Edgar Filing: Summit Midstream Partners, LP

SMLP-6.14-10Q

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

(Mark One)

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2014

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-35666

Summit Midstream Partners, LP
(Exact name of registrant as specified in its charter)



Delaware (State or other jurisdiction of incorporation or organization)		45-5200503 (I.R.S. Employer Identification No.)

2100 McKinney Avenue, Suite 1250 Dallas, Texas (Address of principal executive offices)		75201 (Zip Code)

(214) 242-1955 (Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

x Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer o			Accelerated filer x
Non-accelerated filer o (Do not check if a smaller reporting company)			Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.



Class		As of July 31, 2014
Common Units		34,423,369 units
Subordinated Units		24,409,850 units
General Partner Units		1,200,651 units

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PART I	FINANCIAL INFORMATION	1
Item 1.	Financial Statements.	1
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	1
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013	2
	Unaudited Condensed Consolidated Statements of Partners' Capital for the six months ended June 30, 2014 and 2013	3
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013	4
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	23
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	39
Item 4.	Controls and Procedures.	40

PART II	OTHER INFORMATION	41
Item 1.	Legal Proceedings.	41
Item 1A.	Risk Factors.	41
Item 6.	Exhibits.	41

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FORWARD-LOOKING STATEMENTS

Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officials during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries, are also forward-looking statements. These forward-looking statements involve external risks and uncertainties, including, but not limited to, those described under the section entitled “Risk Factors” included herein.

Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this paragraph. These risks and uncertainties include, among others:


•	changes in general economic conditions;


•	fluctuations in crude oil, natural gas and natural gas liquids prices;


•	the extent and success of drilling efforts, as well as the extent and quality of natural gas volumes produced within proximity of our assets;


•	failure or delays by our customers in achieving expected production in their natural gas and crude oil projects;


•	competitive conditions in our industry and their impact on our ability to connect natural gas supplies to our gathering and processing assets or systems;


•	actions or inactions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements;


•	our ability to consummate acquisitions, successfully integrate the acquired businesses, realize any cost savings and other synergies from any acquisition;


•	the ability to attract and retain key management personnel;


•	commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets;


•	changes in the availability and cost of capital, and the results of our financing efforts, including availability of funds in the credit and/or capital markets;


•	restrictions placed on us by the agreements governing our debt instruments;


•	the availability, terms and cost of downstream transportation and processing services;


•	operating hazards, natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control;


•	weather conditions and seasonal trends;


•	timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule;


•	the effects of existing and future laws and governmental regulations, including environmental and climate change requirements;


•	the effects of litigation; and


•	certain factors discussed elsewhere in this report.

Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of our common units and senior notes.

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The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this document may not in fact occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.

iii

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS



	June 30,		December 31,
	2014		2013
	(Dollars in thousands)
Assets
Current assets:
Cash and cash equivalents	$	23,430	$	20,357
Accounts receivable	53,345		67,877
Other assets	2,044		4,741
Total current assets	78,819		92,975
Property, plant and equipment, net	1,198,727		1,158,081
Intangible assets, net:
Favorable gas gathering contracts	17,010		17,880
Contract intangibles	367,146		383,306
Rights-of-way	101,923		100,991
Total intangible assets, net	486,079		502,177
Goodwill	115,888		115,888
Other noncurrent assets	13,621		14,618
Total assets	$	1,893,134	$	1,883,739

Liabilities and Partners' Capital
Current liabilities:
Trade accounts payable	$	29,670	$	25,117
Due to affiliate	1,578		653
Deferred revenue	2,609		1,555
Ad valorem taxes payable	6,883		8,375
Accrued interest	11,250		12,144
Other current liabilities	9,943		11,729
Total current liabilities	61,933		59,573
Long-term debt	726,000		586,000
Noncurrent liability, net (Note 4)	5,955		6,374
Deferred revenue	37,093		29,683
Other noncurrent liabilities	1,597		372
Total liabilities	832,578		682,002
Commitments and contingencies (Note 11)
Common limited partner capital (34,423,369 units issued and outstanding at June 30, 2014 and 29,079,866 units issued and outstanding at December 31, 2013)	702,298		566,532
Subordinated limited partner capital (24,409,850 units issued and outstanding at June 30, 2014 and December 31, 2013)	332,389		379,287
General partner interests (1,200,651 units issued and outstanding at June 30, 2014 and 1,091,453 issued and outstanding at December 31, 2013)	25,869		23,324
Summit Investments' equity in contributed subsidiaries	—		232,594
Total partners' capital	1,060,556		1,201,737
Total liabilities and partners' capital	$	1,893,134	$	1,883,739

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS



	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
	(In thousands, except per-unit and unit amounts)
Revenues:
Gathering services and other fees	$	54,831		$	47,914		$	104,903		$	93,888
Natural gas, NGLs and condensate sales and other	26,190			23,797			52,546			40,088
Amortization of favorable and unfavorable contracts	(225		)	(250		)	(451		)	(530		)
Total revenues	80,796			71,461			156,998			133,446
Costs and expenses:
Cost of natural gas and NGLs	16,378			13,438			31,660			21,403
Operation and maintenance	19,859			18,371			39,040			35,950
General and administrative	8,690			8,406			16,576			14,973
Transaction costs	76			2,435			612			2,473
Depreciation and amortization	20,480			16,801			40,122			30,714
Total costs and expenses	65,483			59,451			128,010			105,513
Other (expense) income	(5		)	1			(4		)	2
Interest expense	(10,803		)	(3,023		)	(17,947		)	(4,903		)
Income before income taxes	4,505			8,988			11,037			23,032
Income tax expense	(469		)	(221		)	(628		)	(402		)
Net income	$	4,036		$	8,767		$	10,409		$	22,630
Less: net income attributable to Summit Investments (Note 1)	—			699			2,828			2,082
Net income attributable to SMLP	4,036			8,068			7,581			20,548
Less: net income attributable to general partner, including IDRs	801			161			1,232			411
Net income attributable to limited partners	$	3,235		$	7,907		$	6,349		$	20,137

Earnings per limited partner unit (Note 7):
Common unit – basic	$	0.05		$	0.16		$	0.14		$	0.41
Common unit – diluted	$	0.05		$	0.16		$	0.14		$	0.41
Subordinated unit – basic and diluted	$	0.05		$	0.16		$	0.08		$	0.41

Weighted-average limited partner units outstanding (Note 7):
Common units – basic	34,422,273			25,172,087			32,179,431			24,790,158
Common units – diluted	34,618,506			25,281,104			32,360,022			24,871,033
Subordinated units – basic and diluted	24,409,850			24,409,850			24,409,850			24,409,850

Cash distributions declared and paid per common unit	$	0.50		$	0.42		$	0.98		$	0.83

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL



	Partners' capital									Summit Investments' equity in contributed subsidiaries
	Limited partners						General partner
	Common			Subordinated			General partner						Total
	(In thousands)
Partners' capital, January 1, 2013	$	418,856		$	380,169		$	20,222		$	211,001		$	1,030,248
Net income	10,127			10,010			411			2,082			22,630
SMLP LTIP unit-based compensation	1,141			—			—			—			1,141
Distributions to unitholders	(20,262		)	(20,260		)	(826		)	—			(41,348		)
Consolidation of Bison Midstream net assets	—			—			—			303,168			303,168
Contribution from Summit Investments to Bison Midstream	—			—			—			2,229			2,229
Purchase of Bison Midstream	47,936			—			978			(248,914		)	(200,000		)
Contribution of net assets from Summit Investments in excess of consideration paid for Bison Midstream	28,558			26,846			1,131			(56,535		)	—
Issuance of units in connection with the Mountaineer Acquisition	98,000			—			2,000			—			100,000
Cash advance to Summit Investments from contributed subsidiaries, net	—			—			—			(2,243		)	(2,243		)
Expenses paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			4,762			4,762
Capitalized interest allocated to Red Rock Gathering projects from Summit Investments	—			—			—			109			109
Class B membership interest unit-based compensation	17			—			—			244			261
Repurchase of DFW Net Profits Interests	(5,859		)	(5,859		)	(239		)	—			(11,957		)
Partners' capital, June 30, 2013	$	578,514		$	390,906		$	23,677		$	215,903		$	1,209,000

Partners' capital, January 1, 2014	$	566,532		$	379,287		$	23,324		$	232,594		$	1,201,737
Net income	3,634			2,715			1,232			2,828			10,409
SMLP LTIP unit-based compensation	2,424			—			—			—			2,424
Tax withholdings on vested SMLP LTIP awards	(656		)	—			—			—			(656		)
Issuance of common units, net of offering costs	197,989			—			—			—			197,989
Contribution from general partner	—			—			4,235			—			4,235
Purchase of Red Rock Gathering	—			—			—			(305,000		)	(305,000		)
Excess of purchase price over acquired carrying value of Red Rock Gathering	(36,228		)	(25,691		)	(1,264		)	63,183			—
Cash advance from Summit Investments to contributed subsidiaries	—			—			—			1,982			1,982
Expenses paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			4,413			4,413
Repurchase of SMLP LTIP units	(228		)	—			—			—			(228		)
Distributions to unitholders	(31,169		)	(23,922		)	(1,658		)	—			(56,749		)
Partners' capital, June 30, 2014	$	702,298		$	332,389		$	25,869		$	—		$	1,060,556

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Six months ended June 30,
	2014			2013
	(In thousands)
Cash flows from operating activities:
Net income	$	10,409		$	22,630
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	40,573			31,244
Amortization of deferred loan costs	1,220			882
Unit-based compensation	2,424			1,402
Loss on asset sales	6			—
Changes in operating assets and liabilities:
Accounts receivable	14,532			(434		)
Due to affiliate	925			2,674
Trade accounts payable	2,319			2,525
Change in deferred revenue	8,464			5,695
Ad valorem taxes payable	(1,492		)	(2,200		)
Accrued interest	(894		)	(16		)
Other, net	2,213			5,070
Net cash provided by operating activities	80,699			69,472

Cash flows from investing activities:
Capital expenditures	(63,336		)	(49,642		)
Proceeds from asset sales	24			—
Acquisition of gathering system from third party	—			(210,000		)
Acquisition of gathering system from affiliate	(305,000		)	(200,000		)
Net cash used in investing activities	(368,312		)	(459,642		)

