AIM Midstream Holdings and ii) contributed certain midstream assets and $15.0 million in cash to us in exchange for 5,142,857 Series A Units issued by the Partnership. Of the cash consideration paid by HPIP, approximately $2.5 million was used to pay certain transaction expenses of HPIP, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's former credit facility. As a result of these transactions, which were also consummated on April 15, 2013, HPIP acquired both control of our General Partner and a majority of our outstanding limited partnership interests. On April 15, 2013, our General Partner entered into the Third Amended & Restated Agreement of Limited Partnership (the "Amended Partnership Agreement") of the Partnership providing for the creation and designation of the rights, preferences, terms and conditions of the Series A Units.
	The Series A Units receive distributions prior to distributions to Partnership common unitholders. Through October 1, 2014, the distributions to the Series A Unitholders were equal to $0.25 in cash per unit and additional Series A Units in an amount equal to the cash portion of the distribution. Subsequent to that date, the distribution to each Series A Unit is the greater of the distribution to be made on a per unit basis to common unitholders or approximately $0.4125 per unit. The Series A Units may be converted into common units on a one-to-one basis, subject to customary anti-dilutive adjustments, at the option of the unitholders on or any time after January 1, 2014.
	Upon any liquidation and winding up of the Partnership or the sale of substantially all of the assets of the Partnership, the holders of Series A Units generally will be entitled to receive, in preference to the holders of any of the Partnership's other securities, an amount equal to the sum of $17.50 multiplied by the number of Series A Units owned by such holders, plus all accrued but unpaid distributions on such Series A Units.
	Prior to the consummation of any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of common units are to receive securities, cash or other assets (a "Partnership Event"), we are obligated to make an irrevocable written offer, subject to consummation of the Partnership Event, to each holder of Series A Units to redeem all (but not less than all) of such holder's Series A Units for a price per Series A Unit payable in cash equal to the greater of:
	•	the sum of $17.50 and all accrued and accumulated but unpaid distributions for each Series A Unit; or
	•	an amount equal to the product of:
	i) the number of common units into which each Series A Unit is convertible; and
	ii) the sum of:
	(A) the cash consideration per common unit to be paid to the holders of common units pursuant to the Partnership Event, plus
	(B) the fair market value per common unit of the securities or other assets to be distributed to the holders of the common units pursuant to the Partnership Event.
	Upon receipt of such a redemption offer from us, each holder of Series A Units may elect to receive such cash amount or a preferred security issued by the person surviving or resulting from such Partnership Event and containing provisions substantially equivalent to the provisions set forth in the Amended Partnership Agreement with respect to the Series A Units without material abridgement.
	Except as provided in the Amended Partnership Agreement, the Series A Units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, with each Series A Unit entitled to one vote for each common unit into which such Series A Unit is convertible.
	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 Units have been classified as mezzanine equity in the consolidated balance sheets.
	The Partnership executed an amendment (the "Amendment") to the Partnership agreement related to its outstanding Series A convertible preferred units ("Series A Units") which became effective July 24, 2014. As a result of the Amendment, distributions on Series A Units will be made with paid-in-kind Series A Units, cash or a combination thereof, at the discretion of the Board of Directors, which began with the distribution for the three months ended June 30, 2014 and will continue through the distribution for the quarter ended March 31, 2015. Prior to the Amendment, the Partnership was required to pay distributions on the Series A Units with a combination of paid-in-kind units and cash. At December 31, 2014, we have accrued $3.2 million for the paid-in-kind Series A Units.
	Equity Restructuring
	Effective August 9, 2013, we executed an equity restructuring agreement ("Equity Restructuring") with our General Partner and HPIP. As part of the Equity Restructuring, the Partnership's 4,526,066 subordinated units and previous incentive distribution rights (the "former IDRs," all of which were owned by our General Partner, which is controlled by HPIP) were combined into and restructured as a new class of incentive distribution rights (the "new IDRs"). Upon the issuance of the new IDRs, the subordinated units and former IDRs were canceled. The new IDRs were allocated 85.02% to HPIP and 14.98% to our General Partner. The new IDRs entitle the holders of our incentive distribution rights to receive 48% of any quarterly cash distributions from available cash after the Partnership's common unitholders have received the full minimum quarterly distribution ($0.4125 per unit) for each quarter plus any arrearages from prior quarters. On February 5, 2014, further amendments were made as a result of a settlement such that:
	•	HPIP and AIM Midstream Holdings amended the LLC Amendment to, among other things, amend the Sharing Percentages (as defined therein) such that HPIP's sharing percentage thereafter is 95% and AIM Midstream Holdings's Sharing Percentage is 5%;
	•	HPIP transferred all of the 85.02% of our outstanding new IDRs held by HPIP to our General Partner such that our General Partner owns 100% of the outstanding new IDRs; and
	•	we issued to AIM Midstream Holdings a warrant to purchase up to 300,000 common units of the Partnership at an exercise price of $0.01 per common unit (the "Warrant"), which Warrant, among other terms, i) is exercisable at any time on or after February 8, 2014 until the tenth anniversary of February 5, 2014, ii) contains cashless exercise provisions and iii) contains customary anti-dilution and other protections. The Warrant was exercised on February 21, 2014.
	Equity Offerings
	On October 14, 2014, the Partnership acquired Costar Midstream from Energy Spectrum Partners VI LP and Costar Midstream Energy, LLC which was funded, in part, with 6.9 million of limited partner common units issued directly to Energy Spectrum and Costar Midstream Energy LLC, which are subject to customary lock-up provisions.
	On July 14, 2014, the Partnership entered into a common unit purchase agreement with certain institutional investors, which was subsequently amended on August 15, 2014, to provide for the sale of 4,622,352 common units representing limited partner interests in the Partnership in a private placement at a price of $25.8075 per common unit (reflecting an adjustment for the Partnership's second quarter distribution of $0.4625 per unit), for cash consideration of $119.3 million.
	On January 29, 2014, the Partnership and certain of its affiliates entered into an underwriting agreement (the "Underwriting Agreement") with Barclays Capital Inc. and UBS Securities LLC (the "Underwriters"), providing for the issuance and sale by the Partnership, and the purchase by the Underwriter, of 3,400,000 common units representing limited partner interests in the Partnership at a price to the public of $26.75 per common unit. The Partnership used the net proceeds of $86.9 million to fund a portion of the Lavaca Acquisition.
	On December 11, 2013, the Partnership and certain of its affiliates entered into an underwriting agreement (the "Underwriting Agreement") with Barclays Capital Inc. (the "Underwriter"), providing for the issuance and sale by the Partnership, and the purchase by the Underwriter, of 2,568,712 common units representing limited partner interests in the Partnership at a price to the public of $22.47 per common unit. The Partnership used the net proceeds of $54.9 million to fund a portion of the purchase price for the Blackwater Acquisition.
	General Partner Units
	In connection with the equity offerings discussed above, we received proceeds of $5.7 million from our General Partner as consideration for 206,810 additional notional general partner units.
	Outstanding Units
	The numbers of units outstanding were as follows (in thousands):
		December 31,
		2014		2013			2012
	Series A convertible preferred units	5,745		5,279			—
	Series B convertible units	1,255		—			—
	Limited Partner common units	22,670		7,414			4,639
	Limited Partner subordinated units	—		—			4,526
	General Partner units	392		185			185
	Distributions
	We made cash distributions as follows (in thousands):
		Year Ended December 31,
		2014			2013			2012
	Series A convertible preferred units	2,658			2,375			—
	Limited Partner common units	22,656			8,207			7,919
	Limited Partner subordinated units	—			5,073			7,830
	General Partner units	333			284			321
	General Partners' incentive distribution rights	2,362			181			—
		$	28,009		$	16,120		$	16,070
	At December 31, 2014, we have accrued $3.2 million for the paid-in-kind Series A Units. The distributions will be made in the first quarter of 2015. During the year ended December 31, 2014, we issued 555 thousand Series A PIK Units and 86 thousand Series B PIK Units.

Earnings_per_Unit

Earnings per Unit	12 Months Ended
	Dec. 31, 2014
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income Loss Per Limited and General Partner Unit [Text Block]	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 Series A preferred convertible units, declared distributions on the Series B Units, limited partner and to the General Partner units, including IDRs. Unvested unit-based payment awards that contain non-forfeitable rights to distributions (whether paid or unpaid) are classified as participating securities and are included in our computation of basic and diluted net income per limited partner unit. Basic and diluted net income (loss) per limited partner unit is calculated by dividing limited partners' interest in net income (loss) by the weighted average number of outstanding limited partner units during the period. We determined basic and diluted net income (loss) per limited partner unit as follows, (in thousands, except per unit amounts):
		Year Ended December 31,
		2014			2013			2012
	Net income (loss) from continuing operations	$	(97,195	)	$	(30,993	)	$	(6,234	)
	Net income (loss) attributable to noncontrolling interests	214			633			256
	Net income (loss) from continuing operations attributable to the Partnership	(97,409		)	(31,626		)	(6,490		)
	Less:
	Distributions on Series A preferred units	14,492			24,117			—
	Declared distributions on Series B Units	2,220			—			—
	General partner's distributions	2,694			464			322
	General partner's share in undistributed loss	(1,820		)	(1,708		)	(458		)
	Blackwater net loss from continuing operations	—			(716		)	—
	Net income (loss) from continuing operations available to limited Partners	(114,995		)	(53,783		)	(6,354		)
	Net income (loss) from discontinued operations available to Limited Partners	(603		)	(2,051		)	(18		)
	Net income (loss) available to Limited Partners	$	(115,598	)	$	(55,834	)	$	(6,372	)
	Weighted average number of units used in computation of Limited Partners' net income (loss) per unit (basic and diluted)	13,472			7,525			9,113
	Limited Partners' net income (loss) from continuing operations per unit (basic and diluted)	$	(8.54	)	$	(7.15	)	$	(0.70	)
	Limited Partners' net income (loss) from discontinued operations per unit (basic and diluted)	(0.04		)	(0.27		)	—
	Limited Partners' net income (loss) per unit (basic and diluted)	$	(8.58	)	$	(7.42	)	$	(0.70	)

LongTerm_Incentive_Plan

Long-Term Incentive Plan	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Long-Term Incentive Plan	Long-Term Incentive Plan
	Our General Partner manages our operations and activities and employs the personnel who provide support to our operations. On November 2, 2009, the board of directors of our General Partner adopted a long-term incentive plan for its employees, consultants and directors who perform services for it or its affiliates. On May 25, 2010, the board of directors of our General Partner adopted an amended and restated long-term incentive plan. On July 11, 2012, the board of directors of our General Partner adopted a second amended and restated long-term incentive plan ("LTIP") that effectively increased available awards by 871,750 units. At December 31, 2014, 2013 and 2012, there were 688,976, 855,089 and 920,193 units, respectively, available for future grant under the LTIP.
	Ownership in the awards is subject to forfeiture until the vesting date. The LTIP is administered by the board of directors of our General Partner. The board of directors of our General Partner, at its discretion, may elect to settle such vested phantom units with a number of units equivalent to the fair market value at the date of vesting in lieu of cash. Although our General Partner has the option to settle in cash upon the vesting of phantom units, our General Partner has not historically settled these awards in cash. Although other types of awards are contemplated under the LTIP, the only currently outstanding awards are phantom units without distribution equivalent rights ("DERs").
	Generally, grants issued under the LTIP vest in increments of 25% on each grant anniversary date and do not contain any vesting requirements other than continued employment.
	The following table summarizes our unit-based awards for each of the periods indicated, in units:
		Year Ended December 31, 2014
		Shares		Weighted-Average Exercise Price
	Outstanding at beginning of period	75,529		17.62
	Granted	188,946		20.8
	Forfeited	(12,009	)	18.28
	Vested	(51,334	)	20.89
	Outstanding at end of period	201,132		19.73
	The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our units at the grant date. Compensation costs related to these awards for the years ended December 31, 2014, 2013, and 2012 was $1.5 million, $2.1 million and $1.8 million, respectively, and are classified as Equity compensation expense in the consolidated statement of operations and the equity based compensation in partners' capital on the consolidated balance sheet.
	The total fair value of vesting units at the time of vesting was $1.4 million, $2.2 million, and $1.9 million for the years ended December 31, 2014, 2013, and 2012, respectively.
	The total compensation cost related to unvested awards not yet recognized at December 31, 2014, 2013, and 2012 was $3.1 million, $0.9 million, and $1.4 million, respectively, and the weighted average period over which this cost is expected to be recognized as of December 31, 2014, is approximately 3 years.

PostEmployment_Benefits

Post-Employment Benefits	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Post-Employment Benefits	Postretirement Benefits
	We sponsor a contributory postretirement plan that provides medical, dental and life insurance benefits for qualifying U.S. retired employees (referred to as the "OPEB Plan").
	The tables below detail the changes in the benefit obligation, the fair value of the plan assets and the funded status of the OPEB Plan using the accrual method (in thousands):
			Year Ended December 31,
			2014				2013
	Change in benefit obligation
	Benefit obligation, beginning of period		$	532			$	472
	Service cost		2				5
	Interest cost		24				15
	Actuarial (gain) loss		122				(29		)
	Plan amendments		—				126
	Benefits paid		(25		)		(57		)
	Benefit obligation, end of period		$	655			$	532
	Change in plan assets
	Fair value of plan assets, beginning of period		$	1,528			$	1,552
	Actual return on plan assets		104				(53		)
	Employer's contributions		90				90
	Benefits paid		(38		)		(61		)
	Fair value of plan assets, end of period		$	1,684			$	1,528
	Funded status
	Funded status		$	1,029			$	996
	The funded status of the OPEB plan is included in Other assets in the consolidated balance sheets.
	The amounts included in accumulated other comprehensive income (loss) at December 31, 2014, 2013 and 2012 that have not been recognized as components of net periodic benefit expenses are $0.0 million, $(0.1) million, and $(0.1) million, respectively, which relate to net (gains) losses.
	Components of Net Periodic Benefit Cost and Other amounts Recognized in Other Comprehensive Income (in thousands):
			Year Ended December 31,
			2014				2013				2012
	Net Periodic Benefit Cost
	Service cost		$	2			$	5			$	4
	Interest cost		24				15				18
	Expected return on plan assets		(70		)		(70		)		(67		)
	Amortization of prior service cost		4				—				—
	Amortization of net (gain) loss		(5		)		(23		)		(43		)
	Net periodic benefit cost		$	(45	)		$	(73	)		$	(88	)
	Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
	Net (gain) loss		$	102			$	247			$	64
	Total recognized in other comprehensive income		102				247				64
	Total recognized in net periodic benefit cost and other comprehensive income		$	57			$	174			$	(24	)
	The estimated net gain that will be amortized from accumulated other comprehensive income (loss) into net periodic benefit cost over the next fiscal year is less than $0.1 million.
	Economic assumptions
	The assumptions made in measurement of the projected benefit obligations or assets of the OPEB Plan were as follows:
			Year Ended December 31,
			2014			2013
	Discount rate		3.73	%		4.57	%
	Expected return on plan assets		2.5	%		4.5	%
	Health care trend rate		3	%		4.5	%
	A one percent change in the assumed health care trend rate would result in a change of less than $0.1 million in the postretirement benefit obligations.
	The above table reflects the expected long-term rates of return on assets of the OPEB Plan on a weighted-average basis. The overall expected rates of return are based on the asset allocation targets with estimates for returns on equity and debt securities based on long-term expectations. We believe this rate approximates the return we will achieve over the long-term on the assets of our plans. Historically, we have used a discount rate that corresponds to one or more high quality corporate bond indices as an estimate of our expected long-term rate of return on plan assets for our OPEB Plan assets. For 2014, 2013 and 2012 we selected the discount rate using the Citigroup Pension Discount Curve, or CPDC. The CPDC spot rates represent the equivalent yield on high-quality, zero-coupon bonds for specific maturities. These rates are used to develop a single, equivalent discount rate based on the OPEB Plan's expected future cash flows.
	Expected future benefit payments
	The following table presents the benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five years thereafter by the OPEB Plan (in thousands):
	For the year ending
	2015	$	33
	2016	32
	2017	32
	2018	32
	2019	31
	Five years thereafter	194
	The expected future benefit payments are based upon the same assumptions used to measure the projected benefit obligations of the OPEB Plan, including benefits associated with future employee service.
	Future contributions to the Plans
	We expect to make contributions of $0.1 million to the OPEB Plan for the year ending December 31, 2015.
	Plan assets
	The weighted average asset allocation of our OPEB Plan at the measurement date by asset category, which are all classified as Level 1 investments, are as follows:
			December 31,
			2014			2013			2012
	Fixed income (a)		70	%		70.1	%		72.2	%
Other (b)		30	%		29.9	%		27.8	%
Total		100	%		100	%		100	%
(a)	United States government securities, municipal corporate bonds and notes and asset backed securities
(b)	Cash and securities with maturities of one year or less

