Summit Midstream Partners (SMLP) 8-K 14 Sep 15 Other Events Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2014
Document and Entity Information [Abstract]
Document Type	8-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2014
Entity Registrant Name	Summit Midstream Partners, LP
Entity Central Index Key	1,549,922

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 26,504	$ 20,357
Accounts receivable	89,201	69,790
Other current assets	3,517	4,959
Total current assets	119,222	95,106
Property, plant and equipment, net	1,414,350	1,256,314
Intangible assets, net	477,734	505,844
Goodwill	265,062	319,261
Other noncurrent assets	17,353	14,618
Total assets	2,293,721	2,191,143
Current liabilities:
Trade accounts payable	24,855	38,507
Due to affiliate	2,711	653
Deferred revenue	2,377	1,555
Ad valorem taxes payable	9,118	8,375
Accrued interest	18,858	12,144
Other current liabilities	13,550	14,393
Total current liabilities	71,469	75,627
Long-term debt	808,000	586,000
Noncurrent liability, net	5,577	6,374
Deferred revenue	55,239	29,683
Other noncurrent liabilities	1,715	372
Total liabilities	$ 942,000	$ 698,056
Commitments and contingencies
Common limited partner capital (34,427 units issued and outstanding at December 31, 2014 and 29,080 units issued and outstanding at December 31, 2013)	$ 649,060	$ 566,532
Subordinated limited partner capital (24,410 units issued and outstanding at December 31, 2014 and 2013)	293,153	379,287
General partner interests (1,201 units issued and outstanding at December 31, 2014 and 1,091 units issued and outstanding at December 31, 2013)	24,676	23,324
Summit Investments' equity in contributed subsidiaries	384,832	523,944
Total partners' capital	1,351,721	1,493,087
Total liabilities and partners' capital	$ 2,293,721	$ 2,191,143

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares shares in Thousands	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Common limited partner capital, units issued	34,427	29,080
Common limited partner capital, units outstanding	34,427	29,080
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	1,201	1,091
General partner interests, units outstanding	1,201	1,091

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Gathering services and related fees	$ 239,595,000	$ 197,174,000	$ 145,463,000
Natural gas, NGLs and condensate sales	97,094,000	88,185,000	22,825,000
Other revenues	16,446,000	11,454,000	6,135,000
Total revenues	353,135,000	296,813,000	174,423,000
Costs and expenses:
Cost of natural gas and NGLs	52,847,000	41,164,000	3,224,000
Operation and maintenance	88,927,000	77,114,000	53,882,000
General and administrative	38,269,000	32,273,000	22,182,000
Transaction costs	730,000	2,841,000	2,025,000
Depreciation and amortization	87,349,000	70,574,000	36,674,000
Loss on asset sales, net	442,000	113,000	0
Goodwill impairment	54,199,000	0	0
Long-lived asset impairment	5,505,000	0	0
Total costs and expenses	328,268,000	224,079,000	117,987,000
Other income	1,189,000	5,000	9,000
Interest expense	(40,159,000)	(19,173,000)	(7,340,000)
Affiliated interest expense	0	0	(5,426,000)
(Loss) income before income taxes	(14,103,000)	53,566,000	43,679,000
Income tax expense	(631,000)	(729,000)	(682,000)
Net (loss) income	(14,734,000)	52,837,000	42,997,000
Less: net income attributable to the pre-IPO period	0	0	24,112,000
Less: net income attributable to Summit Investments	9,258,000	9,253,000	1,271,000
Net (loss) income attributable to SMLP	(23,992,000)	43,584,000	17,614,000
Less: net (loss) income attributable to general partner, including IDRs	3,125,000	1,035,000	352,000
Net (loss) income attributable to limited partners	$ (27,117,000)	$ 42,549,000	17,262,000
Weighted-average limited partner units outstanding
Cash distributions declared per common unit (in dollars per unit)	$ 2.04	$ 1.725
Common units
Costs and expenses:
Net (loss) income attributable to limited partners	$ (16,324,000)	$ 23,227,000	$ 8,632,000
(Loss) earnings per limited partner unit
Basic (in dollars per share)	$ (0.49)	$ 0.86	$ 0.35
Diluted (in dollars per share)	$ (0.49)	$ 0.86	$ 0.35
Weighted-average limited partner units outstanding
Basic (shares)	33,311	26,951	24,412
Diluted (shares)	33,311	27,101	24,544
Subordinated Units
Costs and expenses:
Net (loss) income attributable to limited partners	$ (10,793,000)	$ 19,322,000	$ 8,630,000
(Loss) earnings per limited partner unit
Basic (in dollars per share)	$ (0.44)	$ 0.79	$ 0.35
Diluted (in dollars per share)	$ (0.44)	$ 0.79	$ 0.35
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 AND MEMBERSHIP INTERESTS - USD ($) $ in Thousands	Total	SMLP units	Class B Units	Summit Investments' equity in contributed subsidiaries	Summit Investments' equity in contributed subsidiariesClass B Units	Membership Interests	Membership InterestsClass B Units	Limited partners, Common	Limited partners, CommonSMLP units	Limited partners, CommonClass B Units	Limited partners, Subordinated	General partner	Bison Midstream	Bison MidstreamSummit Investments' equity in contributed subsidiaries	Bison MidstreamLimited partners, Common	Bison MidstreamLimited partners, Subordinated	Bison MidstreamGeneral partner	Mountaineer Midstream	Mountaineer MidstreamLimited partners, Common	Mountaineer MidstreamGeneral partner	Polar Midstream and Epping	Polar Midstream and EppingSummit Investments' equity in contributed subsidiaries
Beginning balance at Dec. 31, 2011	$ 640,818			$ 0		$ 640,818		$ 0			$ 0	$ 0
Increase (Decrease) in Partners' Capital [Roll Forward]
Net (loss) income	42,997			1,271		24,112		8,631			8,631	352
Unit-based compensation		$ 269	$ 1,607				$ 1,793		$ 269	$ (186)
Net assets retained by the Predecessor	(4,417)					(4,417)
Contribution from general partner						(662,306)		211,938			430,498	19,870
Assets contributed to Red Rock Gathering from Summit Investments	0
Issuance of common units, net of offering costs	262,382							262,382
Distributions	(123,138)							(64,178)			(58,960)
Consolidation of net assets	206,694			206,694
Contribution of net assets from Summit Investments in excess of consideration paid for Bison Midstream	0
Cash advance from Summit Investments to contributed subsidiaries, net	500			500
Capitalized interest allocated from Summit Investments to contributed subsidiaries	0
Expenses paid by Summit Investments on behalf of contributed subsidiaries	2,536			2,536
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	0
Ending balance at Dec. 31, 2012	1,030,248			211,001		$ 0		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
Unit-based compensation		$ 2,999	847		$ 830				2,999	$ 17
Net assets retained by the Predecessor	0
Assets contributed to Red Rock Gathering from Summit Investments	0
Distributions	(90,196)							(46,286)			(42,107)	(1,803)
Consolidation of net assets													$ 303,168	$ 303,168							$ 216,105	$ 216,105
Contribution from Summit Investments to Bison Midstream													2,229	2,229
Units issued to acquire entity													(200,000)	(248,914)	$ 47,936		$ 978	$ 100,000	$ 98,000	$ 2,000
Contribution of net assets from Summit Investments in excess of consideration paid for Bison Midstream	56,535												$ 0	$ (56,535)	$ 28,558	$ 26,846	$ 1,131
Repurchase of DFW Net Profits Interests	(11,957)							(5,859)			(5,859)	(239)
Cash advance from Summit Investments to contributed subsidiaries, net	72,745			72,745
Capitalized interest allocated from Summit Investments to contributed subsidiaries	2,046			2,046
Expenses paid by Summit Investments on behalf of contributed subsidiaries	11,964			11,964
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	52			52
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
Unit-based compensation	4,696		$ 340					4,696
Net assets retained by the Predecessor	0
Contribution from general partner	4,235											4,235
Purchase of Red Rock Gathering	(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
Issuance of common units, net of offering costs	197,806							197,806
Distributions	(122,224)							(67,658)			(49,796)	(4,770)
Tax withholdings on vested SMLP LTIP awards	(656)							(656)
Contribution of net assets from Summit Investments in excess of consideration paid for Bison Midstream	0
Cash advance from Summit Investments to contributed subsidiaries, net	81,421			81,421
Capitalized interest allocated from Summit Investments to contributed subsidiaries	606			606
Expenses paid by Summit Investments on behalf of contributed subsidiaries	10,483			10,483
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	597
Repurchase of SMLP LTIP units	(228)								$ (228)
Ending balance at Dec. 31, 2014	$ 1,351,721			$ 384,832				$ 649,060			$ 293,153	$ 24,676

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net (loss) income	$ (14,734,000)	$ 52,837,000	$ 42,997,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	88,293,000	71,606,000	36,866,000
Amortization of deferred loan costs	2,770,000	2,246,000	1,458,000
Unit-based compensation	5,036,000	3,846,000	1,876,000
Loss on asset sales, net	442,000	113,000	0
Goodwill impairment	54,199,000	0	0
Long-lived asset impairment	5,505,000	0	0
Purchase accounting adjustment	(1,185,000)	0	0
Pay-in-kind interest on promissory notes payable to Sponsors	0	0	5,426,000
Changes in operating assets and liabilities:
Accounts receivable	(19,255,000)	(20,490,000)	(8,174,000)
Due to/from affiliate	(883,000)	1,427,000	(773,000)
Trade accounts payable	(684,000)	(3,419,000)	(2,536,000)
Change in deferred revenue	26,378,000	16,685,000	9,994,000
Ad valorem taxes payable	743,000	(11,000)	3,125,000
Accrued interest	6,714,000	12,128,000	(484,000)
Other, net	1,658,000	3,501,000	(383,000)
Net cash provided by operating activities	154,997,000	140,469,000	89,392,000
Cash flows from investing activities:
Capital expenditures	(220,820,000)	(182,978,000)	(77,296,000)
Proceeds from asset sales	325,000	585,000	0
Acquisition of gathering systems	(10,872,000)	(210,000,000)	0
Acquisition of gathering systems from affiliate	(305,000,000)	(200,000,000)	0
Net cash used in investing activities	(536,367,000)	(592,393,000)	(77,296,000)
Cash flows from financing activities:
Distributions to unitholders	(122,224,000)	(90,196,000)	0
Borrowings under revolving credit facility	237,295,000	380,950,000	213,000,000
Repayments under revolving credit facility	(315,295,000)	(294,180,000)	(160,770,000)
Deferred loan costs	(5,320,000)	(10,608,000)	(3,344,000)
Tax withholdings on vested SMLP LTIP awards	(656,000)	0	0
Proceeds from issuance of common units, net	197,806,000	0	263,125,000
Contribution from general partner	4,235,000	2,229,000	0
Cash advance from Summit Investments to contributed subsidiaries, net	81,421,000	72,745,000	500,000
Expenses paid by Summit Investments on behalf of contributed subsidiaries	10,483,000	11,964,000	2,536,000
Issuance of senior notes	300,000,000	300,000,000	0
Issuance of units to affiliate in connection with the Mountaineer Acquisition	0	100,000,000	0
Repurchase of equity-based compensation awards	(228,000)	(11,957,000)	0
Red Rock Gathering cash contributed by Summit Investments	0	0	1,097,000
Repayment of promissory notes payable to Sponsors	0	0	(209,230,000)
Distributions to Sponsors	0	0	(123,138,000)
Net cash provided by (used in) financing activities	387,517,000	460,947,000	(16,224,000)
Net change in cash and cash equivalents	6,147,000	9,023,000	(4,128,000)
Cash and cash equivalents, beginning of period	20,357,000	11,334,000	15,462,000
Cash and cash equivalents, end of period	26,504,000	20,357,000	11,334,000
Supplemental Cash Flow Disclosures:
Cash interest paid	31,524,000	9,016,000	8,283,000
Less: capitalized interest	3,778,000	6,255,000	2,784,000
Interest paid (net of capitalized interest)	27,746,000	2,761,000	5,499,000
Cash paid for taxes	0	660,000	650,000
Noncash Investing and Financing Activities:
Capital expenditures in trade accounts payable (period-end accruals)	18,076,000	29,860,000	8,523,000
Excess of purchase price over acquired carrying value of Red Rock Gathering	66,124,000	0	0
Red Rock Gathering working capital adjustment	(2,941,000)	0	0
Assets contributed to Red Rock Gathering from Summit Investments	4,233,000	0	0
Issuance of units to affiliate to partially fund the Bison Drop Down	0	48,914,000	0
Contribution of net assets from Summit Investments in excess of consideration paid for Bison Midstream	0	56,535,000	0
Capitalized interest allocated to contributed subsidiaries from Summit Investments	606,000	2,046,000	0
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	597,000	52,000	0
Pay-in-kind interest on promissory notes payable to Sponsors	0	0	6,337,000
Net assets retained by the Predecessor	0	0	4,417,000
Deferred initial public offering costs in trade accounts payable	$ 0	$ 0	$ 743,000

