EXHIBIT 99.2

Item 2. 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, 2016. 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 2016 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. Actual results may differ materially from those contained in any forward-looking statements.

This MD&A comprises the following sections:

• Overview

• Trends and Outlook

• How We Evaluate Our Operations

• Results of Operations

• Liquidity and Capital Resources

• Critical Accounting Estimates

• Forward-Looking Statements

Overview

We are a growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental United States. We are the owner-operator of or have significant ownership interests in the following gathering systems:

• Ohio Gathering, a natural gas gathering system and a condensate stabilization facility operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;

• Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;

• 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;

• Polar and Divide, crude oil and produced water gathering systems and transmission pipelines located in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

• Tioga Midstream, crude oil, produced water and associated natural gas gathering systems operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

• Grand River, 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;

• Niobrara G&P, an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara and Codell shale formations in northeastern Colorado;

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

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

For additional information on our organization and systems, see Notes 1 and 3 to the unaudited condensed consolidated financial statements.

Our financial results are driven primarily by volume throughput and expense management. We generate the majority of our revenues from the gathering, treating and processing services that we provide to our customers. A substantial majority of the volumes that we gather, treat and/or process have a fixed-fee rate structure thereby enhancing the stability of our cash flows by

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EXHIBIT 99.2

providing a revenue stream that is not subject to direct commodity price risk. We also earn revenues from (i) the sale of physical natural gas and NGLs purchased under percentage-of-proceeds arrangements with certain of our customers on the Bison Midstream and Grand River systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. These additional activities, which expose us to direct commodity price risk, accounted for less than9%of total revenues during the three months ended March 31, 2017.

We also have indirect exposure to changes in commodity prices in that persistently low commodity prices may cause our customers to delay and/or cancel drilling and/or completion activities 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 certain of our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, the associated MVCs ensure that we will recognize a minimum amount of revenue.

The following table presents certain consolidated and reportable segment financial data.

	Three month ended March 31,
	2017			2016
	(In thousands)
Net loss	$	(583	)	$	(3,665	)
Reportable segment adjusted EBITDA:
Utica Shale	7,912			3,189
Ohio Gathering	9,073			12,388
Williston Basin	17,809			19,719
Piceance/DJ Basins	28,974			24,817
Barnett Shale	12,088			14,077
Marcellus Shale	5,647			4,600
Net cash provided by operating activities	$	62,449		$	66,849
Acquisitions of gathering systems (1)	—			867,427
Capital expenditures (2)	14,428			61,326
Contributions to equity method investees	4,936			15,645
Distributions to unitholders	$	44,452		$	40,975
Issuance of senior notes	500,000			—
Tender and redemption of senior notes	(300,000		)	—
Net (repayments) borrowings under Revolving Credit Facility	(173,000		)	389,000

_________

(1) Reflects cash and noncash consideration, including working capital and capital expenditure adjustments paid (received), for acquisitions and/or drop downs (see Note 16 to the unaudited condensed consolidated financial statements).

(2) See "Liquidity and Capital Resources" herein and Note 3 to the unaudited condensed consolidated financial statements for additional information on capital expenditures.

Three months ended March 31, 2017.  The following items are reflected in our financial results:

• In March 2017, we recognized $37.7 million of gathering services and related fees revenue that had been previously deferred in connection with an MVC arrangement with a certain Williston Basin customer, for which we determined we had no further performance obligations. We include the effect of adjustments related to MVC shortfall payments in our definition of segment adjusted EBITDA. As such, the Williston Basin segment adjusted EBITDA was not impacted because the revenue recognition was offset by the associated adjustments related to MVC shortfall payments for this customer (see Note 8 to the unaudited condensed consolidated financial statements).

• In February 2017, we amended the 2014 SRS to include additional guarantor subsidiaries and completed a public offering of $500.0 million principal 5.75% Senior Notes.  Concurrent and following the offering, we tendered and redeemed all of the outstanding 7.5% Senior Notes.   The remaining 7.5% Senior Notes were redeemed on March 18, 2017, with payment made on March 20, 2017.  We used the proceeds from the issuance of the 5.75% Senior Notes to (i) fund the repurchase of the outstanding $300.0 million principal 7.5% Senior Notes, (ii) pay redemption and call premiums on the 7.5% Senior Notes totaling $17.9 million and (iii) pay $172.0 million of the balance outstanding under our Revolving Credit Facility.

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Three months ended March 31, 2016.  The following items are reflected in our financial results:

• In March 2016, we acquired the 2016 Drop Down Assets from a subsidiary of Summit Investments. We funded the drop down with borrowings under our revolving credit facility and the execution of the Deferred Purchase Price Obligation with Summit Investments (see Note 16 to the unaudited condensed consolidated financial statements).