Income_Tax_Notes

Income Tax (Notes)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	Income Taxes
	The Partnership is not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. The State of Texas imposes a margin tax that is assessed at 0.95%, 0.975% and 1% of taxable margin apportioned to Texas for each of the three years in the period ended December 31, 2014, respectively. Effective December 17, 2013, we acquired Blackwater Midstream Holdings, LLC, an entity that owns a taxable C Corporation consolidated return group.
	For its taxable operations, the Partnership follows the provisions of ASC 740 "Accounting For Income Taxes," which provides for recognition of deferred tax assets and liabilities for deductible temporary timing differences, net operating loss, statutory depletion and tax credit carryforwards, net of a valuation allowance for any deferred tax asset which more likely than not, will not be realized in the Partnership's tax return. An analysis of the Partnership's deferred taxes is as follows (in thousands):
		31-Dec-14			31-Dec-13
	Deferred tax assets:
	Net operating loss carryforwards	$	4,173		$	5,455
	Other	213			182
	Total deferred tax assets	4,386			5,637
	Deferred tax liabilities:
	Property, plant and equipment	9,112			9,022
	Intangible assets	387			1,364
	Total deferred tax liabilities	9,499			10,386
	Deferred income tax liability, net	$	(5,113	)	$	(4,749	)
	These amounts reflect the classification and presentation that is reported for each tax jurisdiction in which we operate.
	Net deferred income tax assets and liabilities consist of (in thousands):
		31-Dec-14			31-Dec-13
	Current deferred tax asset	$	3,086		$	—
	Deferred tax liability, net	(8,199		)	(4,749		)
		$	(5,113	)	$	(4,749	)
	As of December 31, 2014, we had approximately $10.7 million of operating loss carryforwards which begin to expire in 2028. Some of our net operating losses may be limited by section 382 of the Internal Revenue Code due to the change in control that occurred in December 2013 and another change in control that occurred in October 2012.
	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. We will account for interest and penalties relating to uncertain tax provisions in the current period statement of operations, as necessary. Tax years 2009 through 2013 remain subject to examination by various federal and state tax jurisdictions, as applicable. During the third quarter of 2014, the Internal Revenue Service commenced an audit of the Partnership's 2012 U.S. federal partnership tax return which remains open to examination.
	We must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also on the past administrative practices and precedents of the taxing authority. As of December 31, 2014, we have not recognized tax benefits from uncertain tax positions.
	The provision for income taxes is attributable to the activities of the taxable C-Corporation consolidated return group and taxable margin apportioned to Texas. The details of the provision for taxes on income for the year ended December 31, 2014, are as follows (in thousands):
		Year Ended December 31,
		2014			2013
	Net loss before income tax benefit (expense)	$	(96,638	)	$	(31,488	)
	US Federal statutory tax rate	34		%	34		%
	Federal income tax benefit at statutory rate	32,857			10,706
	Reconciling items:
	Partnership loss not subject to income tax	(33,216		)	(10,296		)
	Income not subject to corporate-level tax	—			222
	State and local tax benefit (expense)	(159		)	71
	Adjustments related to prior years	(37		)	(175		)
	Other	(2		)	(33		)
	Income tax benefit (expense)	$	(557	)	$	495
	The income tax provision related to continuing operations consist of the following (in thousands):
		Year Ended December 31,
		2014			2013
	Current income tax benefit (expense)	$	(10	)	$	—
	Deferred income tax benefit (expense)	(547		)	495
	Effective income tax rate	0.6		%	1.6		%
	Our effective tax rate differs from the statutory rates, primarily due to being structured as a master limited partnership, which is a pass-through entity for federal income tax purposes, while being treated as a taxable entity in certain states.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies
	Legal proceedings
	Equity restructuring
	On September 5, 2013, HPIP, our General Partner and the Partnership were named as defendants in an action filed by AIM challenging the Equity Restructuring. AIM Midstream Holdings, LLC v. High Point Infrastructure Partners, LLC, American Midstream GP, LLC and American Midstream Partners, LP (Civil Action No. 8803-VCP) was filed in the Court of Chancery of the State of Delaware. Among claims against the other parties to the litigation, the action asserts a claim of tortious interference with contract against the Partnership and sought either rescission of the Partnership's equity restructuring agreement executed on August 9, 2013 or, in the alternative, monetary damages.
	On February 5, 2014, we, HPIP and our General Partner entered into a settlement (the "Settlement") with AIM Midstream Holdings regarding the action filed in Delaware Chancery Court by AIM Midstream Holdings. Under the Settlement, among other things:
	•	HPIP and AIM Midstream Holdings amended the LLC Amendment to, among other things, amend the Sharing Percentages (as defined therein) such that HPIP's sharing percentage thereafter is 95% and AIM Midstream Holdings's Sharing Percentage is 5%;
	•	HPIP transferred all of the 85.02% of our outstanding new IDRs held by HPIP to our General Partner such that our General Partner owns 100% of the outstanding new IDRs; and
	•	We issued to AIM Midstream Holdings a warrant to purchase up to 300,000 common units of the Partnership at an exercise price of $0.01 per common unit, which Warrant, among other terms, i) was exercisable at any time on or after February 8, 2014 until the tenth anniversary of February 5, 2014, ii) contained cashless exercise provisions and iii) contains customary anti-dilution and other protections. The Warrant was exercised on February 21, 2014.
	Gloria System Matter
	We were named in a lawsuit in the District Court of Jefferson Parish, Louisiana related to right of way maintenance and damages on our Louisiana Intrastate (Gloria) pipeline system related to a servitude agreement entered into by a predecessor in 1956. The landowner had sued us claiming that we have failed to maintain the pipeline right-of-way, allegedly causing erosion of the pipeline canal, erosion of levees, and deterioration of the adjacent marshland. The landowner sought damages for the cost to narrow the pipeline canal, rebuild the pipeline levees, and restore the damaged marsh.
	Following negotiations, we entered into an agreement with the landowner during the fourth quarter of 2014 for the procurement of additional pipeline right-of-way and permits in order to rebuild sections of the levees and dams which will provide additional protection to portions of our Gloria System. We expect to incur up to $1.0 million of capital expenditures over the next twelve months in connection with this rebuilding.
	Environmental matters
	We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to natural gas pipeline, NGL and crude pipelines and operations, as well as terminal operations and we could, at times, be subject to environmental cleanup and enforcement actions. We attempt to manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment.
	Regulatory matters
	On October 8, 2014, the Partnership reached an agreement in principle with customers regarding its Midla interstate pipeline that traverses Louisiana and Mississippi. The parties involved reached the agreement in principle in order to provide continued service to Midla's customers while addressing safety concerns with the existing pipeline.
	Midla and the parties agreed that Midla may retire the existing 1920s vintage pipeline and replace the existing natural gas service with a new pipeline from Winnsboro, Louisiana to Natchez, Mississippi (the "Natchez Line") to serve existing residential, commercial, and industrial customers. Customers not served by the new Natchez Line will be connected to other interstate or intrastate pipelines, other gas distribution systems, or offered conversion to propane service. The agreement is subject to final agreements and ongoing proceedings at the FERC.
	Under the agreement in principle and subject to FERC approval, Midla will execute long-term agreements to recover its investment in the new Natchez Line.
	Commitments and contractual obligations
	Future non-cancelable commitments related to certain contractual obligations as of December 31, 2014, are presented below (in thousands):
			Operating leases and service contracts		Asset Retirement Obligation		Total
	2015		$	3,428	$	—	$	3,428
	2016		2,204		6,884		9,088
	2017		1,421		—		1,421
	2018		1,306		—		1,306
	2019		1,525		—		1,525
	Thereafter		2,945		27,761		30,706
			$	12,829	$	34,645	$	47,474
	For the years ended December 31, 2014, 2013 and 2012, total expenses related to operating leases, land site leases and right-of-way agreements were $5.8 million, $1.1 million, and $0.9 million, respectively.

RelatedParty_Transactions

Related-Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related-Party Transactions	Related-Party Transactions
	Employees of our General Partner are assigned to work for us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by our General Partner to American Midstream, LLC, which, in turn, charges the appropriate subsidiary. Our General Partner does not record any profit or margin for the administrative and operational services charged to us. During the years ended December 31, 2014, 2013, and 2012, administrative and operational services expenses of $23.5 million, $14.2 million and $12.5 million, respectively, were charged to us by our General Partner. For the year ended December 31, 2014, 2013 and 2012, our General Partner incurred approximately $1.2 million, $1.8 million and $0.4 million of costs associated with certain business development activities, respectively. If the business development activities result in a project that will be pursued and funded by the Partnership, we will reimburse our General Partner for the business development costs related to that project.
	During the second quarter of 2014, the Partnership and an affiliate of its General Partner entered into a Management Service Fee arrangement under which the affiliate pays a monthly fee to reimburse the Partnership for administrative expenses incurred on the affiliate's behalf. For the year ended December 31, 2014, the Partnership recognized $0.9 million in management fee income that has been recorded as a reduction to Selling, general and administrative expenses.
	The High Point System, along with $15.0 million in cash, was contributed to us by HPIP in exchange for 5,142,857 Series A Units. Of the cash consideration paid by HPIP, approximately $2.5 million was used to pay certain transaction expenses of HPIP, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's former credit facility.
	In January 2014, in connection with the acquisition of the Lavaca System, the Partnership issued 1,168,225 Series B Units to our General Partner. The net proceeds related to the issuance was $30.0 million.
	In connection with the Blackwater Acquisition, our General Partner contributed the net assets of Blackwater which were recorded at their historical book value of $22.7 million for consideration of $63.9 million, of which $27.7 million was accounted for as a cash distribution to the General Partner. The consideration also included 125,500 limited partner units which were accounted for as a non-cash distribution to the General Partner at a fair value of $3.1 million. See Note 3 "Acquisitions" for more information.
	On October 9, 2012, Blackwater entered into a Convertible Promissory Note (the "BWHD Note") with ArcLight Energy Partners Fund V, L.P. ("AL Fund V"), in the amount of $20.0 million. AL Fund V is a related party to the Partnership. The BWHD Note was paid off during the fourth quarter of 2013 as part of the Blackwater Acquisition.

Reporting_Segments

Reporting Segments	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Reporting Segments	Reporting Segments
	Our operations are located in the United States and are organized into three reporting segments: i) Gathering and Processing, ii) Transmission and iii) Terminals.
	Gathering and Processing
	Our Gathering and Processing segment provides "wellhead-to-market" services to producers of natural gas and oil, which include transporting raw natural gas from the wellhead through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs and selling or delivering pipeline quality natural gas and NGLs to various markets and pipeline systems.
	Transmission
	Our Transmission segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, including local distribution companies, or LDCs, utilities and industrial, commercial and power generation customers.
	Terminals
	Our Terminals segment provides above-ground storage services at our marine terminals that support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products, including petroleum products, distillates, chemicals and agricultural products.
	These segments are monitored separately by management for performance and are consistent with the Partnership's internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the results of each segment.
	The following tables set forth our segment information for the periods indicated (in thousands):
		Year Ended December 31, 2014
		Gathering			Transmission				Terminals			Total
		and
		Processing
	Revenue	$	203,616		$	88,189			$	15,504		$	307,309
	Gain (loss) on commodity derivatives, net	1,091			—				—			1,091
	Total revenue	204,707			88,189				15,504			308,400
	Operating expenses:
	Purchases of natural gas, NGL's and condensate	152,690			45,262				—			197,952
	Direct operating expenses	23,783			15,577				6,342			45,702
	Selling, general and administrative expenses											23,103
	Equity compensation expense											1,536
	Depreciation, amortization and accretion expense											28,832
	Total operating expenses											297,125
	Gain (loss) on sale of assets, net											(122		)
	Loss on impairment of property, plant and equipment											(99,892		)
	Other expense											(670		)
	Interest expense											(7,577		)
	Earnings in unconsolidated affiliates											348
	Income tax benefit (expense)											(557		)
	Income (loss) from operations of disposal groups, net of tax											(611		)
	Net income (loss)											(97,806		)
	Less: Net income (loss) attributable to noncontrolling interests											214
	Net income (loss) attributable to the Partnership											$	(98,020	)
	Segment gross margin (b)	$	50,817		$	42,828			$	9,162		$	102,807
		Year Ended December 31, 2013
		Gathering			Transmission				Terminals (a)			Total
		and
		Processing
	Revenue	$	205,179		$	79,041			$	9,831		$	294,051
	Gain (loss) on commodity derivatives, net	28			—				—			28
	Total revenue	205,207			79,041				9,831			294,079
	Operating expenses:
	Purchases of natural gas, NGL's and condensate	168,574			46,479				—			215,053
	Direct operating expenses	14,574			13,259				4,403			32,236
	Selling, general and administrative expenses											19,079
	Equity compensation expense											2,094
	Depreciation, amortization and accretion expense											30,002
	Total operating expenses											298,464
	Gain (loss) on involuntary conversion of property, plant and equipment											343
	Loss on impairment of property, plant and equipment											(18,155		)
	Interest expense											(9,291		)
	Income tax benefit (expense)											495
	Income (loss) from operation of disposal groups, net of tax											(2,413		)
	Net income (loss)											(33,406		)
	Less: Net income (loss) attributable to noncontrolling interests											633
	Net income (loss) attributable to the Partnership											$	(34,039	)
	Segment gross margin (b)	$	36,985		$	32,408			$	5,428		$	74,821
		Year Ended December 31, 2012
		Gathering			Transmission				Total
		and
		Processing
	Revenue	$	152,339		$	52,529			$	204,868
	Gain (loss) on commodity derivatives, net	3,400			—				3,400
Total revenue	155,739			52,529				208,268
Operating expenses:
Purchases of natural gas, NGL's and condensate	117,956			36,516				154,472
Direct operating expenses	12,152			5,031				17,183
Selling, general and administrative expenses								14,309
Equity compensation expense								1,783
Depreciation, amortization and accretion expense								21,287
Total operating expenses								209,034
Gain (loss) on involuntary conversion of property, plant and equipment								(1,021		)
Gain (loss) on sale of assets, net								123
Interest expense								(4,570		)
Income (loss) from operations of disposal groups								(18		)
Net income (loss)								(6,252		)
Less: Net income (loss) attributable to noncontrolling interests								256
Net income (loss) attributable to the Partnership								$	(6,508	)
Segment gross margin (b)	$	36,118		$	13,313			$	49,431
	December 31,
	2014		2013
Segment assets:
Gathering and Processing	686,395		178,869
Transmission	132,767		131,136
Terminals	71,180		60,873
Other (c)	26,302		11,197
Total assets	916,644		382,075
(a)	Terminals segment amounts are for the period from April 15, 2013 to December 31, 2013.
(b)	Segment gross margin for our Gathering and Processing segment consists of revenue less purchases of natural gas, NGLs and condensate and COMA. Segment gross margin for our Transmission segment consists of revenue, less purchases of natural gas and COMA. Segment gross margin for our Terminals segment consists of revenue, less direct operating expenses. Gross margin consists of the sum of the segment gross margin amounts for each of these segments. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow from operations as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. Effective October 1, 2012, we changed our segment gross margin measure to exclude construction, operating and maintenance agreement ("COMA") income. Effective January 1, 2011, we changed our segment gross margin measure to exclude unrealized non-cash mark-to-market adjustments related to our commodity derivatives. Effective April 1, 2011, we changed our segment gross margin measure to exclude realized early termination costs on commodity derivatives.
(c)	Other assets not allocable to segments consist of investment in unconsolidated affiliate, corporate leasehold improvements, and other assets.
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."
The following table summarizes the percentage of revenue earned from those customers in each segment that exceed 10% of the Partnership's consolidated segment's revenue for the each of the periods presented below:
	Year Ended December 31,
	2014		2013			2012
Gathering and Processing:
Customer A	33	%	43	%		40	%
Customer B	12	%	19	%		11	%
Customer D	—		—	%		12	%
Other	55	%	38	%		37	%
Total	100	%	100	%		100	%
Transmission:
Customer C	43	%	39	%		50	%
Customer D	16	%	16	%		22	%
Customer E	—		—	%		10	%
Other	41	%	45	%		18	%
Total	100	%	100	%		100	%
Terminals:
Customer F	19	%	20	%		N/A
Customer B	20	%	17	%		N/A
Customer G	15	%	16	%		N/A
Customer H	11	%	13	%		N/A
Other	35	%	34	%		N/A
Total	100	%	100	%		—