ORGANIZATION, BUSINESS OPERATIO

ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION	12 Months Ended
	Dec. 31, 2014
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 North America. Effective with the completion of its IPO on October 3, 2012, SMLP had a 100% ownership interest in Summit Midstream Holdings, LLC ("Summit Holdings") which had a 100% ownership interest in both DFW Midstream Services LLC ("DFW Midstream") and Grand River Gathering, LLC ("Grand River Gathering" 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 wholly owned subsidiary of Summit Midstream Partners, LLC ("Summit Investments") (the "Bison Drop Down"), and thereby acquired certain associated natural gas gathering pipeline, dehydration and compression assets in the Bakken Shale Play in Mountrail and Burke counties in North Dakota (the "Bison Gas Gathering system"). 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 Bison Gas Gathering system was carved out from Meadowlark Midstream in connection with the Bison Drop Down. As such, it was determined to be a transaction among entities under common control. On June 21, 2013, Mountaineer Midstream Company, LLC ("Mountaineer Midstream"), a newly formed, wholly owned subsidiary of the Partnership, acquired certain natural gas gathering pipeline and compression assets in the Marcellus Shale Play in Doddridge and Harrison counties, West Virginia 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"). In October 2012, Summit Investments acquired ETC Canyon Pipeline, LLC ("Canyon") from a subsidiary of Energy Transfer Partners, L.P. The Canyon gathering and processing assets were contributed to Red Rock Gathering, a newly formed, wholly owned subsidiary of Summit Investments. Red Rock Gathering gathers and processes natural gas and natural gas liquids in the Piceance Basin in western Colorado and eastern Utah. As such, the Red Rock Drop Down was determined to be a transaction among entities under common control. Concurrent with the closing of the Red Rock Drop Down, SMLP contributed its interest in Red Rock Gathering to Grand River Gathering. On May 18, 2015, the Partnership acquired certain crude oil and produced water gathering systems and under-development transmission pipelines held by Polar Midstream, LLC ("Polar Midstream") and Epping Transmission Company, LLC ("Epping") located in the Williston Basin (collectively the "Polar and Divide system") from SMP Holdings (the "Polar and Divide Drop Down"). Polar Midstream and Epping are Delaware limited liability companies formed by Summit Investments in April 2014. Polar Midstream's 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. Because the Polar and Divide system was acquired from subsidiaries of Summit Investments, it was deemed a transaction among entities under common control. Common control began in (i) February 2013 for Polar Midstream and (ii) April 2014 for Epping. Summit Investments is a Delaware limited liability company and the predecessor for accounting purposes of SMLP. Summit Investments was formed and began operations in September 2009. Through August 2011, Summit Investments was wholly owned by Energy Capital Partners II, LLC and its parallel and co-investment funds (collectively, "Energy Capital Partners"). In August 2011, Energy Capital Partners sold an interest in Summit Investments to a subsidiary of GE Energy Financial Services, Inc. ("GE Energy Financial Services"). In June 2014, GE Energy Financial Services exchanged 100% of its Class A membership interests in Summit Investments for a new class of membership interests, structured as Class C Preferred interests. As a result, GE Energy Financial Services is no longer a Class A member of Summit Investments. Consequently, we refer to Energy Capital Partners and GE Energy Financial Services as our "Sponsors" for the period from August 17, 2011 until June 17, 2014, and we refer to Energy Capital Partners as our sole "Sponsor" subsequent to June 2014. In March 2013, Summit Investments contributed the ownership of its SMLP common and subordinated units along with its 2% general partner interest in SMLP (including the incentive distribution rights ("IDRs") in respect of SMLP) to Summit Midstream Partners Holdings, LLC ("SMP Holdings") in exchange for a continuing 100% interest in SMP Holdings. As of December 31, 2014 , Summit Investments, through a wholly owned subsidiary, held 5,293,571 SMLP common units, all of our subordinated units, all of our general partner units representing a 2% general partner interest in SMLP and all of our IDRs. SMLP is managed and operated by the board of directors and executive officers of Summit Midstream GP, LLC (the "general partner"). Summit Investments, as the ultimate owner of our general partner, controls SMLP and has the right to appoint the entire board of directors of our general partner, including our independent directors. SMLP's operations are conducted through, and our operating assets are owned by, various wholly-owned operating subsidiaries. However, neither SMLP nor its subsidiaries have any employees. The general partner has the sole responsibility for providing the personnel necessary to conduct SMLP's operations, whether through directly hiring employees or by obtaining the services of personnel employed by others, including Summit Investments. All of the personnel that conduct SMLP's business are employed by the general partner and its subsidiaries, but these individuals are sometimes referred to as our employees. References to the "Company," "we," or "our," when used for dates or periods ended on or after the IPO, refer collectively to SMLP and its subsidiaries. References to the "Company," "we," or "our," when used for dates or periods ended prior to the IPO, refer collectively to Summit Investments and its subsidiaries. Initial Public Offering. On October 3, 2012, SMLP completed its IPO and the following transactions occurred: • Summit Investments conveyed an interest in Summit Holdings to our general partner as a capital contribution; • our general partner conveyed its interest in Summit Holdings to SMLP in exchange for (i) a continuation of its 2% general partner interest in SMLP, represented by 996,320 general partner units, and (ii) SMLP incentive distribution rights, or IDRs; • Summit Investments conveyed its remaining interest in Summit Holdings to SMLP in exchange for (i) 10,029,850 common units (net of the impact of selling 1,875,000 common units to the public for cash in connection with the exercise of the underwriters’ option to purchase additional common units), representing a 20.1% limited partner interest in SMLP, (ii) 24,409,850 subordinated units, representing a 49.0% limited partner interest in SMLP, and (iii) the right to receive $88.0 million in cash as reimbursement for certain capital expenditures made with respect to the contributed assets; • pursuant to its long-term incentive plan, SMLP granted 5,000 common units (in the aggregate) to two of its directors and 125,000 phantom units, with distribution equivalent rights, to certain employees; • SMLP issued 14,375,000 common units to the public (including 1,875,000 additional common units sold out of the common units originally allocated to Summit Investments) representing a 28.9% limited partner interest in SMLP; and • SMLP used the proceeds, net of underwriters’ fees, from the IPO of approximately $269.4 million to (i) repay $140.0 million outstanding under the revolving credit facility; (ii) make cash distributions to Summit Investments of (a) $88.0 million to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it contributed to us and (b) $35.1 million representing the funds received in connection with the underwriters exercising their option to purchase additional common units; and (iii) pay IPO expenses of approximately $6.3 million . 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: • Mountaineer Midstream, a natural gas gathering system, operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia; • Bison Midstream, an associated natural gas gathering system, operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; • the Polar and Divide system ("Polar and Divide"), a crude oil and produced water gathering system and transmission pipelines (under development), operating in the Williston Basin; • DFW Midstream, a natural gas gathering system, operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and • Grand River Gathering, a natural gas gathering and processing system, operating 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 our wholly owned subsidiary, Summit Holdings, are: DFW Midstream (which includes Mountaineer Midstream); Bison Midstream (and its wholly owned subsidiaries Polar Midstream and Epping); and Grand River Gathering (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 five reportable segments: • the Marcellus Shale, which is served by Mountaineer Midstream; • the Williston Basin – Gas, which is served by Bison Midstream; • the Williston Basin – Liquids, which is served by 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. For the purposes of the consolidated financial statements, SMLP's results of operations reflect the Partnership's operations subsequent to the IPO and the results of the Predecessor for the period prior to the IPO. The consolidated financial statements also reflect the results of operations of: (i) Red Rock Gathering since October 23, 2012, (ii) Polar Midstream since February 16, 2013, (iii) Bison Midstream since February 16, 2013 and (iv) Mountaineer Midstream since June 22, 2013. SMLP recognized its acquisitions of Red Rock Gathering, Polar Midstream and Bison Midstream at Summit Investments' historical cost because the acquisitions were executed by entities under common control. The excess of Summit Investments' net investment in Polar Midstream and Bison Midstream over the purchase price paid by SMLP was recognized as an addition to partners' capital. The excess of the purchase price paid by SMLP over Summit Investments' net investment in Red Rock Gathering was recognized as a reduction to partners' capital. Due to the common control aspect, the Red Rock Drop Down, the Polar and Divide Drop Down and the Bison Drop Down were accounted for by the Partnership on an “as-if pooled” basis for the periods during which common control existed. The consolidated financial statements include the assets, liabilities, and results of operations of SMLP or the Predecessor and their respective wholly owned subsidiaries. All intercompany transactions among the consolidated entities have been eliminated in consolidation. The financial position, results of operations and cash flows of Polar Midstream included herein have been derived from the accounting records of Meadowlark Midstream on a carve-out basis. The majority of the assets and liabilities allocated to Polar Midstream have been specifically identified based on Meadowlark Midstream’s existing divisional organization. Goodwill was allocated to Polar Midstream based on initial purchase accounting estimates. Revenues and depreciation and amortization have been specifically identified based on Polar Midstream's relationship to Meadowlark Midstream’s existing divisional structure. Operation and maintenance and general and administrative expenses have been allocated to Polar Midstream based on volume throughput. These allocations and estimates were based on methodologies that management believes are reasonable. The results reflected herein, however, may not reflect what Polar Midstream’s financial position, results of operations or cash flows would have been if Polar Midstream been a stand-alone company. Reclassifications. Certain reclassifications have been made to prior-year amounts to conform to current-year presentation. We evaluated our classification of revenues and concluded that creating an “other revenues” category would provide reporting that was more reflective of our results of operations and how we manage our business. As such, certain revenue transactions that represented the “and other” portions of (i) gathering services and (ii) natural gas, NGLs and condensate sales have been reclassified to other revenues. Other revenues also includes the amortization expense associated with our favorable and unfavorable gas gathering contracts. The amounts reclassified to other revenues for each period presented can be determined based on the total of the other revenues line item and the amount of amortization of favorable and unfavorable gas gathering contracts disclosed in Note 5. We also evaluated our historical classification of electricity expense for Bison Midstream. In connection with the reclassification of certain revenues noted above and to be consistent with the classification of pass-through electricity expense for our other operating segments, we reclassified pass-through electricity expenses for Bison Midstream ( $5.2 million and $3.1 million for the years ended December 31, 2014 and 2013, respectively) from costs of natural gas and NGLs to operation and maintenance. These reclassifications had no impact on total revenues, total costs and expenses, net income, total partners' capital or segment adjusted EBITDA.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2014
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. To the extent we doubt the collectability of our accounts receivable, we recognize an allowance for doubtful accounts. We did not experience any non-payments during the three-year period ended December 31, 2014. As a result, we did not recognize an allowance for doubtful accounts as of December 31, 2014 and 2013. 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. Prior to the Polar and Divide Drop Down and the Red Rock Drop Down, a subsidiary of Summit Investments incurred interest expense related to certain Polar and Divide and Red Rock Gathering capital projects. The associated interest expense was allocated to Polar and Divide and Red Rock Gathering as a noncash equity contribution and capitalized into the basis of the asset. We base an asset’s carrying value on estimates, assumptions and judgments for useful life and salvage value. 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. 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. As of December 31, 2014 and 2013, we evaluated whether any future asset retirement obligations existed. For identified asset retirement obligations, we then evaluated whether the expected retirement date and the related costs of retirement could be estimated. In performing this evaluation, we concluded that our gathering and processing assets have an indeterminate life because they are owned and will operate for an indeterminate future 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, 2014 or 2013. Intangible Assets and Noncurrent Liability. Upon the acquisition of DFW Midstream, certain of our 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 contracts that were above market at acquisition as favorable gas gathering contracts. We have recognized the contract that was deemed to be below market as a noncurrent liability. We amortize these intangibles on a units-of-production basis over the estimated useful life of the contract. We define useful life as the period over which the contract is expected to contribute directly or indirectly to our future cash flows. The related contracts have original terms ranging from 10 years to 20 years. We recognize the amortization expense associated with these intangible assets and liability in other revenues. For our other gas gathering contracts, we amortize contract intangible assets over the period of economic benefit based upon the 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 intangible assets in depreciation and amortization expense. We have right-of-way intangible assets 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. The estimated useful life of our gathering systems is 30 years. We recognize the amortization expense associated with these intangible assets in depreciation and amortization 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 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 an income approach in which we discount the asset’s expected future cash flows to reflect the risk associated with achieving the underlying cash flows. During the three-year period ended December 31, 2014, we concluded that none of our long-lived assets had been impaired, except as discussed in Notes 4 and 5. 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. 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. 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. 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 our electric-drive compression assets on the DFW Midstream system. 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 our 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). 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, 2014 December 31, 2013 Carrying value Estimated fair value (Level 2) Carrying value Estimated fair value (Level 2) (In thousands) Revolving credit facility $ 208,000 $ 208,000 $ 286,000 $ 286,000 5.5% Senior notes 300,000 281,750 — — 7.5% Senior notes 300,000 306,750 300,000 314,625 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, 2014 and December 31, 2013. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the senior notes. Nonfinancial assets and liabilities initially measured at fair value include those acquired and assumed in connection with third-party business combinations. 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 producer customers. We also generate revenue from our marketing of natural gas and NGLs. We realize revenues by receiving fees from our producer customers or by selling the residue natural gas and NGLs. 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 and keep-whole arrangements. These revenues are recognized in natural gas, NGLs and condensate sales with corresponding expense recognition 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 Gathering. 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 natural gas 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: natural gas gathering, treating, and/or processing. Fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase natural gas at the wellhead, or other receipt points, at a settled price at the delivery point less a specified amount, generally the same as the fees we would otherwise charge for gathering of natural gas from the wellhead location to the delivery point. The margins earned are directly related to the volume of natural gas that flows through the system. • 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. • Keep-Whole. Under keep-whole arrangements, after processing we keep 100% of the NGLs produced, and the processed natural gas, or value of the natural gas, is returned to the producer. Since some of the natural gas is used and removed during processing, we compensate the producer for the amount of natural gas used and removed in processing by supplying additional natural gas or by paying an agreed-upon value for the natural gas utilized. These arrangements have commodity price exposure for us because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs. We provide crude oil and produced water gathering services under fee-based arrangements whereby we receive a fee or fees for gathering crude oil and/or produced water. Certain of our natural gas gathering or processing agreements provide for a monthly, quarterly or annual MVC. Under these MVCs, our customers agree to ship a minimum volume of natural gas 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 contract 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 periods to the extent that such customer's throughput volumes in subsequent periods exceed its MVC for that 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 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 volumes of natural gas, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the applicable natural gas gathering agreement. We classify deferred revenue as a current liability for arrangements where the expiration of a customer's right to utilize shortfall payments is twelve 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. Since we are structured as a partnership, we are generally not subject to federal and state income taxes, except as noted below. As a result, our unitholders or members are individually responsible for paying federal and state income taxes on their share of our taxable income. Net income or loss for financial statement purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and the financial reporting 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, the Company 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 $1.0 million deferred tax liability and current income tax expense for the year ended December 31, 2014 was reduced by $0.3 million . The associated deferred tax liability of $1.3 million is included in other noncurrent liabilities at December 31, 2014. Earnings Per Unit ("EPU"). We present earnings or loss per limited partner unit only for periods subsequent to the IPO. Prior to the IPO, Summit Investments' members held membership interests and not units. We determine EPU by dividing the net income or loss that is attributed, in accordance with the net income and loss allocation provisions of the partnership agreement, to the 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 payments to the general partner in connection with its 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 during the years ended December 31, 2014 and 2013, and the period from October 1, 2012 to December 31, 2012. Diluted earnings or loss per limited partner unit 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. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted earnings per limited partner unit calculation, the impact is reflected by applying the treasury stock method. Comprehensive Income. Comprehensive income is the same as net income or 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. Although we believe that we are in material compliance with applicable environmental regulations, the risk of costs and liabilities are inherent in pipeline ownership and operation. 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. There are no such material liabilities in the accompanying financial statements at December 31, 2014 or 2013, and we are currently unaware of any material contingent liabilities that exist with respect to environmental matters. However, we can provide no assurance that significant costs and liabilities will not be incurred by the Partnership in the future. 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 will 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 August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of Effective Date ("ASU 2015-14"). ASU 2015-14 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 February 2015, the FASB issued ASU No. 2015-02—Consolidation (Topic 810): Amendments to the Consolidation Analysis ("ASU 2015-02"). The standard changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. 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 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. 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.

SEGMENT INFORMATION

SEGMENT INFORMATION	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Segment Information	SEGMENT INFORMATION Each of our reportable segments provides midstream services in a specific geographic area. In the fourth quarter of 2014, we discontinued the aggregation of all of our operating segments. Within specific geographic areas, we may further differentiate reportable segments by type of gathering service provided. In connection with the Polar and Divide Drop Down, we identified two reportable segments in the Williston Basin. We had previously only provided natural gas gathering services in the Williston Basin. With the acquisition of Polar Midstream and Epping in May 2015, we now also provide crude oil and produced water gathering services in the Williston Basin. As such, we evaluated the quantitative and qualitative factors for operating segment aggregation in the Williston Basin and concluded that the characteristics for crude oil and produced water gathering services were not sufficiently similar to those of our natural gas gathering services. As a result, we now report the results of Bison Midstream in the Williston Basin – Gas reportable segment and those of Polar Midstream and Epping in the Williston Basin – Liquids reportable segment. As of December 31, 2014, our reportable segments are: • the Marcellus Shale, which is served by Mountaineer Midstream; • the Williston Basin – Gas, which is served by Bison Midstream; • the Williston Basin – Liquids, which is served by Polar and Divide; • the Barnett Shale, which is served by DFW Midstream; and • the Piceance Basin, which is served by Grand River Gathering. Corporate represents those 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. The accounting policies of the reportable segments and Corporate are the same as those described in the summary of significant accounting policies. The following table presents assets by reportable segment as of December 31. December 31, 2014 2013 (In thousands) Assets: Marcellus Shale $ 243,884 $ 214,379 Williston Basin – Gas 311,041 337,610 Williston Basin – Liquids 398,847 307,404 Barnett Shale 428,935 431,578 Piceance Basin 872,437 876,969 Total reportable segment assets 2,255,144 2,167,940 Corporate 38,577 23,203 Total assets $ 2,293,721 $ 2,191,143 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 excludes the effect of allocated corporate expenses, such as certain general and administrative expenses (including compensation-related expenses and professional services fees) interest expense and income tax expense. The following table presents segment adjusted EBITDA by reportable segment. Year ended December 31, 2014 2013 2012 (In thousands) Reportable segment adjusted EBITDA: Marcellus Shale $ 15,940 $ 6,333 Williston Basin – Gas 20,422 16,865 Williston Basin – Liquids 11,129 485 Barnett Shale 60,528 69,473 $ 63,670 Piceance Basin 107,953 80,941 53,179 Total reportable segment adjusted EBITDA $ 215,972 $ 174,097 $ 116,849 The following table presents a reconciliation of income before income taxes to total reportable segment adjusted EBITDA. Year ended December 31, 2014 2013 2012 (In thousands) Reconciliation of Income Before Income Taxes to Segment Adjusted EBITDA: Income before income taxes $ (14,103 ) $ 53,566 $ 43,679 Add: Interest expense and affiliated interest expense 40,159 19,173 12,766 Depreciation and amortization 88,293 71,606 36,866 Allocated corporate expenses 11,065 8,773 10,903 Adjustments related to MVC shortfall payments 26,565 17,025 10,768 Unit-based compensation 5,036 3,846 1,876 Loss on asset sales, net 442 113 — Goodwill impairment 54,199 — — Long-lived asset impairment 5,505 — — Less: Interest income 4 5 9 Impact of purchase price adjustments 1,185 — — Total reportable segment adjusted EBITDA $ 215,972 $ 174,097 $ 116,849 The following table summarizes details by reportable segment for the years ended December 31. Year ended December 31, 2014 2013 2012 (In thousands) Revenues: Marcellus Shale $ 22,694 $ 9,588 Williston Basin – Gas 62,454 50,735 Williston Basin – Liquids 22,449 3,893 Barnett Shale 93,001 105,324 $ 93,453 Piceance Basin 152,537 127,273 81,961 Total reportable segments 353,135 296,813 175,414 Corporate — — (991 ) Total revenues $ 353,135 $ 296,813 $ 174,423 Depreciation and amortization: Marcellus Shale $ 7,648 $ 3,998 Williston Basin – Gas 18,132 16,057 Williston Basin – Liquids 4,359 612 Barnett Shale 15,657 13,929 $ 12,078 Piceance Basin 40,965 35,527 24,310 Total reportable segments 86,761 70,123 36,388 Corporate 588 451 286 Total depreciation and amortization $ 87,349 $ 70,574 $ 36,674 Other income: Marcellus Shale $ — $ — Williston Basin – Gas — — Williston Basin – Liquids — — Barnett Shale — — $ — Piceance Basin 1,185 — — Total reportable segments 1,185 — — Corporate 4 5 9 Total other income $ 1,189 $ 5 $ 9 Capital expenditures: Marcellus Shale $ 33,866 $ 1,822 Williston Basin – Gas 46,927 26,381 Williston Basin – Liquids 92,495 73,602 Barnett Shale 14,567 29,534 $ 39,588 Piceance Basin 32,505 50,709 36,899 Total reportable segments 220,360 182,048 76,487 Corporate 460 930 809 Total capital expenditures $ 220,820 $ 182,978 $ 77,296

PROPERTY, PLANT, AND EQUIPMENT,

PROPERTY, PLANT, AND EQUIPMENT, NET	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT, AND EQUIPMENT, NET	PROPERTY, PLANT, AND EQUIPMENT, NET Details on property, plant, and equipment, net were as follows: Useful lives (In years) December 31, 2014 2013 (Dollars in thousands) Gathering and processing systems and related equipment 30 $ 1,462,706 $ 1,212,227 Construction in progress n/a 44,447 94,130 Other 4-15 28,871 21,885 Total 1,536,024 1,328,242 Less accumulated depreciation 121,674 71,928 Property, plant, and equipment, net $ 1,414,350 $ 1,256,314 During the fourth quarter of 2014, we reviewed certain property, plant and equipment balances associated with a compressor station project on our DFW Midstream system that was terminated and wrote off approximately $5.5 million of costs. The net impact of this action is reflected in long-lived asset impairment on the statement of operations. We also sold certain fixed assets during the fourth quarter of 2014. The net impact of these transactions is reflected in loss on asset sales, net on the statement of operations. Also during the fourth quarter of 2014, prices for natural gas, NGLs and crude oil continued to decline such that we identified a need to evaluate the goodwill associated with the Polar and Divide and Bison Midstream systems. In connection with this evaluation, we also evaluated the property, plant and equipment and intangible assets associated with the Polar and Divide and Bison Midstream systems for impairment and concluded that no impairment was necessary. Construction in progress is depreciated consistent with its applicable asset class once it is placed in service. Depreciation expense related to property, plant, and equipment and capitalized interest were as follows: Year ended December 31, 2014 2013 2012 (In thousands) Depreciation expense $ 49,816 $ 37,313 $ 22,422 Capitalized interest 3,778 6,255 2,784

