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 September 30, 2013

or

[ ] 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 ofincorporation 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)
Registrant’s telephone number, including area code: (214) 242-1955
Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Name of exchange on which registered
Common Units	New York Stock Exchange

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 Filero	Accelerated Filero
Non-Accelerated Filer x (Do not check if a smaller reporting company)	Smaller Reporting Companyo

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 October 31, 2013
Common Units	29,079,866 units
Subordinated Units	24,409,850 units
General Partner Units	1,091,453 units

TABLE OF CONTENTS

PART I	FINANCIAL INFORMATION	1
Item 1.	Financial Statements.	1
	Unaudited Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	1
	Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012	2
	Unaudited Condensed Consolidated Statements of Partners' Capital and Membership Interests for the nine months ended September 30, 2013 and 2012	3
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	4
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	25
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	44
Item 4.	Controls and Procedures.	45
PART II	OTHER INFORMATION	46
Item 1.	Legal Proceedings.	46
Item 1A.	Risk Factors.	46
Item 6.	Exhibits.	46

i

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 compression 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 right-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. 

ii

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

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30,		December 31,
	2013		2012
	(Dollars in thousands)
Assets
Current assets:
Cash and cash equivalents	$	15,283	$	7,895
Accounts receivable	34,911		33,504
Due from affiliate	—		774
Other assets	2,354		2,190
Total current assets	52,548		44,363
Property, plant and equipment, net	957,555		681,993
Intangible assets, net:
Favorable gas gathering contracts	18,348		19,958
Contract intangibles	394,804		229,596
Rights-of-way	51,657		35,986
Total intangible assets, net	464,809		285,540
Goodwill	117,766		45,478
Other noncurrent assets	12,417		6,137
Total assets	$	1,605,095	$	1,063,511
Liabilities and Partners' Capital
Current liabilities:
Trade accounts payable	$	11,909	$	15,817
Due to affiliate	430		—
Deferred revenue	1,555		865
Ad valorem taxes payable	5,604		5,455
Accrued interest	6,525		16
Other current liabilities	7,620		4,308
Total current liabilities	33,643		26,461
Long-term debt	565,050		199,230
Noncurrent liability, net (Note 4)	6,604		7,420
Deferred revenue	22,560		10,899
Other noncurrent liabilities	361		254
Total liabilities	628,218		244,264
Commitments and contingencies (Note 11)
Common limited partner capital (29,075,447 units issued and outstanding at September 30, 2013 and 24,412,427 units issued and outstanding at December 31, 2012)	570,260		418,856
Subordinated limited partner capital (24,409,850 units issued and outstanding at September 30, 2013 and December 31, 2012)	383,281		380,169
General partner interests (1,091,453 units issued and outstanding at September 30, 2013 and 996,320 issued and outstanding at December 31, 2012)	23,336		20,222
Total partners' capital	976,877		819,247
Total liabilities and partners' capital	$	1,605,095	$	1,063,511

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

1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
	(In thousands, except per-unit and unit amounts)
Revenues:
Gathering services and other fees	$	45,968		$	37,903		$	127,098		$	106,550
Natural gas, NGLs and condensate sales and other	17,392			3,232			47,204			10,290
Amortization of favorable and unfavorable contracts	(264		)	(160		)	(794		)	25
Total revenues	63,096			40,975			173,508			116,865
Costs and expenses:
Operation and maintenance	15,918			14,460			45,467			37,177
Cost of natural gas and NGLs	10,464			—			24,328			—
General and administrative	6,248			5,179			18,198			15,977
Transaction costs	123			1,739			2,549			1,972
Depreciation and amortization	16,426			9,156			43,146			26,135
Total costs and expenses	49,179			30,534			133,688			81,261
Other (expense) income	(112		)	2			(110		)	8
Interest expense	(6,937		)	(2,827		)	(11,840		)	(5,573		)
Affiliated interest expense	—			(13		)	—			(5,426		)
Income before income taxes	6,868			7,603			27,870			24,613
Income tax expense	(177		)	(207		)	(579		)	(501		)
Net income	$	6,691		$	7,396		$	27,291		$	24,112
Less: net income attributable to SMP Holdings (Note 1)	—						52
Net income attributable to partners	6,691						27,239
Less: net income attributable to general partner	134						545
Net income attributable to limited partners	$	6,557					$	26,694
Earnings per common unit – basic	$	0.12					$	0.57
Earnings per common unit – diluted	$	0.12					$	0.57
Earnings per subordinated unit – basic and diluted	$	0.12					$	0.48
Weighted-average common units outstanding – basic	29,074,743						26,234,042
Weighted-average common units outstanding – diluted	29,227,041						26,352,234
Weighted-average subordinated units outstanding – basic and diluted	24,409,850						24,409,850
Cash distributions declared and paid per common unit	$	0.435					$	1.265

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

2

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL AND

MEMBERSHIP INTERESTS

	Partners' capital
	Limited partners									SMP Holdings' equity in Bison Midstream
	Common			Subordinated			General partner						Membership interests		Total
	(In thousands)
Membership interests, January 1, 2012	$	—		$	—		$	—		$	—		$	640,818	$	640,818
Net income	—			—			—			—			24,112		24,112
Class B membership interest unit-based compensation	—			—			—			—			1,793		1,793
Membership interests, September 30, 2012	$	—		$	—		$	—		$	—		$	666,723	$	666,723
Partners' capital, January 1, 2013	$	418,856		$	380,169		$	20,222		$	—		$	—	$	819,247
Net income	13,691			13,003			545			52			—		27,291
SMLP unit-based compensation	1,970			—			—			—			—		1,970
Consolidation of Bison Midstream net assets	—			—			—			303,168			—		303,168
Contribution from SMP Holdings to Bison Midstream	—			—			—			2,229			—		2,229
Purchase of Bison Midstream	47,936			—			978			(248,914		)	—		(200,000		)
Contribution of net assets from SMP Holdings 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
Class B membership interest unit-based compensation	17			—			—			—			—		17
Repurchase of DFW Net Profits Interests	(5,859		)	(5,859		)	(239		)	—			—		(11,957		)
Distributions to unitholders	(32,909		)	(30,878		)	(1,301		)	—			—		(65,088		)
Partners' capital, September 30, 2013	$	570,260		$	383,281		$	23,336		$	—		$	—	$	976,877

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

3

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine months ended September 30,
	2013			2012
	(In thousands)
Cash flows from operating activities:
Net income	$	27,291		$	24,112
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	43,146			26,135
Amortization of favorable and unfavorable contracts	794			(25		)
Amortization of deferred loan costs	1,591			1,018
Unit-based compensation	1,987			1,793
Loss on asset sales	113			—
Pay-in-kind interest on promissory notes payable to Sponsors	—			5,426
Changes in operating assets and liabilities:
Accounts receivable	4,198			1,522
Due to/from affiliate	1,204			—
Other assets	(147		)	(286		)
Trade accounts payable	(563		)	(5,250		)
Change in deferred revenue	9,561			7,585
Ad valorem taxes payable	64			4,050
Accrued interest	6,509			(396		)
Other current liabilities	51			2,224
Other noncurrrent liabilities	107			—
Net cash provided by operating activities	95,906			67,908
Cash flows from investing activities:
Capital expenditures	(62,317		)	(60,647		)
Proceeds from asset sales	585			—
Acquisition of Bison Midstream	(200,000		)	—
Acquisition of Mountaineer Midstream	(210,000		)	—
Net cash used in investing activities	(471,732		)	(60,647		)
Cash flows from financing activities:
Distributions to unitholders	(65,088		)	—
Borrowings under revolving credit facility	360,000			213,000
Repayments under revolving credit facility	(294,180		)	(15,770		)
Issuance of senior notes	300,000			—
Contribution from SMP Holdings to Bison Midstream	2,229			—
Issuance of units in connection with the Mountaineer Acquisition	100,000			—
Repurchase of DFW Net Profits Interests	(11,957		)	—
Deferred loan costs and initial public offering costs	(7,790		)	(5,976		)
Repayment of promissory notes payable to Sponsors	—			(209,230		)
Net cash provided by (used in) financing activities	383,214			(17,976		)
Net change in cash and cash equivalents	7,388			(10,715		)
Cash and cash equivalents, beginning of period	7,895			15,462
Cash and cash equivalents, end of period	$	15,283		$	4,747

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

4

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)

	Nine months ended September 30,
	2013		2012
	(In thousands)
Supplemental Schedule of Investing and Financing Activities:
Cash interest paid	$	6,548	$	6,274
Less: capitalized interest	2,808		2,191
Interest paid (net of capitalized interest)	$	3,740	$	4,083
Cash paid for income taxes	$	660	$	650
Supplemental Disclosures of Noncash Investing and Financing Activities:
Capital expenditures in trade accounts payable (period-end accruals)	$	2,592	$	3,682
Unit-based compensation	1,987		1,793
Issuance of units to partially fund the Bison Drop Down	48,914		—
Contribution of net assets from SMP Holdings in excess of consideration paid for Bison Midstream	56,535		—
Pay-in-kind interest on promissory notes payable to Sponsors	—		6,337
Deferred initial public offering costs in trade accounts payable	—		1,531

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

5

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 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 has a 100% ownership interest in Summit Midstream Holdings, LLC ("Summit Holdings") which has a 100% ownership interest in both DFW Midstream Services LLC ("DFW Midstream") and Grand River Gathering, LLC ("Grand River Gathering"). The effects of the IPO and related equity transfers occurring in October 2012 are reflected in SMLP's financial statements. For additional information, see Note 1 to the audited consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2012 (the "2012 Annual Report").

On June 4, 2013, Summit Holdings acquired all of the membership interests of Bison Midstream, LLC ("Bison Midstream") from Summit Midstream Partners Holdings, LLC ("SMP Holdings"), a wholly owned direct 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") and subsequently contributed it to SMP Holdings. The Bison Gas Gathering system was carved out from BTE in connection with the Bison Drop Down. As such, it was deemed a transaction among entities under common control. For additional information, see Notes 5, 6 and 12.

On June 21, 2013, Mountaineer Midstream Company, LLC ("Mountaineer Midstream"), a newly formed, wholly owned subsidiary of Summit Holdings, acquired certain natural gas gathering pipeline and compression assets in the Marcellus Shale Play in Doddridge County, West Virginia from an affiliate of MarkWest Energy Partners, L.P. ("MarkWest") (the "Mountaineer Acquisition").  For additional information, see Notes 5, 6 and 12.

Summit Investments is a Delaware limited liability company and the predecessor for accounting purposes (the "Predecessor") 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", and collectively with Energy Capital Partners, the "Sponsors"). In March 2013, Summit Investments contributed the ownership of its SMLP common and subordinated units along with its 2% general partner interest in SMLP to SMP Holdings in exchange for a continuing 100% interest in SMP Holdings. As of September 30, 2013, SMP Holdings held 14,691,397 SMLP common units, 24,409,850 SMLP subordinated units and 1,091,453 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, 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 has 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.