Quarterly_Financial_Data_Notes

Quarterly Financial Data (Notes)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information [Text Block]	Quarterly Financial Data (Unaudited)
	Summarized unaudited quarterly financial data for 2014 and 2013 are as follows (in thousands, except per unit amounts):
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter (b)
	Year Ended December 31, 2014
	Total revenues	$	80,238		$	77,680		$	70,305		$	80,177
	Gross margin (a)	23,081			22,167			21,332			36,227
	Operating income (loss)	2,450			734			(290		)	(91,633		)
	Net income (loss) from continuing operations	558			(1,095		)	(2,397		)	(94,261		)
	Income (loss) from operations of disposal groups	(50		)	(506		)	(26		)	(29		)
	Net income (loss) attributable to noncontrolling interest	108			66			33			7
	Net income (loss) attributable to the Partnership	400			(1,667		)	(2,456		)	(94,297		)
	General Partner's Interest in net income (loss)	7			(22		)	(32		)	(1,232		)
	Limited Partners' Interest in net income (loss)	$	393		$	(1,645	)	$	(2,424	)	$	(93,065	)
	Limited Partners' income (loss) per unit:
	Income (loss) from continuing operations	$	(0.31	)	$	(0.55	)	$	(0.58	)	$	(4.98	)
	Income (loss) from discontinued operations	(0.01		)	(0.04		)	—			—
	Net income (loss)	$	(0.32	)	$	(0.59	)	$	(0.58	)	$	(4.98	)
	Year Ended December 31, 2013
	Total revenues	$	62,599		$	77,191		$	77,519		$	76,770
	Gross margin (a)	12,705			18,317			20,908			22,891
	Operating income (loss)	(1,661		)	(17,841		)	(104		)	(2,591		)
	Net income (loss) from continuing operations	(3,392		)	(20,057		)	(2,526		)	(5,018		)
	Income (loss) from operations of disposal groups	(6		)	(1,869		)	(15		)	(523		)
	Net income (loss) attributable to noncontrolling interest	155			188			190			100
	Net income (loss) attributable to the Partnership	(3,553		)	(22,114		)	(2,731		)	(5,641		)
	General Partner's Interest in net income (loss)	(70		)	(905		)	(221		)	(209		)
	Limited Partners' Interest in net income (loss)	$	(3,482	)	$	(21,209	)	$	(2,510	)	$	(5,433	)
	Limited Partners' income (loss) per unit:
	Income (loss) from continuing operations	$	(0.39	)	$	(4.01	)	$	(0.81	)	$	(1.43	)
	Income (loss) from discontinued operations	0.01			(0.20		)	0.01			—
	Net income (loss)	$	(0.38	)	$	(4.21	)	$	(0.80	)	$	(1.43	)
	(a)	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."
	(b)	The Partnership record an immaterial out-of-period adjustment in the fourth quarter of 2014 to account for the items associated with the material weakness described in Item 9A.  Management’s Annual Report over Internal Control over Financial Reporting.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events
	Distribution
	On January 22, 2015, we announced that the board of directors of our General Partner declared a quarterly cash distribution of $0.4725 per unit for the fourth quarter ended December 31, 2014, or $1.89 per unit on an annualized basis. The cash distribution was paid on February 13, 2015, to unitholders of record as of the close of business on February 6, 2015, together with our General Partner.

Organization_and_Basis_of_Pres1

Organization and Basis of Presentation (Policies)	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of business	American Midstream Partners, LP (the "Partnership"), was formed on August 20, 2009 as a Delaware limited partnership for the purpose of operating, developing and acquiring a diversified portfolio of midstream energy assets. The Partnership's general partner, American Midstream GP, LLC (the "General Partner"), is 95% owned by High Point Infrastructure Partners, LLC ("HPIP") and 5% owned by AIM Midstream Holdings, LLC. We hold our assets in a series of wholly owned limited liability companies, a limited partnership and a corporation. Our capital accounts consist of notional general partner units and limited partner interests.
	Nature of business
	We are engaged in the business of gathering, treating, processing, and transporting natural gas, fractionating NGLs and storing specialty chemical products through our ownership and operation of twelve gathering systems, five processing facilities, three fractionation facilities, four marine terminal sites, three interstate pipelines and five intrastate pipelines. We also own a 66.7% non-operating interest in Main Pass Oil Gathering, LP ("MPOG"), a crude oil gathering and processing system, as well as a 50% undivided, non-operating interest in the Burns Point Plant, a natural gas processing plant. Our primary assets, which are strategically located in Alabama, Georgia, Louisiana, Maryland, Mississippi, North Dakota, Tennessee and Texas, provide critical infrastructure that links producer of natural gas, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets. We currently operate more than 3,000 miles of pipelines that gather and transport over 1 Bcf/d of natural gas and operate approximately 1.7 million barrels of storage capacity across four marine terminal sites.
Basis of presentation	Basis of presentation
	The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2014 and 2013, and results of operations, comprehensive income, changes in partners' capital and noncontrolling interest, and cash flows for the years ended December 31, 2014, 2013 and 2012.
	We have prepared the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP"). We have made reclassifications to amounts reported in prior period consolidated financial statements to conform with current year presentation. These reclassifications did not have an impact on net income for the period previously reported.
	The financial results for the years ended December 31, 2013 and 2012 have been reclassified to present an asset group previously presented as held for sale as held and used.
	The results of operations for acquisitions accounted for as business combinations have been included in the consolidated financial statements since their respective acquisition dates.
Transactions Between Entities Under Common Control	Transactions Between Entities Under Common Control
	We may enter into transactions with our General Partner and affiliates whereby we receive a contribution of midstream assets or subsidiaries in exchange for consideration from the Partnership. We account for the net assets received using the historical book value of the asset or subsidiary being contributed or transferred as these are transactions between entities under common control. Our historical financial statements may be revised to include the results attributable to the assets contributed from our General Partner as if we owned such assets for all periods presented by the Partnership since either the change in control of our General Partner, effective April 15, 2013 or later.
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. We hold a 50% undivided interest in the Burns Point gas processing facility in which we are responsible for our proportionate share of the costs and expenses of the facility. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of this undivided interest. In July 2012, the Partnership acquired an 87.4% undivided interest in the Chatom Processing and Fractionation facility (the "Chatom System"). In the fourth quarter of 2013, the Partnership acquired an additional 4.8% undivided interest in the Chatom System. Our consolidated financial statements reflect the accounts of the Chatom System since acquisition. The interests in the Chatom System held by non-affiliated working interest owners are reflected as noncontrolling interests in the Partnership's consolidated financial statements.
	The Partnership accounts for its 66.7% non-operated interest in MPOG as an equity method investments under ASC 323, as the Partnership exercises significant influence but does not control nor is the primary beneficiary of MPOG.
Use of estimates	Use of estimates
	When preparing consolidated financial statements in conformity with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and assumptions are based on information available at the time such estimates and assumptions are made. Adjustments made with respect to the use of these estimates and assumptions often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates and assumptions are used in, among other things, i) estimating unbilled revenues, product purchases and operating and general and administrative costs, ii) developing fair value assumptions, including estimates of future cash flows and discount rates, iii) analyzing long-lived assets, goodwill and intangible assets for possible impairment, iv) estimating the useful lives of assets and v) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.
Cash and cash equivalents	Cash and cash equivalents
	We consider all highly liquid investments with an original maturity of three months or less at the date of purchase to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.
Allowance for doubtful accounts	Allowance for doubtful accounts
	We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of December 31, 2014 and 2013, the Partnership recorded no allowances for losses on accounts receivable.
Inventory	Inventory
	Inventory includes natural gas liquids ("NGLs") product inventory. The Partnership records all product inventories at the lower of cost or market with a cost basis determined on a weighted average basis. Product inventories are included within Other current assets on the consolidated balance sheets.
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 as gas imbalances and classified within Other current assets or Other current liabilities on our consolidated balance sheets at cost which approximates fair value.
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. In accordance with the authoritative accounting guidance, 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 derivative financial instruments in our consolidated statements of operations as follows:
	•	Commodity-based derivatives: "Total revenue"
	•	Corporate interest rate derivatives: "Interest expense"
	Our formal hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to the approval and monitoring by the board of directors of our General Partner. We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction, and we do not use derivative financial instruments for speculative or trading purposes.
	The price assumptions we use to value our derivative financial instruments can affect net income (loss) for each period. We use published market price information where available, or quotations from over-the-counter, or OTC, market makers to find executable bids and offers. The valuations also reflect the potential impact of conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
Fair value measurements	Fair value measurements
	We apply the authoritative accounting provisions for measuring fair value of our derivative instruments and disclosures associated with our outstanding indebtedness. We define fair value as an exit price representing the expected amount we would receive when selling an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.
	We use various assumptions and methods in estimating the fair values of our financial instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of our various credit facilities approximate fair value, because the interest rates on these facilities are variable.
	We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:
	•	Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities;
	•	Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets that are either directly or indirectly observable; and
	•	Level 3 – Inputs are unobservable and considered significant to fair value measurement.
	We utilize a mid-market pricing convention, or the "market approach," for valuation for assigning fair value to our derivative assets and liabilities. Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.
Property, plant and equipment	Property, plant and equipment
	We capitalize expenditures related to property, plant and equipment that have a useful life greater than one year for assets purchased or constructed; existing assets that are replaced, improved, or the useful lives of which have been extended; and all land, regardless of cost. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.
	We record property, plant, and equipment at its original cost, which we depreciate on a straight-line basis over its estimated useful life. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We record depreciation using the group method of depreciation, which is commonly used by pipelines, utilities and similar assets.
	We classify long-lived assets to be disposed of through sales that meet specific criteria as held for sale. We cease depreciating those assets effective on the date the asset is classified as held for sale. We record those assets at the lower of their carrying value or the estimated fair value less the cost to sell. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.
Impairment of long lived Assets	Impairment of long lived Assets
	We evaluate the recoverability of our property, plant and equipment 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 for recoverability by estimating the undiscounted future cash flows expected to be derived from the asset as a going concern. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of 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 not amortized but is reviewed for impairment at least annually or more frequently if an event or change in circumstance indicates that an impairment may have occurred. We first assess qualitative factors to evaluate whether it is more likely than not that an impairment has occurred and it is therefore necessary to perform the two-step goodwill impairment test. If the two-step goodwill impairment test indicates that the goodwill is impaired, an impairment loss is recorded.
	We record the estimated fair value of acquired customer contracts, 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 months and thirty years.
Deferred financing costs	Deferred financing costs
	Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchase and debt extinguishment include any associated unamortized deferred financing costs.
Asset retirement obligations (AROs)	Asset retirement obligations ("AROs")
	AROs are legal obligations associated with the retirement of tangible long-lived assets that result from the asset's acquisition, construction, development and 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 a minority of our offshore right-of-way agreements due to requirements or landowner options to compel us to remove the pipe at final abandonment. Sufficient data exists with certain onshore pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement of estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management's experience, or the asset's estimated economic life. The useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to reasonably estimate potential settlement dates and methods.
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 either probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.
Convertible preferred units
Noncontrolling interests	Noncontrolling interests
	Noncontrolling interests represent the noncontrolling interest holders' proportionate share of the equity of the respective systems. Noncontrolling interest is adjusted for the noncontrolling interest holders' proportionate share of the earnings or losses. Management reports noncontrolling interest in the Chatom system in the financial statements pursuant to paragraph ASC 810-10-65-1. The 7.8% noncontrolling interest is held by non-affiliated working interest owners
Revenue recognition and the estimation of revenues and cost of purchases	Revenue recognition and the estimation of revenues and cost of purchases
	We recognize revenue when all of the following criteria are met: i) persuasive evidence of an exchange arrangement exists, ii) delivery has occurred or services have been rendered, iii) the price is fixed or determinable, and iv) collectability is reasonably assured. We record revenue and cost of product sold on a gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that are purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating, transportation or storage, we record those fees separately in revenues. We have the following arrangements:
	Fee-based
	Under these arrangements, we generally are paid a fixed fee for gathering and transporting natural gas. Fee-based revenues are recorded when services have been provided, and collectability of the revenue is reasonably assured.
	Percent-of-proceeds, or POP
	Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas and NGLs at market prices. Where we provide processing services at the processing plants that we own, or obtain processing service for our own account under our own elective processing arrangements we typically retain and sell a percentage of the residue natural gas and resulting NGLs. We recognize percent-of-proceeds contract revenue when the natural gas, NGLs or condensate is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.
	Fixed-margin
	Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. We recognize revenue from fixed-margin contracts when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.
	Firm transportation
	Under arrangements to provide firm transportation service, we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not they utilize the capacity. In most cases, the shipper also pays a variable-use charge with respect to quantities actually transported by us. Firm transportation revenue is recorded when products are delivered, services have been provided, and collectability of the revenue is reasonably assured.
	Interruptible transportation
	Under arrangements to provide interruptible transportation service, we are only obligated to transport natural gas nominated by the shipper to the extent we have available capacity. For this service, the shipper pays no reservation charge but pays a variable-use charge for quantities actually shipped. Interruptible transportation revenue is recorded when products are delivered, services have been provided, and collectability of revenue is reasonably assured.
	Interest in the Burns Point Plant
	We account for our interest in the Burns Point Plant using the proportionate consolidation method. Under this method, we include in our consolidated statement of operations our value of plant revenues taken in-kind and plant expenses reimbursed to the operator.
	Terminal revenue and services
	Revenues for our terminals include storage tank lease fees, whereby a customer agrees to pay for a certain amount of tank storage over a certain period of time; and throughput fees, whereby a customer pays a fee based on volumes moving through the terminal. At our terminals, we also offer and provide packaging, blending, handling, filtering and certain other ancillary services. Revenue from firm storage contracts is recognized ratably, which is typically monthly, over the term of the lease. Occasionally, customers pay for tank lease fees in advance. Fees received in advance are deferred until the period earned. Revenue from throughput fees and ancillary fees are recognized as services are provided to the customer and collectability is reasonably assured.
Equity-based compensation	Equity-based compensation
	We award equity-based compensation to management, non-management employees and directors in the form of phantom units, which are deemed to be equity awards. Compensation expense on phantom units is measured by the fair value of the award at the date of grant as determined by management. Compensation expense is recognized in Equity compensation expense over the requisite service period of each award.
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 taxable C-Corporation consolidated return group which is a taxable entity. We account for income taxes of that subsidiary using an asset and liability approach for financial accounting and reporting of income taxes. If it is more than likely that a deferred tax asset will not be realized, a valuation allowance is recognized.
	Certain tax expense results from the enactment of laws by the State of Texas that apply to entities organized as partnerships and is included in Income tax (expense) benefit in the consolidated statements of operations. The Texas margin tax is computed on our taxable margin apportioned to Texas annually.
	Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) allocable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirement under our Partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner's tax attributes in us is not available.
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. We have no dilutive securities, therefore basic and diluted net income per unit are the same.

