Edgar Filing: Summit Midstream Partners, LP

SMLP-3.14-10Q

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 March 31, 2014

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

For the transition period from to

Commission file number: 001-35666

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



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

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

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

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

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



Class		As of April 30, 2014
Common Units		34,421,844 units
Subordinated Units		24,409,850 units
General Partner Units		1,200,651 units

TABLE OF CONTENTS



PART I	FINANCIAL INFORMATION	1
Item 1.	Financial Statements.	1
	Unaudited Condensed Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013	1
	Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2014 and 2013	2
	Unaudited Condensed Consolidated Statements of Partners' Capital for the three months ended March 31, 2014 and 2013	3
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2014 and 2013	4
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	21
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	30
Item 4.	Controls and Procedures.	31

PART II	OTHER INFORMATION	32
Item 1.	Legal Proceedings.	32
Item 1A.	Risk Factors.	32
Item 6.	Exhibits.	33

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 processing assets or systems;


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


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


•	the ability to attract and retain key management personnel;


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


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


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


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


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


•	weather conditions and seasonal trends;


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


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


•	the effects of litigation; and


•	certain factors discussed elsewhere in this report.

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

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



	March 31,		December 31,
	2014		2013
	(Dollars in thousands)
Assets
Current assets:
Cash and cash equivalents	$	10,404	$	20,357
Accounts receivable	47,104		67,877
Other assets	3,015		4,741
Total current assets	60,523		92,975
Property, plant and equipment, net	1,177,156		1,158,081
Intangible assets, net:
Favorable gas gathering contracts	17,446		17,880
Contract intangibles	375,344		383,306
Rights-of-way	102,035		100,991
Total intangible assets, net	494,825		502,177
Goodwill	115,888		115,888
Other noncurrent assets	14,000		14,618
Total assets	$	1,862,392	$	1,883,739

Liabilities and Partners' Capital
Current liabilities:
Trade accounts payable	$	22,766	$	25,117
Due to affiliate	1,043		653
Deferred revenue	1,555		1,555
Ad valorem taxes payable	4,070		8,375
Accrued interest	5,740		12,144
Other current liabilities	10,395		11,729
Total current liabilities	45,569		59,573
Long-term debt	691,000		586,000
Noncurrent liability, net (Note 4)	6,166		6,374
Deferred revenue	33,410		29,683
Other noncurrent liabilities	371		372
Total liabilities	776,516		682,002
Commitments and contingencies (Note 11)
Common limited partner capital (34,421,259 units issued and outstanding at March 31, 2014 and 29,079,866 units issued and outstanding at December 31, 2013)	716,589		566,532
Subordinated limited partner capital (24,409,850 units issued and outstanding at March 31, 2014 and December 31, 2013)	343,252		379,287
General partner interests (1,200,651 units issued and outstanding at March 31, 2014 and 1,091,453 issued and outstanding at December 31, 2013)	26,035		23,324
Summit Investments' equity in contributed subsidiaries	—		232,594
Total partners' capital	1,085,876		1,201,737
Total liabilities and partners' capital	$	1,862,392	$	1,883,739

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 March 31,
	2014			2013
	(In thousands, except per-unit and unit amounts)
Revenues:
Gathering services and other fees	$	50,072		$	45,972
Natural gas, NGLs and condensate sales and other	26,356			16,292
Amortization of favorable and unfavorable contracts	(226		)	(280		)
Total revenues	76,202			61,984
Costs and expenses:
Operation and maintenance	19,181			17,579
Cost of natural gas and NGLs	15,281			7,965
General and administrative	7,886			6,567
Transaction costs	537			38
Depreciation and amortization	19,642			13,912
Total costs and expenses	62,527			46,061
Other income (expense)	1			1
Interest expense	(7,144		)	(1,879		)
Income before income taxes	6,532			14,045
Income tax expense	(159		)	(181		)
Net income	$	6,373		$	13,864
Less: net income attributable to Summit Investments (Note 1)	2,828			1,384
Net income attributable to SMLP	3,545			12,480
Less: net income attributable to general partner, including IDRs	431			250
Net income attributable to limited partners	$	3,114		$	12,230

Earnings per limited partner unit (Note 7):
Common unit – basic	$	0.08		$	0.25
Common unit – diluted	$	0.08		$	0.25
Subordinated unit – basic and diluted	$	0.02		$	0.25

Weighted-average limited partner units outstanding:
Common units – basic	29,911,669			24,412,427
Common units – diluted	30,067,658			24,455,603
Subordinated units – basic and diluted	24,409,850			24,409,850

Cash distributions declared per common unit	$	0.48		$	0.41

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



	Partners' capital									Summit Investments' equity in contributed subsidiaries
	Limited partners
	Common			Subordinated			General partner						Total
	(In thousands)
Partners' capital, January 1, 2013	$	418,856		$	380,169		$	20,222		$	211,002		$	1,030,249
Net income	6,115			6,115			250			1,384			13,864
SMLP unit-based compensation	327			—			—			—			327
Distributions to unitholders	(10,009		)	(10,008		)	(408		)	—			(20,425		)
Consolidation of Bison Midstream net assets	—			—			—			303,168			303,168
Cash advance from Summit Investments to contributed subsidiaries, net	—			—			—			9,166			9,166
Expenses paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			2,106			2,106
Class B membership interest unit-based compensation	13			—			—			122			135
Partners' capital, March 31, 2013	$	415,302		$	376,276		$	20,064		$	526,948		$	1,338,590

Partners' capital, January 1, 2014	$	566,532		$	379,287		$	23,324		$	232,594		$	1,201,737
Net income	1,741			1,373			431			2,828			6,373
SMLP unit-based compensation	1,063			—			—			—			1,063
Tax withholdings on vested LTIP awards	(656		)	—			—			—			(656		)
Issuance of common units, net of offering costs	198,095			—			—			—			198,095
Contribution from general partner	—			—			4,235			—			4,235
Purchase of Red Rock Gathering	—			—			—			(305,000		)	(305,000		)
Excess of purchase price over acquired carrying value of Red Rock Gathering	(36,228		)	(25,691		)	(1,264		)	63,183			—
Cash advance from Summit Investments to Red Rock Gathering	—			—			—			1,982			1,982
Expenses paid by Summit Investments on behalf of Red Rock Gathering	—			—			—			4,413			4,413
Distributions to unitholders	(13,958		)	(11,717		)	(691		)	—			(26,366		)
Partners' capital, March 31, 2014	$	716,589		$	343,252		$	26,035		$	—		$	1,085,876

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



	Three months ended March 31,
	2014			2013
	(In thousands)
Cash flows from operating activities:
Net income	$	6,373		$	13,864
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	19,868			14,192
Amortization of deferred loan costs	604			435
Unit-based compensation	1,063			462
Changes in operating assets and liabilities:
Accounts receivable	20,773			(5,744		)
Due to/from affiliate	390			(2,058		)
Trade accounts payable	5,949			7,334
Change in deferred revenue	3,727			2,686
Ad valorem taxes payable	(4,305		)	(4,639		)
Accrued interest	(6,404		)	(16		)
Other, net	471			(903		)
Net cash provided by operating activities	48,509			25,613

Cash flows from investing activities:
Capital expenditures	(40,100		)	(28,297		)
Acquisition of Red Rock Gathering from affiliate	(305,000		)	—
Net cash used in investing activities	(345,100		)	(28,297		)

Cash flows from financing activities:
Distributions to unitholders	(26,366		)	(20,425		)
Borrowings under revolving credit facility	125,000			15,000
Repayments under revolving credit facility	(20,000		)	—
Deferred loan costs	(65		)	—
Tax withholdings on vested LTIP awards	(656		)	—
Proceeds from issuance of common units, net	198,095			—
Contribution from general partner	4,235			—
Cash advance from Summit Investments to contributed subsidiaries, net	1,982			9,166
Expenses paid by Summit Investments on behalf of Red Rock Gathering	4,413			2,106
Net cash provided by financing activities	286,638			5,847
Net change in cash and cash equivalents	(9,953		)	3,163
Cash and cash equivalents, beginning of period	20,357			11,334
Cash and cash equivalents, end of period	$	10,404		$	14,497

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)



	Three months ended March 31,
	2014		2013
	(In thousands)
Supplemental Cash Flow Disclosures:
Cash interest paid	$	14,308	$	1,889
Less: capitalized interest	1,358		493
Interest paid (net of capitalized interest)	$	12,950	$	1,396

Noncash Investing and Financing Activities:
Capital expenditures in trade accounts payable (period-end accruals)	$	8,170	$	5,960
Excess of purchase price over acquired carrying value of Red Rock Gathering	63,183		—

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 developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America.

