SEC Filing | Summit Midstream Corporation

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8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 OR 15(d)

of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): September 11, 2015

Summit Midstream Partners, LP

(Exact name of registrant as specified in its charter)



Delaware	001-35666	45-5200503
(State or other jurisdiction	(Commission	(IRS Employer
of incorporation)	File Number)	Identification No.)

1790 Hughes Landing Blvd

Suite 500

The Woodlands, TX 77380

(Address of principal executive offices) (Zip Code)

Registrants’ telephone number, including area code: (832) 413-4770

Not applicable.

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01. Other Events.

Summit Midstream Partners, LP ("SMLP" or the “Partnership”) is filing this Current Report on Form 8-K to update certain items in the Partnership's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015 (the "First Quarter 2015 Form 10-Q"). On May 18, 2015, SMLP acquired all of the membership interests of Polar Midstream, LLC ("Polar Midstream") and Epping Transmission Company, LLC (collectively with Polar Midstream, "Polar and Divide") from Summit Midstream Partners Holdings, LLC ("SMP Holdings"), a wholly owned direct subsidiary of Summit Midstream Partners, LLC ("Summit Investments"), and thereby acquired certain crude oil and produced water gathering systems and under-development transmission pipelines located in the Williston Basin in North Dakota (the "Polar and Divide Drop Down"). Summit Investments, as the ultimate owner of SMLP's general partner, controls SMLP and has the right to appoint the entire board of directors of its general partner. As such, the Polar and Divide Drop Down was deemed a transaction among entities under common control and a change in reporting entity. Transfers of net assets or exchanges of membership interests between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior periods are retrospectively adjusted to furnish comparative information similar to a pooling of interests. As a result, the following items of the First Quarter 2015 Form 10-Q are being retrospectively adjusted to reflect the Polar and Divide Drop Down and the Partnership's 100% interest in the financial results of Polar and Divide for all periods during which common control existed:

•Part I, Item 1. Financial Statements and


•	Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

These items replace the same items filed in the Partnership’s First Quarter 2015 Form 10-Q as filed with the Securities and Exchange Commission (the "SEC") on May 6, 2015.

The information in this Current Report on Form 8-K should be read in conjunction with the other information included (but not replaced as described above) in the First Quarter 2015 Form 10-Q. More current information is contained in the Partnership's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2015 and the Partnership's other filings with the SEC.

Forward-Looking Statements. The following forward-looking statements replace the same items included on pages ii and iii of the Partnership’s First Quarter 2015 Form 10-Q as filed with the SEC on May 6, 2015.

Investors are cautioned that certain statements contained in this report 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 in the section entitled "Risk Factors" in this report.

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:


•	fluctuations in natural gas, natural gas liquids ("NGLs") and crude oil prices;


•	the extent and success of drilling efforts, as well as the extent and quality of natural gas and crude oil 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 hydrocarbon 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 acquire any assets owned by Summit Investments, which is subject to a number of factors, including Summit Investments deciding, in its sole discretion, to offer us the right to acquire such assets, the ability to reach agreement on acceptable terms, the approval of the conflicts committee of our general partner's board of directors (if appropriate), prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets, and our ability to obtain financing on acceptable terms from the credit and/or capital markets or other sources;


•	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;


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


•	operational risks and hazards inherent in the gathering, treating and/or processing of natural gas, crude oil and produced water;


•	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;


•	changes in general economic conditions; 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.

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 report 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.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits.



Exhibit Number		Description
99.1		Updated First Quarter 2015 Form 10-Q - Part I, Item 1. Financial Statements.
99.2		Updated First Quarter 2015 Form 10-Q - Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
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 for the quarter ended March 31, 2015, 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.

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 hereunto duly authorized.



	Summit Midstream Partners, LP
	(Registrant)

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

Date: September 11, 2015	/s/ Matthew S. Harrison
	Matthew S. Harrison, Executive Vice President and Chief Financial Officer

EXHIBIT INDEX



Exhibit Number		Description
99.1		Updated First Quarter 2015 Form 10-Q - Part I, Item 1. Financial Statements.
99.2		Updated First Quarter 2015 Form 10-Q - Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
101.INS		XBRL Instance Document
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

10-Q

EXHIBIT 99.1

Item 1. Financial Statements.

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS



	March 31,		December 31,
	2015		2014
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	13,154	$	26,504
Accounts receivable	48,950		89,201
Other current assets	2,510		3,517
Total current assets	64,614		119,222
Property, plant and equipment, net	1,426,143		1,414,350
Intangible assets, net	468,737		477,734
Goodwill	265,062		265,062
Other noncurrent assets	16,619		17,353
Total assets	$	2,241,175	$	2,293,721

Liabilities and Partners' Capital
Current liabilities:
Trade accounts payable	$	25,017	$	24,855
Due to affiliate	826		2,711
Deferred revenue	2,377		2,377
Ad valorem taxes payable	4,039		9,118
Accrued interest	7,733		18,858
Other current liabilities	8,818		13,550
Total current liabilities	48,810		71,469
Long-term debt	796,000		808,000
Unfavorable gas gathering contract, net	5,402		5,577
Deferred revenue	58,985		55,239
Other noncurrent liabilities	1,535		1,715
Total liabilities	910,732		942,000
Commitments and contingencies

Common limited partner capital (34,495 units issued and outstanding at March 31, 2015 and 34,427 units issued and outstanding at December 31, 2014)	630,241		649,060
Subordinated limited partner capital (24,410 units issued and outstanding at March 31, 2015 and December 31, 2014)	279,524		293,153
General partner interests (1,201 units issued and outstanding at March 31, 2015 and December 31, 2014)	24,100		24,676
Summit Investments' equity in contributed subsidiaries	396,578		384,832
Total partners' capital	1,330,443		1,351,721
Total liabilities and partners' capital	$	2,241,175	$	2,293,721

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

EX 99.1-1

EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS



	Three months ended March 31,
	2015			2014
	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	60,767		$	49,903
Natural gas, NGLs and condensate sales	12,613			26,304
Other revenues	3,781			3,174
Total revenues	77,161			79,381
Costs and expenses:
Cost of natural gas and NGLs	5,384			14,353
Operation and maintenance	21,057			21,832
General and administrative	9,658			9,053
Transaction costs	—			537
Depreciation and amortization	23,755			20,379
Total costs and expenses	59,854			66,154
Other income	1			1
Interest expense	(12,118		)	(7,144		)
Income before income taxes	5,190			6,084
Income tax expense	(177		)	(159		)
Net income	$	5,013		$	5,925
Less: net income attributable to Summit Investments	3,346			2,380
Net income attributable to SMLP	1,667			3,545
Less: net income attributable to general partner, including IDRs	1,568			431
Net income attributable to limited partners	$	99		$	3,114

Earnings per limited partner unit:
Common unit – basic	$	0.00		$	0.08
Common unit – diluted	$	0.00		$	0.08
Subordinated unit – basic and diluted	$	0.00		$	0.02

Weighted-average limited partner units outstanding:
Common units – basic	34,439			29,912
Common units – diluted	34,585			30,068
Subordinated units – basic and diluted	24,410			24,410

Cash distributions declared and paid per common unit	$	0.560		$	0.480

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

EX 99.1-2

EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL



	Partners' capital									Summit Investments' equity in contributed subsidiaries
	Limited partners						General partner
	Common			Subordinated			General partner						Total
	(In thousands)
Partners' capital, January 1, 2014	$	566,532		$	379,287		$	23,324		$	523,944		$	1,493,087
Net income	1,741			1,373			431			2,380			5,925
Distributions to unitholders	(13,958		)	(11,717		)	(691		)	—			(26,366		)
Unit-based compensation	1,063			—			—			—			1,063
Tax withholdings on vested SMLP 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 contributed subsidiaries	—			—			—			14,278			14,278
Expenses paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			5,863			5,863
Capitalized interest allocated from Summit Investments to contributed subsidiaries	—			—			—			272			272
Class B membership interest unit-based compensation	—			—			—			85			85
Partners' capital, March 31, 2014	$	716,589		$	343,252		$	26,035		$	305,005		$	1,390,881

Partners' capital, January 1, 2015	$	649,060		$	293,153		$	24,676		$	384,832		$	1,351,721
Net income	58			41			1,568			3,346			5,013
Distributions to unitholders	(19,279		)	(13,670		)	(2,144		)	—			(35,093		)
Unit-based compensation	1,312			—			—			—			1,312
Tax withholdings on vested SMLP LTIP awards	(910		)	—			—			—			(910		)
Cash advance from Summit Investments to contributed subsidiaries, net	—			—			—			5,899			5,899
Expenses paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			2,112			2,112
Capitalized interest allocated from Summit Investments to contributed subsidiaries	—			—			—			304			304
Class B membership interest unit-based compensation	—			—			—			85			85
Partners' capital, March 31, 2015	$	630,241		$	279,524		$	24,100		$	396,578		$	1,330,443

EX 99.1-3

EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Three months ended March 31,
	2015			2014
	(In thousands)
Cash flows from operating activities:
Net income	$	5,013		$	5,925
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	24,006			20,605
Amortization of deferred loan costs	791			604
Unit-based compensation	1,397			1,148
Changes in operating assets and liabilities:
Accounts receivable	40,251			21,600
Trade accounts payable	(1,322		)	6,661
Due to affiliate	1,056			390
Change in deferred revenue	3,746			3,727
Ad valorem taxes payable	(5,078		)	(4,199		)
Accrued interest	(11,125		)	(6,404		)
Other, net	(3,949		)	(1,814		)
Net cash provided by operating activities	54,786			48,243
Cash flows from investing activities:
Capital expenditures	(25,188		)	(53,580		)
Acquisition of gathering system from affiliate	(2,941		)	(305,000		)
Net cash used in investing activities	(28,129		)	(358,580		)

EX 99.1-4

EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)



	Three months ended March 31,
	2015			2014
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(35,093		)	(26,366		)
Borrowings under revolving credit facility	14,000			125,000
Repayments under revolving credit facility	(26,000		)	(20,000		)
Deferred loan costs	(15		)	(65		)
Tax withholdings on vested SMLP LTIP awards	(910		)	(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	5,899			14,278
Expenses paid by Summit Investments on behalf of contributed subsidiaries	2,112			5,863
Net cash (used in) provided by financing activities	(40,007		)	300,384
Net change in cash and cash equivalents	(13,350		)	(9,953		)
Cash and cash equivalents, beginning of period	26,504			20,357
Cash and cash equivalents, end of period	$	13,154		$	10,404

Supplemental cash flow disclosures:
Cash interest paid	$	22,812		$	14,308
Less: capitalized interest	645			1,630
Interest paid (net of capitalized interest)	$	22,167		$	12,678

Noncash investing and financing activities:
Capital expenditures in trade accounts payable (period-end accruals)	$	19,562		$	16,983
Capitalized interest allocated to Polar and Divide projects from Summit Investments	304			272
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.