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.

6

Business Operations. We provide natural gas gathering and compression services pursuant to long-term, primarily fee-based, natural gas gathering agreements with our customers. Our results are driven primarily by the volumes of natural gas that we gather and compress across our systems. We currently operate in the following unconventional resource basins:

• the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado;

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

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

• the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia.

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

For the purposes of the unaudited condensed consolidated financial statements, SMLP's results of operations reflect the Partnership's operations subsequent to the IPO and the results of the Predecessor for the period prior to the IPO. The unaudited condensed consolidated financial statements also reflect the results of operations of: (i) Bison Midstream since February 16, 2013 and (ii) Mountaineer Midstream since June 22, 2013. Because the Bison Drop Down was executed between entities under common control, SMLP recognized the acquisition of Bison Midstream at SMP Holdings' historical cost which reflected its fair value accounting for the acquisition of BTE. The excess of SMP Holdings' 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 Bison Drop Down was accounted for by the Partnership on an “as if pooled” basis for all periods in which common control existed. See Notes 5, 6 and 12 for additional information. The unaudited condensed consolidated financial statements include the assets, liabilities, and results of operations of SMLP or the Predecessor and their respective wholly owned subsidiaries. All intercompany transactions among the consolidated entities have been eliminated. In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation of the results of operations for the three and nine months ended September 30,2013 and 2012.

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. The unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto that are included in our 2012 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. However, due to their similar characteristics and how we manage our business, we have aggregated these segments into one reportable operating segment for disclosure purposes. The assets of our reportable operating segment consist of natural gas gathering 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.

Reclassifications. Certain reclassifications have been made to prior-year amounts to conform to current-year presentation. These reclassifications had no impact on net income or total partners' capital or membership interests.

7

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Fair Value of Financial Instruments. The carrying amount of cash and cash equivalents (Level 1), accounts receivable, and accounts payable reported on the balance sheet approximates fair value due to their short-term maturities.

GAAP's fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

• Level 1. Inputs represent quoted prices in active markets for identical assets or liabilities;

• Level 2.Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs); and

• Level 3.Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement).

Nonfinancial assets and liabilities initially measured at fair value include those acquired and assumed in connection with third-party business combinations.

A summary of the estimated fair value for financial instruments follows.

	September 30, 2013				December 31, 2012
	Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)
	(In thousands)
Revolving credit facility	$	265,050	$	265,050	$	199,230	$	199,230
Senior notes	300,000		308,500		—		—

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 September 30, 2013. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the senior notes.

Intangible Assets and Noncurrent Liability. Upon the acquisition of DFW Midstream, certain of our gas gathering contracts were deemed to have above-market pricing structures while another was deemed to have pricing that was below market. We have recognized the contracts that were above market at acquisition as favorable gas gathering contracts. We have recognized the contract that was deemed to be below market as a noncurrent liability. We amortize these intangibles on a units-of-production basis over the estimated useful life of the contract. We define useful life as the period over which the contract is expected to contribute directly or indirectly to our future cash flows. The related contracts have original terms ranging from 10 years to 20 years. We recognize the amortization expense associated with these intangible assets and liabilities in revenue.

For our other gas gathering contracts, we amortize contract intangible assets over the period of economic benefit based upon the expected revenues over the life of the contract. The useful life of these contracts ranges from 10 years to 25 years. We recognize the amortization expense associated with these intangible assets in depreciation and amortization expense.

We have right-of-way intangible assets associated with city easements and easements granted within existing rights-of-way. We amortize these intangible assets over the shorter of the contractual term of the rights-of-way or the estimated useful life of the gathering system. The contractual terms of the rights-of-way range from 20 years to 30 years. The estimated useful life of our gathering systems is 30 years. We recognize the amortization expense associated with these intangible assets in depreciation and amortization expense.

Other Noncurrent Assets.Other noncurrent assets primarily consist of external costs incurred in connection with the issuance of our senior notes and the closing of our revolving credit facility and related amendments. We

8

capitalize and then amortize these deferred loan costs over the life of the respective debt instrument. We recognize amortization of deferred loan costs in interest expense.

Revenue Recognition. We generate the majority of our revenue from the natural gas gathering 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 gathering 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 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 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.

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 both 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, compressing, and treating. 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, and sell the natural gas to a third party for processing. We then remit to our producers an agreed-upon percentage of the actual proceeds received from sales of the residue natural gas and NGLs. Certain of these arrangements may also result in returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds.

Many of our natural gas gathering agreements provide for a monthly or annual minimum volume commitment ("MVC") from certain of our customers. Under these monthly or annual 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 month or year, as applicable, if its actual throughput volumes are less than its MVC for that month or year. 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. These contract provisions range from 12 months to eight years.

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 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 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 short term for arrangements where the expiration of a customer's right to utilize shortfall payments is twelve months or less. As of September 30, 2013, we have billed $24.1 million of deferred revenue relative to shortfall payments, of which $1.1 million was included in accounts receivable, attributable to arrangements that provide the customer the ability to offset gathering fees in the next one month to eight years to the extent that a customer's throughput volumes exceed its MVC.

Certain customers reimburse us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis.

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Unit-Based Compensation. For awards of unit-based compensation, we determine a grant date fair value and recognize the related compensation expense, adjusted for expected forfeitures, in the statement of operations over the vesting period of the respective awards. See Note 8 for additional information.

Income Taxes. We are not subject to federal and state income taxes, except as noted below, because we are structured as a partnership. 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 the Revised Texas Franchise Tax (the "Texas Margin Tax"). The Texas Margin Tax has the characteristics of an income tax because it is determined by applying a tax rate to a tax base that considers both revenues and expenses. Our financial statements reflect provisions for these tax obligations.

Earnings Per Unit ("EPU"). We present earnings per limited partner unit data only for periods subsequent to the closing of SMLP’s IPO in October 2012. EPU for periods ended prior to the IPO have not been presented because Summit Investments' members held membership interests and not units.

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 unitholders under the two-class method, after deducting the general partner's 2% interest in net income and any incentive distributions paid to the general partner, by the weighted-average number of common and subordinated units outstanding during the three and nine months ended September 30, 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 September 30, 2013 or December 31, 2012. 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 2012 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.

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3. PROPERTY, PLANT, AND EQUIPMENT, NET

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

	Useful lives (In years)	September 30,			December 31,
		2013			2012
	(Dollars in thousands)
Gas gathering systems	30	$	618,528		$	427,449
Compressor stations and compression equipment	30	334,108			237,618
Construction in progress	n/a	50,381			45,919
Other	4-15	9,680			4,524
Total		1,012,697			715,510
Accumulated depreciation		(55,142		)	(33,517		)
Property, plant, and equipment, net		$	957,555		$	681,993

The increase in property, plant, and equipment primarily reflects the recognition of gas gathering system fixed assets acquired in connection with the Bison Drop Down and Mountaineer Acquisition.

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 September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(In thousands)
Depreciation expense	$	8,429	$	5,623	$	21,625	$	15,682
Capitalized interest	1,838		310		2,808		2,191

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:

	September 30, 2013
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
	(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(5,847	)	$	18,348
Contract intangibles	16.8	429,575		(34,771		)	394,804
Rights-of-way	28.3	55,773		(4,116		)	51,657
Total amortizable intangible assets		$	509,543	$	(44,734	)	$	464,809
Unfavorable gas gathering contract	10.0	$	10,962	$	(4,358	)	$	6,604

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	December 31, 2012
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
	(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(4,237	)	$	19,958
Contract intangibles	12.4	244,100		(14,504		)	229,596
Rights-of-way	28.3	38,848		(2,862		)	35,986
Total amortizable intangible assets		$	307,143	$	(21,603	)	$	285,540
Unfavorable gas gathering contract	10.0	$	10,962	$	(3,542	)	$	7,420

The increase in total amortizable intangible assets primarily reflects the recognition of gas gathering contracts and rights-of-way acquired in connection with the Bison Drop Down and the Mountaineer Acquisition.

We recognized amortization expense as follows:

	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	511		$	501		$	1,610		$	1,181
Amortization expense – contract intangibles	7,559			3,194			20,267			9,483
Amortization expense – rights-of-way	438			340			1,254			970
Amortization expense – unfavorable gas gathering contract	(247		)	(341		)	(816		)	(1,206		)

The estimated aggregate annual amortization of intangible assets and noncurrent liability expected to be recognized as of September 30, 2013 for the remainder of 2013 and each of the four succeeding fiscal years follows.

	Assets		Liabilities
	(In thousands)
2013	$	8,801	$	378
2014	36,949		1,549
2015	39,628		1,650
2016	39,754		1,571
2017	38,316		1,456

Goodwill. We recognized goodwill of $45.5 million in connection with the acquisition of Grand River Gathering in 2011 and allocated it to the Grand River Gathering reporting unit. We recognized goodwill of $54.2 million in connection with the Bison Drop Down in June 2013 and allocated it to the Bison Midstream reporting unit. The goodwill attributed to Bison Midstream represents its allocation of the goodwill that Summit Investments recognized in connection with its acquisition of BTE assets in February 2013. We preliminarily recognized goodwill of $18.1 million in connection with the Mountaineer Acquisition in June 2013 and allocated it to the Mountaineer Midstream reporting unit. Goodwill allocated to the Mountaineer Midstream reporting unit will be finalized in conjunction with the finalization of the acquisition accounting. See Notes 1 and 12 for additional information. A rollforward of the consolidated balance of goodwill for the nine months endedSeptember 30, 2013 follows.

	(In thousands)
Goodwill, beginning of period	$	45,478
Goodwill recognized in connection with the Bison Drop Down	54,199
Goodwill preliminarily recognized in connection with the Mountaineer Acquisition	18,089
Goodwill, end of period	$	117,766

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

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amount. We performed our annual goodwill impairment testing as of September 30, 2013 using a combination of the income and market approaches and determined that the fair value of each of the reporting units exceeded their carrying value resulting in no goodwill impairment. There have been no impairments of goodwill.

5. LONG-TERM DEBT

Long-term debt consisted of the following:

	September 30,		December 31,
	2013		2012
	(In thousands)
Variable rate senior secured revolving credit facility (3.43% at September 30, 2013 and 2.98% at December 31, 2012) due November 2018	$	265,050	$	199,230
7.50% Senior unsecured notes due July 2021	300,000		—
Total long-term debt	$	565,050	$	199,230

Revolving Credit Facility. We have a senior secured revolving credit facility. In June 2013, we exercised the revolving credit facility's $50.0 million accordion provision and increased the total commitments thereunder from $550.0 million to $600.0 million. We also borrowed $200.0 million in connection with the Bison Drop Down and $110.0 million in connection with the Mountaineer Acquisition. See Notes 1, 6 and 12 for additional information. Also in June 2013, we used the proceeds from our senior notes offering to repay $294.2 million of our revolving credit facility. As of September 30, 2013, the outstanding balance of the revolving credit facility was $265.1 million.