IDENTIFIABLE INTANGIBLE ASSETS,

IDENTIFIABLE INTANGIBLE ASSETS, NONCURRENT LIABILITY AND GOODWILL	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
IDENTIFIABLE INTANGIBLE ASSETS, NONCURRENT LIABILITY AND GOODWILL	IDENTIFIABLE INTANGIBLE ASSETS, UNFAVORABLE GAS GATHERING CONTRACT AND GOODWILL Intangible Assets and Unfavorable Gas Gathering Contract. Details regarding our intangible assets and the unfavorable gas gathering contract, all of which are subject to amortization, follow. 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 amortizable intangible assets $ 574,240 $ (96,506 ) $ 477,734 Unfavorable gas gathering contract 10.0 $ 10,962 $ (5,385 ) $ 5,577 December 31, 2013 Useful lives (In years) Gross carrying amount Accumulated amortization Net (Dollars in thousands) Favorable gas gathering contracts 18.7 $ 24,195 $ (6,315 ) $ 17,880 Contract intangibles 12.5 426,464 (43,158 ) 383,306 Rights-of-way 24.7 112,416 (7,758 ) 104,658 Total amortizable intangible assets $ 563,075 $ (57,231 ) $ 505,844 Unfavorable gas gathering contract 10.0 $ 10,962 $ (4,588 ) $ 6,374 We recognized amortization expense in other revenues as follows: Year ended December 31, 2014 2013 2012 (In thousands) Amortization expense – favorable gas gathering contracts $ (1,741 ) $ (2,078 ) $ (1,715 ) Amortization expense – unfavorable gas gathering contract 797 1,046 1,524 Amortization of favorable and unfavorable contracts $ (944 ) $ (1,032 ) $ (191 ) During the fourth quarter of 2014, prices for natural gas and crude oil continued to decline such that we identified a need to evaluate the goodwill associated with the Polar and Divide and Bison Midstream systems, as discussed below. In connection with this evaluation, we also evaluated the intangible assets and property, plant and equipment associated with the Polar and Divide and Bison Midstream systems for impairment and concluded that no impairment was necessary. We recognized amortization expense in costs and expenses as follows: Year ended December 31, 2014 2013 2012 (In thousands) Amortization expense – contract intangibles $ 32,554 $ 28,654 $ 12,642 Amortization expense – rights-of-way 4,979 4,607 1,610 The estimated aggregate annual amortization of intangible assets and noncurrent liability expected to be recognized as of December 31, 2014 for each of the five succeeding fiscal years follows. Assets Liability (In thousands) 2015 $ 42,254 $ 698 2016 42,219 924 2017 41,069 1,047 2018 40,673 1,123 2019 40,619 957 Goodwill. Recorded goodwill is related to the original acquisitions of the Grand River Gathering, 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 Polar Midstream. Our procedures indicated that the remaining goodwill balance at Meadowlark Midstream was entirely attributable to Polar Midstream. Because Epping was an organic growth project, it has no goodwill. A rollforward of goodwill by reportable segment and in total follows. Piceance Basin Williston Basin – Gas Williston Basin – Liquids Marcellus Shale Total (In thousands) Goodwill, December 31, 2012 $ 45,478 $ — $ — $ — $ 45,478 Goodwill recognized in connection with the Bison Drop Down — 54,199 — — 54,199 Goodwill recognized in connection with the Polar and Divide Drop Down — — 203,373 — 203,373 Goodwill preliminarily recognized in connection with the Mountaineer Acquisition — — — 18,089 18,089 Goodwill adjustment recognized in connection with finalizing accounting for the Mountaineer Acquisition and other — — — (1,878 ) (1,878 ) Goodwill, December 31, 2013 45,478 54,199 203,373 16,211 319,261 Goodwill impairment (1) — (54,199 ) — — (54,199 ) Goodwill, December 31, 2014 $ 45,478 $ — $ 203,373 $ 16,211 $ 265,062 __________ (1) Balance represents the cumulative goodwill impairment as of December 31, 2014. Annual Impairment Evaluation. As discussed in Note 2, we evaluate goodwill for impairment annually on September 30. We performed our annual goodwill impairment testing as of September 30, 2014 using a combination of the income and market approaches. The results thereof follow: • We determined that the fair value of the Grand River Gathering reporting unit, as included in the Piceance Basin reportable segment, substantially exceeded its carrying value, including goodwill as of September 30, 2014. • We determined that the fair value of the Mountaineer Midstream reporting unit, as included in the Marcellus Shale reportable segment, substantially exceeded its carrying value, including goodwill as of September 30, 2014. • We determined that the fair value of the Polar Midstream, as included in the Williston Basin – Liquids reportable segment, reporting unit substantially exceeded its carrying value, including goodwill as of September 30, 2014. • We determined that the fair value of the Bison Midstream reporting unit, as included in the Williston Basin – Gas reportable segment, exceeded its carrying value, including goodwill, as of September 30, 2014. However, it did not exceed its carrying value, including goodwill, by a substantial amount. • Because the fair values of these reporting units exceeded their carrying values, including goodwill, there were no associated impairments of goodwill in connection with our 2014 annual goodwill impairment test. Fourth Quarter 2014 Goodwill Impairment. 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 value, including goodwill. 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 Gathering, Mountaineer Midstream, Polar Midstream and Bison Midstream reporting units could have been impaired. Our assessments related to Grand River Gathering 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. 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: • determination of the weighted-average cost of capital; • the selection of guideline public companies; • market multiples; • weighting of the income and market approaches; • growth rates; • commodity prices; and • the expected levels of throughput volume gathered. Changes in the above and other assumptions could materially affect the estimated amount of fair value for any of our reporting units. The results of our step one goodwill impairment testing indicated that the fair value of the Polar Midstream reporting unit substantially 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. This result required that we perform 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 contributing asset charge utilized in our contract intangibles, expected levels of throughput volume and associated capital expenditures and commodity prices. Our preliminary estimates of the fair values of the identified assets and liabilities calculated in the step two testing of the Bison Midstream reporting unit indicated that all of the associated goodwill had been impaired. As such, we recorded an estimated goodwill impairment of $54.2 million . This amount represents our best estimate of impairment pending the finalization of the fair value calculations, which we expect to finalize in 2015. Our impairment determinations, in the context of (i) our annual impairment evaluation and (ii) our fourth quarter 2014 evaluation, 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, 2014
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. If a customer's actual throughput volumes are less than its MVC for the applicable period, it must make a shortfall payment to us at the end of that contract month, quarter or year, as applicable. 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. To the extent that a customer's actual throughput volumes are above or below its MVC for the applicable period, however, many of our gas gathering agreements contain provisions that can reduce or delay the cash flows that we expect to receive from our MVCs. 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 a customer's monthly or annual 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 months or years (as applicable). • To the extent that a customer's throughput volumes exceed its MVC in the applicable 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 – Gas Barnett Shale Piceance Basin Total current (In thousands) Current deferred revenue, January 1, 2012 $ — $ — $ — $ — Additions — 865 — 865 Current deferred revenue, December 31, 2012 — 865 — 865 Additions — 1,555 — 1,555 Less: revenue recognized due to expiration — 865 — 865 Current deferred revenue, December 31, 2013 — 1,555 — 1,555 Additions — 2,610 — 2,610 Less: revenue recognized due to expiration — 1,555 — 1,555 Less: revenue recognized due to usage — 233 — 233 Current deferred revenue, December 31, 2014 $ — $ 2,377 $ — $ 2,377 A rollforward of noncurrent deferred revenue follows. Williston Basin – Gas Barnett Shale Piceance Basin Total noncurrent (In thousands) Noncurrent deferred revenue, January 1, 2012 $ — $ — $ 1,770 $ 1,770 Additions — — 9,129 9,129 Noncurrent deferred revenue, December 31, 2012 — — 10,899 10,899 Additions(1) 6,389 — 12,395 18,784 Noncurrent deferred revenue, December 31, 2013 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 __________ (1) Noncurrent includes amounts recognized in connection with the Bison Drop Down. As of December 31, 2014 , accounts receivable included $13.1 million of shortfall billings related to MVC arrangements that can be utilized to offset gathering fees in subsequent periods. Noncurrent deferred revenue at December 31, 2014 represents amounts that provide certain customers the ability to offset their gathering fees over a period up to seven years to the extent that the customer's throughput volumes exceeds its MVC.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT Long-term debt consisted of the following: December 31, 2014 2013 (In thousands) Variable rate senior secured revolving credit facility (2.67% at December 31, 2014 and 2.42% at December 31, 2013) due November 2018 $ 208,000 $ 286,000 5.50% Senior unsecured notes due August 2022 300,000 — 7.50% Senior unsecured notes due July 2021 300,000 300,000 Total long-term debt $ 808,000 $ 586,000 The aggregate amount of our debt maturities during each of the years after December 31, 2014 are as follows: Long-term debt (In thousands) 2015 $ — 2016 — 2017 — 2018 208,000 2019 — Thereafter 600,000 Total long-term debt $ 808,000 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, 2014 , the applicable margin under LIBOR borrowings was 2.50% , the interest rate was 2.67% and the unused portion of the revolving credit facility totaled $492.0 million (subject to a commitment fee of 0.500% ). 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. As of December 31, 2014 , we were in compliance with the covenants in the revolving credit facility. There were no defaults or events of default during the year ended December 31, 2014 . Senior Notes. On July 15, 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, 2014 , we were in compliance with the covenants for the 5.5% senior notes. There were no defaults or events of default for the 5.5% senior notes during the period from issuance through December 31, 2014 . 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, 2014 , we were in compliance with the covenants for the 7.5% senior notes. There were no defaults or events of default during the year ended December 31, 2014 .

PARTNERS' CAPITAL AND MEMBERHIP

PARTNERS' CAPITAL AND MEMBERHIP INTERESTS	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
PARTNERS' CAPITAL AND MEMBERHIP INTERESTS	PARTNERS' CAPITAL AND MEMBERSHIP INTERESTS Partners' Capital SMLP was formed in May 2012. Prior to the closing of its IPO on October 3, 2012, SMLP had no outstanding common or subordinated units or operations. 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, 2012 — — — — Units issued to the public in connection with the IPO 14,380,000 — — 14,380,000 Units issued to Summit Investments in connection with the IPO 10,029,850 24,409,850 996,320 35,436,020 Units issued under SMLP LTIP 2,577 — — 2,577 Units, December 31, 2012 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) 1,553,849 — 31,711 1,585,560 Units issued to a subsidiary of Summit Investments in connection with the Mountaineer Acquisition (1) 3,107,698 — 63,422 3,171,120 Units issued under SMLP LTIP 5,892 — — 5,892 Units, December 31, 2013 29,079,866 24,409,850 1,091,453 54,581,169 Units issued in connection with the March Equity 2014 Offering (1) 5,300,000 — 108,337 5,408,337 Units issued under SMLP LTIP (1)(2) 46,647 — 861 47,508 Units, December 31, 2014 34,426,513 24,409,850 1,200,651 60,037,014 __________ (1) Including issuance to general partner in connection with contributions made to maintain 2% general partner interest. (2) Units issued under SMLP LTIP in 2014 is net of 14,300 units withheld to meet minimum statutory tax withholding requirements. 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"). Concurrent therewith, our general partner made a capital contribution to us to maintain its 2% general partner interest. We used the proceeds from this offering and the general partner capital contribution to fund a portion of the purchase of Polar and Divide. See Notes 1, 10 and 15 for information on units issued (i) in connection with our IPO, (ii) under the SMLP LTIP plan, and (iii) to fund acquisitions. Red Rock Drop Down. On March 18, 2014, SMLP acquired 100% of the membership interests in Red Rock Gathering from a subsidiary of Summit Investments. In exchange for its $241.8 million net investment in Red Rock Gathering, SMLP paid total cash consideration of $307.9 million , including working capital adjustments. 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 (in thousands). Summit Investments' net investment in Red Rock Gathering $ 241,817 Total cash consideration paid to a subsidiary of Summit Investments 307,941 Excess of purchase price over acquired carrying value of Red Rock Gathering $ (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 allocation $ (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 details of total cash and unit consideration as well as 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 248,914 Summit Investments' contribution of net assets in excess of consideration $ 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 allocation $ 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. 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. Subordinated units will not accrue arrearages for unpaid quarterly distributions or quarterly distributions less than the MQD. If we do not pay the MQD on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the MQD to holders of our common units, we will use this excess available cash to pay any distribution arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. When the subordination period ends, all subordinated units will convert into common units on a one -for-one basis, and thereafter no common units will be entitled to arrearages. The subordination period will end 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. 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. 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. General Partner Interest and Incentive Distribution Rights. 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. Our general partner also currently holds incentive distribution rights 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 incentive distribution rights 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% Details of cash distributions declared to date follow. Attributable to the quarter ended Payment date Per-unit distribution Cash paid to common unitholders Cash paid to subordinated unitholders Cash paid to general partner Cash paid for IDRs Total distribution (In thousands, except per-unit amounts) December 31, 2012 February 14, 2013 $ 0.4100 $ 10,009 $ 10,008 $ 408 $ — $ 20,425 March 31, 2013 May 15, 2013 0.4200 10,253 10,252 418 — 20,923 June 30, 2013 August 14, 2013 0.4350 12,647 10,618 475 — 23,740 September 30, 2013 November 14, 2013 0.4600 13,377 11,229 502 — 25,108 December 31, 2013 February 14, 2014 0.4800 13,958 11,717 528 163 26,366 March 31, 2014 May 15, 2014 0.5000 17,211 12,205 607 360 30,383 June 30, 2014 August 14, 2014 0.5200 17,900 12,693 639 721 31,953 September 30, 2014 November 14, 2014 0.5400 18,589 13,181 670 1,082 33,522 On January 22, 2015, the board of directors of our general partner declared a distribution of $0.56 per unit for the quarterly period ended December 31, 2014. The distribution was paid on February 13, 2015 to unitholders of record at the close of business on February 6, 2015. SMLP allocated its distribution in accordance with the third target distribution level for distributions attributable to the quarter ended December 31, 2014. Membership Interests 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, 2014 and December 31, 2013, net income was attributed to Summit Investments for (i) Polar and Divide for the years ended December 31, 2014 and 2013 (ii) Red Rock Gathering for the period from January 1, 2014 to March 18, 2014, for the year ended December 31, 2013 and for the period from October 23, 2012 to December 31, 2012 and (iii) Bison Midstream for the period from February 16, 2013 to June 4, 2013. Although included in partners' capital, net income attributable to Summit Investments has been excluded from the calculation of EPU for the years ended December 31, 2014 and 2013 and for the period from October 1, 2012 to December 31, 2012. Predecessor Membership Interests. Holders of membership interests in Summit Investments participate in distributions and exercise the other rights or privileges available to each entity under Summit Investments' Fourth Amended and Restated Limited Liability Operating Agreement (the "Summit LLC Agreement"). In accordance with the Summit LLC Agreement, capital accounts are maintained for Summit Investments’ members. The capital account provisions of the Summit LLC Agreement incorporate principles established for U.S. federal income tax purposes and as such are not comparable to the equity accounts reflected under GAAP in our consolidated financial statements. The Summit LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that its membership interest holders will receive. Capital contributions required under the Summit LLC Agreement are in proportion to the members' respective percentage ownership interests. The Summit LLC Agreement also contains provisions for the allocation of net earnings and losses to members. For purposes of maintaining partner capital accounts, the Summit LLC Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests.

EARNINGS PER UNIT

EARNINGS PER UNIT	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
EARNINGS PER UNIT	EARNINGS PER UNIT The following table presents details on EPU. Year ended December 31, 2014 2013 2012 (1) (In thousands, except per-unit amounts) Net (loss) income $ (14,734 ) $ 52,837 $ 42,997 Less: net income attributable to the pre-IPO period — — 24,112 Less: net income attributable to Summit Investments 9,258 9,253 1,271 Net (loss) income attributable to SMLP (23,992 ) 43,584 17,614 Less: net (loss) income attributable to general partner, including IDRs 3,125 1,035 352 Net (loss) income attributable to limited partners $ (27,117 ) $ 42,549 $ 17,262 Numerator for basic and diluted EPU: Allocation of net (loss) income among limited partner interests: Net (loss) income attributable to common units $ (16,324 ) $ 23,227 $ 8,632 Net (loss) income attributable to subordinated units (10,793 ) 19,322 8,630 Net (loss) income attributable to limited partners $ (27,117 ) $ 42,549 $ 17,262 Denominator for basic and diluted EPU: Weighted-average common units outstanding – basic 33,311 26,951 24,412 Effect of nonvested phantom units — 150 132 Weighted-average common units outstanding – diluted 33,311 27,101 24,544 Weighted-average subordinated units outstanding – basic and diluted 24,410 24,410 24,410 (Loss) earnings per limited partner unit: Common unit – basic $ (0.49 ) $ 0.86 $ 0.35 Common unit – diluted $ (0.49 ) $ 0.86 $ 0.35 Subordinated unit – basic and diluted $ (0.44 ) $ 0.79 $ 0.35 __________ (1) Calculated for the period from October 1, 2012 to December 31, 2012 Our general partner was not entitled to receive incentive distributions for periods prior to the fourth quarter of 2013 based on the amount of the distributions declared per common and subordinated unit. During the year ended December 31, 2014, we excluded 231,875 units from the calculation of diluted loss per common unit because their impact was anti-dilutive. There were no units excluded from the calculation of diluted earnings per common unit as we did not have any anti-dilutive units for the year ended December 31, 2013 or for the period from October 1, 2012 to December 31, 2012.

UNIT-BASED COMPENSATION

UNIT-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2014
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, 2014 , approximately 4.6 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, 2012 — $ — Phantom units granted 125,000 20.00 Restricted units granted 6,558 20.23 Nonvested phantom and restricted units, December 31, 2012 131,558 20.00 Phantom units granted 155,330 26.33 Restricted units granted 835 27.50 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 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 vest 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 and 2012 maintained the vesting provisions of the share-based compensation awards they replaced, each of which had an original vesting period of four years. See "—DFW Net Profits Interests" below for additional information. As of December 31, 2014 , the unrecognized unit-based compensation related to the SMLP LTIP was $4.1 million . Incremental unit-based compensation will be recorded over the remaining vesting period of approximately 2.25 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 was as follows: Year ended December 31, 2014 2013 2012 (In thousands) SMLP LTIP unit-based compensation $ 4,696 $ 2,999 $ 269 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. 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. The DFW Net Profits Interests participated in distributions upon time vesting and the achievement of certain distribution targets and were accounted for as compensatory awards. Each grant vested ratably over four years and provided for accelerated vesting in certain limited circumstances. We determined the fair value of the DFW Net Profits Interests with assistance from a third-party valuation expert. 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. A significant input of the option pricing method was the enterprise value of DFW Midstream. We estimated the enterprise value utilizing a combination of the income and market approaches. Additional significant inputs used in the option pricing method included the length of holding period, discount for lack of marketability and volatility. Information regarding the vested and nonvested DFW Net Profits Interests were as follows: Year ended December 31, 2013 2012 Percentage Interest Weighted-average grant date fair value (per 1.0% of DFW Net Profits Interest) Percentage Interest Weighted-average grant date fair value (per 1.0% of DFW Net Profits Interest) (Dollars in thousands) Nonvested, beginning of period 0.038 % $ 1,650 1.750 % $ 306 Repurchased 0.038 % $ 1,650 0.000 % $ — Vested 0.000 % $ — 1.644 % $ 256 Forfeited 0.000 % $ — 0.069 % $ 765 Nonvested, end of period 0.000 % $ — 0.038 % $ 1,650 Vested, end of period 0.000 % $ — 4.294 % $ 257 We recognized noncash compensation expense related to the DFW Net Profits Interests within general and administrative expense of $17 thousand for the year ended December 31, 2013 and $0.7 million for the year ended December 31, 2012. 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 participate in distributions upon time vesting and the achievement of certain distribution targets. The SMP Net Profits Interests are accounted for as compensatory awards. Additional SMP Net Profits Interests were granted through January 2012. All grants vest ratably over five years and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control. As of December 31, 2012, 6.355% of SMP Net Profits Interests had been granted to certain members of management, and no SMP Net Profits Interests had been forfeited. The SMP Net Profits Interests were retained by the Predecessor and as such are not reflected in SMLP's financial statements subsequent to the IPO, except as noted below. We determined the fair value of the SMP Net Profits Interests as of the respective grant dates with assistance from a third-party valuation expert. We 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. A significant input of the option pricing method is the enterprise value of Summit Investments. We estimated enterprise value utilizing a combination of the income and market approaches. The income approach utilized the discounted cash flow method, whereby we applied a discount rate to estimated future cash flows of Summit Investments. Under the market approach, we applied trading multiples of the securities of publicly-traded peer companies to Summit Investments' estimated future cash flows. Additional significant inputs used in the option pricing method included length of holding period, discount for lack of marketability and volatility. The length of holding period was primarily determined based upon our Sponsors' expectations as of the grant date. We estimated the discount for lack of marketability and volatility with assistance from a third-party valuation firm. We estimated the discount for lack of marketability using a protective put methodology. The protective put methodology consisted of estimating the cost to insure an investment in the SMP Net Profits Interests over the length of the holding period. We estimated the expected volatility of the SMP Net Profits Interests based on the historical and implied volatilities of the securities of publicly-traded peer companies. We estimated historical volatility based on daily stock price returns over a look-back period commensurate with the length of the holding period for each grant of SMP Net Profits Interests. We estimated implied volatility based on the average implied volatility of the publicly-traded peer companies using data from Standard & Poor's Capital IQ proprietary research tool. We based the expected volatility conclusions on consideration of both the historical and implied volatilities of the publicly-traded peer companies as of the various grant dates. The inputs used in the option pricing method for the SMP Net Profits Interests granted during the year ended December 31, 2012 were as follows: January 2012 grant Length of holding period restriction (In years) 2.93 Discount for lack of marketability 24.0 % Volatility 37.0 % Information regarding the amount and grant-date fair value of the vested and nonvested SMP Net Profits Interests for the period in which they were reflected in our financial results follows. Year ended December 31, 2012 Percentage Interest Weighted-average grant date fair value (per 1.0% of SMP Net Profits Interest) (Dollars in thousands) Nonvested, beginning of period 3.958 % $ 1,003 Granted 0.500 % $ 1,780 Vested 1.271 % $ 965 Nonvested, end of period (1) 3.187 % $ 1,140 Vested, end of period 3.168 % $ 788 __________ (1) Subsequent to the IPO, the vested and nonvested net profits interests are obligations of the Predecessor and not the Partnership We recognized noncash compensation expense related to the SMP Net Profits Interests in general and administrative expense of $0.3 million for the year ended December 31, 2014, $0.8 million for the year ended December 31, 2013 and $0.9 million for the year ended December 31, 2012. For the year ended December 31, 2014 the expense reflects amounts allocated to Polar and Divide prior to the Polar and Divide Drop Down. For the year ended December 31, 2013, the expense reflects amounts allocated to Polar and Divide and Red Rock Gathering by Summit Investments prior to the Polar and Divide Drop Down and Red Rock Drop Down. For the year ended December 31, 2012, the expense reflects amounts attributable to the Predecessor prior to our IPO.