EX 99.1-5

EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION

Organization. Summit Midstream Partners, LP ("SMLP" or the "Partnership"), a Delaware limited partnership, 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.

SMLP and its subsidiaries are 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 us and has the right to appoint the entire board of directors of our general partner, including our independent directors. Our operations are conducted through, and our operating assets are owned by, various wholly-owned operating subsidiaries. Neither SMLP nor its subsidiaries have any employees. All of the personnel that conduct our business are employed by the general partner and its subsidiaries, but these individuals are sometimes referred to as our employees.

As of March 31, 2015, Summit Midstream Partners Holdings, LLC ("SMP Holdings"), a wholly owned subsidiary of Summit Investments, held 5,293,571 SMLP common units, all of our subordinated units, all of our general partner units representing a 2% general partner interest in SMLP and all of our incentive distribution rights ("IDRs").

On May 18, 2015, the Partnership acquired certain crude oil and produced water gathering systems and under-development transmission pipelines held by Polar Midstream, LLC ("Polar Midstream") and Epping Transmission Company, LLC ("Epping") located in the Williston Basin (collectively the "Polar and Divide system") from SMP Holdings (the "Polar and Divide Drop Down"). Polar Midstream and Epping are Delaware limited liability companies formed in April 2014.

Polar Midstream's assets were carved out of Meadowlark Midstream Company, LLC ("Meadowlark Midstream"), a subsidiary of Summit Investments, immediately prior to the Polar and Divide Drop Down. Concurrent with the closing of the Polar and Divide Drop Down, Epping became a wholly owned subsidiary of Polar Midstream and SMLP contributed Polar Midstream (including Epping) to Bison Midstream, LLC ("Bison Midstream"). Because the Polar and Divide system was acquired from subsidiaries of Summit Investments, it was deemed a transaction among entities under common control. Common control began in (i) February 2013 for Polar Midstream and (ii) April 2014 for Epping.

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


•	Mountaineer Midstream gathering system ("Mountaineer Midstream"), a natural gas gathering system, operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia;


•	Bison Midstream, an associated natural gas gathering system, operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;


•	the Polar and Divide system ("Polar and Divide"), a crude oil and produced water gathering system and transmission pipelines (under development) located in the Williston Basin;


•	DFW Midstream Services LLC ("DFW Midstream"), a natural gas gathering system, operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and


•	Grand River Gathering, LLC ("Grand River Gathering"), a natural gas gathering and processing system, operating in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah.

Our operating subsidiaries, which are wholly owned by our wholly owned subsidiary, Summit Midstream Holdings, LLC ("Summit Holdings"), are: DFW Midstream (which includes Mountaineer Midstream); Bison Midstream (and its wholly owned subsidiaries Polar Midstream and Epping); and Grand River Gathering (and its wholly owned subsidiary Red Rock Gathering Company, LLC ("Red Rock Gathering")). All of our operating subsidiaries are focused on the development, construction and operation of natural gas gathering and processing systems and crude oil and produced water gathering systems.

EX 99.1-6

EXHIBIT 99.1

Presentation and 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 (the "FASB"). The unaudited condensed consolidated financial statements include the assets, liabilities, and results of operations of SMLP and its subsidiaries. All intercompany transactions among the consolidated entities have been eliminated in consolidation.

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 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. We believe that the disclosures made are adequate to make the information not misleading. In the opinion of management, the unaudited condensed consolidated financial statements contain all adjustments, including normal recurring accruals, which are necessary to fairly present the unaudited condensed consolidated balance sheet as of March 31, 2015, the unaudited condensed consolidated statements of operations, partners' capital and cash flows for the three-month periods ended March 31, 2015 and 2014. 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, 2014 as filed with the SEC on March 2, 2015, and as updated and superseded by our current report on Form 8-K dated September 11, 2015 (the "2014 Annual Report"). The results of operations for an interim period are not necessarily indicative of results expected for a full year.

SMLP recognized its acquisitions of (i) Polar Midstream and Epping and (ii) Red Rock Gathering (the "Red Rock Drop Down") at Summit Investments' historical cost of construction or fair value of assets and liabilities at acquisition because the acquisitions were executed by entities under common control. The excess of Summit Investments' net investment in Polar Midstream and Epping was recognized as an addition to partners' capital. The excess of the purchase price paid by SMLP over Summit Investments' net investment in Red Rock Gathering was recognized as a reduction to partners' capital. Due to the common control aspect, the Polar and Divide Drop Down and the Red Rock Drop Down were accounted for by the Partnership on an “as-if pooled” basis for the periods during which common control existed. For the purposes of these unaudited condensed consolidated financial statements, SMLP's results of operations reflect the results of operations of Polar Midstream, Epping and Red Rock Gathering for all periods presented.

The financial position, results of operations and cash flows of Polar Midstream included herein have been derived from the accounting records of Meadowlark Midstream on a carve-out basis. The majority of the assets and liabilities allocated to Polar Midstream have been specifically identified based on Meadowlark Midstream’s existing divisional organization. Goodwill was allocated to Polar Midstream based on initial purchase accounting estimates. Revenues and depreciation and amortization have been specifically identified based on Polar Midstream's relationship to Meadowlark Midstream’s existing divisional structure. Operation and maintenance and general and administrative expenses have been allocated to Polar Midstream based on volume throughput. These allocations and estimates were based on methodologies that management believes are reasonable. The results reflected herein, however, may not reflect what Polar Midstream’s financial position, results of operations or cash flows would have been if Polar Midstream been a stand-alone company.

Reclassifications. Certain reclassifications have been made to prior-year amounts to conform to the current-year presentation. We evaluated our classification of revenues and concluded that creating an “other revenues” category would provide reporting that was more reflective of our results of operations and how we manage our business. As such, certain revenue transactions that represented the “and other” portions of (i) gathering services and (ii) natural gas, NGLs and condensate sales have been reclassified to other revenues. Other revenues also includes the amortization expense associated with our favorable and unfavorable gas gathering contracts. The amounts reclassified to other revenues for each period presented can be determined based on the total of the other revenues line item and the amount of amortization of favorable and unfavorable gas gathering contracts disclosed in Note 5. We also evaluated our historical classification of electricity expense for Bison Midstream. In connection with the reclassification of certain revenues noted above and to be consistent with the classification of pass-through electricity expense for our other operating segments, we reclassified pass-through electricity expenses for Bison Midstream ($1.3 million and $0.9 million for the three months ended March 31, 2015 and 2014, respectively) from costs of natural gas and NGLs to operation and maintenance. These reclassifications had no impact on total revenues, total costs and expenses, net income, total partners' capital or segment adjusted EBITDA.

EX 99.1-7

EXHIBIT 99.1

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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. 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. We accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Such accruals are adjusted as further information develops or circumstances change. Recoveries of environmental remediation costs from other parties or insurers are recorded as assets when their receipt is deemed probable.

Other Significant Accounting Policies. For information on our other significant accounting policies, see Note 2 of the consolidated financial statements included in the 2014 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 may materially affect our financial statements, except as noted below.

In May 2014, the FASB released a joint revenue recognition standard, Accounting Standards Update ("ASU") No. 2014-09 ("ASU 2014-09"). Under ASU 2014-09, revenue will be recognized under a five-step model: (i) identify the contract with the customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to performance obligations; and (v) recognize revenue when (or as) we satisfy a performance obligation. In its original form, ASU 2014-09 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016; early adoption was not permitted. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of Effective Date ("ASU 2015-14"). ASU 2015-14 defers for one year the effective date of the ASU 2014-09 for both public and nonpublic entities reporting under U.S. GAAP and allows early adoption as of the original effective date. We are currently in the process of evaluating the impact of this update.

In February 2015, the FASB issued ASU No. 2015-02—Consolidation (Topic 810): Amendments to the Consolidation Analysis ("ASU 2015-02"). The standard changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, and interim and annual periods thereafter. Early adoption is permitted. We are currently in the process of evaluating the impact of this update.

In April 2015, the FASB issued ASU No. 2015-03 ("ASU 2015-30") Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. Under ASU 2015-03, entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. This presentation will result in debt issuance cost being presented the same way debt discounts have historically been handled. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, and interim and annual periods thereafter. Early adoption is permitted. We are currently in the process of evaluating the impact of this update.

3. SEGMENT INFORMATION

As of March 31, 2015, our reportable segments are:


•	the Marcellus Shale, which is served by Mountaineer Midstream;


•	the Williston Basin – Gas, which is served by Bison Midstream;


•	the Williston Basin – Liquids, which is served by Polar and Divide;


•	the Barnett Shale, which is served by DFW Midstream; and


•	the Piceance Basin, which is served by Grand River Gathering.

Each of our reportable segments provides midstream services in a specific geographic area. Within specific geographic areas, we may further differentiate reportable segments by type of gathering service provided. Our

EX 99.1-8

EXHIBIT 99.1

reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations.

In the first quarter of 2015, we combined our Red Rock Gathering operating segment with the Grand River Gathering operating segment to become one operating segment serving the Piceance Basin. Prior to 2015, we aggregated the Red Rock Gathering and Grand River Gathering operating segments into the Piceance Basin reportable segment.