The revolving credit facility is secured by the membership interests of Summit Holdings, DFW Midstream, Grand River Gathering, Bison Midstream and Mountaineer Midstream and substantially all of the assets of these entities. It is guaranteed by SMLP and all of its subsidiaries, except for Summit Midstream Finance Corp. ("Finance Corp.") and allows for revolving loans, letters of credit and swingline loans.

Borrowings under the revolving credit facility bear interest at the London Interbank Offered Rate ("LIBOR") plus an applicable margin or a base rate, as defined in the credit agreement. At September 30, 2013, the applicable margin under LIBOR borrowings was 3.25%, the interest rate was 3.43% and the unused portion of the revolving credit facility totaled $334.9 million (subject to a commitment fee of 0.50%).

The revolving credit agreement contains affirmative and negative covenants customary for credit facilities of its size and nature that, among other things, limit or restrict the ability to: (i) incur additional debt; (ii) make investments; (iii) engage in certain mergers, consolidations, acquisitions or sales of assets; (iv) enter into swap agreements and power purchase agreements; (v) enter into leases that would cumulatively obligate payments in excess of $30.0 million over any 12-month period; and (vi) prohibits the payment of distributions by Summit Holdings if a default then exists or would result therefrom, and otherwise limits the amount of distributions Summit Holdings can make. In addition, the revolving credit facility requires Summit Holdings to maintain a ratio of consolidated trailing 12-month earnings before interest, income taxes, depreciation and amortization ("EBITDA") to net interest expense of not less than 2.5 to 1.0 (as defined in the credit agreement) and a ratio of total net indebtedness to consolidated trailing 12-month EBITDA of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to six months following certain acquisitions (as defined in the credit agreement).

As of September 30, 2013, we were in compliance with the covenants in the revolving credit facility. There were no defaults or events of default during the nine months ended September 30, 2013.

In November 2013, we closed on an amendment and restatement of the revolving credit facility which: (i) increases the borrowing capacity to $700.0 million, (ii) extends the maturity to November 2018, (iii) includes a $200.0 million accordion feature, (iv) reduces the leverage-based pricing grid by 0.75% to a new range of 1.75% to 2.75%, (v) changes the commitment fee to a leverage-based range of 0.30% to 0.50%, and (vi) adds Finance Corp. as a subsidiary guarantor.

Senior Notes. On June 17, 2013, Summit Holdings and its 100% owned finance subsidiary, Finance Corp. (together with Summit Holdings, the "Co-Issuers"), issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021 (the "senior notes"). The senior notes were sold within the United States only to qualified institutional buyers in reliance on Rule 144A under the Securities Act of 1933, as amended (the "Securities Act"), and outside the United States only to non-U.S. persons in reliance on Regulation S under the Securities Act. The senior notes have not been registered under the Securities Act or any state securities laws, and, unless so registered, may not

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be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws.

We will pay interest on the senior notes semi-annually in cash in arrears on January 1 and July 1 of each year, commencing January 1, 2014. The senior notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 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 senior notes to repay a portion of the balance outstanding under our revolving credit facility. Debt issuance costs of $7.3 million, recognized in other noncurrent assets, are being amortized over the life of the senior notes.

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

Under a registration rights agreement, the Co-Issuers and the Guarantors have agreed to file a registration statement with the SEC pursuant to which the Co-Issuers will either offer to exchange the senior notes and the guarantees for registered notes and guarantees with substantially identical terms or, in certain circumstances, register the resale of the senior notes and their guarantees (the "Exchange Offer").

If the Exchange Offer is not completed (or, if required, the shelf registration statement is not declared effective or does not automatically become effective) on or before the 365th day following the date of issuance of the senior notes (the ‘‘Exchange Completion Deadline’’), the Co-Issuers will be required to pay additional interest in an amount equal to 0.25% per annum of the principal amount of senior notes with respect to the first 90-day period following the Exchange Completion Deadline. The amount of the additional interest will increase by an additional 0.25% per annum with respect to each subsequent 90-day period, up to a maximum amount of additional interest of 1.0% per annum of the principal amount of senior notes outstanding until the Exchange Offer is completed or the shelf registration statement is declared effective (or becomes automatically effective). All accrued additional interest will be paid by the Co-Issuers and the Guarantors on the next scheduled interest payment date in the same manner as other interest is paid on the senior notes. Following the time that the senior notes are registered, the accrual of additional interest will cease.

At any time prior to July 1, 2016, the Co-Issuers may redeem up to 35% of the aggregate principal amount of the senior notes at a redemption price of 107.500% of the principal amount of the senior notes, plus accrued and unpaid interest, if any, to the redemption date, with an amount not greater than the net cash proceeds of certain equity offerings. On and after July 1, 2016, the Co-Issuers may redeem all or part of the senior notes at a redemption price of 105.625% (with the redemption premium declining ratably each year to 100.000% on July 1, 2019), plus accrued and unpaid interest, if any.

The 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 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 senior notes; (ii) default in the payment when due of the principal of, or premium, if any, on the 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

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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 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 senior notes may declare all the senior notes to be due and payable immediately.

There were no defaults or events of default during the period from issuance through September 30, 2013.

6. PARTNERS' CAPITAL AND MEMBERSHIP INTERESTS

Partners' Capital

SMLP was formed in May 2012. Prior to the closing of its IPO on October 3, 2012, SMLP had no outstanding common or subordinated units or operations. A rollforward of the number of common limited partner, subordinated limited partner and general partner units from December 31, 2012 to September 30, 2013 follows.

	Common	Subordinated	General partner	Total
Units, beginning of period	24,412,427	24,409,850	996,320	49,818,597
Units issued to SMP Holdings in connection with the Bison Drop Down	1,553,849	—	31,711	1,585,560
Units issued to SMP Holdings in connection with the Mountaineer Acquisition	3,107,698	—	63,422	3,171,120
Units issued	1,473	—	—	1,473
Units, end of period	29,075,447	24,409,850	1,091,453	54,576,750

Bison Drop Down. On June 4, 2013, SMLP acquired Bison Midstream from SMP Holdings. SMP Holdings contributed 100% of the membership interests in Bison Midstream to SMLP, which concurrently contributed the membership interests to Summit Holdings. In exchange for its $305.4 million net investment in Bison Midstream, SMLP paid SMP Holdings and the general partner total cash and unit consideration of $248.9 million. As a result of the contribution of net assets in excess of consideration, SMLP recognized a capital contribution from SMP Holdings. The details of total cash and unit consideration as well as the calculation of the capital contribution and its allocation to partners' capital follow.

	(Dollars in thousands)
SMP Holdings' net investment in Bison Midstream			$	305,449
Aggregate cash paid to SMP Holdings	$	200,000
Issuance of 1,553,849 SMLP common units to SMP Holdings	47,936
Issuance of 31,711 SMLP general partner units to the general partner	978
Total consideration			248,914
SMP Holdings' contribution of net assets in excess of consideration			$	56,535
Allocation of capital contribution:
General partner interest	$	1,131
Common limited partner interest	28,558
Subordinated limited partner interest	26,846
Partners' capital allocation			$	56,535

The number of units issued to SMP Holdings and the general partner in connection with the Bison Drop Down was calculated based on an assumed equity issuance of $50.0 million and the five-day volume-weighted-average price as of June 3, 2013 of $31.53 per unit. The units were then valued as of June 4, 2013 (the date of closing) using the June 4, 2013 closing price of SMLP's units of $30.85.

The general partner interest allocation was calculated based on a 2% general partner interest in the contribution of assets in excess of consideration given by SMLP to SMP Holdings. Common and subordinated limited partner

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interests allocations were calculated as their respective percentages of total limited partner capital applied to the balance of the contribution by SMP Holdings after giving effect to the general partner allocation. See Notes 1, 5 and 12 for additional information.

Mountaineer Acquisition. On June 4, 2013, SMLP executed definitive agreements with MarkWest to acquire the Mountaineer Midstream system. On June 21, 2013, prior to closing the Mountaineer Acquisition and in accordance with the definitive agreements with MarkWest (the "MarkWest Agreement"), Mountaineer Midstream acquired all of the Mountaineer Gathering system assets. The total acquisition purchase price of $210.0 million was funded with $110.0 million of borrowings under SMLP’s revolving credit facility and the issuance of $100.0 million of SMLP common units and general partner interests to SMP Holdings and the general partner for cash. The allocation and valuation of units issued to SMP Holdings and the general partner to partially fund the Mountaineer Acquisition follow.

	(Dollars in thousands)
Issuance of 3,107,698 SMLP common units to SMP Holdings	$	98,000
Issuance of 63,422 SMLP general partner units to the general partner	2,000
Issuance of units in connection with the Mountaineer Acquisition	$	100,000

Pursuant to a unit purchase agreement, the number of units issued to SMP Holdings and the general partner in connection with the Mountaineer Acquisition was calculated based on an assumed equity issuance of $100.0 million and the five-day volume-weighted-average price as of June 3, 2013 of $31.53 per unit. See Notes 1, 5 and 12 for additional information.

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.

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.

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Details of cash distributions declared during 2013 follow.

Attributable to the quarter ended	Payment date	Per-unit distribution		Cash paid (or payable) to common unitholders		Cash paid (or payable) to subordinated unitholders		Cash paid (or payable) to general partner		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

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 of 50.0% 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 of 50.0% 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

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necessary to maintain its 2.0% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.

	Total quarterly distribution per unit target amount	Marginal percentage interest in distributions
		Unitholders	General partner
Minimum quarterly distribution	$0.40	98.0%	2.0%
First target distribution	$0.40 up to $0.46	98.0%	2.0%
Second target distribution	above $0.46 up to $0.50	85.0%	15.0%
Third target distribution	above $0.50 up to $0.60	75.0%	25.0%
Thereafter	above $0.60	50.0%	50.0%

Membership Interests

Energy Capital Partners and GE Energy Financial Services hold membership interests in Summit Investments. Such membership interests give them the right to participate in distributions and to exercise the other rights or privileges available to each entity under Summit Investments' Amended and Restated Limited Liability Operating Agreement (the "Summit LLC Agreement"). In addition, certain members of Summit Investments’ management hold ownership interests in the form of Class B membership interests (the "SMP Net Profits Interests") through their ownership in Summit Midstream Management, LLC.

In accordance with the Summit LLC Agreement, capital accounts are maintained for Summit Investments’ members. The capital account provisions of the Summit LLC Agreement incorporate principles established for U.S. federal income tax purposes and as such are not comparable to the equity accounts reflected under GAAP in our consolidated financial statements.