Cash flows from financing activities:
Distributions to unitholders	(56,749		)	(41,348		)
Borrowings under revolving credit facility	160,000			360,000
Repayments under revolving credit facility	(20,000		)	(294,180		)
Deferred loan costs	(300		)	(7,333		)
Tax withholdings on vested SMLP LTIP awards	(656		)	—
Proceeds from issuance of common units, net	197,989			—
Contribution from general partner	4,235			—
Cash advance from (to) Summit Investments to (from) contributed subsidiaries, net	1,982			(11		)
Expenses paid by Summit Investments on behalf of contributed subsidiaries	4,413			5,117
Issuance of 7.5% senior notes	—			300,000
Issuance of units to affiliate in connection with the Mountaineer Acquisition	—			100,000
Repurchase of equity-based compensation awards	(228		)	(11,957		)
Net cash provided by financing activities	290,686			410,288
Net change in cash and cash equivalents	3,073			20,118
Cash and cash equivalents, beginning of period	20,357			11,334
Cash and cash equivalents, end of period	$	23,430		$	31,452

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)



	Six months ended June 30,
	2014		2013
	(In thousands)
Supplemental Cash Flow Disclosures:
Cash interest paid	$	17,153	$	4,014
Less: capitalized interest	3,688		1,559
Interest paid (net of capitalized interest)	$	13,465	$	2,455

Cash paid for taxes	$	—	$	660

Noncash Investing and Financing Activities:
Capital expenditures in trade accounts payable (period-end accruals)	$	18,703	$	6,680
Excess of purchase price over acquired carrying value of Red Rock Gathering	63,183		—
Issuance of units to affiliate to partially fund the Bison Drop Down	—		48,914
Contribution of net assets from Summit Investments in excess of consideration paid for Bison Midstream	—		56,535

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION, BUSINESS OPERATIONS AND BASIS OF PRESENTATION

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").

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 deemed 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 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 Company, LLC ("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. On March 18, 2014, SMLP acquired all of the membership interests of Red Rock Gathering from a subsidiary of Summit Investments (the "Red Rock Drop Down"). Concurrent with the closing of the Red Rock Drop Down, SMLP contributed its interest in Red Rock Gathering to Grand River Gathering. For additional information, see Notes 6 and 12.

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"). On June 17, 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 2011 until June 17, 2014, and we refer to Energy Capital Partners as our sole "Sponsor" subsequent to June 17, 2014. As of June 30, 2014, Summit Investments, through a wholly owned subsidiary, held 9,641,397 SMLP common units, 24,409,850 SMLP subordinated units and 1,200,651 general partner units representing a 2% general partner interest in SMLP.

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 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 affiliates, but these individuals are sometimes referred to as our employees.

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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.

Business Operations. We provide natural gas gathering, treating and processing services pursuant to primarily long-term and fee-based, natural gas gathering agreements with our customers. Our results are driven primarily by the volumes of natural gas that we gather, treat and process across our systems. Our gathering and processing systems and the unconventional resource basins in which they operate as of June 30, 2014 were as follows:


•	Mountaineer Midstream – the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia;


•	Bison Midstream – the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;


•	DFW Midstream – the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and


•	Grand River Gathering – the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah.

Our operating subsidiaries are DFW Midstream (which includes the Mountaineer Midstream gathering system), Bison Midstream and Grand River Gathering. All of our operating subsidiaries are midstream energy companies focused on the development, construction and operation of natural gas gathering and processing systems.

Basis of Presentation and Principles of Consolidation. We prepare our unaudited condensed 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.

These unaudited condensed consolidated financial statements reflect the results of operations of: (i) Red Rock Gathering for all periods presented, (ii) Bison Midstream since February 16, 2013, and (iii) Mountaineer Midstream since June 22, 2013. SMLP recognized its acquisitions of Red Rock Gathering and Bison Midstream at Summit Investments' historical cost because the acquisitions were executed by entities under common control. 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. The excess of Summit Investments' net investment in Bison Midstream over the purchase price paid by SMLP was recognized as an addition to partners' capital. Due to the common control aspect, the Red Rock 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 unaudited condensed consolidated financial statements include the assets, liabilities, and results of operations of SMLP and its respective wholly owned subsidiaries. All intercompany transactions among the consolidated entities have been eliminated in consolidation.

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and the regulations of the Securities and Exchange Commission (the "SEC"). Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations, although the Partnership believes that the disclosures made are adequate to make the information not misleading. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto that are included in our annual report on Form 10-K for the year ended December 31, 2013, as updated and superseded by our current report on Form 8-K dated July 3, 2014 (the "2013 Annual Report"). The results of operations for an interim period are not necessarily indicative of results expected for a full year.

We conduct our operations in the midstream sector with four operating segments: Mountaineer Midstream, Bison Midstream, DFW Midstream and Grand River Gathering. However, due to their similar characteristics and how we manage our business, we have aggregated these segments into one reportable segment for disclosure purposes. The assets of our reportable segment consist of natural gas gathering and processing systems and related plant and equipment. Our operating 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 additional information, see Note 1 to the audited consolidated financial statements included in the 2013 Annual Report.

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2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Other Assets. Other assets primarily consist of prepaid expenses that are charged to expense over the period of benefit or the life of the related contract.

Fair Value of Financial Instruments. 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 for financial instruments follows.



	June 30, 2014				December 31, 2013
	Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)
	(In thousands)
Revolving credit facility	$	426,000	$	426,000	$	286,000	$	286,000
7.5% Senior notes	300,000		326,500		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 June 30, 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.

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 natural gas gathering, treating and processing services that we provide to our natural gas producer customers. We also generate revenue from our marketing of natural gas and natural gas liquids ("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 other 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 and other 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 and other; 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.

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 obtain access to natural gas and provide 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

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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.

Certain of our natural gas gathering or processing agreements provide for a monthly, quarterly or annual minimum volume commitment ("MVC") from certain of our customers. 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 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 current for arrangements where the expiration of a customer's right to utilize shortfall payments is twelve months or less. A rollforward of current and noncurrent deferred revenue follows.



	Six months ended June 30, 2014
	Current		Noncurrent
	(In thousands)
Deferred revenue, beginning of period	$	1,555	$	29,683
Additions	2,609		7,410
Less: revenue recognized due to expiration	1,555		—
Deferred revenue, end of period	$	2,609	$	37,093

As of June 30, 2014, accounts receivable included $4.8 million of shortfall billings related to MVC arrangements that can be utilized to offset gathering fees in subsequent periods. Noncurrent deferred revenue at June 30, 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.

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.

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 June 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, current income tax expense for the three and six months ended June 30, 2014 was reduced and a deferred tax liability was recognized. The associated deferred tax liability of $1.2 million is included in other noncurrent liabilities at June 30, 2014.

Earnings Per Unit ("EPU"). We determine EPU by dividing the net income that is attributed, in accordance with the net income and loss allocation provisions of the partnership agreement, to the common and subordinated

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unitholders under the two-class method, after deducting the general partner's 2% interest in net income and any payments to the general partner in connection with their incentive distribution rights ("IDRs"), by the weighted-average number of common and subordinated units outstanding during the quarter-to-date and year-to-date periods in 2014 and 2013. Diluted earnings 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 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 liabilities reflected in the accompanying financial statements at June 30, 2014 or December 31, 2013. However, we can provide no assurances that significant costs and liabilities will not be incurred by the Partnership in the future. We are currently not aware of any material contingent liabilities that exist with respect to environmental matters.

Other Significant Accounting Policies. For information on our other significant accounting policies, see Note 2 of the audited consolidated financial statements included in the 2013 Annual Report.

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 Financial Accounting Standards Board released a joint revenue recognition standard, Accounting Standards Update No. 2014-09 ("ASC Update 2014-09"). Under ASC Update 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 partnership satisfies a performance obligation. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, and interim and annual periods thereafter. Early adoption is not permitted. We are currently in the process of evaluating the impact of this update.

3. PROPERTY, PLANT, AND EQUIPMENT, NET

Details on property, plant, and equipment, net were as follows:



	Useful lives (In years)	June 30,		December 31,
	Useful lives (In years)	2014		2013
	(Dollars in thousands)
Natural gas gathering and processing systems	30	$	810,617	$	744,359
Compressor stations and compression equipment	30	393,483		380,000
Construction in progress	n/a	63,419		83,765
Other	4-15	24,175		21,304
Total		1,291,694		1,229,428
Less: accumulated depreciation		92,967		71,347
Property, plant, and equipment, net		$	1,198,727	$	1,158,081

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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:



	Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013
	(In thousands)
Depreciation expense	$	11,104	$	8,508	$	21,625	$	16,325
Capitalized interest	2,329		1,066		3,688		1,559

4. IDENTIFIABLE INTANGIBLE ASSETS, NONCURRENT LIABILITY AND GOODWILL

Identifiable Intangible Assets and Noncurrent Liability. Identifiable intangible assets and the noncurrent liability, which are subject to amortization, were as follows:



	June 30, 2014
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
	(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(7,185	)	$	17,010
Contract intangibles	12.5	426,464		(59,318		)	367,146
Rights-of-way	24.2	111,975		(10,052		)	101,923
Total amortizable intangible assets		$	562,634	$	(76,555	)	$	486,079

Unfavorable gas gathering contract	10.0	$	10,962	$	(5,007	)	$	5,955



	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	24.3	108,706		(7,715		)	100,991
Total amortizable intangible assets		$	559,365	$	(57,188	)	$	502,177

Unfavorable gas gathering contract	10.0	$	10,962	$	(4,588	)	$	6,374

We recognized amortization expense in revenues as follows:



	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	(436	)	$	(527	)	$	(870	)	$	(1,099	)
Amortization expense – unfavorable gas gathering contract	211			277			419			569
Amortization of favorable and unfavorable contracts	$	(225	)	$	(250	)	$	(451	)	$	(530	)

We recognized amortization expense in costs and expenses as follows:



	Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013
	(In thousands)
Amortization expense – contract intangibles	$	8,198	$	7,421	$	16,160	$	12,709
Amortization expense – rights-of-way	1,178		872		2,337		1,680

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The estimated aggregate annual amortization of intangible assets and noncurrent liability expected to be recognized for the remainder of 2014 and each of the four succeeding fiscal years follows.