Acquisitions_Tables

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Schedule of business acquisitions	The following table summarizes the fair value of consideration transferred to acquire Costar and the preliminary allocation of that amount to the assets acquired, liabilities assumed and the noncontrolling interest based upon their respective fair values as of the acquisition date. Such allocation will be finalized once the Partnership negotiates a final settlement of working capital amounts with the sellers with any resulting adjustment being recorded to goodwill.
	Fair value of consideration transferred (in thousands):
	Cash	$	265,383
	Limited partner common units	147,296
	Total fair value of consideration	$	412,679
Schedule of recognized identified assets acquired and liabilities assumed
	Property, plant and equipment:
	Land	$	2
	Pipelines	58,737
	Equipment	753
	Total property, plant and equipment	59,492
	Intangible assets	21,350
	Goodwill	23,567
	Total cash consideration	$	104,409
	The following table presents the carrying value of the identified assets received and liabilities assumed at the acquisition date (in thousands):
	Cash and cash equivalents	$	1,935
	Accounts receivable	3,629
	Unbilled revenue	1,446
	Other current assets	2,049
	Property, plant and equipment, net	82,615
	Other assets	1,000
	Accounts payable	(11		)
	Accrued expenses and other current liabilities	(4,077		)
	Current portion of long-term debt	(893		)
	Asset retirement obligation liability	(25,763		)
	Total identifiable net assets	$	61,930
	Fair Value of assets acquired, liabilities assumed and noncontrolling interest (in thousands):
	Working capital	$	8,152
	Property, plant and equipment:
	Processing plants	$	48,357
	Pipelines	128,799
	Land	1,244
	Buildings	682
	Equipment	9,827
	Construction in progress	16,146
	Total property, plant and equipment	205,055
	Investment in unconsolidated affiliate	11,884
	Intangible assets:
	Customer relationships	53,400
	Dedicated acreage	32,000
	Goodwill	102,407
	Noncontrolling interest	(219		)
		$	412,679
	The following table presents the fair value of consideration transferred to acquire the Chatom system and the amounts of identified assets acquired and liabilities assumed at the acquisition date, as well as the fair value of the 12.6% noncontrolling interest in the Chatom system at the acquisition date (in thousands):
	Cash consideration:	$	51,377
	Recognized amounts of identifiable assets acquired and liabilities assumed:
	Unbilled revenue	$	4,535
	Property, plant and equipment	58,279
	Asset retirement cost	452
	Accounts payable	(399		)
	Accrued gas purchases	(3,631		)
	Asset retirement obligations	(452		)
	Noncontrolling interest	(7,407		)
	Total identifiable net assets:	$	51,377
Unaudited pro forma consolidated information of the partnership, adjusted for the acquisition of the Costar assets	The following unaudited pro forma summary presents consolidated financial information for the Partnership as if the Costar acquisition had occurred on January 1, 2013 (in thousands):
		Year Ended December 31,
		2014			2013
	Revenue	$	435,133		$	448,748
	Net loss	(101,237		)	(30,672		)
	Limited partners' net loss per unit	(6.15		)	(3.82		)

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]	The following table presents the revenue, expense and (loss) gain from operations of disposal groups associated with the assets classified as held for sale for the years ended December 31, 2014, 2013, and 2012 (in thousands, except per unit amounts):
		Year Ended December 31,
		2014			2013			2012
	Revenue	$	474		$	2,084		$	2,318
	Expense	(658		)	(2,361		)	(2,336		)
	Impairment	(673		)	(2,400		)	—
	Loss on sale of assets	(87		)	(75		)	—
	Income tax benefit	333			339			—
	Gain (loss) from operations of disposal groups, net of tax	$	(611	)	$	(2,413	)	$	(18	)
	Limited partners' net income (loss) per unit from discontinued operations (basic and diluted)	$	(0.04	)	$	(0.27	)	$	—

Concentration_of_Credit_Risk_a1

Concentration of Credit Risk and Trade Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2014
Receivables [Abstract]
Percentage of revenue earned from major customers	The following table summarizes the percentage of revenue earned from those customers that exceed 10% of the Partnership's consolidated revenue in the consolidated statement of operations for the each of the years presented below:
		Year Ended December 31,
		2014		2013		2012
	Customer A	22	%	28	%	30	%
	Customer B	—	%	13	%	—	%
	Customer C	12	%	12	%	13	%
	Customer D	10	%	10	%	14	%
	Other	56	%	37	%	43	%
	Total	100	%	100	%	100	%
	The following table summarizes the percentage of revenue earned from those customers in each segment that exceed 10% of the Partnership's consolidated segment's revenue for the each of the periods presented below:
		Year Ended December 31,
		2014		2013		2012
	Gathering and Processing:
	Customer A	33	%	43	%	40	%
	Customer B	12	%	19	%	11	%
	Customer D	—		—	%	12	%
	Other	55	%	38	%	37	%
	Total	100	%	100	%	100	%
	Transmission:
	Customer C	43	%	39	%	50	%
	Customer D	16	%	16	%	22	%
	Customer E	—		—	%	10	%
	Other	41	%	45	%	18	%
	Total	100	%	100	%	100	%
	Terminals:
	Customer F	19	%	20	%	N/A
	Customer B	20	%	17	%	N/A
	Customer G	15	%	16	%	N/A
	Customer H	11	%	13	%	N/A
	Other	35	%	34	%	N/A
	Total	100	%	100	%	—

Other_Current_Assets_Tables

Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2014
Other Current Assets [Abstract]
Schedule of other current assets	Other current assets consists of the following (in thousands):
		December 31,
		2014		2013
	Prepaid insurance	$	4,162	$	3,166
	Restricted cash	6,475		—
	Other current assets	4,865		4,331
		$	15,502	$	7,497
	Restricted cash of $6.5 million is a cash-backed letter of credit related to Costar Midstream operations that the Partnership was contractually obligated to maintain after the Costar Acquisition. The Partnership was released of this obligation in January 2015.

Derivatives_Tables

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair value associated with commodity derivative instruments	As of December 31, 2014 and 2013, the value associated with our commodity derivatives, interest rate swap and weather derivative were recorded in our consolidated balance sheets, under the captions as follows (in thousands):
		Gross Risk Management Assets						Gross Risk Management Liabilities						Net Risk Management Assets (Liabilities)
	Balance Sheet Classification	December 31, 2014			December 31, 2013			December 31, 2014			December 31, 2013			December 31, 2014			December 31, 2013
	Current	$	688		$	473		$	—		$	—		$	688		$	473
	Noncurrent	—			—			—			—			—			—
	Total assets	$	688		$	473		$	—		$	—		$	688		$	473
	Current	$	—		$	27		$	(215	)	$	(450	)	$	(215	)	$	(423	)
	Noncurrent	—			—			—			(101		)	—			(101		)
	Total liabilities	$	—		$	27		$	(215	)	$	(551	)	$	(215	)	$	(524	)
Realized and unrealized gains (losses) with commodity and interst rate derivative instruments	For the years ended December 31, 2014, 2013 and 2012, the realized and unrealized gains (losses) associated with our commodity, interest rate and weather derivative instruments were recorded in our consolidated statements of operations, under the captions as follows (in thousands):
		Realized			Unrealized
	2014
	Gain (loss) on commodity derivatives, net	$	735		$	356
	Interest expense	(433		)	239
	Direct operating expenses	(1,035		)	—
	Total	$	(733	)	$	595
	2013
	Gain (loss) on commodity derivatives, net	$	1,069		$	(1,041	)
	Interest expense	(207		)	(454		)
	Direct operating expenses	(662		)	—
	Total	$	200		$	(1,495	)
	2012
	Gain (loss) on commodity derivatives, net	$	2,408		$	992
	Total	$	2,408		$	992

Fair_Value_Measurement_Tables

Fair Value Measurement (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair value of financial instruments	Fair Value of Financial Instruments
	The following table sets forth by level within the fair value hierarchy, our commodity derivative instruments and interest rate swap, included as part of Risk management assets and Risk management liabilities within the consolidated balance sheet, that were measured at fair value on a recurring basis as of December 31, 2014 and 2013 (in thousands):
		Carrying			Estimated Fair Value of the Asset (Liability)
		Amount			Level 1		Level 2			Level 3		Total
	Commodity derivative instruments, net
	31-Dec-14	$	286		$	—	$	286		$	—	$	286
	31-Dec-13	(70		)	—		(70		)	—		(70		)
	Interest rate swap
	31-Dec-14	$	(215	)	$	—	$	(215	)	$	—	$	(215	)
	31-Dec-13	(454		)	—		(454		)	—		(454		)
	The unamortized portion of the premium paid to enter the weather derivative described in Note 7 "Derivatives," is included within Risk management assets on the consolidated balance sheet but is not included in the above table as it is recorded at amortized cost, not fair value.

Property_Plant_and_Equipment_N1

Property, Plant and Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Property, plant, and equipment, net	Property, plant and equipment, net, as of December 31, 2014 and 2013, were as follows (in thousands):
		Useful Life	December 31,			December 31,
		(in years)	2014			2013
	Land	N/A	$	5,282		$	6,015
	Construction in progress	N/A	77,551			6,443
	Base gas	N/A	1,108			1,108
	Buildings and improvements	4 to 40	6,905			5,109
	Processing and treating plants	8 to 40	80,141			97,106
	Pipelines	5 to 40	452,180			239,865
	Compressors	4 to 20	24,227			11,955
	Dock	20 to 40	8,072			7,942
	Tanks, truck rack and piping	20 to 40	30,079			22,432
	Equipment	8 to 20	8,952			6,294
	Computer software	5	3,520			3,531
	Total property, plant and equipment		698,017			407,800
	Accumulated depreciation		(115,835		)	(95,099		)
	Property, plant and equipment, net		$	582,182		$	312,701

Goodwill_and_Intangible_assets1

Goodwill and Intangible assets (Tables)	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Finite-Lived Intangible Assets [Table Text Block]	Intangible assets, net, consist of the following (in thousands):
		December 31,
		2014			2013
	Gross carrying amount:
	Customer contracts	$	12,101		$	12,101
	Customer relationships	53,400			—
	Dedicated acreage	53,350			—
		$	118,851		$	12,101
	Accumulated amortization:
	Customer contracts	$	(11,110	)	$	(8,419	)
	Customer relationships	(553		)	—
	Dedicated acreage	(882		)	—
		$	(12,545	)	$	(8,419	)
	Net carrying amount:
	Customer contracts	$	991		$	3,682
	Customer relationships	52,847			—
	Dedicated acreage	52,468			—
		$	106,306		$	3,682

Accrued_Expenses_and_Other_Cur1

Accrued Expenses and Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Payables and Accruals [Abstract]
Schedule of accrued expenses and other current liabilities	Accrued expenses and other current liabilities were as follows (in thousands):
		December 31,
		2014		2013
	Accrued capital expenditures	$	17,134	$	2,562
	Accrued expenses	7,036		5,412
	Gas imbalances payable	1,069		4,305
	Other	549		2,779
		$	25,788	$	15,058

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Schedule of reconciliation of the beginning and ending aggregate carrying amount of ARO liabilities	The following table is a reconciliation of the asset retirement obligations (in thousands):
		Year Ended December 31,
		2014			2013
	Beginning asset retirement obligation	$	34,636		$	8,319
	Liabilities assumed	248			25,763
	Expenditures	(1,030		)	—
	Accretion expense	791			554
	Ending asset retirement obligation	$	34,645		$	34,636
	For the years ended December 31, 2014, 2013 and 2012, total expenses related to operating leases, land site leases and right-of-way agreements were $5.8 million, $1.1 million, and $0.9 million, respectively.

Debt_Obligations_Tables

Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Outstanding borrowings under the credit facility	Our outstanding borrowings under the credit facility were (in thousands):
		December 31,
		2014		2013
	Revolving credit facility	$	372,950	$	130,735
	Other debt	2,908		2,048
	Total debt	375,858		132,783
	Less: current portion	2,908		2,048
	Long-term debt	$	372,950	$	130,735

Partners_Capital_Tables

Partners' Capital (Tables)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Schedule for number of units outstanding	The numbers of units outstanding were as follows (in thousands):
		December 31,
		2014		2013			2012
	Series A convertible preferred units	5,745		5,279			—
	Series B convertible units	1,255		—			—
	Limited Partner common units	22,670		7,414			4,639
	Limited Partner subordinated units	—		—			4,526
	General Partner units	392		185			185
	Distributions
	We made cash distributions as follows (in thousands):
		Year Ended December 31,
		2014			2013			2012
	Series A convertible preferred units	2,658			2,375			—
	Limited Partner common units	22,656			8,207			7,919
	Limited Partner subordinated units	—			5,073			7,830
	General Partner units	333			284			321
	General Partners' incentive distribution rights	2,362			181			—
		$	28,009		$	16,120		$	16,070
	At December 31, 2014, we have accrued $3.2 million for the paid-in-kind Series A Units. The distributions will be made in the first quarter of 2015. During the year ended December 31, 2014, we issued 555 thousand Series A PIK Units and 86 thousand Series B PIK Units.
	The numbers of units outstanding were as follows (in thousands):
		December 31,
		2014		2013			2012
	Series A convertible preferred units	5,745		5,279			—
	Series B convertible units	1,255		—			—
	Limited Partner common units	22,670		7,414			4,639
	Limited Partner subordinated units	—		—			4,526
	General Partner units	392		185			185

Earnings_per_Unit_Tables

Earnings per Unit (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Schedule of Earnings Per Share, Basic and Diluted, Per General and Limited Partner Unit, Including Two Class Method [Table Text Block]	We determined basic and diluted net income (loss) per limited partner unit as follows, (in thousands, except per unit amounts):
		Year Ended December 31,
		2014			2013			2012
	Net income (loss) from continuing operations	$	(97,195	)	$	(30,993	)	$	(6,234	)
	Net income (loss) attributable to noncontrolling interests	214			633			256
	Net income (loss) from continuing operations attributable to the Partnership	(97,409		)	(31,626		)	(6,490		)
	Less:
	Distributions on Series A preferred units	14,492			24,117			—
	Declared distributions on Series B Units	2,220			—			—
	General partner's distributions	2,694			464			322
	General partner's share in undistributed loss	(1,820		)	(1,708		)	(458		)
	Blackwater net loss from continuing operations	—			(716		)	—
	Net income (loss) from continuing operations available to limited Partners	(114,995		)	(53,783		)	(6,354		)
	Net income (loss) from discontinued operations available to Limited Partners	(603		)	(2,051		)	(18		)
	Net income (loss) available to Limited Partners	$	(115,598	)	$	(55,834	)	$	(6,372	)
	Weighted average number of units used in computation of Limited Partners' net income (loss) per unit (basic and diluted)	13,472			7,525			9,113
	Limited Partners' net income (loss) from continuing operations per unit (basic and diluted)	$	(8.54	)	$	(7.15	)	$	(0.70	)
	Limited Partners' net income (loss) from discontinued operations per unit (basic and diluted)	(0.04		)	(0.27		)	—
	Limited Partners' net income (loss) per unit (basic and diluted)	$	(8.58	)	$	(7.42	)	$	(0.70	)

LongTerm_Incentive_Plan_Tables

Long-Term Incentive Plan (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summarizes unit-based awards	The following table summarizes our unit-based awards for each of the periods indicated, in units:
		Year Ended December 31, 2014
		Shares		Weighted-Average Exercise Price
	Outstanding at beginning of period	75,529		17.62
	Granted	188,946		20.8
	Forfeited	(12,009	)	18.28
	Vested	(51,334	)	20.89
	Outstanding at end of period	201,132		19.73

PostEmployment_Benefits_Tables

Post-Employment Benefits (Tables)	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Schedule of changes in the benefit obligation, the fair value of the plan assets and the recorded asset or liability of the OPEB Plan using the accrual method	The tables below detail the changes in the benefit obligation, the fair value of the plan assets and the funded status of the OPEB Plan using the accrual method (in thousands):
			Year Ended December 31,
			2014				2013
	Change in benefit obligation
	Benefit obligation, beginning of period		$	532			$	472
	Service cost		2				5
	Interest cost		24				15
	Actuarial (gain) loss		122				(29		)
	Plan amendments		—				126
	Benefits paid		(25		)		(57		)
	Benefit obligation, end of period		$	655			$	532
	Change in plan assets
	Fair value of plan assets, beginning of period		$	1,528			$	1,552
	Actual return on plan assets		104				(53		)
	Employer's contributions		90				90
	Benefits paid		(38		)		(61		)
	Fair value of plan assets, end of period		$	1,684			$	1,528
	Funded status
	Funded status		$	1,029			$	996
Schedule of amounts of plan assets recognized in consolidated balance sheets	The weighted average asset allocation of our OPEB Plan at the measurement date by asset category, which are all classified as Level 1 investments, are as follows:
			December 31,
			2014			2013			2012
	Fixed income (a)		70	%		70.1	%		72.2	%
	Other (b)		30	%		29.9	%		27.8	%
	Total		100	%		100	%		100	%
	(a)	United States government securities, municipal corporate bonds and notes and asset backed securities
	(b)	Cash and securities with maturities of one year or less
Schedule of components of net periodic benefit cost and other amounts recognized in other comprehensive income	Components of Net Periodic Benefit Cost and Other amounts Recognized in Other Comprehensive Income (in thousands):
			Year Ended December 31,
			2014				2013				2012
	Net Periodic Benefit Cost
	Service cost		$	2			$	5			$	4
	Interest cost		24				15				18
	Expected return on plan assets		(70		)		(70		)		(67		)
	Amortization of prior service cost		4				—				—
	Amortization of net (gain) loss		(5		)		(23		)		(43		)
	Net periodic benefit cost		$	(45	)		$	(73	)		$	(88	)
	Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
	Net (gain) loss		$	102			$	247			$	64
	Total recognized in other comprehensive income		102				247				64
	Total recognized in net periodic benefit cost and other comprehensive income		$	57			$	174			$	(24	)
Schedule of assumptions made in measuremnet of the projected benefit obligations or assets of the OPEB Plan	The assumptions made in measurement of the projected benefit obligations or assets of the OPEB Plan were as follows:
			Year Ended December 31,
			2014			2013
	Discount rate		3.73	%		4.57	%
	Expected return on plan assets		2.5	%		4.5	%
	Health care trend rate		3	%		4.5	%
Schedule of benefits expected to be paid in each of the next five fiscal years	The following table presents the benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five years thereafter by the OPEB Plan (in thousands):
	For the year ending
	2015	$	33
	2016	32
	2017	32
	2018	32
	2019	31
	Five years thereafter	194

