Summit Midstream Partners (SMLP) 10-K 29 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 16, 2016	Jun. 30, 2015
Entity Information [Line Items]
Entity Registrant Name	Summit Midstream Partners, LP
Entity Central Index Key	1,549,922
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 1,208,505,269
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Common units
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		66,472,494
General Partner Units
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		1,354,700

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 19,411	$ 26,504
Accounts receivable	84,022	89,201
Other current assets	3,210	3,517
Total current assets	106,643	119,222
Property, plant and equipment, net	1,463,802	1,414,350
Intangible assets, net	438,093	477,734
Goodwill	16,211	265,062
Other noncurrent assets	15,782	17,353
Total assets	2,040,531	2,293,721
Current liabilities:
Trade accounts payable	18,971	24,855
Due to affiliate	1,149	2,711
Deferred revenue	677	2,377
Ad valorem taxes payable	9,890	9,118
Accrued interest	17,483	18,858
Other current liabilities	11,464	13,550
Total current liabilities	59,634	71,469
Long-term debt	944,000	808,000
Deferred revenue	45,486	55,239
Other noncurrent liabilities	7,169	7,292
Total liabilities	$ 1,056,289	$ 942,000
Commitments and contingencies
Common limited partner capital (42,063 units issued and outstanding at December 31, 2015 and 34,427 units issued and outstanding at December 31, 2014)	$ 744,977	$ 649,060
Subordinated limited partner capital (24,410 units issued and outstanding at December 31, 2015 and 2014)	213,631	293,153
General partner interests (1,355 units issued and outstanding at December 31, 2015 and 1,201 units issued and outstanding at December 31, 2014)	25,634	24,676
Summit Investments' equity in contributed subsidiaries	0	384,832
Total partners' capital	984,242	1,351,721
Total liabilities and partners' capital	$ 2,040,531	$ 2,293,721

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares shares in Thousands	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common limited partner capital, units issued	42,063	34,427
Common limited partner capital, units outstanding	42,063	34,427
Subordinated limited partner capital, units issued	24,410	24,410
Subordinated limited partner capital, units outstanding	24,410	24,410
General partner interests, units issued	1,355	1,201
General partner interests, units outstanding	1,355	1,201

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Gathering services and related fees	$ 310,829	$ 255,211	$ 213,979
Natural gas, NGLs and condensate sales	42,079	97,094	88,185
Other revenues	18,411	20,398	21,522
Total revenues	371,319	372,703	323,686
Costs and expenses:
Cost of natural gas and NGLs	31,398	72,415	68,037
Operation and maintenance	87,285	88,927	77,114
General and administrative	36,544	38,269	32,273
Transaction costs	790	730	2,841
Depreciation and amortization	96,189	87,349	70,574
(Gain) loss on asset sales, net	(172)	442	113
Long-lived asset impairment	9,305	5,505	0
Goodwill impairment	248,851	54,199	0
Total costs and expenses	510,190	347,836	250,952
Other income	2	1,189	5
Interest expense	(48,616)	(40,159)	(19,173)
(Loss) income before income taxes	(187,485)	(14,103)	53,566
Income tax benefit (expense)	676	(631)	(729)
Net (loss) income	(186,809)	(14,734)	52,837
Less net income attributable to Summit Investments	5,403	9,258	9,253
Net (loss) income attributable to SMLP	(192,212)	(23,992)	43,584
Less net (loss) income attributable to general partner, including IDRs	3,398	3,125	1,035
Net (loss) income attributable to limited partners	(195,610)	(27,117)	42,549
Common units
Costs and expenses:
Net (loss) income attributable to limited partners	$ (125,437)	$ (16,324)	$ 23,227
(Loss) earnings per limited partner unit:
Basic (in dollars per share)	$ (3.20)	$ (0.49)	$ 0.86
Diluted (in dollars per share)	$ (3.20)	$ (0.49)	$ 0.86
Weighted-average limited partner units outstanding:
Basic (shares)	39,217	33,311	26,951
Diluted (shares)	39,217	33,311	27,101
Subordinated Units
Costs and expenses:
Net (loss) income attributable to limited partners	$ (70,173)	$ (10,793)	$ 19,322
(Loss) earnings per limited partner unit:
Basic (in dollars per share)	$ (2.88)	$ (0.44)	$ 0.79
Diluted (in dollars per share)	$ (2.88)	$ (0.44)	$ 0.79
Weighted-average limited partner units outstanding:
Basic (shares)	24,410	24,410	24,410
Diluted (shares)	24,410	24,410	24,410

CONSOLIDATED STATEMENTS OF PART

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL - USD ($) $ in Thousands	Total	Bison Midstream	Mountaineer Midstream	Polar Midstream	Class B membership interest	Summit Investments' equity in contributed subsidiaries	Summit Investments' equity in contributed subsidiariesBison Midstream	Summit Investments' equity in contributed subsidiariesPolar Midstream	Summit Investments' equity in contributed subsidiariesClass B membership interest	Limited partners, Common	Limited partners, CommonBison Midstream	Limited partners, CommonMountaineer Midstream	Limited partners, CommonClass B membership interest	Limited partners, Subordinated	General partner	General partnerBison Midstream	General partnerMountaineer Midstream
Beginning balance at Dec. 31, 2012	$ 1,030,248					$ 211,001				$ 418,856				$ 380,169	$ 20,222
Increase (Decrease) in Partners' Capital [Roll Forward]
Net (loss) income	52,837					9,253				22,311				20,238	1,035
Distributions to unitholders	(90,196)									(46,286)				(42,107)	(1,803)
Unit-based compensation	2,999				$ 847				$ 830	2,999			$ 17
Consolidation of net assets		$ 303,168		$ 216,105			$ 303,168	$ 216,105
Contributions	2,229					2,229
Purchase of contributed Subsidiaries		$ (200,000)	$ 100,000				$ (248,914)				$ 47,936	$ 98,000				$ 978	$ 2,000
Assets contributed to Red Rock Gathering from Summit Investments	0
Contribution of net assets/excess of acquired carrying value over consideration paid	56,535					(56,535)				28,558				26,846	1,131
Cash advance from Summit Investments to contributed subsidiaries, net	72,745					72,745
Capitalized interest allocated to contributed subsidiaries from Summit Investments	11,964					11,964
Capitalized interest allocated from Summit Investments to contributed subsidiaries	2,046					2,046
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	52					52
Repurchase of DFW Net Profits Interests and SMLP LTIP units	(11,957)									(5,859)				(5,859)	(239)
Ending balance at Dec. 31, 2013	1,493,087					523,944				566,532				379,287	23,324
Increase (Decrease) in Partners' Capital [Roll Forward]
Net (loss) income	(14,734)					9,258				(15,948)				(11,169)	3,125
Distributions to unitholders	(122,224)									(67,658)				(49,796)	(4,770)
Unit-based compensation	4,696				340				340	4,696
Tax withholdings on vested SMLP LTIP awards	(656)									(656)
Issuance of common units, net of offering costs	197,806									197,806
Contributions	4,235														4,235
Purchase of contributed Subsidiaries	(307,941)					(307,941)
Excess of purchase price over acquired carrying value of Red Rock Gathering						66,124				(37,910)				(26,891)	(1,323)
Assets contributed to Red Rock Gathering from Summit Investments	4,233									2,426				1,722	85
Contribution of net assets/excess of acquired carrying value over consideration paid	0
Cash advance from Summit Investments to contributed subsidiaries, net	81,421					81,421
Capitalized interest allocated to contributed subsidiaries from Summit Investments	10,483					10,483
Capitalized interest allocated from Summit Investments to contributed subsidiaries	606					606
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	597					597
Repurchase of DFW Net Profits Interests and SMLP LTIP units	(228)									(228)
Ending balance at Dec. 31, 2014	1,351,721					384,832				649,060				293,153	24,676
Increase (Decrease) in Partners' Capital [Roll Forward]
Net (loss) income	(186,809)					5,403				(123,817)				(71,793)	3,398
Distributions to unitholders	(152,074)									(86,880)				(55,410)	(9,784)
Unit-based compensation	6,174				$ 85				$ 85	6,174
Tax withholdings on vested SMLP LTIP awards	(1,616)									(1,616)
Issuance of common units, net of offering costs	221,977									221,977
Contributions	4,737														4,737
Purchase of contributed Subsidiaries	(285,677)					(285,677)
Assets contributed to Red Rock Gathering from Summit Investments	0
Contribution of net assets/excess of acquired carrying value over consideration paid	0					(130,367)				80,079				47,681	2,607
Cash advance from Summit Investments to contributed subsidiaries, net	21,719					21,719
Capitalized interest allocated to contributed subsidiaries from Summit Investments	3,084					3,084
Capitalized interest allocated from Summit Investments to contributed subsidiaries	921					921
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	0
Ending balance at Dec. 31, 2015	$ 984,242					$ 0				$ 744,977				$ 213,631	$ 25,634

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net (loss) income	$ (186,809)	$ (14,734)	$ 52,837
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization	96,975	88,293	71,606
Amortization of deferred loan costs	3,257	2,770	2,246
Unit-based compensation	6,259	5,036	3,846
(Gain) loss on asset sales, net	(172)	442	113
Long-lived asset impairment	9,305	5,505	0
Goodwill impairment	248,851	54,199	0
Purchase accounting adjustment	0	(1,185)	0
Changes in operating assets and liabilities:
Accounts receivable	5,180	(19,255)	(20,490)
Trade accounts payable	(2,770)	(684)	(3,419)
Due to affiliate	1,377	(883)	1,427
Change in deferred revenue	(11,453)	26,378	16,685
Ad valorem taxes payable	772	743	(11)
Accrued interest	(1,375)	6,714	12,128
Other, net	(3,447)	1,658	3,501
Net cash provided by operating activities	165,950	154,997	140,469
Cash flows from investing activities:
Capital expenditures	(118,107)	(220,820)	(182,978)
Proceeds from asset sales	323	325	585
Acquisition of gathering systems	0	(10,872)	(210,000)
Acquisitions of gathering systems from affiliate	(288,618)	(305,000)	(200,000)
Net cash used in investing activities	(406,402)	(536,367)	(592,393)
Cash flows from financing activities:
Distributions to unitholders	(152,074)	(122,224)	(90,196)
Borrowings under revolving credit facility	187,000	237,295	380,950
Repayments under revolving credit facility	(51,000)	(315,295)	(294,180)
Deferred loan costs	(277)	(5,320)	(10,608)
Proceeds from issuance of common units, net	221,977	197,806	0
Contribution from general partner	4,737	4,235	2,229
Cash advance from Summit Investments to contributed subsidiaries, net	21,719	81,421	72,745
Expenses paid by Summit Investments on behalf of contributed subsidiaries	3,084	10,483	11,964
Issuance of senior notes	0	300,000	300,000
Repurchase of equity-based compensation awards	0	(228)	(11,957)
Issuance of units to affiliate in connection with the Mountaineer Acquisition	0	0	100,000
Other, net	(1,807)	(656)	0
Net cash provided by financing activities	233,359	387,517	460,947
Net change in cash and cash equivalents	(7,093)	6,147	9,023
Cash and cash equivalents, beginning of period	26,504	20,357	11,334
Cash and cash equivalents, end of period	19,411	26,504	20,357
Supplemental cash flow disclosures:
Cash interest paid	48,947	31,524	9,016
Less capitalized interest	3,137	3,778	6,255
Interest paid (net of capitalized interest)	45,810	27,746	2,761
Cash paid for taxes	0	0	660
Noncash investing and financing activities:
Capital expenditures in trade accounts payable (period-end accruals)	14,962	18,076	29,860
Excess of acquired carrying value over consideration paid for Polar and Divide	130,367	0	0
Capitalized interest allocated from Summit Investments to contributed subsidiaries	921	606	2,046
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	0	597	52
Excess of consideration paid over acquired carrying value of Red Rock Gathering	0	(66,124)	0
Assets contributed to Red Rock Gathering from Summit Investments	0	4,233	0
Issuance of units to affiliate to partially fund the Bison Drop Down	0	0	48,914
Contribution of net assets from Summit Investments in excess of consideration paid for Bison Midstream	$ 0	$ 0	$ 56,535

ORGANIZATION, BUSINESS OPERATIO

ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION	ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION Organization. Summit Midstream Partners, LP ("SMLP" or the "Partnership"), a Delaware limited partnership, was formed in May 2012 and began operations in October 2012 in connection with its initial public offering ("IPO") of common limited partner units. SMLP is a growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental United States. Our business activities are conducted through our subsidiary, Summit Midstream Holdings, LLC ("Summit Holdings"), a Delaware limited liability company, and its subsidiaries. References to the "Partnership," "we," or "our," refer collectively to SMLP and its subsidiaries. Summit Midstream GP, LLC, a Delaware limited liability company (the "general partner"), manages our operations and activities. Summit Midstream Partners, LLC, a Delaware limited liability company ("Summit Investments"), is the ultimate owner of our general partner and has the right to appoint the entire board of directors of our general partner. Summit Investments is controlled by Energy Capital Partners II, LLC and its parallel and co-investment funds (collectively, "Energy Capital Partners"). In addition to its 2% general partner interest in SMLP (including the incentive distribution rights ("IDRs") in respect of SMLP), Summit Investments has direct and indirect ownership interests in our common and subordinated units. As of December 31, 2015 , Summit Investments beneficially owned 5,444,731 SMLP common units and all of our subordinated units. Our operations are conducted through, and our operating assets are owned by, various wholly-owned operating subsidiaries. Neither SMLP nor its subsidiaries have any employees. All of the personnel that conduct our business are employed by Summit Investments, but these individuals are sometimes referred to as our employees. Effective with the completion of its IPO, SMLP had a 100% ownership interest in Summit Holdings, which had a 100% ownership interest in both DFW Midstream Services LLC ("DFW Midstream") and Grand River Gathering, LLC ("Grand River" or the "Legacy Grand River" system). On June 4, 2013, the Partnership acquired all of the membership interests of Bison Midstream, LLC ("Bison Midstream") from a subsidiary of Summit Investments (the "Bison Drop Down"). As such, the Bison Drop Down was determined to be a transaction among entities under common control. Prior to the Bison Drop Down, on February 15, 2013, Summit Investments acquired Bear Tracker Energy, LLC ("BTE"), which was subsequently renamed Meadowlark Midstream Company, LLC ("Meadowlark Midstream"). The net assets that comprise Bison Midstream were carved out from Meadowlark Midstream in connection with the Bison Drop Down. Common control of Bison Midstream began in February 2013. On June 21, 2013, Mountaineer Midstream Company, LLC ("Mountaineer Midstream"), a newly formed, wholly owned subsidiary of the Partnership, acquired natural gas gathering pipeline and compression assets from an affiliate of MarkWest Energy Partners, L.P. ("MarkWest") (the "Mountaineer Acquisition"). In December 2013, Mountaineer Midstream was merged into DFW Midstream. On March 18, 2014, SMLP acquired all of the membership interests of Red Rock Gathering Company, LLC ("Red Rock Gathering") from a subsidiary of Summit Investments (the "Red Rock Drop Down"). As such, the Red Rock Drop Down was determined to be a transaction among entities under common control. Common control of Red Rock Gathering began in October 2012. Concurrent with the closing of the Red Rock Drop Down, SMLP contributed its interest in Red Rock Gathering to Grand River. On May 18, 2015, the Partnership acquired all of the membership interests of Polar Midstream, LLC ("Polar Midstream") and Epping Transmission Company, LLC ("Epping," and collectively with Polar Midstream, "Polar and Divide") from a subsidiary of Summit Investments (the "Polar and Divide Drop Down"). As such, the Polar and Divide Drop Down was determined to be a transaction among entities under common control. Polar Midstream's net assets were carved out of Meadowlark Midstream immediately prior to the Polar and Divide Drop Down. Concurrent with the closing of the Polar and Divide Drop Down, Epping became a wholly owned subsidiary of Polar Midstream and SMLP contributed Polar Midstream (including Epping) to Bison Midstream. Common control began in (i) February 2013 for Polar Midstream and (ii) April 2014 for Epping. On February 25, 2016, Summit Midstream Partners, LP ("SMLP" or the "Partnership") and Summit Midstream Partners Holdings, LLC (“SMP Holdings”) entered into a contribution agreement (the "Contribution Agreement") pursuant to which SMP Holdings agreed to contribute to the Partnership substantially all of (i) the issued and outstanding membership interests of Summit Midstream Utica, LLC, Meadowlark Midstream Company, LLC and Tioga Midstream, LLC (collectively, the "Contributed Entities"), each limited liability companies and indirect wholly owned subsidiaries of SMP Holdings and (ii) SMP Holdings’ 40.0% joint venture interest in each of Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C. (collectively with the Contributed Entities, the “2016 Drop Down Assets”)(the “2016 Drop Down”). The 2016 Drop Down is expected to close in March 2016 (the "Initial Close"), subject to customary closing conditions. Business Operations. We provide natural gas gathering, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term and fee-based agreements with our customers. Our results are driven primarily by the volumes of natural gas that we gather, treat, compress and process as well as by the volumes of crude oil and produced water that we gather. Our gathering systems and the unconventional resource basins in which they operate are as follows: • the Mountaineer Midstream system ("Mountaineer Midstream"), a natural gas gathering system located in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia; • Bison Midstream, an associated natural gas gathering system located in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; • Polar and Divide, a crude oil and produced water gathering system and transmission pipelines located in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; • DFW Midstream, a natural gas gathering system located in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and • Grand River, a natural gas and natural gas liquids gathering and processing system located in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah. Our operating subsidiaries, which are wholly owned by Summit Holdings, are: DFW Midstream (which includes Mountaineer Midstream); Bison Midstream (and its wholly owned subsidiaries Polar Midstream and Epping); and Grand River (and its wholly owned subsidiary Red Rock Gathering). All of our operating subsidiaries are focused on the development, construction and operation of natural gas gathering and processing systems and crude oil and produced water gathering systems. Presentation and Consolidation. We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP"). These principles are established by the Financial Accounting Standards Board. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, including fair value measurements, the reported amounts of revenue and expense, and the disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates. We conduct our operations in the midstream sector through four reportable segments: • the Marcellus Shale, which is served by Mountaineer Midstream; • the Williston Basin, which is served by Bison Midstream and Polar and Divide; • the Barnett Shale, which is served by DFW Midstream; and • the Piceance Basin, which is served by Grand River. Grand River is composed of the Legacy Grand River and Red Rock Gathering systems. Our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations. The consolidated financial statements include the assets, liabilities, and results of operations of SMLP and its wholly owned subsidiaries. All intercompany transactions among the consolidated entities have been eliminated in consolidation. For the purposes of the consolidated financial statements, SMLP's results of operations reflect the results of operations of: (i) DFW Midstream and Grand River for all periods presented, (ii) Bison Midstream and Polar and Divide since February 16, 2013 and (iii) Mountaineer Midstream since June 22, 2013. The financial position, results of operations and cash flows of Bison Midstream and Polar Midstream included herein have been derived from the accounting records of Meadowlark Midstream on a carve-out basis (see Note 2). The carve-out allocations and estimates were based on methodologies that management believes are reasonable. The results reflected herein, however, may not reflect what Bison Midstream's or Polar Midstream’s financial position, results of operations or cash flows would have been if either had been a stand-alone company. SMLP recognized its drop down acquisitions at Summit Investments' historical cost because the acquisitions were executed by entities under common control. The excess of Summit Investments' net investment over the purchase price paid for a contributed subsidiary is recognized as an addition to partners' capital, while the excess of purchase price paid over net investment is recognized as a reduction to partners' capital. Due to the common control aspect, we account for drop down transactions on an “as-if pooled” basis for the periods during which common control existed. Reclassifications. Certain reclassifications have been made to prior-year amounts to conform to current-year presentation. We combined the balances associated with the unfavorable gas gathering contract with other noncurrent liabilities. These balance sheet changes had no impact on (i) total liabilities or (ii) total liabilities and partners' capital. We also evaluated our historical classification of (i) gathering fee revenue associated with certain Bison Midstream percent-of-proceeds contracts and (ii) certain pass-through expenses also for Bison Midstream. As a result of this evaluation, we determined that certain amounts that had previously been recognized in cost of natural gas and NGLs would be more appropriately reflected as gathering services and related fees and other revenues to enhance reporting transparency. The impact of these reclassifications, which had no impact on net (loss) income, total partners' capital or segment adjusted EBITDA, follows. Year ended December 31, 2014 2013 (In thousands) Gathering services and related fees $ 15,616 $ 16,805 Other revenues 3,952 10,068 Net impact on total revenues $ 19,568 $ 26,873 Cost of natural gas and NGLs $ 19,568 $ 26,873 Net impact on cost of natural gas and NGLs and total costs and expenses $ 19,568 $ 26,873 In the fourth quarter 2015, we began reporting all of our operations in North Dakota as one reportable segment, the Williston Basin reportable segment. These presentation changes had no impact on total assets, total liabilities, total revenues, total costs and expenses, net income, partners' capital, cash flows or total segment adjusted EBITDA. See Note 3 for additional information on this change.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cash and Cash Equivalents. Cash and cash equivalents include temporary cash investments with original maturities of three months or less. Accounts Receivable. Accounts receivable relate to gathering and other services provided to our customers and other counterparties. We evaluate the collectability of accounts receivable and the need for an allowance for doubtful accounts based on customer-specific facts and circumstances. To the extent we doubt the collectability of a specific customer or counterparty receivable, we recognize an allowance for doubtful accounts. Other Current Assets. Other current assets primarily consist of the current portion of prepaid expenses that are charged to expense over the period of benefit or the life of the related contract. Property, Plant, and Equipment. We record property, plant, and equipment at historical cost of construction or fair value of the assets at acquisition. We capitalize expenditures that extend the useful life of an asset or enhance its productivity or efficiency from its original design over the expected remaining period of use. For maintenance and repairs that do not add capacity or extend the useful life of an asset, we recognize expenditures as an expense as incurred. We capitalize project costs incurred during construction, including interest on funds borrowed to finance the construction of facilities, as construction in progress. We record depreciation on a straight-line basis over an asset’s estimated useful life. We base our estimates for useful life on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Estimates of useful lives follow. Useful lives (In years) Gathering and processing systems and related equipment 30 Other 4-15 Construction in progress is depreciated consistent with its applicable asset class once it is placed in service. Land and line fill are not depreciated. We base an asset’s carrying value on estimates, assumptions and judgments for useful life and salvage value. Upon sale, retirement or other disposal, we remove the carrying value of an asset and its accumulated depreciation from our balance sheet and recognize the related gain or loss, if any. Accrued capital expenditures are reflected in trade accounts payable. Asset Retirement Obligations. We record a liability for asset retirement obligations only if and when a future asset retirement obligation with a determinable life is identified. For identified asset retirement obligations, we then evaluate whether the expected date and related costs of retirement can be estimated. We have concluded that our gathering and processing assets have an indeterminate life because they are owned and will operate for an indeterminate period when properly maintained. Because we did not have sufficient information to reasonably estimate the amount or timing of such obligations and we have no current plan to discontinue use of any significant assets, we did not provide for any asset retirement obligations as of December 31, 2015 or 2014. Amortizing Intangibles. Upon the acquisition of DFW Midstream, certain of its gas gathering contracts were deemed to have above-market pricing structures while another was deemed to have pricing that was below market. We have recognized the above-market contracts as favorable gas gathering contracts. We have recognized the below-market contract as the unfavorable gas gathering contract and included it in other noncurrent liabilities. We amortize these contracts on a units-of-production basis over the contract's estimated useful life. We define useful life as the period over which the contract is expected to contribute to our future cash flows. These contracts have original terms ranging from 10 years to 20 years. We recognize the amortization expense associated with these contracts in other revenues. We amortize all other gas gathering contracts, or contract intangibles, over the period of economic benefit based upon expected revenues over the life of the contract. The useful life of these contracts ranges from 10 years to 25 years. We recognize the amortization expense associated with these contracts in depreciation and amortization expense. We have rights-of-way associated with city easements and easements granted within existing rights-of-way. We amortize these intangible assets over the shorter of the contractual term of the rights-of-way or the estimated useful life of the gathering system. The contractual terms of the rights-of-way range from 20 years to 30 years. We recognize the amortization expense associated with rights-of-way assets in depreciation and amortization expense. Goodwill. Goodwill represents consideration paid in excess of the fair value of the net identifiable assets acquired in a business combination. We evaluate goodwill for impairment annually on September 30. We also evaluate goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We test goodwill for impairment using a two-step quantitative test. In the first step, we compare the fair value of the reporting unit to its carrying value, including goodwill. To estimate the fair value of the reporting units under step one, we utilize two valuation methodologies: the market approach and the income approach. Both of these approaches incorporate significant estimates and assumptions to calculate enterprise fair value for a reporting unit. The most significant estimates and assumptions inherent within these two valuation methodologies are: (i) determination of the weighted-average cost of capital; (ii) the selection of guideline public companies; (iii) market multiples; (iv) weighting of the income and market approaches; (v) growth rates; (vi) commodity prices; and (vi) the expected levels of throughput volume gathered. Changes in these and other assumptions could materially affect the estimated amount of fair value for any of our reporting units. If the reporting unit’s fair value exceeds its carrying amount, we conclude that the goodwill of the reporting unit has not been impaired and no further work is performed. If we determine that the reporting unit’s carrying value exceeds its fair value, we proceed to step two. In step two, we compare the carrying value of the reporting unit to its implied fair value. Significant estimates and assumptions utilized in the determination of a reporting unit's implied fair value are based on a variety of factors specific to a given reporting unit's individual assets and liabilities as well as market and industry considerations. If we determine that the carrying amount of a reporting unit's goodwill exceeds its implied fair value, we recognize the excess of the carrying value over the implied fair value as an impairment loss. Other Noncurrent Assets. Other noncurrent assets primarily consist of external costs incurred in connection with the issuance of our senior notes and the closing of our revolving credit facility and related amendments. We capitalize and then amortize these deferred loan costs over the life of the respective debt instrument. We recognize amortization of deferred loan costs in interest expense. Impairment of Long-Lived Assets. We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset (except goodwill) is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If we conclude that an asset's carrying value will not be recovered through future cash flows, we recognize an impairment loss on the long-lived asset equal to the amount by which the carrying value exceeds its fair value. We determine fair value using either a market-based approach or an income-based approach. We discuss our policy for goodwill impairment above. Derivative Contracts. We have commodity price exposure related to our sale of the physical natural gas we retain from our DFW Midstream customers and our procurement of electricity to operate DFW Midstream's electric-drive compression assets. Our gas gathering agreements with our DFW Midstream customers permit us to retain a certain quantity of natural gas that we gather to offset the power costs we incur to operate these electric-drive compression assets. We manage this direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices on the Waha Hub Index. Because we also sell our retainage gas at prices that are based on the Waha Hub Index, we have effectively fixed the relationship between our compression electricity expense and natural gas retainage sales. Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. We have designated these contracts as normal under the normal purchase and sale exception under the accounting standards for derivatives. We do not enter into risk management contracts for speculative purposes. Fair Value of Financial Instruments. The fair-value-measurement standard under GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which the inputs are observable. The three levels of the fair value hierarchy are as follows: • Level 1. Inputs represent quoted prices in active markets for identical assets or liabilities; • Level 2. Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs); and • Level 3. Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an internally developed present value of future cash flows model that underlies management's fair value measurement). Commitments and Contingencies. We record accruals for loss contingencies when we determine that it is probable that a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. Revenue Recognition. We generate the majority of our revenue from the gathering, treating and processing services that we provide to our customers. We also generate revenue from our marketing of natural gas, NGLs and condensate. We realize revenues by receiving fees from our customers or by selling the residue natural gas, NGLs and condensate. We recognize revenue earned from fee-based gathering, treating and processing services in gathering services and related fees revenue. We also earn revenue from the sale of physical natural gas purchased from our customers under percentage-of-proceeds arrangements. These revenues are recognized in natural gas, NGLs and condensate sales with corresponding expense recognition for the producer's share of the proceeds in cost of natural gas and NGLs. We sell substantially all of the natural gas that we retain from our DFW Midstream customers to offset the power expenses of the electric-driven compression on the DFW Midstream system. We also sell condensate retained from our gathering services at Grand River. Revenues from the retainage of natural gas and condensate are recognized in natural gas, NGLs and condensate sales; the associated expense is included in operation and maintenance expense. Certain customers reimburse us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis, with the revenue component recognized in other revenues. 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 provide gathering and/or processing services principally under contracts that contain one or more of the following arrangements: • Fee-based arrangements. Under fee-based arrangements, we receive a fee or fees for one or more of the following services (i) natural gas gathering, treating, and/or processing and (ii) crude oil and/or produced water gathering. • Percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat the natural gas, process the natural gas and/or sell the natural gas to a third party for processing. We then remit to our producers an agreed-upon percentage of the actual proceeds received from sales of the residue natural gas and NGLs. Certain of these arrangements may also result in returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. The margins earned are directly related to the volume of natural gas that flows through the system and the price at which we are able to sell the residue natural gas and NGLs. Certain of our gathering and processing agreements provide for a monthly, quarterly or annual minimum volume commitment ("MVC"). Under these MVCs, our customers agree to ship and/or process a minimum volume of production on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contracted measurement period if its actual throughput volumes are less than its MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that contracted measurement period. We recognize customer billings for obligations under their MVCs as revenue when the obligations are billable under the contract and the customer does not have the right to utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods. We record customer billings for obligations under their MVCs as deferred revenue when the customer has the right to utilize shortfall payments to offset gathering or processing fees in subsequent periods. We recognize deferred revenue under these arrangements in revenue once all contingencies or potential performance obligations associated with the related volumes have either (i) been satisfied through the gathering or processing of future excess volume throughput, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the applicable gathering or processing agreement. We also recognize deferred revenue when it is determined that a given amount of MVC shortfall payments cannot be recovered by offsetting gathering or processing fees in subsequent contracted measurement periods. In making this determination, we consider both quantitative and qualitative facts and circumstances, including, but not limited to, contract terms, capacity of the associated pipeline or receipt point and/or expectations regarding future investment, drilling and production. We classify deferred revenue as a current liability for arrangements where the expiration of a customer's right to utilize shortfall payments is 12 months or less. We classify deferred revenue as noncurrent for arrangements where the expiration of the right to utilize shortfall payments and our estimate of its potential utilization is more than 12 months. Unit-Based Compensation. For awards of unit-based compensation, we determine a grant date fair value and recognize the related compensation expense in the statement of operations over the vesting period of the respective awards. Income Taxes. As a partnership, we are generally not subject to federal and state income taxes, except as noted below. However, our unitholders are individually responsible for paying federal and state income taxes on their share of our taxable income. Net income or loss for GAAP purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and the GAAP basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. In general, legal entities that are chartered, organized or conducting business in the state of Texas are subject to a franchise tax (the "Texas Margin Tax"). The Texas Margin Tax has the characteristics of an income tax because it is determined by applying a tax rate to a tax base that considers both revenues and expenses. Our financial statements reflect provisions for these tax obligations. In 2014, we elected to apply changes to the determination of cost of goods sold for the Texas Margin Tax which permits the use of accelerated depreciation allowed for federal income tax purposes. As a result of this change, we recognized a a deferred tax liability. Other noncurrent liabilities included a deferred tax liability of $0.6 million and $1.3 million as of December 31, 2015 and 2014, respectively. Earnings Per Unit ("EPU"). We determine basic EPU by dividing the net income or loss that is attributed, in accordance with the net income and loss allocation provisions of our partnership agreement, to common and subordinated unitholders under the two-class method, after deducting (i) the general partner's 2% interest in net income or loss, (ii) any payment of IDRs and (iii) any net income or loss of contributed subsidiaries that is attributable to Summit Investments, by the weighted-average number of common and subordinated units outstanding. Diluted EPU reflects the potential dilution that could occur if securities or other agreements to issue common units, such as unit-based compensation, were exercised, settled or converted into common units and included in the weighted-average number of units outstanding. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted EPU calculation, the impact is reflected by applying the treasury stock method. Comprehensive Income. Comprehensive income is the same as net income (loss) for all periods presented. Environmental Matters. We are subject to various federal, state and local laws and regulations relating to the protection of the environment. Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. We accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Such accruals are adjusted as further information develops or circumstances change. Recoveries of environmental remediation costs from other parties or insurers are recorded as assets when their receipt is deemed probable. Carve-Out Entities. For drop down transactions involving entities that were carved out of other entities, the majority of the assets and liabilities allocated to the carve-out entity are specifically identified based on the original entity's existing divisional organization. Goodwill is allocated to the carve-out entity based on initial purchase accounting estimates. Revenues and depreciation and amortization are specifically identified based on the relationship of the carve-out entity to the original entity's existing divisional structure. Operation and maintenance and general and administrative expenses are allocated to the carve-out entity based on volume throughput. Recent Accounting Pronouncements. Accounting standard setters frequently issue new or revised accounting rules. We review new pronouncements to determine the impact, if any, on our financial statements. There are currently no recent pronouncements that have been issued that we believe may materially affect our financial statements, except as noted below. In May 2014, the FASB released a joint revenue recognition standard, Accounting Standards Update ("ASU") No. 2014-09 Revenue From Contracts With Customers (Topic 606) ("ASU 2014-09"). Under ASU 2014-09, revenue will be recognized under a five-step model: (i) identify the contract with the customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to performance obligations; and (v) recognize revenue when (or as) the Company satisfies a performance obligation. In its original form, ASU 2014-09 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016; early adoption was not permitted. In July 2015, the FASB reaffirmed the guidance in its April 2015 proposed ASU that defers for one year the effective date of the ASU 2014-09 for both public and nonpublic entities reporting under U.S. GAAP and allows early adoption as of the original effective date. We are currently in the process of evaluating the impact of this update. In April 2015, the FASB issued ASU No. 2015-03 Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). Under ASU 2015-03, entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. This presentation will result in debt issuance cost being presented the same way debt discounts have historically been handled. In August 2015, the FASB amended ASU 2015-03 to address the presentation and subsequent measurement of debt issuance costs related to line of credit (“LOC”) arrangements. The amendment added a paragraph that states that the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing deferred debt issuance costs ratably over the term of a LOC arrangement, regardless of whether there are outstanding borrowings under that LOC arrangement. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, and interim and annual periods thereafter. Early adoption is permitted. The adoption of this update will result in a reclassification from other noncurrent assets to long-term debt of the debt issuance costs associated with our senior notes. Debt issuance costs associated with our revolving credit facility will remain in other noncurrent assets. There will be no impact on interest expense, net income, earnings per unit or partners' capital. In September 2015, the FASB issued ASU No. 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). Under ASU 2015-16, an acquirer would be required to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Further, the acquirer must record in the financial statements for the same period, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Entities must also present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, and interim and annual periods thereafter. Early adoption is permitted. We are currently in the process of evaluating the impact of this update. In January 2016, the FASB issued ASU No. 2016-01 Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). Among other changes, the amendments in ASU 2016-01 supersede the guidance to classify equity securities with readily determinable fair values into different categories and require equity securities to be measured at fair value with changes in the fair value recognized through net income. They also simplify the impairment assessment of equity investments without readily determinable fair values and require use of the exit price notion when measuring the fair value of financial instruments for disclosure purposes. Under ASU 2016-01, an entity will be required to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments, to separately present financial assets and financial liabilities by measurement category and form of financial asset. ASU 2016-01 also clarifies that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 31, 2017. Early adoption is permissible, but limited in application. The adoption of this new update could impact the fair value we disclose for certain financial instruments but is not expected to impact amounts recognized in the consolidated financial statements.

