Summit Midstream Partners, LP - Quarter Report: 2013 June (Form 10-Q)

Table of Contents

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

Form 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2013

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

For the transition period from to

Commission file number: 001-35666

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



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

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

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

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

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



Class		As of July 31, 2013
Common Units		29,073,974 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 June 30, 2013 and December 31, 2012	1
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2013 and 2012	2
	Unaudited Condensed Consolidated Statements of Partners' Capital and Membership Interests for the six months ended June 30, 2013 and 2012	3
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 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.	24
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	42
Item 4.	Controls and Procedures.	42

PART II	Other Information	43
Item 1.	Legal Proceedings.	43
Item 1A.	Risk Factors.	43
Item 5.	Other Information.	43
Item 6.	Exhibits.	44

Table of Contents

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.

Table of Contents

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

Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS



	June 30,		December 31,
	2013		2012
	(Dollars in thousands)
Assets
Current assets:
Cash and cash equivalents	$	30,123	$	7,895
Accounts receivable	33,664		33,504
Due from affiliate	—		774
Other assets	1,114		2,190
Total current assets	64,901		44,363
Property, plant and equipment, net	1,000,488		681,993
Intangible assets, net:
Favorable gas gathering contracts	18,859		19,958
Contract intangibles	375,233		229,596
Rights-of-way	43,803		35,986
Total intangible assets, net	437,895		285,540
Goodwill	99,677		45,478
Other noncurrent assets	12,670		6,137
Total assets	$	1,615,631	$	1,063,511

Liabilities and Partners' Capital
Current liabilities:
Trade accounts payable	$	16,064	$	15,817
Due to affiliate	2,146		—
Deferred revenue	1,535		865
Ad valorem taxes payable	3,424		5,455
Other current liabilities	7,790		4,324
Total current liabilities	30,959		26,461
Long-term debt	565,050		199,230
Noncurrent liability, net (Note 4)	6,851		7,420
Deferred revenue	19,384		10,899
Other noncurrent liabilities	290		254
Total liabilities	622,534		244,264
Commitments and contingencies (Note 11)

Common limited partner capital (29,073,974 units issued and outstanding at June 30, 2013 and 24,412,427 units issued and outstanding at December 31, 2012)	578,514		418,856
Subordinated limited partner capital (24,409,850 units issued and outstanding at June 30, 2013 and December 31, 2012)	390,906		380,169
General partner interests (1,091,453 units issued and outstanding at June 30, 2013 and 996,320 issued and outstanding at December 31, 2012)	23,677		20,222
Total partners' capital	993,097		819,247
Total liabilities and partners' capital	$	1,615,631	$	1,063,511

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

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS



	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
	(In thousands, except per-unit and unit amounts)
Revenues:
Gathering services and other fees	$	41,251		$	36,729		$	81,130		$	68,647
Natural gas, NGLs and condensate sales and other	18,284			3,327			29,811			7,058
Amortization of favorable and unfavorable contracts	(250		)	51			(530		)	185
Total revenues	59,285			40,107			110,411			75,890

Costs and expenses:
Operation and maintenance	15,077			11,728			29,549			22,717
Cost of natural gas and NGLs	9,377			—			13,864			—
General and administrative	6,767			6,384			11,949			10,796
Transaction costs	2,418			41			2,426			234
Depreciation and amortization	14,870			8,689			26,720			16,979
Total costs and expenses	48,509			26,842			84,508			50,726
Other income	1			2			2			6
Interest expense	(3,023		)	(2,051		)	(4,903		)	(2,746		)
Affiliated interest expense	—			(1,932		)	—			(5,414		)
Income before income taxes	7,754			9,284			21,002			17,010
Income tax expense	(221		)	(155		)	(402		)	(294		)
Net income	$	7,533		$	9,129		$	20,600		$	16,716
Less: net (loss) income attributable to SMP Holdings (Note 1)	(535		)				52
Net income attributable to partners	8,068						20,548
Less: net income attributable to general partner	161						411
Net income attributable to limited partners	$	7,907					$	20,137

Earnings per common unit – basic	$	0.16					$	0.41
Earnings per common unit – diluted	$	0.16					$	0.41
Earnings per subordinated unit – basic and diluted	$	0.16					$	0.41

Weighted-average common units outstanding – basic	25,172,087						24,790,158
Weighted-average common units outstanding – diluted	25,281,104						24,871,033
Weighted-average subordinated units outstanding – basic and diluted	24,409,850						24,409,850

Cash distributions declared per common unit	$	0.42					$	0.83

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

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL AND

MEMBERSHIP INTERESTS



	Partners' capital
	Limited partners
	Common			Subordinated			General partner			SMP Holdings' equity in Bison Midstream			Membership interests		Total
	(In thousands, except per-unit amounts)
Membership interests, January 1, 2012	$	—		$	—		$	—		$	—		$	640,818	$	640,818
Net income	—			—			—			—			16,716		16,716
Class B membership interest unit-based compensation	—			—			—			—			1,412		1,412
Membership interests, June 30, 2012	$	—		$	—		$	—		$	—		$	658,946	$	658,946