The Summit LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that its membership interest holders will receive. Capital contributions required under the Summit LLC Agreement are in proportion to the members' respective percentage ownership interests. The Summit LLC Agreement also contains provisions for the allocation of net earnings and losses to members. For purposes of maintaining partner capital accounts, the Summit LLC Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests.

In April 2013, we repurchased the outstanding net profits interests in DFW Midstream. See Note 8 for additional information.

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7. EARNINGS PER UNIT

The following table presents details on EPU.

	Three months ended September 30, 2013		Nine months ended September 30, 2013
	(Dollars in thousands, except per-unit amounts)
Net income	$	6,691	$	27,291
Less: net income attributable to SMP Holdings	—		52
Net income attributable to partners	6,691		27,239
Less: net income attributable to general partner	134		545
Net income attributable to limited partners	$	6,557	$	26,694
Net income attributable to common units	$	3,567	$	14,899
Weighted-average common units outstanding – basic	29,074,743		26,234,042
Earnings per common unit – basic	$	0.12	$	0.57
Weighted-average common units outstanding – diluted	29,227,041		26,352,234
Earnings per common unit – diluted	$	0.12	$	0.57
Net income attributable to subordinated units	$	2,990	$	11,795
Weighted-average subordinated units outstanding – basic and diluted	24,409,850		24,409,850
Earnings per subordinated unit – basic and diluted	$	0.12	$	0.48

The effect of nonvested phantom units and nonvested restricted units on the weighted-average number of units used to calculate diluted earnings per common limited partner unit was 152,298 units for the three months ended September 30, 2013 and 118,192 units for the nine months ended September 30, 2013. There were no units excluded from diluted earnings per unit as we do not have any anti-dilutive units for the three and nine months ended September 30,2013. See Note 8 for additional information.

8. UNIT-BASED COMPENSATION

Long-Term Incentive Plan. The Long-Term Incentive Plan (the "LTIP") provides for equity awards to eligible officers, employees, consultants and directors of our general partner and its affiliates, thereby linking the recipients' compensation directly to SMLP’s performance. The LTIP is administered by our general partner's board of directors, though such administration function may be delegated to a committee appointed by the board. A total of 5.0 million common units was reserved for issuance pursuant to and in accordance with the LTIP. As of September 30, 2013, approximately 4.7 million common units remained available for future issuance.

The LTIP provides for the granting, from time to time, of unit-based awards, including common units, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Grants are made at the discretion of the board of directors or compensation committee of our general partner. The administrator of the LTIP may make grants under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including vesting conditions. The administrator of the LTIP may, in its discretion, base vesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement. Termination of employment prior to vesting will result in forfeiture of the awards, except in limited circumstances as described in the plan documents. Units that are canceled or forfeited will be available for delivery pursuant to other awards.

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The following table presents phantom and restricted unit activity:

	Units		Weighted-average grant date fair value
Nonvested phantom and restricted units, January 1, 2013	131,558		$	20.00
Phantom units granted	155,330		$	26.33
Restricted units granted	835		$	27.50
Phantom units forfeited	(4,041	)	$	25.99
Nonvested phantom and restricted units, September 30, 2013	283,682		$	23.41

A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. Distribution equivalent rights for each phantom unit provide for a lump sum cash amount equal to the accrued distributions from the grant date to be paid in cash upon the vesting date. The phantom units granted in 2013 vest ratably over a three-year period. Upon vesting, awards may be settled in cash and/or common units, at the discretion of the board of directors.

Upon vesting, management intends to settle all phantom unit awards with common units. As of September 30, 2013, the unrecognized unit-based compensation related to the LTIP was $4.4 million. Incremental unit-based compensation will be recorded over the remaining vesting period of 2.92 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 September 30, 2013		Nine months ended September 30, 2013
	(In thousands)
SMLP unit-based compensation	$	829	$	1,970

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 award agreement and the DFW Midstream Amended and Restated Limited Liability Company Agreement and Contribution Agreement).

We recognized unit-based compensation ratably over the respective award's vesting period. Unit-based compensation recognized in general and administrative expense related to the DFW Net Profits Interests was as follows:

	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(In thousands)
Class B membership interest unit-based compensation	$	—	$	75	$	17	$	874

Beginning in October 2012 and continuing into April 2013, we entered into a series of repurchases with the remaining seven holders of the then-outstanding DFW Net Profits Interests whereby we exchanged $12.2 million for their vested DFW Net Profits Interests and 7,393 SMLP restricted units for their unvested DFW Net Profits Interests. The repurchase prices were determined by valuing the vested and unvested net profits interests in relation to the enterprise value of DFW Midstream and represented fair value at the dates of repurchase. Upon the conclusion of these repurchase transactions, there were no remaining or outstanding DFW Net Profits Interests as of April 30, 2013.

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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, at times, may 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 are primarily from natural gas producers shipping natural gas. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of our counterparties and generally 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 September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Revenue:
Counterparty A	17	%	29	%	19	%	19	%
Counterparty B	16	%	29	%	18	%	27	%
Counterparty C	10	%	—	%	9	%	—	%
Counterparty D	10	%	—	%	9	%	—	%
Counterparty E	*		13	%	*		14	%

__________

* Less than 10%

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

	September 30,		December 31,
	2013		2012
Accounts receivable:
Counterparty A	23	%	24	%
Counterparty B	21	%	38	%
Counterparty C	*		—	%
Counterparty D	*		—	%
Counterparty E	*		*

__________

* Less than 10%

10. RELATED-PARTY TRANSACTIONS

Recent Acquisitions and Partners' Capital Issuances. See Notes 5, 6 and 12 for disclosure of the purchase of Bison Midstream from SMP Holdings and the issuance of common units and general partner interests to SMP Holdings in connection with the Bison Drop Down and the Mountaineer Acquisition.

General and Administrative Expense Allocation. 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.

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The payable to our general partner for expenses that were paid on our behalf and the receivable from the general partner for expenses that we paid that were not allocated to the Partnership were as follows:

	September 30,		December 31,
	2013		2012
	(In thousands)
Due to affiliate	$	430	$	—
Due from affiliate	—		774

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

	Three months ended September 30, 2013		Nine months ended September 30, 2013
	(In thousands)
General and administrative expense allocation	$	794	$	2,600

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. Amounts paid for such services were as follows:

	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(In thousands)
Payments for electricity management consulting services	$	54	$	56	$	163	$	144

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 September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(In thousands)
Total rent expense	$	312	$	189	$	819	$	504

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.

In August 2012, four former DFW Midstream employees (the "Plaintiffs") who, by virtue of their Class B membership in DFW Midstream Management LLC ("DFW Management"), filed a claim in the Court of Chancery of the State of Delaware against Summit Investments, Summit Holdings, DFW Midstream and DFW Management (collectively, the "Defendants") seeking dissolution and wind-up of DFW Midstream and DFW Management or, in the alternative, a repurchase of the Plaintiffs' net profits interests and other unspecified monetary damages. In September 2012, the Defendants filed a motion to dismiss all of Plaintiffs’ claims in this matter.  The court heard oral arguments on the motion to dismiss in December 2012, and Defendants' motion to dismiss was granted in March 2013. In April 2013, the Plaintiffs voluntarily dismissed their appeal.

12. ACQUISITIONS

Bison Gas Gathering System.On February 15, 2013, Summit Investments acquired BTE and subsequently contributed it to SMP Holdings. On June 4, 2013, SMP Holdings 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

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from BTE and primarily gathers natural gas production from Mountrail and Burke counties in North Dakota under long-term contracts ranging from five years to 15 years. For additional information, see Notes 1, 5 and 6.

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 right-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 various systems.

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 SMP Holdings and $1.0 million of general partner interests to SMLP’s general partner. SMP Holdings had a net investment in the Bison Gas Gathering system of $303.2 million and received total consideration of $248.9 million from SMLP. As a result, SMLP recognized a capital contribution from SMP Holdings for the contribution of net assets in excess of consideration paid. See Notes 5 and 6 for additional information.

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As noted above, SMLP's acquisition of the Bison Gas Gathering system was a transaction between commonly controlled entities which required that SMLP account for the acquisition in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership 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 in February 2013. Revenues and net income for the previously separate entities and the combined amounts for the nine months ended September 30, 2013, as presented in these unaudited condensed consolidated financial statements follow.

	Nine months ended September 30, 2013
	(In thousands)
SMLP revenues	$	155,894
Bison Gas Gathering system revenues	17,614
Combined revenues	$	173,508
SMLP net income	$	27,239
Bison Gas Gathering system net income	52
Combined net income	$	27,291

See Notes 1, 5 and 6 for additional information.

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 County 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 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 SMP Holdings. For the three months ended September 30, 2013, SMLP recorded $4.3 million of revenue and $1.3 million of net income related to Mountaineer Midstream. For the nine months ended September 30, 2013, SMLP recorded $4.7 million of revenue and $1.6 million of net income related to Mountaineer Midstream.

SMLP is accounting for the Mountaineer Acquisition under the acquisition method of accounting and is currently in the process of determining the assets acquired and the liabilities assumed. As of June 30, 2013, we preliminarily assigned the full $210.0 million purchase price to property plant and equipment. During the third quarter of 2013, we received additional information and, as a result, preliminarily assigned $158.3 million of the purchase price to property, plant and equipment, $27.1 million to contract intangibles, $6.5 million to rights-of-way and $18.1 million to goodwill. We have not completed the final purchase price allocation as of September 30, 2013, because we are waiting to receive additional information from MarkWest related to closing balance sheet and working capital adjustments and the finalization of the fair value estimates of the acquired assets and liabilities.

See Notes 1, 5 and 6 for additional information.

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Unaudited Pro Forma Financial Information. The following unaudited pro forma financial information assumes that the acquisitions of Bison Midstream and Mountaineer Midstream occurred on January 1, 2012. The pro forma results for Bison Midstream were derived from revenues and net income in 2013 and 2012. The pro forma results for Mountaineer Midstream were derived from revenues and net income in 2013. Mountaineer Midstream was not operational until November 2012. The pro forma adjustments also reflect the impact of $310.0 million of incremental borrowings on our revolving credit facility 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. Pro forma net income for the nine months ended September 30, 2013 has been adjusted to remove the impact of $2.5 million of nonrecurring transaction costs incurred during the nine months ended September 30, 2013.