	Assets		Liability
	(In thousands)
2014	$	20,589	$	806
2015	43,872		1,650
2016	44,114		1,571
2017	42,846		1,438
2018	43,115		490

Goodwill. 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. There have been no impairments of goodwill.

5. LONG-TERM DEBT

Long-term debt consisted of the following:



	June 30,		December 31,
	2014		2013
	(In thousands)
Variable rate senior secured revolving credit facility (2.40% at June 30, 2014 and 2.42% at December 31, 2013) due November 2018	$	426,000	$	286,000
7.50% Senior unsecured notes due July 2021	300,000		300,000
Total long-term debt	$	726,000	$	586,000

Revolving Credit Facility. We have a variable rate senior secured revolving credit facility (the "revolving credit facility") which allows for revolving loans, letters of credit and swingline loans. The revolving credit facility 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 (other than Summit Midstream Finance Corp. ("Finance Corp.")).

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, as defined in the credit agreement. At June 30, 2014, the applicable margin under LIBOR borrowings was 2.25%, the interest rate was 2.40% and the unused portion of the revolving credit facility totaled $274.0 million (subject to a commitment fee of 0.375%).

As of June 30, 2014, we were in compliance with the covenants in the revolving credit facility. There were no defaults or events of default during the six months ended June 30, 2014.

Senior Notes. In June 2013, Summit Holdings and its 100% owned finance subsidiary, Finance Corp. (together with Summit Holdings, the "Co-Issuers"), co-issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021 (the "7.5% senior notes").

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.

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.

As of June 30, 2014, we were in compliance with the covenants for the 7.5% senior notes. There were no defaults or events of default during the six months ended June 30, 2014.

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On July 15, 2014, Summit Holdings and Finance Corp. co-issued $300.0 million of 5.50% senior unsecured notes maturing August 15, 2022 (the "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 August 15, 2020), plus accrued and unpaid interest, if any.

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 merger, consolidation, sale of assets, 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.

SMLP and all of its subsidiaries other than the Co-Issuers (the "Guarantors") have fully and unconditionally and jointly and severally guaranteed the 7.5% senior notes and the 5.5% 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 7.5% senior notes and the 5.5% 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 7.5% senior notes and the 5.5% 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.

6. PARTNERS' CAPITAL

Partners' Capital

In March 2014, we completed an underwritten public offering of 10,350,000 common units at a price of $38.75 per unit (the "March 2014 Equity Offering"), of which 5,300,000 common units were offered by the Partnership and 5,050,000 common units were offered by an affiliate of Summit Investments, pursuant to an effective shelf

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registration statement on Form S-3 previously filed with the SEC. Concurrent with the March 2014 Equity Offering, 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. See Notes 1 and 12 for additional information.

Rollforwards of the number of common limited partner, subordinated limited partner and general partner units for the six months ended June 30 follow.



	Common	Subordinated	General partner	Total
Units, January 1, 2013	24,412,427	24,409,850	996,320	49,818,597
Units issued to affiliates in connection with the Bison Drop Down	1,553,849	—	31,711	1,585,560
Units issued to affiliates in connection with the Mountaineer Acquisition	3,107,698	—	63,422	3,171,120
Units, June 30, 2013	29,073,974	24,409,850	1,091,453	54,575,277



	Common	Subordinated	General partner	Total
Units, January 1, 2014	29,079,866	24,409,850	1,091,453	54,581,169
Units issued in connection with the March Equity 2014 Offering (1)	5,300,000	—	108,337	5,408,337
Units issued under LTIP (1)(2)	43,503	—	861	44,364
Units, June 30, 2014	34,423,369	24,409,850	1,200,651	60,033,870

__________

(1) Including issuance to general partner in connection with contributions made to maintain 2% general partner interest.

(2) Units issued to common unitholders is net of 14,047 units withheld to meet minimum statutory tax withholding requirements.

Summit Investments' Equity in Contributed Subsidiaries. Summit Investments' equity in contributed subsidiaries represents its position in the net assets of Red Rock Gathering and Bison Midstream that have been acquired by SMLP. The balance also reflects net income attributable to Summit Investments for 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 three- and six-month periods ended June 30, 2014 and 2013, net income was attributed to Summit Investments for (i) Red Rock Gathering for the period from January 1, 2014 to March 18, 2014 and for the period from January 1, 2013 to June 30, 2013 and (ii) 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 additional information, see Notes 1, 7 and 12.

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 plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages for unpaid quarterly distributions or quarterly distributions less than the minimum quarterly distribution. If we do not pay the minimum quarterly distribution 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 minimum quarterly distribution 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) $1.60 (the minimum quarterly distribution 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 or (2) $2.40 (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the corresponding distributions on the general partner's 2.0% interest and the related distribution on the incentive distribution rights for the four-quarter period immediately preceding that date, in each case provided there are no arrearages on the common units at that time.

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Cash Distribution Policy

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 minimum quarterly distribution 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 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.

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	Total quarterly distribution per unit target amount	Marginal percentage interest in distributions
	Total quarterly distribution per unit target amount	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%

SMLP allocated its distribution in accordance with the third target distribution level for distributions attributable to the quarter ended June 30, 2014. 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 interest		Cash paid for IDRs		Total distribution
		(Dollars 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		608		360		30,384

On July 24, 2014, the board of directors of our general partner declared a distribution of $0.52 per unit for the quarterly period ended June 30, 2014. The distribution will be paid on August 14, 2014 to unitholders of record at the close of business on August 7, 2014.

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7. EARNINGS PER UNIT

The following table presents details on EPU.



	Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013
	(Dollars in thousands, except per-unit amounts)
Net income	$	4,036	$	8,767	$	10,409	$	22,630
Less: net income attributable to Summit Investments	—		699		2,828		2,082
Net income attributable to SMLP	4,036		8,068		7,581		20,548
Less: net income attributable to general partner, including IDRs	801		161		1,232		411
Net income attributable to limited partners	$	3,235	$	7,907	$	6,349	$	20,137

Numerator for basic and diluted EPU:
Allocation of net income among limited partner interests:
Net income attributable to common units	$	1,891	$	4,012	$	4,398	$	10,127
Net income attributable to subordinated units	1,344		3,895		1,951		10,010
Net income attributable to limited partners	$	3,235	$	7,907	$	6,349	$	20,137

Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic	34,422,273		25,172,087		32,179,431		24,790,158
Effect of non-vested phantom units and non-vested restricted units	196,233		109,017		180,591		80,875
Weighted-average common units outstanding – diluted	34,618,506		25,281,104		32,360,022		24,871,033

Weighted-average subordinated units outstanding – basic and diluted	24,409,850		24,409,850		24,409,850		24,409,850

Earnings per limited partner unit:
Common unit – basic	$	0.05	$	0.16	$	0.14	$	0.41
Common unit – diluted	$	0.05	$	0.16	$	0.14	$	0.41
Subordinated unit – basic and diluted	$	0.05	$	0.16	$	0.08	$	0.41

There were no units excluded from diluted earnings per unit as we do not have any anti-dilutive units for the three and six months ended June 30, 2014 or 2013. See Notes 6 and 8 for additional information.

8. UNIT-BASED COMPENSATION

Long-Term Incentive Plan. SMLP’s 2012 Long-Term Incentive Plan (the "LTIP") provides for the granting of unit-based awards, including common units, restricted units and phantom units 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 LTIP is administered by the compensation committee of our general partner. A total of 5.0 million common units was reserved for issuance pursuant to and in accordance with the LTIP. As of June 30, 2014, approximately 4.6 million common units remained available for future issuance.

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A rollfoward of phantom and restricted unit activity follows.



	Six months ended June 30, 2014
	Units		Weighted-average grant date fair value
Nonvested phantom and restricted units, beginning of period	283,682		$	23.41
Phantom units granted	136,867		$	42.32
Restricted units granted	—		$	—
Phantom and restricted units vested	(61,036	)	$	25.20
Phantom units forfeited	(10,760	)	$	25.85
Nonvested phantom and restricted units, end of period	348,753		$	30.44

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. 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.

As of June 30, 2014, the unrecognized unit-based compensation related to the LTIP was $6.9 million. Incremental unit-based compensation will be recorded over the remaining vesting period of approximately 2.7 years. Due to the limited and immaterial forfeiture history associated with the grants under the 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 LTIP was as follows:



	Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013
	(In thousands)
SMLP LTIP unit-based compensation	$	1,361	$	814	$	2,424	$	1,141

DFW Net Profits Interests. Class B membership interests in DFW Midstream (the "DFW Net Profits Interests") participated in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested DFW Net Profits Interests. The DFW Net Profits Interests were accounted for as compensatory awards. All grants vested ratably and provided for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying agreements). In April 2013, we repurchased all of the then-outstanding DFW Net Profits Interests from the five remaining holders. Upon the conclusion of these repurchase transactions, there were no remaining or outstanding DFW Net Profits Interests as of April 30, 2013.

9. 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 natural gas gathering, treating and processing services we provide to our customers. 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

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conditions. We monitor the creditworthiness of our counterparties and can require letters of credit for receivables from counterparties that are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.

Counterparties accounting for more than 10% of total revenues were as follows:



	Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013
Revenue:
Counterparty A	13	%	13	%	13	%	15	%
Counterparty B	10	%	14	%	10	%	17	%

__________

* Less than 10%

Counterparties accounting for more than 10% of total accounts receivable were as follows:



	June 30,		December 31,
	2014		2013
Accounts receivable:
Counterparty A	16	%	37	%
Counterparty B	10	%	11	%

__________

* Less than 10%

10. RELATED-PARTY TRANSACTIONS

Recent Acquisitions. See Notes 1, 5, 6 and 12 for disclosure of the Red Rock Drop Down and 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. In addition, we reimburse our general partner for compensation, travel and entertainment expenses for the directors serving on the board of directors of our general partner and the cost of director and officer liability insurance. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

The payables to our general partner for expenses that were paid on our behalf were as follows:



	June 30,		December 31,
	2014		2013
	(In thousands)
Due to affiliate	$	1,578	$	653

Expenses incurred by the general partner and reimbursed by us under our partnership agreement were as follows:



	Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013
	(In thousands)
Operation and maintenance expense	$	4,503	$	3,268	$	8,395	$	6,171
General and administrative expense	4,898		4,474		9,804		8,890

General and administrative expense includes $0.6 million of expenses allocated by the general partner for the three months ended June 30, 2013 and $1.8 million for the six months ended June 30, 2013.