Partners' capital, January 1, 2013	$	418,856		$	380,169		$	20,222		$	—		$	—	$	819,247
Net income	10,127			10,010			411			52			—		20,600
SMLP unit-based compensation	1,141			—			—			—			—		1,141
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	(20,262		)	(20,260		)	(826		)	—			—		(41,348		)
Partners' capital, June 30, 2013	$	578,514		$	390,906		$	23,677		$	—		$	—	$	993,097

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

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Six months ended June 30,
	2013			2012
	(In thousands)
Cash flows from operating activities:
Net income	$	20,600		$	16,716
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	26,720			16,979
Amortization of favorable and unfavorable contracts	530			(185		)
Amortization of deferred loan costs	882			579
Pay-in-kind interest on promissory notes payable to Sponsors	—			5,414
Unit-based compensation	1,158			1,412
Changes in operating assets and liabilities, net of effects of Bison Drop Down:
Accounts receivable	5,446			(1,741		)
Due from affiliate	2,920			—
Other assets	3,279			1,179
Trade accounts payable	391			(20,840		)
Change in deferred revenue	5,695			5,811
Ad valorem taxes payable	(2,031		)	1,750
Other current liabilities	119			(803		)
Other noncurrrent liabilities	707			—
Net cash provided by operating activities	66,416			26,271

Cash flows from investing activities:
Capital expenditures	(41,599		)	(24,363		)
Acquisition of Bison Midstream	(200,000		)	—
Acquisition of Mountaineer Midstream	(210,000		)	—
Net cash used in investing activities	(451,599		)	(24,363		)

Cash flows from financing activities:
Distributions to unitholders	(41,348		)	—
Borrowings under revolving credit facility	360,000			163,000
Repayments under revolving credit facility	(294,180		)	(8,000		)
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	(7,333		)	(4,775		)
Repayment of promissory notes payable to Sponsors	—			(160,000		)
Net cash provided by (used in) financing activities	407,411			(9,775		)
Net change in cash and cash equivalents	22,228			(7,867		)
Cash and cash equivalents, beginning of period	7,895			15,462
Cash and cash equivalents, end of period	$	30,123		$	7,595

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

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)



	Six months ended June 30,
	2013			2012
	(In thousands)
Supplemental Schedule of Investing and Financing Activities:
Cash interest paid	$	4,014		$	3,591
Capitalized interest	(970		)	(1,916		)
Interest paid (net of capitalized interest)	$	3,044		$	1,675

Cash paid for income taxes	$	660		$	—

Supplemental Disclosures of Noncash Investing and Financing Activities:
Capital expenditures in trade accounts payable (period-end accruals)	$	5,794		$	3,157
Unit-based compensation	1,158			1,412
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	—			6,316
Deferred initial public offering costs in trade accounts payable	—			481

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

Table of Contents

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 (the "Mountaineer Midstream Gathering system") 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 June 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.

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

Table of Contents

volumes of natural gas that we gather and compress across our systems. We currently operate in four 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 four operating subsidiaries are Grand River Gathering, DFW Midstream, Bison Midstream and Mountaineer Midstream. All of our 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 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, the date that common control began and (ii) Mountaineer Midstream since June 22, 2013, the date of acquisition. 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 recent fair value accounting for the acquisition of BTE. The excess of SMP Holdings' basis in the net assets of Bison Midstream over the purchase price paid by Summit Holdings 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 six months ended June 30, 2013 and 2012.

The 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 a single reporting 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.

Table of Contents

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.



	June 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		304,875		—		—

The revolving credit facility’s carrying value on the balance sheet is its fair value due to its floating interest rate. The fair value for the senior notes is based on an average of nonbinding broker quotes as of June 30, 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. We capitalize and then amortize

Table of Contents

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 nine 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 June 30, 2013, we have billed $20.9 million of deferred revenue relative to shortfall payments, of which $1.0 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 nine 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.

Table of Contents

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 six months ended June 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 June 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.

Table of Contents

3. PROPERTY, PLANT, AND EQUIPMENT, NET

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



	Useful lives (In years)	June 30,			December 31,
	Useful lives (In years)	2013			2012
	(Dollars in thousands)
Gas gathering systems	30	$	713,247		$	427,449
Compressor stations and compression equipment	30	272,538			237,618
Construction in progress	n/a	55,543			45,919
Other	4-15	5,873			4,524
Total		1,047,201			715,510
Accumulated depreciation		(46,713		)	(33,517		)
Property, plant, and equipment, net		$	1,000,488		$	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 June 30,				Six months ended June 30,
	2013		2012		2013		2012
	(In thousands)
Depreciation expense	$	7,009	$	5,433	$	13,196	$	10,059
Capitalized interest	478		595		970		1,916

4. IDENTIFIABLE INTANGIBLE ASSETS, NONCURRENT LIABILITY AND GOODWILL

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



	June 30, 2013
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
	(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(5,336	)	$	18,859
Contract intangibles	16.9	402,445		(27,212		)	375,233
Rights-of-way	28.3	47,481		(3,678		)	43,803
Total amortizable intangible assets		$	474,121	$	(36,226	)	$	437,895

Unfavorable gas gathering contract	10.0	$	10,962	$	(4,111	)	$	6,851

Table of Contents



	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.