SEGMENT INFORMATION

SEGMENT INFORMATION	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segment Information	SEGMENT INFORMATION As of December 31, 2015, our reportable segments are: • the Marcellus Shale, which is served by Mountaineer Midstream; • the Williston Basin, which is served by Bison Midstream and Polar and Divide; • the Barnett Shale, which is served by DFW Midstream; and • the Piceance Basin, which is served by Grand River. Each of our reportable segments provides midstream services in a specific geographic area. Our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations. In connection with the Polar and Divide Drop Down, we identified two reportable segments in the Williston Basin. For the second and third quarters of 2015, we reported the results of Bison Midstream in the Williston Basin – Gas reportable segment and those of Polar and Divide in the Williston Basin – Liquids reportable segment. In the fourth quarter of 2015, we changed how we manage and evaluate our operations in North Dakota. Prior to the fourth quarter of 2015, Bison Midstream and Polar and Divide were managed separately and their financial results were evaluated separately. In the fourth quarter of 2015, we began managing our North Dakota operations under a single management team and began reporting their financial results on a combined basis. As a result, we no longer distinguish between liquids and gas in the Williston Basin and now have one reportable segment, the Williston Basin reportable segment, representing those operations. Corporate represents those assets and liabilities and revenues and expenses that are not specifically attributable to a reportable segment, not individually reportable, or that have not been allocated to our reportable segments. Beginning in the first quarter of 2015, we discontinued allocating certain general and administrative expenses, primarily salaries, benefits, incentive compensation and rent expense, to our operating segments. Assets by reportable segment follow. December 31, 2015 2014 2013 (In thousands) Assets: Marcellus Shale $ 233,116 $ 243,884 $ 214,379 Williston Basin 563,952 709,888 645,014 Barnett Shale 416,586 428,935 431,578 Piceance Basin 797,057 872,437 876,969 Total reportable segment assets 2,010,711 2,255,144 2,167,940 Corporate 29,820 38,577 23,203 Total assets $ 2,040,531 $ 2,293,721 $ 2,191,143 For information on the sale or impairment of long-lived assets, other than goodwill, see Note 4. For information on goodwill by reportable segment, including goodwill impairments, see Note 6. Revenues by reportable segment follow. Year ended December 31, 2015 2014 2013 (In thousands) Revenues: Marcellus Shale $ 28,468 $ 22,694 $ 9,588 Williston Basin 85,887 104,471 81,501 Barnett Shale 88,042 93,001 105,324 Piceance Basin 168,922 152,537 127,273 Total reportable segment revenues and total revenues $ 371,319 $ 372,703 $ 323,686 Counterparties accounting for more than 10% of total revenues were as follows: Year ended December 31, 2015 2014 2013 Percentage of total revenues (1): Counterparty A - Piceance 17 % 19 % 19 % Counterparty B - Piceance 16 % * * Counterparty C - Barnett Shale * * 14 % __________ (1) Includes recognition of revenue that was previously deferred in connection with minimum volume commitments (see Notes 2 and 7). * Less than 10% Depreciation and amortization, including the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues, by reportable segment follows. Year ended December 31, 2015 2014 2013 (In thousands) Depreciation and amortization: Marcellus Shale $ 8,682 $ 7,648 $ 3,998 Williston Basin 26,280 22,491 16,669 Barnett Shale 16,392 16,601 14,961 Piceance Basin 45,018 40,965 35,527 Total reportable segment depreciation and amortization 96,372 87,705 71,155 Corporate 603 588 451 Total depreciation and amortization $ 96,975 $ 88,293 $ 71,606 Capital expenditures by reportable segment follow. Year ended December 31, 2015 2014 2013 (In thousands) Capital expenditures: Marcellus Shale $ 1,306 $ 33,866 $ 1,822 Williston Basin 90,234 139,422 99,983 Barnett Shale 6,875 14,567 29,534 Piceance Basin 19,263 32,505 50,709 Total reportable segment capital expenditures 117,678 220,360 182,048 Corporate 429 460 930 Total capital expenditures $ 118,107 $ 220,820 $ 182,978 We assess the performance of our reportable segments based on segment adjusted EBITDA. We define segment adjusted EBITDA as total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) depreciation and amortization, (iii) adjustments related to MVC shortfall payments, (iv) impairments and (v) other noncash expenses or losses, less other noncash income or gains. Segment adjusted EBITDA by reportable segment follows. Year ended December 31, 2015 2014 2013 (In thousands) Reportable segment adjusted EBITDA: Marcellus Shale $ 23,214 $ 15,940 $ 6,333 Williston Basin 47,010 31,551 17,350 Barnett Shale 59,526 60,528 69,473 Piceance Basin 104,467 107,953 80,941 Total reportable segment adjusted EBITDA $ 234,217 $ 215,972 $ 174,097 A reconciliation of (loss) income before income taxes to total reportable segment adjusted EBITDA follows. Year ended December 31, 2015 2014 2013 (In thousands) Reconciliation of Income (loss) Before Income Taxes to Segment Adjusted EBITDA: (Loss) income before income taxes $ (187,485 ) $ (14,103 ) $ 53,566 Add: Allocated corporate expenses 23,772 11,065 8,773 Interest expense 48,616 40,159 19,173 Depreciation and amortization 96,975 88,293 71,606 Adjustments related to MVC shortfall payments (11,902 ) 26,565 17,025 Unit-based compensation 6,259 5,036 3,846 Loss on asset sales 42 442 113 Long-lived asset impairment 9,305 5,505 — Goodwill impairment 248,851 54,199 — Less: Interest income 2 4 5 Gain on asset sales 214 — — Impact of purchase price adjustment — 1,185 — Total reportable segment adjusted EBITDA $ 234,217 $ 215,972 $ 174,097 Segment adjusted EBITDA excludes the effect of allocated corporate expenses, such as certain general and administrative expenses (including compensation-related expenses and professional services fees), transaction costs, interest expense and income tax expense. Adjustments related to MVC shortfall payments account for: • the net increases or decreases in deferred revenue for MVC shortfall payments and • our inclusion of expected annual MVC shortfall payments. We include a proportional amount of these historical or expected MVC shortfall payments in each quarter prior to the quarter in which we actually recognize the shortfall payment. These adjustments have not been billed to our customers and are not recognized in our consolidated financial statements. Adjustments related to MVC shortfall payments by reportable segment follow. Year ended December 31, 2015 2014 2013 (In thousands) Adjustments related to MVC shortfall payments: Williston Basin $ 11,870 $ 10,743 $ 3,600 Barnett Shale (2,182 ) 628 1,030 Piceance Basin (21,590 ) 15,194 12,395 Total adjustments related to MVC shortfall payments $ (11,902 ) $ 26,565 $ 17,025

PROPERTY, PLANT, AND EQUIPMENT,

PROPERTY, PLANT, AND EQUIPMENT, NET	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT, AND EQUIPMENT, NET	PROPERTY, PLANT, AND EQUIPMENT, NET Details on property, plant, and equipment follow. December 31, 2015 2014 (In thousands) Gathering and processing systems and related equipment $ 1,574,916 $ 1,459,585 Construction in progress 25,484 37,604 Land and line fill 9,339 9,964 Other 30,935 28,871 Total 1,640,674 1,536,024 Less accumulated depreciation 176,872 121,674 Property, plant, and equipment, net $ 1,463,802 $ 1,414,350 During 2015 and 2014, we identified certain events, facts and circumstances which indicated that certain of our property, plant and equipment could be impaired. (There were no impairment indicators during 2013.) As such, we reviewed the assets that had been identified as potentially impaired and estimated the fair value of the identified property, plant and equipment using a market-based approach. For the assets which had fair values below their carrying value, we recognized the following long-lived asset impairments, by segment. Year ended December 31, 2015 2014 2013 (In thousands) Long-lived asset impairment: Williston Basin $ 7,554 $ — $ — Barnett Shale 531 5,505 — Piceance Basin 1,220 — — Our impairment determinations, in the context of these reviews, involved significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these estimates are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment. During the fourth quarters of 2015 and 2014, we identified a need to evaluate the goodwill associated with certain of our gathering systems (see Note 6). In connection with these evaluations, we also evaluated the related property, plant and equipment associated therewith for impairment and concluded that no impairment was necessary. Depreciation expense and capitalized interest follow. Year ended December 31, 2015 2014 2013 (In thousands) Depreciation expense $ 55,685 $ 49,816 $ 37,313 Capitalized interest 3,137 3,778 6,255

AMORTIZING INTANGIBLE ASSETS AN

AMORTIZING INTANGIBLE ASSETS AND UNFAVORABLE GAS GATHERING CONTRACT	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
AMORTIZING INTANGIBLE ASSETS AND LIABILITIES AND UNFAVORABLE GAS GATHERING CONTRACT	AMORTIZING INTANGIBLE ASSETS AND UNFAVORABLE GAS GATHERING CONTRACT Details regarding our intangible assets and the unfavorable gas gathering contract (included in other noncurrent liabilities), all of which are subject to amortization, follow. December 31, 2015 Useful lives (In years) Gross carrying amount Accumulated amortization Net (Dollars in thousands) Favorable gas gathering contracts 18.7 $ 24,195 $ (9,534 ) $ 14,661 Contract intangibles 12.5 426,464 (111,052 ) 315,412 Rights-of-way 25.2 125,922 (17,902 ) 108,020 Total intangible assets $ 576,581 $ (138,488 ) $ 438,093 Unfavorable gas gathering contract 10.0 $ 10,962 $ (6,077 ) $ 4,885 December 31, 2014 Useful lives (In years) Gross carrying amount Accumulated amortization Net (Dollars in thousands) Favorable gas gathering contracts 18.7 $ 24,195 $ (8,056 ) $ 16,139 Contract intangibles 12.5 426,464 (75,713 ) 350,751 Rights-of-way 24.7 123,581 (12,737 ) 110,844 Total intangible assets $ 574,240 $ (96,506 ) $ 477,734 Unfavorable gas gathering contract 10.0 $ 10,962 $ (5,385 ) $ 5,577 During the fourth quarters of 2015 and 2014, we identified a need to evaluate the goodwill associated with certain of our gathering systems (see Note 6). In connection with these evaluations, we also evaluated the related intangible assets associated therewith for impairment and concluded that no impairment was necessary. We recognized amortization expense in other revenues as follows: Year ended December 31, 2015 2014 2013 (In thousands) Amortization expense – favorable gas gathering contracts $ (1,478 ) $ (1,741 ) $ (2,078 ) Amortization expense – unfavorable gas gathering contract 692 797 1,046 We recognized amortization expense in costs and expenses as follows: Year ended December 31, 2015 2014 2013 (In thousands) Amortization expense – contract intangibles $ 35,339 $ 32,554 $ 28,654 Amortization expense – rights-of-way 5,165 4,979 4,607 The estimated aggregate annual amortization expected to be recognized as of December 31, 2015 for each of the five succeeding fiscal years follows. Intangible assets Unfavorable gas gathering contract (In thousands) 2016 $ 42,301 $ 924 2017 41,152 1,047 2018 40,606 1,035 2019 40,852 1,045 2020 43,498 834

GOODWILL

GOODWILL	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL	GOODWILL Recorded goodwill is related to the original acquisitions of the Grand River, Bison Midstream, Polar and Divide and Mountaineer Midstream systems. The assets acquired in the Polar and Divide Drop Down were carved out of Meadowlark Midstream. As such, we elected to apply the historical cost approach to determine the amount of goodwill to assign to the Polar and Divide reporting unit. Our procedures indicated that the remaining goodwill balance at Meadowlark Midstream was entirely attributable to the Polar and Divide reporting unit. A rollforward of goodwill by reportable segment and in total follows. Piceance Basin Williston Basin Marcellus Shale Total (In thousands) Goodwill, January 1, 2014 $ 45,478 $ 257,572 $ 16,211 $ 319,261 Goodwill impairment — (54,199 ) — (54,199 ) Goodwill, December 31, 2014 45,478 203,373 16,211 265,062 Goodwill impairment (45,478 ) (203,373 ) — (248,851 ) Goodwill, December 31, 2015 $ — $ — $ 16,211 $ 16,211 Accumulated goodwill impairments by reportable segment for those reporting units that have previously recognized goodwill follow. December 31, 2015 2014 2013 (In thousands) Accumulated goodwill impairment: Piceance Basin $ 45,478 $ — $ — Williston Basin 257,572 54,199 — Total accumulated goodwill impairment $ 303,050 $ 54,199 $ — As discussed in Note 2, we evaluate goodwill for impairment annually on September 30 and whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value, including goodwill. 2014 Annual Impairment Evaluation . In September 2014, we performed our annual goodwill impairment testing as of September 30 using a combination of the income and market approaches. We determined that the fair value of the Grand River, Mountaineer Midstream and Polar Midstream reporting units substantially exceeded their carrying value, including goodwill. We also determined that the fair value of the Bison Midstream reporting unit exceeded its carrying value. However, it did not exceed its carrying value, including goodwill, by a substantial amount. Because the fair value of each reporting unit exceeded its carrying value, including goodwill, there were no associated impairments of goodwill in connection with our 2014 annual goodwill impairment test. Fourth Quarter 2014 Goodwill Impairment . During the latter part of the fourth quarter of 2014, the declines in prices for natural gas, NGLs and crude oil accelerated, negatively impacting producers in each of our areas of operation. As a result, we considered whether the goodwill associated with our Grand River, Mountaineer Midstream, Polar Midstream and Bison Midstream reporting units could have been impaired. Our assessments related to Grand River and Mountaineer Midstream did not result in an indication that the associated goodwill had been impaired. Our assessment related to the Polar Midstream and Bison Midstream reporting units did result in an indication that the associated goodwill could have been impaired. We noted that both reporting units were impacted by the recent price declines. We also noted that a key Bison Midstream customer announced that it was delaying its previously announced drilling plans which caused SMLP to reduce its forecasted volume assumption. The impact of these events increased the likelihood that the goodwill associated with the Polar Midstream and Bison Midstream reporting units could have been impaired. As such, we concluded that a triggering event occurred during the fourth quarter of 2014 requiring that we test the goodwill associated with these reporting units for impairment. In connection therewith, we reperformed our step one analyses for each as of December 31, 2014. To estimate the fair value of the reporting units, we utilized two valuation methodologies: the market approach and the income approach. The results of our step one goodwill impairment testing indicated that the fair value of the Polar Midstream reporting unit exceeded its carrying value, including goodwill as of December 31, 2014. As a result, there was no associated impairment of goodwill in connection with the fourth quarter 2014 triggering event. The results of our step one goodwill impairment testing indicated that the fair value of the Bison Midstream reporting unit was below its carrying value, including goodwill as of December 31, 2014. As a result, we performed step two of the goodwill impairment test. To perform step two, we first determined the fair values of the identifiable assets and liabilities. Significant assumptions utilized in the determination of the fair value of each reporting unit's individual assets and liabilities included the determination of discount rate and contributory asset charge utilized in our calculation of the fair value of our contract intangibles, expected levels of throughput volume and associated capital expenditures and commodity prices. In the first quarter of 2015, we finalized our calculations of the fair values of the identified assets and liabilities in step two of the December 31, 2014 goodwill impairment testing for the Bison Midstream reporting unit. This process confirmed the preliminary goodwill impairment of $54.2 million that was recognized as of December 31, 2014. 2015 Annual Impairment Evaluation . We performed our annual goodwill impairment testing as of September 30, 2015 using a combination of the income and market approaches. We determined that the fair value of the Grand River, Mountaineer Midstream and Polar Midstream reporting units exceeded their carrying value, including goodwill. Because the fair value of each reporting unit exceeded its carrying value, including goodwill, there were no associated impairments of goodwill in connection with our 2015 annual goodwill impairment test. Fourth Quarter 2015 Goodwill Impairments . During the latter part of the fourth quarter of 2015 and the early part of the first quarter of 2016, the declines in forward prices for natural gas, NGLs and crude oil accelerated significantly. As a result, the energy sector's public debt and equity market experienced increased volatility, particularly for comparable companies operating in the midstream services sector. Additionally, during this period, the values of our publicly traded equity and debt instruments decreased as did those of comparable midstream companies. Due to (i) the increased market volatility, (ii) the decrease in market values of comparable companies, (iii) the continued trend of falling commodity prices and (iv) the finalization of our annual financial and operating plans which took into account changes resulting from expected levels of drilling activity, we concluded that a triggering event occurred during the fourth quarter of 2015 requiring that we test the goodwill associated with our Grand River and Polar and Divide reporting units. Our assessment related to Mountaineer Midstream did not result in an indication that a triggering event had occurred for Mountaineer Midstream. In connection therewith, we updated our step one analyses as of December 31, 2015. These updated analyses indicated that the carrying values for Grand River and Polar and Divide exceeded their estimated fair values. As a result, we then performed step two of the goodwill impairment test for both reporting units. To perform step two, we first determined the estimated fair values of the identifiable assets and liabilities. Significant assumptions utilized in the determination of the fair value of each reporting unit's individual assets and liabilities included the determination of discount rate taking into consideration company-specific risks and contributory asset charge utilized in our contract intangibles, expected levels of throughput volume and associated capital expenditures. Our preliminary estimates of the fair values of the identified assets and liabilities calculated in step two indicated that all of the associated goodwill for both reporting units had been impaired. As such, we recorded an estimated goodwill impairment of $45.5 million for Grand River and $203.4 million for Polar and Divide. These amounts represent our estimate of impairment pending finalization of the fair value calculations. We expect finalization to occur in the first quarter of 2016. Fair Value Measurement. Our impairment determinations, in the context of (i) our annual impairment evaluations and (ii) our other-than-annual impairment evaluations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.