Effective with the completion of its IPO on October 3, 2012, SMLP had a 100% ownership interest in Summit Midstream Holdings, LLC ("Summit Holdings") which had a 100% ownership interest in both DFW Midstream Services LLC ("DFW Midstream") and Grand River Gathering, LLC ("Grand River Gathering").

On June 4, 2013, the Partnership acquired all of the membership interests of Bison Midstream, LLC ("Bison Midstream") from a wholly owned subsidiary of Summit Midstream Partners, LLC ("Summit Investments") (the "Bison Drop Down"), and thereby acquired certain associated natural gas gathering pipeline, dehydration and compression assets in the Bakken Shale Play in Mountrail and Burke counties in North Dakota (the "Bison Gas Gathering system").

Prior to the Bison Drop Down, on February 15, 2013, Summit Investments acquired Bear Tracker Energy, LLC ("BTE"). 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.

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

In October 2012, Summit Investments acquired ETC Canyon Pipeline, LLC ("Canyon") from a subsidiary of Energy Transfer Partners, L.P. ("Energy Transfer Partners"). The Canyon gathering and processing assets were contributed to Red Rock Gathering Company, LLC ("Red Rock Gathering"), a newly formed, wholly owned subsidiary of Summit Investments. Red Rock Gathering gathers and processes natural gas and natural gas liquids in the Piceance Basin in western Colorado and eastern Utah. On March 18, 2014, SMLP acquired all of the membership interests of Red Rock Gathering from a subsidiary of Summit Investments (the "Red Rock Drop Down"). Concurrent with the closing of the Red Rock Drop Down, SMLP contributed its interest in Red Rock Gathering to Grand River Gathering. For additional information, see Notes 6 and 12.

Summit Investments is a Delaware limited liability company and the predecessor for accounting purposes (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"). As of March 31, 2014, Summit Investments, through a wholly owned subsidiary, held 9,641,397 SMLP common units, 24,409,850 SMLP subordinated units and 1,200,651 general partner units representing a 2% general partner interest in SMLP.

SMLP is managed and operated by the board of directors and executive officers of Summit Midstream GP, LLC (the "general partner"). Summit Investments, as the ultimate owner of our general partner, controls SMLP and has the right to appoint the entire board of directors of our general partner, including our independent directors. SMLP's operations are conducted through, and our operating assets are owned by, various operating subsidiaries. However, neither SMLP nor its subsidiaries 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, treating and processing 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, treat and process across our systems. Our gathering and processing systems and the unconventional resource basins in which they operate as of March 31, 2014 were as follows:


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


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


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


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

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

Basis of Presentation and Principles of Consolidation. We prepare our unaudited condensed consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP"). These principles are established by the Financial Accounting Standards Board. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, including fair value measurements, the reported amounts of revenue and expense, and the disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.

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

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

We conduct our operations in the midstream sector with four operating segments: Mountaineer Midstream, Bison Midstream, DFW Midstream and Grand River Gathering. However, due to their similar characteristics and how we manage our business, we have aggregated these segments into one reportable segment for disclosure purposes. The assets of our reportable segment consist of natural gas gathering and processing systems and related plant and equipment. Our operating segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations.

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.

For additional information, see Note 1 to the audited consolidated financial statements included in the 2013 Annual Report.

Table of Contents

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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



	March 31, 2014				December 31, 2013
	Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)
	(In thousands)
Revolving credit facility	$	391,000	$	391,000	$	286,000	$	286,000
Senior notes	300,000		321,500		300,000		314,625

The revolving credit facility’s carrying value on the balance sheet is its fair value due to its floating interest rate. The fair value for the senior notes is based on an average of nonbinding broker quotes as of March 31, 2014 and December 31, 2013. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the senior notes.

Commitments and Contingencies. We record accruals for loss contingencies when we determine that it is probable that a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events.

Revenue Recognition. We generate the majority of our revenue from the natural gas gathering, treating and processing services that we provide to our natural gas producer customers. We also generate revenue from our marketing of natural gas and natural gas liquids ("NGLs"). We realize revenues by receiving fees from our producer customers or by selling the residue natural gas and NGLs.

We recognize revenue earned from fee-based gathering, treating and processing services in gathering services and other fees revenue. We also earn revenue from the sale of physical natural gas purchased from our customers under percentage-of-proceeds and keep-whole arrangements. These revenues are recognized in natural gas, NGLs and condensate sales and other with corresponding expense recognition in cost of natural gas and NGLs. We sell the natural gas that we retain from our DFW Midstream customers to offset the power expenses of the electric-driven compression on the DFW Midstream system. We also sell condensate retained from our gathering services at Grand River Gathering. Revenues from the retainage of natural gas and condensate are recognized in natural gas, NGLs and condensate sales and other; the associated expense is included in operation and maintenance expense. Certain customers reimburse us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis.

We recognize revenue when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable, and (iv) collectability is reasonably assured.

We obtain access to natural gas and provide services principally under contracts that contain one or more of the following arrangements:

•

Fee-based arrangements. Under fee-based arrangements, we receive a fee or fees for one or more of the following services: natural gas gathering, treating, and/or processing. Fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase natural gas at the wellhead, or other receipt points, at a settled price at the delivery point less a specified amount, generally the same as the fees we would otherwise charge for gathering of natural gas from the wellhead location to the delivery point. The margins earned are directly related to the volume of natural gas that flows through the system.

•

Percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat the natural gas, process the natural gas and/or sell the natural gas to a third party for processing. We then remit to our producers an agreed-upon percentage of the actual proceeds

Table of Contents

received from sales of the residue natural gas and NGLs. Certain of these arrangements may also result in returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. The margins earned are directly related to the volume of natural gas that flows through the system and the price at which we are able to sell the residue natural gas and NGLs.

•

Keep-Whole. Under keep-whole arrangements, after processing we keep 100% of the NGLs produced, and the processed natural gas, or value of the natural gas, is returned to the producer. Since some of the natural gas is used and removed during processing, we compensate the producer for the amount of natural gas used and removed in processing by supplying additional natural gas or by paying an agreed-upon value for the natural gas utilized. These arrangements have commodity price exposure for us because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.

Certain of our natural gas gathering or processing agreements provide for a monthly, quarterly or annual minimum volume commitment ("MVC") from certain of our customers. Under these MVCs, our customers agree to ship a minimum volume of natural gas on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contract period if its actual throughput volumes are less than its MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering or processing fees in one or more subsequent periods to the extent that such customer's throughput volumes in subsequent periods exceed its MVC for that period.

We record customer billings for obligations under their MVCs as deferred revenue when the customer has the right to utilize shortfall payments to offset gathering or processing fees in subsequent periods. We recognize deferred revenue under these arrangements in revenue once all contingencies or potential performance obligations associated with the related volumes have either (i) been satisfied through the gathering or processing of future excess volumes of natural gas, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the applicable natural gas gathering agreement. We classify deferred revenue as current for arrangements where the expiration of a customer's right to utilize shortfall payments is twelve months or less. A rollforward of current and noncurrent deferred revenue follows.