Expense Allocations. During the period from January 1, 2014 to March 18, 2014 and the three and six months ended June 30, 2013, Summit Investments incurred interest expense which was related to capital projects at Red

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Rock Gathering. As such, the associated interest expense was allocated to Red Rock Gathering as a noncash contribution and capitalized into the basis of the asset.

Certain of Summit Investments’ current and former employees received Class B membership interests, classified as net profits interests, in Summit Investments (the “Net Profits Interests”). The Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested Net Profits Interests. The Net Profits Interests were accounted for as compensatory awards.

Summit Investments allocated a portion of the annual expense associated with the Net Profits Interests to Red Rock Gathering during the three and six months ended June 30, 2013. This amount is reflected in general and administrative expenses in the statement of operations.

Expenses Paid by Summit Investments on Behalf of Red Rock Gathering. Prior to the Red Rock Drop Down, Summit Investments incurred certain support expenses and capital expenditures on behalf of Red Rock Gathering during the six months ended June 30, 2014 and the three and six months ended June 30, 2013. These transactions were settled periodically through membership interests prior to the Red Rock Drop Down.

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:



	Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013
	(In thousands)
Payments for electricity management consulting services	$	72	$	54	$	126	$	109

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 $0.2 million for such services during the six months ended June 30, 2014.

11. COMMITMENTS AND CONTINGENCIES

Operating Leases. We lease various office space to support our operations and have determined that our leases are operating leases. Total rent expense related to operating leases, which is recognized in general and administrative expenses, was as follows:



	Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013
	(In thousands)
Total rent expense	$	460	$	347	$	814	$	607

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 would not individually or in the aggregate have a material adverse effect on its financial position or results of operations.

12. ACQUISITIONS

Red Rock Gathering System. On March 18, 2014, the Partnership acquired Red Rock Gathering from an affiliate of Summit Investments for total cash consideration of $305.0 million, subject to customary working capital adjustments. The acquisition of Red Rock Gathering was funded with the net proceeds from the March 2014 Equity Offering, 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. For additional information, see Notes 1, 5 and 6.

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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. For additional information, see Note 1.

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 recent 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 Summit Investments' acquisition of BTE.

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

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.

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.

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 an affiliate of Antero Resources Corp. 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 an affiliate of Summit Investments. For the three and six months ended June 30, 2013, SMLP recorded $0.4 million of revenue and $0.3 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

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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

See Notes 1, 5 and 6 for additional information.

Supplemental Disclosures – As-If Pooled Basis. As noted above, SMLP's acquisition of Red Rock Gathering and the Bison Gas Gathering system were transactions between commonly controlled entities which required that SMLP account for the acquisitions in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership, 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 for the three months ended June 30, 2013 and the six months ended June 30, 2014 and 2013, as presented in these unaudited condensed consolidated financial statements follow.



	Three months ended June 30, 2013			Six months ended June 30,
	Three months ended June 30, 2013			2014		2013
	(In thousands)
SMLP revenues	$	43,743		$	145,685	$	87,338
Red Rock Gathering revenues	12,176			11,313		23,035
Bison Gas Gathering system revenues (1)	15,542			—		23,073
Combined revenues	$	71,461		$	156,998	$	133,446

SMLP net income	$	8,068		$	7,581	$	20,548
Red Rock Gathering net income	1,234			2,828		2,030
Bison Gas Gathering system net income (1)	(535		)	—		52
Combined net income	$	8,767		$	10,409	$	22,630

__________

(1) Results are fully reflected in SMLP's results of operations for the three and six months ended June 30, 2014.

Unaudited Pro Forma Financial Information. The following unaudited pro forma financial information assumes that:


•	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.


•	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.


•	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.


•	Pro forma net income for the three and six months ended June 30, 2013 has been adjusted to remove the impact of $2.4 million of nonrecurring transaction costs associated with the acquisitions of Bison Midstream and Mountaineer Midstream.

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•

Pro forma adjustments in 2013 also reflect the impact of $310.0 million of incremental borrowings on our revolving credit facility for the Bison Midstream and Mountaineer Midstream acquisitions and incremental depreciation and amortization expense associated with the acquired property, plant and equipment and contract intangibles as a result of the application of fair value accounting for Bison Midstream.


•	Pro forma adjustments in 2014 and 2013 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.



	Three months ended June 30, 2013		Six months ended June 30,
	Three months ended June 30, 2013		2014		2013
	(In thousands, except for per-unit amounts)
Total Red Rock Gathering revenues included in consolidated revenues	$	12,176	$	34,589	$	23,034
Total Bison Midstream and Mountaineer Midstream revenues included in consolidated revenues	15,951				23,482

Total Red Rock Gathering net income included in consolidated net income	$	1,234	$	10,181	$	2,031
Total Bison Midstream and Mountaineer Midstream net income included in consolidated net income	54				641

Pro forma total revenues	$	74,480	$	156,998	$	145,596
Pro forma net income	9,805		9,905		18,110

Pro forma common EPU - basic and diluted	$	0.16	$	0.16	$	0.30
Pro forma subordinated EPU - basic and diluted	0.16		0.12		0.30

The unaudited pro forma financial information presented above is not necessarily indicative of (i) what our financial position or results of operations would have been if the acquisitions of Bison Midstream and Mountaineer Midstream had occurred on January 1, 2012 or 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.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

This Management’s Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") is intended to inform the reader about matters affecting the financial condition and results of operations of SMLP and its subsidiaries for the period since December 31, 2013. As a result, the following discussion should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included in this report and the MD&A and the audited consolidated financial statements and related notes that are included in our annual report on Form 10-K for the year ended December 31, 2013, as updated and superseded by our current report on Form 8-K dated July 3, 2014 (the "2013 Annual Report"). Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in Forward-Looking Statements on page ii of this quarterly report on Form 10-Q. Actual results may differ materially from those contained in any forward-looking statements.

Overview

We are 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. We gather, treat and process natural gas from both dry gas and liquids-rich regions. Dry gas regions contain natural gas reserves that are primarily composed of methane. Liquids-

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rich regions include natural gas reserves that contain natural gas liquids, or NGLs, in addition to methane. We currently operate natural gas gathering systems in four unconventional resource basins: (i) the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia; (ii) the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; (iii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and (iv) the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah. We believe that our gathering systems are well positioned to capture additional volumes from increased producer activity in these regions in the future.

Our results are driven primarily by the volumes of natural gas that we gather, treat and process across our systems. We contract with producers to gather natural gas from pad sites and central receipt points connected to our systems, which we then compress, dehydrate, treat and/or process for delivery to downstream pipelines for ultimate delivery to our and/or third-party processing plants and/or end users.

We generate the majority of our revenue from the natural gas gathering, treating and processing services that we provide to our natural gas producer customers under primarily long-term and fee-based natural gas gathering and processing agreements. Under these agreements, we are paid a fixed fee based on the volume of the natural gas we gather, treat and/or process. These agreements enhance the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk, with the exception of the natural gas that we retain in-kind and sell to offset the power costs we incur to operate our electric-drive compression assets on the DFW Midstream system. We also earn revenue from our marketing of natural gas and natural gas liquids and from the sale of physical natural gas purchased from our customers under percentage-of-proceeds and keep-whole arrangements, which can expose us to commodity price risk. We sell condensate retained from our gathering services at Grand River Gathering.

We have indirect exposure to changes in commodity prices in that persistent low commodity prices may cause our customers to delay drilling or temporarily shut in production, which would reduce the volumes of natural gas that we gather. If our customers delay drilling or temporarily shut-in production, our minimum volume commitments assure us that we will receive a certain amount of revenue from our customers.

Most of our gas gathering agreements are underpinned by areas of mutual interest and MVCs. Our areas of mutual interest cover over 1.4 million acres in the aggregate, have original terms up to 25 years, and provide that any natural gas produced from wells drilled by our customers within the areas of mutual interest will be shipped on our gathering systems. The MVCs, which totaled 4.0 Tcf at June 30, 2014 and average approximately 1,229 MMcf/d through 2018, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our minimum volume commitments have remaining terms that range from two to 12 years and, as of June 30, 2014, had a weighted-average remaining life of 10.1 years, assuming minimum throughput volumes for the remainder of the term.

Trends and Outlook

Our business has been, and we expect our future business to continue to be, affected by the following key trends:


•	Natural gas and crude oil supply and demand dynamics;


•	Growth in production from U.S. shale plays;


•	Interest rate environment; and


•	Rising operating costs and inflation.

Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. For additional information, see the Trends and Outlook section included in the 2013 Annual Report.

How We Evaluate Our Operations

We conduct our operations in the midstream sector through four operating segments. However, due to their similar characteristics and how we manage our business, we have aggregated these segments into a single reporting segment for disclosure purposes. Our management uses a variety of financial and operational metrics to analyze

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our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on a regular basis for consistency and trend analysis. These metrics include:


•	throughput volume;


•	operation and maintenance expenses;


•	EBITDA and adjusted EBITDA; and


•	distributable cash flow.

For additional information on how these metrics help us manage our business, see the How We Evaluate Our Operations section included in the 2013 Annual Report.

Results of Operations

Items Affecting the Comparability of Our Financial Results

Our historical results of operations may not be comparable to our future results of operations due in part to the Red Rock Drop Down, the Bison Drop Down and our June 2013 acquisition of Mountaineer Midstream. The unaudited condensed consolidated financial statements reflect the results of operations of: (i) Red Rock Gathering for all periods presented, (ii) Bison Midstream since February 16, 2013 and (iii) Mountaineer Midstream since June 22, 2013. In addition, we accounted for the Red Rock Drop Down and Bison Drop Down on an "as-if pooled" basis because the transactions were executed by entities under common control. As such, Red Rock Gathering's contribution to the Partnership's financial and operating results have been reflected in the financial and operating results of its parent, Grand River Gathering. For additional information, see Notes 1, 5, 6 and 12 to the unaudited condensed consolidated financial statements.

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The following table presents certain consolidated and other financial and operating data for the periods indicated.