DEFERRED REVENUE

DEFERRED REVENUE	12 Months Ended
	Dec. 31, 2015
Deferred Revenue Disclosure [Abstract]
Deferred Revenue	DEFERRED REVENUE The majority of our gas gathering agreements provide for a monthly, quarterly or annual MVC from our customers. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped or processed for the applicable period and the MVC for the applicable period, multiplied by the applicable gathering or processing fee. Many of our gas gathering agreements contain provisions that can reduce or delay the cash flows that we expect to receive from our MVCs to the extent that a customer's actual throughput volumes are above or below its MVC for the applicable contracted measurement period. These provisions include the following: • To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it may be entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, we would not receive gathering fees on throughput in excess of that customer's MVC (depending on the terms of the specific gas gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding measurement periods (as applicable). • To the extent that a customer's throughput volumes exceed its MVC in the applicable contracted measurement period, it may be entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. As a result of this mechanism, the weighted-average remaining period for which our MVCs apply will be less than the weighted-average of the original stated contract terms of our MVCs. • To the extent that certain of our customers' throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a bank of credits that it can utilize in the future to reduce shortfall payments owed in subsequent periods, subject to expiration if there is no shortfall in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular gas gathering agreement. A rollforward of current deferred revenue follows. Williston Basin Barnett Shale Piceance Basin Total current (In thousands) Current deferred revenue, January 1, 2014 $ — $ 1,555 $ — $ 1,555 Additions — 2,610 — 2,610 Less revenue recognized — 1,788 — 1,788 Current deferred revenue, December 31, 2014 — 2,377 — 2,377 Additions — 677 2,743 3,420 Less revenue recognized — 2,377 2,743 5,120 Current deferred revenue, December 31, 2015 $ — $ 677 $ — $ 677 A rollforward of noncurrent deferred revenue follows. Williston Basin Barnett Shale Piceance Basin Total noncurrent (In thousands) Noncurrent deferred revenue, January 1, 2014 $ 6,389 $ — $ 23,294 $ 29,683 Additions 10,743 — 14,813 25,556 Noncurrent deferred revenue, December 31, 2014 17,132 — 38,107 55,239 Additions 11,897 — 12,765 24,662 Less revenue recognized 27 — 34,388 34,415 Noncurrent deferred revenue, December 31, 2015 $ 29,002 $ — $ 16,484 $ 45,486 __________ (1) Noncurrent includes amounts recognized in connection with the Bison Drop Down. In September 2015, we determined that it would be remote for a certain Piceance Basin customer to ship volumes in excess of its MVC such that it could recover certain previous MVC shortfall payments, which had been recorded as deferred revenue, as an offset to future gathering fees. We based this determination on public statements by the customer regarding future drilling and investment plans in the area covered by the MVC contract. Due to the remote nature of having to perform any services associated with the previously deferred gathering revenue, we evaluated (i) the terms of the customer contract, (ii) the capacity of the central receipt points for throughput volumes covered by the MVC contract and (iii) the size of the area of mutual interest ("AMI"), including the number of drilling locations to determine what amount of previously deferred gathering revenue had met the criteria for revenue recognition. Our evaluation resulted in the recognition of $34.4 million of gathering services and related fees revenue that had been previously deferred with a corresponding reduction to deferred revenue. This represents recognition of amounts deferred up to the September 2015 event triggering the conclusion that the associated shortfall payments should be recognized as revenue. As of December 31, 2015 , accounts receivable included $12.7 million of shortfall billings related to MVC arrangements that can be utilized to offset gathering fees in subsequent periods.

DEBT

DEBT	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
DEBT	DEBT Debt consisted of the following: December 31, 2015 2014 (In thousands) Summit Holdings variable rate senior secured revolving credit facility (2.93% at December 31, 2015 and 2.67% at December 31, 2014) due November 2018 $ 344,000 $ 208,000 Summit Holdings 5.50% Senior unsecured notes due August 2022 300,000 300,000 Summit Holdings 7.50% Senior unsecured notes due July 2021 300,000 300,000 Total long-term debt $ 944,000 $ 808,000 The aggregate amount of our debt maturities during each of the years after December 31, 2015 are as follows: Debt (In thousands) 2016 $ — 2017 — 2018 344,000 2019 — 2020 — Thereafter 600,000 Total long-term debt $ 944,000 Revolving Credit Facility. We have a senior secured revolving credit facility which allows for revolving loans, letters of credit and swingline loans (the "revolving credit facility"). The revolving credit facility has a $700.0 million borrowing capacity, matures in November 2018, and includes a $200.0 million accordion feature. It is secured by the membership interests of Summit Holdings and those of its subsidiaries. Substantially all of Summit Holdings' and its subsidiaries' assets are pledged as collateral under the revolving credit facility. The revolving credit facility, and Summit Holdings' obligations, are guaranteed by SMLP and each of its subsidiaries. Borrowings under the revolving credit facility bear interest at the London Interbank Offered Rate ("LIBOR") or an Alternate Base Rate ("ABR") plus an applicable margin ranging from 0.75% to 1.75% for ABR borrowings and 1.75% to 2.75% for LIBOR borrowings, with the commitment fee ranging from 0.30% to 0.50% in each case based on our relative leverage at the time of determination. At December 31, 2015 , the applicable margin under LIBOR borrowings was 2.50% , the interest rate was 2.93% and the unused portion of the revolving credit facility totaled $356.0 million (subject to a commitment fee of 0.50% ). The revolving credit agreement contains affirmative and negative covenants customary for credit facilities of its size and nature that, among other things, limit or restrict the ability to: (i) incur additional debt; (ii) make investments; (iii) engage in certain mergers, consolidations, acquisitions or sales of assets; (iv) enter into swap agreements and power purchase agreements; (v) enter into leases that would cumulatively obligate payments in excess of $30.0 million over any 12 -month period; and (vi) prohibits the payment of distributions by Summit Holdings if a default then exists or would result therefrom, and otherwise limits the amount of distributions Summit Holdings can make. In addition, the revolving credit facility requires Summit Holdings to maintain a ratio of consolidated trailing 12 -month earnings before interest, income taxes, depreciation and amortization ("EBITDA," as defined in the credit agreement) to net interest expense of not less than 2.5 to 1.0 (as defined in the credit agreement) and a ratio of total net indebtedness to consolidated trailing 12 -month EBITDA of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to 270 days following certain acquisitions. Additionally, the total leverage ratio upper limit can be increased from 5.0 to 1.0 to 5.5 to 1.0 at our option, subject to the inclusion of a senior secured leverage ratio (senior secured net indebtedness to consolidated trailing 12 -month EBITDA, as defined in the credit agreement) upper limit of 3.75 to 1.0. On February 25, 2016, we closed on an amendment to our revolving credit facility, which will become effective contingent upon and concurrent with the Initial Close of the 2016 Drop Down (the "Contingent Amendment"). In connection with the Contingent Amendment, we have received commitments to (i) increase the revolving credit facility's borrowing capacity from $700.0 million to $1.25 billion , (ii) include a new investment basket allowing the Co-Issuers (as defined below) to buy back up to $100.0 million of our outstanding senior unsecured notes and (iii) approve various amendments to facilitate the 2016 Drop Down. There will be no change to the pricing or the maturity date of the revolving credit facility in connection with the Contingent Amendment. As of December 31, 2015 , we were in compliance with the revolving credit facility's covenants. There were no defaults or events of default during the year ended December 31, 2015 . Senior Notes. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Summit Midstream Finance Corp. ("Finance Corp.," together with Summit Holdings, the "Co-Issuers"), co-issued $300.0 million of 5.50% senior unsecured notes maturing August 15, 2022 (the "5.5% senior notes"). In June 2013, the Co-Issuers co-issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021 (the "7.5% senior notes"). SMLP and all of its subsidiaries other than the Co-Issuers (the "Guarantors") have fully and unconditionally and jointly and severally guaranteed the 5.5% senior notes and the 7.5% senior notes. SMLP has no independent assets or operations. Summit Holdings has no assets or operations other than its ownership of its wholly owned subsidiaries and activities associated with its borrowings under the revolving credit facility, the 5.5% senior notes and the 7.5% senior notes. Finance Corp. has no independent assets or operations and was formed for the sole purpose of being a co-issuer of certain of Summit Holdings' indebtedness, including the 5.5% senior notes and the 7.5% senior notes. There are no significant restrictions on the ability of SMLP or Summit Holdings to obtain funds from its subsidiaries by dividend or loan. 5.5% Senior Notes . We will pay interest on the 5.5% senior notes semi-annually in cash in arrears on February 15 and August 15 of each year, commencing February 15, 2015. The 5.5% senior notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 5.5% senior notes are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness. We used the proceeds from the issuance of the 5.5% senior notes to repay a portion of the balance outstanding under our revolving credit facility. At any time prior to August 15, 2017, the Co-Issuers may redeem up to 35% of the aggregate principal amount of the 5.5% senior notes at a redemption price of 105.500% of the principal amount of the 5.5% senior notes, plus accrued and unpaid interest, if any, to the redemption date, with an amount not greater than the net cash proceeds of certain equity offerings. On and after August 15, 2017, the Co-Issuers may redeem all or part of the 5.5% senior notes at a redemption price of 104.125% (with the redemption premium declining ratably each year to 100.000% on and after August 15, 2020), plus accrued and unpaid interest, if any. Debt issuance costs of $5.1 million , recognized in other noncurrent assets, are being amortized over the life of the senior notes. The 5.5% senior notes' indenture restricts SMLP’s and the Co-Issuers’ ability and the ability of certain of their subsidiaries to: (i) incur additional debt or issue preferred stock; (ii) make distributions, repurchase equity or redeem subordinated debt; (iii) make payments on subordinated indebtedness; (iv) create liens or other encumbrances; (v) make investments, loans or other guarantees; (vi) sell or otherwise dispose of a portion of their assets; (vii) engage in transactions with affiliates; and (viii) make acquisitions or merge or consolidate with another entity. These covenants are subject to a number of important exceptions and qualifications. At any time when the senior notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default or event of default under the indenture has occurred and is continuing, many of these covenants will terminate. The 5.5% senior notes' indenture provides that each of the following is an event of default: (i) default for 30 days in the payment when due of interest on the 5.5% senior notes; (ii) default in the payment when due of the principal of, or premium, if any, on the 5.5% senior notes; (iii) failure by the Co-Issuers or SMLP to comply with certain covenants relating to mergers and consolidations, change of control or asset sales; (iv) failure by SMLP for 180 days after notice to comply with certain covenants relating to the filing of reports with the SEC; (v) failure by the Co-Issuers or SMLP for 30 days after notice to comply with any of the other agreements in the indenture; (vi) specified defaults under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by SMLP or any of its restricted subsidiaries (or the payment of which is guaranteed by SMLP or any of its restricted subsidiaries); (vii) failure by SMLP or any of its restricted subsidiaries to pay certain final judgments aggregating in excess of $20.0 million ; (viii) except as permitted by the indenture, any guarantee of the senior notes shall cease for any reason to be in full force and effect or any guarantor, or any person acting on behalf of any guarantor, shall deny or disaffirm its obligations under its guarantee of the senior notes; and (ix) certain events of bankruptcy, insolvency or reorganization described in the indenture. In the case of an event of default as described in the foregoing clause (ix), all outstanding 5.5% senior notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 5.5% senior notes may declare all the 5.5% senior notes to be due and payable immediately. As of December 31, 2015 , we were in compliance with the covenants of the 5.5% senior notes and there were no defaults or events of default during the year ended December 31, 2015 . 7.5% Senior Notes . The 7.5% senior notes were sold within the United States only to qualified institutional buyers in reliance on Rule 144A under the Securities Act of 1933, as amended (the "Securities Act"), and outside the United States only to non-U.S. persons in reliance on Regulation S under the Securities Act. We pay interest on the 7.5% senior notes semi-annually in cash in arrears on January 1 and July 1 of each year. The 7.5% senior notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 7.5% senior notes are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness. We used the proceeds from the issuance of the 7.5% senior notes to repay a portion of the balance outstanding under our revolving credit facility. Effective as of April 7, 2014, all of the holders of our 7.5% senior notes exchanged their unregistered senior notes and the guarantees of those notes for registered notes and guarantees. The terms of the registered senior notes are substantially identical to the terms of the unregistered senior notes, except that the transfer restrictions, registration rights and provisions for additional interest relating to the unregistered senior notes do not apply to the registered senior notes. At any time prior to July 1, 2016, the Co-Issuers may redeem up to 35% of the aggregate principal amount of the 7.5% senior notes at a redemption price of 107.500% of the principal amount of the 7.5% senior notes, plus accrued and unpaid interest, if any, to the redemption date, with an amount not greater than the net cash proceeds of certain equity offerings. On and after July 1, 2016, the Co-Issuers may redeem all or part of the 7.5% senior notes at a redemption price of 105.625% (with the redemption premium declining ratably each year to 100.000% on and after July 1, 2019), plus accrued and unpaid interest, if any. Debt issuance costs of $7.4 million , recognized in other noncurrent assets, are being amortized over the life of the senior notes. The 7.5% senior notes indenture restricts SMLP’s and the Co-Issuers’ ability and the ability of certain of their subsidiaries to: (i) incur additional debt or issue preferred stock; (ii) make distributions, repurchase equity or redeem subordinated debt; (iii) make payments on subordinated indebtedness; (iv) create liens or other encumbrances; (v) make investments, loans or other guarantees; (vi) sell or otherwise dispose of a portion of their assets; (vii) engage in transactions with affiliates; and (viii) make acquisitions or merge or consolidate with another entity. These covenants are subject to a number of important exceptions and qualifications. At any time when the senior notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default or event of default under the indenture has occurred and is continuing, many of these covenants will terminate. The 7.5% senior notes indenture provides that each of the following is an event of default: (i) default for 30 days in the payment when due of interest on the 7.5% senior notes; (ii) default in the payment when due of the principal of, or premium, if any, on the 7.5% senior notes; (iii) failure by the Co-Issuers or SMLP to comply with certain covenants relating to mergers and consolidations, change of control or asset sales; (iv) failure by SMLP for 180 days after notice to comply with certain covenants relating to the filing of reports with the SEC; (v) failure by the Co-Issuers or SMLP for 30 days after notice to comply with any of the other agreements in the indenture; (vi) specified defaults under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by SMLP or any of its restricted subsidiaries (or the payment of which is guaranteed by SMLP or any of its restricted subsidiaries); (vii) failure by SMLP or any of its restricted subsidiaries to pay certain final judgments aggregating in excess of $20.0 million ; (viii) except as permitted by the indenture, any guarantee of the senior notes shall cease for any reason to be in full force and effect or any guarantor, or any person acting on behalf of any guarantor, shall deny or disaffirm its obligations under its guarantee of the 7.5% senior notes; and (ix) certain events of bankruptcy, insolvency or reorganization described in the indenture. In the case of an event of default as described in the foregoing clause (ix), all outstanding 7.5% senior notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 7.5% senior notes may declare all the 7.5% senior notes to be due and payable immediately. As of December 31, 2015, we were in compliance with the covenants for the 7.5% senior notes and there were no defaults or events of default during the year ended December 31, 2015.

FINANCIAL INSTRUMENTS

FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
FINANCIAL INSTRUMENTS	FINANCIAL INSTRUMENTS Concentrations of Credit Risk. Financial instruments that potentially subject us to concentrations of credit risk consist of cash and accounts receivable. We maintain our cash in bank deposit accounts that frequently exceed federally insured limits. We have not experienced any losses in such accounts and do not believe we are exposed to any significant risk. Accounts receivable primarily comprise amounts due for the gathering, treating and processing services we provide to our customers and also the sale of natural gas liquids resulting from our processing services. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of our counterparties and can require letters of credit for receivables from counterparties that are judged to have substandard credit, unless the credit risk can otherwise be mitigated. Our top five customers or counterparties accounted for 70% of total accounts receivable at December 31, 2015 , compared with 62% as of December 31, 2014 . Fair Value. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the balance sheet approximates fair value due to their short-term maturities. A summary of the estimated fair value of our debt financial instruments follows. December 31, 2015 December 31, 2014 Carrying value Estimated fair value (Level 2) Carrying value Estimated fair value (Level 2) (In thousands) Revolving credit facility $ 344,000 $ 344,000 $ 208,000 $ 208,000 5.5% Senior notes 300,000 224,000 300,000 281,750 7.5% Senior notes 300,000 257,000 300,000 306,750 The revolving credit facility’s carrying value on the balance sheet is its fair value due to its floating interest rate. The fair value for the senior notes is based on an average of nonbinding broker quotes as of December 31, 2015 and December 31, 2014 . The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the senior notes.