CONCENTRATIONS OF RISK

CONCENTRATIONS OF RISK	12 Months Ended
	Dec. 31, 2014
Risks and Uncertainties [Abstract]
CONCENTRATIONS OF RISK	CONCENTRATIONS OF 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. Counterparties accounting for more than 10% of total revenues were as follows: Year ended December 31, 2014 2013 2012 Revenue: Counterparty A - Piceance Basin 20 % 21 % 27 % Counterparty B - Barnett Shale * 15 % 19 % Counterparty C - Williston Basin – Gas * * — % Counterparty D - Marcellus Shale * * — % Counterparty E - Piceance Basin * * — % Counterparty F - Barnett Shale * * 14 % __________ * Less than 10% Counterparties accounting for more than 10% of total accounts receivable were as follows: December 31, 2014 2013 Accounts receivable: Counterparty A - Piceance Basin 27 % 36 % Counterparty B - Barnett Shale * 10 % Counterparty C - Williston Basin – Gas 13 % * Counterparty D - Marcellus Shale * * Counterparty E - Piceance Basin * * Counterparty F - Barnett Shale * * __________ * Less than 10%

RELATED-PARTY TRANSACTIONS

RELATED-PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
RELATED-PARTY TRANSACTIONS	RELATED-PARTY TRANSACTIONS Recent 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, 2014 2013 2012 (In thousands) Operation and maintenance expense $ 19,782 $ 14,323 $ 2,913 General and administrative expense 22,370 18,662 3,661 Expenses Incurred by Summit Investments. Prior to the Polar and Divide Drop Down and the Red Rock 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. Electricity Management Services Agreement. We entered into a consulting arrangement with EquiPower Resources Corp. to assist with managing DFW Midstream's electricity price risk. EquiPower Resources Corp. is an affiliate of Energy Capital Partners and is also the employer of a director of our general partner. Amounts paid for such services were as follows: Year ended December 31, 2014 2013 2012 (In thousands) Payments for electricity management consulting services $ 234 $ 199 $ 204 The consulting arrangement terminated on December 31, 2014. Engineering Services Agreement. We entered into an engineering services arrangement with IPS Engineering/EPC. IPS Engineering/EPC is an affiliate of Energy Capital Partners. We paid $0.6 million for such services during the year ended December 31, 2014 and $0.2 million for such services during the year ended December 31, 2013. Promissory Notes Payable to Sponsors . In conjunction with the acquisition of Grand River Gathering in 2011, we executed $200.0 million of promissory notes, on an unsecured basis, with the Sponsors. The notes had an 8% interest rate and were scheduled to mature in October 2013. In May 2012, we borrowed $163.0 million under the revolving credit facility and used a portion of the same borrowings to prepay $160.0 million principal amount of the promissory notes payable to the Sponsors. Then in July 2012, we borrowed an additional $50.0 million under the revolving credit facility, a portion of which was used to pay the remaining $49.2 million principal amount of the promissory notes payable to Sponsors (inclusive of accrued pay-in-kind interest). In accordance with the terms of the underlying note agreement, prior to their repayment in July 2012, we elected to make all interest payments on the note in kind. The amount of interest paid in kind and accrued to the balance of the notes for year ended December 31, 2012, was approximately $6.3 million , of which we capitalized $0.9 million of interest expense related to costs incurred on capital projects under construction. Diligence Expenses. In the past, the Sponsors reimbursed Summit Investments for transactional due diligence expenses related to proposed transactions that were not completed. As of December 31, 2011, we had a receivable from the Sponsors of $1.3 million for similar expenses. During the year ended December 31, 2012, we were reimbursed $0.3 million , while $1.0 million was not paid.

BENEFIT PLAN

BENEFIT PLAN	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Benefit plan	BENEFIT PLAN We have a defined contribution benefit plan for our employees. The expense associated with this plan was approximately $0.9 million in 2014, $0.6 million in 2013, and $0.2 million in 2012.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2014
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, 2014 2013 2012 Rent expense $ 1,786 $ 1,495 $ 732 Future minimum lease payments for the Partnership's operating leases are immaterial. 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 its financial position or results of operations.

ACQUISITIONS

ACQUISITIONS	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Acquisitions	ACQUISITIONS Polar and Divide. On May 18, 2015, SMLP acquired the Polar and Divide system 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. 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, the Partnership acquired Red Rock Gathering from a subsidiary of Summit Investments, subject to customary working capital adjustments. 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. Summit Investments acquired the natural gas gathering pipeline, dehydration, compression and processing assets in the Piceance Basin in western Colorado and eastern Utah that comprise the Red Rock Gathering system from a subsidiary of Energy Transfer Partners, L.P. in September 2012 for $206.7 million . Summit Investments' acquisition of the Red Rock Gathering system closed on October 23, 2012. Summit Investments accounted for its acquisition of Red Rock Gathering under the acquisition method of accounting. Red Rock Gathering's identifiable tangible and intangible assets acquired and liabilities assumed were recognized at their fair values as of October 23, 2012. The intangible assets that were acquired comprised right-of-way easements with a life of 20 years upon acquisition. Their fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete the Red Rock Gathering system. The final fair values of the assets acquired and liabilities assumed as of October 23, 2012, were as follows (in thousands): Red Rock Gathering purchase price $ 206,694 Cash $ 1,097 Accounts receivable 8,018 Other assets 317 Property, plant, and equipment 150,401 Rights-of-way 52,197 Other noncurrent assets 164 Total assets acquired 212,194 Trade accounts payable 2,558 Other current liabilities 2,942 Total liabilities assumed $ 5,500 Net identifiable assets acquired $ 206,694 During the fourth quarter of 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 acquisition of Mountaineer Midstream from MarkWest for $210.0 million on June 21, 2013. 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 MarkWest 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 Grand River Gathering. During the fourth quarter of 2014, we identified and wrote off certain balances previously recognized in connection with the Predecessor's purchase accounting for Grand River Gathering. This write off was recognized as a $1.2 million increase to other income. 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, Epping, 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, 2014 2013 2012 (In thousands) SMLP revenues $ 319,373 $ 225,192 $ 165,499 Polar and Divide revenues 22,449 3,893 Red Rock Gathering revenues 11,313 50,114 8,924 Bison Gas Gathering system revenues (1) 17,614 Combined revenues $ 353,135 $ 296,813 $ 174,423 SMLP net (loss) income $ (23,992 ) $ 43,584 $ 41,726 Polar and Divide net income (loss) 6,430 (467 ) Red Rock Gathering net income 2,828 9,668 1,271 Bison Gas Gathering system net income (1) 52 Combined net (loss) income $ (14,734 ) $ 52,837 $ 42,997 __________ (1) Results are fully reflected in SMLP's results of operations for the year ended December 31, 2014. Unaudited Pro Forma Financial Information. The following unaudited pro forma financial information assumes that: • Any pro forma adjustments for the acquisition of Polar and Divide are not material because (i) the system, which is still under development, was not operational until May 2013 and (ii) all financial results have been reflected. • The acquisition of Red Rock Gathering occurred on January 1, 2011. The pro forma results reflect actual Red Rock Gathering revenues and net income earned and recognized in 2014 and 2013, and by annualizing the actual operating results for Red Rock Gathering that were recorded in 2012 for the year ended December 31, 2012. • The acquisition of the Bison Gas Gathering system occurred on January 1, 2012. The pro forma results for Bison Midstream were derived from revenues and net income in 2013 and 2012. • The acquisition of Mountaineer Midstream occurred on January 1, 2012. The pro forma results for Mountaineer Midstream were derived from revenues and net income in 2013. Mountaineer Midstream was not operational until November 2012. • The acquisition of the Lonestar assets is immaterial for pro forma purposes and as such has not been reflected below. • Pro forma net income for the year ended December 31, 2014 has been adjusted to remove the impact of $0.7 million of nonrecurring transaction costs associated with the acquisition of Red Rock Gathering. • 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 net income for the year ended December 31, 2012 has been adjusted to remove the impact of $1.6 million of nonrecurring transaction costs associated with the acquisition of Red Rock Gathering. • Pro forma adjustments in 2014, 2013 and 2012 also reflect the impact of a 5,300,000 common unit issuance, the general partner capital contribution to maintain its 2% general partner interest and $100.0 million of incremental borrowings on our revolving credit facility to fund the acquisition of Red Rock Gathering. • Pro forma adjustments in 2014, 2013 and 2012 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 and 2012 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. Year ended December 31, 2014 2013 2012 (In thousands, except for per-unit amounts) Total Polar and Divide revenues included in consolidated revenues $ 22,449 $ 3,893 Total Red Rock Gathering revenues included in consolidated revenues 73,266 50,114 $ 8,924 Total Bison Midstream and Mountaineer Midstream revenues included in consolidated revenues 60,323 Total Polar and Divide net income (loss) included in consolidated net income $ 6,430 $ (467 ) Total Red Rock Gathering net income included in consolidated net income 27,447 9,668 $ 1,271 Total Bison Midstream and Mountaineer Midstream net loss included in consolidated net income (457 ) Pro forma total revenues $ 353,135 $ 308,964 $ 256,637 Pro forma net (loss) income (14,508 ) 46,904 38,639 Pro forma common EPU - basic and diluted $ (0.30 ) $ 0.78 $ 0.28 Pro forma subordinated EPU - basic and diluted (0.30 ) 0.78 0.28 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 Polar and Divide, Bison Midstream and Mountaineer Midstream had occurred on January 1, 2012 or if the acquisition of Red Rock Gathering had occurred on January 1, 2011, 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, 2014
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, 2014 , follows. 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) $ 102,986 $ 84,784 $ 85,984 $ 79,381 Net (loss) income attributable to partners (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. (2) In the quarter ended December 31, 2014, includes $54.2 million of goodwill impairment and $5.5 million of long-lived asset impairment. Quarter ended December 31, 2013 Quarter ended September 30, 2013 Quarter ended June 30, 2013 Quarter ended March 31, 2013 (In thousands, except per-unit amounts) Total revenues (1) $ 85,599 $ 77,353 $ 71,847 $ 62,014 Net income attributable to partners $ 16,345 $ 6,691 $ 8,068 $ 12,480 Less: net income attributable to general partner, including IDRs 490 134 161 250 Net income attributable to limited partners $ 15,855 $ 6,557 $ 7,907 $ 12,230 Earnings per limited partner unit: Common unit – basic $ 0.30 $ 0.12 $ 0.16 $ 0.25 Common unit – diluted $ 0.29 $ 0.12 $ 0.16 $ 0.25 Subordinated unit – basic and diluted $ 0.30 $ 0.12 $ 0.16 $ 0.25 __________ (1) Retrospectively adjusted for the impact of the Polar and Divide Drop Down, the Red Rock Drop Down and the Bison Drop Down. The amounts for total revenues as originally filed on the respective 2014 quarterly reports on Form 10-Q have been retrospectively adjusted for the impact of the Polar and Divide Drop Down. There was no impact on net income attributable to partners or EPU. A reconciliation of total revenues follows. Quarter ended December 31, 2014 Quarter ended September 30, 2014 Quarter ended June 30, 2014 Quarter ended March 31, 2014 (In thousands) Total revenues as originally reported $ 94,658 $ 79,030 $ 80,796 $ 76,202 Total revenue impact of Polar and Divide Drop Down 8,328 5,754 5,188 3,179 Total revenues $ 102,986 $ 84,784 $ 85,984 $ 79,381 The amounts for total revenues as originally filed on the respective 2013 quarterly reports on Form 10-Q have been retrospectively adjusted for the impact of the Polar and Divide Drop Down, the Red Rock Drop Down and Bison Drop Down. There was no impact on net income attributable to partners or EPU. A reconciliation of total revenues follows. Quarter ended December 31, 2013 Quarter ended September 30, 2013 Quarter ended June 30, 2013 Quarter ended March 31, 2013 (In thousands) Total revenues as originally reported $ 69,299 $ 63,096 $ 59,285 $ 43,595 Total revenue impact of Polar and Divide Drop Down 2,143 1,334 386 30 Total revenue impact of Red Rock Drop Down 14,157 12,923 12,176 10,858 Total revenue impact of Bison Drop Down — — — 7,531 Total revenues $ 85,599 $ 77,353 $ 71,847 $ 62,014

SUMMARY OF SIGNIFICANT ACCOUN23

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2014
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.
Segment Reporting	We conduct our operations in the midstream sector through five reportable segments: • the Marcellus Shale, which is served by Mountaineer Midstream; • the Williston Basin – Gas, which is served by Bison Midstream; • the Williston Basin – Liquids, which is served by 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.
Principles of Consolidation	For the purposes of the consolidated financial statements, SMLP's results of operations reflect the Partnership's operations subsequent to the IPO and the results of the Predecessor for the period prior to the IPO. The consolidated financial statements also reflect the results of operations of: (i) Red Rock Gathering since October 23, 2012, (ii) Polar Midstream since February 16, 2013, (iii) Bison Midstream since February 16, 2013 and (iv) Mountaineer Midstream since June 22, 2013. SMLP recognized its acquisitions of Red Rock Gathering, Polar Midstream and Bison Midstream at Summit Investments' historical cost because the acquisitions were executed by entities under common control. The excess of Summit Investments' net investment in Polar Midstream and Bison Midstream over the purchase price paid by SMLP was recognized as an addition to partners' capital. The excess of the purchase price paid by SMLP over Summit Investments' net investment in Red Rock Gathering was recognized as a reduction to partners' capital. Due to the common control aspect, the Red Rock Drop Down, the Polar and Divide Drop Down and the Bison Drop Down were accounted for by the Partnership on an “as-if pooled” basis for the periods during which common control existed. The consolidated financial statements include the assets, liabilities, and results of operations of SMLP or the Predecessor and their respective wholly owned subsidiaries. All intercompany transactions among the consolidated entities have been eliminated in consolidation. The financial position, results of operations and cash flows of Polar Midstream included herein have been derived from the accounting records of Meadowlark Midstream on a carve-out basis. The majority of the assets and liabilities allocated to Polar Midstream have been specifically identified based on Meadowlark Midstream’s existing divisional organization. Goodwill was allocated to Polar Midstream based on initial purchase accounting estimates. Revenues and depreciation and amortization have been specifically identified based on Polar Midstream's relationship to Meadowlark Midstream’s existing divisional structure. Operation and maintenance and general and administrative expenses have been allocated to Polar Midstream based on volume throughput. These allocations and estimates were based on methodologies that management believes are reasonable. The results reflected herein, however, may not reflect what Polar Midstream’s financial position, results of operations or cash flows would have been if Polar Midstream been a stand-alone company. Reclassifications. Certain reclassifications have been made to prior-year amounts to conform to current-year presentation. We evaluated our classification of revenues and concluded that creating an “other revenues” category would provide reporting that was more reflective of our results of operations and how we manage our business. As such, certain revenue transactions that represented the “and other” portions of (i) gathering services and (ii) natural gas, NGLs and condensate sales have been reclassified to other revenues. Other revenues also includes the amortization expense associated with our favorable and unfavorable gas gathering contracts. The amounts reclassified to other revenues for each period presented can be determined based on the total of the other revenues line item and the amount of amortization of favorable and unfavorable gas gathering contracts disclosed in Note 5. We also evaluated our historical classification of electricity expense for Bison Midstream. In connection with the reclassification of certain revenues noted above and to be consistent with the classification of pass-through electricity expense for our other operating segments, we reclassified pass-through electricity expenses for Bison Midstream ( $5.2 million and $3.1 million for the years ended December 31, 2014 and 2013, respectively) from costs of natural gas and NGLs to operation and maintenance. These reclassifications had no impact on total revenues, total costs and expenses, net income, total partners' capital or segment adjusted EBITDA.
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. To the extent we doubt the collectability of our accounts receivable, we recognize an allowance for doubtful accounts. We did not experience any non-payments during the three-year period ended December 31, 2014.
Prepaid Expenses	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. Prior to the Polar and Divide Drop Down and the Red Rock Drop Down, a subsidiary of Summit Investments incurred interest expense related to certain Polar and Divide and Red Rock Gathering capital projects. The associated interest expense was allocated to Polar and Divide and Red Rock Gathering as a noncash equity contribution and capitalized into the basis of the asset. We base an asset’s carrying value on estimates, assumptions and judgments for useful life and salvage value. 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. 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. As of December 31, 2014 and 2013, we evaluated whether any future asset retirement obligations existed. For identified asset retirement obligations, we then evaluated whether the expected retirement date and the related costs of retirement could be estimated. In performing this evaluation, we concluded that our gathering and processing assets have an indeterminate life because they are owned and will operate for an indeterminate future 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, 2014 or 2013.
Intangible Assets and Noncurrent Liabilities	Intangible Assets and Noncurrent Liability. Upon the acquisition of DFW Midstream, certain of our 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 contracts that were above market at acquisition as favorable gas gathering contracts. We have recognized the contract that was deemed to be below market as a noncurrent liability. We amortize these intangibles on a units-of-production basis over the estimated useful life of the contract. We define useful life as the period over which the contract is expected to contribute directly or indirectly to our future cash flows. The related contracts have original terms ranging from 10 years to 20 years. We recognize the amortization expense associated with these intangible assets and liability in other revenues. For our other gas gathering contracts, we amortize contract intangible assets over the period of economic benefit based upon the 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 intangible assets in depreciation and amortization expense. We have right-of-way intangible assets 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. The estimated useful life of our gathering systems is 30 years. We recognize the amortization expense associated with these intangible assets in depreciation and amortization 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 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 an income approach in which we discount the asset’s expected future cash flows to reflect the risk associated with achieving the underlying cash flows.
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. 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. 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.
Deferred loan costs	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.
Derivatives	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 our electric-drive compression assets on the DFW Midstream system. 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 our 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). 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, 2014 December 31, 2013 Carrying value Estimated fair value (Level 2) Carrying value Estimated fair value (Level 2) (In thousands) Revolving credit facility $ 208,000 $ 208,000 $ 286,000 $ 286,000 5.5% Senior notes 300,000 281,750 — — 7.5% Senior notes 300,000 306,750 300,000 314,625 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, 2014 and December 31, 2013. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the senior notes. Nonfinancial assets and liabilities initially measured at fair value include those acquired and assumed in connection with third-party business combinations.
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 producer customers. We also generate revenue from our marketing of natural gas and NGLs. We realize revenues by receiving fees from our producer customers or by selling the residue natural gas and NGLs. 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 and keep-whole arrangements. These revenues are recognized in natural gas, NGLs and condensate sales with corresponding expense recognition 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 Gathering. 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 natural gas 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: natural gas gathering, treating, and/or processing. Fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase natural gas at the wellhead, or other receipt points, at a settled price at the delivery point less a specified amount, generally the same as the fees we would otherwise charge for gathering of natural gas from the wellhead location to the delivery point. The margins earned are directly related to the volume of natural gas that flows through the system. • 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. • Keep-Whole. Under keep-whole arrangements, after processing we keep 100% of the NGLs produced, and the processed natural gas, or value of the natural gas, is returned to the producer. Since some of the natural gas is used and removed during processing, we compensate the producer for the amount of natural gas used and removed in processing by supplying additional natural gas or by paying an agreed-upon value for the natural gas utilized. These arrangements have commodity price exposure for us because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs. We provide crude oil and produced water gathering services under fee-based arrangements whereby we receive a fee or fees for gathering crude oil and/or produced water. Certain of our natural gas gathering or processing agreements provide for a monthly, quarterly or annual MVC. Under these MVCs, our customers agree to ship a minimum volume of natural gas 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 contract 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 periods to the extent that such customer's throughput volumes in subsequent periods exceed its MVC for that 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 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 volumes of natural gas, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the applicable natural gas gathering agreement. We classify deferred revenue as a current liability for arrangements where the expiration of a customer's right to utilize shortfall payments is twelve 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. Since we are structured as a partnership, we are generally not subject to federal and state income taxes, except as noted below. As a result, our unitholders or members are individually responsible for paying federal and state income taxes on their share of our taxable income. Net income or loss for financial statement purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and the financial reporting 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.
Earnings per Unit	Earnings Per Unit ("EPU"). We present earnings or loss per limited partner unit only for periods subsequent to the IPO. Prior to the IPO, Summit Investments' members held membership interests and not units. We determine EPU by dividing the net income or loss that is attributed, in accordance with the net income and loss allocation provisions of the partnership agreement, to the 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 payments to the general partner in connection with its 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 during the years ended December 31, 2014 and 2013, and the period from October 1, 2012 to December 31, 2012. Diluted earnings or loss per limited partner unit 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. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted earnings per limited partner unit calculation, the impact is reflected by appl
Comprehensive Income	Comprehensive Income. Comprehensive income is the same as net income or loss for all periods pre
Environmental Matters	Environmental Matters. We are subject to various federal, state and local laws and regulations relating to the protection of the environment. Although we believe that we are in material compliance with applicable environmental regulations, the risk of costs and liabilities are inherent in pipeline ownership and operation. 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. There are no such material liabilities in the accompanying financial statements at December 31, 2014 or 2013, and we are currently unaware of any material contingent liabilities that exist with respect to environmental matters. However, we can provide no assurance that significant costs and liabilities will not be incurred by the Partnership in the future.
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 will materially affect our financial statements, except as noted below.