	Three months ended September 30, 2012		Nine months ended September 30,
			2013		2012
	(In thousands, except per-unit amounts)
Total Bison Midstream and Mountaineer Midstream revenues included in consolidated revenues	$	—	$	44,176	$	—
Total Bison Midstream and Mountaineer Midstream net income included in consolidated net income	—		911		—
Pro forma total revenues	$	50,731	$	185,659	$	141,372
Pro forma net income	6,014		24,316		16,549
Pro forma common EPU - basic and diluted			$	0.44
Pro forma subordinated EPU - basic and diluted			0.44

The unaudited pro forma financial information presented above is not necessarily indicative of 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 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, 2012. 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 2012 Annual Report on Form 10-K (the "2012 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 "Risk Factors" in Item 1A. Risk Factors 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 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 currently provide primarily fee-based natural gas gathering and compression services in four unconventional resource basins: (i) the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado; (ii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; (iii) the Williston Basin, which includes the Bakken and Three Forks

25

shale formations in northwestern North Dakota; and (iv) the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia.

We generate a substantial majority of our revenue under long-term, primarily fee-based natural gas gathering agreements. Substantially all of our gas gathering agreements are underpinned by areas of mutual interest and MVCs. Our areas of mutual interest cover approximately 1,013,800 acres in the aggregate, have original terms that range from five years to 25 years, and provide that any natural gas producing wells drilled by our customers within the areas of mutual interest will be shipped on our gathering systems. The MVCs, which totaled 3.2 Tcf at September 30, 2013 and average approximately 881 MMcf/d through 2020, 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 three to 13 years and, as of September 30, 2013, had a weighted-average remaining life of 10.1 years, assuming minimum throughput volumes for the remainder of the term. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure. For additional information, see the Our Operations section included in the 2012 Annual Report.

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 supply and demand dynamics;

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

• Interest rate environment; and

• Rising operating costs and inflation.

In addition, in connection with the Bison Drop Down, we are now affected by crude oil supply and demand dynamics. Crude oil has been the focus of recent upstream activity in the United States and continues to play a significant role in the energy market. United States domestic crude oil production has increased by 30% from 5.0 MMBbl/d in 2008 to 6.5 MMBbl/d in 2012 according to the U.S. Energy Information Administration (the "EIA"). Over the long term, the domestic production of crude oil will continue to increase according to the EIA. The growth will continue to come from increases in shale and tight crude oil production, which will be spurred by additional technological advances and elevated oil prices. According to the EIA, about 25.3 billion barrels of tight oil will be produced in the U.S. cumulatively from 2012 through 2040 and the Bakken Shale is expected to contribute 32% of this production. For additional information, see the Trends and Outlook section included in the 2012 Annual Report.

How We Evaluate Our Operations

We conduct our operations in the midstream sector with 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 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.

Throughput Volume

The volume of natural gas that we gather depends on the level of production from natural gas wells connected to the Grand River, DFW Midstream, Bison Midstream and Mountaineer Midstream systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity, as production must be maintained or increased by new drilling or other activity, because the production rate of oil and natural gas wells decline over time.

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As a result, we must continually obtain new supplies of natural gas to maintain or increase the throughput volume on our systems. Our ability to maintain or increase throughput volumes from existing customers and obtain new supplies of natural gas is impacted by:

• successful drilling activity within our areas of mutual interest;

• the level of work-overs and recompletions of wells on existing pad sites to which our gathering systems are connected;

• the number of new pad sites in our areas of mutual interest awaiting connections;

• our ability to compete for volumes from successful new wells in the areas in which we operate outside of our existing areas of mutual interest; and

• our ability to gather natural gas that has been released from commitments with our competitors.

Operation and Maintenance Expenses

We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating our assets. Direct labor costs, compression costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are relatively stable and largely independent of volumes delivered through our gathering systems but may fluctuate depending on the activities performed during a specific period.

The majority of the compressors on our DFW Midstream system are electric driven and power costs are directly correlated to the run-time of these compressors, which depends directly on the volume of natural gas gathered. As part of our contracts with our DFW Midstream system customers, we physically retain a percentage of throughput volumes that we subsequently sell to offset the power costs we incur. In addition, we pass along the fees associated with costs we incur on behalf of certain DFW Midstream system customers to deliver pipeline quality natural gas to third-party pipelines. With respect to the Grand River, Bison Midstream and Mountaineer Midstream systems, we either (i) consume physical gas on the system to operate our gas-fired compressors or (ii) charge our customers for the power costs we incur to operate our electric-drive compressors.

EBITDA, Adjusted EBITDA and Distributable Cash Flow

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 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.

EBITDA and adjusted EBITDA are used to assess:

• the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

• the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;

• our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and

• the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

In addition, adjusted EBITDA is used to assess:

• the financial performance of our assets without regard to the impact of the timing of minimum volume commitments shortfall payments under our gas gathering agreements, the impact of unit-based compensation or the timing of gain or loss on asset sales.

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Distributable cash flow is used to assess:

• the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and

• the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

Results of Operations

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

	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
	(Dollars in thousands)
Revenues:
Gathering services and other fees	$	45,968		$	37,903		$	127,098		$	106,550
Natural gas, NGLs and condensate sales and other	17,392			3,232			47,204			10,290
Amortization of favorable and unfavorable contracts (1)	(264		)	(160		)	(794		)	25
Total revenues	63,096			40,975			173,508			116,865
Costs and expenses:
Operation and maintenance	15,918			14,460			45,467			37,177
Cost of natural gas and NGLs	10,464			—			24,328			—
General and administrative	6,248			5,179			18,198			15,977
Transaction costs	123			1,739			2,549			1,972
Depreciation and amortization	16,426			9,156			43,146			26,135
Total costs and expenses	49,179			30,534			133,688			81,261
Other (expense) income	(112		)	2			(110		)	8
Interest expense	(6,937		)	(2,827		)	(11,840		)	(5,573		)
Affiliated interest expense	—			(13		)	—			(5,426		)
Income before income taxes	6,868			7,603			27,870			24,613
Income tax expense	(177		)	(207		)	(579		)	(501		)
Net income	$	6,691		$	7,396		$	27,291		$	24,112
Other Financial Data (2):
EBITDA (3)	$	30,494		$	19,757		$	83,647		$	61,714
Adjusted EBITDA (3)	39,103			23,124			106,458			74,668
Capital expenditures (4)	20,718			36,284			62,317			60,647
Acquisition capital expenditures (5)	—			—			458,914			—
Distributable cash flow (4)	27,919			18,579			83,411			63,832
Operating Data:
Miles of pipeline (end of period)	790			392			790			392
Aggregate average throughput (MMcf/d)	1,022			958			964			928

__________

(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) 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.

28

(3) EBITDA and adjusted EBITDA include transaction costs. These unusual and non-recurring expenses are settled in cash.

(4) In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. For the three and nine months ended September 30, 2012, the calculation of distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.

(5) Reflects cash paid and value of units issued to fund acquisitions.

Items Affecting the Comparability of Our Financial Results

SMLP's future results of operations may not be comparable to the historical results of operations for the reasons described below:

• Based on the terms of our partnership agreement, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our revolving credit facility and future issuances of equity and debt securities. Prior to the IPO, we largely relied on internally generated cash flows and capital contributions from the Sponsors to satisfy our capital expenditure requirements;

• The historical results of operations may not be comparable to our future results of operations due in part to:

• Our June 2013 acquisitions. The unaudited condensed consolidated financial statements reflect the results of operations of: (i) Bison Midstream since February 16, 2013 and (ii) Mountaineer Midstream since June 22, 2013. For additional information, see Notes 1, 5, 6 and 12 to the unaudited condensed consolidated financial statements; and

• Our IPO, which was completed on October 3, 2012. We anticipate incurring approximately $2.5 million (annualized) of general and administrative expenses attributable to operating as a publicly traded partnership. These incremental general and administrative expenses are not reflected in our results of operations prior to the IPO.

29

Three Months Ended September 30, 2013 Compared with the Three Months Ended September 30, 2012

The following table presents certain consolidated and other financial and operating data.

	Three months ended September 30,						Change
	2013			2012			$			%
	(Dollars in thousands)
Statement of Operations Data:
Revenues:
Gathering services and other fees	$	45,968		$	37,903		$	8,065		21	%
Natural gas, NGLs and condensate sales and other	17,392			3,232			14,160			438	%
Amortization of favorable and unfavorable contracts (1)	(264		)	(160		)	(104		)	65	%
Total revenues	63,096			40,975			22,121			54	%
Costs and expenses:
Operation and maintenance	15,918			14,460			1,458			10	%
Cost of natural gas and NGLs	10,464			—			10,464			—
General and administrative	6,248			5,179			1,069			21	%
Transaction costs	123			1,739			(1,616		)	(93	)%
Depreciation and amortization	16,426			9,156			7,270			79	%
Total costs and expenses	49,179			30,534			18,645			61	%
Other (expense) income	(112		)	2			(114		)	—
Interest expense	(6,937		)	(2,827		)	(4,110		)	145	%
Affiliated interest expense	—			(13		)	13			—
Income before income taxes	6,868			7,603			(735		)	(10	)%
Income tax expense	(177		)	(207		)	30			(14	)%
Net income	$	6,691		$	7,396		$	(705	)	(10	)%
Other Financial Data (2):
EBITDA (3)	$	30,494		$	19,757		$	10,737		54	%
Adjusted EBITDA (3)	39,103			23,124			15,979			69	%
Capital expenditures (4)	20,718			36,284			(15,566		)	(43	)%
Distributable cash flow (4)	27,919			18,579			9,340			50	%
Operating Data:
Miles of pipeline (end of period)	790			392			398			102	%
Aggregate average throughput (MMcf/d)	1,022			958			64			7	%

__________

(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) 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) EBITDA and adjusted EBITDA include transaction costs. These unusual and non-recurring expenses are settled in cash.

(4) In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. For the three months ended September 30, 2012, the calculation of distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.

30

Volume. Our revenues are primarily attributable to the volume of natural gas that we gather and compress and the rates we charge for those services. Throughput volumes increased to an average of 1,022 MMcf/d for the three months ended September 30, 2013, compared with an average of 958 MMcf/d in the prior-year period. The increase in volume throughput largely reflects the contribution from Bison Midstream and Mountaineer Midstream, partially offset by volume declines on the Grand River system. Operating data by system as of or for the three months ended September 30 follows:

	Grand River		DFW Midstream		Bison Midstream		Mountaineer Midstream
	2013	2012	2013	2012	2013	2012	2013	2012
Miles of pipeline (end of period)	301	282	119	110	330	*	41	*
Aggregate average throughput (for the quarter-to-date period)(MMcf/d)	489	578	381	380	17	*	135	*

__________

* Gathering system was not an asset of SMLP during this period.

Grand River system volume throughput declined in the third quarter of 2013 primarily due to lower drilling activity and the natural decline of previously drilled Mancos/Niobrara wells in the Orchard Field. Our gas gathering agreements for the Grand River system include MVCs that, in the aggregate, increase over the next several years. As a result, the lower volume throughput for the Grand River system during the third quarter of 2013 primarily translated into larger MVC shortfall payments.