In connection with the Polar and Divide Drop Down, we identified two reportable segments in the Williston Basin. We had previously only provided natural gas gathering services in the Williston Basin. With the acquisition of Polar Midstream and Epping in May 2015, we now also provide crude oil and produced water gathering services in the Williston Basin. As such, we evaluated the quantitative and qualitative factors for operating segment aggregation in the Williston Basin and concluded that the characteristics for crude oil and produced water gathering services were not sufficiently similar to those of our natural gas gathering services. As a result, we now report the results of Bison Midstream in the Williston Basin – Gas reportable segment and those of Polar Midstream and Epping in the Williston Basin – Liquids reportable segment.

Corporate represents those revenues and expenses that are not specifically attributable to a reportable segment, not individually reportable, or that have not been allocated to our reportable segments. Beginning in the first quarter of 2015, we discontinued allocating certain general and administrative expenses, primarily salaries, benefits, incentive compensation and rent expense, to our operating segments.

Assets by reportable segment follow.



	March 31,		December 31,
	2015		2014
	(In thousands)
Assets:
Marcellus Shale	$	243,391	$	243,884
Williston Basin – Gas	296,870		311,041
Williston Basin – Liquids	412,187		398,847
Barnett Shale	425,142		428,935
Piceance Basin	843,054		872,437
Total reportable segment assets	2,220,644		2,255,144
Corporate	20,531		38,577
Total assets	$	2,241,175	$	2,293,721

Revenues by reportable segment follow.



	Three months ended March 31,
	2015		2014
	(In thousands)
Revenues:
Marcellus Shale	$	7,840	$	5,356
Williston Basin – Gas	8,908		16,763
Williston Basin – Liquids	8,582		3,179
Barnett Shale	23,897		23,037
Piceance Basin	27,934		31,046
Total reportable segment revenues and total revenues	$	77,161	$	79,381

EX 99.1-9

EXHIBIT 99.1

Depreciation and amortization by reportable segment follow.



	Three months ended March 31,
	2015		2014
	(In thousands)
Depreciation and amortization:
Marcellus Shale	$	2,168	$	1,801
Williston Basin – Gas	4,698		4,250
Williston Basin – Liquids	1,612		737
Barnett Shale	3,906		3,638
Piceance Basin	11,205		9,811
Total reportable segments	23,589		20,237
Corporate	166		142
Total depreciation and amortization	$	23,755	$	20,379

Capital expenditures by reportable segment follow.



	Three months ended March 31,
	2015		2014
	(In thousands)
Capital expenditures:
Marcellus Shale	$	496	$	4,431
Williston Basin – Gas	4,934		10,941
Williston Basin – Liquids	13,274		13,480
Barnett Shale	893		7,721
Piceance Basin	5,193		16,970
Total reportable segments	24,790		53,543
Corporate	398		37
Total capital expenditures	$	25,188	$	53,580

We assess the performance of our reportable segments based on segment adjusted EBITDA. We define segment adjusted EBITDA as total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) depreciation and amortization, (iii) adjustments related to minimum volume commitment ("MVC") shortfall payments, (iv) impairments and (v) other noncash expenses or losses, less other noncash income or gains. Segment adjusted EBITDA excludes the effect of allocated corporate expenses, such as certain general and administrative expenses (including compensation-related expenses and professional services fees) interest expense and income tax expense.

Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. We include a proportional amount of these historical or expected minimum volume commitment shortfall payments in each quarter prior to the quarter in which we actually recognize the shortfall payment. These adjustments have not been billed to our customers and are not recognized in our consolidated financial statements.

EX 99.1-10

EXHIBIT 99.1

A reconciliation of income before income taxes to total reportable segment adjusted EBITDA follows.



	Three months ended March 31,
	2015		2014
	(In thousands)
Reconciliation of Income Before Income Taxes to Segment Adjusted EBITDA:
Income before income taxes	$	5,190	$	6,084
Add:
Interest expense	12,118		7,144
Depreciation and amortization	24,006		20,605
Allocated corporate expenses	5,857		2,555
Adjustments related to MVC shortfall payments	12,340		12,013
Unit-based compensation	1,397		1,148
Less:
Interest income	1		1
Total reportable segment adjusted EBITDA	$	60,907	$	49,548

Segment adjusted EBITDA by reportable segment follows.



	Three months ended March 31,
	2015		2014
	(In thousands)
Reportable segment adjusted EBITDA:
Marcellus Shale	$	6,535	$	3,883
Williston Basin – Gas	5,333		4,676
Williston Basin – Liquids	5,043		374
Barnett Shale	16,760		15,034
Piceance Basin	27,236		25,581
Total reportable segment adjusted EBITDA	$	60,907	$	49,548

4. PROPERTY, PLANT, AND EQUIPMENT, NET

Details on property, plant, and equipment, net follow.



	Useful lives (In years)	March 31,		December 31,
	Useful lives (In years)	2015		2014
		(Dollars in thousands)
Gathering and processing systems and related equipment	30	$	1,479,712	$	1,462,706
Construction in progress	n/a	52,144		44,447
Other	4-15	29,599		28,871
Total		1,561,455		1,536,024
Less accumulated depreciation		135,312		121,674
Property, plant, and equipment, net		$	1,426,143	$	1,414,350

EX 99.1-11

EXHIBIT 99.1

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,
	2015		2014
	(In thousands)
Depreciation expense	$	13,638	$	11,199
Capitalized interest	645		1,630

5. AMORTIZING INTANGIBLE ASSETS AND UNFAVORABLE GAS GATHERING CONTRACT

Details regarding our intangible assets and the unfavorable gas gathering contract, all of which are subject to amortization, follow.



	March 31, 2015
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
	(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(8,482	)	$	15,713
Contract intangibles	12.5	426,464		(84,548		)	341,916
Rights-of-way	24.7	125,127		(14,019		)	111,108
Total intangible assets		$	575,786	$	(107,049	)	$	468,737

Unfavorable gas gathering contract	10.0	$	10,962	$	(5,560	)	$	5,402



	December 31, 2014
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
	(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(8,056	)	$	16,139
Contract intangibles	12.5	426,464		(75,713		)	350,751
Rights-of-way	24.7	123,581		(12,737		)	110,844
Total intangible assets		$	574,240	$	(96,506	)	$	477,734

Unfavorable gas gathering contract	10.0	$	10,962	$	(5,385	)	$	5,577

We recognized amortization expense in other revenues as follows:



	Three months ended March 31,
	2015			2014
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	(426	)	$	(434	)
Amortization expense – unfavorable gas gathering contract	175			208

We recognized amortization expense in costs and expenses as follows:



	Three months ended March 31,
	2015		2014
	(In thousands)
Amortization expense – contract intangibles	$	8,835	$	7,962
Amortization expense – rights-of-way	1,282		1,218

EX 99.1-12

EXHIBIT 99.1

The estimated aggregate annual amortization expected to be recognized for the remainder of 2015 and each of the four succeeding fiscal years follows.



	Intangible assets		Unfavorable gas gathering contract
	(In thousands)
2015	$	31,707	$	530
2016	42,275		924
2017	41,126		1,047
2018	40,580		1,035
2019	40,825		1,045

6. GOODWILL

We evaluate goodwill for impairment annually on September 30 and 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 during the three months ended March 31, 2015.

Annual Impairment Evaluation. We performed our annual goodwill impairment testing as of September 30, 2014 using a combination of the income and market approaches. Details on the results of the annual goodwill impairment testing for all reporting units except those acquired in the Polar and Divide Drop Down are included in our 2014 Annual Report. The assets acquired in the Polar and Divide Drop Down were carved out of Meadowlark Midstream. As such, we elected to apply the historical cost approach to determine the amount of goodwill to assign to Polar Midstream. Our procedures indicated that the remaining goodwill balance at Meadowlark Midstream was entirely attributable to Polar Midstream. We then performed the quantitative analysis for the Polar Midstream reporting unit and determined that the fair value of the Polar Midstream reporting unit substantially exceeded its carrying value, including goodwill as of September 30, 2014. Because the fair value of the Polar Midstream reporting unit exceeded its carrying value, including goodwill, there was no associated impairment of goodwill in connection with our 2014 annual goodwill impairment test and therefore no impairment of the $203.4 million of goodwill that was allocated to the Polar Midstream reporting unit. Because Epping was an organic growth project, it has no goodwill.

Bison Midstream Fourth Quarter 2014 Goodwill Impairment. In the first quarter of 2015, we finalized our calculations of the fair values of the identified assets and liabilities in step two of the December 31, 2014 goodwill impairment testing for the Bison Midstream reporting unit. This process confirmed the preliminary goodwill impairment of $54.2 million that was recognized as of December 31, 2014.

Polar Midstream Fourth Quarter 2014 Goodwill Impairment Evaluation. During the latter part of the fourth quarter of 2014, the declines in prices for natural gas, NGLs and crude oil accelerated, negatively impacting producers in each of our areas of operation. As a result, we considered whether the goodwill associated with our Polar Midstream reporting unit could have been impaired. Our assessment related to the Polar Midstream reporting unit did result in an indication that the associated goodwill could have been impaired.

We noted that the reporting unit had been impacted by the recent price declines, thereby increasing the likelihood that the associated goodwill could have been impaired. As such, we concluded that a triggering event occurred during the fourth quarter of 2014 requiring that we test Polar Midstream's goodwill.

In connection therewith, we reperformed our step one analysis as of December 31, 2014. To estimate the fair value of the reporting unit, we utilized two valuation methodologies: the market approach and the income approach. Both of these approaches incorporate significant estimates and assumptions to calculate enterprise fair value for a reporting unit. The most significant estimates and assumptions inherent within these two valuation methodologies are:


•	determination of the weighted-average cost of capital;


•	the selection of guideline public companies;


•	market multiples;


•	weighting of the income and market approaches;


•	growth rates;

EX 99.1-13

EXHIBIT 99.1


•	commodity prices; and


•	the expected levels of throughput volume gathered.

Changes in the above and other assumptions could materially affect the estimated amount of fair value for any of our reporting units.

The results of our step one goodwill impairment testing indicated that the fair value of the Polar Midstream reporting unit substantially exceeded its carrying value, including goodwill as of December 31, 2014. As a result, there was no associated impairment of goodwill in connection with the fourth quarter 2014 triggering event and no impairment of goodwill acquired in connection with the Polar and Divide Drop Down.