Income_Tax_Tables

Income Tax (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	Net deferred income tax assets and liabilities consist of (in thousands):
		31-Dec-14			31-Dec-13
	Current deferred tax asset	$	3,086		$	—
	Deferred tax liability, net	(8,199		)	(4,749		)
		$	(5,113	)	$	(4,749	)
	An analysis of the Partnership's deferred taxes is as follows (in thousands):
		31-Dec-14			31-Dec-13
	Deferred tax assets:
	Net operating loss carryforwards	$	4,173		$	5,455
	Other	213			182
	Total deferred tax assets	4,386			5,637
	Deferred tax liabilities:
	Property, plant and equipment	9,112			9,022
	Intangible assets	387			1,364
	Total deferred tax liabilities	9,499			10,386
	Deferred income tax liability, net	$	(5,113	)	$	(4,749	)
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The details of the provision for taxes on income for the year ended December 31, 2014, are as follows (in thousands):
		Year Ended December 31,
		2014			2013
	Net loss before income tax benefit (expense)	$	(96,638	)	$	(31,488	)
	US Federal statutory tax rate	34		%	34		%
	Federal income tax benefit at statutory rate	32,857			10,706
	Reconciling items:
	Partnership loss not subject to income tax	(33,216		)	(10,296		)
	Income not subject to corporate-level tax	—			222
	State and local tax benefit (expense)	(159		)	71
	Adjustments related to prior years	(37		)	(175		)
	Other	(2		)	(33		)
	Income tax benefit (expense)	$	(557	)	$	495
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The income tax provision related to continuing operations consist of the following (in thousands):
		Year Ended December 31,
		2014			2013
	Current income tax benefit (expense)	$	(10	)	$	—
	Deferred income tax benefit (expense)	(547		)	495
	Effective income tax rate	0.6		%	1.6		%

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Future non-cancelable commitments related to certain contractual obligations	Future non-cancelable commitments related to certain contractual obligations as of December 31, 2014, are presented below (in thousands):
			Operating leases and service contracts			Asset Retirement Obligation		Total
	2015		$	3,428		$	—	$	3,428
	2016		2,204			6,884		9,088
	2017		1,421			—		1,421
	2018		1,306			—		1,306
	2019		1,525			—		1,525
	Thereafter		2,945			27,761		30,706
			$	12,829		$	34,645	$	47,474
Total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements	The following table is a reconciliation of the asset retirement obligations (in thousands):
		Year Ended December 31,
		2014			2013
	Beginning asset retirement obligation	$	34,636		$	8,319
	Liabilities assumed	248			25,763
	Expenditures	(1,030		)	—
	Accretion expense	791			554
	Ending asset retirement obligation	$	34,645		$	34,636
	For the years ended December 31, 2014, 2013 and 2012, total expenses related to operating leases, land site leases and right-of-way agreements were $5.8 million, $1.1 million, and $0.9 million, respectively.

Reporting_Segments_Tables

Reporting Segments (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Segment information for the periods	The following tables set forth our segment information for the periods indicated (in thousands):
		Year Ended December 31, 2014
		Gathering			Transmission				Terminals			Total
		and
		Processing
	Revenue	$	203,616		$	88,189			$	15,504		$	307,309
	Gain (loss) on commodity derivatives, net	1,091			—				—			1,091
	Total revenue	204,707			88,189				15,504			308,400
	Operating expenses:
	Purchases of natural gas, NGL's and condensate	152,690			45,262				—			197,952
	Direct operating expenses	23,783			15,577				6,342			45,702
	Selling, general and administrative expenses											23,103
	Equity compensation expense											1,536
	Depreciation, amortization and accretion expense											28,832
	Total operating expenses											297,125
	Gain (loss) on sale of assets, net											(122		)
	Loss on impairment of property, plant and equipment											(99,892		)
	Other expense											(670		)
	Interest expense											(7,577		)
	Earnings in unconsolidated affiliates											348
	Income tax benefit (expense)											(557		)
	Income (loss) from operations of disposal groups, net of tax											(611		)
	Net income (loss)											(97,806		)
	Less: Net income (loss) attributable to noncontrolling interests											214
	Net income (loss) attributable to the Partnership											$	(98,020	)
	Segment gross margin (b)	$	50,817		$	42,828			$	9,162		$	102,807
		Year Ended December 31, 2013
		Gathering			Transmission				Terminals (a)			Total
		and
		Processing
	Revenue	$	205,179		$	79,041			$	9,831		$	294,051
	Gain (loss) on commodity derivatives, net	28			—				—			28
	Total revenue	205,207			79,041				9,831			294,079
	Operating expenses:
	Purchases of natural gas, NGL's and condensate	168,574			46,479				—			215,053
	Direct operating expenses	14,574			13,259				4,403			32,236
	Selling, general and administrative expenses											19,079
	Equity compensation expense											2,094
	Depreciation, amortization and accretion expense											30,002
	Total operating expenses											298,464
	Gain (loss) on involuntary conversion of property, plant and equipment											343
	Loss on impairment of property, plant and equipment											(18,155		)
	Interest expense											(9,291		)
	Income tax benefit (expense)											495
	Income (loss) from operation of disposal groups, net of tax											(2,413		)
	Net income (loss)											(33,406		)
	Less: Net income (loss) attributable to noncontrolling interests											633
	Net income (loss) attributable to the Partnership											$	(34,039	)
	Segment gross margin (b)	$	36,985		$	32,408			$	5,428		$	74,821
		Year Ended December 31, 2012
		Gathering			Transmission				Total
		and
		Processing
	Revenue	$	152,339		$	52,529			$	204,868
	Gain (loss) on commodity derivatives, net	3,400			—				3,400
	Total revenue	155,739			52,529				208,268
	Operating expenses:
	Purchases of natural gas, NGL's and condensate	117,956			36,516				154,472
	Direct operating expenses	12,152			5,031				17,183
	Selling, general and administrative expenses								14,309
	Equity compensation expense								1,783
	Depreciation, amortization and accretion expense								21,287
	Total operating expenses								209,034
	Gain (loss) on involuntary conversion of property, plant and equipment								(1,021		)
Gain (loss) on sale of assets, net								123
Interest expense								(4,570		)
Income (loss) from operations of disposal groups								(18		)
Net income (loss)								(6,252		)
Less: Net income (loss) attributable to noncontrolling interests								256
Net income (loss) attributable to the Partnership								$	(6,508	)
Segment gross margin (b)	$	36,118		$	13,313			$	49,431
	December 31,
	2014		2013
Segment assets:
Gathering and Processing	686,395		178,869
Transmission	132,767		131,136
Terminals	71,180		60,873
Other (c)	26,302		11,197
Total assets	916,644		382,075
(a)	Terminals segment amounts are for the period from April 15, 2013 to December 31, 2013.
(b)	Segment gross margin for our Gathering and Processing segment consists of revenue less purchases of natural gas, NGLs and condensate and COMA. Segment gross margin for our Transmission segment consists of revenue, less purchases of natural gas and COMA. Segment gross margin for our Terminals segment consists of revenue, less direct operating expenses. Gross margin consists of the sum of the segment gross margin amounts for each of these segments. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow from operations as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. Effective October 1, 2012, we changed our segment gross margin measure to exclude construction, operating and maintenance agreement ("COMA") income. Effective January 1, 2011, we changed our segment gross margin measure to exclude unrealized non-cash mark-to-market adjustments related to our commodity derivatives. Effective April 1, 2011, we changed our segment gross margin measure to exclude realized early termination costs on commodity derivatives.
(c)	Other assets not allocable to segments consist of investment in unconsolidated affiliate, corporate leasehold improvements, and other assets.
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."
Percentage of revenue earned from major customers	The following table summarizes the percentage of revenue earned from those customers that exceed 10% of the Partnership's consolidated revenue in the consolidated statement of operations for the each of the years presented below:
		Year Ended December 31,
		2014		2013			2012
	Customer A	22	%	28	%		30	%
	Customer B	—	%	13	%		—	%
	Customer C	12	%	12	%		13	%
	Customer D	10	%	10	%		14	%
	Other	56	%	37	%		43	%
	Total	100	%	100	%		100	%
	The following table summarizes the percentage of revenue earned from those customers in each segment that exceed 10% of the Partnership's consolidated segment's revenue for the each of the periods presented below:
		Year Ended December 31,
		2014		2013			2012
	Gathering and Processing:
	Customer A	33	%	43	%		40	%
	Customer B	12	%	19	%		11	%
	Customer D	—		—	%		12	%
	Other	55	%	38	%		37	%
	Total	100	%	100	%		100	%
	Transmission:
	Customer C	43	%	39	%		50	%
	Customer D	16	%	16	%		22	%
	Customer E	—		—	%		10	%
	Other	41	%	45	%		18	%
	Total	100	%	100	%		100	%
	Terminals:
	Customer F	19	%	20	%		N/A
	Customer B	20	%	17	%		N/A
	Customer G	15	%	16	%		N/A
	Customer H	11	%	13	%		N/A
	Other	35	%	34	%		N/A
	Total	100	%	100	%		—

Quarterly_Financial_Data_Table

Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information [Table Text Block]	Summarized unaudited quarterly financial data for 2014 and 2013 are as follows (in thousands, except per unit amounts):
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter (b)
	Year Ended December 31, 2014
	Total revenues	$	80,238		$	77,680		$	70,305		$	80,177
	Gross margin (a)	23,081			22,167			21,332			36,227
	Operating income (loss)	2,450			734			(290		)	(91,633		)
	Net income (loss) from continuing operations	558			(1,095		)	(2,397		)	(94,261		)
	Income (loss) from operations of disposal groups	(50		)	(506		)	(26		)	(29		)
	Net income (loss) attributable to noncontrolling interest	108			66			33			7
	Net income (loss) attributable to the Partnership	400			(1,667		)	(2,456		)	(94,297		)
	General Partner's Interest in net income (loss)	7			(22		)	(32		)	(1,232		)
	Limited Partners' Interest in net income (loss)	$	393		$	(1,645	)	$	(2,424	)	$	(93,065	)
	Limited Partners' income (loss) per unit:
	Income (loss) from continuing operations	$	(0.31	)	$	(0.55	)	$	(0.58	)	$	(4.98	)
	Income (loss) from discontinued operations	(0.01		)	(0.04		)	—			—
	Net income (loss)	$	(0.32	)	$	(0.59	)	$	(0.58	)	$	(4.98	)
	Year Ended December 31, 2013
	Total revenues	$	62,599		$	77,191		$	77,519		$	76,770
	Gross margin (a)	12,705			18,317			20,908			22,891
	Operating income (loss)	(1,661		)	(17,841		)	(104		)	(2,591		)
	Net income (loss) from continuing operations	(3,392		)	(20,057		)	(2,526		)	(5,018		)
	Income (loss) from operations of disposal groups	(6		)	(1,869		)	(15		)	(523		)
	Net income (loss) attributable to noncontrolling interest	155			188			190			100
	Net income (loss) attributable to the Partnership	(3,553		)	(22,114		)	(2,731		)	(5,641		)
	General Partner's Interest in net income (loss)	(70		)	(905		)	(221		)	(209		)
	Limited Partners' Interest in net income (loss)	$	(3,482	)	$	(21,209	)	$	(2,510	)	$	(5,433	)
	Limited Partners' income (loss) per unit:
	Income (loss) from continuing operations	$	(0.39	)	$	(4.01	)	$	(0.81	)	$	(1.43	)
	Income (loss) from discontinued operations	0.01			(0.20		)	0.01			—
	Net income (loss)	$	(0.38	)	$	(4.21	)	$	(0.80	)	$	(1.43	)
	(a)	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."
	(b)	The Partnership record an immaterial out-of-period adjustment in the fourth quarter of 2014 to account for the items associated with the material weakness described in Item 9A.  Management’s Annual Report over Internal Control over Financial Reporting.

Organization_and_Basis_of_Pres2

Organization and Basis of Presentation (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Jul. 02, 2012	Sep. 30, 2014
	mi
	billion_cubic_feet_per_day
	bbl
	pipeline
	gathering_system
	facility
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
General Partners' Capital Account, Percentage	95.00%
Limited Partners' Capital Account, Percentage	5.00%
Number of Gathering Systems	12
Number of Processing Facilities	5
Number of Fractionation Facilities	3
Number of Marine Terminal Sites	4
Number of Interstate Pipelines	3
Number of Intrastate Pipelines	5
Gathering pipeline (miles)	3,000
Volume of Natural Gas, Operating	1
Million barrels of storage capacity	1,700,000
Useful life	25 years
Noncontrolling interest, ownership percentage by noncontrolling owners	12.60%	7.80%
Burns Point Plant [Member]
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
Acquired interest (percent)		50.00%
Chatom processing, gathering and fractionation plant [Member]
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
Acquired interest (percent)		4.80%	87.40%
Minimum [Member]
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
Useful life	0 years 5 months 0 days
Maximum [Member]
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
Useful life	30 years
Equity Method Investments [Member]
Collaborative Arrangements and Non-collaborative Arrangement Transactions [Line Items]
Ownership percentage	66.70%			66.70%

Acquisitions_Consideration_Tra

Acquisitions (Consideration Transferred) (Details) (USD $)	12 Months Ended	0 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Oct. 14, 2014
Business Acquisition [Line Items]
Useful life	25 years
Costar Midstream, L.L.C. [Member]
Business Acquisition [Line Items]
Cash		$265,383
Limited partner common units		147,296
Total fair value of consideration		$412,679

Acquisitions_Fair_Value_of_Ide

Acquisitions Fair Value of Identifiable Assets and Consideration Transferred (Details) (USD $)	0 Months Ended
In Thousands, unless otherwise specified	Oct. 14, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 02, 2012	Apr. 15, 2013
Business Acquisition [Line Items]
Goodwill		$142,236	$16,447
Property, plant and equipment		582,182	312,701
Asset retirement cost		34,645	34,636	8,319
Accounts payable		20,326	3,261
Accrued gas purchases		14,326	17,386
Chatom processing, gathering and fractionation plant [Member]
Business Acquisition [Line Items]
Total cash consideration					51,377
Cash					51,377
Unbilled revenue					4,535
Property, plant and equipment					58,279
Asset retirement cost					452
Accounts payable					399
Accrued gas purchases					3,631
Asset retirement obligations					452
Noncontrolling interest					-7,407
Costar Midstream, L.L.C. [Member]
Business Acquisition [Line Items]
Working capital	8,152
Processing plants	48,357
Pipelines	128,799
Land	1,244
Buildings	682
Equipment	9,827
Construction in progress	16,146
Total property, plant and equipment	205,055
Investment in unconsolidated affiliate	11,884
Customer relationships	53,400
Dedicated acreage	32,000
Noncontrolling interest	219
Goodwill	102,407
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest	412,679
Cash	265,383
Lavaca [Member]
Business Acquisition [Line Items]
Land		2
Equipment		753
Total property, plant and equipment		59,492
Goodwill	23,567
Intangible assets		21,350
Cash	104,409
High Point [Member]
Business Acquisition [Line Items]
Cash and cash equivalents						1,935
Accounts receivable						3,629
Unbilled revenue						1,446
Other current assets						2,049
Property, plant and equipment, net						82,615
Other assets						1,000
Accounts payable						11
Accrued expenses and other current liabilities						4,077
Current portion of long-term debt						893
Asset retirement obligation liability						25,763
Total identifiable net assets						61,930
Pipelines [Member] | Lavaca [Member]
Business Acquisition [Line Items]
Total property, plant and equipment		$58,737