	Three months ended March 31, 2014				Three months ended March 31, 2013
	Current		Noncurrent		Current		Noncurrent
	(In thousands)
Deferred revenue, beginning of period	$	1,555	$	29,683	$	865	$	10,899
Additions (1)	—		3,727		—		5,470
Deferred revenue, end of period	$	1,555	$	33,410	$	865	$	16,369

__________

(1) Noncurrent for the three months ended March 31, 2013 includes amounts recognized in connection with the Bison Drop Down.

As of March 31, 2014, accounts receivable included $2.3 million of shortfall payments related to MVC arrangements that can be utilized to offset gathering fees in subsequent periods. Current and noncurrent deferred revenue at March 31, 2014 represent amounts that provide the customer the ability to offset its gathering fees over the next 8 years to the extent that the customer's throughput volumes exceeds its MVC.

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 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 payments to the general partner in connection with their incentive distribution rights ("IDRs"), by the weighted-average number of common and subordinated units outstanding during the three months ended March 31, 2014 and 2013. Diluted earnings per limited partner unit reflects the potential dilution that could occur if securities or other agreements to issue common units, such as unit-based compensation, were exercised, settled or converted

Table of Contents

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 March 31, 2014 or December 31, 2013. However, we can provide no assurances that significant costs and liabilities will not be incurred by the Partnership in the future. We are currently not aware of any material contingent liabilities that exist with respect to environmental matters.

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

Recent Accounting Pronouncements. Accounting standard setters frequently issue new or revised accounting rules. We review new pronouncements to determine the impact, if any, on our financial statements. There are currently no recent pronouncements that have been issued that we believe will materially affect our financial statements.

3. PROPERTY, PLANT, AND EQUIPMENT, NET

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



	Useful lives (In years)	March 31,			December 31,
	Useful lives (In years)	2014			2013
	(Dollars in thousands)
Natural gas gathering and processing systems	30	$	782,250		$	744,359
Compressor stations and compression equipment	30	393,587			380,000
Construction in progress	n/a	49,535			83,765
Other	4-15	33,652			21,304
Total		1,259,024			1,229,428
Accumulated depreciation		(81,868		)	(71,347		)
Property, plant, and equipment, net		$	1,177,156		$	1,158,081

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 March 31,
	2014		2013
	(In thousands)
Depreciation expense	$	10,521	$	7,817
Capitalized interest	1,358		493

Table of Contents

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:



	March 31, 2014
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
	(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(6,749	)	$	17,446
Contract intangibles	12.5	426,464		(51,120		)	375,344
Rights-of-way	24.2	110,909		(8,874		)	102,035
Total amortizable intangible assets		$	561,568	$	(66,743	)	$	494,825

Unfavorable gas gathering contract	10.0	$	10,962	$	(4,796	)	$	6,166



	December 31, 2013
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
	(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(6,315	)	$	17,880
Contract intangibles	12.4	426,464		(43,158		)	383,306
Rights-of-way	24.3	108,706		(7,715		)	100,991
Total amortizable intangible assets		$	559,365	$	(57,188	)	$	502,177

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

We recognized amortization expense as follows:



	Three months ended March 31,
	2014			2013
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	434		$	572
Amortization expense – contract intangibles	7,962			5,287
Amortization expense – rights-of-way	1,159			808
Amortization expense – unfavorable gas gathering contract	(208		)	(292		)

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



	Assets		Liabilities
	(In thousands)
2014	$	30,821	$	1,179
2015	43,836		1,649
2016	44,079		1,571
2017	42,811		1,767
2018	42,352		—

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

Table of Contents

5. LONG-TERM DEBT

Long-term debt consisted of the following:



	March 31,		December 31,
	2014		2013
	(In thousands)
Variable rate senior secured revolving credit facility (2.42% at March 31, 2014 and December 31, 2013) due November 2018	$	391,000	$	286,000
7.50% Senior unsecured notes due July 2021	300,000		300,000
Total long-term debt	$	691,000	$	586,000

Revolving Credit Facility. We have a senior secured revolving credit facility. The revolving credit facility is secured by the membership interests of Summit Holdings and those of its subsidiaries. Substantially all of Summit Holdings' and its subsidiaries' assets are pledged as collateral under the revolving credit facility. The revolving credit facility, and Summit Holdings' obligations, are guaranteed by SMLP and each of its subsidiaries 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") or an Alternate Base Rate ("ABR") plus an applicable margin, as defined in the credit agreement. At March 31, 2014, the applicable margin under LIBOR borrowings was 2.25%, the interest rate was 2.42% and the unused portion of the revolving credit facility totaled $309.0 million (subject to a commitment fee of 0.375%).

As of March 31, 2014, we were in compliance with the covenants in the revolving credit facility. There were no defaults or events of default during the three months ended March 31, 2014.

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

We pay interest on the senior notes semi-annually in cash in arrears on January 1 and July 1 of each year. The senior notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The senior notes are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness.

SMLP and all of its subsidiaries other than the Co-Issuers (the "Guarantors") have fully and unconditionally and jointly and severally guaranteed the senior notes. SMLP has no independent assets or operations. Summit Holdings has no assets or operations other than its ownership of its wholly owned subsidiaries and activities associated with its borrowings under the revolving credit facility and the senior notes. Finance Corp. has no independent assets or operations and was formed for the sole purpose of being a co-issuer of certain of Summit Holdings' indebtedness, including the senior notes. There are no significant restrictions on the ability of SMLP or Summit Holdings to obtain funds from its subsidiaries by dividend or loan.

Effective as of April 7, 2014, all of the holders of our senior notes exchanged their unregistered senior notes and the guarantees of those notes for registered notes and guarantees. The terms of the registered senior notes are substantially identical to the terms of the unregistered senior notes, except that the transfer restrictions, registration rights and provisions for additional interest relating to the unregistered senior notes do not apply to the registered senior notes.

As of March 31, 2014, we were in compliance with the covenants for the senior notes. There were no defaults or events of default during the three months ended March 31, 2014.

6. PARTNERS' CAPITAL

Partners' Capital

In March 2014, we completed an underwritten public offering of 10,350,000 common units at a price of $38.75 per unit (the "March 2014 Offering"), of which 5,300,000 common units were offered by the Partnership and 5,050,000 common units were offered by Summit Investments, pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC. Concurrent with the March 2014 Offering, Summit Investments made a capital contribution to maintain its 2% general partner interest in SMLP. We used the proceeds from the primary offering to fund a portion of the purchase of Red Rock Gathering. See Notes 1 and 12 for additional information.

Table of Contents

A rollforward of the number of common limited partner, subordinated limited partner and general partner units follows.



	Common	Subordinated	General partner	Total
Units, January 1, 2014	29,079,866	24,409,850	1,091,453	54,581,169
Units issued in connection with the March 2014 Offering (1)	5,300,000	—	108,337	5,408,337
Units issued under LTIP (1)(2)	41,393	—	861	42,254
Units, March 31, 2014	34,421,259	24,409,850	1,200,651	60,031,760

__________

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

(2) Units issued to common unitholders is net of 13,170 units withheld to meet the minimum statutory tax withholding requirement.

There was no unit activity during the three months ended March 31, 2013.

Summit Investments' Equity in Contributed Subsidiaries. Summit Investments' equity in contributed subsidiaries represents its position in the net assets of Red Rock Gathering and Bison Midstream that have been acquired by SMLP. The balance also reflects net income attributable to Summit Investments for Red Rock Gathering and Bison Midstream for the periods beginning on their respective acquisition dates by Summit Investments and ending on the dates they were acquired by the Partnership. For the three months ended March 31, 2014 and 2013, net income was attributed to Summit Investments for (i) Red Rock Gathering for the period from January 1, 2014 to March 18, 2014 and the three months ended March 31, 2013 and (ii) Bison Midstream for the period from February 16, 2013 to March 31, 2013. Although included in partners' capital, these net income amounts have been excluded from the calculation of EPU for the three months ended March 31, 2014 and 2013. For additional information, see Notes 1, 7 and 12.