Volume throughput for the DFW Midstream system was flat due to multiple customers temporarily shutting-in several large pad sites during the quarter to drill and/or complete new wells. While this activity is beneficial over the long term, it can create volume and cash flow volatility.

Bison Midstream volume throughput during the third quarter of 2013 was impacted by temporary operational interruptions across the system due to increased levels of produced water in the pipelines. These operational issues, which are being remediated, are expected to be resolved in the near term. Third quarter 2013 volume throughput was also impacted by temporary interruptions which occurred throughout the quarter as we continued to install new compression assets designed to increase throughput capacity on the Bison Midstream system.

Volume throughput for the Mountaineer Midstream system in the third quarter of 2013 was impacted by temporary processing capacity curtailments resulting from a line break on one of MarkWest’s NGL pipelines which forced Mountaineer Midstream to curtail its natural gas deliveries to MarkWest's processing plant beginning in August 2013. The affected NGL pipeline was returned to service mid-October 2013 and had returned to pre-curtailment levels by November 2013.

Revenues. Total revenues increased for the three months ended September 30, 2013, largely as a result of Bison Midstream's contribution to natural gas, NGLs and condensate sales and other, Mountaineer Midstream's contribution to gathering services and other fees and DFW Midstream's overall contribution. Total revenues for the three months ended September 30, 2013 included a $16.4 million contribution from Bison Midstream and a $4.3 million contribution from Mountaineer Midstream.

Gathering services and other fees increased during the three months ended September 30, 2013, primarily as a result of a $4.4 million contribution from Bison Midstream and a $4.3 million contribution from Mountaineer Midstream. The aggregate average throughput rate for the three months ended September 30, 2013 was approximately $0.47 per Mcf, compared with approximately $0.40 per Mcf for the three months ended September 30, 2012. The period-over-period increase was largely driven by the proportionate contribution of throughput volumes from our DFW Midstream system which has a higher average gathering fee per Mcf. Additionally, the period-over-period increase in aggregate average throughput rate also benefited from gas gathering agreement provisions which increased the average gas gathering fee per Mcf on our Grand River system beginning in January 2013. These contractual provisions helped partially offset the financial impact of the volume decreases on the Grand River system. The impact of Bison Midstream's higher rates were largely offset by the lower average gathering fee per Mcf received on the Mountaineer Midstream system.

The increase in natural gas, NGLs and condensate sales and other primarily reflects a $12.0 million contribution from Bison Midstream as well as a $2.0 million increase on our DFW Midstream system as a result of an increase in the prices we were able to obtain for natural gas sales.

31

Operation and Maintenance Expense. Operation and maintenance expense increasedduring the three months ended September 30, 2013, largely reflecting contributions from the Bison Midstream and Mountaineer Midstream systems, an increase in operation and maintenance expense for the DFW Midstream system and a decline in operation and maintenance expense on the Grand River system. Of the $1.5 million increase during the three months ended September 30, 2013, Bison Midstream accounted for $1.4 million and Mountaineer Midstream accounted for $1.2 million. The increase in operation and maintenance expense also reflects $0.6 million of higher power-related costs for DFW Midstream and a $0.3 million increase in carbon dioxide expenses for DFW Midstream. The increase in operation and maintenance expense was partially offset by the impact of a net $1.2 million decline in compressor lease and contract maintenance expenses primarily as a result of our purchase of previously leased compression assets in the first quarter of 2013 and a $0.9 million net decrease in property tax expenses due to a change in our estimate for property tax expenses in the third quarter of 2012.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs represents the expenses associated with the percent-of-proceeds arrangements under which Bison Midstream sells natural gas purchased from our customers.

General and Administrative Expense. General and administrative expense increased during the three months ended September 30, 2013, largely as a result of the expenses recognized for the Bison Midstream and Mountaineer Midstream systems. Of the total increase in general and administrative expense, Bison Midstream system accounted for $0.7 million and Mountaineer Midstream accounted for $0.4 million. General and administrative expense also reflects an increase in salaries, benefits and incentive compensation largely as a result of an increase in headcount.

Transaction Costs. Transaction costs of $1.7 million in the prior-year period largely reflect costs associated with Summit Investments' acquisition of the Red Rock Gathering system. Red Rock was not contributed to SMLP and is not an asset of SMLP.

Depreciation and Amortization Expense. Depreciation and amortization expense increased during the three months ended September 30, 2013 largely due to recognizing depreciation and amortization from the Bison Midstream and Mountaineer Midstream systems. Of the increase in depreciation and amortization for the three months ended September 30, 2013, Bison Midstream accounted for $4.7 million and Mountaineer Midstream accounted for $1.5 million. An increase in contract amortization for the Grand River system and assets placed into service in connection with the development of the DFW Midstream and Grand River systems also contributed to the increase.

Interest Expense and Affiliated Interest Expense. Interest expense increased during the three months ended September 30, 2013, primarily as a result of our issuance of $300.0 million of 7.50% senior notes in June 2013. The increase in interest expense due to the senior notes was partially offset by the impact of a lower balance on our revolving credit facility in the third quarter of 2013 when compared with the third quarter of 2012.

32

Nine Months Ended September 30, 2013 Compared with the Nine Months Ended September 30, 2012

The following table presents certain consolidated and other financial and operating data.

	Nine months ended September 30,						Change
	2013			2012			$			%
	(Dollars in thousands)
Statement of Operations Data:
Revenues:
Gathering services and other fees	$	127,098		$	106,550		$	20,548		19	%
Natural gas, NGLs and condensate sales and other	47,204			10,290			36,914			359	%
Amortization of favorable and unfavorable contracts (1)	(794		)	25			(819		)	—
Total revenues	173,508			116,865			56,643			48	%
Costs and expenses:
Operation and maintenance	45,467			37,177			8,290			22	%
Cost of natural gas and NGLs	24,328			—			24,328			—
General and administrative	18,198			15,977			2,221			14	%
Transaction costs	2,549			1,972			577			29	%
Depreciation and amortization	43,146			26,135			17,011			65	%
Total costs and expenses	133,688			81,261			52,427			65	%
Other (expense) income	(110		)	8			(118		)	—
Interest expense	(11,840		)	(5,573		)	(6,267		)	112	%
Affiliated interest expense	—			(5,426		)	5,426			(100	)%
Income before income taxes	27,870			24,613			3,257			13	%
Income tax expense	(579		)	(501		)	(78		)	16	%
Net income	$	27,291		$	24,112		$	3,179		13	%
Other Financial Data (2):
EBITDA (3)	$	83,647		$	61,714		$	21,933		36	%
Adjusted EBITDA (3)	106,458			74,668			31,790			43	%
Capital expenditures (4)	62,317			60,647			1,670			3	%
Acquisition capital expenditures (5)	458,914			—			458,914			—
Distributable cash flow (4)	83,411			63,832			19,579			31	%
Operating Data:
Miles of pipeline (end of period)	790			392			398			102	%
Aggregate average throughput (MMcf/d)	964			928			36			4	%

__________

(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) 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) EBITDA and adjusted EBITDA include transaction costs. These unusual and non-recurring expenses are settled in cash.

(4) In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. For the nine months ended September 30, 2012, the calculation of distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.

33

(5) Reflects cash paid and value of units issued to fund acquisitions.

Volume. Our revenues are primarily attributable to the volume of natural gas that we gather and compress and the rates we charge for those services. Throughput volumes increased to an average of 964 MMcf/d for the nine months ended September 30, 2013, compared with an average of 928 MMcf/d in the prior-year period. The increase in volume throughput largely reflects the combined effect of contributions from Bison Midstream and Mountaineer Midstream and a production curtailment by one of our largest producer customers on the DFW Midstream system in the first and second quarters of 2012, partially offset by the volume throughput declines on the Grand River system. Operating data by system as of or for the nine months ended September 30 follows.

	Grand River		DFW Midstream		Bison Midstream		Mountaineer Midstream
	2013	2012	2013	2012	2013	2012	2013	2012
Miles of pipeline (end of period)	301	282	119	110	330	*	41	*
Aggregate average throughput (for the year-to-date period)(MMcf/d)	502	585	398	344	14	*	50	*

__________

* Gathering system was not an asset of SMLP during this period.

Grand River system volume throughput declined in the first nine months of 2013 primarily due to lower drilling activity and the natural decline of previously drilled Mancos/Niobrara wells in the Orchard Field. Our gas gathering agreements for the Grand River system include MVCs that, in the aggregate, increase over the next several years. As a result, the lower volume throughput for the Grand River system during the first nine months of 2013 primarily translated into larger MVC shortfall payments.

The increase in DFW Midstream system volume throughput was primarily due to the prior-year impact of the production curtailment noted above. Volume throughput for the nine months ended September 30, 2013 also benefited from the continued development of the DFW Midstream system, most notably our January 2013 commissioning of a compressor which increased system throughput capacity from 410 MMcf/d to 450 MMcf/d. Volume throughput for the DFW Midstream system for the nine month period ended September 30, 2013 was also impacted by multiple customers temporarily shutting-in several large pad sites during the third quarter to drill and/or complete new wells.

Bison Midstream volume throughput during the nine months ended September 30, 2013, was impacted by temporary operational interruptions across the system due to increased levels of produced water in the pipelines during the third quarter of 2013. These operational issues, which are being remediated, are expected to be resolved during the fourth quarter of 2013. Volume throughput was also impacted by temporary interruptions which occurred throughout the second and third quarters of 2013 as we continued to install new compression assets designed to increase throughput capacity on the Bison Midstream system.

Volume throughput for the Mountaineer Midstream system since our acquisition in late June 2013 was impacted by temporary processing capacity curtailments resulting from a line break on one of MarkWest’s NGL pipelines which forced Mountaineer Midstream to curtail its natural gas deliveries to MarkWest's processing plant beginning in August 2013. The affected NGL pipeline was returned to service mid-October 2013 and had returned to pre-curtailment levels by November 2013.

Revenues. Total revenues increased for the nine months ended September 30, 2013, largely due to the revenue from the Bison Midstream system and an increase in revenues for the DFW Midstream system. Mountaineer Midstream also contributed to the increase in total revenues. Total revenues for the nine months ended September 30, 2013 included a $39.5 million contribution from Bison Midstream and a $4.7 million contribution from Mountaineer Midstream.

The increase in gathering services and other fees during the nine months ended September 30, 2013, was largely driven by increased throughput volumes on the DFW Midstream system and our acquisitions of the Bison Midstream and Mountaineer Midstream systems. Gathering services and other fees for the nine months ended September 30, 2013 included a $9.7 million contribution from Bison Midstream and a $4.7 million contribution from Mountaineer Midstream. The aggregate average throughput rate for the nine months ended September 30, 2013 was approximately $0.47 per Mcf, compared with approximately $0.39 per Mcf for the nine months ended September 30, 2012. The period-over-period increase was largely driven by the proportionate contribution of throughput volumes from our DFW Midstream system which has a higher average gathering fee per Mcf.