Our impairment determinations, in the context of (i) our annual impairment evaluation and (ii) our fourth quarter 2014 evaluations, involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.

7. DEFERRED REVENUE

A rollforward of current deferred revenue follows.



	Williston Basin - Gas		Barnett Shale		Piceance Basin		Total current
	(In thousands)
Current deferred revenue, January 1, 2015	$	—	$	2,377	$	—	$	2,377
Additions	—		322		—		322
Less revenue recognized	—		322		—		322
Current deferred revenue, March 31, 2015	$	—	$	2,377	$	—	$	2,377

A rollforward of noncurrent deferred revenue follows.



	Williston Basin - Gas		Barnett Shale		Piceance Basin		Total noncurrent
	(In thousands)
Noncurrent deferred revenue, January 1, 2015	$	17,132	$	—	$	38,107	$	55,239
Additions	—		—		3,773		3,773
Less revenue recognized	27		—		—		27
Noncurrent deferred revenue, March 31, 2015	$	17,105	$	—	$	41,880	$	58,985

As of March 31, 2015, accounts receivable included $2.5 million of shortfall billings related to MVC arrangements that can be utilized to offset gathering fees in subsequent periods. Noncurrent deferred revenue at March 31, 2015 represents amounts that provide certain customers the ability to offset their gathering fees over a period up to seven years to the extent that the customer's throughput volumes exceeds its MVC.

EX 99.1-14

EXHIBIT 99.1

8. LONG-TERM DEBT

Long-term debt consisted of the following:



	March 31,		December 31,
	2015		2014
	(In thousands)
Variable rate senior secured revolving credit facility (2.43% at March 31, 2015 and 2.67% at December 31, 2014) due November 2018	$	196,000	$	208,000
5.50% Senior unsecured notes due August 2022	300,000		300,000
7.50% Senior unsecured notes due July 2021	300,000		300,000
Total long-term debt	$	796,000	$	808,000

Revolving Credit Facility. We have a senior secured revolving credit facility which allows for revolving loans, letters of credit and swingline loans (the "revolving credit facility"). The revolving credit facility has a $700.0 million borrowing capacity, matures in November 2018, and includes a $200.0 million accordion feature. It is secured by the membership interests of Summit Holdings and those of its subsidiaries. Substantially all of the assets of Summit Holdings and its subsidiaries 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.

As of March 31, 2015, we were in compliance with the revolving credit facility's covenants. There were no defaults or events of default during the three months ended March 31, 2015.

Senior Notes. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Summit Midstream Finance Corp. ("Finance Corp.," together with Summit Holdings, the "Co-Issuers"), co-issued $300.0 million of 5.50% senior unsecured notes maturing August 15, 2022 (the "5.5% senior notes"). In June 2013, the Co-Issuers co-issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021 (the "7.5% senior notes").

SMLP and all of its subsidiaries other than the Co-Issuers (the "Guarantors") have fully and unconditionally and jointly and severally guaranteed the 5.5% senior notes and the 7.5% senior notes. SMLP has no independent assets or operations. Summit Holdings has no assets or operations other than its ownership of its wholly owned subsidiaries and activities associated with its borrowings under the revolving credit facility, the 5.5% senior notes and the 7.5% senior notes. Finance Corp. has no independent assets or operations and was formed for the sole purpose of being a co-issuer of certain of Summit Holdings' indebtedness, including the 5.5% senior notes and the 7.5% senior notes. There are no significant restrictions on the ability of SMLP or Summit Holdings to obtain funds from their subsidiaries by dividend or loan.

As of March 31, 2015, we were in compliance with the covenants of the 5.5% senior notes and the 7.5% senior notes. There were no defaults or events of default during the three months ended March 31, 2015.

Fair Value of Debt Instruments. A summary of the estimated fair value of our debt financial instruments follows.



	March 31, 2015				December 31, 2014
	Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)
	(In thousands)
Revolving credit facility	$	196,000	$	196,000	$	208,000	$	208,000
5.5% Senior notes	300,000		283,250		300,000		281,750
7.5% Senior notes	300,000		310,625		300,000		306,750

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, 2015 and December 31, 2014. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the senior notes.

EX 99.1-15

EXHIBIT 99.1

9. PARTNERS' CAPITAL

Partners' Capital

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, 2015	34,426,513	24,409,850	1,200,651	60,037,014
Units issued under SMLP LTIP (1)	68,955	—	—	68,955
Units, March 31, 2015	34,495,468	24,409,850	1,200,651	60,105,969

__________

(1) Net of 19,175 units withheld to meet minimum statutory tax withholding requirements

On May 13, 2015, we completed an underwritten public offering of 6,500,000 common units at a price of $30.75 per unit pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC (the "May 2015 Equity Offering"). Concurrent therewith, our general partner made a capital contribution to us to maintain its 2% general partner interest.

Red Rock Drop Down. On March 18, 2014, SMLP acquired 100% of the membership interests in Red Rock Gathering from a subsidiary of Summit Investments. SMLP paid total cash consideration of $307.9 million (including working capital adjustments accrued in December 2014 and cash settled in February 2015) in exchange for Summit Investments' net investment in Red Rock Gathering. As a result of the excess of the purchase price over acquired carrying value of Red Rock Gathering, SMLP recognized a capital distribution to Summit Investments. The calculation of the capital distribution and its allocation to partners' capital follow (in thousands).



Summit Investments' net investment in Red Rock Gathering				$	241,817
Total cash consideration paid to a subsidiary of Summit Investments				307,941
Excess of purchase price over acquired carrying value of Red Rock Gathering				$	(66,124	)

Allocation of capital distribution:
General partner interest	$	(1,323	)
Common limited partner interest	(37,910		)
Subordinated limited partner interest	(26,891		)
Partners' capital allocation				$	(66,124	)

Details of cash distributions declared in 2015 follow.



Attributable to the quarter ended	Payment date	Per-unit distribution		Cash paid to common unitholders		Cash paid to subordinated unitholders		Cash paid to general partner		Cash paid for IDRs		Total distribution
		(In thousands, except per-unit amounts)
December 31, 2014	February 13, 2015	$	0.5600	$	19,279	$	13,670	$	702	$	1,442	$	35,093

On April 23, 2015, the board of directors of our general partner declared a distribution of $0.565 per unit attributable to the quarter ended March 31, 2015. The distribution will be paid in accordance with the third target distribution level on May 15, 2015 to unitholders of record at the close of business on May 8, 2015.

Summit Investments' Equity in Contributed Subsidiaries. Summit Investments' equity in contributed subsidiaries represents its position in the net assets of Polar and Divide and Red Rock Gathering that have been acquired by SMLP. The balance also reflects net income attributable to Summit Investments for Polar and Divide and Red Rock Gathering for the periods beginning on their respective acquisition dates by Summit Investments and ending on the dates they were acquired by the Partnership. Net income was attributed to Summit Investments for (i) Polar and Divide for the three months ended March 31, 2015 and 2014 and (ii) Red Rock Gathering for the period from January 1, 2014 to March 18, 2014. Although included in partners' capital, these net income amounts have been excluded from the calculation of earnings per unit ("EPU").

EX 99.1-16

EXHIBIT 99.1

10. EARNINGS PER UNIT

The following table details the components of earnings per limited partner unit.



	Three months ended March 31,
	2015		2014
	(In thousands, except per-unit amounts)
Net income attributable to limited partners	$	99	$	3,114

Numerator for basic and diluted EPU:
Allocation of net income among limited partner interests:
Net income attributable to common units	$	69	$	2,508
Net income attributable to subordinated units	30		606
Net income attributable to limited partners	$	99	$	3,114

Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic	34,439		29,912
Effect of nonvested phantom units	146		156
Weighted-average common units outstanding – diluted	34,585		30,068

Weighted-average subordinated units outstanding – basic and diluted	24,410		24,410

Earnings per limited partner unit:
Common unit – basic	$	0.00	$	0.08
Common unit – diluted	$	0.00	$	0.08
Subordinated unit – basic and diluted	$	0.00	$	0.02

We excluded 8,524 units in our calculation of the effect of nonvested phantom units for the three months ended March 31, 2015 because they were anti-dilutive. There were no anti-dilutive units during the three months ended March 31, 2014.

11. UNIT-BASED COMPENSATION

SMLP Long-Term Incentive Plan. The SMLP Long-Term Incentive Plan (the "SMLP LTIP") provides for equity awards to eligible officers, employees, consultants and directors of our general partner and its affiliates. As of March 31, 2015, approximately 4.4 million common units remained available for future issuance.

The following table presents activity under the SMLP LTIP.



	Three months ended March 31, 2015
	Units		Weighted-average grant date fair value
Nonvested phantom units, beginning of period	336,202		$	30.61
Phantom units granted (1)	200,283		33.94
Phantom units vested	(89,107	)	34.07
Phantom units forfeited	(2,106	)	36.36
Nonvested phantom units, end of period	445,272		$	31.39

__________

(1) Grants vest ratably over a three-year period.

EX 99.1-17

EXHIBIT 99.1

As of March 31, 2015, the unrecognized unit-based compensation related to the SMLP LTIP was $9.5 million. Incremental unit-based compensation will be recorded in general and administrative expense over the remaining vesting period of approximately 3.0 years. Due to the limited and immaterial forfeiture history associated with the grants under the SMLP LTIP, no forfeitures were assumed in the determination of estimated compensation expense.

12. CONCENTRATIONS OF RISK

Financial instruments that potentially subject us to concentrations of credit risk consist of cash and accounts receivable. We maintain our cash in bank deposit accounts that frequently exceed federally insured limits. We have not experienced any losses in such accounts and do not believe we are exposed to any significant risk.

Accounts receivable primarily comprise amounts due for the gathering, treating and processing services we provide to our customers and also the sale of natural gas liquids resulting from our processing services. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of our counterparties and can require letters of credit for receivables from counterparties that are judged to have substandard credit, unless the credit risk can otherwise be mitigated.