Subordination. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages for unpaid quarterly distributions or quarterly distributions less than the minimum quarterly distribution. If we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess available cash to pay any distribution arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and thereafter no common units will be entitled to arrearages.

The subordination period will end on the first business day after we have earned and paid at least (1) $1.60 (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and subordinated unit and the corresponding distribution on the general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2015 or (2) $2.40 (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the corresponding distributions on the general partner's 2.0% interest and the related distribution on the incentive distribution rights for the four-quarter period immediately preceding that date, in each case provided there are no arrearages on the common units at that time.

Cash Distribution Policy

Our partnership agreement requires that we distribute all of our available cash (as defined below) within 45 days after the end of each quarter to unitholders of record on the applicable record date. Our policy is to distribute to our unitholders an amount of cash each quarter that is equal to or greater than the minimum quarterly distribution stated in our partnership agreement.

Minimum Quarterly Distribution. Our partnership agreement generally requires that we make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.40 per unit, or $1.60 on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. The amount

Table of Contents

of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

Definition of Available Cash. Available cash generally means, for any quarter, all cash on hand at the end of that quarter:


•	less the amount of cash reserves established by our general partner at the date of determination of available cash for that quarter to:


•	provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debt service requirements);


•	comply with applicable law, any of our debt instruments or other agreements; or

•

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);


•	plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

General Partner Interest and Incentive Distribution Rights. Our general partner is entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner's initial 2.0% interest in our distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.

Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentage allocations, up to a maximum of 50.0% (as set forth in the chart below), of the cash we distribute from operating surplus in excess of $0.46 per unit per quarter. The maximum distribution includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution does not include any distributions that our general partner may receive on any common or subordinated units that it owns.

Percentage Allocations of Available Cash. The following table illustrates the percentage allocations of available cash between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth in the column Marginal Percentage Interest in Distributions are the percentage interests of our general partner and the unitholders in any available cash we distribute up to and including the corresponding amount in the column Total Quarterly Distribution Per Unit Target Amount. The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.



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

SMLP allocated its distribution in accordance with the second target distribution level for distributions attributable to the quarter ended March 31, 2014. Details of cash distributions declared to date follow.

Table of Contents



Attributable to the quarter ended	Payment date	Per-unit distribution		Cash paid (or payable) to common unitholders		Cash paid (or payable) to subordinated unitholders		Cash paid (or payable) to general partner interest		Cash paid (or payable) for IDRs		Total distribution
		(Dollars in thousands, except per-unit amounts)
December 31, 2012	February 14, 2013	$	0.4100	$	10,009	$	10,008	$	408	$	—	$	20,425
March 31, 2013	May 15, 2013	0.4200		10,253		10,252		418		—		20,923
June 30, 2013	August 14, 2013	0.4350		12,647		10,618		475		—		23,740
September 30, 2013	November 14, 2013	0.4600		13,377		11,229		502		—		25,108
December 31, 2013	February 14, 2014	0.4800		13,958		11,717		528		163		26,366
March 31, 2014	May 15, 2014	0.5000		17,211		12,205		608		360		30,384

7. EARNINGS PER UNIT

The following table presents details on EPU.



	Three months ended March 31,
	2014		2013
	(Dollars in thousands, except per-unit amounts)
Net income	$	6,373	$	13,864
Less: net income attributable to Summit Investments	2,828		1,384
Net income attributable to SMLP	3,545		12,480
Less: net income attributable to general partner, including IDRs	431		250
Net income attributable to limited partners	$	3,114	$	12,230

Numerator for basic and diluted EPU:
Allocation of net income among limited partner interests:
Net income attributable to common units	$	2,508	$	6,115
Net income attributable to subordinated units	606		6,115
Net income attributable to limited partners	$	3,114	$	12,230

Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic	29,911,669		24,412,427
Effect of non-vested phantom units and non-vested restricted units	155,989		43,176
Weighted-average common units outstanding – diluted	30,067,658		24,455,603

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

Net income per limited partner unit:
Common unit – basic	$	0.08	$	0.25
Common unit – diluted	$	0.08	$	0.25
Subordinated unit – basic and diluted	$	0.02	$	0.25

There were no units excluded from diluted earnings per unit as we do not have any anti-dilutive units for the three months ended March 31, 2014 or 2013. See Notes 6 and 8 for additional information.

Table of Contents

8. UNIT-BASED COMPENSATION

Long-Term Incentive Plan. SMLP’s 2012 Long-Term Incentive Plan (the "LTIP") provides for the granting of unit-based awards, including common units, restricted units and phantom units to eligible officers, employees, consultants and directors of our general partner and its affiliates, thereby linking the recipients' compensation directly to SMLP’s performance. The LTIP is administered by the compensation committee of our general partner. A total of 5.0 million common units was reserved for issuance pursuant to and in accordance with the LTIP. As of March 31, 2014, approximately 4.6 million common units remained available for future issuance.

A rollfoward of phantom and restricted unit activity follows.



	Three months ended March 31, 2014				Three months ended March 31, 2013
	Units		Weighted-average grant date fair value		Units		Weighted-average grant date fair value
Nonvested phantom and restricted units, beginning of period	283,682		$	23.41	131,558		$	20.00
Phantom units granted	134,557		$	42.30	146,231		$	25.99
Phantom and restricted units vested	(58,049	)	$	24.95	—		—
Phantom units forfeited	(2,347	)	$	23.32	(962	)	$	25.99
Nonvested phantom and restricted units, end of period	357,843		$	30.26	276,827		$	23.15

A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. A restricted unit is a common limited partner unit that is subject to a restricted period during which the unit remains subject to forfeiture.

The phantom units granted in connection with the IPO vest on the third anniversary of the IPO. All other phantom units granted to date vest ratably over a three-year period. Grant date fair value is determined based on the closing price our common units on the date of grant multiplied by the number of phantom units awarded to the grantee. Holders of all phantom units granted to date are entitled to receive distribution equivalent rights for each phantom unit, providing for a lump sum cash amount equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. Upon vesting, phantom unit awards may be settled, at our discretion, in cash and/or common units, but the current intention is to settle all phantom unit awards with common units.

As of March 31, 2014, the unrecognized unit-based compensation related to the LTIP was $8.3 million. Incremental unit-based compensation will be recorded over the remaining vesting period of 2.96 years. Due to the limited and immaterial forfeiture history associated with the grants under the LTIP, no forfeitures were assumed in the determination of estimated compensation expense.

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



	Three months ended March 31,
	2014		2013
	(In thousands)
SMLP unit-based compensation	$	1,063	$	327

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

Table of Contents

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 primarily comprise natural gas gathering, treating and processing services we provide to our customers. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other 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 March 31,
	2014		2013
Revenue:
Counterparty A	17	%	18	%
Counterparty B	11	%	19	%
Counterparty C	10	%	*

__________

* Less than 10%

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



	March 31,		December 31,
	2014		2013
Accounts receivable:
Counterparty A	17	%	37	%
Counterparty B	12	%	11	%
Counterparty C	*		*

__________

* Less than 10%

10. RELATED-PARTY TRANSACTIONS

Recent Acquisition. See Notes 1, 6 and 12 for disclosure of the purchase of Red Rock Gathering from Summit Investments and the primary offering of common units to fund the Red Rock Drop Down.

Reimbursement of Expenses from General Partner. Our general partner and its affiliates do not receive a management fee or other compensation in connection with the management of our business, but will be reimbursed for expenses incurred on our behalf. Under our partnership agreement, we reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our general partner's employees and executive officers who perform services necessary to run our business. In addition, we reimburse our general partner for compensation, travel and entertainment expenses for the directors serving on the board of directors of our general partner and the cost of director and officer liability insurance. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

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



	March 31,		December 31,
	2014		2013
	(In thousands)
Due to affiliate	$	1,043	$	653

Table of Contents

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



	Three months ended March 31,
	2014		2013
	(In thousands)
Operation and maintenance expense	$	3,892	$	2,903
General and administrative expense	4,906		4,416

General and administrative expense for the three months ended March 31, 2013 includes $1.2 million of expenses allocated by the general partner.