	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
	(Dollars in thousands)
Revenues:
Gathering services and other fees	$	54,831		$	47,914		$	104,903		$	93,888
Natural gas, NGLs and condensate sales and other	26,190			23,797			52,546			40,088
Amortization of favorable and unfavorable contracts (1)	(225		)	(250		)	(451		)	(530		)
Total revenues	80,796			71,461			156,998			133,446

Costs and expenses:
Cost of natural gas and NGLs	16,378			13,438			31,660			21,403
Operation and maintenance	19,859			18,371			39,040			35,950
General and administrative	8,690			8,406			16,576			14,973
Transaction costs	76			2,435			612			2,473
Depreciation and amortization	20,480			16,801			40,122			30,714
Total costs and expenses	65,483			59,451			128,010			105,513
Other (expense) income	(5		)	1			(4		)	2
Interest expense	(10,803		)	(3,023		)	(17,947		)	(4,903		)
Income before income taxes	4,505			8,988			11,037			23,032
Income tax expense	(469		)	(221		)	(628		)	(402		)
Net income	$	4,036		$	8,767		$	10,409		$	22,630

Other Financial Data:
EBITDA (2)	$	36,012		$	29,061		$	69,555		$	59,177
Adjusted EBITDA (2)	47,956			36,750			94,575			73,623
Capital expenditures	23,236			21,345			63,336			49,642
Acquisitions of gathering systems (3)	—			458,914			305,000			458,914
Distributable cash flow (2)	34,670			27,879			68,403			60,239

Operating Data:
Miles of pipeline (end of period)	2,324			2,232			2,324			2,232
Aggregate average throughput (MMcf/d)	1,403			1,060			1,356			1,075

__________

(1) The amortization of favorable and unfavorable contracts relates to gas gathering agreements that were deemed to be above or below market at the acquisition of the DFW Midstream system. We amortize these contracts on a units-of-production basis over the life of the applicable contract. The life of the contract is the period over which the contract is expected to contribute directly or indirectly to our future cash flows.

(2) Includes transaction costs. These unusual and non-recurring expenses are settled in cash. See "Non-GAAP Financial Measures" below for additional information on EBITDA, adjusted EBITDA and distributable cash flow as well as their reconciliations to the most directly comparable GAAP financial measure.

(3) Reflects cash paid and value of units issued, if any, to fund acquisitions and/or drop downs. For additional information, see Note 12 to the unaudited condensed consolidated financial statements.

Revenues. For the three months ended June 30, 2014, total revenues increased $9.3 million, or 13%, largely as a result of growth at Red Rock Gathering and Mountaineer Midstream's contribution to gathering services and other fees, partially offset by declines in (i) gathering services and other fees and (ii) natural gas, NGLs and condensate sales and other on the DFW Midstream system. Total revenues for the three months ended June 30, 2014 included a $36.1 million contribution from Grand River Gathering (including a $20.2 million contribution from Red Rock Gathering), compared with a $27.4 million contribution in the prior-year period (including a $12.1 million contribution

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as a result of the Red Rock Drop Down). Total revenues for the three months ended June 30, 2014 included a $5.7 million contribution from Mountaineer Midstream, compared with $0.4 million in the prior-year period.

For the six months ended June 30, 2014, total revenues increased $23.6 million, or 18%, largely as a result of growth at Red Rock Gathering, Mountaineer Midstream's contribution to gathering services and other fees and Bison Midstream's contribution to natural gas, NGLs and condensate sales and other. These increases were partially offset by the previously mentioned revenue declines on the DFW Midstream system. Total revenues for the six months ended June 30, 2014 included a $67.1 million contribution from Grand River Gathering (including a $34.6 million contribution from Red Rock Gathering and as a result of the Red Rock Drop Down), compared with a $55.5 million contribution in the prior-year period (including a $23.0 million contribution as a result of the Red Rock Drop Down). Total revenues for the six months ended June 30, 2014 included an $11.0 million contribution from Mountaineer Midstream, compared with $0.4 million in the prior-year period. Total revenues for the six months ended June 30, 2014 included a $31.6 million contribution from Bison Midstream, compared with $23.1 million in the prior-year period.

Costs and Expenses. For the three months ended June 30, 2014, total costs and expenses increased $6.0 million, or 10%, primarily due to an increase in cost of natural gas and NGLs as a result of growth at Red Rock Gathering and an increase in depreciation and amortization primarily associated with the buildout of Grand River Gathering and Mountaineer Midstream. Total costs and expenses for the three months ended June 30, 2014 included a $28.2 million contribution from Grand River Gathering (including a $14.1 million contribution from Red Rock Gathering), compared with a $24.4 million contribution in the prior-year period (including a $10.9 million contribution as a result of the Red Rock Drop Down). Total costs and expenses for the three months ended June 30, 2014 included a $3.7 million contribution from Mountaineer Midstream, compared with $0.1 million in the prior-year period.

For the six months ended June 30, 2014, total costs and expenses increased $22.5 million, or 21%, primarily due to an increase in cost of natural gas and NGLs as a result of growth on the Bison Midstream and Red Rock Gathering systems and an increase in depreciation and amortization primarily associated with the buildout of Grand River Gathering and Mountaineer Midstream. Total costs and expenses for the six months ended June 30, 2014 included a $36.2 million contribution from Bison Midstream, compared with $22.7 million in the prior-year period. Total costs and expenses for the six months ended June 30, 2014 included a $51.9 million contribution from Grand River Gathering (including a $24.4 million contribution from Red Rock Gathering and as a result of the Red Rock Drop Down), compared with a $48.8 million contribution in the prior-year period (including a $21.0 million contribution as a result of the Red Rock Drop Down). Total costs and expenses for the six months ended June 30, 2014 included a $7.0 million contribution from Mountaineer Midstream, compared with $0.1 million in the prior-year period.

Volumes. Our revenues are primarily attributable to the volume of natural gas that we gather, treat and process and the rates we charge for those services. For the three months ended June 30, 2014, our aggregate throughput volumes increased to an average of 1,403 MMcf/d, compared with an average of 1,060 MMcf/d for the three months ended June 30, 2013. The increase in volume throughput largely reflects the contribution from Mountaineer Midstream and Grand River Gathering as a result of growth at Red Rock Gathering, partially offset by volume throughput declines on the DFW Midstream system.

For the six months ended June 30, 2014, our aggregate throughput volumes increased to an average of 1,356 MMcf/d, compared with an average of 1,075 MMcf/d for the six months ended June 30, 2013. The increase in volume throughput largely reflects the contribution from Mountaineer Midstream and Grand River Gathering as a result of growth at Red Rock Gathering, partially offset by volume throughput declines on the DFW Midstream system. Volume throughput on the DFW Midstream system benefited in the prior-year period due to the first quarter 2013 commissioning of an additional compressor which increased throughput capacity on the DFW Midstream system from 410 MMcf/d to 450 MMcf/d.

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System Overview. The following table provides information regarding our gathering systems as of June 30.



	Mountaineer Midstream		Bison Midstream		DFW Midstream		Grand River (1)
	2014	2013	2014	2013	2014	2013	2014	2013
Miles of pipeline	40	40	380	309	124	118	1,780	1,765
Total remaining MVC commitment (Bcf)	*	*	23	30	169	317	2,304	2,509
Average daily MVCs through 2018 (MMcf/d)	*	*	13	14	103	155	743	717
Weighted-average remaining contract life (years) (2)	*	*	6.1	6.9	5.7	6.7	10.7	11.5

__________

* Contract terms excluded for confidentiality purposes.

(1) Includes operating data for Red Rock Gathering as of June 30, 2013 as a result of the Red Rock Drop Down.

(2) Based on total remaining MVCs (total remaining MVCs multiplied by average rate).

Mountaineer Midstream. Volume throughput for the Mountaineer Midstream gas gathering system, which was acquired in late June 2013, increased throughout the first half of 2014 as a result of an active drilling program by our customer, Antero Resources Corp. ("Antero"). We are currently in the process of expanding throughput capacity to 1,050 MMcf/d to support Antero's current and future anticipated drilling activities. The incremental volumes that will be gathered as a result of this capacity expansion will be driven by higher pressure natural gas. Therefore, we expect to receive only gathering rates for these additional volumes. We believe that volume throughput will continue to grow on this system throughout the balance of 2014 as new Antero wells are connected by third parties upstream of our system and as processing capacity at MarkWest’s Sherwood Processing Complex increases from 600 MMcf/d currently to 1.4 Bcf/d by the third quarter of 2015.

Bison Midstream. Volume throughput on the Bison Midstream gas gathering system grew continuously during the second quarter of 2014 increasing from 14 MMcf/d in April to approximately 19 MMcf/d in June. The extreme winter weather and operational issues that negatively impacted volume throughput on Bison Midstream since the third quarter of 2013 were resolved in the second quarter of 2014. We expect volume growth to continue throughout the second half of 2014 as we continue to connect new pad sites and expand the system’s compression capacity. We currently have four compressor expansion projects underway on the Bison Midstream system including the construction of two new compressor stations to support producer activity.

DFW Midstream. DFW Midstream volume throughput declined during the three and six months ended June 30, 2014 primarily reflecting continued natural declines and lack of drilling activity by DFW Midstream's anchor customer, partially offset by the benefit of several customers bringing new wells on line early in the second quarter of 2014. For the six months ended June 30, 2014, volume throughput was impacted by multiple customers temporarily shutting-in several large pad sites to drill or complete new wells beginning in the third quarter of 2013 and continuing into the second quarter of 2014. While this activity is beneficial over the long term, it can create volume and cash flow volatility over the short term. Volume throughput in the first half of 2013 also benefited from the January 2013 commissioning of a compressor, which increased system throughput capacity from 410 MMcf/d to 450 MMcf/d. Given current drilling activity and producer plans in our service area, we believe that DFW Midstream volume throughput will continue to increase throughout the second half of 2014.

Grand River. Grand River system volume throughput during the three and six months ended June 30, 2014 reflects increases over the prior-year periods as a result of growth at Red Rock Gathering. Red Rock Gathering became part of our Grand River system in connection with the Red Rock Drop Down. Volume throughput from Red Rock Gathering was favorably impacted by new pad site connections for WPX Energy, Inc. and Ursa Resources Group II as well as the March 2014 start-up of a cryogenic processing plant servicing production from Black Hills Corporation. Volume throughput on the legacy Grand River system declined as a result of Encana Corp.'s temporary suspension of drilling activities in the Piceance Basin during 2014. Certain of our gas gathering agreements for the Grand River system include MVCs that increase in both rate and volume commitment over the next few years, and largely mitigate the financial impact associated with declining volumes from certain customers. As a result, lower volume throughput for the customers subject to these MVCs translated into larger MVC shortfall payments during 2014 and 2013.