Trends and Outlook

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

• Natural gas, 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.

Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. For additional information, see the "Trends and Outlook" section of MD&A included in the 2016 Annual Report.

How We Evaluate Our Operations

We conduct and report our operations in the midstream energy industry through six reportable segments. We evaluate our business operations each reporting period to determine whether any of our gathering system operating segments in which we internally report financial information are considered significant and would require us to separately disclose certain segment financial information in our external reporting. As a result of our evaluation for the quarterly period ended June 30, 2017, we determined that both the Summit Utica natural gas gathering system and the Ohio Gathering natural gas gathering system, each previously reported within the Utica Shale reportable segment, were and are expected to continue to be significant operating segments. As such, we modified our current segments such that the Utica Shale reportable segment includes the Summit Utica gathering system and the Ohio Gathering reportable segment includes our ownership interest in OGC and OCC. We have disclosed the required segment information for Summit Utica and Ohio Gathering and the periods presented herein have been recast to reflect this change. Our reportable segments are as follows:

• the Utica Shale, which is served by Summit Utica;

• Ohio Gathering, which includes our ownership interest in OGC and OCC;

• the Williston Basin, which is served by Bison Midstream, Polar and Divide and Tioga Midstream;

• the Piceance/DJ Basins, which is served by Grand River and Niobrara G&P;

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

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

Each of our reportable segments provides midstream services in a specific geographic area. Our 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 (see Note 3 to the unaudited condensed consolidated financial statements).

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 determining the amounts of cash distributions to pay to our unitholders. These metrics include:

• throughput volume,

• revenues,

• operation and maintenance expenses and

• segment adjusted EBITDA.

We review these metrics on a regular basis for consistency and trend analysis. There have been no changes in the composition or characteristics of these metrics during the three months ended March 31, 2017.

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Additional Information. For additional information, see the "Results of Operations" section herein and the notes to the unaudited condensed consolidated financial statements. For additional information on how these metrics help us manage our business, see the "How We Evaluate Our Operations" section of MD&A included in the 2016 Annual Report. For information on impending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 to the unaudited condensed consolidated financial statements.

Results of Operations

Consolidated Overview of the Three Months Ended March 31, 2017 and 2016

The following table presents certain consolidated and operating data.

	Three months ended March 31,
	2017			2016
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	118,013		$	78,100
Natural gas, NGLs and condensate sales	11,120			7,588
Other revenues	6,672			4,883
Total revenues	135,805			90,571
Costs and expenses:
Cost of natural gas and NGLs	9,052			6,290
Operation and maintenance	23,692			25,842
General and administrative	14,132			12,879
Depreciation and amortization	28,569			27,728
Transaction costs	—			1,174
Loss (gain) on asset sales, net	3			(63		)
Long-lived asset impairment	284			—
Total costs and expenses	75,732			73,850
Other income	71			22
Interest expense	(16,716		)	(15,882		)
Early extinguishment of debt	(22,020		)	—
Deferred Purchase Price Obligation expense	(20,883		)	(7,463		)
Income (loss) before income taxes and (loss) income from equity method investees	525			(6,602		)
Income tax (expense) benefit	(452		)	77
(Loss) income from equity method investees	(656		)	2,860
Net loss	$	(583	)	$	(3,665	)
Volume throughput (1):
Aggregate average daily throughput – natural gas (MMcf/d)	1,627			1,523
Aggregate average daily throughput – liquids (Mbbl/d)	76.4			95.0

__________

(1) Exclusive of volume throughput for Ohio Gathering. For additional information, see the “Ohio Gathering” section herein.

Volumes – Gas.  Natural gas throughput volumes increased 104 MMcf/d compared to the first quarter of 2016, primarily reflecting:

• a volume throughput increase of 143 MMcf/d for the Utica Shale segment.

• a volume throughput increase of 43 MMcf/d for the Piceance/DJ Basins segment.

• a volume throughput decrease of 55 MMcf/d for the Barnett Shale segment.

• a volume throughput decrease of 19 MMcf/d for the Marcellus Shale segment.

Volumes – Liquids.  Crude oil and produced water throughput volumes decreased 18.6 Mbbl/d compared to the first quarter of 2016, primarily reflecting decreased drilling activity and natural production declines.  Volume throughput was also impacted by the severe winter weather in North Dakota starting the fourth quarter of 2016 which continued through most of the first quarter of 2017.

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EXHIBIT 99.2

Revenues.  Total revenues increased $45.2 million, or 50%, compared to the first quarter of 2016 primarily reflecting:

• the recognition of $37.7 million of previously deferred revenue related to a certain Williston Basin customer.

• the recognition of $2.6 million of business interruption recoveries for the Williston Basin segment.