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



	Three months ended March 31,
	2015		2014
Revenue:
Counterparty A - Piceance Basin	14	%	17	%
Counterparty B - Barnett Shale	*		10	%
Counterparty C - Marcellus Shale	10	%	*
Counterparty D - Piceance Basin	*		*
Counterparty E - Williston Basin – Gas	*		*

__________

* Less than 10%

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



	March 31,		December 31,
	2015		2014
Accounts receivable:
Counterparty A - Piceance Basin	14	%	27	%
Counterparty B - Barnett Shale	10	%	*
Counterparty C - Marcellus Shale	12	%	*
Counterparty D - Piceance Basin	11	%	*
Counterparty E - Williston Basin – Gas	*		13	%

__________

* Less than 10%

13. RELATED-PARTY TRANSACTIONS

Reimbursement of Expenses from General Partner. Our general partner and its affiliates do not receive a management fee or other compensation in connection with the management of our business, but will be reimbursed for expenses incurred on our behalf. Under our partnership agreement, we reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our general partner's employees and executive officers who perform services necessary to run our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Due to affiliate on the consolidated balance sheet represents the payables to our general partner for expenses incurred by it and paid on our behalf.

EX 99.1-18

EXHIBIT 99.1

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



	Three months ended March 31,
	2015		2014
	(In thousands)
Operation and maintenance expense	$	5,782	$	4,376
General and administrative expense	5,778		5,872

Expenses Incurred by Summit Investments. Prior to the Polar and Divide Drop Down and the Red Rock Drop Down, Summit Investments incurred:


•	certain support expenses and capital expenditures on behalf of the contributed subsidiaries. These transactions were settled periodically through membership interests prior to the respective drop down and


•	interest expense that was related to capital projects for the contributed subsidiaries. As such, the associated interest expense was allocated to the respective contributed subsidiary's capital projects as a noncash contribution and capitalized into the basis of the asset.

14. COMMITMENTS AND CONTINGENCIES

Operating Leases. Rent expense related to operating leases, including rent expense incurred on our behalf and allocated to us by Summit Investments, was as follows:



	Three months ended March 31,
	2015		2014
	(In thousands)
Rent expense	$	427	$	382

Environmental Matters. There are no material liabilities related to environmental remediation costs, arising from claims, assessments, litigation, fines, or penalties and other sources in the accompanying financial statements at March 31, 2015 or December 31, 2014. However, we can provide no assurance that significant costs and liabilities will not be incurred in the future. We are currently not aware of any material contingent liabilities that exist with respect to environmental matters.

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

15. ACQUISITIONS

Red Rock Gathering System. On March 18, 2014, the Partnership acquired Red Rock Gathering from a subsidiary of Summit Investments, subject to customary working capital adjustments. The Partnership paid total cash consideration of $307.9 million, comprising $305.0 million at the date of acquisition and $2.9 million of working capital adjustments that were recognized in due to affiliate as of December 31, 2014 and settled in February 2015. Because of the common control aspects of 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.

EX 99.1-19

EXHIBIT 99.1

Supplemental Disclosures – As-If Pooled Basis. As a result of accounting for our drop down transactions similar to a pooling of interests, our historical financial statements and those of Polar Midstream, Epping and Red Rock Gathering have been combined to reflect the historical operations, financial position and cash flows from the date common control began. Revenues and net income for the previously separate entities and the combined amounts, as presented in these consolidated financial statements follow.



	Three months ended March 31,
	2015		2014
	(In thousands)
SMLP revenues	$	68,579	$	64,889
Polar and Divide revenues	8,582		3,179
Red Rock Gathering revenues (1)			11,313
Combined revenues	$	77,161	$	79,381

SMLP net income	$	1,667	$	3,545
Polar and Divide net income	3,346		(448		)
Red Rock Gathering net income (1)			2,828
Combined net income	$	5,013	$	5,925

_________

(1) Results are fully reflected in SMLP's revenues and net income subsequent to March 2014.

Subsequent Event. On May 18, 2015, we acquired Polar Midstream and Epping from a subsidiary of Summit Investments, subject to customary working capital and capital expenditures adjustments. Due to the concurrent timing of acquiring Polar Midstream and Epping, we have aggregated these purchases into the Polar and Divide Drop Down. We funded the initial combined purchase price of $290.0 million with (i) $92.5 million of borrowings under our revolving credit facility and (ii) the issuance of $193.4 million of SMLP common units in connection with the May 2015 Equity Offering and $4.1 million of general partner interests to SMLP’s general partner.

EX 99.1-20

Exhibit

EXHIBIT 99.2

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, 2014. 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 the 2014 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 in this report. Actual results may differ materially from those contained in any forward-looking statements.

MD&A comprises the following sections:


•	Overview


•	Trends and Outlook


•	How We Evaluate Our Operations


•	Results of Operations


•	Non-GAAP Financial Measures


•	Liquidity and Capital Resources


•	Critical Accounting Estimates

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. Our gathering systems and the unconventional resource basins in which they operate are as follows:


•	Mountaineer Midstream, a natural gas gathering system located in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia;


•	Bison Midstream, an associated natural gas gathering system located in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;


•	Polar and Divide, a crude oil and produced water gathering system and transmission pipelines (under development) located in the Williston Basin;


•	DFW Midstream, a natural gas gathering system located in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and


•	Grand River Gathering, a natural gas gathering and processing system located in 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 volumes from producer activity in these regions in the future.

We provide natural gas gathering, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term and fee-based gathering and processing agreements with our customers and counterparties. We contract with producers to gather natural gas from pad sites, wells and central receipt points connected to our systems. We then compress, dehydrate, treat and/or process these volumes for delivery to downstream pipelines for ultimate delivery to third-party processing plants and/or end users. We also contract with producers to gather crude oil and produced water from wells connected to our systems for delivery to third-party rail terminals in the case of crude oil and to third-party disposal facilities in the case of produced water.

Our results are driven primarily by the volumes that we gather, treat and/or process. We generate the majority of our revenue from the natural gas gathering, treating and processing services that we provide to our natural gas

EX 99.2-1

EXHIBIT 99.2

producer customers. Under the substantial majority of these agreements, we are paid a fixed fee based on the volumes 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. We also earn revenue from (i) crude oil and produced water gathering, (ii) our marketing of natural gas and natural gas liquids, (iii) the sale of physical natural gas purchased from our customers under percentage-of-proceeds and keep-whole arrangements, and (iv) from the sale of condensate retained from our gathering services at Grand River Gathering. We can be exposed to commodity price risk from engaging in any of these additional activities with the exception of produced water gathering.

We also 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 and crude oil (and associated volumes of produced water) that we gather. If our customers delay drilling or temporarily shut-in production, our MVCs ensure that we will receive a certain amount of revenue from our customers.

Most of our gathering agreements are underpinned by areas of mutual interest ("AMIs") and MVCs. Our AMIs cover over 1.6 million acres in the aggregate and provide that any production from wells drilled by our customers within the AMI will be shipped on our gathering systems. Our MVCs, which totaled 3.9 trillion cubic feet equivalent ("Tcfe," determined using a ratio of six Mcf of gas to one barrel ("Bbl") of oil) at March 31, 2015 and average approximately 1.3 Bcfe/d through 2019, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any MVC shortfall. Our MVCs had a weighted-average remaining life of 9.1 years as of March 31, 2015, 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:


•	Acquisitions from Summit Investments and third parties;


•	Natural gas, NGL and crude oil supply and demand dynamics;


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


•	Capital markets activity and cost of capital; and


•	Shifts in operating costs and inflation.

In connection with the Polar and Divide Drop Down, our exposure to crude oil supply and demand dynamics has increased. Our expectations regarding any of the above trends 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 of MD&A included in the 2014 Annual Report.

How We Evaluate Our Operations

We conduct and report our operations in the midstream energy industry through five reportable segments:


•	the Marcellus Shale, which is served by Mountaineer Midstream;


•	the Williston Basin – Gas, which is served by Bison Midstream;


•	the Williston Basin – Liquids, which is served by Polar and Divide;


•	the Barnett Shale, which is served by DFW Midstream; and


•	the Piceance Basin, which is served by Grand River Gathering.

Our management uses a variety of financial and operational metrics to analyze our consolidated and segment 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,


•	revenues,


•	operation and maintenance expenses,

EX 99.2-2

EXHIBIT 99.2


•	EBITDA,


•	adjusted EBITDA and segment adjusted EBITDA, and


•	distributable cash flow.

There have been no changes in the composition or characteristics of these metrics during the three months ended March 31, 2015, except as noted below.

Throughput Volume

The volume of (i) natural gas that we gather, treat and/or process and (ii) crude oil and produced water that we gather depends on the level of production from natural gas or crude oil wells connected to our gathering systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity. Furthermore, because the production rate of natural gas and crude oil wells decline over time, production can only be maintained or increased by new drilling or other activity.

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


•	successful drilling activity within our areas of mutual interest;


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


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


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


•	our ability to gather, treat and/or process production that has been released from commitments with our competitors.

Following the Polar and Divide Drop Down, we will continue to report volumes for natural gas gathering and will now also report volumes for crude oil and produced water gathering. Crude oil and produced water gathering are aggregated and reported as "liquids" gathering and measured in thousands of barrels per day ("Mbbl/d"). Gathering rates are reported in barrels.

Revenues

Our revenues are primarily attributable to the volumes that we gather, treat and/or process and the rates we charge for those services. A substantial majority of our gathering and processing agreements are fee-based, which limits our direct commodity price exposure. We also have percent-of-proceeds and keep-whole arrangements under which the gathering and processing revenues that we earn correlate directly with the fluctuating price of natural gas, condensate and NGLs.

Many of our gathering and processing agreements contain MVCs pursuant to which our customers agree to ship or process a minimum volume of production on our gathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. These MVCs support our revenues and serve to mitigate the financial impact associated with declining volumes.

Certain revenue reclassifications have been made to prior-year amounts to conform to the current-year presentation. We evaluated our classification of revenues and concluded that creating an “other revenues” category would provide reporting that was more reflective of our results of operations and how we manage our business. As such, certain revenue transactions that previously represented the “and other” portions of (i) gathering services and (ii) natural gas, NGLs and condensate sales have been reclassified to other revenues. Other revenues largely comprises electricity pass-throughs for customers of Bison Midstream and Grand River Gathering and connection fees on the Polar and Divide system. Other revenues also includes the amortization expense associated with our favorable and unfavorable gas gathering contracts. These reclassifications had no impact on total revenues, net income or total partners' capital.