PARTNERS' CAPITAL

PARTNERS' CAPITAL	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
PARTNERS' CAPITAL	PARTNERS' CAPITAL A rollforward of the number of common limited partner, subordinated limited partner and general partner units follows. Common Subordinated General partner Total Units, January 1, 2013 24,412,427 24,409,850 996,320 49,818,597 Units issued to a subsidiary of Summit Investments in connection with the Bison Drop Down 1,553,849 — 31,711 1,585,560 Units issued to a subsidiary of Summit Investments in connection with the Mountaineer Acquisition 3,107,698 — 63,422 3,171,120 Net units issued under SMLP LTIP 5,892 — — 5,892 Units, January 1, 2014 29,079,866 24,409,850 1,091,453 54,581,169 Units issued in connection with the March Equity 2014 Offering 5,300,000 — 108,337 5,408,337 Net units issued under SMLP LTIP 46,647 — 861 47,508 Units, December 31, 2014 34,426,513 24,409,850 1,200,651 60,037,014 Units issued in connection with the May 2015 Equity Offering 7,475,000 — 152,551 7,627,551 Net units issued under SMLP LTIP 161,131 — 1,498 162,629 Units, December 31, 2015 42,062,644 24,409,850 1,354,700 67,827,194 Unit Offerings. In March 2014, we completed an underwritten public offering of 10,350,000 common units at a price of $38.75 per unit, of which 5,300,000 common units were offered by the Partnership and 5,050,000 common units were offered by a subsidiary of Summit Investments, pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC. Concurrently, our general partner made a capital contribution to maintain its 2% general partner interest in SMLP. We used the proceeds from the primary offering and the general partner capital contribution to fund a portion of the purchase of Red Rock Gathering. In September 2014, a subsidiary of Summit Investments completed an underwritten public offering of 4,347,826 SMLP common units pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC. We did not receive any proceeds from this offering. In May 2015, we completed an underwritten public offering of 6,500,000 common units at a price of $30.75 per unit pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC (the "May 2015 Equity Offering"). On May 22, 2015, the underwriters exercised in full their option to purchase an additional 975,000 common units from us at a price of $30.75 per unit. Concurrent with both transactions, our general partner made a capital contribution to us to maintain its 2% general partner interest. Subordination. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution ("MQD," as defined below) plus any arrearages in the payment of the MQD from prior quarters. The subordination period ends on the first business day after we have earned and paid at least $1.60 (the MQD on an annualized basis) on each outstanding common unit and subordinated unit and the corresponding distribution on the general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2015. The subordination period ended in conjunction with the February 2016 distribution payment in respect of the fourth quarter of 2015 and the then-outstanding subordinated units converted to common units on a one -for-one basis. Summit Investments' Equity in Contributed Subsidiaries. Summit Investments' equity in contributed subsidiaries represents its position in the net assets of Polar and Divide, Red Rock Gathering and Bison Midstream that have been acquired by SMLP. The balance also reflects net income attributable to Summit Investments for Polar and Divide, Red Rock Gathering and Bison Midstream for the periods beginning on their respective acquisition dates by Summit Investments and ending on the dates they were acquired by the Partnership. During the years ended December 31, 2015, 2014 and 2013, net income was attributed to Summit Investments for: • Polar and Divide for the period from February 16, 2013 to May 18, 2015; • Red Rock Gathering for the period from January 1, 2013 to March 18, 2014; and • Bison Midstream for the period from February 16, 2013 to June 4, 2013. Although included in partners' capital, any net income attributable to Summit Investments is excluded from the calculation of EPU. Polar and Divide Drop Down . On May 18, 2015, we acquired 100% of the membership interests in Polar Midstream and Epping from a subsidiary of Summit Investments. We paid total net cash consideration of $285.7 million in exchange for Summit Investments' $416.0 million net investment in Polar Midstream and Epping, including customary working capital and capital expenditures adjustments (see Note 15 for additional information). We recognized a capital contribution from Summit Investments for the difference between cash consideration paid and Summit Investments' net investment in Polar Midstream and Epping. The calculation of the capital contribution and its allocation to partners' capital follow (dollars in thousands). Summit Investments' net investment in Polar Midstream and Epping $ 416,044 Total net cash consideration paid to a subsidiary of Summit Investments 285,677 Excess of acquired carrying value over consideration paid $ 130,367 Allocation of capital contribution: General partner interest $ 2,607 Common limited partner interest 80,079 Subordinated limited partner interest 47,681 Partners' capital contribution – excess of acquired carrying value over consideration paid $ 130,367 Red Rock Drop Down . On March 18, 2014, we acquired 100% of the membership interests in Red Rock Gathering from a subsidiary of Summit Investments. We paid total net cash consideration of $307.9 million (including working capital adjustments accrued in December 2014 and cash settled in February 2015) in exchange for Summit Investments' $241.8 million net investment in Red Rock Gathering. As a result of the excess of the purchase price over acquired carrying value of Red Rock Gathering, SMLP recognized a capital distribution to Summit Investments. The calculation of the capital distribution and its allocation to partners' capital follow (dollars in thousands). Summit Investments' net investment in Red Rock Gathering $ 241,817 Total net cash consideration paid to a subsidiary of Summit Investments 307,941 Excess of consideration paid over acquired carrying value $ (66,124 ) Allocation of capital distribution: General partner interest $ (1,323 ) Common limited partner interest (37,910 ) Subordinated limited partner interest (26,891 ) Partners' capital distribution – excess of consideration paid over acquired carrying value $ (66,124 ) Bison Drop Down . On June 4, 2013, a subsidiary of Summit Investments entered into a purchase and sale agreement with SMLP whereby SMLP acquired the Bison Gas Gathering system. In exchange for its $305.4 million net investment in Bison Midstream, SMLP paid Summit Investments and the general partner total cash and unit consideration of $248.9 million . As a result of the contribution of net assets in excess of consideration, SMLP recognized a capital contribution from Summit Investments. The calculation of the capital contribution and its allocation to partners' capital follow (dollars in thousands). Summit Investments' net investment in Bison Midstream $ 305,449 Aggregate cash paid to Summit Investments $ 200,000 Issuance of 1,553,849 SMLP common units to Summit Investments 47,936 Issuance of 31,711 SMLP general partner units to the general partner 978 Total consideration paid to a subsidiary of Summit Investments 248,914 Excess of acquired carrying value over consideration paid $ 56,535 Allocation of capital contribution: General partner interest $ 1,131 Common limited partner interest 28,558 Subordinated limited partner interest 26,846 Partners' capital contribution – excess of acquired carrying value over consideration paid $ 56,535 The number of units issued to Summit Investments and the general partner in connection with the Bison Drop Down was calculated based on an assumed equity issuance of $50.0 million and the five -day volume-weighted-average price as of June 3, 2013 of $31.53 per unit. The units were then valued as of June 4, 2013 (the date of closing) using the June 4, 2013 closing price of SMLP's units of $30.85 . The general partner interest allocation was calculated based on a 2% general partner interest in the contribution of assets in excess of consideration given by SMLP to Summit Investments. Common and subordinated limited partner interests allocations were calculated as their respective percentages of total limited partner capital applied to the balance of the contribution by Summit Investments after giving effect to the general partner allocation. Mountaineer Acquisition. We completed the acquisition of Mountaineer Midstream on June 21, 2013. The purchase price of $210.0 million was funded with $110.0 million of borrowings under SMLP’s revolving credit facility and the issuance for cash of $100.0 million of SMLP common units and general partner interests to a subsidiary of Summit Investments and the general partner. The allocation and valuation of units issued to partially fund the Mountaineer Acquisition follow (dollars in thousands). Issuance of 3,107,698 SMLP common units to Summit Investments $ 98,000 Issuance of 63,422 SMLP general partner units to the general partner 2,000 Issuance of units in connection with the Mountaineer Acquisition $ 100,000 Pursuant to a unit purchase agreement, the number of units issued to Summit Investments and the general partner in connection with the Mountaineer Acquisition was calculated based on an assumed equity issuance of $100.0 million and the five -day volume-weighted-average price as of June 3, 2013 of $31.53 per unit. Cash Distribution Policy Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. Our partnership agreement requires that we distribute all of our available cash (as defined below) within 45 days after the end of each quarter to unitholders of record on the applicable record date. Our policy is to distribute to our unitholders an amount of cash each quarter that is equal to or greater than the MQD stated in our partnership agreement. General Partner Interest. Our general partner is entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner's initial 2.0% interest in our distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Minimum Quarterly Distribution. Our partnership agreement generally requires that we make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.40 per unit, or $1.60 on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. The amount of distributions paid under our policy is subject to fluctuations based on the amount of cash we generate from our business and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Definition of Available Cash. Available cash generally means, for any quarter, all cash on hand at the end of that quarter: • less the amount of cash reserves established by our general partner at the date of determination of available cash for that quarter to: • provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debt service requirements); • comply with applicable law, any of our debt instruments or other agreements; or • provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter); • plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter. Cash Distributions Paid and Declared. We paid the following per-unit distributions during the years ended December 31: Year ended December 31, 2015 2014 2013 Per-unit annual distributions to unitholders $ 2.270 $ 2.040 $ 1.725 On January 21, 2016, the board of directors of our general partner declared a distribution of $ 0.575 per unit for the quarterly period ended December 31, 2015. This distribution, which totaled $ 41.0 million , was paid on February 12, 2016 to unitholders of record at the close of business on February 5, 2016. As noted above, the payment of this distribution triggered the end of the subordination period and all of the then-outstanding subordinated units converted to common units on a one-for-one basis on February 16, 2016. We allocated the February 2016 distribution in accordance with the third target distribution level (see "Incentive Distribution Rights—Percentage Allocations of Available Cash" below for additional information.) Incentive Distribution Rights. Our general partner also currently holds IDRs that entitle it to receive increasing percentage allocations, up to a maximum of 50.0% (as set forth in the chart below), of the cash we distribute from operating surplus in excess of $0.46 per unit per quarter. The maximum distribution includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0% . The maximum distribution does not include any distributions that our general partner may receive on any common or subordinated units that it owns. Percentage Allocations of Available Cash . The following table illustrates the percentage allocations of available cash between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth in the column Marginal Percentage Interest in Distributions are the percentage interests of our general partner and the unitholders in any available cash we distribute up to and including the corresponding amount in the column Total Quarterly Distribution Per Unit Target Amount. The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its IDRs and that there are no arrearages on common units. Total quarterly distribution per unit target amount Marginal percentage interest in distributions Unitholders General partner Minimum quarterly distribution $0.40 98.0% 2.0% First target distribution $0.40 up to $0.46 98.0% 2.0% Second target distribution above $0.46 up to $0.50 85.0% 15.0% Third target distribution above $0.50 up to $0.60 75.0% 25.0% Thereafter above $0.60 50.0% 50.0% We reached the second target distribution in connection with the distribution declared in respect of the fourth quarter of 2013. We reached the third target distribution in connection with the distribution declared in respect of the second quarter of 2014. Our payment of IDRs as reported in distributions to unitholders – general partner in the statement of partners' capital during the years ended December 31 follow. Year ended December 31, 2015 2014 2013 (In thousands) IDR payments $ 6,743 $ 2,326 $ — Our general partner was not entitled to receive IDR payments prior to the distribution declared and paid in respect of the fourth quarter of 2013 based on the amount of the distributions declared and paid per common and subordinated unit. For the purposes of calculating net income attributable to general partner, the financial impact of IDRs is recognized in respect of the quarter for which the distributions were declared. For the purposes of calculating distributions to unitholders in the statements of partners' capital and cash flows, IDR payments are recognized in the quarter in which they are paid.

EARNINGS PER UNIT

EARNINGS PER UNIT	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
EARNINGS PER UNIT	EARNINGS PER UNIT The following table details the components of (loss) earnings per limited partner unit. Year ended December 31, 2015 2014 2013 (In thousands, except per-unit amounts) Numerator for basic and diluted EPU: Allocation of net (loss) income among limited partner interests: Net (loss) income attributable to common units $ (125,437 ) $ (16,324 ) $ 23,227 Net (loss) income attributable to subordinated units (70,173 ) (10,793 ) 19,322 Net (loss) income attributable to limited partners $ (195,610 ) $ (27,117 ) $ 42,549 Denominator for basic and diluted EPU: Weighted-average common units outstanding – basic 39,217 33,311 26,951 Effect of nonvested phantom units — — 150 Weighted-average common units outstanding – diluted 39,217 33,311 27,101 Weighted-average subordinated units outstanding – basic and diluted 24,410 24,410 24,410 (Loss) earnings per limited partner unit: Common unit – basic $ (3.20 ) $ (0.49 ) $ 0.86 Common unit – diluted $ (3.20 ) $ (0.49 ) $ 0.86 Subordinated unit – basic and diluted $ (2.88 ) $ (0.44 ) $ 0.79 During the years ended December 31, 2015 and 2014, we excluded 109,201 and 231,875 units, respectively, in our calculation of the effect of nonvested phantom units because they were anti-dilutive. There were no anti-dilutive units during for the year ended December 31, 2013

UNIT-BASED COMPENSATION

UNIT-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
UNIT-BASED COMPENSATION	UNIT-BASED COMPENSATION SMLP Long-Term Incentive Plan. The SMLP Long-Term Incentive Plan (the "SMLP LTIP") provides for equity awards to eligible officers, employees, consultants and directors of our general partner and its affiliates, thereby linking the recipients' compensation directly to SMLP’s performance. The SMLP LTIP is administered by our general partner's board of directors, though such administration function may be delegated to a committee appointed by the board. A total of 5.0 million common units was reserved for issuance pursuant to and in accordance with the SMLP LTIP. As of December 31, 2015 , approximately 4.4 million common units remained available for future issuance. The SMLP LTIP provides for the granting, from time to time, of unit-based awards, including common units, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Grants are made at the discretion of the board of directors or compensation committee of our general partner. The administrator of the SMLP LTIP may make grants under the SMLP LTIP that contain such terms, consistent with the SMLP LTIP, as the administrator may determine are appropriate, including vesting conditions. The administrator of the SMLP LTIP may, in its discretion, base vesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the SMLP LTIP) or as otherwise described in an award agreement. Termination of employment prior to vesting will result in forfeiture of the awards, except in limited circumstances as described in the plan documents. Units that are canceled or forfeited will be available for delivery pursuant to other awards. The following table presents phantom and restricted unit activity: Units Weighted-average grant date fair value Nonvested phantom and restricted units, January 1, 2013 131,558 $ 20.00 Phantom and restricted units granted 156,165 26.33 Phantom units forfeited (4,041 ) 25.99 Nonvested phantom and restricted units, December 31, 2013 283,682 23.41 Phantom units granted 136,867 42.32 Phantom and restricted units vested (61,917 ) 25.33 Phantom units forfeited (22,430 ) 25.56 Nonvested phantom units, December 31, 2014 336,202 30.61 Phantom units granted 289,735 29.21 Phantom units vested (229,497 ) 27.66 Phantom units forfeited (16,529 ) 35.09 Nonvested phantom units, December 31, 2015 379,911 $ 31.13 A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. Distribution equivalent rights for each phantom unit provide for a lump sum cash amount equal to the accrued distributions from the grant date to be paid in cash upon the vesting date. A restricted unit is a common limited partner unit that is subject to a restricted period during which the unit remains subject to forfeiture. The phantom units granted in connection with the IPO vested on the third anniversary of the IPO. All other phantom units granted to date vest ratably over a three -year period. Grant date fair value is determined based on the closing price of our common units on the date of grant multiplied by the number of phantom units awarded to the grantee. Holders of all phantom units granted to date are entitled to receive distribution equivalent rights for each phantom unit, providing for a lump sum cash amount equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. Upon vesting, phantom unit awards may be settled, at our discretion, in cash and/or common units, but the current intention is to settle all phantom unit awards with common units. The restricted units granted in 2013 maintained the vesting provisions of the share-based compensation awards they replaced, each of which had an original vesting period of four years. As of December 31, 2015 , the unrecognized unit-based compensation related to the SMLP LTIP was $5.5 million . Incremental unit-based compensation will be recorded over the remaining vesting period of approximately 1.17 years . Due to the limited and immaterial forfeiture history associated with the grants under the SMLP LTIP, no forfeitures were assumed in the determination of estimated compensation expense. Unit-based compensation recognized in general and administrative expense related to awards under the SMLP LTIP follows. Year ended December 31, 2015 2014 2013 (In thousands) SMLP LTIP unit-based compensation $ 6,174 $ 4,696 $ 2,999 SMP Net Profits Interests. In connection with the formation of Summit Investments in 2009, up to 7.5% of total membership interests were authorized for issuance. SMP Net Profits Interests were granted through January 2012. Each grant vests ratably over five years and provides for accelerated vesting in certain limited circumstances. Summit Investments valued the SMP Net Profits Interests utilizing an option pricing method, which modeled membership interests as call options on the underlying equity value of Summit Investments and considered the rights and preferences of each class of equity to allocate a fair value to each class. Summit Investments retained the SMP Net Profits Interests and, as such, they are not reflected in SMLP's financial statements subsequent to the IPO, except as noted below. Due to common control, we recognized the SMP Net Profits Interests' noncash compensation expense that had been allocated to the contributed subsidiaries prior to their respective drop down date. Unit-based compensation recognized in general and administrative expense related to the SMP Net Profits Interests was as follows: Year ended December 31, 2015 2014 2013 (In thousands) SMP net profits interests unit-based compensation $ 85 $ 340 $ 830 DFW Net Profits Interests . In connection with the formation of DFW Midstream in 2009, up to 5% of DFW Midstream's total membership interests were authorized for issuance (the "DFW Net Profits Interests"). Grants were made in 2009 and 2010. Each grant vested ratably over four years and provided for accelerated vesting in certain limited circumstances. The DFW Net Profits Interests were valued utilizing an option pricing method, which modeled membership interests as call options on the underlying equity value of DFW Midstream and considered the rights and preferences of each class of equity to allocate a fair value to each class. Beginning in October 2012 and continuing into April 2013, we entered into a series of repurchases with the remaining seven holders of the then-outstanding DFW Net Profits Interests whereby we exchanged $12.2 million for their vested DFW Net Profits Interests and 7,393 SMLP restricted units for their unvested DFW Net Profits Interests. The repurchase prices were determined by valuing the vested and unvested net profits interests in relation to the enterprise value of DFW Midstream and represented fair value at the dates of repurchase. Upon the conclusion of these repurchase transactions, there were no remaining or outstanding DFW Net Profits Interests.

RELATED-PARTY TRANSACTIONS

RELATED-PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
RELATED-PARTY TRANSACTIONS	RELATED-PARTY TRANSACTIONS Acquisitions. See Notes 1, 8 and 15 for disclosure of the Polar and Divide Drop Down, the Red Rock Drop Down, the Bison Drop Down and the funding of those transactions. Reimbursement of Expenses from General Partner. Our general partner and its affiliates do not receive a management fee or other compensation in connection with the management of our business, but will be reimbursed for expenses incurred on our behalf. Under our partnership agreement, we reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our general partner's employees and executive officers who perform services necessary to run our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Due to affiliate on the consolidated balance sheet represents the payables to our general partner for expenses incurred by it and paid on our behalf. Expenses incurred by the general partner and reimbursed by us under our partnership agreement were as follows: Year ended December 31, 2015 2014 2013 (In thousands) Operation and maintenance expense $ 21,537 $ 19,782 $ 14,323 General and administrative expense 21,116 22,370 18,662 Expenses Incurred by Summit Investments. Prior to the Polar and Divide Drop Down, the Red Rock Drop Down and the Bison Drop Down, Summit Investments incurred: • certain support expenses and capital expenditures on behalf of the contributed subsidiaries. These transactions were settled periodically through membership interests prior to the respective drop down; • interest expense that was related to capital projects for the contributed subsidiaries. As such, the associated interest expense was allocated to the respective contributed subsidiary's capital projects as a noncash contribution and capitalized into the basis of the asset; and • SMP Net Profits Interests accounted for as compensatory awards. As such, the annual expense associated with the SMP Net Profits was allocated to the respective contributed subsidiary and is reflected in general and administrative expenses in the statement of operations.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES Operating Leases. We and Summit Investments lease certain office space to support our operations. We have determined that our leases are operating leases. We recognize total rent expense incurred or allocated to us in general and administrative expenses. Rent expense related to operating leases, including rent expense incurred on our behalf and allocated to us, was as follows: Year ended December 31, 2015 2014 2013 (In thousands) Rent expense $ 1,990 $ 1,786 $ 1,495 Future minimum lease payments for the Partnership's operating leases are immaterial. Environmental Matters. There are no material liabilities related to environmental remediation costs, arising from claims, assessments, litigation, fines, or penalties and other sources in the accompanying financial statements at December 31, 2015 or December 31, 2014. However, we can provide no assurance that significant costs and liabilities will not be incurred in the future. We are currently not aware of any material contingent liabilities that exist with respect to environmental matters. Legal Proceedings. The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims or those arising in the normal course of business would not individually or in the aggregate have a material adverse effect on the Partnership's financial position or results of operations.

ACQUISITIONS AND DROP DOWN TRAN

ACQUISITIONS AND DROP DOWN TRANSACTIONS	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions and Drop Down Transactions	ACQUISITIONS AND DROP DOWN TRANSACTIONS Polar and Divide. On May 18, 2015, SMLP acquired the Polar and Divide system, a crude oil and produced water gathering system, including under-development transmission pipelines, located in North Dakota from a subsidiary of Summit Investments, subject to customary working capital and capital expenditures adjustments. We funded the initial combined purchase price of $290.0 million with (i) $92.5 million of borrowings under SMLP’s revolving credit facility and (ii) the issuance of $193.4 million of SMLP common units and $4.1 million of general partner interests to SMLP’s general partner in connection with the May 2015 Equity Offering. In July 2015, we received $4.3 million of cash from a subsidiary of Summit Investments as payment in full for working capital and capital expenditure adjustments. Summit Investments accounted for its purchase of Meadowlark Midstream, the entity that Polar Midstream was carved out of, under the acquisition method of accounting, whereby the various gathering systems' identifiable tangible and intangible assets acquired and liabilities assumed were recorded based on their fair values as of initial acquisition on February 15, 2013. Their fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete the system. We recognized the acquisition of Polar Midstream at Summit Investments' historical cost of construction and fair value of assets and liabilities at acquisition, which reflected its fair value accounting for the acquisition of Meadowlark Midstream, due to common control. The fair values of the assets acquired and liabilities assumed as of February 15, 2013, were as follows (in thousands): Purchase price assigned to Polar Midstream $ 216,105 Current assets $ 368 Property, plant, and equipment 9,755 Other noncurrent assets 7,201 Total assets acquired 17,324 Current liabilities 4,592 Total liabilities assumed $ 4,592 Net identifiable assets acquired 12,732 Goodwill $ 203,373 We believe that the goodwill recorded represents the incremental value of future cash flow potential attributed to estimated future gathering services within the Williston Basin. Red Rock Gathering System. On March 18, 2014, SMLP acquired Red Rock Gathering, a natural gas gathering and processing system located in Colorado and Utah, from a subsidiary of Summit Investments, subject to customary working capital adjustments. In October 2012, Summit Investments acquired ETC Canyon Pipeline, LLC ("Canyon") and contributed the Canyon gathering and processing assets to Red Rock Gathering, a newly formed, wholly owned subsidiary of Summit Investments. The Partnership paid total cash consideration of $307.9 million , comprising $305.0 million at the date of acquisition and $2.9 million of working capital adjustments that were recognized in due to affiliate as of December 31, 2014 and settled in February 2015. The acquisition of Red Rock Gathering was funded with the net proceeds from an offering of common units in March 2014, $100.0 million of borrowings under our revolving credit facility and cash on hand. Because of the common control aspects in the drop down transaction, the Red Rock Gathering acquisition was deemed a transaction between entities under common control and, as such, was accounted for on an “as-if pooled” basis for all periods in which common control existed. SMLP’s financial results retrospectively include Red Rock Gathering’s financial results for all periods ending after October 23, 2012, the date Summit Investments acquired its interests, and before March 18, 2014. In 2014, we identified and wrote off the balance associated with a working capital adjustment received after the purchase accounting measurement period closed for Summit Investments' acquisition of Red Rock Gathering. This write off was recognized as a $1.2 million increase to gathering services and other fees for the year ended December 31, 2014. Lonestar Assets. DFW Midstream completed the acquisition of certain natural gas gathering assets located in the Barnett Shale Play ("Lonestar") from Texas Energy Midstream, L.P. ("TEM") for $10.9 million on September 30, 2014. The Lonestar assets gather natural gas under two long-term, fee-based contracts. SMLP is accounting for the purchase under the acquisition method of accounting. As of September 30, 2014, we preliminarily assigned the full purchase price to property, plant and equipment. During the fourth quarter of 2014, we received additional information from TEM and finalized the purchase price allocation. Bison Gas Gathering System. On February 15, 2013, Summit Investments acquired BTE. On June 4, 2013, a subsidiary of Summit Investments entered into a purchase and sale agreement with SMLP whereby SMLP acquired the Bison Gas Gathering system. The Bison Gas Gathering system was carved out from Meadowlark Midstream and primarily gathers associated natural gas production from customers operating in Mountrail and Burke counties in North Dakota under long-term contracts ranging from five years to 15 years . The weighted-average life of the acquired contracts was 12 years upon acquisition. Summit Investments accounted for its purchase of BTE (the "BTE Transaction") under the acquisition method of accounting, whereby the various gathering systems' identifiable tangible and intangible assets acquired and liabilities assumed were recorded based on their fair values as of February 15, 2013. The intangible assets that were acquired are composed of gas gathering agreement contract values and rights-of-way easements. Their fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete the system. Because the Bison Drop Down was executed between entities under common control, SMLP recognized the acquisition of the Bison Gas Gathering system at historical cost which reflected Summit Investments fair value accounting for the BTE Transaction. Furthermore, due to the common control aspect, the Bison Drop Down was accounted for by SMLP on an “as-if pooled” basis for all periods in which common control existed. Common control began on February 15, 2013 concurrent with the BTE Transaction. The fair values of the assets acquired and liabilities assumed as of February 15, 2013, were as follows (in thousands): Purchase price assigned to Bison Gas Gathering system $ 303,168 Current assets $ 5,705 Property, plant, and equipment 85,477 Intangible assets 164,502 Other noncurrent assets 2,187 Total assets acquired 257,871 Current liabilities 6,112 Other noncurrent liabilities 2,790 Total liabilities assumed $ 8,902 Net identifiable assets acquired 248,969 Goodwill $ 54,199 The Bison Drop Down closed on June 4, 2013. The total acquisition purchase price of $248.9 million was funded with $200.0 million of borrowings under SMLP’s revolving credit facility and the issuance of $47.9 million of SMLP common units to Summit Investments and $1.0 million of general partner interests to SMLP’s general partner. Summit Investments had a net investment in the Bison Gas Gathering system of $303.2 million and received total consideration of $248.9 million from SMLP. As a result, SMLP recognized a capital contribution from Summit Investments for the contribution of net assets in excess of consideration paid. Mountaineer Midstream. We completed the Mountaineer Acquisition on June 21, 2013 for $210.0 million cash consideration. The Mountaineer Midstream natural gas gathering and compression assets are located in the Appalachian Basin which includes the Marcellus Shale formation primarily in Doddridge and Harrison counties in northern West Virginia. The Mountaineer Midstream system consists of newly constructed, high-pressure gas gathering pipelines, certain rights-of-way associated with the pipeline, and two compressor stations. The assets gather natural gas under a long-term, fee-based contract with Antero Resources Corp. ("Antero"). The life of the acquired contract was 13 years upon acquisition. The Mountaineer Acquisition was funded with $110.0 million of borrowings under the Partnership's revolving credit agreement and the issuance of $100.0 million of common and general partner interests to a subsidiary of Summit Investments. For the year ended December 31, 2013, SMLP recorded $9.6 million of revenue and $2.3 million of net income related to Mountaineer Midstream. SMLP accounted for the Mountaineer Acquisition under the acquisition method of accounting. As of June 30, 2013, we preliminarily assigned the full $210.0 million purchase price to property plant and equipment. During the third quarter of 2013, we received additional information and, as a result, preliminarily assigned $158.3 million of the purchase price to property, plant and equipment, $27.1 million to contract intangibles, $6.5 million to rights-of-way and $18.1 million to goodwill. During the fourth quarter of 2013, we received additional information from the seller and finalized the purchase price allocation. The final fair values of the assets acquired and liabilities assumed as of June 21, 2013, were as follows (in thousands): Purchase price assigned to Mountaineer Midstream $ 210,000 Property, plant, and equipment $ 163,661 Gas gathering agreement contract intangibles 24,019 Rights-of-way 6,109 Total assets acquired 193,789 Total liabilities assumed $ — Net identifiable assets acquired 193,789 Goodwill $ 16,211 Subsequent Event. On February 25, 2016, the Partnership signed the Contribution Agreement to acquire the 2016 Drop Down Assets. These assets include certain natural gas, crude oil and produced water gathering systems located in the Utica Shale, the Williston Basin and the Denver-Julesburg Basin as well as joint venture interests in a natural gas gathering system and a condensate stabilization facility, both located in the Utica Shale. The consideration to be paid by the Partnership to SMP Holdings for the 2016 Drop Down Assets will consist of (i) a cash payment to SMP Holdings at Initial Close of $360.0 million (the “Initial Payment”) which will be funded with borrowings under the Partnership's revolving credit facility and (ii) a deferred payment in 2020 (the “Deferred Payment”). The Deferred Payment will be equal to: • six-and-one-half ( 6.5 ) multiplied by the average adjusted EBITDA, as defined in the Contribution Agreement, of the 2016 Drop Down Assets for 2018 and 2019; • less the Initial Payment; • less all capital expenditures incurred for the 2016 Drop Down Assets between the Initial Close and December 31, 2019; • plus all adjusted EBITDA from the 2016 Drop Down Assets between the Initial Close and December 31, 2019. At the discretion of the board of directors of our general partner, the Deferred Payment can be paid in cash, SMLP common units or a combination thereof. The present value of the Deferred Payment will be reflected as a liability on our balance sheet until paid. We currently expect that the Deferred Payment will be financed with a combination of (i) net proceeds from the sale of common units by us, (ii) the net proceeds from the issuance of senior unsecured debt by us, (iii) borrowings under our revolving credit facility and/or (iv) other internally generated sources of cash. Because of the common control aspects in a drop down transaction, the 2016 Drop Down is expected to be deemed a transaction between entities under common control and, as such, will be accounted for on an “as if pooled” basis for all periods in which common control existed. Upon closing the 2016 Drop Down on the Initial Close, SMLP’s financial results will retrospectively include the combined financial results of the 2016 Drop Down Assets for all common-control periods. Supplemental Disclosures – As-If Pooled Basis. As a result of accounting for our drop down transactions similar to a pooling of interests, our historical financial statements and those of Polar Midstream, Red Rock Gathering and the Bison Gas Gathering system have been combined to reflect the historical operations, financial position and cash flows from the date common control began. Revenues and net income for the previously separate entities and the combined amounts, as presented in these consolidated financial statements follow. Year ended December 31, 2015 2014 2013 (In thousands) SMLP revenues $ 358,046 $ 338,941 $ 241,089 Polar and Divide revenues (1) 13,273 22,449 3,893 Red Rock Gathering revenues (1) 11,313 50,114 Bison Gas Gathering system revenues (1) 28,590 Combined revenues $ 371,319 $ 372,703 $ 323,686 SMLP net (loss) income $ (192,212 ) $ (23,992 ) $ 43,584 Polar and Divide net income (loss) (1) 5,403 6,430 (467 ) Red Rock Gathering net income (1) 2,828 9,668 Bison Gas Gathering system net income (1) 52 Combined net (loss) income $ (186,809 ) $ (14,734 ) $ 52,837 __________ (1) Results are fully reflected in SMLP's revenues and net income on the date common control began, see Note 1. Unaudited Pro Forma Financial Information. The following unaudited pro forma financial information assumes that: • The acquisition of the Bison Gas Gathering system and Mountaineer Midstream occurred on January 1, 2012. The pro forma results for Bison Midstream and Mountaineer Midstream were derived from revenues and net income in 2013. • Pro forma net income for the year ended December 31, 2013 has been adjusted to remove the impact of $2.5 million of nonrecurring transaction costs associated with the acquisitions of Bison Midstream and Mountaineer Midstream. • Pro forma adjustments in 2013 also reflect the impact of 4,661,547 common unit issuance and the general partner capital contribution to maintain its 2% general partner interest to fund the acquisition of Bison Midstream and Mountaineer Midstream. • Pro forma adjustments in 2013 also reflect the impact of $310.0 million of incremental borrowings on our revolving credit facility for the Bison Midstream and Mountaineer Midstream acquisitions and incremental depreciation and amortization expense associated with the acquired property, plant and equipment and contract intangibles as a result of the application of fair value accounting for Bison Midstream. • Pro forma adjustments for Polar and Divide are not required because the system was not in service prior to common control beginning in February 2013. • The acquisition of the Lonestar assets is immaterial for pro forma purposes and as such has not been reflected below. Year ended December 31, 2013 (In thousands, except for per-unit amounts) Total Bison Midstream and Mountaineer Midstream revenues included in consolidated revenues $ 87,196 Total Bison Midstream and Mountaineer Midstream net loss included in consolidated net income (457 ) Pro forma total revenues $ 335,837 Pro forma net income 46,904 Pro forma common EPU - basic and diluted $ 0.78 Pro forma subordinated EPU - basic and diluted 0.78 The unaudited pro forma financial information presented above is not necessarily indicative of (i) what our financial position or results of operations would have been if the acquisitions of Bison Midstream and Mountaineer Midstream had occurred on January 1, 2012, or (ii) what SMLP’s financial position or results of operations will be for any future periods.