• a $4.5 million increase for the Utica Shale segment due to the ongoing development of the Summit Utica system.

• a $3.5 million increase in natural gas, NGLs and condensate sales primarily due to increases for the Williston Basin and Piceance/DJ Basins segments primarily as a result of higher commodity prices and the addition of natural gas and crude oil marketing services provided for the Piceance/DJ Basins segment.

• a $3.9 million increase in gathering services and related fees for the Piceance/DJ Basins segment primarily as a result of ongoing drilling and completion activity.

• a $4.7 million decrease, net of the recognition for the above-mentioned previously deferred revenue and business interruption recoveries, in gathering services and related fees for the Williston Basin segment primarily due to decreased drilling activity and natural production declines.

• a $2.7 million decrease for the Barnett Shale segment primarily due to lower volume throughput on the DFW Midstream system.

Gathering Services and Related Fees.  The increase in gathering services and related fees compared to the first quarter of 2016 primarily reflected:

• the recognition of $37.7 million of previously deferred revenue related to a certain Williston Basin customer.

• the recognition of $2.6 million of business interruption recoveries for the Williston Basin segment.

• a $4.5 million increase for the Utica Shale segment due to the ongoing development of the Summit Utica system.

• a $3.9 million increase for the Piceance/DJ Basins segment primarily as a result of ongoing drilling and completion activity.

• a $4.7 million decrease, net of the recognition for the above-mentioned previously deferred revenue and business interruption recoveries, for the Williston Basin segment primarily due to decreased drilling activity and natural production declines.

• a $4.0 million decrease for the Barnett Shale segment primarily due to lower volume throughput on the DFW Midstream system.

Natural Gas, NGLs and Condensate Sales.  The increase in natural gas, NGLs and condensate sales primarily reflected the impact on pricing and throughput of higher commodity prices on our Williston Basin and Piceance/DJ Basins segments and the addition of natural gas and crude oil marketing services provided for the Piceance/DJ Basins segment.

Costs and Expenses.  Total costs and expenses increased $1.9 million, or 3%, compared to the first quarter of 2016 primarily reflecting:

• a $2.8 million increase in cost of natural gas and NGLs primarily for the Williston Basin and Piceance/DJ Basins segments primarily due to the impact of increasing commodity prices on their percent-of-proceeds and condensate sales activity.

• a $1.3 million increase in general and administrative expenses reflecting an increase in salaries and benefits.

• a $2.2 million decrease in operation and maintenance expenses primarily due to costs associated with repairs to rights-of-way in the Marcellus Shale segment and certain environmental remediation expenses in the Williston Basin segment recognized in 2016.

Cost of Natural Gas and NGLs.The increase in cost of natural gas and NGLs compared to the first quarter of 2016 largely reflected the impact on pricing and throughput of higher comparative commodity prices on our Williston Basin and Piceance/DJ Basins segments and the associated impact on (i) our percent-of-proceeds arrangements for the Bison Midstream system and (ii) our percent-of-proceeds arrangements and condensate sales for the Grand River system.

Operation and Maintenance. Operation and maintenance expense decreased compared to the first quarter of 2016 primarily reflecting a decrease for the Marcellus Shale segment for expenses associated with repairs to rights-of-ways and certain environmental remediation expenses in the Williston Basin segment recognized in 2016.

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EXHIBIT 99.2

General and Administrative.General and administrative expense increased compared to the first quarter of 2016 primarily reflecting an increase in salaries and benefits.

Depreciation and Amortization. The increase in depreciation and amortization expense compared to the first quarter of 2016 was largely driven by an increase in assets placed into service in the Summit Utica system.

Transaction Costs. Transaction costs recognized during the first quarter of 2016 primarily relate to financial and legal advisory costs associated with the 2016 Drop Down.

Interest Expense.The increase in interest expense compared to the first quarter of 2016 was primarily driven by the interest associated with issuance of the $500.0 million principal 5.75% Senior Notes offset by a decrease resulting from the tender and redemption of the $300.0 million principal 7.5% Senior Notes.

Early Extinguishment of Debt.The early extinguishment of debt recognized during the three months ended March 31, 2017 was driven by the tender and redemption of the $300.0 million principal 7.5% Senior Notes.

Deferred Purchase Price Obligation Expense.Deferred Purchase Price Obligation expense recognized during the three months ended March 31, 2017 represents the change in present value to Remaining Consideration in connection with the 2016 Drop Down (see Notes 16 to the unaudited condensed consolidated financial statements).

For additional information, see the "Segment Overview of the Three Months Ended March 31, 2017 and 2016" and "Corporate and Other Overview of the Three Months Ended March 31, 2017 and 2016" sections herein.