34

Additionally, the period-over-period increase in aggregate average throughput rate benefited from gas gathering agreement provisions which increased the average gas gathering fee per Mcf on our Grand River system beginning in January 2013. These contractual provisions helped offset the financial impact of the volume decreases on the Grand River system. The impact of Bison Midstream's higher rates were largely offset by the lower average gathering fee per Mcf received on the Mountaineer Midstream system.

The increase in natural gas, NGLs and condensate sales and other for the nine months ended September 30, 2013, was primarily a result of the contribution from the Bison Midstream system, higher throughput volumes and the associated retainage on our DFW Midstream system, and an increase in the prices we were able to obtain for natural gas sales. Bison Midstream accounted for $29.8 million of the total increase in natural gas, NGLs and condensate sales and other for the nine months ended September 30, 2013. During that same period, natural gas, NGLs and condensate sales and other also benefited $0.7 million from condensate sales on our Grand River system.

Operation and Maintenance Expense. Operation and maintenance expense increasedduring the nine months ended September 30, 2013, largely as a result of increased expenses on the DFW Midstream system as well as expenses associated with the Bison Midstream and Mountaineer Midstream systems. The increase in expenses for the nine months ended September 30, 2013, reflects $4.2 million of higher power-related costs for DFW Midstream, a $1.3 million increase in carbon dioxide expenses for DFW Midstream, and a $0.9 million increase in field employee costs for the DFW Midstream and Grand River systems. Of the total increase in operation and maintenance expense for the nine months ended September 30, 2013, Bison Midstream accounted for $2.9 million and Mountaineer Midstream accounted for $1.3 million. The increase in operation and maintenance expense was partially offset by the impact of a $2.9 million decline in compressor lease and contract maintenance expenses primarily as a result of our purchase of previously leased compression assets in the first quarter of 2013.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs represents the expenses associated with the percent-of-proceeds arrangements under which Bison Midstream sells natural gas purchased from our customers.

General and Administrative Expense. General and administrative expense increased during the nine months ended September 30, 2013, primarily due to an increase in salaries, benefits and incentive compensation primarily as a result of increased head count. The Bison Midstream system accounted for $1.5 million and the Mountaineer Midstream system accounted for $0.4 million of general and administrative expense for the nine months ended September 30, 2013.

Transaction Costs. Transaction costs were $2.5 million for the nine months ended September 30, 2013, of which $0.7 million related to the acquisition of the Bison Midstream system and $1.8 million related to the acquisition of the Mountaineer Midstream system. Transaction costs of $2.0 million in the prior-year period largely reflect costs associated with Summit Investments' acquisition of the Red Rock Gathering system. Red Rock Gathering was not contributed to SMLP and is not an asset of SMLP.

Depreciation and Amortization Expense. Depreciation and amortization expense increased during the nine months ended September 30, 2013 largely due to recognizing depreciation and amortization from the Bison Midstream system. An increase in contract amortization for the Grand River system and assets placed into service in connection with the development of the DFW Midstream and Grand River systems also contributed to the increase. The Bison Midstream system accounted for $11.3 million of depreciation and amortization expense for the nine months ended September 30, 2013. Mountaineer Midstream also contributed $1.5 million to the increase in depreciation and amortization expense for the nine months ended September 30, 2013.

Interest Expense and Affiliated Interest Expense. The increase in interest expense during the nine months ended September 30, 2013, primarily reflects our issuance of $300.0 million of 7.50% senior notes in June 2013. Additionally, higher balances on our revolving credit facility beginning in May 2012 as well as an increase in commitment fees as a result of the May 2012 amendment and restatement of the revolving credit facility which increased our borrowing capacity by $265.0 million and the June 2013 amendment and restatement which increased our borrowing capacity by $50.0 million also contributed to the increase in interest expense. Affiliated interest expense for the nine months ended September 30, 2012 related to the $200.0 million promissory notes that we issued to the Sponsors in connection with the acquisition of the Grand River system in October 2011. The promissory notes were partially prepaid in May 2012 with the remaining balance prepaid in July 2012.

35

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 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.

36

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

	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(In thousands)
Reconciliation of Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
Net income	$	6,691	$	7,396	$	27,291	$	24,112
Add:
Interest expense	6,937		2,840		11,840		10,999
Income tax expense	177		207		579		501
Depreciation and amortization expense	16,426		9,156		43,146		26,135
Amortization of favorable and unfavorable contracts	264		160		794		(25		)
Less:
Interest income	1		2		3		8
EBITDA (1)	$	30,494	$	19,757	$	83,647	$	61,714
Add:
Unit-based compensation	829		381		1,987		1,793
Adjustments related to MVC shortfall payments (2)	7,667		2,986		20,711		11,161
Loss on asset sales	113		—		113		—
Adjusted EBITDA (1)	$	39,103	$	23,124	$	106,458	$	74,668
Add:
Interest income	1		2		3		8
Less:
Cash interest paid	2,534		2,683		6,548		6,274
Senior notes interest expense (3)	5,625		—		6,500		—
Cash taxes paid	—		650		660		650
Maintenance capital expenditures (4)	3,026		1,214		9,342		3,920
Distributable cash flow	$	27,919	$	18,579	$	83,411	$	63,832

__________

(1) EBITDA and adjusted EBITDA include 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 or will 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 expense represents interest expense recognized and accrued during the period.  Interest of 7.50% on the $300.0 million 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. In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. For the three and nine months ended September 30, 2012, the calculation of distributable cash flow and adjusted distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.

37

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

	Nine months ended September 30,
	2013			2012
	(In thousands)
Reconciliation of Net Cash Provided by Operating Activities to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
Net cash provided by operating activities	$	95,906		$	67,908
Add:
Interest expense (1)	10,249			4,555
Income tax expense	579			501
Changes in operating assets and liabilities	(20,984		)	(9,449		)
Less:
Unit-based compensation	1,987			1,793
Interest income	3			8
Loss on asset sales	113			—
EBITDA (2)	$	83,647		$	61,714
Add:
Unit-based compensation	1,987			1,793
Adjustments related to MVC shortfall payments (3)	20,711			11,161
Loss on asset sales	113			—
Adjusted EBITDA (2)	$	106,458		$	74,668
Add:
Interest income	3			8
Less:
Cash interest paid	6,548			6,274
Senior notes interest expense (4)	6,500			—
Cash taxes paid	660			650
Maintenance capital expenditures (5)	9,342			3,920
Distributable cash flow	$	83,411		$	63,832

__________

(1) 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 and pay-in-kind interest on the promissory notes payable to our Sponsors. For the nine months ended September 30, 2013, interest expense excluded $1.6 million of amortization of deferred loan costs. For the nine months ended September 30, 2012, interest expense excluded $1.0 million of amortization of deferred loan costs and $5.4 million of pay-in-kind interest.

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

(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 or will 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 expense represents interest expense recognized and accrued during the period.  Interest of 7.50% on the $300.0 million 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. In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. For the nine months ended September 30, 2012,

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the calculation of distributable cash flow and adjusted distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.

Liquidity and Capital Resources

In June 2013, we completed an offering of senior notes and issued common limited partner units and general partner interests in connection with the Bison Drop Down and the Mountaineer Acquisition. For additional information, see Note 5 to the unaudited condensed consolidated financial statements. In October 2012, we completed an IPO of our common units. For additional information, see Note 1 to the audited consolidated financial statements included in the 2012 Annual Report. 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.

In October 2013, SMLP filed a shelf registration statement with the SEC to register 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 SMP Holdings in accordance with our obligations under a registration rights agreement that was executed in connection with our IPO.

In November 2013, we closed on an amendment and restatement of the revolving credit facility which: (i) increases the borrowing capacity to $700.0 million, (ii) extends the maturity to November 2018, (iii) includes a $200.0 million accordion feature, (iv) reduces the leverage-based pricing grid by 0.75% to a new range of 1.75% to 2.75%, (v) changes the commitment fee to a leverage-based range of 0.30% to 0.50%, and (vi) adds Finance Corp. as a subsidiary guarantor. For additional information, see Long-Term Debt—Revolving Credit Facility below.

Cash Flows

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

	Nine months ended September 30,
	2013			2012
	(In thousands)
Net cash provided by operating activities	$	95,906		$	67,908
Net cash used in investing activities	(471,732		)	(60,647		)
Net cash provided by (used in) financing activities	383,214			(17,976		)
Change in cash and cash equivalents	$	7,388		$	(10,715	)

Operating activities. Cash flows from operating activities increased by $28.0 million for the nine months ended September 30, 2013 largely as result of the increase in volumes on the DFW Midstream system and the contribution from the Bison Midstream and Mountaineer Midstream systems, partially offset by a decline in volumes on the Grand River system.

Investing activities. Cash flows used in investing activities for the nine months ended September 30, 2013 were largely due to the acquisitions of Bison Midstream and Mountaineer Midstream. Additional expenditures in 2013 reflect the construction of seven miles 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 6,000 horsepower electric-drive compressor unit on the DFW Midstream system in January 2013, which increased system throughput capacity from 410 MMcf/d to 450 MMcf/d. Development activities also included construction projects to connect new receipt points on the Bison Midstream and DFW Midstream systems and to expand compression capacity on the Bison Midstream system. We also began construction on a new 150 gallon per minute natural gas treating facility on the DFW Midstream system, which is expected to be in service in the first quarter of 2014.

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Financing activities. Details of cash flows provided by (used in) financing activities for the nine months ended September 30, 2013 and 2012 were as follows:

	Nine months ended September 30,
	2013			2012
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	$	(65,088	)	$	—
Borrowings under revolving credit facility	360,000			213,000
Repayments under revolving credit facility	(294,180		)	(15,770		)
Issuance of senior notes	300,000			—
Contribution from SMP Holdings to Bison Midstream	2,229			—
Issuance of units in connection with the Mountaineer Acquisition	100,000			—
Repurchase of DFW Net Profits Interests	(11,957		)	—
Repayment of promissory notes payable to Sponsors	—			(209,230		)
Deferred loan costs and initial public offering costs	(7,790		)	(5,976		)
Net cash provided by (used in) financing activities	$	383,214		$	(17,976	)

Net cash used in financing activities for the nine months endedSeptember 30, 2013 was primarily composed of the following:

• Distributions declared in respect of the second quarter of 2013, the first quarter of 2013, and the fourth quarter of 2012 (paid in the first quarter of 2013) (see Note 6 to the unaudited condensed consolidated financial statements);

• 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 (see Notes 5, 6 and 12 to the unaudited condensed consolidated financial statements);

• 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 $7.3 million in connection with the senior notes issuance which will be amortized over the life of the senior notes (see Note 5 to the unaudited condensed consolidated financial statements);

• 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 (see Notes 6 and 12 to the unaudited condensed consolidated financial statements); and

• Our repurchase of the remaining vested DFW Net Profits Interests (see Notes 8 and 11 to the unaudited condensed consolidated financial statements).