SUMMARY OF SIGNIFICANT ACCOUN24

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of Estimated Fair Value for Financial instruments	A summary of the estimated fair value of our debt financial instruments follows. December 31, 2014 December 31, 2013 Carrying value Estimated fair value (Level 2) Carrying value Estimated fair value (Level 2) (In thousands) Revolving credit facility $ 208,000 $ 208,000 $ 286,000 $ 286,000 5.5% Senior notes 300,000 281,750 — — 7.5% Senior notes 300,000 306,750 300,000 314,625

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Schedule of assets by reportable segment	The following table presents assets by reportable segment as of December 31. December 31, 2014 2013 (In thousands) Assets: Marcellus Shale $ 243,884 $ 214,379 Williston Basin – Gas 311,041 337,610 Williston Basin – Liquids 398,847 307,404 Barnett Shale 428,935 431,578 Piceance Basin 872,437 876,969 Total reportable segment assets 2,255,144 2,167,940 Corporate 38,577 23,203 Total assets $ 2,293,721 $ 2,191,143
Schedule of segment reporting information	The following table summarizes details by reportable segment for the years ended December 31. Year ended December 31, 2014 2013 2012 (In thousands) Revenues: Marcellus Shale $ 22,694 $ 9,588 Williston Basin – Gas 62,454 50,735 Williston Basin – Liquids 22,449 3,893 Barnett Shale 93,001 105,324 $ 93,453 Piceance Basin 152,537 127,273 81,961 Total reportable segments 353,135 296,813 175,414 Corporate — — (991 ) Total revenues $ 353,135 $ 296,813 $ 174,423 Depreciation and amortization: Marcellus Shale $ 7,648 $ 3,998 Williston Basin – Gas 18,132 16,057 Williston Basin – Liquids 4,359 612 Barnett Shale 15,657 13,929 $ 12,078 Piceance Basin 40,965 35,527 24,310 Total reportable segments 86,761 70,123 36,388 Corporate 588 451 286 Total depreciation and amortization $ 87,349 $ 70,574 $ 36,674 Other income: Marcellus Shale $ — $ — Williston Basin – Gas — — Williston Basin – Liquids — — Barnett Shale — — $ — Piceance Basin 1,185 — — Total reportable segments 1,185 — — Corporate 4 5 9 Total other income $ 1,189 $ 5 $ 9 Capital expenditures: Marcellus Shale $ 33,866 $ 1,822 Williston Basin – Gas 46,927 26,381 Williston Basin – Liquids 92,495 73,602 Barnett Shale 14,567 29,534 $ 39,588 Piceance Basin 32,505 50,709 36,899 Total reportable segments 220,360 182,048 76,487 Corporate 460 930 809 Total capital expenditures $ 220,820 $ 182,978 $ 77,296 The following table presents segment adjusted EBITDA by reportable segment. Year ended December 31, 2014 2013 2012 (In thousands) Reportable segment adjusted EBITDA: Marcellus Shale $ 15,940 $ 6,333 Williston Basin – Gas 20,422 16,865 Williston Basin – Liquids 11,129 485 Barnett Shale 60,528 69,473 $ 63,670 Piceance Basin 107,953 80,941 53,179 Total reportable segment adjusted EBITDA $ 215,972 $ 174,097 $ 116,849
Reconciliation of net income to adjusted EBITDA	The following table presents a reconciliation of income before income taxes to total reportable segment adjusted EBITDA. Year ended December 31, 2014 2013 2012 (In thousands) Reconciliation of Income Before Income Taxes to Segment Adjusted EBITDA: Income before income taxes $ (14,103 ) $ 53,566 $ 43,679 Add: Interest expense and affiliated interest expense 40,159 19,173 12,766 Depreciation and amortization 88,293 71,606 36,866 Allocated corporate expenses 11,065 8,773 10,903 Adjustments related to MVC shortfall payments 26,565 17,025 10,768 Unit-based compensation 5,036 3,846 1,876 Loss on asset sales, net 442 113 — Goodwill impairment 54,199 — — Long-lived asset impairment 5,505 — — Less: Interest income 4 5 9 Impact of purchase price adjustments 1,185 — — Total reportable segment adjusted EBITDA $ 215,972 $ 174,097 $ 116,849

PROPERTY, PLANT, AND EQUIPMEN26

PROPERTY, PLANT, AND EQUIPMENT, NET (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Schedule of property, plant, and equipment, net	Details on property, plant, and equipment, net were as follows: Useful lives (In years) December 31, 2014 2013 (Dollars in thousands) Gathering and processing systems and related equipment 30 $ 1,462,706 $ 1,212,227 Construction in progress n/a 44,447 94,130 Other 4-15 28,871 21,885 Total 1,536,024 1,328,242 Less accumulated depreciation 121,674 71,928 Property, plant, and equipment, net $ 1,414,350 $ 1,256,314
Schedule of depreciation expense related to property, plant and equipment and capitalized interest	Depreciation expense related to property, plant, and equipment and capitalized interest were as follows: Year ended December 31, 2014 2013 2012 (In thousands) Depreciation expense $ 49,816 $ 37,313 $ 22,422 Capitalized interest 3,778 6,255 2,784

IDENTIFIABLE INTANGIBLE ASSET27

IDENTIFIABLE INTANGIBLE ASSETS, NONCURRENT LIABILITY AND GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of identifiable intangible assets and a noncurrent liability, which are subject to amortization	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 amortizable intangible assets $ 574,240 $ (96,506 ) $ 477,734 Unfavorable gas gathering contract 10.0 $ 10,962 $ (5,385 ) $ 5,577 December 31, 2013 Useful lives (In years) Gross carrying amount Accumulated amortization Net (Dollars in thousands) Favorable gas gathering contracts 18.7 $ 24,195 $ (6,315 ) $ 17,880 Contract intangibles 12.5 426,464 (43,158 ) 383,306 Rights-of-way 24.7 112,416 (7,758 ) 104,658 Total amortizable intangible assets $ 563,075 $ (57,231 ) $ 505,844 Unfavorable gas gathering contract 10.0 $ 10,962 $ (4,588 ) $ 6,374
Schedule of recognized amortization expense within the statements of operations	We recognized amortization expense in other revenues as follows: Year ended December 31, 2014 2013 2012 (In thousands) Amortization expense – favorable gas gathering contracts $ (1,741 ) $ (2,078 ) $ (1,715 ) Amortization expense – unfavorable gas gathering contract 797 1,046 1,524 Amortization of favorable and unfavorable contracts $ (944 ) $ (1,032 ) $ (191 ) During the fourth quarter of 2014, prices for natural gas and crude oil continued to decline such that we identified a need to evaluate the goodwill associated with the Polar and Divide and Bison Midstream systems, as discussed below. In connection with this evaluation, we also evaluated the intangible assets and property, plant and equipment associated with the Polar and Divide and Bison Midstream systems for impairment and concluded that no impairment was necessary. We recognized amortization expense in costs and expenses as follows: Year ended December 31, 2014 2013 2012 (In thousands) Amortization expense – contract intangibles $ 32,554 $ 28,654 $ 12,642 Amortization expense – rights-of-way 4,979 4,607 1,610
Schedule of estimated aggregate amortization of intangible assets and the noncurrent liability for each of the five succeeding fiscal years	The estimated aggregate annual amortization of intangible assets and noncurrent liability expected to be recognized as of December 31, 2014 for each of the five succeeding fiscal years follows. Assets Liability (In thousands) 2015 $ 42,254 $ 698 2016 42,219 924 2017 41,069 1,047 2018 40,673 1,123 2019 40,619 957
Schedule of goodwill by segment	A rollforward of goodwill by reportable segment and in total follows. Piceance Basin Williston Basin – Gas Williston Basin – Liquids Marcellus Shale Total (In thousands) Goodwill, December 31, 2012 $ 45,478 $ — $ — $ — $ 45,478 Goodwill recognized in connection with the Bison Drop Down — 54,199 — — 54,199 Goodwill recognized in connection with the Polar and Divide Drop Down — — 203,373 — 203,373 Goodwill preliminarily recognized in connection with the Mountaineer Acquisition — — — 18,089 18,089 Goodwill adjustment recognized in connection with finalizing accounting for the Mountaineer Acquisition and other — — — (1,878 ) (1,878 ) Goodwill, December 31, 2013 45,478 54,199 203,373 16,211 319,261 Goodwill impairment (1) — (54,199 ) — — (54,199 ) Goodwill, December 31, 2014 $ 45,478 $ — $ 203,373 $ 16,211 $ 265,062 __________ (1) Balance represents the cumulative goodwill impairment as of December 31, 2014.

DEFERRED REVENUE (Tables)

DEFERRED REVENUE (Tables)	12 Months Ended
	Dec. 31, 2014
Deferred Revenue Disclosure [Abstract]
Rollforward of deferred revenue	A rollforward of current deferred revenue follows. Williston Basin – Gas Barnett Shale Piceance Basin Total current (In thousands) Current deferred revenue, January 1, 2012 $ — $ — $ — $ — Additions — 865 — 865 Current deferred revenue, December 31, 2012 — 865 — 865 Additions — 1,555 — 1,555 Less: revenue recognized due to expiration — 865 — 865 Current deferred revenue, December 31, 2013 — 1,555 — 1,555 Additions — 2,610 — 2,610 Less: revenue recognized due to expiration — 1,555 — 1,555 Less: revenue recognized due to usage — 233 — 233 Current deferred revenue, December 31, 2014 $ — $ 2,377 $ — $ 2,377 A rollforward of noncurrent deferred revenue follows. Williston Basin – Gas Barnett Shale Piceance Basin Total noncurrent (In thousands) Noncurrent deferred revenue, January 1, 2012 $ — $ — $ 1,770 $ 1,770 Additions — — 9,129 9,129 Noncurrent deferred revenue, December 31, 2012 — — 10,899 10,899 Additions(1) 6,389 — 12,395 18,784 Noncurrent deferred revenue, December 31, 2013 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 __________ (1) Noncurrent includes amounts recognized in connection with the Bison Drop Down.

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Schedule of long-term debt instruments	Long-term debt consisted of the following: December 31, 2014 2013 (In thousands) Variable rate senior secured revolving credit facility (2.67% at December 31, 2014 and 2.42% at December 31, 2013) due November 2018 $ 208,000 $ 286,000 5.50% Senior unsecured notes due August 2022 300,000 — 7.50% Senior unsecured notes due July 2021 300,000 300,000 Total long-term debt $ 808,000 $ 586,000
Schedule of maturities of long-term debt	The aggregate amount of our debt maturities during each of the years after December 31, 2014 are as follows: Long-term debt (In thousands) 2015 $ — 2016 — 2017 — 2018 208,000 2019 — Thereafter 600,000 Total long-term debt $ 808,000

PARTNERS' CAPITAL AND MEMBERH30

PARTNERS' CAPITAL AND MEMBERHIP INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2012 — — — — Units issued to the public in connection with the IPO 14,380,000 — — 14,380,000 Units issued to Summit Investments in connection with the IPO 10,029,850 24,409,850 996,320 35,436,020 Units issued under SMLP LTIP 2,577 — — 2,577 Units, December 31, 2012 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) 1,553,849 — 31,711 1,585,560 Units issued to a subsidiary of Summit Investments in connection with the Mountaineer Acquisition (1) 3,107,698 — 63,422 3,171,120 Units issued under SMLP LTIP 5,892 — — 5,892 Units, December 31, 2013 29,079,866 24,409,850 1,091,453 54,581,169 Units issued in connection with the March Equity 2014 Offering (1) 5,300,000 — 108,337 5,408,337 Units issued under SMLP LTIP (1)(2) 46,647 — 861 47,508 Units, December 31, 2014 34,426,513 24,409,850 1,200,651 60,037,014 __________ (1) Including issuance to general partner in connection with contributions made to maintain 2% general partner interest. (2) Units issued under SMLP LTIP in 2014 is net of 14,300 units withheld to meet minimum statutory tax withholding requirements.
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	Details of cash distributions declared to date follow. Attributable to the quarter ended Payment date Per-unit distribution Cash paid to common unitholders Cash paid to subordinated unitholders Cash paid to general partner Cash paid for IDRs Total distribution (In thousands, except per-unit amounts) December 31, 2012 February 14, 2013 $ 0.4100 $ 10,009 $ 10,008 $ 408 $ — $ 20,425 March 31, 2013 May 15, 2013 0.4200 10,253 10,252 418 — 20,923 June 30, 2013 August 14, 2013 0.4350 12,647 10,618 475 — 23,740 September 30, 2013 November 14, 2013 0.4600 13,377 11,229 502 — 25,108 December 31, 2013 February 14, 2014 0.4800 13,958 11,717 528 163 26,366 March 31, 2014 May 15, 2014 0.5000 17,211 12,205 607 360 30,383 June 30, 2014 August 14, 2014 0.5200 17,900 12,693 639 721 31,953 September 30, 2014 November 14, 2014 0.5400 18,589 13,181 670 1,082 33,522
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 (in thousands). Summit Investments' net investment in Red Rock Gathering $ 241,817 Total cash consideration paid to a subsidiary of Summit Investments 307,941 Excess of purchase price over acquired carrying value of Red Rock Gathering $ (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 allocation $ (66,124 )
Mountaineer Midstream
Limited Partners' Capital Account [Line Items]
Allocation and valuation of units issued to fund acquisition	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, 2014
Earnings Per Share [Abstract]
Schedule of earnings per Unit	The following table presents details on EPU. Year ended December 31, 2014 2013 2012 (1) (In thousands, except per-unit amounts) Net (loss) income $ (14,734 ) $ 52,837 $ 42,997 Less: net income attributable to the pre-IPO period — — 24,112 Less: net income attributable to Summit Investments 9,258 9,253 1,271 Net (loss) income attributable to SMLP (23,992 ) 43,584 17,614 Less: net (loss) income attributable to general partner, including IDRs 3,125 1,035 352 Net (loss) income attributable to limited partners $ (27,117 ) $ 42,549 $ 17,262 Numerator for basic and diluted EPU: Allocation of net (loss) income among limited partner interests: Net (loss) income attributable to common units $ (16,324 ) $ 23,227 $ 8,632 Net (loss) income attributable to subordinated units (10,793 ) 19,322 8,630 Net (loss) income attributable to limited partners $ (27,117 ) $ 42,549 $ 17,262 Denominator for basic and diluted EPU: Weighted-average common units outstanding – basic 33,311 26,951 24,412 Effect of nonvested phantom units — 150 132 Weighted-average common units outstanding – diluted 33,311 27,101 24,544 Weighted-average subordinated units outstanding – basic and diluted 24,410 24,410 24,410 (Loss) earnings per limited partner unit: Common unit – basic $ (0.49 ) $ 0.86 $ 0.35 Common unit – diluted $ (0.49 ) $ 0.86 $ 0.35 Subordinated unit – basic and diluted $ (0.44 ) $ 0.79 $ 0.35 __________ (1) Calculated for the period from October 1, 2012 to December 31, 2012

UNIT-BASED COMPENSATION (Tables

UNIT-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2012 — $ — Phantom units granted 125,000 20.00 Restricted units granted 6,558 20.23 Nonvested phantom and restricted units, December 31, 2012 131,558 20.00 Phantom units granted 155,330 26.33 Restricted units granted 835 27.50 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
DFW Net Profit Interests
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of activity	Information regarding the vested and nonvested DFW Net Profits Interests were as follows: Year ended December 31, 2013 2012 Percentage Interest Weighted-average grant date fair value (per 1.0% of DFW Net Profits Interest) Percentage Interest Weighted-average grant date fair value (per 1.0% of DFW Net Profits Interest) (Dollars in thousands) Nonvested, beginning of period 0.038 % $ 1,650 1.750 % $ 306 Repurchased 0.038 % $ 1,650 0.000 % $ — Vested 0.000 % $ — 1.644 % $ 256 Forfeited 0.000 % $ — 0.069 % $ 765 Nonvested, end of period 0.000 % $ — 0.038 % $ 1,650 Vested, end of period 0.000 % $ — 4.294 % $ 257
SMP Net Profits Interests
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of inputs used in the option pricing method	The inputs used in the option pricing method for the SMP Net Profits Interests granted during the year ended December 31, 2012 were as follows: January 2012 grant Length of holding period restriction (In years) 2.93 Discount for lack of marketability 24.0 % Volatility 37.0 %
Schedule of activity	Information regarding the amount and grant-date fair value of the vested and nonvested SMP Net Profits Interests for the period in which they were reflected in our financial results follows. Year ended December 31, 2012 Percentage Interest Weighted-average grant date fair value (per 1.0% of SMP Net Profits Interest) (Dollars in thousands) Nonvested, beginning of period 3.958 % $ 1,003 Granted 0.500 % $ 1,780 Vested 1.271 % $ 965 Nonvested, end of period (1) 3.187 % $ 1,140 Vested, end of period 3.168 % $ 788 __________ (1) Subsequent to the IPO, the vested and nonvested net profits interests are obligations of the Predecessor and not the Partnership
Long-term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of non-cash compensation expense recognized in general and administrative expense	Unit-based compensation recognized in general and administrative expense related to awards under the SMLP LTIP was as follows: Year ended December 31, 2014 2013 2012 (In thousands) SMLP LTIP unit-based compensation $ 4,696 $ 2,999 $ 269

CONCENTRATIONS OF RISK (Tables)

CONCENTRATIONS OF RISK (Tables)	12 Months Ended
	Dec. 31, 2014
Revenue | Customer concentration
CONCENTRATIONS OF RISK
Schedule of customers accounting for more than 10% of total revenues and accounts receivable	Counterparties accounting for more than 10% of total revenues were as follows: Year ended December 31, 2014 2013 2012 Revenue: Counterparty A - Piceance Basin 20 % 21 % 27 % Counterparty B - Barnett Shale * 15 % 19 % Counterparty C - Williston Basin – Gas * * — % Counterparty D - Marcellus Shale * * — % Counterparty E - Piceance Basin * * — % Counterparty F - Barnett Shale * * 14 % __________ * Less than 10%
Accounts receivable | Credit concentration
CONCENTRATIONS OF RISK
Schedule of customers accounting for more than 10% of total revenues and accounts receivable	Counterparties accounting for more than 10% of total accounts receivable were as follows: December 31, 2014 2013 Accounts receivable: Counterparty A - Piceance Basin 27 % 36 % Counterparty B - Barnett Shale * 10 % Counterparty C - Williston Basin – Gas 13 % * Counterparty D - Marcellus Shale * * Counterparty E - Piceance Basin * * Counterparty F - Barnett Shale * * __________ * Less than 10%

RELATED-PARTY TRANSACTIONS (Tab

RELATED-PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Schedules of Related Party Transactions	Amounts paid for such services were as follows: Year ended December 31, 2014 2013 2012 (In thousands) Payments for electricity management consulting services $ 234 $ 199 $ 204 Expenses incurred by the general partner and reimbursed by us under our partnership agreement were as follows: Year ended December 31, 2014 2013 2012 (In thousands) Operation and maintenance expense $ 19,782 $ 14,323 $ 2,913 General and administrative expense 22,370 18,662 3,661

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014 2013 2012 Rent expense $ 1,786 $ 1,495 $ 732

ACQUISITIONS (Tables)