UNAUDITED QUARTERLY FINANCIAL D

UNAUDITED QUARTERLY FINANCIAL DATA	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Unaudited Quarterly Financial Data	UNAUDITED QUARTERLY FINANCIAL DATA Summarized information on the consolidated results of operations for each of the quarters during the two-year period ended December 31, 2015 , follows. Quarter ended December 31, 2015 Quarter ended September 30, 2015 Quarter ended June 30, 2015 Quarter ended March 31, 2015 (In thousands, except per-unit amounts) Total revenues (1) $ 102,601 $ 106,557 $ 80,944 $ 81,217 Net (loss) income attributable to SMLP (2)(3) $ (220,468 ) $ 23,604 $ 2,985 $ 1,667 Less net (loss) income attributable to general partner, including IDRs (2,469 ) 2,408 1,891 1,568 Net (loss) income attributable to limited partners $ (217,999 ) $ 21,196 $ 1,094 $ 99 (Loss) earnings per limited partner unit: Common unit – basic $ (3.28 ) $ 0.32 $ 0.05 $ 0.00 Common unit – diluted $ (3.28 ) $ 0.32 $ 0.05 $ 0.00 Subordinated unit – basic and diluted $ (3.28 ) $ 0.32 $ (0.03 ) $ 0.00 __________ (1) Retrospectively adjusted for the impact of the Polar and Divide Drop Down and reclassification of certain revenues for Bison Midstream. (2) In the quarter ended December 31, 2015, net loss attributable to SMLP includes $ 248.9 million of goodwill impairments and $ 1.6 million of long-lived asset impairments. (3) In the quarter ended September 30, 2015, net income attributable to SMLP includes $ 7.7 million of long-lived asset impairments. Quarter ended December 31, 2014 Quarter ended September 30, 2014 Quarter ended June 30, 2014 Quarter ended March 31, 2014 (In thousands, except per-unit amounts) Total revenues (1) $ 108,230 $ 90,044 $ 90,649 $ 83,780 Net (loss) income attributable to SMLP (2) $ (37,686 ) $ 6,113 $ 4,036 $ 3,545 Less net (loss) income attributable to general partner, including IDRs 689 1,204 801 431 Net (loss) income attributable to limited partners $ (38,375 ) $ 4,909 $ 3,235 $ 3,114 (Loss) earnings per limited partner unit: Common unit – basic $ (0.65 ) $ 0.08 $ 0.05 $ 0.08 Common unit – diluted $ (0.65 ) $ 0.08 $ 0.05 $ 0.08 Subordinated unit – basic and diluted $ (0.65 ) $ 0.08 $ 0.05 $ 0.02 __________ (1) Retrospectively adjusted for the impact of the Polar and Divide Drop Down and reclassification of certain revenues for Bison Midstream. (2) In the quarter ended December 31, 2014, net loss attributable to SMLP includes $54.2 million of goodwill impairment and $5.5 million of long-lived asset impairment. The amounts for total revenues as originally filed on the respective 2015 and 2014 quarterly reports on Form 10-Q have been retrospectively adjusted for the impact of the Polar and Divide Drop Down and reclassification of certain revenues for Bison Midstream. There was no impact on net income attributable to partners or EPU. A reconciliation of total revenues follows. Quarter ended September 30, 2015 Quarter ended June 30, 2015 Quarter ended March 31, 2015 (In thousands) Total revenues as originally reported $ 103,249 $ 77,274 $ 68,579 Bison revenue reclass 3,308 3,670 4,056 Polar and Divide Drop Down — — 8,582 Total revenues $ 106,557 $ 80,944 $ 81,217 Quarter ended September 30, 2014 Quarter ended June 30, 2014 Quarter ended March 31, 2014 (In thousands) Total revenues as originally reported $ 79,030 $ 80,796 $ 76,202 Bison revenue reclass 5,260 4,665 4,399 Polar and Divide Drop Down 5,754 5,188 3,179 Total revenues $ 90,044 $ 90,649 $ 83,780

SUMMARY OF SIGNIFICANT ACCOUN23

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Basis of Presentation	Presentation and Consolidation. We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP"). These principles are established by the Financial Accounting Standards Board. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, including fair value measurements, the reported amounts of revenue and expense, and the disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents. Cash and cash equivalents include temporary cash investments with original maturities of three months or less.
Accounts Receivable	Accounts Receivable. Accounts receivable relate to gathering and other services provided to our customers and other counterparties. We evaluate the collectability of accounts receivable and the need for an allowance for doubtful accounts based on customer-specific facts and circumstances. To the extent we doubt the collectability of a specific customer or counterparty receivable, we recognize an allowance for doubtful accounts.
Other Current Assets	Other Current Assets. Other current assets primarily consist of the current portion of prepaid expenses that are charged to expense over the period of benefit or the life of the related contract.
Property, Plant and Equipment	Property, Plant, and Equipment. We record property, plant, and equipment at historical cost of construction or fair value of the assets at acquisition. We capitalize expenditures that extend the useful life of an asset or enhance its productivity or efficiency from its original design over the expected remaining period of use. For maintenance and repairs that do not add capacity or extend the useful life of an asset, we recognize expenditures as an expense as incurred. We capitalize project costs incurred during construction, including interest on funds borrowed to finance the construction of facilities, as construction in progress. We record depreciation on a straight-line basis over an asset’s estimated useful life. We base our estimates for useful life on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Estimates of useful lives follow. Useful lives (In years) Gathering and processing systems and related equipment 30 Other 4-15 Construction in progress is depreciated consistent with its applicable asset class once it is placed in service. Land and line fill are not depreciated. We base an asset’s carrying value on estimates, assumptions and judgments for useful life and salvage value. Upon sale, retirement or other disposal, we remove the carrying value of an asset and its accumulated depreciation from our balance sheet and recognize the related gain or loss, if any. Accrued capital expenditures are reflected in trade accounts payable.
Asset Retirement Obligations	Asset Retirement Obligations. We record a liability for asset retirement obligations only if and when a future asset retirement obligation with a determinable life is identified. For identified asset retirement obligations, we then evaluate whether the expected date and related costs of retirement can be estimated. We have concluded that our gathering and processing assets have an indeterminate life because they are owned and will operate for an indeterminate period when properly maintained. Because we did not have sufficient information to reasonably estimate the amount or timing of such obligations and we have no current plan to discontinue use of any significant assets, we did not provide for any asset retirement obligations as of December 31, 2015 or 2014.
Amortizing Intangibles	Amortizing Intangibles. Upon the acquisition of DFW Midstream, certain of its gas gathering contracts were deemed to have above-market pricing structures while another was deemed to have pricing that was below market. We have recognized the above-market contracts as favorable gas gathering contracts. We have recognized the below-market contract as the unfavorable gas gathering contract and included it in other noncurrent liabilities. We amortize these contracts on a units-of-production basis over the contract's estimated useful life. We define useful life as the period over which the contract is expected to contribute to our future cash flows. These contracts have original terms ranging from 10 years to 20 years. We recognize the amortization expense associated with these contracts in other revenues. We amortize all other gas gathering contracts, or contract intangibles, over the period of economic benefit based upon expected revenues over the life of the contract. The useful life of these contracts ranges from 10 years to 25 years. We recognize the amortization expense associated with these contracts in depreciation and amortization expense. We have rights-of-way associated with city easements and easements granted within existing rights-of-way. We amortize these intangible assets over the shorter of the contractual term of the rights-of-way or the estimated useful life of the gathering system. The contractual terms of the rights-of-way range from 20 years to 30 years. We recognize the amortization expense associated with rights-of-way assets in depreciation and amortization expense.
Goodwill	Goodwill. Goodwill represents consideration paid in excess of the fair value of the net identifiable assets acquired in a business combination. We evaluate goodwill for impairment annually on September 30. We also evaluate goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We test goodwill for impairment using a two-step quantitative test. In the first step, we compare the fair value of the reporting unit to its carrying value, including goodwill. To estimate the fair value of the reporting units under step one, we utilize two valuation methodologies: the market approach and the income approach. Both of these approaches incorporate significant estimates and assumptions to calculate enterprise fair value for a reporting unit. The most significant estimates and assumptions inherent within these two valuation methodologies are: (i) determination of the weighted-average cost of capital; (ii) the selection of guideline public companies; (iii) market multiples; (iv) weighting of the income and market approaches; (v) growth rates; (vi) commodity prices; and (vi) the expected levels of throughput volume gathered. Changes in these and other assumptions could materially affect the estimated amount of fair value for any of our reporting units. If the reporting unit’s fair value exceeds its carrying amount, we conclude that the goodwill of the reporting unit has not been impaired and no further work is performed. If we determine that the reporting unit’s carrying value exceeds its fair value, we proceed to step two. In step two, we compare the carrying value of the reporting unit to its implied fair value. Significant estimates and assumptions utilized in the determination of a reporting unit's implied fair value are based on a variety of factors specific to a given reporting unit's individual assets and liabilities as well as market and industry considerations. If we determine that the carrying amount of a reporting unit's goodwill exceeds its implied fair value, we recognize the excess of the carrying value over the implied fair value as an impairment loss.
Other Noncurrent Assets	Other Noncurrent Assets. Other noncurrent assets primarily consist of external costs incurred in connection with the issuance of our senior notes and the closing of our revolving credit facility and related amendments. We capitalize and then amortize these deferred loan costs over the life of the respective debt instrument. We recognize amortization of deferred loan costs in interest expense.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets. We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset (except goodwill) is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If we conclude that an asset's carrying value will not be recovered through future cash flows, we recognize an impairment loss on the long-lived asset equal to the amount by which the carrying value exceeds its fair value. We determine fair value using either a market-based approach or an income-based approach. We discuss our policy for goodwill impairment above.
Derivative Contracts	Derivative Contracts. We have commodity price exposure related to our sale of the physical natural gas we retain from our DFW Midstream customers and our procurement of electricity to operate DFW Midstream's electric-drive compression assets. Our gas gathering agreements with our DFW Midstream customers permit us to retain a certain quantity of natural gas that we gather to offset the power costs we incur to operate these electric-drive compression assets. We manage this direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices on the Waha Hub Index. Because we also sell our retainage gas at prices that are based on the Waha Hub Index, we have effectively fixed the relationship between our compression electricity expense and natural gas retainage sales. Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. We have designated these contracts as normal under the normal purchase and sale exception under the accounting standards for derivatives. We do not enter into risk management contracts for speculative purposes.
Fair Value of Financial Instruments	Fair Value of Financial Instruments. The fair-value-measurement standard under GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which the inputs are observable. The three levels of the fair value hierarchy are as follows: • Level 1. Inputs represent quoted prices in active markets for identical assets or liabilities; • Level 2. Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs); and • Level 3. Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an internally developed present value of future cash flows model that underlies management's fair value measurement).
Commitments and Contingencies	Commitments and Contingencies. We record accruals for loss contingencies when we determine that it is probable that a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events.
Revenue Recognition	Revenue Recognition. We generate the majority of our revenue from the gathering, treating and processing services that we provide to our customers. We also generate revenue from our marketing of natural gas, NGLs and condensate. We realize revenues by receiving fees from our customers or by selling the residue natural gas, NGLs and condensate. We recognize revenue earned from fee-based gathering, treating and processing services in gathering services and related fees revenue. We also earn revenue from the sale of physical natural gas purchased from our customers under percentage-of-proceeds arrangements. These revenues are recognized in natural gas, NGLs and condensate sales with corresponding expense recognition for the producer's share of the proceeds in cost of natural gas and NGLs. We sell substantially all of the natural gas that we retain from our DFW Midstream customers to offset the power expenses of the electric-driven compression on the DFW Midstream system. We also sell condensate retained from our gathering services at Grand River. Revenues from the retainage of natural gas and condensate are recognized in natural gas, NGLs and condensate sales; the associated expense is included in operation and maintenance expense. Certain customers reimburse us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis, with the revenue component recognized in other revenues. 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 provide gathering and/or processing services principally under contracts that contain one or more of the following arrangements: • Fee-based arrangements. Under fee-based arrangements, we receive a fee or fees for one or more of the following services (i) natural gas gathering, treating, and/or processing and (ii) crude oil and/or produced water gathering. • Percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat the natural gas, process the natural gas and/or sell the natural gas to a third party for processing. We then remit to our producers an agreed-upon percentage of the actual proceeds received from sales of the residue natural gas and NGLs. Certain of these arrangements may also result in returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. The margins earned are directly related to the volume of natural gas that flows through the system and the price at which we are able to sell the residue natural gas and NGLs. Certain of our gathering and processing agreements provide for a monthly, quarterly or annual minimum volume commitment ("MVC"). Under these MVCs, our customers agree to ship and/or process a minimum volume of production on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contracted measurement period if its actual throughput volumes are less than its MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that contracted measurement period. We recognize customer billings for obligations under their MVCs as revenue when the obligations are billable under the contract and the customer does not have the right to utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods. We record customer billings for obligations under their MVCs as deferred revenue when the customer has the right to utilize shortfall payments to offset gathering or processing fees in subsequent periods. We recognize deferred revenue under these arrangements in revenue once all contingencies or potential performance obligations associated with the related volumes have either (i) been satisfied through the gathering or processing of future excess volume throughput, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the applicable gathering or processing agreement. We also recognize deferred revenue when it is determined that a given amount of MVC shortfall payments cannot be recovered by offsetting gathering or processing fees in subsequent contracted measurement periods. In making this determination, we consider both quantitative and qualitative facts and circumstances, including, but not limited to, contract terms, capacity of the associated pipeline or receipt point and/or expectations regarding future investment, drilling and production. We classify deferred revenue as a current liability for arrangements where the expiration of a customer's right to utilize shortfall payments is 12 months or less. We classify deferred revenue as noncurrent for arrangements where the expiration of the right to utilize shortfall payments and our estimate of its potential utilization is more than 12 months.
Unit-Based Compensation	Unit-Based Compensation. For awards of unit-based compensation, we determine a grant date fair value and recognize the related compensation expense in the statement of operations over the vesting period of the respective awards.
Income Taxes	Income Taxes. As a partnership, we are generally not subject to federal and state income taxes, except as noted below. However, our unitholders are individually responsible for paying federal and state income taxes on their share of our taxable income. Net income or loss for GAAP purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and the GAAP basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. In general, legal entities that are chartered, organized or conducting business in the state of Texas are subject to a franchise tax (the "Texas Margin Tax"). The Texas Margin Tax has the characteristics of an income tax because it is determined by applying a tax rate to a tax base that considers both revenues and expenses. Our financial statements reflect provisions for these tax obligations. In 2014, we elected to apply changes to the determination of cost of goods sold for the Texas Margin Tax which permits the use of accelerated depreciation allowed for federal income tax purposes.
Earnings Per Unit	Earnings Per Unit ("EPU"). We determine basic EPU by dividing the net income or loss that is attributed, in accordance with the net income and loss allocation provisions of our partnership agreement, to common and subordinated unitholders under the two-class method, after deducting (i) the general partner's 2% interest in net income or loss, (ii) any payment of IDRs and (iii) any net income or loss of contributed subsidiaries that is attributable to Summit Investments, by the weighted-average number of common and subordinated units outstanding. Diluted EPU reflects the potential dilution that could occur if securities or other agreements to issue common units, such as unit-based compensation, were exercised, settled or converted into common units and included in the weighted-average number of units outstanding. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted EPU calculation, the impact is reflected by applying the treasury stock method.
Comprehensive Income	Comprehensive Income. Comprehensive income is the same as net income (loss) for all periods presented.
Environmental Matters	Environmental Matters. We are subject to various federal, state and local laws and regulations relating to the protection of the environment. Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. We accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Such accruals are adjusted as further information develops or circumstances change. Recoveries of environmental remediation costs from other parties or insurers are recorded as assets when their receipt is deemed probable.
Recent Accounting Pronouncements	Recent Accounting Pronouncements. Accounting standard setters frequently issue new or revised accounting rules. We review new pronouncements to determine the impact, if any, on our financial statements. There are currently no recent pronouncements that have been issued that we believe may materially affect our financial statements, except as noted below. In May 2014, the FASB released a joint revenue recognition standard, Accounting Standards Update ("ASU") No. 2014-09 Revenue From Contracts With Customers (Topic 606) ("ASU 2014-09"). Under ASU 2014-09, revenue will be recognized under a five-step model: (i) identify the contract with the customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to performance obligations; and (v) recognize revenue when (or as) the Company satisfies a performance obligation. In its original form, ASU 2014-09 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016; early adoption was not permitted. In July 2015, the FASB reaffirmed the guidance in its April 2015 proposed ASU that defers for one year the effective date of the ASU 2014-09 for both public and nonpublic entities reporting under U.S. GAAP and allows early adoption as of the original effective date. We are currently in the process of evaluating the impact of this update. In April 2015, the FASB issued ASU No. 2015-03 Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). Under ASU 2015-03, entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. This presentation will result in debt issuance cost being presented the same way debt discounts have historically been handled. In August 2015, the FASB amended ASU 2015-03 to address the presentation and subsequent measurement of debt issuance costs related to line of credit (“LOC”) arrangements. The amendment added a paragraph that states that the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing deferred debt issuance costs ratably over the term of a LOC arrangement, regardless of whether there are outstanding borrowings under that LOC arrangement. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, and interim and annual periods thereafter. Early adoption is permitted. The adoption of this update will result in a reclassification from other noncurrent assets to long-term debt of the debt issuance costs associated with our senior notes. Debt issuance costs associated with our revolving credit facility will remain in other noncurrent assets. There will be no impact on interest expense, net income, earnings per unit or partners' capital. In September 2015, the FASB issued ASU No. 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). Under ASU 2015-16, an acquirer would be required to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Further, the acquirer must record in the financial statements for the same period, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Entities must also present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, and interim and annual periods thereafter. Early adoption is permitted. We are currently in the process of evaluating the impact of this update. In January 2016, the FASB issued ASU No. 2016-01 Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). Among other changes, the amendments in ASU 2016-01 supersede the guidance to classify equity securities with readily determinable fair values into different categories and require equity securities to be measured at fair value with changes in the fair value recognized through net income. They also simplify the impairment assessment of equity investments without readily determinable fair values and require use of the exit price notion when measuring the fair value of financial instruments for disclosure purposes. Under ASU 2016-01, an entity will be required to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments, to separately present financial assets and financial liabilities by measurement category and form of financial asset. ASU 2016-01 also clarifies that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 31, 2017. Early adoption is permissible, but limited in application. The adoption of this new update could impact the fair value we disclose for certain financial instruments but is not expected to impact amounts recognized in the consolidated financial statements.