Segment Overview of the Three Months Ended March 31, 2017 and 2016

Utica Shale. The Utica Shale reportable segment includes the Summit Utica system, which was acquired from a subsidiary of Summit Investments in March 2016.

Volume throughput for our Summit Utica system follows.

	Utica Shale
	Three months ended March 31,		Percentage Change
	2017	2016	2017 v. 2016
Average daily throughput (MMcf/d)	275	132	108	%

Volume throughput on the Summit Utica system increased compared to the first quarter of 2016 due to our continued buildout of the Summit Utica system and completion of new wells during the second half of 2016.

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EXHIBIT 99.2

Financial data for our Utica Shale reportable segment follows.

	Utica Shale
	Three months ended March 31,				Percentage Change
	2017		2016		2017 v. 2016
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	8,796	$	4,283	105	%
Total revenues	8,796		4,283		105	%
Costs and expenses:
Operation and maintenance	763		525		45	%
General and administrative	121		569		(79	)%
Depreciation and amortization	1,647		844		95	%
Long-lived asset impairment	284		—		*
Total costs and expenses	2,815		1,938		45	%
Add:
Depreciation and amortization	1,647		844
Long-lived asset impairment	284		—
Segment adjusted EBITDA	$	7,912	$	3,189	148	%

__________

* Not considered meaningful

Three months ended March 31, 2017. Segment adjusted EBITDA increased$4.7 millioncompared to the first quarter of 2016 primarily reflecting an increase in gathering services and related fees primarily due to the growth and ongoing development of the Summit Utica system.

Depreciation and amortization increased compared to the first quarter of 2016 as a result of placing assets into service in the Summit Utica system.

Ohio Gathering. The Ohio Gathering reportable segment includes Ohio Gathering which was acquired from a subsidiary of Summit Investments in March 2016.

Gross volume throughput for Ohio Gathering, based on a one-month lag follows.

	Ohio Gathering
	Three months ended March 31,		Percentage Change
	2017	2016	2017 v. 2016
Average daily throughput (MMcf/d)	769	870	(12	)%

Volume throughput for the Ohio Gathering system, which is based on a one-month lag, decreased compared to the first quarter of 2016 primarily as a result of decreased drilling activity and natural production declines.

Financial data for our Ohio Gathering reportable segment, based on a one-month lag follows.

	Ohio Gathering
	Three months ended March 31,				Percentage Change
	2017		2016		2017 v. 2016
	(Dollars in thousands)
Proportional adjusted EBITDA for equity method investees	$	9,073	$	12,388	(27)	%
Segment adjusted EBITDA	$	9,073	$	12,388	(27)	%

Three months ended March 31, 2017. Segment adjusted EBITDA decreased$3.3 millioncompared to the first quarter of 2016 primarily reflecting a decrease in our proportional share of Ohio Gathering's adjusted EBITDA primarily due to decreased drilling activity and natural production declines.

Williston Basin. The Bison Midstream, Polar and Divide and Tioga Midstream systems provide our midstream services for the Williston Basin reportable segment. Polar and Divide was acquired from subsidiaries of Summit Investments in May 2015, with additional assets that currently comprise a portion of the Polar and Divide system, subsequently acquired from Summit Investments in March 2016. Tioga Midstream was acquired from a subsidiary of Summit Investments in March 2016.

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EXHIBIT 99.2

Volume throughput for our Williston Basin reportable segment follows.

	Williston Basin
	Three months ended March 31,		Percentage Change
	2017	2016	2017 v. 2016
Aggregate average daily throughput – natural gas (MMcf/d)	17	25	(32	)%
Aggregate average daily throughput – liquids (Mbbl/d)	76.4	95.0	(20	)%

Natural gas. Natural gas volume throughput decreased compared to the first quarter of 2016 largely reflecting natural declines and decreased drilling activity. Volume throughput was also impacted by the severe winter weather in North Dakota starting the fourth quarter of 2016 which continued through most of the first quarter of 2017.

Liquids. The decrease in liquids volume throughput compared to the first quarter of 2016 largely reflected natural declines and decreased drilling activity. Volume throughput was also impacted by the severe winter weather in North Dakota starting the fourth quarter of 2016 which continued through most of the first quarter of 2017.

Financial data for our Williston Basin reportable segment follows.