Subsequent to the reclassification, revenues are recognized as follows:


•	Gathering services and related fees. Revenue earned from the gathering, treating and processing services that we provide to our natural gas and crude oil producer customers.

EX 99.2-3

EXHIBIT 99.2

•

Natural gas, NGLs and condensate sales. Revenue earned from (i) the sale of physical natural gas and natural gas liquids purchased from our customers under percentage-of-proceeds and keep-whole arrangements with certain of our customers on the Bison Midstream and Red Rock gathering systems, (ii) the sale of natural gas we retain from our DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River.


•	Other revenues. Revenue earned primarily from (i) electricity costs for which our Bison Midstream and Grand River Gathering customers have agreed to reimburse us and (ii) connection fees for customers of the Polar and Divide system.

For additional information on our reportable segments and how the other metrics noted above help us manage our business, see Note 3 to the unaudited condensed consolidated financial statements and the "How We Evaluate Our Operations" section of MD&A included in the 2014 Annual Report.

EX 99.2-4

EXHIBIT 99.2

Results of Operations

Consolidated Overview of the Three Months Ended March 31, 2015 and 2014

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



	Three months ended March 31,
	2015			2014
	(Dollars in thousands, except fee-rate data)
Revenues:
Gathering services and related fees	$	60,767		$	49,903
Natural gas, NGLs and condensate sales	12,613			26,304
Other revenues	3,781			3,174
Total revenues	77,161			79,381
Costs and expenses:
Cost of natural gas and NGLs	5,384			14,353
Operation and maintenance	21,057			21,832
General and administrative	9,658			9,053
Transaction costs	—			537
Depreciation and amortization	23,755			20,379
Total costs and expenses	59,854			66,154
Other income	1			1
Interest expense	(12,118		)	(7,144		)
Income before income taxes	5,190			6,084
Income tax expense	(177		)	(159		)
Net income	$	5,013		$	5,925

Other Financial Data:
EBITDA (1)	$	41,313		$	33,832
Adjusted EBITDA (1)	55,050			46,993
Capital expenditures (2)	25,188			53,580
Acquisitions of gathering systems (3)	2,941			305,000
Distributable cash flow (1)(2)	40,926			33,602

Operating Data:
Miles of pipeline as of March 31	2,645			2,451
Aggregate average throughput – gas (MMcf/d)	1,583			1,311
Aggregate average throughput rate per Mcf – gas	$	0.40		$	0.44
Average throughput – liquids (Mbbl/d)	59.9			29.1
Average throughput rate per Bbl – liquids	$	1.43		$	1.06

__________

(1) See "Non-GAAP Financial Measures" herein for additional information on EBITDA, adjusted EBITDA and distributable cash flow as well as their reconciliations to the most directly comparable GAAP financial measure.

(2) See "Liquidity and Capital Resources" herein for additional information on capital expenditures.

(3) Reflects cash paid (including working capital and capital expenditure adjustments) and value of units issued, if any, to fund acquisitions and/or drop downs. For additional information, see Note 15 to the unaudited condensed consolidated financial statements.

Volumes – Gas. For the three months ended March 31, 2015, our aggregate throughput volumes increased to an average of 1,583 MMcf/d, compared with an average of 1,311 MMcf/d for the three months ended March 31, 2014.

EX 99.2-5

EXHIBIT 99.2

The increase in volume throughput largely reflects the contribution from the Mountaineer Midstream and DFW Midstream systems, partially offset by volume throughput declines on the Grand River Gathering system.

Volumes – Liquids. Average daily throughput for crude oil and produced water increased to 59.9 Mbbl/d for the three months ended March 31, 2015, compared with an average of 29.1 Mbbl/d in the prior-year period. The increase in crude oil and produced water volume throughput primarily reflects the continued development of the Polar and Divide system, new pad site connections and producers' ongoing drilling activity.

Revenues. For the three months ended March 31, 2015, total revenues decreased $2.2 million, or 3%. The decrease in total revenues reflects a decline in natural gas, NGLs and condensate sales and other for Bison Midstream, Grand River Gathering and DFW Midstream, partially offset by an increase in gathering services and other fees across all gathering systems.

Gathering Services and Related Fees. The increase in gathering services and related fees during the three months ended March 31, 2015 was primarily driven by higher volume throughput on the Polar and Divide, DFW Midstream and Mountaineer Midstream systems. The aggregate average throughput rate for gas decreased to $0.40 per Mcf during the three months ended March 31, 2015, compared with $0.44 per Mcf in the prior-year period primarily as a result of a larger proportion of gathering fee revenue from Mountaineer Midstream. The average throughput rate for crude oil and produced water increased to $1.43 per Bbl during the three months ended March 31, 2015, compared with $1.06 per Bbl in the prior-year period primarily as a result of contract amendments in 2014 which increased gathering rates in connection with our commitment to further expand the Polar and Divide system.

Natural Gas, NGLs and Condensate Sales. The decrease in natural gas, NGLs and condensate sales for the three months ended March 31, 2015 was primarily a result of the impact of declining commodity prices, partially offset by an increase in volumes on the Bison Midstream and Grand River Gathering systems that are subject to percent-of-proceeds arrangements. Declining commodity prices negatively impacted our percent-of-proceeds arrangements at Bison Midstream and Grand River Gathering, our fuel retainage revenue at DFW Midstream and condensate revenue for Grand River Gathering.

Costs and Expenses. For the three months ended March 31, 2015, total costs and expenses decreased $6.3 million, or 10%, primarily due to a decrease in cost of natural gas and NGLs at Bison Midstream and Grand River Gathering and a decrease in operation and maintenance at each of our gathering systems, except Polar and Divide. These lower expenses were partially offset by increased operation and maintenance and general and administrative expenses for Polar and Divide as well as an increase in depreciation and amortization across all of our gathering systems.

Cost of Natural Gas and NGLs. The decrease in cost of natural gas and NGLs during the three months ended March 31, 2015 was largely driven by declining commodity prices and the associated impact on our percent-of-proceeds arrangements at Bison Midstream and Grand River Gathering. This impact was partially offset by an increase in volume throughput for these arrangements.

Operation and Maintenance. Operation and maintenance expense decreased during the three months ended March 31, 2015 primarily as a result of lower-cost electricity and a decline in third-party natural gas treating expenses for DFW Midstream, partially offset by an overall increase in compensation-related expenses and an increase in connection fee pass-through expense for Polar and Divide as a result of system expansion (the revenue component of which is recognized in other revenues).

General and Administrative. General and administrative expense increased during the three months ended March 31, 2015 largely as a result of an increase in salaries, benefits and incentive compensation and professional services fees.

Transaction Costs. Transaction costs recognized during the three months ended March 31, 2014 primarily relate to financial and legal advisory costs associated with the Red Rock Drop Down.

Depreciation and Amortization. The increase in depreciation and amortization expense during the three months ended March 31, 2015 was largely driven by an increase in assets placed into service and contract amortization, with the substantial majority of the increase being attributed to Grand River Gathering and Polar and Divide.

Interest Expense. The increase in interest expense during the three months ended March 31, 2015, was primarily driven by our issuance of $300.0 million of 5.50% senior notes in July 2014.

For information on how our financial results are recognized, see the "Results of Operations" section of MD&A included in the 2014 Annual Report.

EX 99.2-6

EXHIBIT 99.2

Segment Overview of the Three Months Ended March 31, 2015 and 2014

Marcellus Shale. The Mountaineer Midstream gathering system provides our midstream services for the Marcellus Shale reportable segment. Marcellus Shale volume throughput averaged 547 MMcf/d for the three months ended March 31, 2015, compared with 286 MMcf/d in the prior-year period and reflects the continuation of active drilling by Mountaineer Midstream's anchor customer and the connection of new wells upstream of the Mountaineer Midstream system.

Information regarding our operations in the Marcellus Shale follows.



	Marcellus Shale (1)
	Three months ended March 31,				Percentage Change
	2015		2014		2015 v. 2014
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	7,840	$	5,356	46	%
Total revenues	7,840		5,356		46	%
Costs and expenses:
Operation and maintenance	1,215		969		25	%
General and administrative	90		504		(82	)%
Depreciation and amortization	2,168		1,801		20	%
Total costs and expenses	3,473		3,274		6	%
Add:
Depreciation and amortization	2,168		1,801
Segment adjusted EBITDA	$	6,535	$	3,883	68	%

Average throughput (MMcf/d)	547		286		91	%

__________

(1) Contract terms related to throughput rate per MCF are excluded for confidentiality purposes.

Segment adjusted EBITDA increased $2.7 million during the three months ended March 31, 2015 reflecting:


•	the impact of an increase in volume throughput which translated into higher gathering services and other fees revenue.

•

the benefit of higher volume throughput was partially offset by a decline in compression services, which resulted from a shift in volume throughput mix to a larger percentage of previously compressed natural gas entering our gathering lines. As a result of this shift in volume throughput mix, the proportion of high-pressure gathering services increased, which, due to its lower rate relative to compression fees, negatively impacted gathering services and other fees as well as the average throughput rate per Mcf.


•	minimum revenue commitment payments related to the recently completed Zinnia Loop project, received in the first quarter of 2015.


•	an increase in operation and maintenance primarily as a result of system expansion and the associated increase in volume throughput.


•	a decline in general and administrative expenses primarily as a result of our decision to discontinue allocating certain corporate expenses beginning in the first quarter of 2015.

Depreciation and amortization increased during the three months ended March 31, 2015 largely as a result of assets placed into service during the third quarter of 2014, most notably the Zinnia Loop project.

Williston Basin – Gas. The Bison Midstream gathering system provides our midstream services for the Williston Basin – Gas reportable segment. Williston Basin – Gas volume throughput averaged 18 MMcf/d for the three months ended March 31, 2015, compared with 12 MMcf/d in the prior-year period. The increase in volume throughput in 2015 reflects additional pad site connections and compression capacity installed in the latter half of 2014, which improved system hydraulics. Volume throughput in the first quarter of 2014 also reflected the impact of severe winter weather in northwestern North Dakota and operational challenges caused by water hydrate issues.