ACQUISITIONS (Tables)	12 Months Ended
	Dec. 31, 2014
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information	T
Red Rock Gathering Company, LLC
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 October 23, 2012, were as follows (in thousands): Red Rock Gathering purchase price $ 206,694 Cash $ 1,097 Accounts receivable 8,018 Other assets 317 Property, plant, and equipment 150,401 Rights-of-way 52,197 Other noncurrent assets 164 Total assets acquired 212,194 Trade accounts payable 2,558 Other current liabilities 2,942 Total liabilities assumed $ 5,500 Net identifiable assets acquired $ 206,694
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
Schedule of Revenue and Net Income Disclosures	Year ended December 31, 2014 2013 2012 (In thousands) SMLP revenues $ 319,373 $ 225,192 $ 165,499 Polar and Divide revenues 22,449 3,893 Red Rock Gathering revenues 11,313 50,114 8,924 Bison Gas Gathering system revenues (1) 17,614 Combined revenues $ 353,135 $ 296,813 $ 174,423 SMLP net (loss) income $ (23,992 ) $ 43,584 $ 41,726 Polar and Divide net income (loss) 6,430 (467 ) Red Rock Gathering net income 2,828 9,668 1,271 Bison Gas Gathering system net income (1) 52 Combined net (loss) income $ (14,734 ) $ 52,837 $ 42,997 __________ (1) Results are fully reflected in SMLP's results of operations for the year ended December 31, 2014.
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 FINANCIAL37

UNAUDITED QUARTERLY FINANCIAL DATA (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014 , follows. 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) $ 102,986 $ 84,784 $ 85,984 $ 79,381 Net (loss) income attributable to partners (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. (2) In the quarter ended December 31, 2014, includes $54.2 million of goodwill impairment and $5.5 million of long-lived asset impairment. Quarter ended December 31, 2013 Quarter ended September 30, 2013 Quarter ended June 30, 2013 Quarter ended March 31, 2013 (In thousands, except per-unit amounts) Total revenues (1) $ 85,599 $ 77,353 $ 71,847 $ 62,014 Net income attributable to partners $ 16,345 $ 6,691 $ 8,068 $ 12,480 Less: net income attributable to general partner, including IDRs 490 134 161 250 Net income attributable to limited partners $ 15,855 $ 6,557 $ 7,907 $ 12,230 Earnings per limited partner unit: Common unit – basic $ 0.30 $ 0.12 $ 0.16 $ 0.25 Common unit – diluted $ 0.29 $ 0.12 $ 0.16 $ 0.25 Subordinated unit – basic and diluted $ 0.30 $ 0.12 $ 0.16 $ 0.25 __________ (1) Retrospectively adjusted for the impact of the Polar and Divide Drop Down, the Red Rock Drop Down and the Bison Drop Down.
Retrospective adjustments from impact of acquisitions	A reconciliation of total revenues follows. Quarter ended December 31, 2013 Quarter ended September 30, 2013 Quarter ended June 30, 2013 Quarter ended March 31, 2013 (In thousands) Total revenues as originally reported $ 69,299 $ 63,096 $ 59,285 $ 43,595 Total revenue impact of Polar and Divide Drop Down 2,143 1,334 386 30 Total revenue impact of Red Rock Drop Down 14,157 12,923 12,176 10,858 Total revenue impact of Bison Drop Down — — — 7,531 Total revenues $ 85,599 $ 77,353 $ 71,847 $ 62,014 A reconciliation of total revenues follows. Quarter ended December 31, 2014 Quarter ended September 30, 2014 Quarter ended June 30, 2014 Quarter ended March 31, 2014 (In thousands) Total revenues as originally reported $ 94,658 $ 79,030 $ 80,796 $ 76,202 Total revenue impact of Polar and Divide Drop Down 8,328 5,754 5,188 3,179 Total revenues $ 102,986 $ 84,784 $ 85,984 $ 79,381

ORGANIZATION, BUSINESS OPERAT38

ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION (Details) $ in Thousands	Oct. 03, 2012	Jun. 30, 2014	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2014USD ($)segmentshares	Dec. 31, 2013USD ($)shares	Dec. 31, 2012USD ($)
ORGANIZATION AND BUSINESS OPERATIONS
Limited partner interest (as a percent)				100.00%
Common limited partner capital, units outstanding | shares					34,427,000	29,080,000
Number of reportable segments | segment					5
Cost of natural gas and NGLs					$ 52,847	$ 41,164	$ 3,224
Summit Holdings
ORGANIZATION AND BUSINESS OPERATIONS
Cumulative percentage ownership after all transactions	100.00%
DFW Midstream
ORGANIZATION AND BUSINESS OPERATIONS
Cumulative percentage ownership after all transactions	100.00%
Grand River Gathering, LLC
ORGANIZATION AND BUSINESS OPERATIONS
Cumulative percentage ownership after all transactions	100.00%
Common units | Summit Investments
ORGANIZATION AND BUSINESS OPERATIONS
Common limited partner capital, units outstanding | shares					5,293,571
General partner
ORGANIZATION AND BUSINESS OPERATIONS
General partner interest (as a percent)	2.00%		2.00%	2.00%	2.00%	2.00%	2.00%
Class A Membership Interest | GE Energy Financial Services
ORGANIZATION AND BUSINESS OPERATIONS
Exchange of membership interests, percent		100.00%
Restatement Adjustment | Williston Basin – Gas Segment | Operating and Maintenance Expense
ORGANIZATION AND BUSINESS OPERATIONS
Cost of natural gas and NGLs					$ 5,200	$ 3,100

ORGANIZATION, BUSINESS OPERAT39

ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION - Initial Public Offering (Details) $ in Thousands	Oct. 03, 2012USD ($)directorshares	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)shares	Dec. 31, 2012USD ($)shares
Limited Partners' Capital Account [Line Items]
Limited partner interest (as a percent)			100.00%
Distributions made to reimburse for certain capital expenditures | $	$ 88,000
Common units sold in public offering				5,408,337		14,380,000
Net proceeds from IPO | $	269,400			$ 197,806	$ 0	$ 263,125
Repayments of indebtedness | $				$ 315,295	$ 294,180	$ 160,770
Distributions made in connection with underwriters exercising option to purchase additional units | $	35,100
Estimated IPO expenses | $	$ 6,300
General partner
Limited Partners' Capital Account [Line Items]
General partner interest (as a percent)	2.00%	2.00%	2.00%	2.00%	2.00%	2.00%
Partner units	996,320
Revolving credit facility
Limited Partners' Capital Account [Line Items]
Repayments of indebtedness | $	$ 140,000
Common units | Limited Partner
Limited Partners' Capital Account [Line Items]
Partner units	10,029,850
Units sold to public for cash in connection with the exercise of the underwriters' option to purchase additional common units	1,875,000
Limited partner interest (as a percent)	20.10%
Common units sold in public offering	14,375,000
Limited partner interest sold in public offering (as a percent)	28.90%
Subordinated Units | Limited Partner
Limited Partners' Capital Account [Line Items]
Partner units	24,409,850
Limited partner interest (as a percent)	49.00%
Director | Common units
Limited Partners' Capital Account [Line Items]
Units granted in connection with IPO pursuant to LTIP	5,000
Number of related persons to whom common units were granted | director	2
Phantom Units
Limited Partners' Capital Account [Line Items]
Units granted in connection with IPO pursuant to LTIP				136,867	155,330	125,000
Phantom Units | Employees
Limited Partners' Capital Account [Line Items]
Units granted in connection with IPO pursuant to LTIP	125,000

SUMMARY OF SIGNIFICANT ACCOUN40

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($)	12 Months Ended		36 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts	$ 0	$ 0	$ 0
Unfavorable gas gathering contract, useful lives	10 years	10 years
Impairment of long-lived assets			$ 0
Favorable gas gathering contract
Significant Accounting Policies [Line Items]
Useful lives	18 years 8 months 12 days	18 years 8 months 12 days
Rights-of-way
Significant Accounting Policies [Line Items]
Useful lives	24 years 8 months	24 years 8 months
Gathering System
Significant Accounting Policies [Line Items]
Useful lives	30 years
Minimum
Significant Accounting Policies [Line Items]
Unfavorable gas gathering contract, useful lives	10 years
Minimum | Favorable gas gathering contract
Significant Accounting Policies [Line Items]
Useful lives	10 years
Minimum | Other Gas Gathering Contract
Significant Accounting Policies [Line Items]
Useful lives	10 years
Minimum | Rights-of-way
Significant Accounting Policies [Line Items]
Useful lives	20 years
Maximum
Significant Accounting Policies [Line Items]
Unfavorable gas gathering contract, useful lives	20 years
Maximum | Favorable gas gathering contract
Significant Accounting Policies [Line Items]
Useful lives	20 years
Maximum | Other Gas Gathering Contract
Significant Accounting Policies [Line Items]
Useful lives	25 years
Maximum | Rights-of-way
Significant Accounting Policies [Line Items]
Useful lives	30 years

SUMMARY OF SIGNIFICANT ACCOUN41

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving credit facility, Carrying value	$ 208,000	$ 286,000
Fair value, Level 2 inputs
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving credit facility, Estimated fair value (Level 2)	208,000	286,000
5.5% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes, Carrying value	300,000	0
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)	281,750	0
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)	$ 306,750	$ 314,625

SUMMARY OF SIGNIFICANT ACCOUN42

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Income Taxes and EPS (Details) - USD ($) $ in Millions	Oct. 03, 2012	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Significant Accounting Policies [Line Items]
Deferred tax liability due to changes from the Texas Margin Tax				$ 1
Reduction in current income tax expense				0.3
Deferred tax liability, noncurrent				$ 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%	2.00%

SEGMENT INFORMATION - Assets by

SEGMENT INFORMATION - Assets by Reportable Segment (Details) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Assets	$ 2,293,721	$ 2,191,143
Reportable Segments
Segment Reporting Information [Line Items]
Assets	2,255,144	2,167,940
Reportable Segments | Marcellus Shale Segment
Segment Reporting Information [Line Items]
Assets	243,884	214,379
Reportable Segments | Williston Basin – Gas Segment
Segment Reporting Information [Line Items]
Assets	311,041	337,610
Reportable Segments | Williston Basin – Liquids Segment
Segment Reporting Information [Line Items]
Assets	398,847	307,404
Reportable Segments | Barnett Shale Segment
Segment Reporting Information [Line Items]
Assets	428,935	431,578
Reportable Segments | Piceance Basin Segment
Segment Reporting Information [Line Items]
Assets	872,437	876,969
Corporate
Segment Reporting Information [Line Items]
Assets	$ 38,577	$ 23,203

SEGMENT INFORMATION - Adjusted

SEGMENT INFORMATION - Adjusted EBITDA by Reportable Segment (Details) - Reportable Segments - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ 215,972	$ 174,097	$ 116,849
Marcellus Shale Segment
Segment Reporting Information [Line Items]
Adjusted EBITDA	15,940	6,333
Williston Basin – Gas Segment
Segment Reporting Information [Line Items]
Adjusted EBITDA	20,422	16,865
Williston Basin – Liquids Segment
Segment Reporting Information [Line Items]
Adjusted EBITDA	11,129	485
Barnett Shale Segment
Segment Reporting Information [Line Items]
Adjusted EBITDA	60,528	69,473	63,670
Piceance Basin Segment
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ 107,953	$ 80,941	$ 53,179

SEGMENT INFORMATION - Reconcili

SEGMENT INFORMATION - Reconciliation of Net Income to Adjusted EBITDA (Details) - USD ($)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Income before income taxes			$ (14,103,000)	$ 53,566,000	$ 43,679,000
Add:
Interest expense and affiliated interest expense			40,159,000	19,173,000	12,766,000
Depreciation and amortization			88,293,000	71,606,000	36,866,000
Adjustments related to MVC shortfall payments			26,565,000	17,025,000	10,768,000
Unit-based compensation			5,036,000	3,846,000	1,876,000
Loss on asset sales, net			442,000	113,000	0
Goodwill impairment	$ 54,200,000	$ 0	54,199,000	0	0
Long-lived asset impairment	$ 5,500,000		5,505,000	0	0
Less:
Interest income			4,000	5,000	9,000
Impact of purchase price adjustments			1,185,000	0	0
Corporate
Add:
Allocated corporate expenses			11,065,000	8,773,000	10,903,000
Reportable Segments
Less:
Adjusted EBITDA			$ 215,972,000	$ 174,097,000	$ 116,849,000

SEGMENT INFORMATION - Revenues,

SEGMENT INFORMATION - Revenues, Depreciation and Amortization, Other (Expense) Income, and Capital Expenditures by Reportable Segment (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Revenues	$ 102,986	$ 84,784	$ 85,984	$ 79,381	$ 85,599	$ 77,353	$ 71,847	$ 62,014	$ 353,135	$ 296,813	$ 174,423
Depreciation and amortization									87,349	70,574	36,674
Other income									1,189	5	9
Capital expenditures									220,820	182,978	77,296
Reportable Segments
Segment Reporting Information [Line Items]
Revenues									353,135	296,813	175,414
Depreciation and amortization									86,761	70,123	36,388
Other income									1,185	0	0
Capital expenditures									220,360	182,048	76,487
Reportable Segments | Marcellus Shale Segment
Segment Reporting Information [Line Items]
Revenues									22,694	9,588
Depreciation and amortization									7,648	3,998
Other income									0	0
Capital expenditures									33,866	1,822
Reportable Segments | Williston Basin – Gas Segment
Segment Reporting Information [Line Items]
Revenues									62,454	50,735
Depreciation and amortization									18,132	16,057
Other income									0	0
Capital expenditures									46,927	26,381
Reportable Segments | Williston Basin – Liquids Segment
Segment Reporting Information [Line Items]
Revenues									22,449	3,893
Depreciation and amortization									4,359	612
Other income									0	0
Capital expenditures									92,495	73,602
Reportable Segments | Barnett Shale Segment
Segment Reporting Information [Line Items]
Revenues									93,001	105,324	93,453
Depreciation and amortization									15,657	13,929	12,078
Other income									0	0	0
Capital expenditures									14,567	29,534	39,588
Reportable Segments | Piceance Basin Segment
Segment Reporting Information [Line Items]
Revenues									152,537	127,273	81,961
Depreciation and amortization									40,965	35,527	24,310
Other income									1,185	0	0
Capital expenditures									32,505	50,709	36,899
Corporate
Segment Reporting Information [Line Items]
Revenues									0	0	(991)
Depreciation and amortization									588	451	286
Other income									4	5	9
Capital expenditures									$ 460	$ 930	$ 809

PROPERTY, PLANT, AND EQUIPMEN47

PROPERTY, PLANT, AND EQUIPMENT, NET (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Gross	$ 1,536,024	$ 1,536,024	$ 1,328,242
Less accumulated depreciation	121,674	121,674	71,928
Property, plant, and equipment, net	1,414,350	1,414,350	1,256,314
Long-lived asset impairment	5,500	5,505	0	$ 0
Depreciation expense		49,816	37,313	22,422
Capitalized interest		$ 3,778	6,255	$ 2,784
Gathering and processing systems and related equipment
Property, Plant and Equipment [Line Items]
Useful lives		30 years
Gross	1,462,706	$ 1,462,706	1,212,227
Construction in progress
Property, Plant and Equipment [Line Items]
Gross	44,447	44,447	94,130
Other
Property, Plant and Equipment [Line Items]
Gross	28,871	$ 28,871	$ 21,885
Other | Minimum
Property, Plant and Equipment [Line Items]
Useful lives		4 years
Other | Maximum
Property, Plant and Equipment [Line Items]
Useful lives		15 years
Compressor station project
Property, Plant and Equipment [Line Items]
Long-lived asset impairment	$ 5,500

IDENTIFIABLE INTANGIBLE ASSET48

IDENTIFIABLE INTANGIBLE ASSETS, NONCURRENT LIABILITY AND GOODWILL (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	$ 574,240	$ 563,075
Accumulated amortization	(96,506)	(57,231)
Total intangible assets, net	$ 477,734	$ 505,844
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	(5,385)	(4,588)
Unfavorable gas gathering contract, Net	5,577	6,374
Amortization expense
Amortization expense - unfavorable contract	797	1,046	$ 1,524
Amortization of favorable and unfavorable contracts	(944)	$ (1,032)	(191)
Assets
2,015	42,254
2,016	42,219
2,017	41,069
2,018	40,673
2,019	40,619
Liability
2,015	698
2,016	924
2,017	1,047
2,018	1,123
2,019	$ 957
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	(8,056)	(6,315)
Total intangible assets, net	16,139	17,880
Amortization expense
Amortization expense	$ 1,741	$ 2,078	1,715
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	(75,713)	(43,158)
Total intangible assets, net	350,751	383,306
Amortization expense
Amortization expense	$ 32,554	$ 28,654	12,642
Rights-of-way
Finite-Lived Intangible Assets [Line Items]
Useful lives	24 years 8 months	24 years 8 months
Gross carrying amount	$ 123,581	$ 112,416
Accumulated amortization	(12,737)	(7,758)
Total intangible assets, net	110,844	104,658
Amortization expense
Amortization expense	$ 4,979	$ 4,607	$ 1,610

IDENTIFIABLE INTANGIBLE ASSET49

IDENTIFIABLE INTANGIBLE ASSETS, NONCURRENT LIABILITY AND GOODWILL - Goodwill (Details) - USD ($)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Goodwill [Roll Forward]
Goodwill, beginning balance		$ 319,261,000	$ 319,261,000	$ 45,478,000
Goodwill impairment	$ (54,200,000)	0	(54,199,000)	0	$ 0
Goodwill, ending balance	265,062,000		265,062,000	319,261,000	45,478,000
Piceance Basin Segment
Goodwill [Roll Forward]
Goodwill, beginning balance		45,478,000	45,478,000	45,478,000
Goodwill impairment			0
Goodwill, ending balance	45,478,000		45,478,000	45,478,000	45,478,000
Williston Basin – Gas Segment
Goodwill [Roll Forward]
Goodwill, beginning balance		54,199,000	54,199,000	0
Goodwill impairment			(54,199,000)
Goodwill, ending balance	0		0	54,199,000	0
Williston Basin – Liquids Segment
Goodwill [Roll Forward]
Goodwill, beginning balance		203,373,000	203,373,000	0
Goodwill impairment			0
Goodwill, ending balance	203,373,000		203,373,000	203,373,000	0
Marcellus Shale Segment
Goodwill [Roll Forward]
Goodwill, beginning balance		$ 16,211,000	16,211,000	0
Goodwill impairment			0
Goodwill, ending balance	$ 16,211,000		$ 16,211,000	16,211,000	$ 0
Bison Midstream
Goodwill [Roll Forward]
Goodwill acquired				54,199,000
Bison Midstream | Piceance Basin Segment
Goodwill [Roll Forward]
Goodwill acquired				0
Bison Midstream | Williston Basin – Gas Segment
Goodwill [Roll Forward]
Goodwill acquired				54,199,000
Bison Midstream | Williston Basin – Liquids Segment
Goodwill [Roll Forward]
Goodwill acquired				0
Bison Midstream | Marcellus Shale Segment
Goodwill [Roll Forward]
Goodwill acquired				0
Polar Midstream and Epping
Goodwill [Roll Forward]
Goodwill acquired				203,373,000
Polar Midstream and Epping | Piceance Basin Segment
Goodwill [Roll Forward]
Goodwill acquired				0
Polar Midstream and Epping | Williston Basin – Gas Segment
Goodwill [Roll Forward]
Goodwill acquired				0
Polar Midstream and Epping | Williston Basin – Liquids Segment
Goodwill [Roll Forward]
Goodwill acquired				203,373,000
Polar Midstream and Epping | Marcellus Shale Segment
Goodwill [Roll Forward]
Goodwill acquired				0
Mountaineer Midstream
Goodwill [Roll Forward]
Goodwill acquired				18,089,000
Goodwill adjustment recognized in connection with finalizing accounting for the Mountaineer Acquisition and other				(1,878,000)
Mountaineer Midstream | Piceance Basin Segment
Goodwill [Roll Forward]
Goodwill acquired				0
Goodwill adjustment recognized in connection with finalizing accounting for the Mountaineer Acquisition and other				0
Mountaineer Midstream | Williston Basin – Gas Segment
Goodwill [Roll Forward]
Goodwill acquired				0
Goodwill adjustment recognized in connection with finalizing accounting for the Mountaineer Acquisition and other				0
Mountaineer Midstream | Williston Basin – Liquids Segment
Goodwill [Roll Forward]
Goodwill acquired				0
Goodwill adjustment recognized in connection with finalizing accounting for the Mountaineer Acquisition and other				0
Mountaineer Midstream | Marcellus Shale Segment
Goodwill [Roll Forward]
Goodwill acquired				18,089,000
Goodwill adjustment recognized in connection with finalizing accounting for the Mountaineer Acquisition and other				$ (1,878,000)