Acquisitions_Pro_Forma_Informa

Acquisitions (Pro Forma Information) (Details) (Costar Midstream, L.L.C. [Member], USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Costar Midstream, L.L.C. [Member]
Business Acquisition [Line Items]
Revenue	$435,133	$448,748
Net loss	($101,237)	($30,672)
Limited partners' net loss per unit	($6.15)	($3.82)

Acquisitions_Narrative_Details

Acquisitions Narrative (Details) (USD $)	0 Months Ended	3 Months Ended								12 Months Ended			0 Months Ended	3 Months Ended	0 Months Ended	9 Months Ended	0 Months Ended		3 Months Ended
	Jan. 29, 2014	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 14, 2014	Dec. 31, 2014	Jan. 31, 2014	Sep. 30, 2014	Apr. 15, 2013	Dec. 17, 2013	Apr. 15, 2013	Aug. 20, 2014	Dec. 11, 2013	Jul. 02, 2012
		bbl								mi					mi
										bbl
Business Acquisition [Line Items]
Proceeds from sale of property, plant, and equipment										$6,323,000	$500,000	$128,000
Noncontrolling interest, ownership percentage by noncontrolling owners		12.60%				7.80%				12.60%	7.80%			12.60%
Noncontrolling Interest, Ownership Percentage by Parent		92.20%								92.20%				92.20%
Partners' Capital Account, Distributions to Existing Interest										0	15,612,000	0
Discount rate		9.50%								10.00%	10.00%
Revenues		80,177,000	70,305,000	77,680,000	80,238,000	76,770,000	77,519,000	77,191,000	62,599,000	308,400,000	294,079,000	208,268,000
Net income (loss)		-94,297,000	-2,456,000	-1,667,000	400,000	-5,641,000	-2,731,000	-22,114,000	-3,553,000	-98,020,000	-34,039,000	-6,508,000
Operating Income (Loss)		-91,633,000	-290,000	734,000	2,450,000	-2,591,000	-104,000	-17,841,000	-1,661,000	-88,739,000	-22,197,000	-1,664,000
Length Of Pipeline										3,000
Issuance of common units, net of offering costs	86,900,000	119,300,000								204,255,000	54,853,000	0
Limited partners, units issued	3,400,000	22,670,000				7,414,000				22,670,000	7,414,000			22,670,000						4,622,352	2,568,712
Useful life										25 years
Finite-lived intangible assets, amortization expense, next twelve months		5,300,000								5,300,000				5,300,000
Payments to acquire equity method investments										12,000,000	0	0
Earnings in unconsolidated affiliates										348,000	0	0
Proceeds from equity method investement, return of capital			2,000,000							1,632,000	0	0
Million barrels of storage capacity		1,700,000								1,700,000				1,700,000
Distributions										28,009,000	16,120,000	16,070,000
Payments on long-term debt										250,870,000	131,571,000	59,230,000
Series A convertible preferred units		107,965,000				94,811,000				107,965,000	94,811,000			107,965,000			90,000,000		90,000,000
Fair value, paid in kind distributions										$19.67
Distribution made to member or limited partner, payment In kind declared										13,200,000
Fair value input, option value										3.32
Business Acquisition Fair Value Measurement Composition, Assumed Cost of Capital											9.25%
Business Acquisition Fair Value Measurement Composition, Inflationary Cost											2.50%
Effective income tax rate, continuing operations											35.00%
Effective income tax rate reconciliation, state and local income taxes, percent											6.50%
Loss on impairment of property, plant and equipment		99,900,000				3,000,000		15,200,000	100,000	99,892,000	18,155,000	0
Property plant and equipment gross		698,017,000				407,800,000				698,017,000	407,800,000			698,017,000
Series B
Business Acquisition [Line Items]
Issuance of common units, net of offering costs										-30,000,000	0	0
Limited partners, units issued															1,168,225
Distributions										2,220,000	0	0
Chatom processing, gathering and fractionation plant [Member]
Business Acquisition [Line Items]
Acquired interest (percent)						4.80%					4.80%											87.40%
Revenues												25,400,000
Operating Income (Loss)												1,800,000
Total Consideration																						51,377,000
Chatom Assets location											15
Refrigeration processing plant											25
Fractation unit											1,900
Long-ton per day sulfur recovery											160
Gas gathering system											24
Percent of outstanding noncontrolling interest acquired																						38.00%
Costar Midstream, L.L.C. [Member]
Business Acquisition [Line Items]
Acquired interest (percent)													100.00%
Cash													265,383,000
Equity interests issued (in units)													6,900,000
Limited partner common units													147,296,000
Working capital, accounts receivable													11,200,000
Revenues														19,900,000
Operating Income (Loss)														300,000
Transaction costs		500,000								500,000				500,000
Total fair value of consideration													412,679,000
Lavaca [Member]
Business Acquisition [Line Items]
Preliminary purchase price allocation adjustment		23,600,000								23,600,000				23,600,000
Finite Lived Intangible Assets Accumulated Amortization Adjustment																500,000
Cash													104,409,000
Discount rate										10.50%
Revenues										16,800,000
Operating Income (Loss)										7,600,000
Transaction costs		100,000								100,000				100,000
Length Of Pipeline															100
High Point [Member]
Business Acquisition [Line Items]
Acquired interest (percent)																	100.00%		100.00%
Total identifiable net assets																	61,930,000		61,930,000
Revenues							30,400,000
Net income (loss)							7,200,000
Length Of Pipeline										700
Total Consideration for Issuance of Preferred Units																	15,000,000		15,000,000
Williams [Member]
Business Acquisition [Line Items]
Total Consideration						6,500,000					6,500,000
Minimum [Member]
Business Acquisition [Line Items]
Useful life										0 years 5 months 0 days
Minimum [Member] | Costar Midstream, L.L.C. [Member]
Business Acquisition [Line Items]
Discount rate													11.00%
Maximum [Member]
Business Acquisition [Line Items]
Useful life										30 years
Maximum [Member] | Costar Midstream, L.L.C. [Member]
Business Acquisition [Line Items]
Discount rate													16.00%
Total Partners Capital
Business Acquisition [Line Items]
Partners' Capital Account, Distributions to Existing Interest											15,612,000						-15,600,000
Net income (loss)										-98,020,000	-34,039,000	-6,508,000
Issuance of common units, net of offering costs											54,853,000
Distributions										42,063,000	22,251,000	16,070,000
Total Partners Capital | Series B
Business Acquisition [Line Items]
Issuance of Series B Units										32,220,000
Series B
Business Acquisition [Line Items]
Issuance of common units, net of offering costs										0
Series B | Series B
Business Acquisition [Line Items]
Issuance of Series B Units										32,220,000					30,000,000
Equity Method Investments [Member]
Business Acquisition [Line Items]
Ownership percentage		66.70%	66.70%							66.70%				66.70%		66.70%
Payments to acquire equity method investments																12,000,000
Terminals [Member]
Business Acquisition [Line Items]
Revenues							9,800,000			15,504,000
Operating Income (Loss)							800,000
Million barrels of storage capacity																		1,300,000
ArcLight [Member] | High Point [Member]
Business Acquisition [Line Items]
Number of natural gas collection receipt points										75
Blackwater [Member]
Business Acquisition [Line Items]
Limited partner common units											3,100,000
Total identifiable net assets																	22,700,000		22,700,000
Total fair value of consideration																		63,900,000
Distributions										0	27,650,000	0
Units issued in business acquisition																		125,500
Series A
Business Acquisition [Line Items]
Discount rate																	18.00%
Distribution made to member or limited partner, distributions paid, conversion price per unit																	$17.50
Distribution growth rate										1.00%
Issuance of Preferred Units [Member] | High Point [Member] | Series A
Business Acquisition [Line Items]
Contributed capital																	5,142,857		5,142,857
Transaction expenses																			2,500,000
Revolving Credit Facility [Member] | Fourth Amendment [Member] | Series A
Business Acquisition [Line Items]
Payments on long-term debt																	12,500,000
AIM Midstream Holdings [Member] | High Point [Member] | Partnership Interest [Member]
Business Acquisition [Line Items]
Partnership cancellation of subordinated units (percent)																	90.00%
Madison [Member]
Business Acquisition [Line Items]
Proceeds from sale of property, plant, and equipment			6,100,000
Loss on impairment of property, plant and equipment											3,000,000
Property plant and equipment gross						$6,100,000					$6,100,000

Discontinued_Operations_Detail

Discontinued Operations (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Revenue									$474,000	$2,084,000	$2,318,000
Disposal Group, Including Discontinued Operation, Operating Expense									-658,000	-2,361,000	-2,336,000
Disposal Group, Including Discontinued Operation, Impairment									-673,000	-2,400,000	0
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax									-87,000	-75,000	0
Discontinued Operation, Tax Effect of Discontinued Operation									333,000	339,000	0
Current liabilities held for sale	12,000				114,000				12,000	114,000
Loss on impairment of noncurrent assets held for sale		700,000							673,000	2,400,000	0
Discount rate	9.50%								10.00%	10.00%
Current assets held for sale	52,000				272,000				52,000	272,000
Gain (loss) from operations of disposal groups, net of tax	-29,000	-26,000	-506,000	-50,000	-523,000	-15,000	-1,869,000	-6,000	-611,000	-2,413,000	-18,000
Limited partners' net income (loss) from discontinued operations per unit (basic and diluted)	$0	$0	($0.04)	($0.01)	$0	$0.01	($0.20)	$0.01	($0.04)	($0.27)	$0
Blackwater [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Noncurrent assets held for sale, net					1,200,000					1,200,000
Current liabilities held for sale					100,000					100,000
Current assets held for sale					100,000					100,000
Gathering And Processing [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on impairment of noncurrent assets held for sale									600,000	1,800,000
Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on impairment of noncurrent assets held for sale		$400,000

Concentration_of_Credit_Risk_a2

Concentration of Credit Risk and Trade Accounts Receivable (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue, Major Customer
Entity-wide revenue by major customer, percentage	100.00%	100.00%	100.00%
Customer A [Member]
Revenue, Major Customer
Entity-wide revenue by major customer, percentage	22.00%	28.00%	30.00%
Customer B [Member]
Revenue, Major Customer
Entity-wide revenue by major customer, percentage	0.00%	13.00%	0.00%
Cusotmer C [Member]
Revenue, Major Customer
Entity-wide revenue by major customer, percentage	12.00%	12.00%	13.00%
Customer D [Member]
Revenue, Major Customer
Entity-wide revenue by major customer, percentage	10.00%	10.00%	14.00%
Customer Other [Member]
Revenue, Major Customer
Entity-wide revenue by major customer, percentage	56.00%	37.00%	43.00%

Other_Current_Assets_Details

Other Current Assets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Other Current Assets [Abstract]
Prepaid insurance	$4,162	$3,166
Restricted cash	6,475	0
Other current assets	4,865	4,331
Other current assets	$15,502	$7,497

Derivatives_Fair_Value_of_Comm

Derivatives (Fair Value of Commodity Derivatives) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Risk management assets and Risk management liabilities
Derivative Asset, Fair Value, Net	$688	$473
Derivative Liability, Fair Value, Net	-215	-524
Commodity derivatives [Member]
Risk management assets and Risk management liabilities
Derivative asset, gross derivative asset	688	473
Derivative asset, gross derivative liabilities	0	0
Derivative liability, gross derivative assets	0	27
Derivative liability, gross derivative liabilities	-215	-551
Commodity derivatives [Member] | Risk Management Assets [Member]
Risk management assets and Risk management liabilities
Derivative asset, gross derivative asset	688	473
Derivative asset, gross derivative liabilities	0	0
Derivative Asset, Fair Value, Net	688	473
Commodity derivatives [Member] | Risk Management Assets - Long Term [Member]
Risk management assets and Risk management liabilities
Derivative asset, gross derivative asset	0	0
Derivative asset, gross derivative liabilities	0	0
Derivative Asset, Fair Value, Net	0	0
Commodity derivatives [Member] | Risk Management Liabilities [Member]
Risk management assets and Risk management liabilities
Derivative liability, gross derivative assets	0	27
Derivative liability, gross derivative liabilities	-215	-450
Derivative Liability, Fair Value, Net	-215	-423
Commodity derivatives [Member] | Risk Management Liabilities - Long Term [Member]
Risk management assets and Risk management liabilities
Derivative liability, gross derivative assets	0	0
Derivative liability, gross derivative liabilities	0	-101
Derivative Liability, Fair Value, Net	$0	($101)

Derivatives_Realized_and_Unrea

Derivatives (Realized and Unrealized Gains (Losses)) (Details) (Commodity derivatives [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Gain (loss) on derivatives, realized	($733)	$200	$2,408
Gain (loss) on derivatives, unrealized	595	-1,495	992
Gain (Loss) on Derivative Instruments [Member]
Derivatives, Fair Value [Line Items]
Gain (loss) on derivatives, realized	735	1,069	2,408
Gain (loss) on derivatives, unrealized	356	-1,041	992
Interest Expense [Member]
Derivatives, Fair Value [Line Items]
Gain (loss) on derivatives, realized	-433	-207
Gain (loss) on derivatives, unrealized	239	-454
Other Income [Member]
Derivatives, Fair Value [Line Items]
Gain (loss) on derivatives, realized	-1,035	-662
Gain (loss) on derivatives, unrealized	$0	$0

Derivatives_Details_Textual

Derivatives (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	gal
Derivative [Line Items]
Aggregate notional volume of our commodity derivative	500,000
Amortization of weather derivative premium	$1,035,000	$662,000	$0
Interest Rate Swap [Member]
Derivative [Line Items]
Notional amount of interest rate derivatives	100,000,000
Weather Contract [Member]
Derivative [Line Items]
Derivative instruments not designated as hedging instruments, potential cash proceeds from Contract		10,000,000
Derivative instruments not designated as hedging instruments, asset, at fair value	0
Payments of derivative issuance costs	1,000,000	1,100,000
Term of Contract	1 year 0 months 0 days
Amortization of weather derivative premium	$400,000	$500,000

Fair_Value_Measurement_Fair_Va

Fair Value Measurement (Fair Value of Financial Instruments) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Commodity Contract [Member]
Quantitative Information about Level 3 Fair Value Measurements
Estimated Fair Value	$286	($70)
Commodity Contract [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Quantitative Information about Level 3 Fair Value Measurements
Estimated Fair Value	286	-70
Commodity Contract [Member] | Level 1 [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Quantitative Information about Level 3 Fair Value Measurements
Estimated Fair Value	0	0
Commodity Contract [Member] | Level 2 [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Quantitative Information about Level 3 Fair Value Measurements
Estimated Fair Value	286	-70
Commodity Contract [Member] | Level 3 [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Quantitative Information about Level 3 Fair Value Measurements
Estimated Fair Value	0	0
Interest Rate Swap [Member]
Quantitative Information about Level 3 Fair Value Measurements
Estimated Fair Value	-215	-454
Interest Rate Swap [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Quantitative Information about Level 3 Fair Value Measurements
Estimated Fair Value	-215	-454
Interest Rate Swap [Member] | Level 1 [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Quantitative Information about Level 3 Fair Value Measurements
Estimated Fair Value	0	0
Interest Rate Swap [Member] | Level 2 [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Quantitative Information about Level 3 Fair Value Measurements
Estimated Fair Value	-215	-454
Interest Rate Swap [Member] | Level 3 [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Quantitative Information about Level 3 Fair Value Measurements
Estimated Fair Value	$0	$0

Fair_Value_Measurement_Details

Fair Value Measurement (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Fair Value Disclosures [Abstract]
Transfers out of Level 3	$0	$0