Expense Allocations. During the three months ended March 31, 2014 and 2013, Summit Investments incurred interest expense which was related to capital projects at Red Rock Gathering. As such, the associated interest expense was allocated to Red Rock Gathering as a noncash contribution and capitalized into the basis of the asset.

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

Summit Investments allocated a portion of the annual expense associated with the Net Profits Interests to Red Rock Gathering during the three months ended March 31, 2013. This amount is reflected in general and administrative expenses in the statement of operations.

Expenses Paid by Summit Investments on Behalf of Red Rock Gathering. Prior to the Red Rock Drop Down, Summit Investments incurred certain support expenses and capital expenditures on behalf of Red Rock Gathering during the three months ended March 31, 2014 and 2013. These transactions were settled through membership interests prior to the Red Rock Drop Down.

Electricity Management Services Agreement. We entered into a consulting arrangement with EquiPower Resources Corp. to assist with managing DFW Midstream's electricity price risk. EquiPower Resources Corp. is an affiliate of Energy Capital Partners and is also the employer of a director of our general partner. Amounts paid for such services were as follows:



	Three months ended March 31,
	2014		2013
	(In thousands)
Payments for electricity management consulting services	$	72	$	55

Engineering Services Agreement. We entered into an engineering services arrangement with IPS Engineering/EPC. IPS Engineering/EPC is an affiliate of Energy Capital Partners. We paid $0.2 million for such services during the three months ended March 31, 2014.

11. COMMITMENTS AND CONTINGENCIES

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



	Three months ended March 31,
	2014		2013
	(In thousands)
Total rent expense	$	354	$	260

Legal Proceedings. The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position or results of operations.

Table of Contents

12. ACQUISITIONS

Red Rock Gathering System. On March 18, 2014, Summit Investments offered 100% of its interests in Red Rock Gathering to the Partnership in exchange for total cash consideration of $305.0 million, subject to customary working capital adjustments. Because of the common control aspects in the drop down transaction, the Red Rock Gathering acquisition was deemed a transaction between entities under common control and, as such, was accounted for on an “as if pooled” basis for all periods in which common control existed. SMLP’s financial results retrospectively include Red Rock’s financial results for all periods ending after October 23, 2012, the date Summit Investments acquired its interests, and before March 18, 2014.

Bison Gas Gathering System. On February 15, 2013, Summit Investments acquired BTE. On June 4, 2013, a subsidiary of Summit Investments entered into a purchase and sale agreement with SMLP whereby SMLP acquired the Bison Gas Gathering system. The Bison Gas Gathering system was carved out from BTE and primarily gathers associated natural gas production from customers operating in Mountrail and Burke counties in North Dakota under long-term contracts ranging from five years to 15 years. The weighted-average life of the acquired contracts was 12 years upon acquisition. For additional information, see Note 1.

Summit Investments accounted for its purchase of BTE (the "BTE Transaction") under the acquisition method of accounting, whereby the various gathering systems' identifiable tangible and intangible assets acquired and liabilities assumed were recorded based on their fair values as of February 15, 2013. The intangible assets that were acquired are composed of gas gathering agreement contract values and 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 system.

Because the Bison Drop Down was executed between entities under common control, SMLP recognized the acquisition of the Bison Gas Gathering system at historical cost which reflected Summit Investments recent fair value accounting for the BTE Transaction. Furthermore, due to the common control aspect, the Bison Drop Down was accounted for by SMLP on an “as if pooled” basis for all periods in which common control existed. Common control began on February 15, 2013 concurrent with Summit Investments' acquisition of BTE.

The fair values of the assets acquired and liabilities assumed as of February 15, 2013, were as follows (in thousands):



Purchase price assigned to Bison Gas Gathering system			$	303,168
Current assets	$	5,705
Property, plant, and equipment	85,477
Intangible assets	164,502
Other noncurrent assets	2,187
Total assets acquired	257,871
Current liabilities	6,112
Other noncurrent liabilities	2,790
Total liabilities assumed	$	8,902
Net identifiable assets acquired			248,969
Goodwill			$	54,199

We believe that the goodwill recorded represents the incremental value of future cash flow potential attributed to estimated future gathering services within the Williston Basin.

The Bison Drop Down closed on June 4, 2013. The total acquisition purchase price of $248.9 million was funded with $200.0 million of borrowings under SMLP’s revolving credit facility and the issuance of $47.9 million of SMLP common units to Summit Investments and $1.0 million of general partner interests to SMLP’s general partner. Summit Investments had a net investment in the Bison Gas Gathering system of $303.2 million.

Table of Contents

Supplemental Disclosures. As noted above, SMLP's acquisition of the Red Rock Gathering and Bison Gas Gathering systems were transactions between commonly controlled entities which required that SMLP account for the acquisitions in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership and the Red Rock Gathering and Bison Gas Gathering systems have been combined to reflect the historical operations, financial position and cash flows from the date common control began. Revenues and net income for the previously separate entities and the combined amounts for the three months ended March 31, 2014 and 2013, as presented in these unaudited condensed consolidated financial statements follow.



	Three months ended March 31,
	2014		2013
	(In thousands)
SMLP revenues	$	64,889	$	43,595
Red Rock Gathering system revenues	11,313		10,858
Bison Gas Gathering system revenues (1)	—		7,531
Combined revenues	$	76,202	$	61,984

SMLP net income	$	3,545	$	12,480
Red Rock Gathering system net income	2,828		797
Bison Gas Gathering system net income (1)	—		587
Combined net income	$	6,373	$	13,864

__________

(1) Results are fully reflected in SMLP's results of operations for the three months ended March 31, 2014.

See Notes 1, 5 and 6 for additional information.

Unaudited Pro Forma Financial Information. The following unaudited pro forma financial information assumes that the acquisition of Bison Midstream occurred on January 1, 2012. The pro forma results for Bison Midstream were derived from revenues and net income in 2013. The pro forma adjustments to the three months ended March 31, 2013 for Bison Midstream also reflect the impact of $200.0 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. Nonrecurring transaction costs incurred during the three months ended March 31, 2013 were immaterial.



	Three months ended March 31, 2013
	(In thousands)
Total Bison Midstream revenues included in consolidated revenues	$	7,531
Total Bison Midstream net income included in consolidated net income	587

Pro forma total revenues	$	70,013
Pro forma net income	12,650

Pro forma common EPU - basic and diluted	$	0.25
Pro forma subordinated EPU - basic and diluted	0.25

The unaudited pro forma financial information presented above is not necessarily indicative of (i) what our financial position or results of operations would have been if the acquisition of Bison Midstream had occurred on January 1, 2012, or (ii) what SMLP’s financial position or results of operations will be for any future periods.

Table of Contents

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

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

Overview

We are a growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America. We gather natural gas from both dry gas and liquids-rich regions. Dry gas regions contain natural gas reserves that are primarily composed of methane. Liquids-rich regions include natural gas reserves that contain natural gas liquids, or NGLs, in addition to methane. We currently operate natural gas gathering systems in four unconventional resource basins: (i) the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia; (ii) the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; (iii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and (iv) the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah. We believe that our gathering systems are well positioned to capture additional volumes from increased producer activity in these regions in the future.

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

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

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

Most of our gas gathering agreements are underpinned by areas of mutual interest and MVCs. Our areas of mutual interest cover over 1.4 million acres in the aggregate, have original terms that range from five years to 25 years, and provide that any natural gas produced from wells drilled by our customers within the areas of mutual interest will be shipped on our gathering systems. The MVCs, which totaled 4.0 Tcf at March 31, 2014 and average approximately 1,220 MMcf/d through 2018, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our minimum volume commitments have remaining terms that range from two to 13 years and, as of March 31,

Table of Contents

2014, had a weighted-average remaining life of 10.3 years, assuming minimum throughput volumes for the remainder of the term.