	Williston Basin
	Three months ended March 31,					Percentage Change
	2017			2016		2017 v. 2016
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	57,985		$	22,415	159	%
Natural gas, NGLs and condensate sales	6,158			4,276		44	%
Other revenues	2,742			3,317		(17	)%
Total revenues	66,885			30,008		123	%
Costs and expenses:
Cost of natural gas and NGLs	6,362			4,626		38	%
Operation and maintenance	6,463			8,210		(21	)%
General and administrative	540			989		(45	)%
Depreciation and amortization	8,381			8,357		—	%
Loss on asset sales, net	3			—		*
Total costs and expenses	21,749			22,182		(2	)%
Add:
Depreciation and amortization	8,381			8,357
Adjustments related to MVC shortfall payments	(35,711		)	3,536
Loss on asset sales, net	3			—
Segment adjusted EBITDA	$	17,809		$	19,719	(10	)%

__________

* Not considered meaningful

Three months ended March 31, 2017. Segment adjusted EBITDA decreased$1.9 millioncompared to the first quarter of 2016 primarily reflecting:

• a $4.7 million decrease, after taking into account the recognition of $37.7 million of previously deferred revenue and $2.6 million of business interruption recoveries, in gathering services and related fees primarily due to natural production declines and a lower rate redetermination for a certain Williston Basin customer.

• a $1.7 million decrease in operation and maintenance expenses primarily due to costs associated with certain environmental remediation expenses recognized in 2016.

Other items to note:

• The recognition of $37.7 million of previously deferred revenue related to a certain Williston Basin customer.

• The adjustments for MVC shortfall payments is primarily driven by the recognition of $37.7 million of gathering services and related fees revenue that had been previously deferred in connection with an MVC arrangement with a certain Williston Basin customer, for which we determined we had no further performance obligations. As a result, the increase in gathering services and related fees compared with the first quarter 2016 was offset by the change in adjustments related

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EXHIBIT 99.2

to MVC shortfall payments, with no impact on segment adjusted EBITDA (see Note 8 to the consolidated financial statements).

Piceance/DJ Basins.The Grand River system provides midstream services for the Piceance/DJ Basins reportable segment. The Red Rock Gathering system was acquired from a subsidiary of Summit Investments in March 2014. Niobrara G&P was acquired from a subsidiary of Summit Investments in March 2016. Our results include activityfor the Grand River, Red Rock Gathering and Niobrara G&P systems for all periods presented.

Volume throughput for our Piceance/DJ Basins reportable segment follows.

	Piceance/DJ Basins
	Three months ended March 31,		Percentage Change
	2017	2016	2017 v. 2016
Aggregate average daily throughput (MMcf/d)	615	572	8	%

Volume throughput increased compared to the first quarter of 2016 primarily as a result of ongoing drilling and completion activity across our gathering footprint.

Financial data for our Piceance/DJ Basins reportable segment follows.

	Piceance/DJ Basins
	Three months ended  March 31,					Percentage Change
	2017		2016			2017 v. 2016
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	29,274	$	25,392		15	%
Natural gas, NGLs and condensate sales	3,757		2,203			71	%
Other revenues	1,777		1,398			27	%
Total revenues	34,808		28,993			20	%
Costs and expenses:
Cost of natural gas and NGLs	2,183		1,664			31	%
Operation and maintenance	8,779		8,597			2	%
General and administrative	625		1,432			(56	)%
Depreciation and amortization	12,211		12,273			(1	)%
Gain on asset sales, net	—		(63		)	*
Total costs and expenses	23,798		23,903			—	%
Add:
Depreciation and amortization	12,211		12,273
Adjustments related to MVC shortfall payments	5,753		7,517
Gain on asset sales, net	—		(63		)
Segment adjusted EBITDA	$	28,974	$	24,817		17	%

__________

* Not considered meaningful

Three months ended March 31, 2017. Segment adjusted EBITDA increased$4.2 millionfrom the first quarter of 2016 primarily reflecting:

• a $2.1 million increase, after taking into account the adjustments related to MVC shortfall payments, in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity.

• a $1.6 million increase in natural gas, NGLs and condensate sales due to higher commodity prices and the addition of marketing services, offset by a $0.5 million increase in cost of natural gas and NGLs.

Barnett Shale. The DFW Midstream system provides our midstream services for the Barnett Shale reportable segment.

Volume throughput for our Barnett Shale reportable segment follows.

	Barnett Shale
	Three months ended March 31,		Percentage Change
	2017	2016	2017 v. 2016
Average daily throughput (MMcf/d)	286	341	(16	)%

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EXHIBIT 99.2

Volume throughput declined compared to the first quarter of 2016 reflecting reduced drilling and completion activity, in addition to natural production declines.

Financial data for our Barnett Shale reportable segment follows.