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Overview of the Three Months Ended June 30, 2014 and 2013

The following table presents certain consolidated and other financial and operating data for the periods indicated.



	Three months ended June 30,						Percentage Change
	2014			2013			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and other fees	$	54,831		$	47,914		14	%
Natural gas, NGLs and condensate sales and other	26,190			23,797			10	%
Amortization of favorable and unfavorable contracts (1)	(225		)	(250		)	*
Total revenues	80,796			71,461			13	%
Costs and expenses:
Cost of natural gas and NGLs	19,859			18,371			8	%
Operation and maintenance	16,378			13,438			22	%
General and administrative	8,690			8,406			3	%
Transaction costs	76			2,435			(97	)%
Depreciation and amortization	20,480			16,801			22	%
Total costs and expenses	65,483			59,451			10	%
Other (expense) income	(5		)	1			*
Interest expense	(10,803		)	(3,023		)	*
Income before income taxes	4,505			8,988			(50	)%
Income tax expense	(469		)	(221		)	*
Net income	$	4,036		$	8,767		(54	)%

Other Financial Data:
EBITDA (2)	$	36,012		$	29,061		24	%
Adjusted EBITDA (2)	47,956			36,750			30	%
Capital expenditures	23,236			21,345			9	%
Acquisition capital expenditures (3)	—			458,914			*
Distributable cash flow (2)	34,670			27,879			24	%

Operating Data:
Aggregate average throughput (MMcf/d)	1,403			1,060			32	%

__________

* Not considered meaningful

(3) Reflects cash paid and value of units issued, if any, to fund acquisitions and/or drop downs. For additional information, see Note 12 to the unaudited condensed consolidated financial statements.

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Operating Data by System. Operating data by system for the three months ended June 30 follows.



	Mountaineer Midstream (1)		Bison Midstream				DFW Midstream				Grand River (2)
	2014	2013	2014		2013		2014		2013		2014		2013
Aggregate average throughput (MMcf/d)	366	12	15		17		350		395		672		636
Average fee per Mcf	*	*	$	3.71	$	4.04	$	0.62	$	0.61	$	0.40	$	0.33

__________

* Contract terms excluded for confidentiality purposes.

(1) Gathering system was acquired by SMLP on June 21, 2013. For the period of SMLP's ownership in 2013, average throughput was 120 MMcf/d.

(2) Includes contribution from Red Rock Gathering during the three months ended June 30, 2013 due to the common control aspect of the Red Rock Drop Down.

Gathering Services and Other Fees. Gathering services and other fees increased during the three months ended June 30, 2014, largely as a result of our acquisition of the Mountaineer Midstream system and growth on the Grand River system. The Grand River system increase was primarily driven by growth at Red Rock Gathering, which benefited from higher margin throughput volumes from certain customers. Additionally, certain of our gas gathering agreements include provisions which increased the gas gathering fee on our Grand River and Bison Midstream systems. These increases were partially offset by volume declines on the DFW Midstream and Bison Midstream systems.

Natural Gas, NGLs and Condensate Sales and Other. The increase in natural gas, NGLs and condensate sales and other for the three months ended June 30, 2014, was primarily a result of increases for Grand River, which benefited from growth at Red Rock Gathering, and Bison Midstream, partially offset by a decline at DFW Midstream.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs represents the expenses associated with the percent-of-proceeds and keep-whole arrangements under which the Bison Midstream and Grand River systems sell natural gas purchased from our customers. The increase for the three months ended June 30, 2014 is primarily a result of growth on the Grand River system in connection with growth at Red Rock Gathering.

Operation and Maintenance. Operation and maintenance expense increased during the three months ended June 30, 2014, largely as a result of expenses associated with a full quarter of operations at Mountaineer Midstream. The increase in consolidated operation and maintenance expense also reflects a $1.3 million increase in salaries, benefits and incentive compensation, a $0.4 million increase in chemicals primarily for the Bison Midstream and Grand River systems, and a $0.4 million increase in property tax expense largely as a result of the June 2013 acquisition of Mountaineer Midstream. These increases were partially offset by a $1.1 million decline in expenses associated with third-party treatment of volume throughput on the DFW Midstream system to prepare it for transportation on downstream pipelines. In the first quarter of 2014, DFW Midstream commissioned a natural gas treating facility which allowed the Partnership to provide treating services to its customers in lieu of using third-party facilities.

General and Administrative. General and administrative expense increased during the three months ended June 30, 2014, largely as a result of expenses associated with a full quarter of operations at Mountaineer Midstream. For the three months ended June 30, 2014, the increase in general and administrative expense was largely driven by salaries, benefits and incentive compensation at Mountaineer Midstream and an increase in professional services expense.

Transaction Costs. Transaction costs for the three months ended June 30, 2014, primarily related to financial and legal advisory costs associated with the Red Rock Drop Down. Transaction costs for the three months ended June 30, 2013, primarily related to financial and legal advisory costs associated with the Bison Drop Down and our acquisition of Mountaineer Midstream.

Depreciation and Amortization. The increase in depreciation and amortization expense during the three months ended June 30, 2014 was largely due to the development of the Mountaineer Midstream and DFW Midstream systems. An increase in contract amortization and assets placed into service on the Grand River system also contributed to the increase.

Interest Expense. The increase in interest expense during the three months ended June 30, 2014, was primarily driven by our issuance of $300.0 million of 7.50% senior notes in June 2013 and a higher average outstanding balance on our revolving credit facility as a result of our June 2013 and March 2014 borrowings to partially fund the Partnership's acquisition capital expenditures.

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Overview of the Six Months Ended June 30, 2014 and 2013

The following table presents certain consolidated and other financial and operating data for the periods indicated.



	Six months ended June 30,						Percentage Change
	2014			2013			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and other fees	$	104,903		$	93,888		12	%
Natural gas, NGLs and condensate sales and other	52,546			40,088			31	%
Amortization of favorable and unfavorable contracts (1)	(451		)	(530		)	*
Total revenues	156,998			133,446			18	%
Costs and expenses:
Cost of natural gas and NGLs	31,660			21,403			48	%
Operation and maintenance	39,040			35,950			9	%
General and administrative	16,576			14,973			11	%
Transaction costs	612			2,473			*
Depreciation and amortization	40,122			30,714			31	%
Total costs and expenses	128,010			105,513			21	%
Other (expense) income	(4		)	2			*
Interest expense	(17,947		)	(4,903		)	*
Income before income taxes	11,037			23,032			(52	)%
Income tax expense	(628		)	(402		)	*
Net income	$	10,409		$	22,630		(54	)%

Other Financial Data:
EBITDA (2)	$	69,555		$	59,177		18	%
Adjusted EBITDA (2)	94,575			73,623			28	%
Capital expenditures	63,336			49,642			28	%
Acquisition capital expenditures (3)	305,000			458,914			(34	)%
Distributable cash flow (2)	68,403			60,239			14	%

Operating Data:
Aggregate average throughput (MMcf/d)	1,356			1,075			26	%

__________

* Not considered meaningful

(3) Reflects cash paid and value of units issued, if any, to fund acquisitions and/or drop downs. For additional information, see Note 12 to the unaudited condensed consolidated financial statements.

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Operating Data by System. Operating data by system for the six months ended June 30 follows.



	Mountaineer Midstream (1)		Bison Midstream (2)				DFW Midstream				Grand River (3)
	2014	2013	2014		2013		2014		2013		2014		2013
Aggregate average throughput (MMcf/d)	326	6	14		13		349		407		667		649
Average fee per Mcf	*	*	$	4.09	$	4.07	$	0.60	$	0.60	$	0.39	$	0.33

__________

* Contract terms excluded for confidentiality purposes.

(1) Gathering system was acquired by SMLP on June 21, 2013. For the period of SMLP's ownership in 2013, average throughput was 120 MMcf/d.

(2) Includes contribution from Bison Midstream during the period from February 16, 2013 to June 4, 2013 due to the common control aspect of the Bison Drop Down. For the period of SMLP's common control ownership in 2013, average throughput was 17 MMcf/d.

(3) Includes contribution from Red Rock Gathering during the six months ended June 30, 2013 and the period from January 1, 2014 to March 18, 2014 due to the common control aspect of the Red Rock Drop Down.

Gathering Services and Other Fees. Gathering services and other fees increased during the six months ended June 30, 2014, largely as a result of our acquisition of the Mountaineer Midstream system and increases on the Grand River Gathering system as a result of growth at Red Rock Gathering. The year-over-year increase on the Grand River system was largely driven by the proportionate contribution of higher margin throughput volumes from certain customers. Additionally, certain gas gathering agreements benefited from provisions which increased the gas gathering fee on our Grand River and Bison Midstream systems. These increases were partially offset by the continued natural decline in volumes and lack of producer drilling activity on the DFW Midstream system as well as declines on Bison Midstream.

Natural Gas, NGLs and Condensate Sales and Other. The increase in natural gas, NGLs and condensate sales and other for the six months ended June 30, 2014, was primarily a result of the contribution from the Bison Midstream system and Grand River Gathering as a result of growth at Red Rock Gathering.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs represents the expenses associated with the percent-of-proceeds and keep-whole arrangements under which the Bison Midstream and Grand River Gathering systems sell natural gas purchased from our customers. The increase in the six months ended June 30, 2014 is primarily a result of the contribution from the Bison Midstream system and an increase as a result of growth at Red Rock Gathering.

Operation and Maintenance. Operation and maintenance expense increased during the six months ended June 30, 2014, largely as a result of expenses associated with Mountaineer Midstream and Bison Midstream, partially offset by declines at DFW Midstream and Grand River Gathering. The increase in consolidated operation and maintenance expense also reflects a $1.9 million increase in salaries, benefits and incentive compensation, a $0.7 million increase in property tax expense largely as a result of the June 2013 acquisition of Mountaineer Midstream and a $0.5 million increase in chemicals primarily for the Bison Midstream and Grand River Gathering systems. These increases were partially offset by the $1.1 million decline in third-party natural gas treating expenses and a $0.4 million decrease in compressor-related expenses as a result of our purchase of previously leased compression assets in the first quarter of 2013.