Net cash used in financing activities for the nine months endedSeptember 30, 2012 was primarily composed of borrowings of $213.0 million under our revolving credit facility, of which $209.2 million was used to repay amounts outstanding under the promissory notes payable to Sponsors.

Contractual Obligations Update

The material changes in contractual obligations from those disclosed in the 2012 Annual Report include the June 2013 issuance of senior notes and activity associated with our revolving credit facility during 2013. See Note 5 to the unaudited condensed consolidated financial statements for additional information. The table below summarizes and updates our long-term debt and interest payments obligations as of December 31, 2012 after giving effect to these 2013 events:

	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(In thousands)
Long-term debt and interest payments (1)	$	773,770	$	9,573	$	64,147	$	45,000	$	655,050

__________

(1) Includes a 0.50% commitment fee on the unused portion of the revolving credit facility. See Note 5 to the unaudited condensed consolidated financial statements for additional information.

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Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the nine months endedSeptember 30, 2013.

Capital Requirements

The natural gas gathering segment of the midstream energy 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.

Total capital expenditures were as follows:

	Nine months ended September 30,
	2013		2012
	(In thousands)
Capital expenditures	$	62,317	$	60,647
Acquisitions of Bison Midstream and Mountaineer Midstream (1)	458,914		—

__________

(1) Reflects cash paid and value of units issued to fund acquisitions.

For the nine months ended September 30, 2013, development activities were primarily related to pipeline construction projects to connect new natural gas receipt points and to expand compression capacity across the our gas gathering systems. Capital expenditures also reflect the acquisition of previously leased compression assets for our Grand River system in the first quarter of 2013. For the nine months ended September 30, 2012, capital expenditures were largely the result of the construction of new pipeline and compression infrastructure to connect new pad sites on our DFW Midstream system. Acquisition capital expenditures reflect the cash effect of the Bison Drop Down and the Mountaineer Acquisition. See Notes 1, 5, 6, and 12 to the unaudited condensed consolidated financial statements.

In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. As a result, our calculation of distributable cash flow reflects an estimate for the portion of these expenditures that were maintenance capital expenditures in periods prior to the fourth quarter of 2012.

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 SMLP’s partnership agreement, SMLP expects that it will distribute to its unitholders most of the cash generated by its operations. As a result, SMLP expects to fund future capital expenditures from cash and cash equivalents on hand, non-distributed cash flow generated from its operations, borrowings under the revolving credit facility and future issuances of equity and debt securities. Historically, we have largely relied on internally generated cash flows and capital contributions from Energy Capital Partners and GE Energy Financial Services to satisfy its capital expenditure requirements.

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Details of cash distributions declared during 2013 follow.

Attributable to the quarter ended	Payment date	Per-unit distribution		Cash paid (or payable) to common unitholders		Cash paid (or payable) to subordinated unitholders		Cash paid (or payable) to general partner		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

Long-Term Debt

Revolving Credit Facility. We have a senior secured revolving credit facility. In June 2013, we exercised the revolving credit facility's $50.0 million accordion provision and increased the total commitments thereunder from $550.0 million to $600.0 million. We also borrowed $200.0 million in connection with the Bison Drop Down and $110.0 million in connection with the Mountaineer Acquisition. See Notes 1, 6 and 12 to the unaudited condensed consolidated financial statements for additional information. Also in June 2013, we used the proceeds from our senior notes offering to repay $294.2 million of our revolving credit facility. As of September 30, 2013, the outstanding balance of the revolving credit facility was $265.1 million.

The revolving credit facility is secured by the membership interests of Summit Holdings, DFW Midstream, Grand River Gathering, Bison Midstream and Mountaineer Midstream and substantially all of the assets of these entities. It is guaranteed by SMLP and all of its subsidiaries, except for Finance Corp., and allows for revolving loans, letters of credit and swingline loans.

Borrowings under the revolving credit facility bear interest at LIBOR plus an applicable margin or a base rate, as defined in the credit agreement. At September 30, 2013, the applicable margin under LIBOR borrowings was 3.25%, the interest rate was 3.43% and the unused portion of the revolving credit facility totaled $334.9 million (subject to a commitment fee of 0.50%).

The revolving credit agreement contains affirmative and negative covenants customary for credit facilities of its size and nature that, among other things, limit or restrict the ability to: (i) incur additional debt; (ii) make investments; (iii) engage in certain mergers, consolidations, acquisitions or sales of assets; (iv) enter into swap agreements and power purchase agreements; (v) enter into leases that would cumulatively obligate payments in excess of $30.0 million over any 12-month period; and (vi) prohibits the payment of distributions by Summit Holdings if a default then exists or would result therefrom, and otherwise limits the amount of distributions Summit Holdings can make. In addition, the revolving credit facility requires Summit Holdings to maintain a ratio of consolidated trailing 12-month EBITDA to net interest expense of not less than 2.5 to 1.0 (as defined in the credit agreement) and a ratio of total net indebtedness to consolidated trailing 12-month EBITDA of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to six months following certain acquisitions (as defined in the credit agreement).

As of September 30, 2013, we were in compliance with the covenants in the revolving credit facility. There were no defaults or events of default during the nine months ended September 30, 2013.

In November 2013, we closed on an amendment and restatement of the revolving credit facility which: (i) increases the borrowing capacity to $700.0 million, (ii) extends the maturity to November 2018, (iii) includes a $200.0 million accordion feature, (iv) reduces the leverage-based pricing grid by 0.75% to a new range of 1.75% to 2.75%, (v) changes the commitment fee to a leverage-based range of 0.30% to 0.50%, and (vi) adds Finance Corp. as a subsidiary guarantor. Had the restatement been in effect as of September 30, 2013, the unused portion of the revolving credit facility would have totaled $434.9 million, the margin under LIBOR would have been 2.50% and our commitment fee would have been 0.50%.

Senior Notes. On June 17, 2013, Summit Holdings and its 100% owned finance subsidiary, Finance Corp. (together with Summit Holdings, the "Co-Issuers"), issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021 (the "senior notes"). The senior notes were sold within the United States only to qualified institutional buyers in reliance on Rule 144A under the Securities Act, and outside the United States only to non-U.S. persons in reliance on Regulation S under the Securities Act. The senior notes have not been registered under the Securities Act or any state securities laws, and, unless so registered, may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws.

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We will pay interest on the senior notes semi-annually in cash in arrears on January 1 and July 1 of each year, commencing January 1, 2014. The senior notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 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 senior notes to repay a portion of the balance outstanding under our revolving credit facility. Debt issuance costs of $7.3 million, recognized in other noncurrent assets, are being amortized over the life of the senior notes.

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

Under a registration rights agreement, the Co-Issuers and the Guarantors have agreed to file a registration statement with the SEC pursuant to which the Co-Issuers will either offer to exchange the senior notes and the guarantees for registered notes and guarantees with substantially identical terms or, in certain circumstances, register the resale of the senior notes and their guarantees (the "Exchange Offer").

If the Exchange Offer is not completed (or, if required, the shelf registration statement is not declared effective or does not automatically become effective) on or before the 365th day following the date of issuance of the senior notes (the ‘‘Exchange Completion Deadline’’), the Co-Issuers will be required to pay additional interest in an amount equal to 0.25% per annum of the principal amount of senior notes with respect to the first 90-day period following the Exchange Completion Deadline. The amount of the additional interest will increase by an additional 0.25% per annum with respect to each subsequent 90-day period, up to a maximum amount of additional interest of 1.0% per annum of the principal amount of senior notes outstanding until the Exchange Offer is completed or the shelf registration statement is declared effective (or becomes automatically effective). All accrued additional interest will be paid by the Co-Issuers and the Guarantors on the next scheduled interest payment date in the same manner as other interest is paid on the senior notes. Following the time that the senior notes are registered, the accrual of additional interest will cease.

At any time prior to July 1, 2016, the Co-Issuers may redeem up to 35% of the aggregate principal amount of the senior notes at a redemption price of 107.500% of the principal amount of the senior notes, plus accrued and unpaid interest, if any, to the redemption date, with an amount not greater than the net cash proceeds of certain equity offerings. On and after July 1, 2016, the Co-Issuers may redeem all or part of the senior notes at a redemption price of 105.625% (with the redemption premium declining ratably each year to 100.000% on July 1, 2019), plus accrued and unpaid interest, if any.

The 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 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 senior notes; (ii) default in the payment when due of the principal of, or premium, if any, on the 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

43

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 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 senior notes may declare all the senior notes to be due and payable immediately.

There were no defaults or events of default during the period from issuance through September 30, 2013.

For additional information, see Note 5 to the unaudited condensed consolidated financial statements.

Credit Risk and Customer Concentration

We examine the creditworthiness of third-party customers 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 three producer customers. For additional information, see Note 9 to the unaudited condensed consolidated financial statements.

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 nine months endedSeptember 30, 2013. For additional information regarding critical accounting estimates, see the Critical Accounting Policies and Estimates section of MD&A included in the 2012 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 nine months endedSeptember 30, 2013.

Commodity Price Risk

We currently generate a substantial majority of our revenues pursuant to long-term, primarily fee-based gas gathering agreements that include MVCs and AMIs. 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 collect on the Grand River system and (iv) the sale of processed natural gas and natural gas liquids pursuant to our percent-of-proceeds contracts with certain of our customers on the Bison Midstream system. 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

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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

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 Securities Exchange Act of 1934, as amended (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 third fiscal quarter of2013 that have materially affected, or are reasonably likely to materially affect, SMLP's internal control over financial reporting.

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PART II—OTHER INFORMATION

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.

There has been no material change in the Partnership risk factors as previously disclosed in the 2012 Annual Report other than as supplemented by our Form 10-Q for the quarterly period ended June 30, 2013 in response to Part II, Item 1A. of such Form 10-Q.  Such risk factors 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))
10.1		Amended and Restated Employment Agreement, dated September 13, 2013, by and between Summit Midstream Partners, LLC and Matthew S. Harrison (Incorporated herein by reference to Exhibit 10.1 to SMLP's Current Report on Form 8-K dated September 18, 2013 (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

* Filed herewith

** 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 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 unaudited materials contained in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, formatted in XBRL: (i) Unaudited Condensed Consolidated Balance Sheets, (ii) Unaudited Condensed Consolidated Statements of Operations, (iii) Unaudited Condensed Consolidated Statements of Partners' Capital and Membership Interests, (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)
November 8, 2013	/s/ Matthew S. Harrison
	Matthew S. Harrison, Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

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