We recognized amortization expense as follows:



	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	527		$	361		$	1,099		$	680
Amortization expense – contract intangibles	7,421			2,939			12,708			6,289
Amortization expense – rights-of-way	440			316			816			630
Amortization expense – unfavorable gas gathering contract	(277		)	(412		)	(569		)	(865		)

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



	Assets		Liabilities
	(In thousands)
2013	$	17,118	$	750
2014	35,958		1,549
2015	38,609		1,650
2016	38,709		1,571
2017	37,249		1,331

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. See Notes 1 and 12 for additional information. A rollforward of the consolidated balance of goodwill for the six months ended June 30, 2013 follows.



	(Dollars in thousands)
Goodwill, beginning of period	$	45,478
Goodwill recognized in connection with the Bison Drop Down	54,199
Goodwill, end of period	$	99,677

We evaluate goodwill for impairment annually on September 30. We also evaluate goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. There have been no impairments of goodwill.

Table of Contents

5. LONG-TERM DEBT

Long-term debt consisted of the following:



	June 30,		December 31,
	2013		2012
	(In thousands)
Variable rate senior secured revolving credit facility (2.71% at June 30, 2013 and 2.98% at December 31, 2012) due May 2016	$	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 June 30, 2013, the outstanding balance of the revolving credit facility was $265.1 million. The facility matures in May 2016.

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 all of Summit Holdings' 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 June 30, 2013, the applicable margin under LIBOR borrowings was 2.50%, the interest rate was 2.71% 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 June 30, 2013, we were in compliance with the covenants in the revolving credit facility. There were no defaults or events of default during the six months ended June 30, 2013.

Senior Notes. On June 17, 2013, Summit Holdings and its 100% owned finance subsidiary, Finance Corp. (collectively 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 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 will 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 $7.1 million, recognized in other noncurrent assets, are being amortized over the life of the senior notes.

Table of Contents

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 independent 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 some 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 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 June 30, 2013.

Table of Contents

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 June 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, end of period	29,073,974	24,409,850	1,091,453	54,575,277

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 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. The allocation and valuation of units issued to SMP Holdings and the

Table of Contents

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. Details of cash distributions declared during 2013 follow.



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

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:

Table of Contents


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

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.

Table of Contents

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.

7. EARNINGS PER UNIT

The following table presents details on EPU.



	Three months ended June 30, 2013			Six months ended June 30, 2013
	(Dollars in thousands, except per-unit amounts)
Net income	$	7,533		$	20,600
Less: net (loss) income attributable to SMP Holdings	(535		)	52
Net income attributable to partners	8,068			20,548
Less: net income attributable to general partner	161			411
Net income attributable to limited partners	$	7,907		$	20,137

Net income attributable to common units	$	4,012		$	10,127

Weighted-average common units outstanding – basic	25,172,087			24,790,158
Earnings per common unit – basic	$	0.16		$	0.41

Weighted-average common units outstanding – diluted	25,281,104			24,871,033
Earnings per common unit – diluted	$	0.16		$	0.41

Net income attributable to subordinated units	$	3,895		$	10,010

Weighted-average subordinated units outstanding – basic and diluted	24,409,850			24,409,850
Earnings per subordinated unit – basic and diluted	$	0.16		$	0.41

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 109,018 units for the three months ended June 30, 2013 and 80,875 units for the six months ended June 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 six months ended June 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 June 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

Table of Contents

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.

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	152,687		$	26.20
Restricted units granted	835		$	27.50
Phantom units forfeited	(3,079	)	$	25.99
Nonvested phantom and restricted units, June 30, 2013	282,001		$	23.31

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 June 30, 2013, the unrecognized non-cash compensation expense related to the LTIP was $5.2 million. Incremental non-cash compensation expense will be recorded over the remaining vesting period of 2.93 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.

Non-cash compensation expense recognized in general and administrative expense related to awards under the LTIP was as follows:



	Three months ended June 30, 2013		Six months ended June 30, 2013
	(In thousands)
SMLP non-cash compensation expense	$	814	$	1,141

DFW Net Profits Interests. Class B membership interests in DFW Midstream (the "DFW Net Profits Interests") participated in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested DFW Net Profits Interests. The DFW Net Profits Interests were accounted for as compensatory awards. All grants vested ratably and provided for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and the DFW Midstream Amended and Restated Limited Liability Company Agreement and Contribution Agreement).

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



	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
	(In thousands)
Non-cash compensation expense	$	4	$	647	$	17	$	800

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

Table of Contents

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.

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 June 30,				Six months ended June 30,
	2013		2012		2013		2012
Revenue:
Counterparty A	19	%	17	%	21	%	16	%
Counterparty B	16	%	26	%	18	%	29	%
Counterparty C	11	%	—	%	*		—	%
Counterparty D	*		14	%	*		16	%

__________

* Less than 10%

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



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

__________

* 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.

Table of Contents

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:



	June 30,		December 31,
	2013		2012
	(In thousands)
Due to affiliate	$	—	$	774
Due from affiliate	2,146		—

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



	Three months ended June 30, 2013		Six months ended June 30, 2013
	(In thousands)
General and administrative expense allocation	$	595	$	1,806

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 June 30,				Six months ended June 30,
	2013		2012		2013		2012
	(In thousands)
Payments for electricity management consulting services	$	54	$	44	$	109	$	88

11. COMMITMENTS AND CONTINGENCIES

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



	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
	(In thousands)
Total rent expense	$	280	$	178	$	507	$	315

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.