Property_Plant_and_Equipment_N2

Property, Plant and Equipment, Net (Details) (USD $)	3 Months Ended	12 Months Ended			3 Months Ended
	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Insurance settlements receivable			$1,100,000
Loss on impairment of noncurrent assets held for sale	700,000	673,000	2,400,000	0
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross		698,017,000	407,800,000		698,017,000
Accumulated depreciation		-115,835,000	-95,099,000		-115,835,000
Property, plant and equipment, net		582,182,000	312,701,000		582,182,000
Interest Costs Capitalized		800,000	200,000
Depreciation		23,900,000	25,900,000
Land [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross		5,282,000	6,015,000		5,282,000
Construction in progress [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross		77,551,000	6,443,000		77,551,000
Base Gas [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross		1,108,000	1,108,000		1,108,000
Buildings and improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross		6,905,000	5,109,000		6,905,000
Processing and treating plants [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross		80,141,000	97,106,000		80,141,000
Pipelines [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross		452,180,000	239,865,000		452,180,000
Compressors [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross		24,227,000	11,955,000		24,227,000
Dock [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross		8,072,000	7,942,000		8,072,000
Tanks, truck rack and piping [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross		30,079,000	22,432,000		30,079,000
Equipment [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross		8,952,000	6,294,000		8,952,000
Computer software [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross		3,520,000	3,531,000		3,520,000
Minimum [Member] | Buildings and improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					4 years
Minimum [Member] | Processing and treating plants [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					8 years
Minimum [Member] | Pipelines [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					5 years
Minimum [Member] | Compressors [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					4 years
Minimum [Member] | Dock [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					20 years
Minimum [Member] | Tanks, truck rack and piping [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					20 years
Minimum [Member] | Equipment [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					8 years
Maximum [Member] | Buildings and improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					40 years
Maximum [Member] | Processing and treating plants [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					40 years
Maximum [Member] | Pipelines [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					40 years
Maximum [Member] | Compressors [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					20 years
Maximum [Member] | Dock [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					40 years
Maximum [Member] | Tanks, truck rack and piping [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					40 years
Maximum [Member] | Equipment [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					20 years
Maximum [Member] | Computer software [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment in useful life					5 years
Ala Tenn System [Member]
Property, Plant and Equipment, Net [Abstract]
Property plant and equipment gross		101,900,000	100,500,000		101,900,000
Gathering And Processing [Member]
Property, Plant and Equipment [Line Items]
Loss on impairment of noncurrent assets held for sale		$600,000	$1,800,000

Property_Plant_and_Equipment_N3

Property, Plant and Equipment, Net (Asset Impairments and Insurance Proceeds) (Details) (USD $)	3 Months Ended					12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Loss on impairment of property, plant and equipment	$99,900,000		$3,000,000	$15,200,000	$100,000	$99,892,000	$18,155,000	$0
Discount rate	9.50%					10.00%	10.00%
Impairment of long lived assets		700,000				673,000	2,400,000	0
Insurance settlements receivable							1,100,000
Insurance proceeds from involuntary conversion of property, plant and equipment				600,000	500,000	0	482,000	527,000
Gain (loss) on involuntary conversion of property, plant and equipment					400,000	0	343,000	-1,021,000
Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member]
Property, Plant and Equipment [Line Items]
Throughput volume decline rate							2.50%
Discontinued Operations [Member]
Property, Plant and Equipment [Line Items]
Impairment of long lived assets		400,000
Gathering And Processing [Member]
Property, Plant and Equipment [Line Items]
Impairment of long lived assets						$600,000	$1,800,000

Goodwill_and_Intangible_assets2

Goodwill and Intangible assets (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Goodwill [Line Items]
Goodwill	$142,236,000	$16,447,000
Useful life	25 years
Amortization of Intangible Assets	4,100,000	3,700,000
Finite-lived intangible assets, amortization expense, next twelve months	5,300,000
Finite-Lived Intangible Assets, Amortization Expense, Year Two	4,300,000
Finite-Lived Intangible Assets, Amortization Expense, Year Three	4,300,000
Finite-Lived Intangible Assets, Amortization Expense, Year Four	4,300,000
Finite-Lived Intangible Assets, Amortization Expense, Year Five	4,300,000
Gathering And Processing [Member]
Goodwill [Line Items]
Goodwill	125,900,000
Terminals [Member]
Goodwill [Line Items]
Goodwill	$16,300,000
Minimum [Member]
Goodwill [Line Items]
Useful life	0 years 5 months 0 days
Maximum [Member]
Goodwill [Line Items]
Useful life	30 years

Goodwill_and_Intangible_assets3

Goodwill and Intangible assets Schedule of intangible assets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	$118,851	$12,101
Accumulated amortization	-12,545	-8,419
Net carrying amount	106,306	3,682
Customer Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	12,101	12,101
Accumulated amortization	-11,110	-8,419
Net carrying amount	991	3,682
Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	53,400	0
Accumulated amortization	-553	0
Net carrying amount	52,847	0
Dedicated Acreage [Member]
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	53,350	0
Accumulated amortization	-882	0
Net carrying amount	$52,468	$0

Accrued_Expenses_and_Other_Cur2

Accrued Expenses and Other Current Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Payables and Accruals [Abstract]
Accrued capital expenditures	$17,134	$2,562
Accrued expenses	7,036	5,412
Gas imbalances payable	1,069	4,305
Other	549	2,779
Accrued expenses and other current liabilities	$25,788	$15,058

Asset_Retirement_Obligation_De

Asset Retirement Obligation (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Restricted Cash and Cash Equivalents	$5,000,000	$3,000,000
Balance at beginning of period	34,636,000	8,319,000
Additions	248,000	25,763,000
Expenditures	-1,030,000	0
Accretion expense	791,000	554,000
Balance at end of period	$34,645,000	$34,636,000

Debt_Obligations_Outstanding_B

Debt Obligations (Outstanding Borrowings) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Disclosure [Abstract]
Revolving credit facility	$372,950	$130,735
Other debt	2,908	2,048
Total debt	375,858	132,783
Less: current portion	2,908	2,048
Long-term debt	$372,950	$130,735

Debt_Obligations_Textual_Detai

Debt Obligations (Textual) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Line of credit facility, amount outstanding limit	$500,000,000
Unused capacity, commitment fee percentage	0.50%
Ratio of indebtedness to net capital	4.44
Interest coverage ratio	13.4
Debt, weighted average interest rate	3.80%	4.53%	4.09%
Letters of credit outstanding amount	1,600,000	4,800,000
Revolving credit facility	372,950,000	130,735,000
Proceeds from (payments for) other financing activities	3,300,000
Periodic payment	400,000
Debt issuance cost	10,400,000
Gains on extinguishment of debt	$700,000
Minimum [Member]
Debt Instrument [Line Items]
Interest coverage ratio	2.5
Maximum [Member]
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 [Member]
Debt Instrument [Line Items]
Facility fee (percent)	0.50%
Eurodollar [Member]
Debt Instrument [Line Items]
Facility fee (percent)	1.00%
Insurance Premium Financing [Member]
Debt Instrument [Line Items]
Facility fee (percent)	3.95%
Fiscal Quarter Ending December 31, 2014 [Member] | Fourth Amendment [Member] | Base Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate	2.00%
Fiscal Quarter Ending December 31, 2014 [Member] | Fourth Amendment [Member] | Base Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate	3.25%
Fiscal Quarter Ending December 31, 2014 [Member] | Fourth Amendment [Member] | Eurodollar [Member] | Minimum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate	1.00%
Fiscal Quarter Ending December 31, 2014 [Member] | Fourth Amendment [Member] | Eurodollar [Member] | Maximum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate	2.25%

Partners_Capital_Units_Outstan

Partners' Capital (Units Outstanding) (Details)	Dec. 31, 2014	Dec. 31, 2013	Aug. 09, 2013	Dec. 31, 2012
Limited partner common units	22,670,000	7,414,000
General partner units	392,000	185,000
AIM Midstream Holdings No. of units outstanding [Member]
Preferred units outstanding				0
Limited partner common units	22,670,000	7,414,000		4,639,000
Limited partner subordinated units	0	0	4,526,066	4,526,000
General partner units	392,000	185,000		185,000
Series A
Preferred units outstanding	5,745,000	5,279,000
Series B
Preferred units outstanding	1,255,000	0		0

Partners_Capital_Details_Textu

Partners Capital (Details Textual) (USD $)	0 Months Ended	3 Months Ended		12 Months Ended			0 Months Ended	3 Months Ended		0 Months Ended
	Jan. 29, 2014	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 15, 2013	Apr. 15, 2013	Sep. 30, 2014	Oct. 14, 2014	Aug. 20, 2014	Feb. 05, 2014	Dec. 11, 2013	Aug. 09, 2013	Jan. 31, 2014
Subsidiary, Sale of Stock [Line Items]
General partner interest				1.30%
Limited partner interest				98.70%
Limited partners, units issued	3,400,000	22,670,000		22,670,000	7,414,000						4,622,352		2,568,712
Payments on long-term debt				($250,870,000)	($131,571,000)	($59,230,000)
Fair value, paid in kind distributions		3,200,000
Class of Warrant or Right, Number of Securities Called by Warrants or Rights												300,000
Class of Warrant or Right, Exercise Price of Warrants or Rights												$0.01
Sale of Stock, Price Per Share	$26.75	$22.47		$22.47							$25.81
Distribution declared per common unit (a)			$0.46	$1.85	$1.75	$1.73
Issuance of common units, net of offering costs	86,900,000	119,300,000		204,255,000	54,853,000	0
General partners' interest units issued		392,000		392,000	185,000
Series B
Subsidiary, Sale of Stock [Line Items]
Issuance of common units, net of offering costs				0
Partners' Capital Account, Contributions				0
General Partner Interest
Subsidiary, Sale of Stock [Line Items]
Issuance of common units, net of offering costs				0
Partners' Capital Account, Contributions				5,678,000	12,500,000	13,000
General partners' interest units issued		206,810		206,810
General Partner [Member]
Subsidiary, Sale of Stock [Line Items]
Incentive Distribution, Distribution Per Unit				$0.41
Incentive Distribution Right Allocation				14.98%
Incentive Distribution Right, After Minimum Quarterly Distributions, Percent				48.00%
AIM Midstream Holdings [Member]
Subsidiary, Sale of Stock [Line Items]
Partners' Capital Account, Percentage												5.00%
High Point [Member]
Subsidiary, Sale of Stock [Line Items]
Partners' Capital Account, Percentage												95.00%
Series A
Subsidiary, Sale of Stock [Line Items]
Distribution made to member or limited partner, distributions paid, conversion price per unit							$17.50
Series A | Cash Distribution [Member]
Subsidiary, Sale of Stock [Line Items]
Earned and paid (usd per unit)							$0.25
Issuance of Preferred Units [Member] | Series A | High Point [Member]
Subsidiary, Sale of Stock [Line Items]
Contributed capital							5,142,857	5,142,857
Transaction expenses								2,500,000
Partnership Interest [Member]
Subsidiary, Sale of Stock [Line Items]
Other Ownership Interests, Units Outstanding		0		0	0	4,526,000								4,526,066
Partnership Interest [Member] | High Point [Member] | AIM Midstream Holdings [Member]
Subsidiary, Sale of Stock [Line Items]
Partnership cancellation of subordinated units (percent)							90.00%
High Point [Member]
Subsidiary, Sale of Stock [Line Items]
Incentive Distribution Right Allocation		100.00%		85.02%	85.02%				100.00%
Costar Midstream, L.L.C. [Member]
Subsidiary, Sale of Stock [Line Items]
Limited partner common units										147,296,000
High Point [Member]
Subsidiary, Sale of Stock [Line Items]
Total Consideration for Issuance of Preferred Units							15,000,000	15,000,000
Fourth Amendment [Member] | Revolving Credit Facility [Member] | Series A
Subsidiary, Sale of Stock [Line Items]
Payments on long-term debt							-12,500,000
Series A
Subsidiary, Sale of Stock [Line Items]
Accrued Paid in Kind		3,200,000		3,200,000
Payment in Kind, Units Issued				555,000
Series B
Subsidiary, Sale of Stock [Line Items]
Limited partners, units issued															1,168,225
Issuance of common units, net of offering costs				-30,000,000	0	0
Payment in Kind, Units Issued				86,000
Series B | Series B
Subsidiary, Sale of Stock [Line Items]
Partners' Capital Account, Private Placement of Units				2,200,000
Dividend Paid [Member] | Series B
Subsidiary, Sale of Stock [Line Items]
Limited partners, units issued		86,461		86,461
Limited Partner [Member] | Costar Midstream, L.L.C. [Member]
Subsidiary, Sale of Stock [Line Items]
Limited partner common units										$6,900,000

Partners_Capital_Cash_Distribu

Partners' Capital Cash Distributions (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Class of Stock [Line Items]
Distributions	$28,009	$16,120	$16,070
Preferred Partner [Member] | Series A
Class of Stock [Line Items]
Distributions	2,658	2,375	0
Limited Partner [Member]
Class of Stock [Line Items]
Distributions	22,656	8,207	7,919
Limited Party, Subordinated [Member]
Class of Stock [Line Items]
Distributions	0	5,073	7,830
General Partner [Member]
Class of Stock [Line Items]
Distributions	333	284	321
General Partner, Incentive Distribution Rights [Member]
Class of Stock [Line Items]
Distributions	$2,362	$181	$0

Earnings_per_Unit_Details

Earnings per Unit (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss) from continuing operations	($94,261)	($2,397)	($1,095)	$558	($5,018)	($2,526)	($20,057)	($3,392)	($97,195)	($30,993)	($6,234)
Net Income (loss) attributable to noncontrolling interests									214	633	256
Net income (loss) from continuing operations attributable to the Partnership									-97,409	-31,626	-6,490
Distributions on Series A preferred units									14,492	24,117	0
Distributions									28,009	16,120	16,070
General partner's share in undistributed loss									-1,820	-1,708	-458
Net income (loss) from continuing operations available to limited partners									-114,995	-53,783	-6,354
Net income (loss) from discontinued operations available to limited partners									-603	-2,051	-18
Net income (loss) available to limited partners									-115,598	-55,834	-6,372
Weighted average number of units used in computation of limited partners' net income (loss) per unit (basic and diluted)									13,472	7,525	9,113
Limited partners' net income (loss) from continuing operations per unit (basic and diluted)	($4.98)	($0.58)	($0.55)	($0.31)	($1.43)	($0.81)	($4.01)	($0.39)	($8.54)	($7.15)	($0.70)
Limited partners' net income (loss) from discontinued operations per unit (basic and diluted)	$0	$0	($0.04)	($0.01)	$0	$0.01	($0.20)	$0.01	($0.04)	($0.27)	$0
Limited partners’ net income (loss) per unit (basic and diluted)	($4.98)	($0.58)	($0.59)	($0.32)	($1.43)	($0.80)	($4.21)	($0.38)	($8.58)	($7.42)	($0.70)
Series B
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Distributions									2,220	0	0
Blackwater [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss) from continuing operations									0	-716	0
General Partner [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Distributions									2,913	623	322
General Partner [Member] | Dividend Declared [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Distributions									$2,694	$464	$322

LongTerm_Incentive_Plan_Unitba

Long-Term Incentive Plan (Unit-based Awards) (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding
Outstanding at beginning of period	75,529
Granted	188,946
Forfeited	-12,009
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	-51,334
Outstanding at end of period	201,132
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price	$20.80
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$18.28
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price	$20.89
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$19.73	$17.62

Long_Term_Incentive_Plan_Textu

Long Term Incentive Plan (Textual) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 11, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity compensation expense	$1,536,000	$2,094,000	$1,783,000
Long-term incentive plan, increase in available awards				871,750
Long term incentive plan available for future grant	688,976	855,089	920,193
Grants issued under long term incentive plan	25.00%
Total fair value of vested units	1,400,000	2,200,000	1,900,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$3,100,000	$900,000	$1,400,000
Weighted average period cost recognized	3 years 0 months

PostEmployment_Benefits_Change

Post-Employment Benefits (Changes in Benefit Obligation) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Change in plan assets
Funded status	$1,029	$996
Defined Benefit Plan, Plan Amendments	0	126
Change in Benefit Obligation [Member]
Change in benefit obligation
Obligation, beginning of period	532	472
Service cost	2	5
Interest cost	24	15
Actuarial (gain) loss	122	-29
Benefits paid	-25	-57
Benefit obligationm, ending	655	532
Change in plan assets
Benefits paid	-25	-57
Change in Plan Assets [Member]
Change in benefit obligation
Benefits paid	-38	-61
Change in plan assets
Fair value of plan assets, beginning of period	1,528	1,552
Actual return on plan assets	104	-53
Employer's contributions	90	90
Benefits paid	-38	-61
Fair value of plan assets, ending	$1,684	$1,528

PostEmployment_Benefits_Plan_A

Post-Employment Benefits (Plan Assets Recognized) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Amortization of Net Gains (Losses)	$0	($100)	($100)
OPEB Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Amortization of Net Gains (Losses)	$5	$23	$43