	Barnett Shale
	Three months ended March 31,				Percentage Change
	2017		2016		2017 v. 2016
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	15,124	$	19,125	(21	)%
Natural gas, NGLs and condensate sales	459		1,109		(59	)%
Other revenues	2,159		168		*
Total revenues	17,742		20,402		(13	)%
Costs and expenses:
Operation and maintenance	6,532		6,314		3	%
General and administrative	289		237		22	%
Depreciation and amortization	3,913		3,919		—	%
Total costs and expenses	10,734		10,470		3	%
Add:
Depreciation and amortization	3,762		4,056
Adjustments related to MVC shortfall payments	1,318		89
Segment adjusted EBITDA	$	12,088	$	14,077	(14	)%

__________

*Not considered meaningful

Three months ended March 31, 2017. Segment adjusted EBITDA decreased$2.0 millionfrom the first quarter of 2016 primarily reflecting:

• a $4.0 million decrease in gathering services and related fees largely as a result of reduced drilling activity and natural production declines.

• a $2.0 million increase in other revenues primarily due to electricity expense reimbursements that we began passing through to certain customers beginning in the fourth quarter of 2016.

Marcellus Shale. The Mountaineer Midstream system provides our midstream services for the Marcellus Shale reportable segment.

Volume throughput for the Marcellus Shale reportable segment follows.

	Marcellus Shale
	Three months ended March 31,		Percentage Change
	2017	2016	2017 v. 2016
Average daily throughput (MMcf/d)	434	453	(4	)%

Volume throughput declined compared to the first quarter of 2016 primarily due to natural production declines in addition to our customer's decision to continue to defer completion activities.

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EXHIBIT 99.2

Financial data for our Marcellus Shale reportable segment follows.

	Marcellus Shale
	Three months ended March 31,				Percentage Change
	2017		2016		2017 v. 2016
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	6,904	$	6,885	—	%
Total revenues	6,904		6,885		—	%
Costs and expenses:
Operation and maintenance	1,158		2,196		(47	)%
General and administrative	99		89		11	%
Depreciation and amortization	2,263		2,219		2	%
Total costs and expenses	3,520		4,504		(22	)%
Add:
Depreciation and amortization	2,263		2,219
Segment adjusted EBITDA	$	5,647	$	4,600	23	%

Three months ended March 31, 2017. Segment adjusted EBITDA increased$1.0 millionfrom the first quarter of 2016 primarily reflecting:

• a $1.0 million decrease in operation and maintenance primarily as a result of a decrease in expenses associated with repairs to rights-of-way in 2016.

Corporate and Other Overview of the Three Months ended March 31, 2017 and 2016

Corporate and other represents those results 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, natural gas and crude oil marketing services, transaction costs, interest expense, early extinguishment of debt and Deferred Purchase Price Obligation expense.Items to note follow.

	Corporate and Other
	Three months ended March 31,				Percentage Change
	2017		2016		2017 v. 2016
	(Dollars in thousands)
Costs and expenses:
General and administrative	$	12,458	$	9,563	30	%
Transaction costs	—		1,174		*
Interest expense (1)	16,716		15,882		5	%
Early extinguishment of debt (2)	22,020		—		*
Deferred Purchase Price Obligation expense	20,883		7,463		*

__________

* Not considered meaningful

(1) Includes interest expense on debt allocated to the 2016 Drop Down Assets during the common control period.

(2) Early extinguishment of debt includes $17.9 million paid for redemption and call premiums, as well as $4.1 million of unamortized debt issuance costs which were written off in connection with the repurchase of the outstanding $300.0 million 7.5% Senior Notes in the first quarter of 2017.

General and Administrative.General and administrative expense increased compared to the first quarter of 2016 primarily reflecting an increase in salaries and benefits.

Transaction Costs.Transaction costs recognized during the three months ended March 31, 2016 primarily relate to financial and legal advisory costs associated with the 2016 Drop Down.

Interest Expense.The increase in interest expense compared to the first quarter of 2016 was primarily driven by the interest associated with issuance of the $500.0 million principal 5.75% Senior Notes offset by a decrease resulting from the tender and redemption of the $300.0 million principal 7.5% Senior Notes.

Early Extinguishment of Debt.The early extinguishment of debt recognized during the three months ended March 31, 2017 was driven by the tender and redemption of the $300.0 million principal 7.5% Senior Notes.

Ex 99.2-11

EXHIBIT 99.2

Deferred Purchase Price Obligation Expense.Deferred Purchase Price Obligation expense recognized during the three months ended March 31, 2017 represents the change in present value to Remaining Consideration in connection with the 2016 Drop Down (see Notes 16 to the unaudited condensed consolidated financial statements).

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 flows generated from our operations, borrowings under our Revolving Credit Facility and future issuances of equity and debt instruments.

Capital Markets Activity

Capital markets activity during the three months ended March 31, 2017 follows.

November 2016 Shelf Registration Statement.In October 2016, we filed the 2016 SRS and in November 2016, the SEC declared it effective. The following transactions have been executed pursuant thereto:

• In January 2017, we completed a secondary public offering of 4,000,000 SMLP common units held by a subsidiary of Summit Investments in accordance with our obligations under our partnership agreement.  We did not receive any proceeds from this secondary offering.