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"), collectively owned an aggregate 4.1% vested net profits interests in DFW Midstream, 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. The Plaintiffs also sought other unspecified monetary damages, including attorneys' fees and costs. The complaint alleged that the Defendants breached (i) the DFW Midstream limited liability company agreement; (ii) compensatory arrangements with each Plaintiff; (iii) the implied covenant of good faith and fair dealing; and (iv) in the case of Summit Investments and Summit Holdings, their alleged fiduciary duties to the Plaintiffs. The complaint further alleged that the Defendants acted fraudulently with respect to the Plaintiffs. 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. The Plaintiffs filed a notice of appeal to the Supreme Court of Delaware on April 24, 2013. On April 30, 2013, the Plaintiffs voluntarily dismissed their appeal.

Table of Contents

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 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	$	5,707
Property, plant, and equipment	85,477
Intangible assets	164,502
Other noncurrent assets	2,187
Total assets acquired	257,873
Current liabilities	6,112
Other noncurrent liabilities	2,790
Total liabilities assumed	$	8,902
Net identifiable assets acquired			248,971
Goodwill			$	54,197

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.

Table of Contents

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 three and six months ended June 30, 2013, as presented in these unaudited condensed consolidated financial statements follow.



	Three months ended June 30, 2013			Six months ended June 30, 2013
	(In thousands)
SMLP revenues	$	43,743		$	87,338
Bison Gas Gathering system revenues	15,542			23,073
Combined revenues	$	59,285		$	110,411

SMLP net income	$	7,790		$	20,270
Bison Gas Gathering system net (loss) income	(257		)	330
Combined net income	$	7,533		$	20,600

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 and six months ended June 30, 2013, SMLP recorded $0.4 million of revenue and $0.3 million of net income related to Mountaineer Midstream.

SMLP is accounting for the Mountaineer Acquisition under the acquisition method of accounting. We are in the process of determining the assets acquired and the liabilities assumed and have preliminarily assigned the full purchase price to property, plant and equipment. We have not completed the final purchase price allocation as of June 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.

Table of Contents

Unaudited Pro Forma Financial Information. The following unaudited pro forma financial information assumes that both the Bison Drop Down and the Mountaineer Acquisition 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 three and six months ended June 30, 2013 has been adjusted to remove the impact of $2.4 million of nonrecurring transaction costs incurred during the three months ended June 30, 2013.



	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
	(In thousands, except per-unit amounts)
Total Bison Midstream and Mountaineer Midstream revenues included in consolidated revenues	$	15,951	$	—	$	23,482	$	—
Total Bison Midstream and Mountaineer Midstream net income (loss) included in consolidated net income	54		—		641		—

Pro forma total revenues	$	62,304	$	48,045	$	122,562	$	90,641
Pro forma net income	9,248		7,033		17,502		10,535

Pro forma common EPU - basic and diluted	$	0.17			$	0.32
Pro forma subordinated EPU - basic and diluted	0.17				0.32

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 Bison Drop Down and the Mountaineer Acquisition 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 the 2012 Annual Report as updated by those included in Item 1A. Risk Factors included herein. 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 shale formations in northwestern North Dakota; and (iv) the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia.

Table of Contents

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 1,006,500 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 3.3 Tcf at June 30, 2013 and average approximately 886 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 four to 13 years and, as of June 30, 2013, had a weighted-average remaining life of 10.4 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.

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;

Table of Contents


•	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 system, 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 non-cash compensation expense and adjustments related to MVC shortfall payments. 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 or the impact of non-cash compensation expense.

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.

Table of Contents

Results of Operations

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



	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
	(In thousands)
Revenues:
Gathering services and other fees	$	41,251		$	36,729		$	81,130		$	68,647
Natural gas, NGLs and condensate sales and other	18,284			3,327			29,811			7,058
Amortization of favorable and unfavorable contracts (1)	(250		)	51			(530		)	185
Total revenues	59,285			40,107			110,411			75,890

Costs and expenses:
Operation and maintenance	15,077			11,728			29,549			22,717
Cost of natural gas and NGLs	9,377			—			13,864			—
General and administrative	6,767			6,384			11,949			10,796
Transaction costs	2,418			41			2,426			234
Depreciation and amortization	14,870			8,689			26,720			16,979
Total costs and expenses	48,509			26,842			84,508			50,726
Other income	1			2			2			6
Interest expense	(3,023		)	(2,051		)	(4,903		)	(2,746		)
Affiliated interest expense	—			(1,932		)	—			(5,414		)
Income before income taxes	7,754			9,284			21,002			17,010
Income tax expense	(221		)	(155		)	(402		)	(294		)
Net income	$	7,533		$	9,129		$	20,600		$	16,716

Other Financial Data (2):
EBITDA (3)	$	25,896		$	21,903		$	53,153		$	41,958
Adjusted EBITDA (3)	33,463			26,663			67,355			51,544
Capital expenditures (4)	16,460			3,786			41,599			24,363
Acquisitions of Bison Midstream and Mountaineer Midstream	410,000			—			410,000			—
Distributable cash flow (4)	25,969			23,369			55,492			45,253

Operating Data:
Miles of pipeline (end of period)	757			388			757			388
Aggregate average throughput (MMcf/d)	918			914			935			913

__________

(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 and six months ended June 30, 2012, the calculation of distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.