IDENTIFIABLE INTANGIBLE ASSET50

IDENTIFIABLE INTANGIBLE ASSETS, NONCURRENT LIABILITY AND GOODWILL - Additional Disclosures (Details) - USD ($)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Goodwill [Line Items]
Goodwill impairment	$ 54,200,000	$ 0	$ 54,199,000	$ 0	$ 0
Williston Basin – Liquids Segment
Goodwill [Line Items]
Goodwill impairment			$ 0

DEFERRED REVENUE (Details)

DEFERRED REVENUE (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Movement in Deferred Revenue [Roll Forward]
Current deferred revenue, beginning balance	$ 1,555	$ 865	$ 0
Additions	2,610	1,555	865
Less: revenue recognized due to expiration	1,555	865
Less: revenue recognized due to usage	233
Current deferred revenue, ending balance	2,377	1,555	865
Noncurrent deferred revenue, beginning balance	29,683	10,899	1,770
Additions	25,556	18,784	9,129
Noncurrent deferred revenue, ending balance	55,239	29,683	10,899
Shortfall payments billed and included in accounts receivable	$ 13,100
Maximum period customers have the ability to offset their gathering fees	7 years
Williston Basin – Gas Segment
Movement in Deferred Revenue [Roll Forward]
Current deferred revenue, beginning balance	$ 0	0	0
Additions	0	0	0
Less: revenue recognized due to expiration	0	0
Less: revenue recognized due to usage	0
Current deferred revenue, ending balance	0	0	0
Noncurrent deferred revenue, beginning balance	6,389	0	0
Additions	10,743	6,389	0
Noncurrent deferred revenue, ending balance	17,132	6,389	0
Barnett Shale Segment
Movement in Deferred Revenue [Roll Forward]
Current deferred revenue, beginning balance	1,555	865	0
Additions	2,610	1,555	865
Less: revenue recognized due to expiration	1,555	865
Less: revenue recognized due to usage	233
Current deferred revenue, ending balance	2,377	1,555	865
Noncurrent deferred revenue, beginning balance	0	0	0
Additions	0	0	0
Noncurrent deferred revenue, ending balance	0	0	0
Piceance Basin Segment
Movement in Deferred Revenue [Roll Forward]
Current deferred revenue, beginning balance	0	0	0
Additions	0	0	0
Less: revenue recognized due to expiration	0	0
Less: revenue recognized due to usage	0
Current deferred revenue, ending balance	0	0	0
Noncurrent deferred revenue, beginning balance	23,294	10,899	1,770
Additions	14,813	12,395	9,129
Noncurrent deferred revenue, ending balance	$ 38,107	$ 23,294	$ 10,899

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Line of Credit Facility [Line Items]
Revolving credit facility	$ 208,000	$ 286,000
Total long-term debt	$ 808,000	$ 586,000
Revolving credit facility
Line of Credit Facility [Line Items]
Weighted-average interest rate (as a percent)	2.67%	2.42%
5.5% Senior Notes
Line of Credit Facility [Line Items]
Senior unsecured notes	$ 300,000	$ 0
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%

LONG-TERM DEBT - Maturities (De

LONG-TERM DEBT - Maturities (Details) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
2,015	$ 0
2,016	0
2,017	0
2,018	208,000
2,019	0
Thereafter	600,000
Long-term Debt	$ 808,000	$ 586,000

LONG-TERM DEBT - Revolving Cred

LONG-TERM DEBT - Revolving Credit Facility (Details) - Dec. 31, 2014 - Revolving credit facility	USD ($)
Line of Credit Facility [Line Items]
Borrowing capacity	$ 700,000,000
Commitment fee on unused portion of the facility (as a percent)	0.50%
Interest rate at period end	2.67%
Unused portion under the facility	$ 492,000,000
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
Trailing period used in calculating the ratio of total indebtedness to consolidated EBITDA	12 months
Period following certain acquisitions, for which higher ratio of total indebtedness to consolidated EBITDA is to be maintained	270 days
Debt defaults	$ 0
LIBOR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)	2.50%
Accordion provision
Line of Credit Facility [Line Items]
Borrowing capacity	$ 200,000,000
Minimum
Line of Credit Facility [Line Items]
Commitment fee on unused portion of the facility (as a percent)	0.30%
Ratio of consolidated EBITDA to net interest expense	2.5
Minimum | ABR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)	0.75%
Minimum | LIBOR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)	1.75%
Maximum
Line of Credit Facility [Line Items]
Commitment fee on unused portion of the facility (as a percent)	0.50%
Ratio of total indebtedness to consolidated EBITDA	5
Ratio of total indebtedness to consolidated EBITDA, for a specified period following certain acquisitions	5.5
Maximum | ABR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)	1.75%
Maximum | LIBOR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)	2.75%

LONG-TERM DEBT - Senior Notes (

LONG-TERM DEBT - Senior Notes (Details) - USD ($)	Jul. 15, 2014	Dec. 31, 2014	Dec. 31, 2013	Jun. 30, 2013
Finance Corp.
Debt Instrument [Line Items]
Cumulative percentage ownership in subsidiary	100.00%
5.5% Senior Notes
Debt Instrument [Line Items]
Senior unsecured notes		$ 300,000,000	$ 0
5.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Stated interest rate		5.50%	5.50%
5.5% Senior Notes | Summit Holdings and Finance Corporation | 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%
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
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%
7.5% Senior Notes | Summit Holdings and Finance Corporation | Senior Notes
Debt Instrument [Line Items]
Senior unsecured notes				$ 300,000,000
Stated interest rate				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
Prior to August 15, 2017 | 5.5% Senior Notes | Summit Holdings and Finance Corporation | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		105.50%
August 15, 2017 - August 15, 2020 | 5.5% Senior Notes | Summit Holdings and Finance Corporation | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		104.125%
August 15, 2020 | 5.5% Senior Notes | Summit Holdings and Finance Corporation | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		100.00%
Prior to July 1, 2016 | 7.5% Senior Notes | Summit Holdings and Finance Corporation | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		107.50%
July 1, 2016 - June 30, 2019 | 7.5% Senior Notes | Summit Holdings and Finance Corporation | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		105.625%
July 1, 2019 | 7.5% Senior Notes | Summit Holdings and Finance Corporation | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		100.00%
Other noncurrent assets | 5.5% Senior Notes | Summit Holdings and Finance Corporation | Senior Notes
Debt Instrument [Line Items]
Debt issuance costs	$ 5,100,000

PARTNERS' CAPITAL AND MEMBERH56

PARTNERS' CAPITAL AND MEMBERHIP INTERESTS - Partners' Capital and Schedule of Units (Details) - $ / shares	May. 13, 2015	Oct. 03, 2012	Sep. 30, 2014	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Class of Stock [Line Items]
Common units sold in public offering						5,408,337		14,380,000
Rollforwards of the number of partner units
Units, beginning balance						54,581,169	49,818,597	0
Units issued to the public in connection with public offering						5,408,337		14,380,000
Units issued to Summit Investments in connection with the IPO								35,436,020
Units issued under SMLP LTIP						47,508	5,892	2,577
Units, ending balance						60,037,014	54,581,169	49,818,597
Units withheld to meet the minimum statutory tax withholding requirement						14,300,000
Common
Class of Stock [Line Items]
Common units sold in public offering			4,347,826	10,350,000		5,300,000		14,380,000
Price per unit (dollars per unit)				$ 38.75
Rollforwards of the number of partner units
Units, beginning balance						29,079,866	24,412,427	0
Units issued to the public in connection with public offering			4,347,826	10,350,000		5,300,000		14,380,000
Units issued to Summit Investments in connection with the IPO								10,029,850
Units issued under SMLP LTIP						46,647	5,892	2,577
Units, ending balance						34,426,513	29,079,866	24,412,427
Subordinated
Class of Stock [Line Items]
Common units sold in public offering						0		0
Rollforwards of the number of partner units
Units, beginning balance						24,409,850	24,409,850	0
Units issued to the public in connection with public offering						0		0
Units issued to Summit Investments in connection with the IPO								24,409,850
Units issued under SMLP LTIP						0	0	0
Units, ending balance						24,409,850	24,409,850	24,409,850
General partner
Class of Stock [Line Items]
Common units sold in public offering						108,337		0
Rollforwards of the number of partner units
Units, beginning balance						1,091,453	996,320	0
Units issued to the public in connection with public offering						108,337		0
Units issued to Summit Investments in connection with the IPO								996,320
Units issued under SMLP LTIP						861	0	0
Units, ending balance						1,200,651	1,091,453	996,320
Partnership | Common
Class of Stock [Line Items]
Common units sold in public offering				5,300,000
Rollforwards of the number of partner units
Units issued to the public in connection with public offering				5,300,000
Summit Investments | Common
Class of Stock [Line Items]
Common units sold in public offering				5,050,000
Rollforwards of the number of partner units
Units issued to the public in connection with public offering				5,050,000
General partner
Class of Stock [Line Items]
General partner interest (as a percent)		2.00%		2.00%	2.00%	2.00%	2.00%	2.00%
Rollforwards of the number of partner units
Units issued to affiliates in connection with acquisition		996,320
Bison Midstream
Rollforwards of the number of partner units
Units issued to affiliates in connection with acquisition							1,585,560
Bison Midstream | Common
Rollforwards of the number of partner units
Units issued to affiliates in connection with acquisition							1,553,849
Bison Midstream | Subordinated
Rollforwards of the number of partner units
Units issued to affiliates in connection with acquisition							0
Bison Midstream | General partner
Rollforwards of the number of partner units
Units issued to affiliates in connection with acquisition							31,711
Mountaineer Midstream
Rollforwards of the number of partner units
Units issued to affiliates in connection with acquisition							3,171,120
Mountaineer Midstream | Common
Rollforwards of the number of partner units
Units issued to affiliates in connection with acquisition							3,107,698
Mountaineer Midstream | Subordinated
Rollforwards of the number of partner units
Units issued to affiliates in connection with acquisition							0
Mountaineer Midstream | General partner
Rollforwards of the number of partner units
Units issued to affiliates in connection with acquisition							63,422
Subsequent Event | General partner
Class of Stock [Line Items]
General partner interest (as a percent)	2.00%
Public Offering [Member] | Subsequent Event | Common
Class of Stock [Line Items]
Common units sold in public offering	6,500,000
Price per unit (dollars per unit)	$ 30.75
Rollforwards of the number of partner units
Units issued to the public in connection with public offering	6,500,000

PARTNERS' CAPITAL AND MEMBERH57

PARTNERS' CAPITAL AND MEMBERHIP INTERESTS - Allocation of Capital Contributions and Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands

May. 18, 2015

May. 13, 2015

Mar. 18, 2014

Jun. 21, 2013

Jun. 04, 2013

Jun. 04, 2013

Jun. 03, 2013

Oct. 23, 2012

Oct. 03, 2012

Mar. 31, 2014

Mar. 31, 2013

Jul. 31, 2012

May. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Business Acquisition [Line Items]

Distributions to unitholders

$ (122,224)

$ (90,196)

$ (123,138)

Contributions to unitholders

4,235

Basis for determining number of units issued, period

5 days

Closing price (in dollars per unit)

$ 30.85

$ 30.85

Red Rock Gathering Company, LLC

Business Acquisition [Line Items]

Percent of membership interest acquired

100.00%

Total cash consideration

$ 305,000

Total consideration

307,941

Liabilities incurred for acquisition

2,900

Distributions to unitholders

(66,124)

Bison Midstream

Business Acquisition [Line Items]

Total cash consideration

$ 200,000

Total consideration

248,914

Contributions to unitholders

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 unit)

$ 31.53

Mountaineer Midstream

Business Acquisition [Line Items]

Total cash consideration

$ 110,000

Cost of acquired entity, equity interests issued and issuable

100,000

Total consideration

210,000

Basis for determining number of units issued, assumed equity issuance

$ 100,000

Basis for determining number of units issued, weighted-average price (in dollars per unit)

$ 31.53

General partner

Business Acquisition [Line Items]

Distributions to unitholders

(4,770)

$ (1,803)

Contributions to unitholders

$ 4,235

$ 19,870

General partner interest (as a percent)

2.00%

2.00%

2.00%

2.00%

2.00%

2.00%

General partner | Red Rock Gathering Company, LLC

Business Acquisition [Line Items]

Distributions to unitholders

(1,323)

General partner | Bison Midstream

Business Acquisition [Line Items]

Cost of acquired entity, equity interests issued and issuable

978

Units issued

31,711

Contributions to unitholders

1,131

General partner | Mountaineer Midstream

Business Acquisition [Line Items]

Cost of acquired entity, equity interests issued and issuable

$ 2,000

Units issued

63,422

Limited partners, Common

Business Acquisition [Line Items]

Distributions to unitholders

$ (67,658)

$ (46,286)

$ (64,178)

Contributions to unitholders

211,938

Limited partners, Common | Red Rock Gathering Company, LLC

Business Acquisition [Line Items]

Distributions to unitholders

(37,910)

Limited partners, Common | Bison Midstream

Business Acquisition [Line Items]

Cost of acquired entity, equity interests issued and issuable

47,936

Units issued

1,553,849

Contributions to unitholders

28,558

Limited partners, Common | Mountaineer Midstream

Business Acquisition [Line Items]

Cost of acquired entity, equity interests issued and issuable

$ 98,000

Units issued

3,107,698

Limited partners, Subordinated

Business Acquisition [Line Items]

Distributions to unitholders

$ (49,796)

$ (42,107)

(58,960)

Contributions to unitholders

$ 430,498

Limited partners, Subordinated | Red Rock Gathering Company, LLC

Business Acquisition [Line Items]

Distributions to unitholders

(26,891)

Limited partners, Subordinated | Bison Midstream

Business Acquisition [Line Items]

Contributions to unitholders

26,846

Summit Investments | Red Rock Gathering Company, LLC

Business Acquisition [Line Items]

Total consideration

$ 206,694

Red Rock Gathering Company, LLC | Summit Investments

Business Acquisition [Line Items]

Net investment

241,817

Bison Midstream | Summit Investments

Business Acquisition [Line Items]

Net investment

$ 305,449

$ 305,449

Revolving credit facility

Business Acquisition [Line Items]

Amounts borrowed under revolving credit facility

$ 50,000

$ 163,000

Revolving credit facility | Red Rock Gathering Company, LLC

Business Acquisition [Line Items]

Amounts borrowed under revolving credit facility

$ 100,000

Revolving credit facility | Mountaineer Midstream

Business Acquisition [Line Items]

Amounts borrowed under revolving credit facility

$ 110,000

Subsequent Event | Polar Midstream and Epping

Business Acquisition [Line Items]

Total consideration

$ 290,000

Liabilities incurred for acquisition

$ 92,500

Subsequent Event | General partner

Business Acquisition [Line Items]

General partner interest (as a percent)

2.00%

PARTNERS' CAPITAL AND MEMBERH58

PARTNERS' CAPITAL AND MEMBERHIP INTERESTS - Subordination and Cash Distribution Policy (Details)	Oct. 03, 2012	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2014$ / shares	Dec. 31, 2013	Dec. 31, 2012
Schedule of Partners' Capital [Line Items]
Maximum period following end of quarter to distribute all available cash				45 days
General partner
Schedule of Partners' Capital [Line Items]
General partner interest (as a percent)	2.00%	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 (in shares)				1

PARTNERS' CAPITAL AND MEMBERH59

PARTNERS' CAPITAL AND MEMBERHIP INTERESTS - Minimum Quarterly Distribution (Details)	12 Months Ended
	Dec. 31, 2014$ / shares
Equity [Abstract]
Minimum quarterly distributions (in dollars per share)	$ 0.40
Minimum annual distributions (in dollars per share)	$ 1.60

PARTNERS' CAPITAL AND MEMBERH60

PARTNERS' CAPITAL AND MEMBERHIP INTERESTS - Partnership Target Distributions (Details) - 12 months ended Dec. 31, 2014 - $ / shares	Total
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%

PARTNERS' CAPITAL AND MEMBERH61

PARTNERS' CAPITAL AND MEMBERHIP INTERESTS - Cash Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands	Jan. 22, 2015	Nov. 14, 2014	Aug. 14, 2014	May. 15, 2014	Feb. 14, 2014	Nov. 14, 2013	Aug. 14, 2013	May. 15, 2013	Feb. 14, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Distribution Made to Limited Partner [Line Items]
Per-unit distribution (in dollars per unit)		$ 0.54	$ 0.52	$ 0.5	$ 0.48	$ 0.46	$ 0.435	$ 0.42	$ 0.41	$ 2.04	$ 1.725
Distributions to unitholders		$ 33,522	$ 31,953	$ 30,383	$ 26,366	$ 25,108	$ 23,740	$ 20,923	$ 20,425	$ 122,224	$ 90,196	$ 0
Subsequent Event
Distribution Made to Limited Partner [Line Items]
Per-unit distribution (in dollars per unit)	$ 0.56
General partner
Distribution Made to Limited Partner [Line Items]
General partner's IDRs		1,082	721	360	163	0	0	0	0
Limited partners, Common
Distribution Made to Limited Partner [Line Items]
Distributions to unitholders		18,589	17,900	17,211	13,958	13,377	12,647	10,253	10,009
Subordinated
Distribution Made to Limited Partner [Line Items]
Distributions to unitholders		13,181	12,693	12,205	11,717	11,229	10,618	10,252	10,008
General Partner Units
Distribution Made to Limited Partner [Line Items]
Distributions to unitholders		$ 670	$ 639	$ 607	$ 528	$ 502	$ 475	$ 418	$ 408

EARNINGS PER UNIT (Details)

EARNINGS PER UNIT (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net (loss) income										$ (14,734)	$ 52,837	$ 42,997
Less: net income attributable to the pre-IPO period										0	0	24,112
Less: net income attributable to Summit Investments										9,258	9,253	1,271
Net (loss) income attributable to SMLP	$ (37,686)	$ 6,113	$ 4,036	$ 3,545	$ 16,345	$ 6,691	$ 8,068	$ 12,480		(23,992)	43,584	17,614
Less: net (loss) income attributable to general partner, including IDRs	689	1,204	801	431	490	134	161	250		3,125	1,035	352
Net (loss) income attributable to limited partners	$ (38,375)	$ 4,909	$ 3,235	$ 3,114	$ 15,855	$ 6,557	$ 7,907	$ 12,230		$ (27,117)	$ 42,549	17,262
(Loss) earnings per limited partner unit:
Antidilutive securities diluted excluded from the calculation of diluted loss per common unit									0	231,875	0
Common units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net (loss) income attributable to limited partners										$ (16,324)	$ 23,227	$ 8,632
Weighted-average units outstanding - basic										33,311,000	26,951,000	24,412,000
Less: effect of non-vested phantom units and non-vested restricted units (in units)										0	150,000	132,000
Weighted-average units outstanding – diluted										33,311,000	27,101,000	24,544,000
(Loss) earnings per limited partner unit:
Basic (in dollars per share)	$ (0.65)	$ 0.08	$ 0.05	$ 0.08	$ 0.30	$ 0.12	$ 0.16	$ 0.25		$ (0.49)	$ 0.86	$ 0.35
Diluted (in dollars per share)	(0.65)	0.08	0.05	0.08	0.29	0.12	0.16	0.25		$ (0.49)	$ 0.86	$ 0.35
Subordinated Units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net (loss) income attributable to limited partners										$ (10,793)	$ 19,322	$ 8,630
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)	(0.65)	0.08	0.05	0.02	0.30	0.12	0.16	0.25		$ (0.44)	$ 0.79	$ 0.35
Diluted (in dollars per share)	$ (0.65)	$ 0.08	$ 0.05	$ 0.02	$ 0.30	$ 0.12	$ 0.16	$ 0.25		$ (0.44)	$ 0.79	$ 0.35