• In February 2017, we executed a new equity distribution agreement and filed a prospectus and a prospectus supplement with the SEC for the issuance and sale from time to time of SMLP common units having an aggregate offering price of up to $150.0 million.  During the three months ended March 31, 2017, we issued 17,700 units under the ATM Program for aggregate gross proceeds of $0.4 million.  In March 2017, in accordance with the terms of our Partnership Agreement, our General Partner made a capital contribution to maintain its 2% general partner interest in SMLP.

Following the January 2017 secondary offering, we can issue up to $1.50 billion of debt and equity securities in primary offerings and a total of 32,701,230 common units held by (i) a subsidiary of Summit Investments and (ii) affiliates of our Sponsor pursuant to the 2016 SRS. The 2016 SRS expires in November 2019.

July 2014 Shelf Registration Statement.In July 2014, we filed the 2014 SRS with the SEC to issue an unlimited amount of debt and equity securities and shortly thereafter completed a public offering of $300.0 million aggregate principal 5.5% senior unsecured notes due 2022. We used the proceeds to repay a portion of the then-outstanding borrowings under our Revolving Credit Facility.

OnFebruary 8, 2017, we amended the 2014 SRS to include additional guarantor subsidiaries and completed a public offering of$500.0 millionprincipal 5.75% senior unsecured notes due 2025. Concurrent therewith, we made a tender offer to purchase all the outstanding 7.5% Senior Notes. The tender offer expired on February 14, 2017 with$276.9million validly tendered. OnFebruary 16, 2017, we issued a notice of redemption for the 7.5% Senior Notes that remained outstanding subsequent to the tender offer. The remaining 7.5% Senior Notes were redeemed on March 18, 2017, with payment made on March 20, 2017. We used the proceeds from the issuance of the 5.75% Senior Notes to (i) fund the repurchase of the outstanding$300.0million principal 7.5% Senior Notes, (ii) pay redemption and call premiums on the 7.5% Senior Notes totaling $17.9 million and (iii) pay$172.0 millionof the balance outstanding under our Revolving Credit Facility.

For additional information, see Notes 9 and 11 to the unaudited condensed consolidated financial statements.

Debt

Revolving Credit Facility. We have a $1.25 billion senior secured Revolving Credit Facility. As of March 31, 2017, the outstanding balance of the Revolving Credit Facility was $475.0 millionand the unused portion totaled $775.0 million. There were no defaults or events of default during the first quarter of 2017 and, as of March 31, 2017, we were in compliance with the covenants in the Revolving Credit Facility.

Senior Notes.  In February 2017, the Co-Issuers co-issued the 5.75% Senior Notes. There were no defaults or events of default during the first quarter of 2017 on any series of senior notes.

For additional information on our long-term debt, see Notes 9 and 17 to the unaudited condensed consolidated financial statements.

Deferred Purchase Price Obligation

In March 2016, we entered into an agreement with a subsidiary of Summit Investments to fund a portion of the 2016 Drop Down whereby we have recognized the Deferred Purchase Price Obligation (see Note 16 to the unaudited condensed consolidated financial statements).

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EXHIBIT 99.2

Cash Flows

Due to the common control aspect in a drop down transaction, we account for drop downs on an “as-if pooled” basis for the periods during which common control existed. As such, cash flows retrospectively reflect the cash flows associated with (i) the assets acquired from Summit Investments and (ii) the assets and liabilities allocated to the Partnership from Summit Investments.

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

	Three months ended March 31,
	2017			2016
	(In thousands)
Net cash provided by operating activities	$	62,449		$	66,849
Net cash used in investing activities	(19,725		)	(437,348		)
Net cash (used in) provided by financing activities	(43,867		)	361,793
Net change in cash and cash equivalents	$	(1,143	)	$	(8,706	)

Operating activities. Cash flows from operating activities for the three months ended March 31, 2017 primarily reflected:

• a $2.9 million decrease in distributions from Ohio Gathering; and

• a $2.9 million increase in cash interest payments.

Investing activities. Cash flows used in investing activities during the three months ended March 31, 2017 primarily reflected:

• $14.4 million of capital expenditures primarily attributable to the ongoing development of the Summit Utica system; and

• $4.9 million of capital contributions to Ohio Gathering.

Cash flows used in investing activities during the three months ended March 31, 2016 primarily reflected:

• $360.0 million consideration paid and recognized in connection with the 2016 Drop Down;

• $61.3 million of capital expenditures primarily attributable to the ongoing development of the Summit Utica system and Williston Basin segment; and

• $15.6 million of capital contributions to Ohio Gathering.