General and Administrative. General and administrative expense increased during the six months ended June 30, 2014, largely as a result of an increase in salaries, benefits and incentive compensation primarily as a result of increased head count and an increase in professional services expense.

Transaction Costs. Transaction costs for the six months ended June 30, 2014, primarily related to financial and legal advisory costs associated with the Red Rock Drop Down. Transaction costs for the six months ended June 30, 2013, primarily related to financial and legal advisory costs associated with the Bison Drop Down and our acquisition of Mountaineer Midstream.

Depreciation and Amortization. The increase in depreciation and amortization expense during the six months ended June 30, 2014 was largely driven by contributions from Mountaineer Midstream and Bison Midstream. An increase in contract amortization and assets placed into service on the Grand River system also contributed to the increase.

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Interest Expense. The increase in interest expense during the six months ended June 30, 2014, was primarily driven by our issuance of $300.0 million of 7.50% senior notes in June 2013 and a higher average outstanding balance on our revolving credit facility as a result of our June 2013 and March 2014 borrowings to partially fund the Partnership's acquisition capital expenditures.

Non-GAAP Financial Measures

EBITDA, adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with accounting principles generally accepted in the United States of America ("GAAP"). We define EBITDA as net income, plus interest expense, income tax expense, and depreciation and amortization expense, less interest income and income tax benefit. We define adjusted EBITDA as EBITDA plus unit-based compensation, adjustments related to MVC shortfall payments and loss on asset sales, less gain on asset sales. We define distributable cash flow as adjusted EBITDA plus cash interest income, less cash paid for interest expense and income taxes, senior notes interest and maintenance capital expenditures.

EBITDA, adjusted EBITDA and distributable cash flow are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others. We believe that the presentation of these non-GAAP financial measures provides useful information to investors in assessing our financial condition and results of operations.

Net income and net cash provided by operating activities are the GAAP financial measures most directly comparable to EBITDA, adjusted EBITDA and distributable cash flow. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Furthermore, each of these non-GAAP financial measures has limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. Some of these limitations include:


•	certain items excluded from EBITDA, adjusted EBITDA and distributable cash flow are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure;


•	EBITDA, adjusted EBITDA, and distributable cash flow do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;


•	EBITDA, adjusted EBITDA, and distributable cash flow do not reflect changes in, or cash requirements for, our working capital needs;


•	although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA, adjusted EBITDA and distributable cash flow do not reflect any cash requirements for such replacements; and


•	our computations of EBITDA, adjusted EBITDA and distributable cash flow may not be comparable to other similarly titled measures of other companies.

We compensate for the limitations of EBITDA, adjusted EBITDA and distributable cash flows as analytical tools by reviewing the comparable GAAP financial measures, understanding the differences between the financial measures and incorporating these data points into our decision-making process.

EBITDA, adjusted EBITDA or distributable cash flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Because EBITDA, adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

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Net Income-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of net income to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.



	Three months ended June 30,				Six months ended June 30,
	2014		2013		2014			2013
	(In thousands)
Reconciliation of Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
Net income	$	4,036	$	8,767	$	10,409		$	22,630
Add:
Interest expense	10,803		3,023		17,947			4,903
Income tax expense	469		221		628			402
Depreciation and amortization expense	20,480		16,801		40,122			30,714
Amortization of favorable and unfavorable contracts	225		250		451			530
Less:
Interest income	1		1		2			2
EBITDA (1)	$	36,012	$	29,061	$	69,555		$	59,177
Add:
Unit-based compensation	1,361		940		2,424			1,402
Adjustments related to MVC shortfall payments (2)	10,577		6,749		22,590			13,044
Loss on asset sales	6		—		6			—
Adjusted EBITDA (1)	$	47,956	$	36,750	$	94,575		$	73,623
Add:
Interest income	1		1		2			2
Less:
Cash interest paid	2,845		2,125		17,153			4,014
Senior notes interest (3)	5,625		875		(875		)	875
Cash taxes paid	—		660		—			660
Maintenance capital expenditures (4)	4,817		5,212		9,896			7,837
Distributable cash flow	$	34,670	$	27,879	$	68,403		$	60,239

__________

(1) Includes transaction costs. These unusual and non-recurring expenses are settled in cash. For additional information, see "Results of Operations" above.

(2) Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. We include a proportional amount of these historical or expected minimum volume commitment shortfall payments in each quarter prior to the quarter in which we actually receive the shortfall payment.

(3) Senior notes interest represents the net of interest expense accrued and paid during the period. Interest on the $300.0 million 7.5% senior notes is paid in cash semi-annually in arrears on January 1 and July 1 until maturity in July 2021.

(4) Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity.

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Cash Flow-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of net cash provided by operating activities to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.



	Six months ended June 30,
	2014			2013
	(In thousands)
Reconciliation of Net Cash Provided by Operating Activities to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
Net cash provided by operating activities (1)	$	80,699		$	69,472
Add:
Interest expense (2)	16,727			4,021
Income tax expense	628			402
Changes in operating assets and liabilities	(26,067		)	(13,314		)
Less:
Unit-based compensation	2,424			1,402
Interest income	2			2
Loss on asset sales	6			—
EBITDA (1)	$	69,555		$	59,177
Add:
Unit-based compensation	2,424			1,402
Adjustments related to MVC shortfall payments(3)	22,590			13,044
Loss on asset sales	6			—
Adjusted EBITDA (1)	$	94,575		$	73,623
Add:
Interest income	2			2
Less:
Cash interest paid	17,153			4,014
Senior notes interest (4)	(875		)	875
Cash taxes paid	—			660
Maintenance capital expenditures (5)	9,896			7,837
Distributable cash flow	$	68,403		$	60,239

__________

(1) Includes transaction costs. These unusual and non-recurring expenses are settled in cash. For additional information, see "Results of Operations" above.

(2) Interest expense presented in the cash flow-basis non-GAAP reconciliation above differs from the interest expense presented in the net income-basis non-GAAP reconciliation presented earlier due to adjustments for amortization of deferred loan costs. For the six months ended June 30, 2014, interest expense excluded $1.2 million of amortization of deferred loan costs. For the six months ended June 30, 2013, interest expense excluded $0.9 million of amortization of deferred loan costs.

(3) Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. We include a proportional amount of these historical or expected minimum volume commitment shortfall payments in each quarter prior to the quarter in which we actually receive the shortfall payment.

(4) Senior notes interest represents the net of interest expense accrued and paid during the period. Interest on the $300.0 million 7.5% senior notes is paid in cash semi-annually in arrears on January 1 and July 1 until maturity in July 2021.

(5) Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity.

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Liquidity and Capital Resources

In July 2014, we filed a registration statement and completed a public offering of $300.0 million aggregate principal 5.5% senior notes due 2022 thereunder. We used the proceeds to repay a portion of the outstanding borrowings under our revolving credit facility.

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 Summit Investments, pursuant to our November 2013 shelf registration statement on Form S-3 (discussed below). Concurrent with the offering, our general partner made a capital contribution to maintain its 2% general partner interest. We used the proceeds from our primary offering of common units and the general partner capital contribution to fund a portion of the purchase of Red Rock Gathering.

In January 2014, we filed a registration statement to offer to exchange all of the unregistered 7.5% senior notes and guarantees for registered senior notes and guarantees with substantially identical terms. In March 2014, the SEC declared our registration statement effective and in April 2014, the exchange period concluded with 100% of the unregistered senior notes being exchanged for registered notes.

In November 2013, our shelf registration statement became effective, allowing us to issue up to $1.2 billion of equity and debt securities in primary offerings as well as all of the 14,691,397 common units held by Summit Investments in accordance with our obligations under several registration rights agreements. Following the March 2014 Equity Offering, up to $1.0 billion of equity and debt securities in primary offerings and 9,641,397 common units may be issued pursuant to this shelf registration statement.

In June 2013, we completed an offering of $300.0 million aggregate principal 7.5% senior notes due 2021 and issued common limited partner units and general partner interests in connection with the Bison Drop Down and the Mountaineer Acquisition. In future periods, we expect our sources of liquidity to include:


•	cash generated from operations;


•	borrowings under the revolving credit facility; and


•	additional issuances of debt and equity securities.

For additional information, see Notes 1, 5, 6 and 12 to the unaudited condensed consolidated financial statements.

Long-Term Debt

Revolving Credit Facility. We have a $700.0 million senior secured revolving credit facility. The revolving credit facility 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 facility, and Summit Holdings' obligations, are guaranteed by SMLP and each of its subsidiaries. At our option, borrowings under the revolving credit facility bear interest at a variable rate per annum equal to either (i) the London InterBank Offered Rate plus the applicable margin ranging from 1.75% to 2.75% or (ii) a base rate plus the applicable margin ranging from 0.75% to 1.75%. As of June 30, 2014, the outstanding balance of the revolving credit facility was $426.0 million and the unused portion totaled $274.0 million. We used the proceeds from our July 2014 offering of senior notes to pay down $295.2 million

As of June 30, 2014, we were in compliance with the covenants in the revolving credit facility. There were no defaults or events of default during the three months ended June 30, 2014. See Note 5 to the unaudited condensed consolidated financial statements for additional information.

Senior Notes. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Finance Corp. (together with Summit Holdings, the "Co-Issuers") co-issued $300.0 million of 5.50% senior unsecured notes maturing August 15, 2022.

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 were initially sold in reliance on Rule 144A and Regulation S under the Securities Act. Effective as of April 7, 2014, all of the holders of our 7.5% senior notes exchanged their unregistered 7.5% senior notes and the guarantees of those notes for registered 7.5% notes and guarantees. The terms of the registered 7.5% senior notes are substantially identical to the terms of the unregistered 7.5% senior notes, except that the transfer restrictions, registration rights and provisions for additional interest relating to the unregistered 7.5% senior notes do not apply to the registered 7.5% senior notes.

Our 7.5% and 5.5% senior notes are senior, unsecured obligations, rank equally in right of payment with all of our existing and future senior obligations and are effectively subordinated in right of payment to all of our secured

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indebtedness, to the extent of the collateral securing such indebtedness. The Guarantors have fully and unconditionally and jointly and severally guaranteed the 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 and the 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 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.

There were no defaults or events of default during the six months ended June 30, 2014. For additional information, see Note 5 to the unaudited condensed consolidated financial statements.