ORGANIZATION, BUSINESS OPERAT24

ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION (Tables)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Reclassifications	The impact of these reclassifications, which had no impact on net (loss) income, total partners' capital or segment adjusted EBITDA, follows. Year ended December 31, 2014 2013 (In thousands) Gathering services and related fees $ 15,616 $ 16,805 Other revenues 3,952 10,068 Net impact on total revenues $ 19,568 $ 26,873 Cost of natural gas and NGLs $ 19,568 $ 26,873 Net impact on cost of natural gas and NGLs and total costs and expenses $ 19,568 $ 26,873

SUMMARY OF SIGNIFICANT ACCOUN25

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Useful lives of Property, Plant and Equipment	Useful lives (In years) Gathering and processing systems and related equipment 30 Other 4-15 Details on property, plant, and equipment follow. December 31, 2015 2014 (In thousands) Gathering and processing systems and related equipment $ 1,574,916 $ 1,459,585 Construction in progress 25,484 37,604 Land and line fill 9,339 9,964 Other 30,935 28,871 Total 1,640,674 1,536,024 Less accumulated depreciation 176,872 121,674 Property, plant, and equipment, net $ 1,463,802 $ 1,414,350

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Schedule of assets by reportable segment	Assets by reportable segment follow. December 31, 2015 2014 2013 (In thousands) Assets: Marcellus Shale $ 233,116 $ 243,884 $ 214,379 Williston Basin 563,952 709,888 645,014 Barnett Shale 416,586 428,935 431,578 Piceance Basin 797,057 872,437 876,969 Total reportable segment assets 2,010,711 2,255,144 2,167,940 Corporate 29,820 38,577 23,203 Total assets $ 2,040,531 $ 2,293,721 $ 2,191,143
Schedule of segment reporting information	Depreciation and amortization, including the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues, by reportable segment follows. Year ended December 31, 2015 2014 2013 (In thousands) Depreciation and amortization: Marcellus Shale $ 8,682 $ 7,648 $ 3,998 Williston Basin 26,280 22,491 16,669 Barnett Shale 16,392 16,601 14,961 Piceance Basin 45,018 40,965 35,527 Total reportable segment depreciation and amortization 96,372 87,705 71,155 Corporate 603 588 451 Total depreciation and amortization $ 96,975 $ 88,293 $ 71,606 Capital expenditures by reportable segment follow. Year ended December 31, 2015 2014 2013 (In thousands) Capital expenditures: Marcellus Shale $ 1,306 $ 33,866 $ 1,822 Williston Basin 90,234 139,422 99,983 Barnett Shale 6,875 14,567 29,534 Piceance Basin 19,263 32,505 50,709 Total reportable segment capital expenditures 117,678 220,360 182,048 Corporate 429 460 930 Total capital expenditures $ 118,107 $ 220,820 $ 182,978 Revenues by reportable segment follow. Year ended December 31, 2015 2014 2013 (In thousands) Revenues: Marcellus Shale $ 28,468 $ 22,694 $ 9,588 Williston Basin 85,887 104,471 81,501 Barnett Shale 88,042 93,001 105,324 Piceance Basin 168,922 152,537 127,273 Total reportable segment revenues and total revenues $ 371,319 $ 372,703 $ 323,686 Adjustments related to MVC shortfall payments by reportable segment follow. Year ended December 31, 2015 2014 2013 (In thousands) Adjustments related to MVC shortfall payments: Williston Basin $ 11,870 $ 10,743 $ 3,600 Barnett Shale (2,182 ) 628 1,030 Piceance Basin (21,590 ) 15,194 12,395 Total adjustments related to MVC shortfall payments $ (11,902 ) $ 26,565 $ 17,025 Segment adjusted EBITDA by reportable segment follows. Year ended December 31, 2015 2014 2013 (In thousands) Reportable segment adjusted EBITDA: Marcellus Shale $ 23,214 $ 15,940 $ 6,333 Williston Basin 47,010 31,551 17,350 Barnett Shale 59,526 60,528 69,473 Piceance Basin 104,467 107,953 80,941 Total reportable segment adjusted EBITDA $ 234,217 $ 215,972 $ 174,097
Schedule of counterparties accounting for more than 10% of total revenues	Counterparties accounting for more than 10% of total revenues were as follows: Year ended December 31, 2015 2014 2013 Percentage of total revenues (1): Counterparty A - Piceance 17 % 19 % 19 % Counterparty B - Piceance 16 % * * Counterparty C - Barnett Shale * * 14 % __________ (1) Includes recognition of revenue that was previously deferred in connection with minimum volume commitments (see Notes 2 and 7). * Less than 10%
Reconciliation of net income to adjusted EBITDA	A reconciliation of (loss) income before income taxes to total reportable segment adjusted EBITDA follows. Year ended December 31, 2015 2014 2013 (In thousands) Reconciliation of Income (loss) Before Income Taxes to Segment Adjusted EBITDA: (Loss) income before income taxes $ (187,485 ) $ (14,103 ) $ 53,566 Add: Allocated corporate expenses 23,772 11,065 8,773 Interest expense 48,616 40,159 19,173 Depreciation and amortization 96,975 88,293 71,606 Adjustments related to MVC shortfall payments (11,902 ) 26,565 17,025 Unit-based compensation 6,259 5,036 3,846 Loss on asset sales 42 442 113 Long-lived asset impairment 9,305 5,505 — Goodwill impairment 248,851 54,199 — Less: Interest income 2 4 5 Gain on asset sales 214 — — Impact of purchase price adjustment — 1,185 — Total reportable segment adjusted EBITDA $ 234,217 $ 215,972 $ 174,097

PROPERTY, PLANT, AND EQUIPMEN27

PROPERTY, PLANT, AND EQUIPMENT, NET (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Schedule of property, plant, and equipment, net	Useful lives (In years) Gathering and processing systems and related equipment 30 Other 4-15 Details on property, plant, and equipment follow. December 31, 2015 2014 (In thousands) Gathering and processing systems and related equipment $ 1,574,916 $ 1,459,585 Construction in progress 25,484 37,604 Land and line fill 9,339 9,964 Other 30,935 28,871 Total 1,640,674 1,536,024 Less accumulated depreciation 176,872 121,674 Property, plant, and equipment, net $ 1,463,802 $ 1,414,350
Schedule of long-lived asset impairments	Year ended December 31, 2015 2014 2013 (In thousands) Long-lived asset impairment: Williston Basin $ 7,554 $ — $ — Barnett Shale 531 5,505 — Piceance Basin 1,220 — —
Schedule of depreciation expense and capitalized interest	Depreciation expense and capitalized interest follow. Year ended December 31, 2015 2014 2013 (In thousands) Depreciation expense $ 55,685 $ 49,816 $ 37,313 Capitalized interest 3,137 3,778 6,255

AMORTIZING INTANGIBLE ASSETS 28

AMORTIZING INTANGIBLE ASSETS AND UNFAVORABLE GAS GATHERING CONTRACT (Tables)	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible assets and liabilities subject to amortization	Details regarding our intangible assets and the unfavorable gas gathering contract (included in other noncurrent liabilities), all of which are subject to amortization, follow. December 31, 2015 Useful lives (In years) Gross carrying amount Accumulated amortization Net (Dollars in thousands) Favorable gas gathering contracts 18.7 $ 24,195 $ (9,534 ) $ 14,661 Contract intangibles 12.5 426,464 (111,052 ) 315,412 Rights-of-way 25.2 125,922 (17,902 ) 108,020 Total intangible assets $ 576,581 $ (138,488 ) $ 438,093 Unfavorable gas gathering contract 10.0 $ 10,962 $ (6,077 ) $ 4,885 December 31, 2014 Useful lives (In years) Gross carrying amount Accumulated amortization Net (Dollars in thousands) Favorable gas gathering contracts 18.7 $ 24,195 $ (8,056 ) $ 16,139 Contract intangibles 12.5 426,464 (75,713 ) 350,751 Rights-of-way 24.7 123,581 (12,737 ) 110,844 Total intangible assets $ 574,240 $ (96,506 ) $ 477,734 Unfavorable gas gathering contract 10.0 $ 10,962 $ (5,385 ) $ 5,577
Recognized amortization expense in other revenues and cost and expenses	We recognized amortization expense in other revenues as follows: Year ended December 31, 2015 2014 2013 (In thousands) Amortization expense – favorable gas gathering contracts $ (1,478 ) $ (1,741 ) $ (2,078 ) Amortization expense – unfavorable gas gathering contract 692 797 1,046 We recognized amortization expense in costs and expenses as follows: Year ended December 31, 2015 2014 2013 (In thousands) Amortization expense – contract intangibles $ 35,339 $ 32,554 $ 28,654 Amortization expense – rights-of-way 5,165 4,979 4,607
Estimated aggregate annual amortization expected to be recognized	The estimated aggregate annual amortization expected to be recognized as of December 31, 2015 for each of the five succeeding fiscal years follows. Intangible assets Unfavorable gas gathering contract (In thousands) 2016 $ 42,301 $ 924 2017 41,152 1,047 2018 40,606 1,035 2019 40,852 1,045 2020 43,498 834

GOODWILL (Tables)

GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Rollforward of goodwill by reportable segment	A rollforward of goodwill by reportable segment and in total follows. Piceance Basin Williston Basin Marcellus Shale Total (In thousands) Goodwill, January 1, 2014 $ 45,478 $ 257,572 $ 16,211 $ 319,261 Goodwill impairment — (54,199 ) — (54,199 ) Goodwill, December 31, 2014 45,478 203,373 16,211 265,062 Goodwill impairment (45,478 ) (203,373 ) — (248,851 ) Goodwill, December 31, 2015 $ — $ — $ 16,211 $ 16,211 Accumulated goodwill impairments by reportable segment for those reporting units that have previously recognized goodwill follow. December 31, 2015 2014 2013 (In thousands) Accumulated goodwill impairment: Piceance Basin $ 45,478 $ — $ — Williston Basin 257,572 54,199 — Total accumulated goodwill impairment $ 303,050 $ 54,199 $ —

DEFERRED REVENUE (Tables)

DEFERRED REVENUE (Tables)	12 Months Ended
	Dec. 31, 2015
Deferred Revenue Disclosure [Abstract]
Rollforward of deferred revenue	A rollforward of current deferred revenue follows. Williston Basin Barnett Shale Piceance Basin Total current (In thousands) Current deferred revenue, January 1, 2014 $ — $ 1,555 $ — $ 1,555 Additions — 2,610 — 2,610 Less revenue recognized — 1,788 — 1,788 Current deferred revenue, December 31, 2014 — 2,377 — 2,377 Additions — 677 2,743 3,420 Less revenue recognized — 2,377 2,743 5,120 Current deferred revenue, December 31, 2015 $ — $ 677 $ — $ 677 A rollforward of noncurrent deferred revenue follows. Williston Basin Barnett Shale Piceance Basin Total noncurrent (In thousands) Noncurrent deferred revenue, January 1, 2014 $ 6,389 $ — $ 23,294 $ 29,683 Additions 10,743 — 14,813 25,556 Noncurrent deferred revenue, December 31, 2014 17,132 — 38,107 55,239 Additions 11,897 — 12,765 24,662 Less revenue recognized 27 — 34,388 34,415 Noncurrent deferred revenue, December 31, 2015 $ 29,002 $ — $ 16,484 $ 45,486 __________ (1) Noncurrent includes amounts recognized in connection with the Bison Drop Down.

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Schedule of debt and capital leases	Debt consisted of the following: December 31, 2015 2014 (In thousands) Summit Holdings variable rate senior secured revolving credit facility (2.93% at December 31, 2015 and 2.67% at December 31, 2014) due November 2018 $ 344,000 $ 208,000 Summit Holdings 5.50% Senior unsecured notes due August 2022 300,000 300,000 Summit Holdings 7.50% Senior unsecured notes due July 2021 300,000 300,000 Total long-term debt $ 944,000 $ 808,000
Schedule of maturities of long-term debt	The aggregate amount of our debt maturities during each of the years after December 31, 2015 are as follows: Debt (In thousands) 2016 $ — 2017 — 2018 344,000 2019 — 2020 — Thereafter 600,000 Total long-term debt $ 944,000

FINANCIAL INSTRUMENTS (Tables)

FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Summary of the estimated fair value of debt instruments	A summary of the estimated fair value of our debt financial instruments follows. December 31, 2015 December 31, 2014 Carrying value Estimated fair value (Level 2) Carrying value Estimated fair value (Level 2) (In thousands) Revolving credit facility $ 344,000 $ 344,000 $ 208,000 $ 208,000 5.5% Senior notes 300,000 224,000 300,000 281,750 7.5% Senior notes 300,000 257,000 300,000 306,750

PARTNERS' CAPITAL (Tables)

PARTNERS' CAPITAL (Tables)	12 Months Ended
	Dec. 31, 2015
Limited Partners' Capital Account [Line Items]
Schedule of partner units activity	A rollforward of the number of common limited partner, subordinated limited partner and general partner units follows. Common Subordinated General partner Total Units, January 1, 2013 24,412,427 24,409,850 996,320 49,818,597 Units issued to a subsidiary of Summit Investments in connection with the Bison Drop Down 1,553,849 — 31,711 1,585,560 Units issued to a subsidiary of Summit Investments in connection with the Mountaineer Acquisition 3,107,698 — 63,422 3,171,120 Net units issued under SMLP LTIP 5,892 — — 5,892 Units, January 1, 2014 29,079,866 24,409,850 1,091,453 54,581,169 Units issued in connection with the March Equity 2014 Offering 5,300,000 — 108,337 5,408,337 Net units issued under SMLP LTIP 46,647 — 861 47,508 Units, December 31, 2014 34,426,513 24,409,850 1,200,651 60,037,014 Units issued in connection with the May 2015 Equity Offering 7,475,000 — 152,551 7,627,551 Net units issued under SMLP LTIP 161,131 — 1,498 162,629 Units, December 31, 2015 42,062,644 24,409,850 1,354,700 67,827,194
Schedule of partnership target distributions	Total quarterly distribution per unit target amount Marginal percentage interest in distributions Unitholders General partner Minimum quarterly distribution $0.40 98.0% 2.0% First target distribution $0.40 up to $0.46 98.0% 2.0% Second target distribution above $0.46 up to $0.50 85.0% 15.0% Third target distribution above $0.50 up to $0.60 75.0% 25.0% Thereafter above $0.60 50.0% 50.0%
Details of cash distributions	Cash Distributions Paid and Declared. We paid the following per-unit distributions during the years ended December 31: Year ended December 31, 2015 2014 2013 Per-unit annual distributions to unitholders $ 2.270 $ 2.040 $ 1.725 Our payment of IDRs as reported in distributions to unitholders – general partner in the statement of partners' capital during the years ended December 31 follow. Year ended December 31, 2015 2014 2013 (In thousands) IDR payments $ 6,743 $ 2,326 $ —
Polar Midstream and Epping
Limited Partners' Capital Account [Line Items]
Calculation of capital contribution and its allocation to partners' capital	The calculation of the capital contribution and its allocation to partners' capital follow (dollars in thousands). Summit Investments' net investment in Polar Midstream and Epping $ 416,044 Total net cash consideration paid to a subsidiary of Summit Investments 285,677 Excess of acquired carrying value over consideration paid $ 130,367 Allocation of capital contribution: General partner interest $ 2,607 Common limited partner interest 80,079 Subordinated limited partner interest 47,681 Partners' capital contribution – excess of acquired carrying value over consideration paid $ 130,367
Red Rock Gathering Company, LLC
Limited Partners' Capital Account [Line Items]
Calculation of capital distribution and its allocation to partners' capital	The calculation of the capital distribution and its allocation to partners' capital follow (dollars in thousands). Summit Investments' net investment in Red Rock Gathering $ 241,817 Total net cash consideration paid to a subsidiary of Summit Investments 307,941 Excess of consideration paid over acquired carrying value $ (66,124 ) Allocation of capital distribution: General partner interest $ (1,323 ) Common limited partner interest (37,910 ) Subordinated limited partner interest (26,891 ) Partners' capital distribution – excess of consideration paid over acquired carrying value $ (66,124 )
Bison Midstream
Limited Partners' Capital Account [Line Items]
Calculation of capital contribution and its allocation to partners' capital	The calculation of the capital contribution and its allocation to partners' capital follow (dollars in thousands). Summit Investments' net investment in Bison Midstream $ 305,449 Aggregate cash paid to Summit Investments $ 200,000 Issuance of 1,553,849 SMLP common units to Summit Investments 47,936 Issuance of 31,711 SMLP general partner units to the general partner 978 Total consideration paid to a subsidiary of Summit Investments 248,914 Excess of acquired carrying value over consideration paid $ 56,535 Allocation of capital contribution: General partner interest $ 1,131 Common limited partner interest 28,558 Subordinated limited partner interest 26,846 Partners' capital contribution – excess of acquired carrying value over consideration paid $ 56,535
Mountaineer Midstream
Limited Partners' Capital Account [Line Items]
Allocation and valuation of units issued to partially fund	The allocation and valuation of units issued to partially fund the Mountaineer Acquisition follow (dollars in thousands). Issuance of 3,107,698 SMLP common units to Summit Investments $ 98,000 Issuance of 63,422 SMLP general partner units to the general partner 2,000 Issuance of units in connection with the Mountaineer Acquisition $ 100,000

EARNINGS PER UNIT (Tables)

EARNINGS PER UNIT (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of earnings per limited partner unit	The following table details the components of (loss) earnings per limited partner unit. Year ended December 31, 2015 2014 2013 (In thousands, except per-unit amounts) Numerator for basic and diluted EPU: Allocation of net (loss) income among limited partner interests: Net (loss) income attributable to common units $ (125,437 ) $ (16,324 ) $ 23,227 Net (loss) income attributable to subordinated units (70,173 ) (10,793 ) 19,322 Net (loss) income attributable to limited partners $ (195,610 ) $ (27,117 ) $ 42,549 Denominator for basic and diluted EPU: Weighted-average common units outstanding – basic 39,217 33,311 26,951 Effect of nonvested phantom units — — 150 Weighted-average common units outstanding – diluted 39,217 33,311 27,101 Weighted-average subordinated units outstanding – basic and diluted 24,410 24,410 24,410 (Loss) earnings per limited partner unit: Common unit – basic $ (3.20 ) $ (0.49 ) $ 0.86 Common unit – diluted $ (3.20 ) $ (0.49 ) $ 0.86 Subordinated unit – basic and diluted $ (2.88 ) $ (0.44 ) $ 0.79

UNIT-BASED COMPENSATION (Tables

UNIT-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of unit-based compensation recognized in general and administrative expense	Unit-based compensation recognized in general and administrative expense related to awards under the SMLP LTIP follows. Year ended December 31, 2015 2014 2013 (In thousands) SMLP LTIP unit-based compensation $ 6,174 $ 4,696 $ 2,999
Phantom and Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of activity	The following table presents phantom and restricted unit activity: Units Weighted-average grant date fair value Nonvested phantom and restricted units, January 1, 2013 131,558 $ 20.00 Phantom and restricted units granted 156,165 26.33 Phantom units forfeited (4,041 ) 25.99 Nonvested phantom and restricted units, December 31, 2013 283,682 23.41 Phantom units granted 136,867 42.32 Phantom and restricted units vested (61,917 ) 25.33 Phantom units forfeited (22,430 ) 25.56 Nonvested phantom units, December 31, 2014 336,202 30.61 Phantom units granted 289,735 29.21 Phantom units vested (229,497 ) 27.66 Phantom units forfeited (16,529 ) 35.09 Nonvested phantom units, December 31, 2015 379,911 $ 31.13
SMP Net Profits Interests
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of unit-based compensation recognized in general and administrative expense	Unit-based compensation recognized in general and administrative expense related to the SMP Net Profits Interests was as follows: Year ended December 31, 2015 2014 2013 (In thousands) SMP net profits interests unit-based compensation $ 85 $ 340 $ 830

RELATED-PARTY TRANSACTIONS (Tab

RELATED-PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Schedule of related party transactions	Expenses incurred by the general partner and reimbursed by us under our partnership agreement were as follows: Year ended December 31, 2015 2014 2013 (In thousands) Operation and maintenance expense $ 21,537 $ 19,782 $ 14,323 General and administrative expense 21,116 22,370 18,662

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Schedule of total rent expense related to operating leases	Rent expense related to operating leases, including rent expense incurred on our behalf and allocated to us, was as follows: Year ended December 31, 2015 2014 2013 (In thousands) Rent expense $ 1,990 $ 1,786 $ 1,495

ACQUISITIONS AND DROP DOWN TR38

ACQUISITIONS AND DROP DOWN TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2015
Business Acquisition [Line Items]
Schedule of Revenue and Net Income Disclosures	Revenues and net income for the previously separate entities and the combined amounts, as presented in these consolidated financial statements follow. Year ended December 31, 2015 2014 2013 (In thousands) SMLP revenues $ 358,046 $ 338,941 $ 241,089 Polar and Divide revenues (1) 13,273 22,449 3,893 Red Rock Gathering revenues (1) 11,313 50,114 Bison Gas Gathering system revenues (1) 28,590 Combined revenues $ 371,319 $ 372,703 $ 323,686 SMLP net (loss) income $ (192,212 ) $ (23,992 ) $ 43,584 Polar and Divide net income (loss) (1) 5,403 6,430 (467 ) Red Rock Gathering net income (1) 2,828 9,668 Bison Gas Gathering system net income (1) 52 Combined net (loss) income $ (186,809 ) $ (14,734 ) $ 52,837 __________ (1) Results are fully reflected in SMLP's revenues and net income on the date common control began, see Note 1.
Business Acquisitions, Pro Forma Information	Year ended December 31, 2013 (In thousands, except for per-unit amounts) Total Bison Midstream and Mountaineer Midstream revenues included in consolidated revenues $ 87,196 Total Bison Midstream and Mountaineer Midstream net loss included in consolidated net income (457 ) Pro forma total revenues $ 335,837 Pro forma net income 46,904 Pro forma common EPU - basic and diluted $ 0.78 Pro forma subordinated EPU - basic and diluted 0.78
Polar Midstream
Business Acquisition [Line Items]
Fair Value of Assets Acquired and Liabilities Assumed	The fair values of the assets acquired and liabilities assumed as of February 15, 2013, were as follows (in thousands): Purchase price assigned to Polar Midstream $ 216,105 Current assets $ 368 Property, plant, and equipment 9,755 Other noncurrent assets 7,201 Total assets acquired 17,324 Current liabilities 4,592 Total liabilities assumed $ 4,592 Net identifiable assets acquired 12,732 Goodwill $ 203,373
Bison Midstream
Business Acquisition [Line Items]
Fair Value of Assets Acquired and Liabilities Assumed	The fair values of the assets acquired and liabilities assumed as of February 15, 2013, were as follows (in thousands): Purchase price assigned to Bison Gas Gathering system $ 303,168 Current assets $ 5,705 Property, plant, and equipment 85,477 Intangible assets 164,502 Other noncurrent assets 2,187 Total assets acquired 257,871 Current liabilities 6,112 Other noncurrent liabilities 2,790 Total liabilities assumed $ 8,902 Net identifiable assets acquired 248,969 Goodwill $ 54,199
Mountaineer Midstream
Business Acquisition [Line Items]
Fair Value of Assets Acquired and Liabilities Assumed	The final fair values of the assets acquired and liabilities assumed as of June 21, 2013, were as follows (in thousands): Purchase price assigned to Mountaineer Midstream $ 210,000 Property, plant, and equipment $ 163,661 Gas gathering agreement contract intangibles 24,019 Rights-of-way 6,109 Total assets acquired 193,789 Total liabilities assumed $ — Net identifiable assets acquired 193,789 Goodwill $ 16,211

UNAUDITED QUARTERLY FINANCIAL39

UNAUDITED QUARTERLY FINANCIAL DATA (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Quarterly summarized information on the consolidated results of operations	Summarized information on the consolidated results of operations for each of the quarters during the two-year period ended December 31, 2015 , follows. Quarter ended December 31, 2015 Quarter ended September 30, 2015 Quarter ended June 30, 2015 Quarter ended March 31, 2015 (In thousands, except per-unit amounts) Total revenues (1) $ 102,601 $ 106,557 $ 80,944 $ 81,217 Net (loss) income attributable to SMLP (2)(3) $ (220,468 ) $ 23,604 $ 2,985 $ 1,667 Less net (loss) income attributable to general partner, including IDRs (2,469 ) 2,408 1,891 1,568 Net (loss) income attributable to limited partners $ (217,999 ) $ 21,196 $ 1,094 $ 99 (Loss) earnings per limited partner unit: Common unit – basic $ (3.28 ) $ 0.32 $ 0.05 $ 0.00 Common unit – diluted $ (3.28 ) $ 0.32 $ 0.05 $ 0.00 Subordinated unit – basic and diluted $ (3.28 ) $ 0.32 $ (0.03 ) $ 0.00 __________ (1) Retrospectively adjusted for the impact of the Polar and Divide Drop Down and reclassification of certain revenues for Bison Midstream. (2) In the quarter ended December 31, 2015, net loss attributable to SMLP includes $ 248.9 million of goodwill impairments and $ 1.6 million of long-lived asset impairments. (3) In the quarter ended September 30, 2015, net income attributable to SMLP includes $ 7.7 million of long-lived asset impairments. Quarter ended December 31, 2014 Quarter ended September 30, 2014 Quarter ended June 30, 2014 Quarter ended March 31, 2014 (In thousands, except per-unit amounts) Total revenues (1) $ 108,230 $ 90,044 $ 90,649 $ 83,780 Net (loss) income attributable to SMLP (2) $ (37,686 ) $ 6,113 $ 4,036 $ 3,545 Less net (loss) income attributable to general partner, including IDRs 689 1,204 801 431 Net (loss) income attributable to limited partners $ (38,375 ) $ 4,909 $ 3,235 $ 3,114 (Loss) earnings per limited partner unit: Common unit – basic $ (0.65 ) $ 0.08 $ 0.05 $ 0.08 Common unit – diluted $ (0.65 ) $ 0.08 $ 0.05 $ 0.08 Subordinated unit – basic and diluted $ (0.65 ) $ 0.08 $ 0.05 $ 0.02 __________ (1) Retrospectively adjusted for the impact of the Polar and Divide Drop Down and reclassification of certain revenues for Bison Midstream. (2) In the quarter ended December 31, 2014, net loss attributable to SMLP includes $54.2 million of goodwill impairment and $5.5 million of long-lived asset impairment.
Retrospective adjustments from impact of acquisitions	A reconciliation of total revenues follows. Quarter ended September 30, 2015 Quarter ended June 30, 2015 Quarter ended March 31, 2015 (In thousands) Total revenues as originally reported $ 103,249 $ 77,274 $ 68,579 Bison revenue reclass 3,308 3,670 4,056 Polar and Divide Drop Down — — 8,582 Total revenues $ 106,557 $ 80,944 $ 81,217 Quarter ended September 30, 2014 Quarter ended June 30, 2014 Quarter ended March 31, 2014 (In thousands) Total revenues as originally reported $ 79,030 $ 80,796 $ 76,202 Bison revenue reclass 5,260 4,665 4,399 Polar and Divide Drop Down 5,754 5,188 3,179 Total revenues $ 90,044 $ 90,649 $ 83,780