Table of Contents

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, the date that common control began and (ii) Mountaineer Midstream since June 22, 2013, the date of acquisition. 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.

Table of Contents

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

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



	Three months ended June 30,						Change
	2013			2012			$			%
	(Dollars in thousands)
Statement of Operations Data:
Revenue:
Gathering services and other fees	$	41,251		$	36,729		$	4,522		12	%
Natural gas, NGLs and condensate sales and other	18,284			3,327			14,957			450	%
Amortization of favorable and unfavorable contracts (1)	(250		)	51			(301		)	(590	)%
Total revenue	59,285			40,107			19,178			48	%
Costs and expenses:
Operation and maintenance	15,077			11,728			3,349			29	%
Cost of natural gas and NGLs	9,377			—			9,377			—
General and administrative	6,767			6,384			383			6	%
Transaction costs	2,418			41			2,377			5,798	%
Depreciation and amortization	14,870			8,689			6,181			71	%
Total costs and expenses	48,509			26,842			21,667			81	%
Other income	1			2			(1		)	(50	)%
Interest expense	(3,023		)	(2,051		)	(972		)	47	%
Affiliated interest expense	—			(1,932		)	1,932			(100	)%
Income before income taxes	7,754			9,284			(1,530		)	(16	)%
Income tax expense	(221		)	(155		)	(66		)	43	%
Net income	$	7,533		$	9,129		$	(1,596	)	(17	)%

Other Financial Data (2):
EBITDA (3)	$	25,896		$	21,903		$	3,993		18	%
Adjusted EBITDA (3)	33,463			26,663			6,800			26	%
Capital expenditures (4)	16,460			3,786			12,674			335	%
Acquisition capital expenditures	410,000			—			410,000			—
Distributable cash flow (4)	25,969			23,369			2,600			11	%

Operating Data:
Miles of pipeline (end of period)	757			388			369			95	%
Aggregate average throughput (MMcf/d)	918			914			4			—	%

__________

(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 June 30, 2012, the calculation of distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.

Table of Contents

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 918 MMcf/d for the three months ended June 30, 2013, compared with an average of 914 MMcf/d in the prior-year period, and largely reflect the impact of a production curtailment announced in the first quarter of 2012 by one of our largest producer customers on the DFW Midstream system. In the second quarter of 2012, this producer customer began bringing production back on line and returned to pre-curtailment levels by the end of the third quarter of 2012. Operating data by system as of or for the three months ended June 30 follows:



	Grand River		DFW Midstream		Bison Midstream		Mountaineer Midstream
	June 30,		June 30,		June 30,		June 30,
	2013	2012	2013	2012	2013	2012	2013	2012
Miles of pipeline (end of period)	290	279	118	109	309	—	41	—
Aggregate average throughput (for the quarter-to-date period)(MMcf/d)	494	582	395	331	17	—	12	—

Grand River system volume throughput declined in the second 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 second quarter 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.

Revenue. Total revenues increased for the three months ended June 30, 2013, largely due to Bison Midstream's contribution to natural gas, NGLs and condensate sales and other. Natural gas, NGLs and condensate sales and other also reflect higher volumes on our DFW Midstream system and an increase quarter over quarter in the prices we were able to obtain for natural gas sales. Gathering services and other fees increased during the three months ended June 30, 2013, primarily as a result of the contribution from the Bison Midstream system and also benefited from increased throughput volumes on the DFW Midstream system. The aggregate average throughput rate for the three months ended June 30, 2013 was approximately $0.49 per Mcf, compared with approximately $0.39 per Mcf for the three months ended June 30, 2012. The period-over-period increase was largely driven by the proportionate increase in volumes on 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 offset the financial impact of the volume decreases on the Grand River system. Total revenues for the three months ended June 30, 2013 included a $15.5 million contribution from Bison Midstream, of which $3.4 million was reflected in gathering services and other fees and $12.1 million was reflected in natural gas, NGLs and condensate sales and other.

Operation and Maintenance Expense. Operation and maintenance expense increased during the three months ended June 30, 2013, largely as a result of $2.0 million of higher power-related costs for DFW Midstream, a $0.6 million increase in property tax expenses due to a change in our estimate for property tax expenses in the third quarter of 2012, a $0.5 million increase in carbon dioxide expenses for DFW Midstream, and a $0.4 million increase in field employee and contractor costs. In addition, Bison Midstream accounted for $1.0 million of operation and maintenance expense for the three months ended June 30, 2013. The increase in operation and maintenance expense was partially offset by the impact of a $1.1 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 three months ended June 30, 2013, largely as a result of the expenses recognized for the Bison Midstream system and an increase in salaries, benefits and incentive compensation. The Bison Midstream system accounted for $0.7 million of general and administrative expense for the three months ended June 30, 2013.

Table of Contents

Transaction Costs. Transaction costs were $2.4 million for the three months ended June 30, 2013, of which $0.7 million related to the acquisition of the Bison Midstream system and $1.7 million related to the acquisition of the Mountaineer Midstream system.

Depreciation and Amortization Expense. Depreciation and amortization expense increased during the three months ended June 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 system also contributed to the increase. The Bison Midstream system accounted for $4.7 million of depreciation and amortization expense for the three months ended June 30, 2013.