Cash Flows

The components of the change in cash and cash equivalents were as follows:



	Six months ended June 30,
	2014			2013
	(In thousands)
Net cash provided by operating activities	$	80,699		$	69,472
Net cash used in investing activities	(368,312		)	(459,642		)
Net cash provided by financing activities	290,686			410,288
Change in cash and cash equivalents	$	3,073		$	20,118

Operating activities. Cash flows from operating activities increased by $11.2 million for the six months ended June 30, 2014 largely due to cash received as a result of MVCs.

Investing activities. Cash flows used in investing activities for the six months ended June 30, 2014 reflect the Partnership's acquisition of Red Rock Gathering from an affiliate of Summit Investments. Additional expenditures in the six months ended June 30, 2014 primarily reflect construction of a processing plant on the Grand River Gathering system, projects to expand compression capacity on the Bison Midstream system, adding pipeline on the Mountaineer Midstream system, and commissioning a new natural gas treating facility on the DFW Midstream system, which was commissioned in February 2014.

Cash flows used in investing activities in the six months ended June 30, 2013 reflect the acquisitions of Mountaineer Midstream from a third party and Bison Midstream from an affiliate of Summit Investments. Additional expenditures in 2013 reflect the construction of new gathering pipeline across the DFW Midstream system and the acquisition of previously leased compression assets on the Grand River system. We also commissioned a new compressor unit on the DFW Midstream system in January 2013.

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Financing activities. Details of cash flows provided by financing activities for the six months ended June 30, 2014 and 2013, were as follows:



	Six months ended June 30,
	2014			2013
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	$	(56,749	)	$	(41,348	)
Borrowings under revolving credit facility	160,000			360,000
Repayments under revolving credit facility	(20,000		)	(294,180		)
Deferred loan costs	(300		)	(7,333		)
Tax withholdings on vested SMLP LTIP awards	(656		)	—
Proceeds from issuance of common units	197,989			—
Contribution from general partner	4,235			—
Cash advance from (to) Summit Investments to (from) contributed subsidiaries, net	1,982			(11		)
Expenses paid by Summit Investments on behalf of contributed subsidiaries	4,413			5,117
Issuance of 7.5% senior notes	—			300,000
Issuance of units to affiliate in connection with the Mountaineer Acquisition	—			100,000
Repurchase of equity-based compensation awards	(228		)	(11,957		)
Net cash provided by financing activities	$	290,686		$	410,288

Net cash provided by financing activities for the six months ended June 30, 2014 was primarily composed of proceeds from the March 2014 Equity Offering and net borrowings under our revolving credit facility, both of which were used to fund the Red Rock Drop Down, partially offset by distributions declared in respect of both the first quarter of 2014 (paid in the second quarter of 2014) and fourth quarter of 2013 (paid in the first quarter of 2014).

Net cash provided by financing activities for the six months ended June 30, 2013 was primarily composed of the following:


•	Distributions declared in respect of both the first quarter of 2013 (paid in the second quarter of 2013) and fourth quarter of 2012 (paid in the first quarter of 2013);


•	Borrowings of $360.0 million under our revolving credit facility, of which $200.0 million was used to partially fund the Bison Drop Down and $110.0 million was used to partially fund the Mountaineer Acquisition;


•	Payments of $294.2 million on our revolving credit facility, all of which was funded by our $300.0 million senior notes issuance;


•	Net proceeds of $294.2 million from our issuance of $300.0 million senior notes, all of which was used to pay down our revolving credit facility. We incurred loan costs of $7.1 million in connection with the senior notes issuance which will be amortized over the life of the senior notes;


•	Issuance of $98.0 million of common units and $2.0 million of general partner interests to Summit Investments for cash to partially fund the Mountaineer Acquisition; and


•	Our repurchase of the remaining vested DFW Net Profits Interests.

Capital Requirements

Our business is capital-intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement requires that we categorize our capital expenditures as either:


•	maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or


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

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We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by borrowings under the revolving credit facility and the issuance of debt and equity securities.

Distributions

Based on the terms of our partnership agreement, we expect to distribute to unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures primarily from borrowings under our revolving credit facility and future issuances of equity and debt securities. See Note 6 to the unaudited condensed consolidated financial statements for additional information.

Credit Risk and Customer Concentration

We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. A significant percentage of our revenue is attributable to two producer customers. For additional information, see Note 9 to the unaudited condensed consolidated financial statements.

Contractual Obligations Update

In July 2014, we replaced $295.2 million of outstanding indebtedness under our revolving credit facility with the net proceeds from our public offering of $300.0 million of 5.5% senior unsecured notes due August 2022. The impact of this transaction increased our annual interest expense obligation by approximately $10.5 million (using the June 30, 2014 revolving credit facility rate and the 5.5% senior notes rate, assuming no change in outstanding principal) and extended the maturity from November 2018 to August 2022.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the six months ended June 30, 2014.

Critical Accounting Policies and Estimates

We prepare our financial statements in accordance with GAAP. These principles are established by the Financial Accounting Standards Board. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. Our significant accounting policies are described in Note 2 to the unaudited condensed consolidated financial statements.

The estimates that we deem to be most critical to an understanding of our financial position and results of operations are those related to determination of fair value and recognition of deferred revenue. The preparation and evaluation of these critical accounting estimates involve the use of various assumptions developed from management's analyses and judgments. Subsequent experience or use of other methods, estimates or assumptions could produce significantly different results.

There have been no changes in the accounting methodology for items that we have identified as critical accounting estimates during the six months ended June 30, 2014. For additional information regarding critical accounting estimates, see the Critical Accounting Policies and Estimates section of MD&A included in the 2013 Annual Report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness associated with the revolving credit facility. The credit markets have recently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

A hypothetical 1.0% increase (decrease) in interest rates would have increased (decreased) our interest expense by approximately $1.8 million for the six months ended June 30, 2014.

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Commodity Price Risk

We currently generate a substantial majority of our revenues pursuant to primarily long-term and fee-based gas gathering agreements, many of which include MVCs and areas of mutual interest. Our direct commodity price exposure relates to (i) our sale of physical natural gas we retain from our DFW Midstream customers, (ii) our procurement of electricity to operate our electric-drive compression assets on the DFW Midstream system, (iii) the sale of condensate volumes that we retain on the Grand River system and (iv) the sale of processed natural gas and natural gas liquids pursuant to our percent-of-proceeds and keep-whole contracts with certain of our customers on the Bison Midstream and Grand River Gathering systems. Our gas gathering agreements with our DFW Midstream customers permit us to retain a certain quantity of natural gas that we sell to offset the power costs we incur to operate our electric-drive compression assets. Our gas gathering agreements with our Grand River customers permit us to retain condensate volumes from the Grand River system gathering lines. We manage our 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 sales. We do not enter into risk management contracts for speculative purposes.

Item 4. Controls and Procedures.

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to the management of our general partner, including our general partner’s principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. SMLP’s management, with the participation of the Chief Executive Officer and Chief Financial Officer of SMLP's general partner, has evaluated the effectiveness of SMLP’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this quarterly report (the "Evaluation Date"). Based on such evaluation, the Chief Executive Officer and Chief Financial Officer of SMLP's general partner have concluded that, as of the Evaluation Date, SMLP’s disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have not been any changes in SMLP’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the second fiscal quarter of 2014 that have materially affected, or are reasonably likely to materially affect, SMLP's internal control over financial reporting.

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PART II

Item 1. Legal Proceedings.

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any significant legal or governmental proceedings. In addition, we are not aware of any significant legal or governmental proceedings contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

Item 1A. Risk Factors.

The risk factors contained in our annual report on Form 10-K for the year ended December 31, 2013, as updated and superseded by our current report on Form 8-K dated July 3, 2014 are incorporated herein by reference.

Item 6. Exhibits.



Exhibit number		Description
3.1		First Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated as of October 3, 2012 (Incorporated herein by reference to Exhibit 3.1 to SMLP's Current Report on Form 8-K dated October 4, 2012 (Commission File No. 001-35666))
3.2		Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated as of October 3, 2012 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K dated October 4, 2012 (Commission File No. 001-35666))
3.3		Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
3.4		Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
10.1		Base Indenture, dated as of July 15, 2014, by and among Summit Midstream Holdings, LLC, Summit Midstream Finance Corp. and U.S. Bank National Association (Incorporated herein by reference to Exhibit 4.1 to SMLP's Current Report on Form 8-K dated July 15, 2014 (Commission File No. 001-35666))
10.2		First Supplemental Indenture, dated as of July 15, 2014, by and among Summit Midstream Holdings, LLC, Summit Midstream Finance Corp., the Guarantors party thereto and U.S. Bank National Association (including form of the 5½% senior notes due 2022) (Incorporated herein by reference to Exhibit 4.2 to SMLP's Current Report on Form 8-K dated July 15, 2014 (Commission File No. 001-35666))
31.1		Rule 13a-14(a)/15d-14(a) Certification, executed by Steven J. Newby, President, Chief Executive Officer and Director
31.2		Rule 13a-14(a)/15d-14(a) Certification, executed by Matthew S. Harrison, Senior Vice President and Chief Financial Officer
32.1		Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Steven J. Newby, President, Chief Executive Officer and Director, and Matthew S. Harrison, Senior Vice President and Chief Financial Officer
101.INS	**	XBRL Instance Document (1)
101.SCH	**	XBRL Taxonomy Extension Schema
101.CAL	**	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	**	XBRL Taxonomy Extension Definition Linkbase
101.LAB	**	XBRL Taxonomy Extension Label Linkbase
101.PRE	**	XBRL Taxonomy Extension Presentation Linkbase

** Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as

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amended, and otherwise are not subject to liability under those sections. The financial information contained in the XBRL(eXtensible Business Reporting Language)-related documents is unaudited and unreviewed.

(1) Includes the following materials contained in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, formatted in XBRL: (i) Unaudited Condensed Consolidated Balance Sheets, (ii) Unaudited Condensed Consolidated Statements of Operations, (iii) Unaudited Condensed Consolidated Statements of Partners' Capital, (iv) Unaudited Condensed Consolidated Statements of Cash Flows, and (v) Notes to Unaudited Condensed Consolidated Financial Statements.

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SIGNATURES

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



	Summit Midstream Partners, LP
	(Registrant)

	By: Summit Midstream GP, LLC (its general partner)

August 8, 2014	/s/ Matthew S. Harrison
	Matthew S. Harrison, Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)