EX 99.2-7

EXHIBIT 99.2

These issues were remediated during the second quarter of 2014. Bison Midstream's aggregate average throughput rate declined to $2.80 per Mcf during the three months ended March 31, 2015, compared with $4.59 per Mcf in the prior-year period, primarily as a result of a larger proportion of percent-of-proceeds contracts and the impact of declining commodity prices.

Information regarding our operations in the Williston Basin – Gas follows.



	Williston Basin – Gas
	Three months ended March 31,				Percentage Change
	2015		2014		2015 v. 2014
	(Dollars in thousands, except fee-rate data)
Revenues:
Gathering services and related fees	$	244	$	209	17	%
Natural gas, NGLs and condensate sales	7,358		15,476		(52	)%
Other revenues	1,306		1,078		21	%
Total revenues	8,908		16,763		(47	)%
Costs and expenses:
Cost of natural gas and NGLs	3,079		10,789		(71	)%
Operation and maintenance	2,989		2,962		1	%
General and administrative	167		1,028		(84	)%
Depreciation and amortization	4,698		4,250		11	%
Total costs and expenses	10,933		19,029		(43	)%
Add:
Depreciation and amortization	4,698		4,250
Adjustments related to MVC shortfall payments	2,660		2,692
Segment adjusted EBITDA	$	5,333	$	4,676	14	%

Average throughput (MMcf/d)	18		12		50	%
Average throughput rate per Mcf	$	2.80	$	4.59	(39	)%

Segment adjusted EBITDA increased $0.7 million during the three months ended March 31, 2015 reflecting:


•	the previously mentioned decision to discontinue certain general and administrative expense allocations.


•	the impact of declining commodity prices which negatively affected the margins we earn under percent-of-proceeds arrangements.


•	a decrease in operation and maintenance expenses largely as a result of the first quarter 2014 water hydrate remediation effort.

Depreciation and amortization increased during the three months ended March 31, 2015 largely as a result compression assets placed into service during the second half of 2014.

Williston Basin – Liquids. The Polar and Divide system provides our midstream services for the Williston Basin – Liquids reportable segment. Williston Basin – Liquids volume throughput averaged 59.9 Mbbl/d for the three months ended March 31, 2015, compared with 29.1 Mbbl/d in the prior-year period. The increase in volume throughput in 2015 reflects new pad site connections and ongoing drilling activity in Polar and Divide's service area. Polar Midstream's aggregate average throughput rate increased to $1.43 per Bbl during the three months ended March 31, 2015, compared with $1.06 per Bbl in the prior-year period, primarily as a result of contract amendments in 2014 which increased gathering rates in connection with our commitment to further expand the Polar and Divide system.

EX 99.2-8

EXHIBIT 99.2

Information regarding our operations in the Williston Basin – Liquids follows.



	Williston Basin – Liquids
	Three months ended March 31,				Percentage Change
	2015		2014		2015 v. 2014
	(Dollars in thousands, except fee-rate data)
Revenues:
Gathering services and related fees	$	7,726	$	2,772	*
Other revenues	856		407		110	%
Total revenues	8,582		3,179		*
Costs and expenses:
Operation and maintenance	2,317		1,723		34	%
General and administrative	1,307		1,167		12	%
Depreciation and amortization	1,612		737		119	%
Total costs and expenses	5,236		3,627		44	%
Add:
Depreciation and amortization	1,612		737
Unit-based compensation	85		85
Segment adjusted EBITDA	$	5,043	$	374	*

Average throughput (Mbbl/d)	59.9		29.1		106	%
Average throughput rate per Bbl	$	1.43	$	1.06	35	%

__________

* Not considered meaningful

Segment adjusted EBITDA increased $4.7 million during the three months ended March 31, 2015 reflecting:


•	the impact of higher volume throughput on gathering services and related fees.


•	higher gathering rates associated with contract amendments in 2014.


•	an increase in operation and maintenance expenses largely as a result of system buildout.

Other revenues and operation and maintenance also reflect the effect of an increase in connection fees, which, due to their pass-through nature, have no impact on segment adjusted EBITDA.

Depreciation and amortization increased during the three months ended March 31, 2015 largely as a result of gathering pipeline placed into service during 2014.

Barnett Shale. The DFW Midstream gathering system provides our midstream services for the Barnett Shale reportable segment. DFW Midstream volume throughput increased to 403 MMcf/d during the three months ended March 31, 2015, compared with 348 MMcf/d in the prior-year period. The increase in volume throughput primarily reflects customer production which recommenced from several pad sites that had been temporarily shut-in for drilling and completion activities beginning in the third quarter of 2013 and continuing until late 2014. In addition, DFW Midstream volume throughput benefited from the contribution of the Lonestar assets, which we acquired on September 30, 2014. These increases were partially offset by a lack of drilling activity by DFW Midstream's anchor customer. DFW Midstream's aggregate average throughput rate was relatively unchanged at $0.60 per Mcf during the three months ended March 31, 2015, compared with $0.59 per Mcf in the prior-year period.

EX 99.2-9

EXHIBIT 99.2

Information regarding our operations in the Barnett Shale follows.



	Barnett Shale
	Three months ended March 31,						Percentage Change
	2015			2014			2015 v. 2014
	(Dollars in thousands, except fee-rate data)
Revenues:
Gathering services and related fees	$	21,794		$	19,177		14	%
Natural gas, NGLs and condensate sales	1,922			4,064			(53	)%
Other revenues	181			(204		)	*
Total revenues	23,897			23,037			4	%
Costs and expenses:
Operation and maintenance	6,812			7,892			(14	)%
General and administrative	353			1,170			(70	)%
Depreciation and amortization	3,906			3,638			7	%
Total costs and expenses	11,071			12,700			(13	)%
Add:
Depreciation and amortization	4,157			3,864
Adjustments related to MVC shortfall payments	(223		)	833
Segment adjusted EBITDA	$	16,760		$	15,034		11	%

Average throughput (MMcf/d)	403			348			16	%
Average throughput rate per Mcf	$	0.60		$	0.59		2	%

__________

* Not considered meaningful

Segment adjusted EBITDA increased $1.7 million during the three months ended March 31, 2015 reflecting:


•	an increase in gathering services and other fees due to increased volumes.


•	the impact of declining natural gas prices on the fuel retainage fee that is paid in-kind by certain of our customers to offset the costs we incur to operate DFW Midstream's electric-drive compression assets.

•

a decline in operation and maintenance expense due to lower electricity expense and a decline in third-party natural gas treating expenses. We purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices. As a result, the decline in natural gas prices translated into lower electricity expenses. The natural gas price effect was partially offset by an increase in electricity usage due to higher volume throughput.


•	a decline in third-party natural gas treating expenses, which we recognize in operation and maintenance. In February 2014, we commissioned a new 150 gallon per minute natural gas treating facility which allowed us to provide treating services to our customers rather than having to contract with a third-party service provider for treating services.


•	a negative adjustment to MVC shortfall payments in the first quarter of 2015 for a customer that exceeded volume throughput expectations as a result of wells placed in service in December 2014. The 2015 adjustment was necessary to true-up the customer's balance due to its annual MVC period ending on April 10.


•	the previously mentioned decision to discontinue certain general and administrative expense allocations.

Depreciation and amortization increased during the three months ended March 31, 2015 largely as a result of placing the Lonestar assets into service in September 2014.

Piceance Basin. The Grand River Gathering system provides our midstream services for the Piceance Basin reportable segment. Red Rock Gathering became part of the Grand River Gathering system in connection with the Red Rock Drop Down in March 2014. Our results include activity for Red Rock Gathering since October 23, 2012,

EX 99.2-10

EXHIBIT 99.2

the date on which common control began. For additional information, see Notes 1 and 3 to the unaudited condensed consolidated financial statements.

Volume throughput for the Piceance Basin decreased to 615 MMcf/d during the three months ended March 31, 2015 from 665 MMcf/d during the prior-year period primarily as a result of Encana's temporary suspension of drilling activities, which began in the fourth quarter of 2013. This decline was partially offset by new pad site connections as well as the March 2014 start-up of a cryogenic processing plant. The aggregate average throughput rate increased to $0.42 per Mcf during the first quarter of 2015 from $0.38 per Mcf during the first quarter of 2014 largely as a result of the shift in volume throughput mix noted above. A shift in volume throughput mix has translated into higher average gathering rates per Mcf.

Certain of our gas gathering agreements for Grand River Gathering include MVCs that increase in both rate and volume commitment over the next few years and largely mitigate the financial impact associated with declining volumes from certain customers. As a result, lower volume throughput for the customers subject to these MVCs translated into larger MVC shortfall payments.

Information regarding our operations in the Piceance Basin follows.



	Piceance Basin
	Three months ended March 31,				Percentage Change
	2015		2014		2015 v. 2014
	(Dollars in thousands, except fee-rate data)
Revenues:
Gathering services and related fees	$	23,163	$	22,389	3	%
Natural gas, NGLs and condensate sales	3,333		6,764		(51	)%
Other revenue	1,438		1,893		(24	)%
Total revenues	27,934		31,046		(10	)%
Costs and expenses:
Cost of natural gas and NGLs	2,305		3,564		(35	)%
Operation and maintenance	7,724		8,286		(7	)%
General and administrative	572		2,103		(73	)%
Depreciation and amortization	11,205		9,811		14	%
Total costs and expenses	21,806		23,764		(8	)%
Add:
Depreciation and amortization	11,205		9,811
Adjustments related to MVC shortfall payments	9,903		8,488
Segment adjusted EBITDA	$	27,236	$	25,581	6	%

Average throughput (MMcf/d)	615		665		(8	)%
Average throughput rate per Mcf	$	0.42	$	0.38	11	%

Segment adjusted EBITDA increased $1.7 million during the three months ended March 31, 2015 reflecting:


•	lower condensate sales due to a weak commodity price environment.


•	the previously mentioned decision to discontinue certain general and administrative expense allocations.


•	an increase in anticipated MVC shortfall payments due to increasing rate and volume commitment provisions in certain gas gathering agreements, as noted above.


•	the impact of declining commodity prices which negatively impacted the margins that we earn from our percent-of-proceeds contracts.