Interest Expense and Affiliated Interest Expense. Interest expense increased during the three months ended June 30, 2013, primarily as a result of our issuance of $300.0 million of 7.50% senior notes in June 2013. Affiliated interest expense for the three months ended June 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.

Table of Contents

Six Months Ended June 30, 2013 Compared with the Six Months Ended June 30, 2012

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



	Six months ended June 30,						Change
	2013			2012			$			%
	(Dollars in thousands)
Statement of Operations Data:
Revenue:
Gathering services and other fees	$	81,130		$	68,647		$	12,483		18	%
Natural gas, NGLs and condensate sales and other	29,811			7,058			22,753			322	%
Amortization of favorable and unfavorable contracts (1)	(530		)	185			(715		)	(386	)%
Total revenue	110,411			75,890			34,521			45	%
Costs and expenses:
Operation and maintenance	29,549			22,717			6,832			30	%
Cost of natural gas and NGLs	13,864			—			13,864			—
General and administrative	11,949			10,796			1,153			11	%
Transaction costs	2,426			234			2,192			937	%
Depreciation and amortization	26,720			16,979			9,741			57	%
Total costs and expenses	84,508			50,726			33,782			67	%
Other income	2			6			(4		)	(67	)%
Interest expense	(4,903		)	(2,746		)	(2,157		)	79	%
Affiliated interest expense	—			(5,414		)	5,414			(100	)%
Income before income taxes	21,002			17,010			3,992			23	%
Income tax expense	(402		)	(294		)	(108		)	37	%
Net income	$	20,600		$	16,716		$	3,884		23	%

Other Financial Data (2):
EBITDA (3)	$	53,153		$	41,958		$	11,195		27	%
Adjusted EBITDA (3)	67,355			51,544			15,811			31	%
Capital expenditures (4)	41,599			24,363			17,236			71	%
Acquisition capital expenditures	410,000			—			410,000			—
Distributable cash flow (4)	55,492			45,253			10,239			23	%

Operating Data:
Miles of pipeline (end of period)	757			388			369			95	%
Aggregate average throughput (MMcf/d)	935			913			22			2	%

__________

(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 six months ended June 30, 2012, the calculation of distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.

Table of Contents

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 935 MMcf/d for the six months ended June 30, 2013, compared with an average of 913 MMcf/d in the prior-year period, and largely reflect the impact of a production curtailment announced in the first quarter of 2012 by one of our largest producer customers on the DFW Midstream system. In the second quarter of 2012, this producer customer began bringing production back on line and returned to pre-curtailment levels by the end of the third quarter of 2012. Operating data by system as of or for the six months ended June 30 follows.



	Grand River		DFW Midstream		Bison Midstream		Mountaineer Midstream
	June 30,		June 30,		June 30,		June 30,
	2013	2012	2013	2012	2013	2012	2013	2012
Miles of pipeline (end of period)	290	279	118	109	309	—	41	—
Aggregate average throughput (for the year-to-date period)(MMcf/d)	509	588	407	325	13	—	6	—

Grand River system volume throughput declined in the first half 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 half 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 six months ended June 30, 2012 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 by 40 MMcf/d.

Revenue. Total revenues increased for the six months ended June 30, 2013, largely due to the revenue from the Bison Midstream system. The increase in gathering services and other fees during the six months ended June 30, 2013, also reflects increased throughput volumes on the DFW Midstream system. The aggregate average throughput rate for the six months ended June 30, 2013 was approximately $0.47 per Mcf, compared with approximately $0.38 per Mcf for the six months ended June 30, 2012. The period-over-period increase was largely driven by the proportionate increase in volumes on 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 offset the financial impact of the volume decreases on the Grand River system. Natural gas and condensate sales increased for the six months ended June 30, 2013, primarily as a result of higher volumes on our DFW Midstream system and an increase quarter over quarter in the prices we were able to obtain for natural gas sales. Total revenues for the six months ended June 30, 2013 included a $23.1 million contribution from Bison Midstream, of which $5.3 million was reflected in gathering services and other fees and $17.8 million was reflected in natural gas, NGLs and condensate sales and other.

Operation and Maintenance Expense. Operation and maintenance expense increased during the six months ended June 30, 2013, largely as a result of $3.6 million of higher power-related costs for DFW Midstream, a $1.4 million increase in property tax expenses due to a change in our estimate for property tax expenses in the third quarter of 2012, a $1.0 million increase in carbon dioxide expenses for DFW Midstream, and a $1.0 million increase in field employee and contractor costs. The Bison Midstream system contributed for $1.5 million of operation and maintenance expense for the six months ended June 30, 2013. The increase in operation and maintenance expense was partially offset by the impact of a $1.7 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.

General and Administrative Expense. General and administrative expense increased during the six months ended June 30, 2013, primarily due to an increase in salaries, benefits and incentive compensation. The Bison Midstream system accounted for $0.8 million of general and administrative expense for the six months ended June 30, 2013.

Table of Contents

Transaction Costs. Transaction costs were $2.4 million for the six months ended June 30, 2013, of which $0.7 million related to the acquisition of the Bison Midstream system and $1.7 million related to the acquisition of the Mountaineer Midstream system.