Trends and Outlook

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


•	Natural gas and crude oil supply and demand dynamics;


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


•	Interest rate environment; and


•	Rising operating costs and inflation.

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

How We Evaluate Our Operations

We conduct our operations in the midstream sector through four operating segments. However, due to their similar characteristics and how we manage our business, we have aggregated these segments into a single reporting segment for disclosure purposes. Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on a regular basis for consistency and trend analysis. These metrics include:


•	throughput volume;


•	operation and maintenance expenses;


•	EBITDA and adjusted EBITDA; and


•	distributable cash flow.

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

Results of Operations

Items Affecting the Comparability of Our Financial Results

Our historical results of operations may not be comparable to our future results of operations due in part to our June 2013 acquisitions. The unaudited condensed consolidated financial statements reflect the results of operations of: (i) Bison Midstream since February 16, 2013 and (ii) Mountaineer Midstream since June 22, 2013. In addition, we accounted for the Red Rock Drop Down on an "as-if pooled" basis for all periods presented because the Red Rock Drop Down was executed in October 2012 by entities under common control. As such, Red Rock Gathering's contribution to the Partnership's financial and operating results for the three months ended March 31, 2014 and 2013 have been reflected in the financial and operating results of its parent, Grand River Gathering. For additional information, see Notes 1, 5 and 12 to the unaudited condensed consolidated financial statements.

Overview of the Three Months Ended March 31, 2014 and 2013

Revenues. For the three months ended March 31, 2014, total revenues increased $14.2 million, or 23%, largely as a result of Bison Midstream's contribution to natural gas, NGLs and condensate sales and other, Mountaineer Midstream's contribution to gathering services and other fees and an increase in gathering services and other fees for Grand River Gathering. These increases were partially offset by declines in gathering services and other fees on the DFW Midstream. Total revenues for the three months ended March 31, 2014 included a $5.4 million contribution from Mountaineer Midstream.

Costs and Expenses. For the three months ended March 31, 2014, total costs and expenses increased $16.5 million, or 36%, primarily due to the impact on cost of natural gas and NGLs of a full quarter of operations at Bison Midstream, an increase in depreciation and amortization associated with assets placed in service and increased

Table of Contents

contract amortization across all gathering systems, and the acquisition of Mountaineer Midstream. Total costs and expenses for the three months ended March 31, 2014 included a $3.3 million contribution from Mountaineer Midstream.

Volumes. Our revenues are primarily attributable to the volume of natural gas that we gather, treat and process and the rates we charge for those services. For the three months ended March 31, 2014, our aggregate throughput volumes increased to an average of 1,311 MMcf/d, compared with an average of 1,090 MMcf/d for the three months ended March 31, 2013. The increase in volume throughput largely reflects the contribution from Mountaineer Midstream, partially offset by volume throughput declines on the DFW Midstream system. Volume throughput on the DFW Midstream system benefited in the prior-year period due to the first quarter 2013 commissioning of an additional compressor which increased throughput capacity on the DFW Midstream system from 410 MMcf/d to 450 MMcf/d.

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



	Three months ended March 31,						Percentage Change
	2014			2013			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and other fees	$	50,072		$	45,972		9	%
Natural gas, NGLs and condensate sales and other	26,356			16,292			62	%
Amortization of favorable and unfavorable contracts (1)	(226		)	(280		)	(19	)%
Total revenues	76,202			61,984			23	%
Costs and expenses:
Operation and maintenance	19,181			17,579			9	%
Cost of natural gas and NGLs	15,281			7,965			92	%
General and administrative	7,886			6,567			20	%
Transaction costs	537			38			*
Depreciation and amortization	19,642			13,912			41	%
Total costs and expenses	62,527			46,061			36	%
Other income (expense)	1			1			—	%
Interest expense	(7,144		)	(1,879		)	*
Income before income taxes	6,532			14,045			(53	)%
Income tax expense	(159		)	(181		)	(12	)%
Net income	$	6,373		$	13,864		(54	)%

Other Financial Data:
EBITDA (2)	$	33,543		$	30,115		11	%
Adjusted EBITDA (2)	46,619			36,872			26	%
Capital expenditures	40,100			28,297			42	%
Acquisition capital expenditures (3)	305,000			—			*
Distributable cash flow (2)	33,733			32,359			4	%

Operating Data:
Miles of pipeline (end of period)	2,294			2,172			6	%
Aggregate average throughput (MMcf/d)	1,311			1,090			20	%

__________

* Not considered meaningful

(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.

Table of Contents

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

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

System Overview. Operating data by system as of or for the three months ended March 31 follows.



	Mountaineer Midstream (1)	Bison Midstream (2)				DFW Midstream				Grand River (3)
	2014	2014		2013		2014		2013		2014		2013
Miles of pipeline (end of period)	40	352		294		122		117		1,780		1,761
Aggregate average throughput (MMcf/d)	285	12		8		348		419		665		662
Average fee per Mcf	n/a	$	4.59	$	4.14	$	0.59	$	0.58	$	0.38	$	0.33
Total Remaining MVC Commitment (Bcf)	n/a	25		31		210		343		2,326		2,554
Average daily MVCs through 2018 (MMcf/d)(end of period)	n/a	13		13		119		161		722		705
Weighted-average remaining contract life (years)(end of period) (4)	n/a	6.3		7.3		5.9		6.9		10.9		11.9

__________

(1) Gathering system was not an asset of SMLP during the three months ended March 31, 2013.

(2) Includes contribution from Bison Midstream during the period from February 16, 2013 to March 31, 2013 due to the common control aspect of the Bison Drop Down. For the period of SMLP's common control ownership in 2013, average throughput was 16 MMcf/d.

(3) Includes contribution from Red Rock Gathering during the three months ended March 31, 2013 and the period from January 1, 2014 to March 18, 2014 due to the common control aspect of the Red Rock Drop Down.

n/a - Contract terms excluded for confidentiality purposes.

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

Mountaineer Midstream. Volume throughput for the Mountaineer Midstream system, which was acquired in late June 2013, increased throughout the first quarter of 2014 as a result of an active drilling program by our customer, Antero Resources Corp., as well as increased third-party pad site connections upstream of the Mountaineer Midstream system.

Bison Midstream. Bison Midstream system volume throughput during the three months ended March 31, 2014, was negatively impacted by (i) a continuation of severe winter weather in northwestern North Dakota during the first quarter of 2014 and (ii) operational challenges caused by water hydrate issues experienced during the fourth quarter of 2013 and the first quarter of 2014. During the first quarter of 2014, SMLP completed operational improvements on the Bison Midstream system that are expected to remediate the water hydrate issues going forward.

DFW Midstream. The decline in DFW Midstream system volume throughput during the three months ended March 31, 2014 was primarily the result of multiple customers temporarily shutting-in several large pad sites to drill and/or complete new wells beginning in the third quarter of 2013 and continuing into the first quarter of 2014. While this activity is beneficial over the long term, it can create volume and cash flow volatility over the short term. Volume throughput in the first quarter of 2013 also benefited from the January 2013 commissioning of a compressor which increased system throughput capacity from 410 MMcf/d to 450 MMcf/d.

Grand River. Grand River system volume throughput was flat during the three months ended March 31, 2014. Certain of our gas gathering agreements for the Grand River system include MVCs that, in the aggregate, increase over the next several years. As a result, lower volume throughput for the customers subject to these MVCs translated into larger MVC shortfall payments for the Grand River system during the first quarters of 2014 and 2013.

Gathering services and other fees. Gathering services and other fees increased during the three months ended March 31, 2014, largely as a result of our acquisition of the Mountaineer Midstream system and increases on the Grand River Gathering system as a result of the Red Rock Drop Down. The quarter-over-quarter increase on the Grand River system was largely driven by the proportionate contribution of higher margin throughput volumes from certain customers. Additionally, certain gas gathering agreements benefited from provisions which increased the

Table of Contents

gas gathering fee per Mcf on our Grand River and Bison Midstream systems. These increases were partially offset by the decline in volumes on the DFW Midstream system.