ORGANIZATION, BUSINESS OPERAT40

ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION (Details)	Feb. 25, 2016	May. 31, 2015	Mar. 31, 2014	Mar. 31, 2013	Oct. 31, 2012	Dec. 31, 2015segmentshares	Dec. 31, 2015segmentshares	Dec. 31, 2014shares	Dec. 31, 2013
ORGANIZATION AND BUSINESS OPERATIONS
Common limited partner capital, units outstanding | shares						42,063,000	42,063,000	34,427,000
Number of reportable segments | segment							4
Williston Basin Segment
ORGANIZATION AND BUSINESS OPERATIONS
Number of reportable segments | segment						1
Summit Holdings
ORGANIZATION AND BUSINESS OPERATIONS
Cumulative percentage ownership in subsidiary					100.00%
SMP Holdings | Ohio Gathering | Subsequent Event
ORGANIZATION AND BUSINESS OPERATIONS
Join venture interest	40.00%
Summit Holdings | DFW Midstream
ORGANIZATION AND BUSINESS OPERATIONS
Cumulative percentage ownership in subsidiary					100.00%
Summit Holdings | Grand River
ORGANIZATION AND BUSINESS OPERATIONS
Cumulative percentage ownership in subsidiary					100.00%
Common units | SMP Holdings
ORGANIZATION AND BUSINESS OPERATIONS
Common limited partner capital, units outstanding | shares						5,444,731	5,444,731
General partner
ORGANIZATION AND BUSINESS OPERATIONS
General partner interest (as a percent)		2.00%	2.00%				2.00%	2.00%	2.00%
General partner | Summit Investments | Summit Midstream Partners, LP
ORGANIZATION AND BUSINESS OPERATIONS
General partner interest (as a percent)				2.00%

ORGANIZATION, BUSINESS OPERAT41

ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION - Reclassifications (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Gathering services and related fees									$ 310,829	$ 255,211	$ 213,979
Other revenues									18,411	20,398	21,522
Net impact on total revenues	$ 102,601	$ 106,557	$ 80,944	$ 81,217	$ 108,230	$ 90,044	$ 90,649	$ 83,780	371,319	372,703	323,686
Cost of natural gas and NGLs									31,398	72,415	68,037
Net impact on cost of natural gas and NGLs and total costs and expenses									$ 510,190	347,836	250,952
Reclassifications of Revenues and Expenses
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Gathering services and related fees										15,616	16,805
Other revenues										3,952	10,068
Net impact on total revenues										19,568	26,873
Cost of natural gas and NGLs										19,568	26,873
Net impact on cost of natural gas and NGLs and total costs and expenses										$ 19,568	$ 26,873

SUMMARY OF SIGNIFICANT ACCOUN42

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Accounts Receivable and Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2015
Gathering and processing systems and related equipment
Property, Plant and Equipment [Line Items]
Useful life	30 years
Other | Minimum
Property, Plant and Equipment [Line Items]
Useful life	4 years
Other | Maximum
Property, Plant and Equipment [Line Items]
Useful life	15 years

SUMMARY OF SIGNIFICANT ACCOUN43

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Intangible Assets and Noncurrent Liability (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Favorable gas gathering contract
Finite-Lived Intangible Assets [Line Items]
Useful lives	18 years 8 months 12 days	18 years 8 months 12 days
Favorable gas gathering contract | Minimum
Finite-Lived Intangible Assets [Line Items]
Useful lives	10 years
Favorable gas gathering contract | Maximum
Finite-Lived Intangible Assets [Line Items]
Useful lives	20 years
Other Gas Gathering Contract | Minimum
Finite-Lived Intangible Assets [Line Items]
Useful lives	10 years
Other Gas Gathering Contract | Maximum
Finite-Lived Intangible Assets [Line Items]
Useful lives	25 years
Rights-of-way
Finite-Lived Intangible Assets [Line Items]
Useful lives	25 years 2 months	24 years 8 months
Rights-of-way | Minimum
Finite-Lived Intangible Assets [Line Items]
Useful lives	20 years
Rights-of-way | Maximum
Finite-Lived Intangible Assets [Line Items]
Useful lives	30 years

SUMMARY OF SIGNIFICANT ACCOUN44

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Income Taxes and EPS (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	May. 31, 2015	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Significant Accounting Policies [Line Items]
Deferred tax liability, noncurrent			$ 0.6	$ 1.3
General partner
Significant Accounting Policies [Line Items]
General partner interest (as a percent)	2.00%	2.00%	2.00%	2.00%	2.00%

SEGMENT INFORMATION - Assets by

SEGMENT INFORMATION - Assets by Reportable Segment (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Assets	$ 2,040,531	$ 2,293,721	$ 2,191,143
Reportable Segments
Segment Reporting Information [Line Items]
Assets	2,010,711	2,255,144	2,167,940
Reportable Segments | Marcellus Shale Segment
Segment Reporting Information [Line Items]
Assets	233,116	243,884	214,379
Reportable Segments | Williston Basin Segment
Segment Reporting Information [Line Items]
Assets	563,952	709,888	645,014
Reportable Segments | Barnett Shale Segment
Segment Reporting Information [Line Items]
Assets	416,586	428,935	431,578
Reportable Segments | Piceance Basin Segment
Segment Reporting Information [Line Items]
Assets	797,057	872,437	876,969
Corporate
Segment Reporting Information [Line Items]
Assets	$ 29,820	$ 38,577	$ 23,203

SEGMENT INFORMATION - Revenues,

SEGMENT INFORMATION - Revenues, Depreciation and Amortization, and Capital Expenditures by Reportable Segment (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Revenues	$ 102,601	$ 106,557	$ 80,944	$ 81,217	$ 108,230	$ 90,044	$ 90,649	$ 83,780	$ 371,319	$ 372,703	$ 323,686
Depreciation and amortization									96,975	88,293	71,606
Capital expenditures									118,107	220,820	182,978
Reportable Segments
Segment Reporting Information [Line Items]
Revenues									371,319	372,703	323,686
Depreciation and amortization									96,372	87,705	71,155
Capital expenditures									117,678	220,360	182,048
Reportable Segments | Marcellus Shale Segment
Segment Reporting Information [Line Items]
Revenues									28,468	22,694	9,588
Depreciation and amortization									8,682	7,648	3,998
Capital expenditures									1,306	33,866	1,822
Reportable Segments | Williston Basin Segment
Segment Reporting Information [Line Items]
Revenues									85,887	104,471	81,501
Depreciation and amortization									26,280	22,491	16,669
Capital expenditures									90,234	139,422	99,983
Reportable Segments | Barnett Shale Segment
Segment Reporting Information [Line Items]
Revenues									88,042	93,001	105,324
Depreciation and amortization									16,392	16,601	14,961
Capital expenditures									6,875	14,567	29,534
Reportable Segments | Piceance Basin Segment
Segment Reporting Information [Line Items]
Revenues									168,922	152,537	127,273
Depreciation and amortization									45,018	40,965	35,527
Capital expenditures									19,263	32,505	50,709
Corporate
Segment Reporting Information [Line Items]
Depreciation and amortization									603	588	451
Capital expenditures									$ 429	$ 460	$ 930

SEGMENT INFORMATION - Concentra

SEGMENT INFORMATION - Concentration Risk (Details) - Revenue - Customer concentration	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Counterparty A - Piceance
Segment Reporting Information [Line Items]
Concentration risk, percentage	17.00%	19.00%	19.00%
Counterparty B - Piceance
Segment Reporting Information [Line Items]
Concentration risk, percentage	16.00%
Counterparty C - Barnett Shale
Segment Reporting Information [Line Items]
Concentration risk, percentage			14.00%

SEGMENT INFORMATION - Adjusted

SEGMENT INFORMATION - Adjusted EBITDA by Reportable Segment (Details) - Reportable Segments - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ 234,217	$ 215,972	$ 174,097
Marcellus Shale Segment
Segment Reporting Information [Line Items]
Adjusted EBITDA	23,214	15,940	6,333
Williston Basin Segment
Segment Reporting Information [Line Items]
Adjusted EBITDA	47,010	31,551	17,350
Barnett Shale Segment
Segment Reporting Information [Line Items]
Adjusted EBITDA	59,526	60,528	69,473
Piceance Basin Segment
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ 104,467	$ 107,953	$ 80,941

SEGMENT INFORMATION - Reconcili

SEGMENT INFORMATION - Reconciliation of Net Income to Adjusted EBITDA (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Income before income taxes				$ (187,485)	$ (14,103)	$ 53,566
Add:
Interest expense				48,616	40,159	19,173
Depreciation and amortization				96,975	88,293	71,606
Adjustments related to MVC shortfall payments				(11,902)	26,565	17,025
Unit-based compensation				6,259	5,036	3,846
Loss on asset sales				42	442	113
Long-lived asset impairment	$ 1,600	$ 7,700	$ 5,500	9,305	5,505	0
Goodwill impairment	$ 248,900		$ 54,200	248,851	54,199	0
Less:
Interest income				2	4	5
Gain on asset sales				214	0	0
Impact of purchase price adjustment				0	1,185	0
Corporate
Add:
Allocated corporate expenses				23,772	11,065	8,773
Depreciation and amortization				603	588	451
Reportable Segments
Add:
Depreciation and amortization				96,372	87,705	71,155
Adjustments related to MVC shortfall payments				(11,902)	26,565	17,025
Less:
Total reportable segment adjusted EBITDA				$ 234,217	$ 215,972	$ 174,097

SEGMENT INFORMATION - Adjustmen

SEGMENT INFORMATION - Adjustments Related to MVC Shortfall Payments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Adjustments related to MVC shortfall payments	$ (11,902)	$ 26,565	$ 17,025
Reportable Segments
Segment Reporting Information [Line Items]
Adjustments related to MVC shortfall payments	(11,902)	26,565	17,025
Reportable Segments | Williston Basin Segment
Segment Reporting Information [Line Items]
Adjustments related to MVC shortfall payments	11,870	10,743	3,600
Reportable Segments | Barnett Shale Segment
Segment Reporting Information [Line Items]
Adjustments related to MVC shortfall payments	(2,182)	628	1,030
Reportable Segments | Piceance Basin Segment
Segment Reporting Information [Line Items]
Adjustments related to MVC shortfall payments	$ (21,590)	$ 15,194	$ 12,395

PROPERTY, PLANT, AND EQUIPMEN51

PROPERTY, PLANT, AND EQUIPMENT, NET (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Gross	$ 1,640,674		$ 1,536,024	$ 1,640,674	$ 1,536,024
Less accumulated depreciation	176,872		121,674	176,872	121,674
Property, plant, and equipment, net	1,463,802		1,414,350	1,463,802	1,414,350
Long-lived asset impairment	1,600	$ 7,700	5,500	9,305	5,505	$ 0
Depreciation expense				55,685	49,816	37,313
Capitalized interest				3,137	3,778	6,255
Williston Basin Segment
Property, Plant and Equipment [Line Items]
Long-lived asset impairment				7,554	0	0
Barnett Shale Segment
Property, Plant and Equipment [Line Items]
Long-lived asset impairment				531	5,505	0
Piceance Basin Segment
Property, Plant and Equipment [Line Items]
Long-lived asset impairment				1,220	0	$ 0
Gathering and processing systems and related equipment
Property, Plant and Equipment [Line Items]
Gross	1,574,916		1,459,585	1,574,916	1,459,585
Construction in progress
Property, Plant and Equipment [Line Items]
Gross	25,484		37,604	25,484	37,604
Land and line fill
Property, Plant and Equipment [Line Items]
Gross	9,339		9,964	9,339	9,964
Other
Property, Plant and Equipment [Line Items]
Gross	$ 30,935		$ 28,871	$ 30,935	$ 28,871

AMORTIZING INTANGIBLE ASSETS 52

AMORTIZING INTANGIBLE ASSETS AND UNFAVORABLE GAS GATHERING CONTRACT (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	$ 576,581	$ 574,240
Accumulated amortization	(138,488)	(96,506)
Total intangible assets, net	$ 438,093	$ 477,734
Noncurrent liability
Unfavorable gas gathering contract, useful lives	10 years	10 years
Unfavorable contract, gross carrying amount	$ 10,962	$ 10,962
Unfavorable gas gathering contract, accumulated amortization	(6,077)	(5,385)
Unfavorable gas gathering contract, Net	4,885	5,577
Amortization expense
Amortization expense - unfavorable contract	692	$ 797	$ 1,046
Intangible assets
2,016	42,301
2,017	41,152
2,018	40,606
2,019	40,852
2,020	43,498
Unfavorable gas gathering contract
2,016	924
2,017	1,047
2,018	1,035
2,019	1,045
2,020	$ 834
Favorable gas gathering contract
Finite-Lived Intangible Assets [Line Items]
Useful lives	18 years 8 months 12 days	18 years 8 months 12 days
Gross carrying amount	$ 24,195	$ 24,195
Accumulated amortization	(9,534)	(8,056)
Total intangible assets, net	14,661	16,139
Amortization expense
Amortization expense	$ 1,478	$ 1,741	2,078
Contract intangibles
Finite-Lived Intangible Assets [Line Items]
Useful lives	12 years 6 months	12 years 6 months
Gross carrying amount	$ 426,464	$ 426,464
Accumulated amortization	(111,052)	(75,713)
Total intangible assets, net	315,412	350,751
Amortization expense
Amortization expense	$ 35,339	$ 32,554	28,654
Rights-of-way
Finite-Lived Intangible Assets [Line Items]
Useful lives	25 years 2 months	24 years 8 months
Gross carrying amount	$ 125,922	$ 123,581
Accumulated amortization	(17,902)	(12,737)
Total intangible assets, net	108,020	110,844
Amortization expense
Amortization expense	$ 5,165	$ 4,979	$ 4,607

GOODWILL (Details)

GOODWILL (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Goodwill [Roll Forward]
Goodwill, beginning balance			$ 265,062	$ 319,261
Goodwill impairment	$ (248,900)	$ (54,200)	(248,851)	(54,199)	$ 0
Goodwill, ending balance	16,211	265,062	16,211	265,062	319,261
Accumulated goodwill impairment	303,050	54,199	303,050	54,199	0
Piceance Basin Segment
Goodwill [Roll Forward]
Goodwill, beginning balance			45,478	45,478
Goodwill impairment			(45,478)	0
Goodwill, ending balance	0	45,478	0	45,478	45,478
Accumulated goodwill impairment	45,478	0	45,478	0	0
Williston Basin Segment
Goodwill [Roll Forward]
Goodwill, beginning balance			203,373	257,572
Goodwill impairment			(203,373)	(54,199)
Goodwill, ending balance	0	203,373	0	203,373	257,572
Accumulated goodwill impairment	257,572	54,199	257,572	54,199	0
Williston Basin Segment | Bison Midstream
Goodwill [Roll Forward]
Goodwill impairment		(54,200)
Marcellus Shale Segment
Goodwill [Roll Forward]
Goodwill, beginning balance			16,211	16,211
Goodwill impairment			0	0
Goodwill, ending balance	$ 16,211	$ 16,211	$ 16,211	$ 16,211	$ 16,211

DEFERRED REVENUE (Details)

DEFERRED REVENUE (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
Movement in Deferred Revenue [Roll Forward]
Current deferred revenue, beginning balance		$ 2,377	$ 1,555
Additions		3,420	2,610
Less revenue recognized		5,120	1,788
Current deferred revenue, ending balance		677	2,377
Noncurrent deferred revenue, beginning balance		55,239	29,683
Additions		24,662	25,556
Less revenue recognized		34,415
Noncurrent deferred revenue, ending balance		45,486	55,239
Shortfall payments billed and included in accounts receivable		12,700
Williston Basin Segment
Movement in Deferred Revenue [Roll Forward]
Current deferred revenue, beginning balance		0	0
Additions		0	0
Less revenue recognized		0	0
Current deferred revenue, ending balance		0	0
Noncurrent deferred revenue, beginning balance		17,132	6,389
Additions		11,897	10,743
Less revenue recognized		27
Noncurrent deferred revenue, ending balance		29,002	17,132
Barnett Shale Segment
Movement in Deferred Revenue [Roll Forward]
Current deferred revenue, beginning balance		2,377	1,555
Additions		677	2,610
Less revenue recognized		2,377	1,788
Current deferred revenue, ending balance		677	2,377
Noncurrent deferred revenue, beginning balance		0	0
Additions		0	0
Less revenue recognized		0
Noncurrent deferred revenue, ending balance		0	0
Piceance Basin Segment
Movement in Deferred Revenue [Roll Forward]
Current deferred revenue, beginning balance		0	0
Additions		2,743	0
Less revenue recognized		2,743	0
Current deferred revenue, ending balance		0	0
Noncurrent deferred revenue, beginning balance		38,107	23,294
Additions		12,765	14,813
Less revenue recognized		34,388
Noncurrent deferred revenue, ending balance		$ 16,484	$ 38,107
Piceance Basin Segment | Gathering Services and Related Fees
Movement in Deferred Revenue [Roll Forward]
Less revenue recognized	$ 34,400

DEBT - Components of Long-Term

DEBT - Components of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Revolving credit facility	$ 344,000	$ 208,000
Total long-term debt	$ 944,000	$ 808,000
Revolving credit facility
Line of Credit Facility [Line Items]
Variable interest rate	2.93%	2.67%
5.5% Senior Notes
Line of Credit Facility [Line Items]
Senior unsecured notes	$ 300,000	$ 300,000
7.5% Senior Notes
Line of Credit Facility [Line Items]
Senior unsecured notes	$ 300,000	$ 300,000
Senior Notes | 5.5% Senior Notes
Line of Credit Facility [Line Items]
Stated interest rate	5.50%	5.50%
Senior Notes | 7.5% Senior Notes
Line of Credit Facility [Line Items]
Stated interest rate	7.50%	7.50%

DEBT - Maturities (Details)

DEBT - Maturities (Details) $ in Thousands	Dec. 31, 2015USD ($)
Debt
2,016	$ 0
2,017	0
2,018	344,000
2,019	0
2,020	0
Thereafter	600,000
Total long-term debt	$ 944,000

DEBT - Revolving Credit Facilit

DEBT - Revolving Credit Facility (Details)	Feb. 26, 2016USD ($)	Dec. 31, 2015USD ($)	Feb. 29, 2016USD ($)	Dec. 31, 2014
Senior Notes
Line of Credit Facility [Line Items]
Debt defaults		$ 0
Subsequent Event | Senior Notes | Summit Holdings and Finance Corporation
Line of Credit Facility [Line Items]
Buy-back of debt, up to	$ 100,000,000
Revolving credit facility
Line of Credit Facility [Line Items]
Borrowing capacity		700,000,000
Accordion feature		$ 200,000,000
Commitment fee on unused portion of the facility (as a percent)		0.50%
Interest rate at period end		2.93%		2.67%
Unused portion under the facility		$ 356,000,000
Maximum cumulative lease payment obligations allowable under terms of covenants		$ 30,000,000
Period that cumulative lease payment obligations may not exceed specified amount under terms of covenants		12 months
Trailing period used in calculating the ratio of EBITDA to net interest expense		12 months
Ratio of consolidated EBITDA to net interest expense		2.5
Trailing period used in calculating the ratio of total indebtedness to consolidated EBITDA		12 months
Senior secured leverage ratio		3.75
Ratio of total indebtedness to consolidated EBITDA		5
Ratio of total indebtedness to consolidated EBITDA, for a specified period following certain acquisitions		5.5
Period following certain acquisitions, for which higher ratio of total indebtedness to consolidated EBITDA is to be maintained		270 days
Total leverage ratio		5.5
Debt defaults		$ 0
Revolving credit facility | Subsequent Event
Line of Credit Facility [Line Items]
Borrowing capacity			$ 1,250,000,000
Revolving credit facility | LIBOR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)		2.50%
Revolving credit facility | Minimum
Line of Credit Facility [Line Items]
Commitment fee on unused portion of the facility (as a percent)		0.30%
Revolving credit facility | Minimum | ABR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)		0.75%
Revolving credit facility | Minimum | LIBOR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)		1.75%
Revolving credit facility | Maximum
Line of Credit Facility [Line Items]
Commitment fee on unused portion of the facility (as a percent)		0.50%
Revolving credit facility | Maximum | ABR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)		1.75%
Revolving credit facility | Maximum | LIBOR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)		2.75%

DEBT - Senior Notes (Details)

DEBT - Senior Notes (Details) - USD ($)	1 Months Ended	12 Months Ended
	Jul. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Jun. 30, 2013
Senior Notes
Debt Instrument [Line Items]
Debt defaults		$ 0
5.5% Senior Notes
Debt Instrument [Line Items]
Senior unsecured notes		$ 300,000,000	$ 300,000,000
5.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Stated interest rate		5.50%	5.50%
Events of default, period of payment default		30 days
Events of default, failure to comply with covenants, period after notice		180 days
Events of default, failure to comply with other agreements in the indenture, period after notice		30 days
Events of default, failure to pay final judgments, in excess of 20.0 million		$ 20,000,000
Declaration of immediate payment, holding percent of principal amount required		25.00%
7.5% Senior Notes
Debt Instrument [Line Items]
Senior unsecured notes		$ 300,000,000	$ 300,000,000
7.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Stated interest rate		7.50%	7.50%
Other noncurrent assets | 5.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Debt issuance costs	$ 5,100,000
Summit Holdings and Finance Corporation | 5.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Senior unsecured notes	$ 300,000,000
Stated interest rate	5.50%
Maximum percent of aggregate principal amount redeemable		35.00%
Summit Holdings and Finance Corporation | 7.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Senior unsecured notes				$ 300,000,000
Stated interest rate		7.50%		7.50%
Maximum percent of aggregate principal amount redeemable		35.00%
Debt issuance costs		$ 7,400,000
Events of default, period of payment default		30 days
Events of default, failure to comply with covenants, period after notice		180 days
Events of default, failure to comply with other agreements in the indenture, period after notice		30 days
Events of default, failure to pay final judgments, in excess of 20.0 million		$ 20,000,000
Declaration of immediate payment, holding percent of principal amount required		25.00%
Debt defaults		$ 0
Summit Holdings and Finance Corporation | Prior to August 15, 2017 | 5.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		105.50%
Summit Holdings and Finance Corporation | August 15, 2017 - August 15, 2020 | 5.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		104.125%
Summit Holdings and Finance Corporation | August 15, 2020 | 5.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		100.00%
Summit Holdings and Finance Corporation | Prior to July 1, 2016 | 7.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		107.50%
Summit Holdings and Finance Corporation | July 1, 2016 - June 30, 2019 | 7.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		105.625%
Summit Holdings and Finance Corporation | July 1, 2019 | 7.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		100.00%
Summit Holdings | Finance Corp.
Debt Instrument [Line Items]
Cumulative percentage ownership in subsidiary	100.00%

FINANCIAL INSTRUMENTS - Concent

FINANCIAL INSTRUMENTS - Concentration Risk (Details) - Accounts receivable - Customer concentration - customer	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
CONCENTRATIONS OF RISK
Concentration risk, number	5	5
Concentration risk, percentage	70.00%	62.00%

FINANCIAL INSTRUMENTS - Fair va

FINANCIAL INSTRUMENTS - Fair value of Debt Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving credit facility, Carrying value	$ 344,000	$ 208,000
Fair value, Level 2 inputs
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving credit facility, Estimated fair value (Level 2)	344,000	208,000
5.5% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes, Carrying value	300,000	300,000
5.5% Senior Notes | Fair value, Level 2 inputs
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes, Estimated fair value (Level 2)	224,000	281,750
7.5% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes, Carrying value	300,000	300,000
7.5% Senior Notes | Fair value, Level 2 inputs
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes, Estimated fair value (Level 2)	$ 257,000	$ 306,750

PARTNERS' CAPITAL - Partners' C

PARTNERS' CAPITAL - Partners' Capital and Schedule of Units (Details) - $ / shares	May. 22, 2015	May. 31, 2015	Sep. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Rollforwards of the number of partner units
Units, beginning balance					60,037,014	54,581,169	49,818,597
Units issued in connection with offering					7,627,551	5,408,337
Net units issued under SMLP LTIP					162,629	47,508	5,892
Units, ending balance					67,827,194	60,037,014	54,581,169
General partner
Rollforwards of the number of partner units
General partner interest (as a percent)		2.00%		2.00%	2.00%	2.00%	2.00%
Bison Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							1,585,560
Mountaineer Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							3,171,120
Common
Rollforwards of the number of partner units
Units, beginning balance					34,426,513	29,079,866	24,412,427
Units issued in connection with offering					7,475,000	5,300,000
Net units issued under SMLP LTIP					161,131	46,647	5,892
Units, ending balance					42,062,644	34,426,513	29,079,866
Common | Summit Investments
Rollforwards of the number of partner units
Common units sold in public offering			4,347,826
Common | Public Offering
Rollforwards of the number of partner units
Common units sold in public offering		6,500,000		10,350,000
Common units sold in public offering, price per share (in dollars per share)		$ 30.75		$ 38.75
Common | Public Offering | Partnership
Rollforwards of the number of partner units
Common units sold in public offering				5,300,000
Common | Public Offering | Summit Investments
Rollforwards of the number of partner units
Common units sold in public offering				5,050,000
Common | Over-Allotment Option
Rollforwards of the number of partner units
Common units sold in public offering	975,000
Common units sold in public offering, price per share (in dollars per share)	$ 30.75
Common | Bison Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							1,553,849
Common | Mountaineer Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							3,107,698
Subordinated
Rollforwards of the number of partner units
Units, beginning balance					24,409,850	24,409,850	24,409,850
Units issued in connection with offering					0	0
Net units issued under SMLP LTIP					0	0	0
Units, ending balance					24,409,850	24,409,850	24,409,850
Subordinated | Bison Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							0
Subordinated | Mountaineer Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							0
General partner
Rollforwards of the number of partner units
Units, beginning balance					1,200,651	1,091,453	996,320
Units issued in connection with offering					152,551	108,337
Net units issued under SMLP LTIP					1,498	861	0
Units, ending balance					1,354,700	1,200,651	1,091,453
General partner | Bison Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							31,711
General partner | Mountaineer Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							63,422