Financing activities. Cash flows used in financing activities during the three months ended March 31, 2017 primarily reflected:

• $300.0 million paid for the repurchase of the outstanding 7.5% Senior Notes;

• $17.9 million paid for the redemption and call premiums on the 7.5% Senior Notes;

• $173.0 million of net repayments under our Revolving Credit Facility;

• $44.5 million of distributions paid in the first quarter of 2017 (declared in respect of the fourth quarter of 2016); and

• $500.0 million of borrowings from the issuance of 5.75% Senior Notes.

Cash flows provided by financing activities during the three months ended March 31, 2016 primarily reflected:

• $389.0 million of net borrowings under our Revolving Credit Facility primarily to fund the 2016 Drop Down; and

• $41.0 million of distributions paid in the first quarter of 2016 (declared in respect of the fourth quarter of 2015).

Contractual Obligations Update

In March 2016, we borrowed an additional $360.0 million under our revolving credit facility and recognized a liability of $507.4 million for the Deferred Purchase Price Obligation, both in connection with the 2016 Drop Down.  The Deferred Purchase Price Obligation is due no later than December 31, 2020 and is currently expected to be $829.6 million based on information available as of March 31, 2017. There are no cash interest payments associated with the Deferred Purchase Price Obligation.

In February 2017, we issued $500.0 million principal of 5.75% senior, unsecured notes due 2025.  We used the proceeds from the issuance of the 5.75% Senior Notes to (i) fund the repurchase of the outstanding $300.0 million principal 7.5% Senior Notes, (ii) pay redemption and call premiums on the 7.5% Senior Notes totaling $17.9 million and (iii) pay $172.0 million of the balance outstanding under our Revolving Credit Facility.

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EXHIBIT 99.2

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, 2017, cash paid for capital expenditures totaled$14.4 million(see Note 3 to the unaudited condensed consolidated financial statements) which included$2.2 millionof maintenance capital expenditures. For the three months ended March 31, 2017, contributions to equity method investees totaled$4.9 million(see Note 7 to the unaudited condensed consolidated financial statements).

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 instruments.

We believe that our Revolving Credit Facility, together with financial support from our Sponsor and/or access to the debt and equity capital markets, will be adequate to finance our growth objectives for the foreseeable future without adversely impacting our liquidity or our ability to make quarterly cash distributions to our unitholders.

Distributions, Including IDRs

Based on the terms of our Partnership Agreement, we expect to distribute most of the cash generated by our operations to our unitholders. With respect to our payment of IDRs to the General Partner, we reached the second target distribution in connection with the distribution declared in respect of the fourth quarter of 2013. We reached the third target distribution in connection with the distribution declared in respect of the second quarter of 2014. For additional information, see Note 11 to the unaudited condensed consolidated financial statements.

Credit and Counterparty Concentration Risks

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.

Given the current environment, certain of our customers may be temporarily unable to meet their current obligations. While this may cause disruption to cash flows, we believe that we are properly positioned to deal with the potential disruption because the vast majority of our gathering assets are strategically positioned at the beginning of the midstream value chain. The majority of our infrastructure is connected directly to our customer’s wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customer’s commodities flow and, in many cases, the only way for our customers to get their production to market.

We estimate the quarterly impact of expected MVC shortfall payments for inclusion in our calculation of segment adjusted EBITDA. As such, we have exposure due to nonperformance under our MVC contracts whereby a customer, who was not meeting their MVCs, does not have the wherewithal to make its MVC shortfall payments when they become due. We typically receive payment for all prior-year MVC shortfall billings in the quarter immediately following billing. Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period

For additional information, see Notes 3, 8 and 10 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, 2017.

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. There have been no changes to our significant accounting policies since December 31, 2016.

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

Ex 99.2-14

EXHIBIT 99.2

accounting estimates involve the use of various assumptions developed from management's analyses and judgments. Subsequent experience or use of other methods, estimates or assumptions could produce significantly different results. There have been no changes in the accounting methodology for items that we have identified as critical accounting estimates and no updates or additions to critical accounting estimates during the three months ended March 31, 2017.

Forward-Looking Statements

Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officials during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us, Summit Investments or our Sponsor, are also forward-looking statements. These forward-looking statements involve various risks and uncertainties, including, but not limited to, those described in Item 1A. Risk Factors included 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, NGLs and crude oil prices;

• the extent and success of our customers' drilling efforts, as well as the quantity 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, crude oil and produced water 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 nonperformance 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 and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers;

• our ability to acquire assets owned by third parties, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets and our ability to obtain financing on acceptable terms;

• 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 terrain in certain areas in which we operate;

Ex 99.2-15

EXHIBIT 99.2

• any other issues that can result in deficiencies in the design, installation or operation of our gathering, treating and processing facilities;

• 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, safety 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 document may not in fact occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.

Ex 99.2-16