•	a decline in operation and maintenance due to lower utilities and compression expenses and property taxes, partially offset by an increase in salaries and benefits.

EX 99.2-11

EXHIBIT 99.2

Depreciation and amortization increased $1.4 million during the three months ended March 31, 2015 largely as a result of an increase in contract amortization for Grand River Gathering's anchor customer and the March 2014 commissioning of the cryogenic processing plant.

Corporate. Corporate represents those revenues and expenses that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, transaction costs and interest expense. Items to note follow.



	Corporate
	Three months ended March 31,				Percentage Change
	2015		2014		2015 v. 2014
	(In thousands)
Costs and expenses:
General and administrative	$	7,169	$	3,081	133	%
Transaction costs	—		537		(100	)%
Depreciation and amortization	166		142		17	%
Interest expense	12,118		7,144		70	%

General and Administrative. The increase in general and administrative expense during the three months ended March 31, 2015, largely reflects the impact of our decision to discontinue allocating certain expenses, primarily salaries, benefits, incentive compensation and rent expense, to our operating segments.

Transaction Costs. Transaction costs recognized during the three months ended March 31, 2014 primarily relate to financial and legal advisory costs associated with the Red Rock Drop Down.

Interest Expense. The increase in interest expense during the three months ended March 31, 2015, was primarily driven by our issuance of $300.0 million of 5.50% senior notes in July 2014.

Non-GAAP Financial Measures

EBITDA, adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We define EBITDA as net income, plus interest expense, income tax expense, and depreciation and amortization, less interest income and income tax benefit. We define adjusted EBITDA as EBITDA plus adjustments related to MVC shortfall payments, impairments and other noncash expenses or losses, less other noncash income or gains. We define distributable cash flow as adjusted EBITDA plus cash interest received, less cash interest paid, senior notes interest, cash taxes paid and maintenance capital expenditures. 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. For additional information on the limitations of our non-GAAP financial measures and how we compensate for those limitations, see the "Non-GAAP Financial Measures" section of MD&A included in the 2014 Annual Report.

Non-GAAP reconciliations items to note. The following items should be noted when reviewing our non-GAAP reconciliations:


•	Interest expense presented in the net income-basis non-GAAP reconciliation includes amortization of deferred loan costs while interest expense presented in the cash flow-basis non-GAAP reconciliation is adjusted to exclude amortization of deferred loan costs. See the unaudited condensed consolidated statements of cash flows for additional information.


•	Depreciation and amortization includes the favorable and unfavorable gas gathering contract amortization expense reported in other revenues.

•

EX 99.2-12

EXHIBIT 99.2


•	Senior notes interest represents the net of interest expense accrued and paid during the period. See "Liquidity and Capital Resources—Long-Term Debt" and Note 7 to the consolidated financial statements included in the 2014 Annual Report.


•	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.

•

As a result of accounting for our drop down transactions similar to a pooling of interests, EBITDA, adjusted EBITDA, and distributable cash flow reflect the historical operations, financial position and cash flows of Polar Midstream, Epping and Red Rock Gathering for the periods beginning with the date that common control began and ending on the date that the respective drop down closed. See Notes 1 and 15 to the unaudited condensed consolidated financial statements and Note 15 to the consolidated financial statements included in the 2014 Annual Report.


•	EBITDA, adjusted EBITDA, distributable cash flow and net cash provided by operating activities include transaction costs. These unusual expenses are settled in cash. For additional information, see "Results of Operations—Corporate" herein.

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



	Three months ended March 31,
	2015			2014
	(In thousands)
Reconciliation of net income to EBITDA, adjusted EBITDA and distributable cash flow:
Net income	$	5,013		$	5,925
Add:
Interest expense	12,118			7,144
Income tax expense	177			159
Depreciation and amortization	24,006			20,605
Less:
Interest income	1			1
EBITDA	$	41,313		$	33,832
Add:
Adjustments related to MVC shortfall payments	12,340			12,013
Unit-based compensation	1,397			1,148
Adjusted EBITDA	$	55,050		$	46,993
Add:
Cash interest received	1			1
Less:
Cash interest paid	22,812			14,308
Senior notes interest	(11,171		)	(6,500		)
Maintenance capital expenditures	2,484			5,584
Distributable cash flow	$	40,926		$	33,602

EX 99.2-13

EXHIBIT 99.2

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



	Three months ended March 31,
	2015			2014
	(In thousands)
Reconciliation of net cash provided by operating activities to EBITDA, adjusted EBITDA and distributable cash flow:
Net cash provided by operating activities	$	54,786		$	48,243
Add:
Interest expense	11,327			6,540
Income tax expense	177			159
Changes in operating assets and liabilities	(23,579		)	(19,961		)
Less:
Unit-based compensation	1,397			1,148
Interest income	1			1
EBITDA	$	41,313		$	33,832
Add:
Adjustments related to MVC shortfall payments	12,340			12,013
Unit-based compensation	1,397			1,148
Adjusted EBITDA	$	55,050		$	46,993
Add:
Cash interest received	1			1
Less:
Cash interest paid	22,812			14,308
Senior notes interest	(11,171		)	(6,500		)
Maintenance capital expenditures	2,484			5,584
Distributable cash flow	$	40,926		$	33,602

Liquidity and Capital Resources

Based on the terms of our partnership agreement, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our revolving credit facility and future issuances of equity and debt securities.

Capital Markets Activity

We had no capital markets activity during the three months ended March 31, 2015.

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 the assets of Summit Holdings and its subsidiaries 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. As of March 31, 2015, the outstanding balance of the revolving credit facility was $196.0 million and the unused portion totaled $504.0 million. As of March 31, 2015, 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, 2015.

Senior Notes. In July 2014, Summit Holdings and Summit Midstream Finance Corp. co-issued $300.0 million of 5.50% senior unsecured notes maturing August 15, 2022. In June 2013, they co-issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021. There were no defaults or events of default during the three months ended March 31, 2015 on either series of senior notes.

EX 99.2-14

EXHIBIT 99.2

For additional information, see Note 8 to the unaudited condensed consolidated financial statements.

Cash Flows

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



	Three months ended March 31,
	2015			2014
	(In thousands)
Net cash provided by operating activities	$	54,786		$	48,243
Net cash used in investing activities	(28,129		)	(358,580		)
Net cash (used in) provided by financing activities	(40,007		)	300,384
Change in cash and cash equivalents	$	(13,350	)	$	(9,953	)

Operating activities. Cash flows from operating activities increased by $6.5 million for the three months ended March 31, 2015 primarily due to cash received as a result of MVCs. These cash receipts were largely offset by an increase in interest due to the 5.5% senior notes and other operating activities.

Investing activities. Cash flows used in investing activities for the three months ended March 31, 2015 were related primarily to (i) the ongoing expansion of the Polar and Divide system, (ii) expansion of compression capacity on the Bison Midstream system, (iii) pipeline construction projects to connect new receipt points on the Grand River and Bison Midstream systems and (iv) the settlement of the working capital adjustment associated with the Red Rock Drop Down.

Cash flows used in investing activities for the three months ended March 31, 2014 primarily reflect the Partnership's acquisition of Red Rock Gathering from a subsidiary of Summit Investments. Additional expenditures for the three months ended March 31, 2014 primarily reflect (i) construction of a processing plant for Grand River Gathering, (ii) ongoing expansion of the Polar and Divide system, (iii) projects to expand compression capacity on the Bison Midstream system and (iv) adding pipeline on the Mountaineer Midstream system.

Financing activities. Details of cash flows provided by financing activities were as follows:



	Three months ended March 31,
	2015			2014
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	$	(35,093	)	$	(26,366	)
Borrowings under revolving credit facility	14,000			125,000
Repayments under revolving credit facility	(26,000		)	(20,000		)
Deferred loan costs	(15		)	(65		)
Tax withholdings on vested SMLP LTIP awards	(910		)	(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	5,899			14,278
Expenses paid by Summit Investments on behalf of contributed subsidiaries	2,112			5,863
Net cash (used in) provided by financing activities	$	(40,007	)	$	300,384

Net cash used in financing activities for the three months ended March 31, 2015 was primarily composed of the following:


•	Distributions declared in respect of the fourth quarter of 2014 (paid in the first quarter of 2015); and


•	Net repayments under our revolving credit facility.

EX 99.2-15

EXHIBIT 99.2

Net cash provided by financing activities for the three months ended March 31, 2014 was primarily composed of the following:


•	Net proceeds from an offering of common units in March 2014, which were used to partially fund the Red Rock Drop Down;


•	Net borrowings of $105.0 million under our revolving credit facility, including $100.0 million to partially fund the Red Rock Drop Down; and


•	Distributions declared in respect of the fourth quarter of 2013 (paid in the first quarter of 2014).

Capital Requirements

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


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


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

For the three months ended March 31, 2015, SMLP recorded total capital expenditures of $25.2 million, which included $2.5 million of maintenance capital expenditures.

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.

We believe that our existing $700.0 million revolving credit facility, which had approximately $504.0 million of available capacity at March 31, 2015, together with our access to the debt and equity capital markets, will be adequate to finance our acquisition strategy for the foreseeable future without adversely impacting our liquidity or our ability to make quarterly cash distributions to our unitholders.

Distributions

Based on the terms of our partnership agreement, we expect to distribute to unitholders most of the cash generated by our operations. For additional information, see Note 9 to the unaudited condensed consolidated financial statements.

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. For additional information, see Note 12 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, 2015.

Critical Accounting Estimates

We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. 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

EX 99.2-16

EXHIBIT 99.2

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, 2015.

Goodwill. As of December 31, 2014, our preliminary estimates of the fair values of the identified assets and liabilities calculated in the step two testing of the Bison Midstream reporting unit indicated that all of the associated goodwill had been impaired. In the first quarter of 2015, we finalized our calculations of the fair values of the identified assets and liabilities, confirming the preliminary goodwill impairment of $54.2 million. For additional information, see Note 5 to the consolidated financial statements included in the 2014 Annual Report.

For additional information regarding critical accounting estimates generally, see the "Critical Accounting Estimates" section of MD&A included in the 2014 Annual Report.

EX 99.2-17