Natural gas, NGLs and condensate sales and other. The increase in natural gas, NGLs and condensate sales and other for the three months ended March 31, 2014, was primarily a result of the contribution from the Bison Midstream system.

Operation and Maintenance Expense. Operation and maintenance expense increased during the three months ended March 31, 2014, largely as a result of expenses associated with the Mountaineer Midstream system and a full quarter of operations at Bison Midstream in 2014, a $0.7 million increase in power-related costs at DFW Midstream, partially offset by a decline in operation and maintenance expenses at Grand River Gathering largely as a result of our purchase of previously leased compression assets in the first quarter of 2013 and a $0.5 million decline in carbon dioxide expenses at DFW Midstream.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs represents the expenses associated with the percent-of-proceeds and keep-whole arrangements under which the Bison Midstream and Grand River Gathering systems sell natural gas purchased from our customers. The increase in the three months ended March 31, 2014 is primarily a result of the contribution from the Bison Midstream system.

General and Administrative Expense. General and administrative expense increased during the three months ended March 31, 2014, largely as a result of an increase in salaries, benefits and incentive compensation primarily as a result of increased head count and an increase in professional services expense.

Transaction Costs. Transaction costs were $0.5 million for the three months ended March 31, 2014, and primarily related to financial and legal advisory costs associated with the Red Rock Drop Down.

Depreciation and Amortization Expense. Depreciation and amortization expense increased during the three months ended March 31, 2014 largely due to recognizing depreciation and amortization from the Bison Midstream and Mountaineer Midstream systems. An increase in contract amortization for the Grand River system and assets placed into service on the Grand River system also contributed to the increase.

Interest Expense and Affiliated Interest Expense. The increase in interest expense during the three months ended March 31, 2014, was primarily driven by our issuance of $300.0 million of 7.50% senior notes in June 2013.

Non-GAAP Financial Measures

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

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

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


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


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


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

Table of Contents


•	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.

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 March 31,
	2014			2013
	(In thousands)
Reconciliation of Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
Net income (1)	$	6,373		$	13,864
Add:
Interest expense	7,144			1,879
Income tax expense	159			181
Depreciation and amortization expense	19,642			13,912
Amortization of favorable and unfavorable contracts	226			280
Less:
Interest income	1			1
EBITDA (1)	$	33,543		$	30,115
Add:
Unit-based compensation	1,063			462
Adjustments related to MVC shortfall payments (2)	12,013			6,295
Adjusted EBITDA (1)	$	46,619		$	36,872
Add:
Interest income	1			1
Less:
Cash interest paid	14,308			1,889
Senior notes interest expense (3)	(6,500		)	—
Cash taxes paid	—			—
Maintenance capital expenditures(4)	5,079			2,625
Distributable cash flow	$	33,733		$	32,359

__________

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

(2) Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. We include 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.

Table of Contents

(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.

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.



	Three months ended March 31,
	2014			2013
	(In thousands)
Reconciliation of Net Cash Provided by Operating Activities to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
Net cash provided by operating activities (1)	$	48,509		$	25,613
Add:
Interest expense (2)	6,540			1,444
Income tax expense	159			181
Changes in operating assets and liabilities	(20,601		)	3,340
Less:
Unit-based compensation	1,063			462
Interest income	1			1
EBITDA (1)	$	33,543		$	30,115
Add:
Unit-based compensation	1,063			462
Adjustments related to MVC shortfall payments(3)	12,013			6,295
Adjusted EBITDA (1)	$	46,619		$	36,872
Add:
Interest income	1			1
Less:
Cash interest paid	14,308			1,889
Senior notes interest expense (4)	(6,500		)	—
Cash taxes paid	—			—
Maintenance capital expenditures (5)	5,079			2,625
Distributable cash flow	$	33,733		$	32,359

__________

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

(2) Interest expense presented in the cash flow-basis non-GAAP reconciliation above differs from the interest expense presented in the net income-basis non-GAAP reconciliation presented earlier due to adjustments for amortization of deferred loan costs. For the three months ended March 31, 2014, interest expense excluded $0.6 million of amortization of deferred loan costs. For the three months ended March 31, 2013, interest expense excluded $0.4 million of amortization of deferred loan costs.

(3) Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. We include 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.

Table of Contents

Liquidity and Capital Resources

In October 2013, SMLP filed a shelf registration statement on Form S-3 with the SEC to register up to $1.2 billion of equity and debt securities in primary offerings as well as all of the 14,691,397 common units held by Summit Investments in accordance with our obligations under a registration rights agreement that was executed in connection with our IPO.

In January 2014, we filed a registration statement on Form S-4 with the SEC to offer to exchange all of the unregistered senior notes and guarantees for registered senior notes and guarantees with substantially identical terms. On March 7, 2014, the SEC declared our registration statement effective and we began the notice process to properly effect the exchange. The exchange period ended on April 7, 2014, with 100% of the unregistered senior notes being exchanged for registered notes.

In future periods, we expect our sources of liquidity to include:


•	cash generated from operations;


•	borrowings under the revolving credit facility; and


•	additional issuances of debt and equity securities.

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

Long-Term Debt

Revolving Credit Facility. We have a $700.0 million senior secured revolving credit facility. The revolving credit facility is secured by the membership interests of Summit Holdings and those of its subsidiaries. Substantially all of Summit Holdings' and its subsidiaries' assets are pledged as collateral under the revolving credit facility. The facility, and Summit Holdings' obligations, are guaranteed by SMLP and each of its subsidiaries. At our option, borrowings under the revolving credit facility bear interest at a variable rate per annum equal to either (i) the London InterBank Offered Rate plus the applicable margin ranging from 1.75% to 2.75% or (ii) a base rate plus the applicable margin ranging from 0.75% to 1.75%. As of March 31, 2014, the outstanding balance of the revolving credit facility was $391.0 million and the unused portion totaled $309.0 million.

As of March 31, 2014, we were in compliance with the covenants in the revolving credit facility. There were no defaults or events of default during the three months ended March 31, 2014. See Note 5 to the unaudited condensed consolidated financial statements for additional information.

Senior Notes. In June 2013, Summit Holdings and its 100% owned finance subsidiary, Finance Corp. (together with Summit Holdings, the "Co-Issuers"), issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021 (the "senior notes"). The senior notes were initially sold in reliance on Rule 144A and Regulation S under the Securities Act. Effective as of April 7, 2014, all of the holders of our senior notes exchanged their unregistered senior notes and the guarantees of those notes for registered notes and guarantees. The terms of the registered senior notes are substantially identical to the terms of the unregistered senior notes, except that the transfer restrictions, registration rights and provisions for additional interest relating to the unregistered senior notes do not apply to the registered senior notes.

The senior notes are senior, unsecured obligations, rank equally in right of payment with all of our existing and future senior obligations and are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness. SMLP and all of its subsidiaries other than the Co-Issuers (the "Guarantors") have fully and unconditionally and jointly and severally guaranteed the senior notes. SMLP has no independent assets or operations. Summit Holdings has no assets or operations other than its ownership of its wholly owned subsidiaries and activities associated with its borrowings under the revolving credit facility and the senior notes. Finance Corp. has no independent assets or operations and was formed for the sole purpose of being a co-issuer of certain of Summit Holdings' indebtedness, including the senior notes. There are no significant restrictions on the ability of SMLP or Summit Holdings to obtain funds from its subsidiaries by dividend or loan.

There were no defaults or events of default during the three months ended March 31, 2014. For additional information, see Note 5 to the unaudited condensed consolidated financial statements.