UNIT-BASED COMPENSATION - Addit

UNIT-BASED COMPENSATION - Additional Disclosures (Details) $ in Thousands	7 Months Ended	12 Months Ended
	Apr. 30, 2013USD ($)holdershares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)shares	Dec. 31, 2012USD ($)shares	Dec. 31, 2009
Long-term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized non-cash compensation expense | $		$ 4,100
Remaining expected weighted-average vesting period of recognition of incremental non-cash compensation expense		2 years 3 months
Units forfeited (in shares)		0
Common Units | Long-term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units reserved for issuance pursuant to LTIP		5,000,000
Units available for future issuance		4,600,000
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units forfeited (in shares)		22,430	4,041
Remaining or outstanding interests		336,202
Phantom Units | Long-term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period		3 years
DFW Net Profit Interests
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period		4 years
Portion of membership interests authorized for issuance, percent					5.00%
Repurchase of DFW Net Profit Interest, number of holders | holder	7
Payment to acquire vested net profit interests | $	$ 12,200
Remaining or outstanding interests		0
Non-cash compensation expense | $			$ 17	$ 700
Restricted Units | Long-term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted units exchanged for unvested net profit interests	7,393
SMP Net Profits Interests
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period		5 years
Portion of membership interests issued, percent				6.355%
Units forfeited (in shares)				0
Portion of membership interests authorized for issuance, percent					7.50%
Non-cash compensation expense | $		$ 300	$ 800	$ 900
Polar Midstream and Epping | SMP Net Profits Interests
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation expense | $		$ 300

UNIT-BASED COMPENSATION - Phant

UNIT-BASED COMPENSATION - Phantom and Restricted Unit Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Phantom and Restricted units
Phantom and Restricted Unit Activity
Nonvested phantom and restricted units, beginning of period (in shares)	283,682	131,558	0
Unit vested (in shares)	(61,917)
Nonvested phantom and restricted units, end of period (in shares)		283,682	131,558
Weighted-average grant date fair value
Nonvested, Weighted-average grant date fair value, beginning (in dollars per share)	$ 23.41	$ 20	$ 0
Units vested, Weighted-average grant date fair value (in dollars per share)	$ 25.33
Nonvested, Weighted-average grant date fair value, ending (in dollars per share)		$ 23.41	$ 20
Phantom Units
Phantom and Restricted Unit Activity
Units granted (in shares)	136,867	155,330	125,000
Units forfeited (in shares)	(22,430)	(4,041)
Nonvested phantom and restricted units, end of period (in shares)	336,202
Weighted-average grant date fair value
Units granted, Weighted-average grant date fair value (in dollars per share)	$ 42.32	$ 26.33	$ 20
Units forfeited, Weighted-average grant date fair value (in dollars per share)	25.56	$ 25.99
Nonvested, Weighted-average grant date fair value, ending (in dollars per share)	$ 30.61
Restricted Units
Phantom and Restricted Unit Activity
Units granted (in shares)		835	6,558
Weighted-average grant date fair value
Units granted, Weighted-average grant date fair value (in dollars per share)		$ 27.50	$ 20.23

UNIT-BASED COMPENSATION - Veste

UNIT-BASED COMPENSATION - Vested and Nonvested Interests (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
DFW Net Profit Interests
Percentage Interest
Nonvested at the beginning of the period (as a percent)	0.038%	1.75%
Repurchased (as a percent)	0.038%	0.00%
Vested (as a percent)	0.00%	1.644%
Forfeited (as a percent)	0.00%	0.069%
Nonvested at the end of the period (as a percent)	0.00%	0.038%
Vested, end of period (as a percent)	0.00%	4.294%
Weighted-average grant date fair value (per 1.0% of Net Profits Interests)
Nonvested at the beginning of the period (in dollars)	$ 1,650	$ 306
Repurchased (in dollars)	1,650	0
Vested (in dollars)	0	256
Forfeited (in dollars)	0	765
Nonvested at the end of the period (in dollars)	0	1,650
Vested, end of period (in dollars)	$ 0	$ 257
SMP Net Profits Interests
Percentage Interest
Nonvested at the beginning of the period (as a percent)	3.187%	3.958%
Granted (as a percent)		0.50%
Vested (as a percent)		1.271%
Nonvested at the end of the period (as a percent)		3.187%
Vested, end of period (as a percent)		3.168%
Weighted-average grant date fair value (per 1.0% of Net Profits Interests)
Nonvested at the beginning of the period (in dollars)	$ 1,140	$ 1,003
Granted (in dollars)		1,780
Vested (in dollars)		965
Nonvested at the end of the period (in dollars)		1,140
Vested, end of period (in dollars)		$ 788

UNIT-BASED COMPENSATION - Unit-

UNIT-BASED COMPENSATION - Unit-based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation	$ 4,696
Long-term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation	4,696	$ 2,999	$ 269
SMP Net Profits Interests
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation expense	$ 300	800	900
DFW Net Profit Interests
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation expense		$ 17	$ 700

UNIT-BASED COMPENSATION - Input

UNIT-BASED COMPENSATION - Inputs Used in Option Pricing Method (Details) - 1 months ended Jan. 31, 2012 - SMP Net Profits Interests	Total
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Length of holding period restriction	2 years 11 months 5 days
Discount for lack of marketability (as a percent)	24.00%
Volatility (as a percent)	37.00%

CONCENTRATIONS OF RISK (Details

CONCENTRATIONS OF RISK (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Counterparty A - Piceance Basin | Revenue | Customer concentration
CONCENTRATIONS OF RISK
Concentration risk, percentage	20.00%	21.00%	27.00%
Counterparty A - Piceance Basin | Accounts receivable | Credit concentration
CONCENTRATIONS OF RISK
Concentration risk, percentage	27.00%	36.00%
Counterparty B - Barnett Shale | Revenue | Customer concentration
CONCENTRATIONS OF RISK
Concentration risk, percentage		15.00%	19.00%
Counterparty B - Barnett Shale | Accounts receivable | Credit concentration
CONCENTRATIONS OF RISK
Concentration risk, percentage		10.00%
Counterparty C - Williston Basin - Gas | Revenue | Customer concentration
CONCENTRATIONS OF RISK
Concentration risk, percentage			0.00%
Counterparty C - Williston Basin - Gas | Accounts receivable | Credit concentration
CONCENTRATIONS OF RISK
Concentration risk, percentage	13.00%
Counterparty D - Marcellus Shale | Revenue | Customer concentration
CONCENTRATIONS OF RISK
Concentration risk, percentage			0.00%
Counterparty E - Piceance Basin | Revenue | Customer concentration
CONCENTRATIONS OF RISK
Concentration risk, percentage			0.00%
Counterparty F - Barnett Shale | Revenue | Customer concentration
CONCENTRATIONS OF RISK
Concentration risk, percentage			14.00%

RELATED-PARTY TRANSACTIONS (Det

RELATED-PARTY TRANSACTIONS (Details) - USD ($)	1 Months Ended		12 Months Ended
	Jul. 31, 2012	May. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Oct. 27, 2011
RELATED-PARTY TRANSACTIONS
Interest paid in kind			$ 0	$ 0	$ 5,426,000
General partner | Operation and maintenance expense allocation [Member]
RELATED-PARTY TRANSACTIONS
General and administrative expense allocation			19,782,000	14,323,000	2,913,000
General partner | General and administrative expense allocation [Member]
RELATED-PARTY TRANSACTIONS
General and administrative expense allocation			22,370,000	18,662,000	3,661,000
Equipower
RELATED-PARTY TRANSACTIONS
Payments for service agreements with related party			234,000	199,000	204,000
IPS Engineering/EPC
RELATED-PARTY TRANSACTIONS
Payments for service agreements with related party			$ 600,000	$ 200,000
Sponsors
RELATED-PARTY TRANSACTIONS
Transaction expenses receivable						$ 1,300,000
Reimbursements received for transaction expenses					300,000
Write-off of transaction expense receivable					1,000,000
Promissory Notes | Sponsors
RELATED-PARTY TRANSACTIONS
Principal amount of debt							$ 200,000,000
Stated interest rate							8.00%
Prepayments of notes	$ 49,200,000	$ 160,000,000
Interest paid in kind					6,300,000
Interest expense capitalized					$ 900,000
Revolving credit facility
RELATED-PARTY TRANSACTIONS
Amounts borrowed under revolving credit facility	$ 50,000,000	$ 163,000,000

BENEFIT PLAN (Details)

BENEFIT PLAN (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Compensation and Retirement Disclosure [Abstract]
Defined contribution benefit plan expense	$ 0.9	$ 0.6	$ 0.2

COMMITMENTS AND CONTINGENCIES71

COMMITMENTS AND CONTINGENCIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commitments and Contingencies Disclosure [Abstract]
Total rent expense related to operating leases	$ 1,786	$ 1,495	$ 732

ACQUISITONS - Polar Divide Drop

ACQUISITONS - Polar Divide Drop Down (Details) - Investment, Name [Domain] - Entity [Domain] - USD ($) $ in Thousands	May. 18, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 15, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Goodwill		$ 265,062	$ 319,261		$ 45,478
Polar Midstream
Business Acquisition [Line Items]
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
Subsequent Event | Polar Midstream and Epping
Business Acquisition [Line Items]
Total consideration	$ 290,000
Borrowings incurred for acquisition	92,500
Subsequent Event | Common units | Polar Midstream and Epping
Business Acquisition [Line Items]
Cost of acquired entity, equity interests issued and issuable	193,400
Subsequent Event | General Partner Units | Polar Midstream and Epping
Business Acquisition [Line Items]
Cost of acquired entity, equity interests issued and issuable	$ 4,100

ACQUISITIONS - Red Rock Gatheri

ACQUISITIONS - Red Rock Gathering (Details) - USD ($) $ in Thousands	Mar. 18, 2014	Oct. 23, 2012	Jul. 31, 2012	May. 31, 2012	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Purchase accounting adjustments						$ 1,185	$ 0	$ 0
Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Cost of acquired entity, cash paid	$ 305,000
Borrowings incurred for acquisition	2,900
Cost of acquired entity, purchase price	307,941
Purchase accounting adjustments					$ 1,200
Summit Investments | Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Cost of acquired entity, purchase price		$ 206,694
Cash		1,097
Accounts receivable		8,018
Other assets		317
Property, plant, and equipment		150,401
Rights-of-way		52,197
Other noncurrent assets		164
Total assets acquired		212,194
Trade accounts payable		2,558
Other current liabilities		2,942
Total liabilities assumed		5,500
Net identifiable assets acquired		$ 206,694
Rights-of-way
Business Acquisition [Line Items]
Useful lives						24 years 8 months	24 years 8 months
Rights-of-way | Summit Investments | Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Useful lives						20 years
Revolving credit facility
Business Acquisition [Line Items]
Amounts borrowed under revolving credit facility			$ 50,000	$ 163,000
Revolving credit facility | Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Amounts borrowed under revolving credit facility	$ 100,000

ACQUISITIONS - Lonestar Assets

ACQUISITIONS - Lonestar Assets (Details) - Sep. 30, 2014 - Barnett Shale Play [Member] $ in Millions	USD ($)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 - Bison Midstream

ACQUISITIONS - Bison Midstream (Details) - USD ($) $ in Thousands	Jun. 04, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 15, 2013
Business Acquisition [Line Items]
Purchase price assigned to Bison Gas Gathering system				$ 206,694
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Goodwill		$ 265,062	$ 319,261	45,478
SMP Holdings' equity in Bison Midstream
Business Acquisition [Line Items]
Purchase price assigned to Bison Gas Gathering system				$ 206,694
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
Business Acquisition [Line Items]
Cost of acquired entity, purchase price	$ 248,914
Cost of acquired entity, cash paid	200,000
Purchase price assigned to Bison Gas Gathering system			303,168
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
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 | Limited partners, Common
Business Acquisition [Line Items]
Cost of acquired entity, equity interests issued and issuable	47,900
Bison Midstream | General Partner Units
Business Acquisition [Line Items]
Cost of acquired entity, equity interests issued and issuable	1,000
Bison Midstream | SMP Holdings' equity in Bison Midstream
Business Acquisition [Line Items]
Cost of acquired entity, cash paid	200,000
Purchase price assigned to Bison Gas Gathering system	$ 303,200		$ 303,168
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 - Mountaineer Mids

ACQUISITIONS - Mountaineer Midstream and Grant River Gathering (Details) $ in Thousands	Jun. 21, 2013USD ($)compressor_station	Dec. 31, 2014USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)
Business Acquisition [Line Items]
Impact of purchase price adjustments			$ 1,185	$ 0	$ 0
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Goodwill		$ 265,062	$ 265,062	$ 319,261	$ 45,478
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
Cost of acquired entity, cash paid	$ 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
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Purchase price	210,000
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
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Intangible assets	24,019
Mountaineer Midstream | Rights-of-way
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Intangible assets	$ 6,109
Grand River Gathering, LLC
Business Acquisition [Line Items]
Impact of purchase price adjustments		$ 1,200
Weighted Average | Mountaineer Midstream
Business Acquisition [Line Items]
Useful lives	13 years
Scenario, Previously Reported | Mountaineer Midstream
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Property, plant, and equipment	$ 158,300
Goodwill	18,100
Scenario, Previously Reported | Mountaineer Midstream | Contract intangibles
Business Acquisition [Line Items]
Purchase price assigned, intangibles assets	27,100
Scenario, Previously Reported | Mountaineer Midstream | Rights-of-way
Business Acquisition [Line Items]
Purchase price assigned, intangibles assets	$ 6,500

ACQUISITIONS - Revenue and Net

ACQUISITIONS - Revenue and Net Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Revenues	$ 102,986	$ 84,784	$ 85,984	$ 79,381	$ 85,599	$ 77,353	$ 71,847	$ 62,014	$ 353,135	$ 296,813	$ 174,423
Net (loss) income									(14,734)	52,837	42,997
Summit Midstream Partners, LP
Business Acquisition [Line Items]
Revenues									319,373	225,192	165,499
Net (loss) income									(23,992)	43,584	41,726
Polar Midstream and Epping
Business Acquisition [Line Items]
Revenues									22,449	3,893
Net (loss) income									6,430	(467)
Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Revenues									11,313	50,114	8,924
Net (loss) income									$ 2,828	9,668	$ 1,271
Bison Midstream, LLC
Business Acquisition [Line Items]
Revenues										17,614
Net (loss) income										$ 52

ACQUISITIONS - Pro Forma (Detai

ACQUISITIONS - Pro Forma (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 03, 2012	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Revenues				$ 102,986	$ 84,784	$ 85,984	$ 79,381	$ 85,599	$ 77,353	$ 71,847	$ 62,014	$ 353,135	$ 296,813	$ 174,423
Net (loss) income												(14,734)	52,837	42,997
Pro forma total revenues												353,135	308,964	256,637
Pro forma net (loss) income												$ (14,508)	$ 46,904	$ 38,639
Limited partners, Common
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Pro forma EPU, basic and diluted (in dollars per share)												$ (0.30)	$ 0.78	$ 0.28
Subordinated units
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Pro forma EPU, basic and diluted (in dollars per share)												$ (0.30)	$ 0.78	$ 0.28
Red Rock Gathering Company, LLC
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Incremental borrowings on revolving credit facility												$ 100,000	$ 100,000	$ 100,000
Common unit issuance												5,300,000	5,300,000	5,300,000
Bison Midstream and Mountaineer Midstream
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Incremental borrowings on revolving credit facility													$ 310,000	$ 310,000
Common unit issuance												4,661,547	4,661,547	4,661,547
Polar Midstream and Epping
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Revenues												$ 22,449	$ 3,893
Net (loss) income												6,430	(467)
Red Rock Gathering Company, LLC
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Revenues												11,313	50,114	$ 8,924
Net (loss) income												2,828	9,668	1,271
Red Rock Gathering Company, LLC | Red Rock Gathering Company, LLC
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Revenues												73,266	50,114	8,924
Net (loss) income												27,447	9,668	1,271
Bison Midstream and Mountaineer Midstream | Bison Midstream and Mountaineer Midstream
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Revenues													60,323
Net (loss) income													(457)
Acquisition-related Costs | Red Rock Gathering Company, LLC
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Nonrecurring transaction cost												$ 700		$ 1,600
Acquisition-related Costs | Bison Midstream and Mountaineer Midstream
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%	2.00%
Net (loss) income												$ 3,125	$ 1,035	$ 352

UNAUDITED QUARTERLY FINANCIAL79

UNAUDITED QUARTERLY FINANCIAL DATA (Details) - USD ($)	3 Months Ended								9 Months Ended	12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Limited Partners' Capital Account [Line Items]
Revenues	$ 102,986,000	$ 84,784,000	$ 85,984,000	$ 79,381,000	$ 85,599,000	$ 77,353,000	$ 71,847,000	$ 62,014,000		$ 353,135,000	$ 296,813,000	$ 174,423,000
Net (loss) income attributable to SMLP	(37,686,000)	6,113,000	4,036,000	3,545,000	16,345,000	6,691,000	8,068,000	12,480,000		(23,992,000)	43,584,000	17,614,000
Less: net (loss) income attributable to general partner, including IDRs	689,000	1,204,000	801,000	431,000	490,000	134,000	161,000	250,000		3,125,000	1,035,000	352,000
Net (loss) income attributable to limited partners	(38,375,000)	$ 4,909,000	$ 3,235,000	$ 3,114,000	$ 15,855,000	$ 6,557,000	$ 7,907,000	$ 12,230,000		(27,117,000)	42,549,000	17,262,000
(Loss) earnings per limited partner unit:
Goodwill impairment	54,200,000								$ 0	54,199,000	0	0
Long-lived asset impairment	$ 5,500,000									5,505,000	0	0
Common units
Limited Partners' Capital Account [Line Items]
Net (loss) income attributable to limited partners										$ (16,324,000)	$ 23,227,000	$ 8,632,000
(Loss) earnings per limited partner unit:
Basic (in dollars per share)	$ (0.65)	$ 0.08	$ 0.05	$ 0.08	$ 0.30	$ 0.12	$ 0.16	$ 0.25		$ (0.49)	$ 0.86	$ 0.35
Diluted (in dollars per share)	(0.65)	0.08	0.05	0.08	0.29	0.12	0.16	0.25		$ (0.49)	$ 0.86	$ 0.35
Subordinated units
Limited Partners' Capital Account [Line Items]
Net (loss) income attributable to limited partners										$ (10,793,000)	$ 19,322,000	$ 8,630,000
(Loss) earnings per limited partner unit:
Basic (in dollars per share)	(0.65)	0.08	0.05	0.02	0.30	0.12	0.16	0.25		$ (0.44)	$ 0.79	$ 0.35
Diluted (in dollars per share)	$ (0.65)	$ 0.08	$ 0.05	$ 0.02	$ 0.30	$ 0.12	$ 0.16	$ 0.25		$ (0.44)	$ 0.79	$ 0.35
Scenario, Previously Reported
Limited Partners' Capital Account [Line Items]
Revenues	$ 94,658,000	$ 79,030,000	$ 80,796,000	$ 76,202,000	$ 69,299,000	$ 63,096,000	$ 59,285,000	$ 43,595,000
Polar Midstream and Epping | Adjustment
Limited Partners' Capital Account [Line Items]
Revenues	$ 8,328,000	$ 5,754,000	$ 5,188,000	$ 3,179,000	2,143,000	1,334,000	386,000	30,000
Red Rock Gathering Company, LLC | Adjustment
Limited Partners' Capital Account [Line Items]
Revenues					14,157,000	12,923,000	12,176,000	10,858,000
Bison Midstream | Adjustment
Limited Partners' Capital Account [Line Items]
Revenues					$ 0	$ 0	$ 0	$ 7,531,000