Depreciation and Amortization Expense. Depreciation and amortization expense increased during the six months ended June 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 $6.6 million of depreciation and amortization expense for the six months ended June 30, 2013.

Interest Expense and Affiliated Interest Expense. The increase in interest expense during the six months ended June 30, 2013, primarily reflected our issuance of $300.0 million of 7.50% senior notes in June 2013, higher balances on our revolving credit facility beginning in May 2012 and 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. Affiliated interest expense for the six months ended June 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.

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.

Table of Contents

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 June 30,					Six months ended June 30,
	2013		2012			2013		2012
	(In thousands)
Reconciliation of Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
Net income	$	7,533	$	9,129		$	20,600	$	16,716
Add:
Interest expense	3,023		3,983			4,903		8,160
Income tax expense	221		155			402		294
Depreciation and amortization expense	14,870		8,689			26,720		16,979
Amortization of favorable and unfavorable contracts	250		(51		)	530		(185		)
Less:
Interest income	1		2			2		6
EBITDA (1)	$	25,896	$	21,903		$	53,153	$	41,958
Add:
Non-cash compensation expense	818		952			1,158		1,412
Adjustments related to MVC shortfall payments (2)	6,749		3,808			13,044		8,174
Adjusted EBITDA (1)	$	33,463	$	26,663		$	67,355	$	51,544
Add:
Interest income	1		2			2		6
Less:
Cash interest paid	2,125		1,896			4,014		3,591
Senior notes interest expense (3)	875		—			875		—
Cash taxes paid	660		—			660		—
Maintenance capital expenditures (4)	3,835		1,400			6,316		2,706
Distributable cash flow	$	25,969	$	23,369		$	55,492	$	45,253

__________

(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 six months ended June 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.

Table of Contents

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.



	Six months ended June 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	$	66,416		$	26,271
Add:
Interest expense (1)	4,021			2,167
Income tax expense	402			294
Changes in operating assets and liabilities	(16,526		)	14,644
Less:
Non-cash compensation expense	1,158			1,412
Interest income	2			6
EBITDA (2)	$	53,153		$	41,958
Add:
Non-cash compensation expense	1,158			1,412
Adjustments related to MVC shortfall payments (3)	13,044			8,174
Adjusted EBITDA (2)	$	67,355		$	51,544
Add:
Interest income	2			6
Less:
Cash interest paid	4,014			3,591
Senior notes interest expense (4)	875			—
Cash taxes paid	660			—
Maintenance capital expenditures (5)	6,316			2,706
Distributable cash flow	$	55,492		$	45,253

__________

(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 six months ended June 30, 2013, interest expense excluded $0.9 million of amortization of deferred loan costs. For the six months ended June 30, 2012, interest expense excluded $0.6 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 six months ended June 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.

Table of Contents

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.

Cash Flows

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



	Six months ended June 30,
	2013			2012
	(In thousands)
Net cash provided by operating activities	$	66,416		$	26,271
Net cash used in investing activities	(451,599		)	(24,363		)
Net cash provided by (used in) financing activities	407,411			(9,775		)
Change in cash and cash equivalents	$	22,228		$	(7,867	)

Operating activities. Cash flows from operating activities increased by $40.1 million for the six months ended June 30, 2013 largely as result of the increase in volumes on the DFW Midstream system and the contribution from the Bison Midstream system, partially offset by a decline in volumes on the Grand River system.

Investing activities. Cash flows used in investing activities for the six months ended June 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 connection of four new pad sites as well as 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 early January 2013, which increased system throughput capacity from 410 MMcf/d to 450 MMcf/d.

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



	Six months ended June 30,
	2013			2012
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	$	(41,348	)	$	—
Borrowings under revolving credit facility	360,000			163,000
Repayments under revolving credit facility	(294,180		)	(8,000		)
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	—			(160,000		)
Deferred loan costs and initial public offering costs	(7,333		)	(4,775		)
Net cash provided by (used in) financing activities	$	407,411		$	(9,775	)

Table of Contents

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


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


•	Payments of $294.2 million on our revolving credit facility, all of which was funded by our $300.0 million senior notes issuance (see Note 5 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 $7.1 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 six months ended June 30, 2012 was primarily composed borrowings of $163.0 million under our revolving credit facility, of which $160.0 million was used to partially 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 the impact of an increased borrowing capacity, borrowings and repayments on our revolving credit facility during the first six months of 2013. The table below summarizes and updates our long-term debt obligations as of June 30, 2013 after giving effect to these 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)	$	771,624	$	31,358	$	327,766	$	45,000	$	367,500

__________

(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.

Off-Balance Sheet Arrangements

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

Table of Contents

Total capital expenditures were as follows:



	Six months ended June 30,
	2013		2012
	(In thousands)
Capital expenditures	$	41,599	$	24,363
Acquisitions of Bison Midstream and Mountaineer Midstream	410,000		—

For the six months ended June 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 Grand River, DFW Midstream and Bison Midstream 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 six months ended June 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, the Predecessor 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.

Details of cash distributions declared during 2013 follow.



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

Long-Term Debt

Table of Contents

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

Table of Contents

There were no defaults or events of default during the period from issuance through June 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 six months ended June 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.

Table of Contents

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 $1.2 million for the six months ended June 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 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 second fiscal quarter of 2013 that have materially affected, or are reasonably likely to materially affect, SMLP's internal control over financial reporting.