Table of Contents

Cash Flows

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



	Three months ended March 31,
	2014			2013
	(In thousands)
Net cash provided by operating activities	$	48,509		$	25,613
Net cash used in investing activities	(345,100		)	(28,297		)
Net cash provided by financing activities	286,638			5,847
Change in cash and cash equivalents	$	(9,953	)	$	3,163

Operating activities. Cash flows from operating activities increased by $22.9 million for the three months ended March 31, 2014 largely due to cash received as a result of MVCs and accelerated accounts receivable collections in comparison to prior year.

Investing activities. Cash flows used in investing activities for the three months ended March 31, 2014 largely reflect the Red Rock Drop Down. Additional expenditures in the first quarter of 2014 primarily reflect construction of a processing plant on the Grand River Gathering system, projects to expand compression capacity on the Bison Midstream system, adding pipeline on the Mountaineer Midstream system, and commissioning a new natural gas treating facility on the DFW Midstream system, which was commissioned in February 2014.

Cash flows used in investing activities in the first quarter of 2013 reflect the construction of new gathering pipeline across the DFW Midstream system and the acquisition of previously leased compression assets on the Grand River system. We also commissioned a new compressor unit on the DFW Midstream system in January 2013.

Financing activities. Details of cash flows provided by financing activities for the three months ended March 31, 2014 and 2013, were as follows:



	Three months ended March 31,
	2014			2013
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	$	(26,366	)	$	(20,425	)
Borrowings under revolving credit facility	125,000			15,000
Repayments under revolving credit facility	(20,000		)	—
Deferred loan costs	(65		)	—
Tax withholdings on vested LTIP awards	(656		)	—
Proceeds from issuance of common units	198,095			—
Contribution from general partner	4,235			—
Cash advance from Summit Investments to contributed subsidiaries	1,982			9,166
Expenses paid by Summit Investments on behalf of Red Rock Gathering	4,413			2,106
Net cash provided by financing activities	$	286,638		$	5,847

Net cash provided by financing activities for the three months ended March 31, 2014 was primarily composed of proceeds from the March 2014 Offering and net borrowings under our revolving credit facility both of which were used to fund the Red Rock Drop Down.

Net cash used in financing activities for the three months ended March 31, 2013 was primarily composed of distributions declared in respect of the fourth quarter of 2012 (paid in the first quarter of 2013) and repayments under our revolving credit facility.

Capital Requirements

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

Table of Contents


•	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.

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

Distributions

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

Credit Risk and Customer Concentration

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

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the three months ended March 31, 2014.

Critical Accounting Policies and Estimates

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

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

There have been no changes in the accounting methodology for items that we have identified as critical accounting estimates during the three months ended March 31, 2014. For additional information regarding critical accounting estimates, see the Critical Accounting Policies and Estimates section of MD&A included in the 2013 Annual Report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Interest Rate Risk

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

A hypothetical 1.0% increase (decrease) in interest rates would have increased (decreased) our interest expense by approximately $0.8 million for the three months ended March 31, 2014.

Table of Contents

Commodity Price Risk

We currently generate a substantial majority of our revenues pursuant to long-term, primarily fee-based gas gathering agreements, many of which include MVCs and areas of mutual interest. Our direct commodity price exposure relates to (i) our sale of physical natural gas we retain from our DFW Midstream customers, (ii) our procurement of electricity to operate our electric-drive compression assets on the DFW Midstream system, (iii) the sale of condensate volumes that we retain on the Grand River system and (iv) the sale of processed natural gas and natural gas liquids pursuant to our percent-of-proceeds and keep-whole contracts with certain of our customers on the Bison Midstream and Grand River Gathering systems. Our gas gathering agreements with our DFW Midstream customers permit us to retain a certain quantity of natural gas that we sell to offset the power costs we incur to operate our electric-drive compression assets. Our gas gathering agreements with our Grand River customers permit us to retain condensate volumes from the Grand River system gathering lines. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices on the Waha Hub Index. Because we also sell our retainage gas at prices that are based on the Waha Hub Index, we have effectively fixed the relationship between our compression electricity expense and natural gas sales. We do not enter into risk management contracts for speculative purposes.

Item 4. Controls and Procedures.

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

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

Table of Contents

PART II

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

The Risk Factors contained in the 2013 Annual Report are incorporated herein by reference and updated to include the additional risks discussed below.

The Red Rock Drop Down may not be beneficial to us.

As a result of the Red Rock Drop Down, we are subject to additional risks, in particular the risk that we fail to realized the expected profitability, growth or accretion from the transaction. The Red Rock Drop Down involves additional potential risks, including:


•	environmental or regulatory compliance matters or liabilities;


•	title issues or liabilities or accidents;


•	construction cost overruns and delays resulting from numerous factors, many of which may be out of our control;


•	the temporary diversion of management’s attention from our existing business;


•	an increase in our interest expense and financial leverage resulting from any additional debt incurred to finance the Red Rock Drop Down, which may offset the expected accretion from such acquisition;


•	the incurrence of significant charges, such as asset devaluation or restructuring charges; and


•	the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate.

If these risks or other unanticipated liabilities were to materialize, the desired benefits of the Red Rock Drop Down may not be fully realized, and our future financial performance and results of operations could be negatively impacted.

Interruptions in operations at any of our facilities may adversely affect our operations and cash flows available for distribution to our unitholders.

Our operations depend upon the infrastructure that we have developed, including the recently completed Debeque Natural Gas Processing Plant owned by Grand River Gathering (the "Debeque Plant"). Any significant interruption at the Debeque Plant or our other midstream facilities, or in our ability to gather or process natural gas or NGLs, would adversely affect our operations and cash flows available for distribution to our unitholders.

Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as:


•	unscheduled turnarounds or catastrophic events at our physical plants or pipeline facilities;


•	restrictions imposed by governmental authorities or court proceedings;


•	labor difficulties that result in a work stoppage or slowdown;


•	a disruption in the supply of natural gas to the Debeque Plant or our other midstream facilities;


•	disruption in our supply of resources necessary to operate our facilities;


•	damage to our facilities resulting from gas or NGLs that do not comply with applicable specifications; and


•	inadequate transportation or market access to support production volumes, including lack of availability of pipeline capacity.

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))
3.3		Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
3.4		Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
10.1		Purchase and Sale Agreement among Summit Midstream Partners Holdings, LLC, Red Rock Gathering Company, LLC and Summit Midstream Partners, LP dated as of March 8, 2014 (Incorporated herein by reference to Exhibit 10.1 to SMLP's Current Report on Form 8-K dated March 8, 2014 (Commission File No. 001-35666))
10.2		Summit Midstream Partners, LP 2012 Long-Term Incentive Plan Phantom Unit Agreement (Incorporated herein by reference to Exhibit 10.1 to SMLP's Current Report on Form 8-K dated March 11, 2014 (Commission File No. 001-35666))
31.1		Rule 13a-14(a)/15d-14(a) Certification, executed by Steven J. Newby, President, Chief Executive Officer and Director
31.2		Rule 13a-14(a)/15d-14(a) Certification, executed by Matthew S. Harrison, Senior Vice President and Chief Financial Officer
32.1		Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Steven J. Newby, President, Chief Executive Officer and Director, and Matthew S. Harrison, Senior Vice President and Chief Financial Officer
101.INS	**	XBRL Instance Document (1)
101.SCH	**	XBRL Taxonomy Extension Schema
101.CAL	**	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	**	XBRL Taxonomy Extension Definition Linkbase
101.LAB	**	XBRL Taxonomy Extension Label Linkbase
101.PRE	**	XBRL Taxonomy Extension Presentation Linkbase

** Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections. The financial information contained in the XBRL(eXtensible Business Reporting Language)-related documents is unaudited and unreviewed.

(1) Includes the following materials contained in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, formatted in XBRL: (i) Unaudited Condensed Consolidated Balance Sheets, (ii) Unaudited Condensed Consolidated Statements of Operations, (iii) Unaudited Condensed Consolidated Statements of Partners' Capital, (iv) Unaudited Condensed Consolidated Statements of Cash Flows, and (v) Notes to Unaudited Condensed Consolidated Financial Statements.

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)

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

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