PARTNERS' CAPITAL - Subordinati

PARTNERS' CAPITAL - Subordination (Details)	1 Months Ended		12 Months Ended
	May. 31, 2015	Mar. 31, 2014	Dec. 31, 2015$ / shares	Dec. 31, 2014	Dec. 31, 2013
General partner
Schedule of Partners' Capital [Line Items]
General partner interest (as a percent)	2.00%	2.00%	2.00%	2.00%	2.00%
Condition one
Schedule of Partners' Capital [Line Items]
Minimum quarterly distribution (in dollars per share)			$ 1.60
Term for condition to be met to end subordination period			3 years
Condition one | General partner
Schedule of Partners' Capital [Line Items]
General partner interest (as a percent)			2.00%
Subordinated units
Schedule of Partners' Capital [Line Items]
Common unit per subordinated unit upon conversion at end of subordination period			1

PARTNERS' CAPITAL - Allocation

PARTNERS' CAPITAL - Allocation of Capital Distributions and Contributions (Details) - USD ($) $ / shares in Units, $ in Thousands	May. 18, 2015	Mar. 18, 2014	Jun. 21, 2013	Jun. 04, 2013	Jun. 03, 2013	Feb. 15, 2013	Feb. 28, 2015	Feb. 28, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Partners' capital contribution									$ 4,737	$ 4,235	$ 2,229
Partners' capital distribution									(152,074)	(122,224)	(90,196)
Polar Midstream and Epping
Business Acquisition [Line Items]
Percent of membership interest acquired	100.00%
Liabilities incurred for acquisition	$ 92,500
Total consideration	285,677
Partners' capital contribution	130,367
Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Percent of membership interest acquired		100.00%
Cost of acquired entity, cash paid		$ 305,000					$ 2,900	$ 307,900
Total consideration		307,941
Partners' capital distribution		(66,124)
Bison Midstream
Business Acquisition [Line Items]
Cost of acquired entity, cash paid				$ 200,000
Liabilities incurred for acquisition				200,000
Total consideration				248,914
Partners' capital contribution				$ 56,535
Basis for determining number of units issued, assumed equity issuance					$ 50,000
Basis for determining number of units issued, period					5 days
Basis for determining number of units issued, weighted-average price (in dollars per share)					$ 31.53
Closing price (in dollars per unit)				$ 30.85
Mountaineer Midstream
Business Acquisition [Line Items]
Cost of acquired entity, equity interests issued and issuable			$ 100,000
Liabilities incurred for acquisition			110,000
Total consideration			210,000
Basis for determining number of units issued, assumed equity issuance					$ 100,000
Basis for determining number of units issued, period					5 days
Basis for determining number of units issued, weighted-average price (in dollars per share)					$ 31.53
General partner
Business Acquisition [Line Items]
Partners' capital contribution									4,737	4,235
Partners' capital distribution									(9,784)	(4,770)	(1,803)
General partner | Polar Midstream and Epping
Business Acquisition [Line Items]
Partners' capital contribution	2,607
General partner | Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Partners' capital distribution		(1,323)
General partner | Bison Midstream
Business Acquisition [Line Items]
Cost of acquired entity, equity interests issued and issuable				$ 978
Number of shares issued for acquisition				31,711
Partners' capital contribution				$ 1,131
General partner | Mountaineer Midstream
Business Acquisition [Line Items]
Cost of acquired entity, equity interests issued and issuable			$ 2,000
Number of shares issued for acquisition			63,422
Limited partners, Common
Business Acquisition [Line Items]
Partners' capital distribution									(86,880)	(67,658)	(46,286)
Limited partners, Common | Polar Midstream and Epping
Business Acquisition [Line Items]
Partners' capital contribution	80,079
Limited partners, Common | Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Partners' capital distribution		(37,910)
Limited partners, Common | Bison Midstream
Business Acquisition [Line Items]
Cost of acquired entity, equity interests issued and issuable				$ 47,936
Number of shares issued for acquisition				1,553,849
Partners' capital contribution				$ 28,558
Limited partners, Common | Mountaineer Midstream
Business Acquisition [Line Items]
Cost of acquired entity, equity interests issued and issuable			$ 98,000
Number of shares issued for acquisition			3,107,698
Limited partners, Subordinated
Business Acquisition [Line Items]
Partners' capital distribution									$ (55,410)	$ (49,796)	$ (42,107)
Limited partners, Subordinated | Polar Midstream and Epping
Business Acquisition [Line Items]
Partners' capital contribution	47,681
Limited partners, Subordinated | Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Partners' capital distribution		(26,891)
Limited partners, Subordinated | Bison Midstream
Business Acquisition [Line Items]
Partners' capital contribution				26,846
Summit Investments | Bison Midstream
Business Acquisition [Line Items]
Total consideration						$ 303,168
Polar Midstream and Epping | Summit Investments
Business Acquisition [Line Items]
Net investment	$ 416,044
Red Rock Gathering Company, LLC | Summit Investments
Business Acquisition [Line Items]
Net investment		$ 241,817
Bison Midstream
Business Acquisition [Line Items]
Net investment				$ 305,449

PARTNERS' CAPITAL - Cash Distri

PARTNERS' CAPITAL - Cash Distribution Policy and Minimum Quarterly Distribution (Details)	12 Months Ended
	Dec. 31, 2015$ / shares
Equity [Abstract]
Maximum period following end of quarter to distribute all available cash	45 days
Minimum quarterly distributions (in dollars per share)	$ 0.40
Minimum annual distributions (in dollars per share)	$ 1.60

PARTNERS' CAPITAL - Cash Dist65

PARTNERS' CAPITAL - Cash Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 12, 2016	Jan. 21, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Distribution Made to Limited Partner [Line Items]
Per-unit distribution (in dollars per unit)			$ 2.270	$ 2.040	$ 1.725
Cash paid to unit holders			$ 152,074	$ 122,224	$ 90,196
Subsequent Event
Distribution Made to Limited Partner [Line Items]
Per-unit distribution (in dollars per unit)		$ 0.575
Cash paid to unit holders	$ 41,000

PARTNERS' CAPITAL - Partnership

PARTNERS' CAPITAL - Partnership Target Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Partnership Target Distributions [Line Items]
IDR payments	$ 6,743	$ 2,326	$ 0
Minimum quarterly distribution
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	$ 0.4
Thereafter
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	0.60
Minimum | First target distribution
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	0.40
Minimum | Second target distribution
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	0.46
Minimum | Third target distribution
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	0.50
Maximum | First target distribution
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	0.46
Maximum | Second target distribution
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	0.5
Maximum | Third target distribution
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	$ 0.6
Unitholders | Minimum quarterly distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	98.00%
Unitholders | First target distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	98.00%
Unitholders | Second target distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	85.00%
Unitholders | Third target distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	75.00%
Unitholders | Thereafter
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	50.00%
General partner
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	2.00%
Quarterly distributions per unit, incentive threshold	$ 0.46
General partner | Minimum quarterly distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	2.00%
General partner | First target distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	2.00%
General partner | Second target distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	15.00%
General partner | Third target distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	25.00%
General partner | Thereafter
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	50.00%
General partner | Maximum
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions in excess of incentive threshold	50.00%

EARNINGS PER UNIT (Details)

EARNINGS PER UNIT (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net (loss) income attributable to limited partners	$ (217,999)	$ 21,196	$ 1,094	$ 99	$ (38,375)	$ 4,909	$ 3,235	$ 3,114	$ (195,610)	$ (27,117)	$ 42,549
(Loss) earnings per limited partner unit:
Antidilutive securities excluded from the calculation of diluted loss per common unit											0
Phantom Units
(Loss) earnings per limited partner unit:
Antidilutive securities excluded from the calculation of diluted loss per common unit									109,201	231,875
Common units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net (loss) income attributable to limited partners									$ (125,437)	$ (16,324)	$ 23,227
Weighted-average units outstanding - basic									39,217,000	33,311,000	26,951,000
Effect of nonvested phantom units									0	0	150,000
Weighted-average units outstanding – diluted									39,217,000	33,311,000	27,101,000
(Loss) earnings per limited partner unit:
Basic (in dollars per share)	$ (3.28)	$ 0.32	$ 0.05	$ 0	$ (0.65)	$ 0.08	$ 0.05	$ 0.08	$ (3.20)	$ (0.49)	$ 0.86
Diluted (in dollars per share)	(3.28)	0.32	0.05	0	(0.65)	0.08	0.05	0.08	$ (3.20)	$ (0.49)	$ 0.86
Subordinated Units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net (loss) income attributable to limited partners									$ (70,173)	$ (10,793)	$ 19,322
Weighted-average units outstanding - basic									24,410,000	24,410,000	24,410,000
Weighted-average units outstanding – diluted									24,410,000	24,410,000	24,410,000
(Loss) earnings per limited partner unit:
Basic (in dollars per share)	(3.28)	0.32	(0.03)	0	(0.65)	0.08	0.05	0.02	$ (2.88)	$ (0.44)	$ 0.79
Diluted (in dollars per share)	$ (3.28)	$ 0.32	$ (0.03)	$ 0	$ (0.65)	$ 0.08	$ 0.05	$ 0.02	$ (2.88)	$ (0.44)	$ 0.79

UNIT-BASED COMPENSATION - SMLP

UNIT-BASED COMPENSATION - SMLP Long-Term Incentive Plan (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Weighted-average grant date fair value
Unit-based compensation	$ 6,174	$ 4,696	$ 2,999
Phantom Units
Weighted-average grant date fair value
Award vesting period	3 years
SMLP LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units reserved for issuance	5,000,000
Units available for future issuance	4,400,000
Weighted-average grant date fair value
Unrecognized unit-based compensation	$ 5,500
Remaining vesting period	1 year 2 months
Forfeitures assumed in the determination of estimated compensation expense	0
SMLP LTIP | General and administrative expense
Weighted-average grant date fair value
Unit-based compensation	$ 6,174	$ 4,696	$ 2,999
SMLP LTIP | Phantom and Restricted Units
Phantom and Restricted Unit Activity
Nonvested units, beginning of period	336,202	283,682	131,558
Units granted			156,165
Unit vested		(61,917)
Nonvested units, end of period	379,911	336,202	283,682
Weighted-average grant date fair value
Nonvested, Weighted-average grant date fair value, beginning (in dollars per unit)	$ 30.61	$ 23.41	$ 20
Units granted, Weighted-average grant date fair value (in dollars per unit)			26.33
Units vested, Weighted-average grant date fair value (in dollars per unit)		25.33
Nonvested, Weighted-average grant date fair value, ending (in dollars per unit)	$ 31.13	$ 30.61	$ 23.41
SMLP LTIP | Phantom Units
Phantom and Restricted Unit Activity
Units granted	289,735	136,867
Unit vested	(229,497)
Units forfeited	(16,529)	(22,430)	(4,041)
Weighted-average grant date fair value
Units granted, Weighted-average grant date fair value (in dollars per unit)	$ 29.21	$ 42.32
Units vested, Weighted-average grant date fair value (in dollars per unit)	27.66
Units forfeited, Weighted-average grant date fair value (in dollars per unit)	$ 35.09	$ 25.56	$ 25.99

UNIT-BASED COMPENSATION - SMP N

UNIT-BASED COMPENSATION - SMP Net Profits Interests (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation	$ 6,174	$ 4,696	$ 2,999
SMP Net Profits Interests
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Portion of membership interests authorized for issuance, percent				7.50%
Award vesting period	5 years
Summit Investments' equity in contributed subsidiaries | SMP Net Profits Interests | General and administrative expense
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation	$ 85	$ 340	$ 830

UNIT-BASED COMPENSATION - DFW N

UNIT-BASED COMPENSATION - DFW Net Profits Interests (Details) - DFW Net Profit Interests $ in Millions	7 Months Ended	12 Months Ended
	Apr. 30, 2013USD ($)holdershares	Dec. 31, 2015shares	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Portion of membership interests authorized for issuance, percent			5.00%
Award vesting period		4 years
Repurchase of DFW Net Profits Interest, number of holders | holder	7
Payment to acquire vested net profits interests | $	$ 12.2
Restricted units exchanged for unvested net profits interests	7,393
Remaining or outstanding interests		0

RELATED-PARTY TRANSACTIONS (Det

RELATED-PARTY TRANSACTIONS (Details) - General partner - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operation and maintenance expense
RELATED-PARTY TRANSACTIONS
Expenses from transactions with related party	$ 21,537	$ 19,782	$ 14,323
General and administrative expense
RELATED-PARTY TRANSACTIONS
Expenses from transactions with related party	$ 21,116	$ 22,370	$ 18,662

COMMITMENTS AND CONTINGENCIES72

COMMITMENTS AND CONTINGENCIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Total rent expense related to operating leases	$ 1,990	$ 1,786	$ 1,495

ACQUISITIONS AND DROP DOWN TR73

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Polar and Divide Drop Down (Details) - USD ($) $ in Thousands, shares in Millions	May. 18, 2015	Feb. 15, 2013	Jul. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Values of Assets Acquired and Liabilities Assumed:
Goodwill				$ 16,211	$ 265,062	$ 319,261
Polar Midstream and Epping
Business Acquisition [Line Items]
Total consideration	$ 285,677
Liabilities incurred for acquisition	92,500
Cash payment for working capital and capital expenditure adjustments			$ 4,300
Fair Values of Assets Acquired and Liabilities Assumed:
Cost of acquired entity, purchase price	$ 285,677
Polar Midstream and Epping | Common units
Business Acquisition [Line Items]
Number of shares issued for acquisition	193.4
Polar Midstream and Epping | General Partner Units
Business Acquisition [Line Items]
Number of shares issued for acquisition	4.1
Polar Midstream and Epping | Previously Reported
Business Acquisition [Line Items]
Total consideration	$ 290,000
Fair Values of Assets Acquired and Liabilities Assumed:
Cost of acquired entity, purchase price	$ 290,000
Polar Midstream | Summit Investments
Business Acquisition [Line Items]
Total consideration		$ 216,105
Fair Values of Assets Acquired and Liabilities Assumed:
Cost of acquired entity, purchase price		216,105
Current assets		368
Property, plant, and equipment		9,755
Other noncurrent assets		7,201
Total assets acquired		17,324
Current liabilities		4,592
Total liabilities assumed		4,592
Net identifiable assets acquired		12,732
Goodwill		$ 203,373

ACQUISITIONS AND DROP DOWN TR74

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Red Rock Gathering (Details) - USD ($) $ in Thousands	Mar. 18, 2014	Feb. 28, 2015	Mar. 31, 2014	Feb. 28, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Purchase accounting adjustments					$ 0	$ 1,185	$ 0
Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Cost of acquired entity, cash paid	$ 305,000	$ 2,900		$ 307,900
Purchase accounting adjustments						$ 1,200
Red Rock Gathering Company, LLC | Revolving credit facility
Business Acquisition [Line Items]
Borrowings incurred for acquisition			$ 100,000

ACQUISITIONS AND DROP DOWN TR75

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Lonestar Assets (Details) - Barnett Shale Play $ in Millions	Sep. 30, 2014USD ($)contract
Property, Plant and Equipment [Line Items]
Payments to acquire gas gathering assets | $	$ 10.9
Number of long-term, fee-based contracts | contract	2

ACQUISITIONS AND DROP DOWN TR76

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Bison Midstream (Details) - USD ($) $ in Thousands	Jun. 04, 2013	Feb. 15, 2013	Dec. 31, 2015	Dec. 31, 2013	Dec. 31, 2014
Fair Values of Assets Acquired and Liabilities Assumed:
Goodwill			$ 16,211	$ 319,261	$ 265,062
Gas Gathering Contract | Minimum
Business Acquisition [Line Items]
Useful lives			10 years
Gas Gathering Contract | Maximum
Business Acquisition [Line Items]
Useful lives			25 years
Bison Midstream
Fair Values of Assets Acquired and Liabilities Assumed:
Cost of acquired entity, purchase price	$ 248,914
Cost of acquired entity, cash paid	200,000
Liabilities incurred for acquisition	200,000
Purchase price assigned to Bison Gas Gathering system				$ 303,168
Bison Midstream | Common units
Fair Values of Assets Acquired and Liabilities Assumed:
Cost of acquired entity, equity interests issued and issuable	47,900
Bison Midstream | General Partner Units
Fair Values of Assets Acquired and Liabilities Assumed:
Cost of acquired entity, equity interests issued and issuable	1,000
Purchase price assigned to Bison Gas Gathering system	$ 303,200
Bison Midstream | Summit Investments
Fair Values of Assets Acquired and Liabilities Assumed:
Cost of acquired entity, purchase price		$ 303,168
Current assets		5,705
Property, plant, and equipment		85,477
Intangible assets		164,502
Other noncurrent assets		2,187
Total assets acquired		257,871
Current liabilities		6,112
Other noncurrent liabilities		2,790
Total liabilities assumed		8,902
Net identifiable assets acquired		248,969
Goodwill		$ 54,199
Bison Midstream | Gas Gathering Contract | Minimum
Business Acquisition [Line Items]
Useful lives			5 years
Bison Midstream | Gas Gathering Contract | Maximum
Business Acquisition [Line Items]
Useful lives			15 years
Bison Midstream | Gas Gathering Contract | Weighted Average
Business Acquisition [Line Items]
Useful lives			12 years

ACQUISITIONS AND DROP DOWN TR77

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Mountaineer Midstream (Details) $ in Thousands	Jun. 21, 2013USD ($)compressor_station	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Fair Values of Assets Acquired and Liabilities Assumed:
Goodwill		$ 16,211	$ 265,062	$ 319,261
Contract intangibles
Business Acquisition [Line Items]
Useful lives		12 years 6 months	12 years 6 months
Mountaineer Midstream
Business Acquisition [Line Items]
Cost of acquired entity, purchase price	$ 210,000
Number of compressor stations acquired | compressor_station	2
Liabilities incurred for acquisition	$ 110,000
Cost of acquired entity, equity interests issued and issuable	100,000
Mountaineer Midstream revenues since acquisition				9,600
Mountaineer Midstream net income since acquisition				$ 2,300
Fair Values of Assets Acquired and Liabilities Assumed:
Property, plant, and equipment	163,661
Total assets acquired	193,789
Total liabilities assumed	0
Net identifiable assets acquired	193,789
Goodwill	16,211
Mountaineer Midstream | Gas gathering agreement contract intangibles
Fair Values of Assets Acquired and Liabilities Assumed:
Intangible assets	24,019
Mountaineer Midstream | Contract intangibles
Business Acquisition [Line Items]
Useful lives		13 years
Mountaineer Midstream | Rights-of-way
Fair Values of Assets Acquired and Liabilities Assumed:
Intangible assets	6,109
Mountaineer Midstream | Previously Reported
Fair Values of Assets Acquired and Liabilities Assumed:
Property, plant, and equipment	158,300
Goodwill	18,100
Mountaineer Midstream | Previously Reported | Contract intangibles
Fair Values of Assets Acquired and Liabilities Assumed:
Intangible assets	27,100
Mountaineer Midstream | Previously Reported | Rights-of-way
Fair Values of Assets Acquired and Liabilities Assumed:
Intangible assets	$ 6,500

ACQUISITIONS AND DROP DOWN TR78

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Subsequent Event (Details) - SMP Holdings - Subsequent Event $ in Millions	Feb. 25, 2016USD ($)
Business Acquisition [Line Items]
Cost of acquired entity, cash paid	$ 360
Deferred payment multiple	6.5

ACQUISITIONS AND DROP DOWN TR79

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Revenue and Net Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Revenues	$ 102,601	$ 106,557	$ 80,944	$ 81,217	$ 108,230	$ 90,044	$ 90,649	$ 83,780	$ 371,319	$ 372,703	$ 323,686
Net (loss) income									(186,809)	(14,734)	52,837
Summit Midstream Partners, LP
Business Acquisition [Line Items]
Revenues									358,046	338,941	241,089
Net (loss) income									(192,212)	(23,992)	43,584
Polar Midstream and Epping
Business Acquisition [Line Items]
Revenues									13,273	22,449	3,893
Net (loss) income									$ 5,403	6,430	(467)
Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Revenues										11,313	50,114
Net (loss) income										$ 2,828	9,668
Bison Midstream
Business Acquisition [Line Items]
Revenues											28,590
Net (loss) income											$ 52

ACQUISITIONS AND DROP DOWN TR80

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Unaudited Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended		12 Months Ended
	May. 31, 2015	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Pro forma total revenues					$ 335,837
Pro forma net income					$ 46,904
Limited partners, Common
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Pro forma EPU, basic and diluted (in dollars per share)					$ 0.78
Subordinated Units
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Pro forma EPU, basic and diluted (in dollars per share)					$ 0.78
Bison Midstream and Mountaineer Midstream
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Common unit issuance			4,661,547
Incremental borrowings on revolving credit facility					$ 310,000
Revenues included in consolidated revenues					87,196
Net income included in consolidated net income					(457)
Bison Midstream and Mountaineer Midstream | Acquisition-related costs
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Nonrecurring transaction cost					$ 2,500
General partner
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
General partner interest (as a percent)	2.00%	2.00%	2.00%	2.00%	2.00%

UNAUDITED QUARTERLY FINANCIAL81

UNAUDITED QUARTERLY FINANCIAL DATA (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Limited Partners' Capital Account [Line Items]
Revenues	$ 102,601	$ 106,557	$ 80,944	$ 81,217	$ 108,230	$ 90,044	$ 90,649	$ 83,780	$ 371,319	$ 372,703	$ 323,686
Net (loss) income attributable to SMLP	(220,468)	23,604	2,985	1,667	(37,686)	6,113	4,036	3,545	(192,212)	(23,992)	43,584
Less net (loss) income attributable to general partner, including IDRs	(2,469)	2,408	1,891	1,568	689	1,204	801	431	3,398	3,125	1,035
Net (loss) income attributable to limited partners	(217,999)	21,196	$ 1,094	$ 99	(38,375)	$ 4,909	$ 3,235	$ 3,114	(195,610)	(27,117)	42,549
(Loss) earnings per limited partner unit:
Goodwill impairment	248,900				54,200				248,851	54,199	0
Long-lived asset impairment	$ 1,600	$ 7,700			$ 5,500				9,305	5,505	0
Common units
Limited Partners' Capital Account [Line Items]
Net (loss) income attributable to limited partners									$ (125,437)	$ (16,324)	$ 23,227
(Loss) earnings per limited partner unit:
Basic (in dollars per share)	$ (3.28)	$ 0.32	$ 0.05	$ 0	$ (0.65)	$ 0.08	$ 0.05	$ 0.08	$ (3.20)	$ (0.49)	$ 0.86
Diluted (in dollars per share)	(3.28)	0.32	0.05	0	(0.65)	0.08	0.05	0.08	$ (3.20)	$ (0.49)	$ 0.86
Subordinated units
Limited Partners' Capital Account [Line Items]
Net (loss) income attributable to limited partners									$ (70,173)	$ (10,793)	$ 19,322
(Loss) earnings per limited partner unit:
Basic (in dollars per share)	(3.28)	0.32	(0.03)	0	(0.65)	0.08	0.05	0.02	$ (2.88)	$ (0.44)	$ 0.79
Diluted (in dollars per share)	$ (3.28)	$ 0.32	$ (0.03)	$ 0	$ (0.65)	$ 0.08	$ 0.05	$ 0.02	$ (2.88)	$ (0.44)	$ 0.79
Previously Reported
Limited Partners' Capital Account [Line Items]
Revenues		$ 103,249	$ 77,274	$ 68,579		$ 79,030	$ 80,796	$ 76,202
Bison Midstream | Adjustment
Limited Partners' Capital Account [Line Items]
Revenues		3,308	3,670	4,056		5,260	4,665	4,399
Polar and Divide Drop Down | Adjustment
Limited Partners' Capital Account [Line Items]
Revenues		$ 0	$ 0	$ 8,582		$ 5,754	$ 5,188	$ 3,179