Table of Contents

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.

As disclosed in our quarterly report on Form 10-Q for the quarterly period ended March 31, 2013, on April 30, 2013, we resolved our previously reported litigation involving four former DFW Midstream employees related to their net profits interests in DFW Midstream.

Item 1A. Risk Factors.

The Risk Factors contained in the 2012 Annual Report are incorporated herein by reference and updated to include the additional risks discussed below.

Risks Related to Our Business

Oil and gas activities in certain areas of our gathering systems may be adversely affected by seasonal weather conditions which in turn could negatively impact the operations of our gathering facilities and our construction of additional facilities.

Winter weather conditions across our system, especially in North Dakota, can be severe and can adversely affect oil and gas operations due to the potential shut-in of producing wells or decreased drilling activities. The result of these types of interruptions could result in a decrease in the volumes of natural gas supplied to our gathering systems. Further, delays and shutdowns caused by severe weather during the winter months may have a material negative impact on the continuous operations of our gathering systems, including interruptions in service. These types of interruptions could materially affect our business and the results of our operations.

Risks Related to Our Indebtedness and the Notes

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

We are a holding company, and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than our interest in our operating subsidiaries. As a result, our ability to make required payments on the notes depends on the performance of our operating subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the revolving credit facility and applicable state limited liability company laws and other laws and regulations. If we are unable to obtain the funds necessary to pay the principal amount at maturity of the notes, or to repurchase the notes upon the occurrence of a change of control, we may be required to adopt one or more alternatives, such as a refinancing of the notes or a sale of assets. We may not be able to refinance the notes or sell assets on acceptable terms, or at all.

Item 5. Other Information.

Our Corporate Governance Guidelines, which are available on our website under the “Corporate Governance” subsection of the “Investors” section at www.summitmidstream.com, provide that (i) Jerry L. Peters, as the chairman of our Audit Committee, shall preside over any executive sessions, and (ii) interested parties may communicate directly with our independent directors by submitting a specially marked envelope to the Secretary of our general partner.

Table of Contents

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))
4.1		7 1/2% Senior Notes Due 2021 Indenture dated as of June 17, 2013 by and between Summit Midstream Holdings, LLC, Summit Midstream Finance Corp., Summit Midstream Partners, LP, the subsidiary guarantors named therein and U.S. Bank National Association (Incorporated herein by reference to Exhibit 4.1 to SMLP's Current Report on Form 8-K dated June 17, 2013 (Commission File No. 001-35666))
4.2		Registration Rights Agreement dated as of June 17, 2013 by and between Summit Midstream Holdings, LLC, Summit Midstream Finance Corp., Summit Midstream Partners, LP, DFW Midstream Services LLC, Grand River Gathering, LLC, Bison Midstream, LLC, Mountaineer Midstream Company, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated Deutsche Bank Securities Inc., RBC Capital Markets, LLC, and RBS Securities Inc., (Incorporated herein by reference to Exhibit 4.2 to SMLP's Current Report on Form 8-K dated June 17, 2013 (Commission File No. 001-35666))
10.1	† *	Gas Purchase Agreement dated as of December 20, 2010 by and between Bear Tracker Energy, LLC., and EOG Resources, Inc.
10.2	† *	Gas Gathering and Compression Agreement dated as of April 16, 2012 by and between MarkWest Liberty Midstream & Resources, L.L.C., and Antero Resources Appalachian Corporation
10.3	† *	Purchase and Sale Agreement dated as of June 4, 2013 by and between MarkWest Liberty Midstream & Resources, L.L.C. and Summit Midstream Partners, LP
10.4		Summit Midstream Partners, LLC Deferred Compensation Plan dated as of July 1, 2013 (Incorporated by reference to Exhibit 4.3 to the registration statement on Form S-8 of Summit Midstream Partners, LP (File No. 333-189684), filed on June 28, 2013)
10.5		Purchase Agreement dated as of June 12, 2013 by and between Summit Midstream Holdings, LLC, Summit Midstream Finance Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated and the other several initial purchasers (Incorporated herein by reference to Exhibit 1.1 to SMLP's Current Report on Form 8-K dated June 17, 2013 (Commission File No. 001-35666))
10.8		Contribution Agreement dated as of June 4, 2013 by and between Summit Midstream Partners Holdings, LLC, Bison Midstream, LLC and Summit Midstream Partners, LP, (Incorporated herein by reference to Exhibit 10.1 to SMLP's Current Report on Form 8-K dated June 5, 2013 (Commission File No. 001-35666))
10.9		Increase Joinder dated as of June 4, 2013 with respect to the Amended and Restated Credit Agreement, dated as of May 7, 2012 (Incorporated herein by reference to Exhibit 10.2 to SMLP's Current Report on Form 8-K dated June 5, 2013 (Commission File No. 001-35666))
10.10		Unit Purchase Agreement dated as of June 4, 2013 by and between Summit Midstream Partners, LP, Summit Midstream Partners Holdings, LLC, and Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 10.3 to SMLP's Current Report on Form 8-K dated June 5, 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

Table of Contents

† Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Securities and Exchange Commission.

* 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 June 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.

Table of Contents

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)

August 12, 2013	By: Summit Midstream GP, LLC (its general partner)

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