PostEmployment_Benefits_Net_Pe

Post-Employment Benefits (Net Periodic Benefit Cost) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	$100,000
Cost recognized in Consolidated Statements of Operations
Defined Benefit Plan, Amortization of Net Gains (Losses)	0	100,000	100,000
Net periodic (benefit) cost	-45,000	-73,000	-88,000
OPEB Plan [Member]
Cost recognized in Consolidated Statements of Operations
Service cost	2,000	5,000	4,000
Interest cost	24,000	15,000	18,000
Expected return on plan assets	-70,000	-70,000	-67,000
Amortization of prior service cost	4,000	0	0
Defined Benefit Plan, Amortization of Net Gains (Losses)	-5,000	-23,000	-43,000
Net periodic (benefit) cost	-45,000	-73,000	-88,000
Net loss (gain)	102,000	247,000	64,000
Total recognized in other comprehensive income	102,000	247,000	64,000
Total recognized in net periodic benefit cost and other comprehensive income	$57,000	$174,000	($24,000)

PostEmployment_Benefits_Econom

Post-Employment Benefits (Economic Assumptions) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Effect of one percentage point increase in assumed medical and dental care trend	$0.10
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	3.00%	4.50%
OPEB Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.73%	4.57%
Expected return on plan assets	2.50%	4.50%

PostEmployment_Benefits_Expect

Post-Employment Benefits (Expected Future Benefit Payments) (Details) (OPEB Plan [Member], USD $)	12 Months Ended
	Dec. 31, 2014
OPEB Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
2015	$33,000
2016	32,000
2017	32,000
2018	32,000
2019	31,000
Five years thereafter	194,000
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	$100,000

PostEmployment_Benefits_Weight

Post-Employment Benefits (Weighted Average Asset Allocation) (Details)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation (as a percent)	100.00%		100.00%		100.00%
Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation (as a percent)	70.00%	[1]	70.10%	[1]	72.20%	[1]
Cash and Short Term Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation (as a percent)	30.00%	[2]	29.90%	[2]	27.80%	[2]
[1]	United States government securities, municipal corporate bonds and notes and asset backed securities
[2]	Cash and securities with maturities of one year or less

PostEmployment_Benefits_Detail

Post-Employment Benefits (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Amortization of Net Gains (Losses)	$0	($100,000)	($100,000)
OPEB Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	100,000
Defined Benefit Plan, Amortization of Net Gains (Losses)	$5,000	$23,000	$43,000

Income_Tax_Details

Income Tax (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Loss Carryforwards [Line Items]
Current deferred tax asset	$3,086,000	$0
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	-96,638,000	-31,488,000	-6,234,000
Current Income Tax Expense (Benefit)	-10,000	0
Deferred Income Tax Expense (Benefit)	-547,000	495,000
Effective Income Tax Rate, Continuing Operations	0.60%	1.60%
Effective income tax rate, continuing operations	34.00%	34.00%
Operating Loss Carryforwards	10,700,000
Operating Loss Carryforwards	4,173,000	5,455,000
Deferred Tax Assets, Other	213,000	182,000
Deferred Tax Assets, Gross	4,386,000	5,637,000
Deferred Tax Liabilities, Property, Plant and Equipment	9,112,000	9,022,000
Deferred Tax Liabilities, Intangible Assets	387,000	1,364,000
Deferred Tax Liabilities, Gross	9,499,000	10,386,000
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate	32,857,000	10,706,000
Effective Income Tax Rate Reconciliation, Tax Exempt Income	-33,216,000	-10,296,000
Income Tax Reconciliation, Other Adjustments	0	222,000
Current State and Local Tax Expense (Benefit)	-159,000	71,000
Income Tax Reconciliation, Prior Year Income Taxes	-37,000	-175,000
Income Tax Reconciliation, Other Reconciling Items	-2,000	-33,000
Income Tax Expense (Benefit), Continuing Operations	-557,000	495,000	0
Deferred Tax Liabilities, Net	-8,199,000	-4,749,000
Deferred Tax Assets, Net	($5,113,000)	($4,749,000)
2012
Operating Loss Carryforwards [Line Items]
Margin tax rate	0.95%
2013
Operating Loss Carryforwards [Line Items]
Margin tax rate	0.98%
2014
Operating Loss Carryforwards [Line Items]
Margin tax rate	1.00%

Commitments_and_Contingencies_1

Commitments and Contingencies (Contractual Obligations) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Future Non Cancelable Commitment [Line Items]
2015	$3,428
2016	9,088
2017	1,421
2018	1,306
2019	1,525
Thereafter	30,706
Total	47,474
Operating leases and service contract [Member]
Future Non Cancelable Commitment [Line Items]
2015	3,428
2016	2,204
2017	1,421
2018	1,306
2019	1,525
Thereafter	2,945
Total	12,829
ARO [Member]
Future Non Cancelable Commitment [Line Items]
2015	0
2016	6,884
2017	0
2018	0
2019	0
Thereafter	27,761
Total	$34,645

Commitments_and_Contingencies_2

Commitments and Contingencies (Details Textual) (USD $)	12 Months Ended			3 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Sep. 30, 2014	Feb. 05, 2014
Loss Contingencies [Line Items]
Class of Warrant or Right, Number of Securities Called by Warrants or Rights						300,000
Class of Warrant or Right, Exercise Price of Warrants or Rights						$0.01
Loss Contingency, Damages Sought	1
Operating leases	$5.80	$1.10	$0.90
High Point [Member]
Loss Contingencies [Line Items]
Partners' Capital Account, Percentage						95.00%
AIM Midstream Holdings [Member]
Loss Contingencies [Line Items]
Partners' Capital Account, Percentage						5.00%
High Point [Member]
Loss Contingencies [Line Items]
Incentive Distribution Right Allocation	85.02%	85.02%		100.00%	100.00%

Related_Party_Transactions_Det

Related- Party Transactions (Details Textual) (USD $)	12 Months Ended			3 Months Ended	0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 15, 2013	Apr. 15, 2013	Dec. 17, 2013	Jan. 31, 2014	Aug. 20, 2014	Jan. 29, 2014	Dec. 11, 2013	Oct. 09, 2012
Related Party Transactions (Textual) [Abstract]
Management Fees Revenue	$900,000
Notes Payable, Related Parties, Current											20,000,000
Payments on long-term debt	-250,870,000	-131,571,000	-59,230,000
Distributions	28,009,000	16,120,000	16,070,000
Limited partners, units issued	22,670,000	7,414,000						4,622,352	3,400,000	2,568,712
American Midstream, LLC [Member]
Related Party Transactions (Textual) [Abstract]
Administrative and operational service expenses	23,500,000	14,200,000	12,500,000
Cost of business development activities	-1,200,000	1,800,000	400,000
High Point [Member]
Related Party Transactions (Textual) [Abstract]
Total Consideration for Issuance of Preferred Units				15,000,000	15,000,000
Total identifiable net assets				61,930,000	61,930,000
High Point [Member] | Issuance of Preferred Units [Member] | Series A
Related Party Transactions (Textual) [Abstract]
Contributed capital				5,142,857	5,142,857
Transaction expenses				2,500,000
Revolving Credit Facility [Member] | Fourth Amendment [Member] | Series A
Related Party Transactions (Textual) [Abstract]
Payments on long-term debt					-12,500,000
Blackwater [Member]
Related Party Transactions (Textual) [Abstract]
Total identifiable net assets				22,700,000	22,700,000
Purchase price of business						63,900,000
Distributions	0	27,650,000	0
Units issued in business acquisition						125,500
Limited Partner [Member]
Related Party Transactions (Textual) [Abstract]
Distributions	39,150,000	21,628,000	15,748,000
Issuance of Series B Units	0
Limited Partner [Member] | Blackwater [Member]
Related Party Transactions (Textual) [Abstract]
General Partner Noncash Distributions						3,052,000
Series B
Related Party Transactions (Textual) [Abstract]
Distributions	2,220,000	0	0
Limited partners, units issued							1,168,225
Series B | Series B
Related Party Transactions (Textual) [Abstract]
Issuance of Series B Units	$32,220,000						$30,000,000

Reporting_Segments_Details

Reporting Segments (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment information
Revenue, net									$307,309	$294,051	$204,868
Derivative, Gain (Loss) on Derivative, Net									1,091	28	3,400
Total revenue	80,177	70,305	77,680	80,238	76,770	77,519	77,191	62,599	308,400	294,079	208,268
Direct operating expenses									-45,702	-32,236	-17,183
Purchases of natural gas, NGLs and condensate									197,952	215,053	154,472
Selling, general and administrative expenses									-23,103	-19,079	-14,309
Advisory services agreement termination fee											-6,252
Allocated Share-based Compensation Expense									-1,536	-2,094	-1,783
Depreciation and Accretion Expense, Including Discontinued Operation									28,832	29,999	21,414
Depreciation, Depletion and Amortization									-28,832	-30,002	-21,287
Gross Profit	36,227	21,332	22,167	23,081	22,891	20,908	18,317	12,705	102,807	74,821	209,034
Costs and Expenses									297,125	298,464
Gain (loss) on acquisition of assets											49,431
Gain (loss) on involuntary conversion of property, plant and equipment								400	0	343	-1,021
Loss on impairment of property, plant and equipment									-122	0	123
Other expense									-670	0	0
Loss on impairment of property, plant and equipment	99,900				3,000		15,200	100	99,892	18,155	0
Interest expense									7,577	9,291	4,570
Earnings in unconsolidated affiliates									348	0	0
Income Tax Expense (Benefit), Continuing Operations									557	-495	0
Net income (loss)									-97,806	-33,406	-6,252
Gain (loss) from operations of disposal groups, net of tax	-29	-26	-506	-50	-523	-15	-1,869	-6	-611	-2,413	-18
Less: Comprehensive income (loss) attributable to noncontrolling interests									214	633	256
Net income (loss)	-94,297	-2,456	-1,667	400	-5,641	-2,731	-22,114	-3,553	-98,020	-34,039	-6,508
Gathering And Processing [Member]
Segment information
Revenue, net									203,616	205,179	152,339
Derivative, Gain (Loss) on Derivative, Net									1,091	28	3,400
Total revenue									204,707	205,207	155,739
Direct operating expenses									-23,783	-14,574	-12,152
Purchases of natural gas, NGLs and condensate									152,690	168,574	117,956
Gross Profit									50,817	36,985	36,118
Transmission [Member]
Segment information
Revenue, net									88,189	79,041	52,529
Derivative, Gain (Loss) on Derivative, Net									0	0	0
Total revenue									88,189	79,041	52,529
Direct operating expenses									-15,577	-13,259	-5,031
Purchases of natural gas, NGLs and condensate									45,262	46,479	36,516
Gross Profit									42,828	32,408	13,313
Terminals [Member]
Segment information
Revenue, net										9,831
Derivative, Gain (Loss) on Derivative, Net									0	0
Total revenue						9,800			15,504
Business Acquisition, Pro Forma Revenue										9,831
Direct operating expenses									-6,342	-4,403
Purchases of natural gas, NGLs and condensate									0	0
Gross Profit									9,162	5,428
Commodity Contract [Member]
Segment information
Unrealized gain (loss) on commodity derivatives									595	-1,495	992
Gain (Loss) on Derivative Instruments [Member] | Commodity Contract [Member]
Segment information
Unrealized gain (loss) on commodity derivatives									356	-1,041	992
Terminals [Member] | Terminals [Member]
Segment information
Revenue, net									$15,504

Reporting_Segments_Reporting_S

Reporting Segments Reporting Segment (Revenue Earned from Customers that Exceed 10%) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	100.00%	100.00%	100.00%
Customer A [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	22.00%	28.00%	30.00%
Customer B [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	0.00%	13.00%	0.00%
Customer D [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	10.00%	10.00%	14.00%
Customer Other [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	56.00%	37.00%	43.00%
Customer Concentration Risk [Member] | Revenue [Member] | Gathering And Processing [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	100.00%	100.00%	100.00%
Customer Concentration Risk [Member] | Revenue [Member] | Transmission [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	100.00%	100.00%	100.00%
Customer Concentration Risk [Member] | Revenue [Member] | Terminals [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	100.00%	100.00%	0.00%
Customer Concentration Risk [Member] | Revenue [Member] | Customer A [Member] | Gathering And Processing [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	33.00%	43.00%	40.00%
Customer Concentration Risk [Member] | Revenue [Member] | Customer B [Member] | Gathering And Processing [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	12.00%	19.00%	11.00%
Customer Concentration Risk [Member] | Revenue [Member] | Customer B [Member] | Terminals [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	20.00%	17.00%
Customer Concentration Risk [Member] | Revenue [Member] | Customer C [Member] | Transmission [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	43.00%	39.00%	50.00%
Customer Concentration Risk [Member] | Revenue [Member] | Customer D [Member] | Gathering And Processing [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	0.00%	0.00%	12.00%
Customer Concentration Risk [Member] | Revenue [Member] | Customer D [Member] | Transmission [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	16.00%	16.00%	22.00%
Customer Concentration Risk [Member] | Revenue [Member] | Customer E [Member] | Transmission [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	0.00%	0.00%	10.00%
Customer Concentration Risk [Member] | Revenue [Member] | Customer H [Member] | Terminals [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	11.00%	13.00%
Customer Concentration Risk [Member] | Revenue [Member] | Customer F [Member] | Terminals [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	19.00%	20.00%
Customer Concentration Risk [Member] | Revenue [Member] | Customer G [Member] | Terminals [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	15.00%	16.00%
Customer Concentration Risk [Member] | Revenue [Member] | Customer Other [Member] | Gathering And Processing [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	55.00%	38.00%	37.00%
Customer Concentration Risk [Member] | Revenue [Member] | Customer Other [Member] | Transmission [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	41.00%	45.00%	18.00%
Customer Concentration Risk [Member] | Revenue [Member] | Customer Other [Member] | Terminals [Member]
Segment Reporting Information [Line Items]
Entity-wide revenue by major customer, percentage	35.00%	34.00%

Reporting_Segments_Assets_Deta

Reporting Segments Assets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Segment Reporting Information [Line Items]
Total assets	$916,644	$382,075
Gathering And Processing [Member]
Segment Reporting Information [Line Items]
Total assets	686,395	178,869
Transmission [Member]
Segment Reporting Information [Line Items]
Total assets	132,767	131,136
Terminals [Member]
Segment Reporting Information [Line Items]
Total assets	71,180	60,873
Other Segments [Member]
Segment Reporting Information [Line Items]
Total assets	$26,302	$11,197

Quarterly_Financial_Data_Detai

Quarterly Financial Data (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Total revenue	$80,177	$70,305	$77,680	$80,238	$76,770	$77,519	$77,191	$62,599	$308,400	$294,079	$208,268
Gross Profit	36,227	21,332	22,167	23,081	22,891	20,908	18,317	12,705	102,807	74,821	209,034
Operating Income (Loss)	-91,633	-290	734	2,450	-2,591	-104	-17,841	-1,661	-88,739	-22,197	-1,664
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	-94,261	-2,397	-1,095	558	-5,018	-2,526	-20,057	-3,392	-97,195	-30,993	-6,234
Gain (loss) from operations of disposal groups, net of tax	-29	-26	-506	-50	-523	-15	-1,869	-6	-611	-2,413	-18
Net income (loss) attributable to noncontrolling interests	7	33	66	108	100	190	188	155
Net income (loss)	-94,297	-2,456	-1,667	400	-5,641	-2,731	-22,114	-3,553	-98,020	-34,039	-6,508
Net Income (Loss) Allocated to General Partners	-1,232	-32	-22	7	-209	-221	-905	-70
Net Income (Loss) Allocated to Limited Partners	($93,065)	($2,424)	($1,645)	$393	($5,433)	($2,510)	($21,209)	($3,482)
Limited partners’ net income (loss) per unit (basic and diluted)	($4.98)	($0.58)	($0.59)	($0.32)	($1.43)	($0.80)	($4.21)	($0.38)	($8.58)	($7.42)	($0.70)
Income (Loss) from Continuing Operations, Per Outstanding Limited Partnership Unit, Basic	($4.98)	($0.58)	($0.55)	($0.31)	($1.43)	($0.81)	($4.01)	($0.39)	($8.54)	($7.15)	($0.70)
Limited partners' net income (loss) from discontinued operations per unit (basic and diluted)	$0	$0	($0.04)	($0.01)	$0	$0.01	($0.20)	$0.01	($0.04)	($0.27)	$0

Subsequent_Events_Subsequent_e

Subsequent Events Subsequent events (Details) (USD $)	3 Months Ended	12 Months Ended			0 Months Ended
	Jun. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 22, 2015
Subsequent Event [Line Items]
Distribution declared per common unit (a)	$0.46	$1.85	$1.75	$1.73
Subsequent Event [Member]
Subsequent Event [Line Items]
Distribution declared per common unit (a)					$0.47
Distribution Made to Limited Partner, Distributions Declared, Per Unit, Annualized Basis					$1.89