EXHIBIT 99.5

EXPLANATORY NOTE

On May 28, 2020, Summit Midstream Partners, LP, a Delaware limited partnership (the “Partnership”), closed on a Purchase Agreement (the “Purchase Agreement”) with affiliates of Energy Capital Partners II, LLC, a Delaware limited liability company (“ECP”) to acquire all the outstanding limited liability company interests of Summit Midstream Partners, LLC, a Delaware limited liability company (“Summit Investments”). We refer to the transactions contemplated by the Purchase Agreement as the “GP Buy-In Transaction.”

The May 2020 acquisition of Summit Investments was a transaction between entities under common control. As a result, the Partnership recast its financial statements for the period that the entities were under common control by Summit Investments to retrospectively reflect the May 2020 acquisition. Under GAAP, the GP Buy-In Transaction was deemed a transaction among entities under common control with a change in reporting entity. Although the Partnership is the surviving entity for legal purposes, Summit Investments is the surviving entity for accounting purposes; therefore, the historical financial results of the Partnership prior to the GP Buy-In Transaction presented below are those of Summit Investments. Prior to the GP Buy-In Transaction, Summit Investments controlled the Partnership and the Partnership’s financial statements were consolidated into Summit Investments.

The information in this Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations includes periods prior to the GP Buy-In Transaction. Consequently, the Partnership’s consolidated financial statements and this Item 2 have been retrospectively recast for all periods presented in order to present the financial results of the surviving entity for accounting purposes.

EX 99.5-1

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 periods since December 31, 2019. As a result, the following discussion should be read in conjunction with Item 1, “Financial Statements” and Item 8, “Financial Statements and Supplementary Data” of this Current Report on Form 8-K. 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 value-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in unconventional resource basins, primarily shale formations, in the continental United States.

We classify our midstream energy infrastructure assets into two categories:

• Core Focus Areas – core producing areas of basins in which we expect our gathering systems to experience greater long-term growth, driven by our customers’ ability to generate more favorable returns and support sustained drilling and completion activity in varying commodity price environments. In the near-term, we expect to concentrate the majority of our capital expenditures in our Core Focus Areas. Our Utica Shale, Ohio Gathering, Williston Basin, DJ Basin and Permian Basin reportable segments (as described below) comprise our Core Focus Areas.

• Legacy Areas – production basins in which we expect volume throughput on our gathering systems to experience relatively lower long-term growth compared to our Core Focus Areas, given that our customers require relatively higher commodity prices to support drilling and completion activities in these basins. Upstream production served by our gathering systems in our Legacy Areas is generally more mature, as compared to our Core Focus Areas, and the decline rates for volume throughput on our gathering systems in the Legacy Areas are typically lower as a result. We expect to continue to reduce our near-term capital expenditures in these Legacy Areas. Our Piceance Basin, Barnett Shale and Marcellus Shale reportable segments (as described below) comprise our Legacy Areas.

EX 99.5-2

We are the owner-operator of or have significant ownership interests in the following gathering and transportation systems, which comprise our Core Focus Areas:

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

• 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;

• Polar and Divide, a crude oil and produced water gathering system and transmission pipeline operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

• 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;

• 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 and southeastern Wyoming;

• Summit Permian, an associated natural gas gathering and processing system operating in the northern Delaware Basin, which includes the Wolfcamp and Bone Spring formations, in southeastern New Mexico; and

• Double E, a 1.35 Bcf/d natural gas transmission pipeline that is under development and will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas.

We are the owner-operator of the following gathering systems, which comprise our Legacy Areas:

• Grand River, 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;

• 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 4 to the unaudited condensed consolidated financial statements.

Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn revenues from the following activities that directly expose us to fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers on the Bison Midstream, Grand River and Summit Permian 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. During the three months ended March 31, 2020, these additional activities accounted for approximately 13% of total revenues.

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, if any, ensure that we will earn a minimum amount of revenue.

EX 99.5-3

The following table presents certain consolidated and reportable segment financial data. For additional information on our reportable segments, see the “Segment Overview for the Three Months Ended March 31, 2020 and 2019” section herein.

	Three months ended March 31,
	2020			2019
	(In thousands)
Net income (loss)	$	3,762		$	(40,280	)
Reportable segment adjusted EBITDA
Utica Shale	$	5,928		$	6,193
Ohio Gathering		7,939			9,210
Williston Basin		16,192			18,734
DJ Basin		5,911			2,673
Permian Basin		1,581			(550	)
Piceance Basin		23,557			25,999
Barnett Shale		8,760			11,374
Marcellus Shale		5,320			5,142
Net cash provided by operating activities	$	70,201		$	45,193
Capital expenditures (1)		18,583			60,848
Investment in equity method investee		58,033			—
Net cash distributions to noncontrolling interest SMLP unitholders	$	6,037		$	27,374
Net borrowings (repayments) under Revolving Credit Facility		21,000			(32,000	)
Repayments under SMP Holdings term loan		(750	)		(12,250	)
Proceeds from issuance of Subsidiary Series A preferred units, net of costs (2)		33,946			—

Segment Overview for the Three Months Ended March 31, 2020 and 2019” section herein.

(1) See “Liquidity and Capital Resources” herein and Note 4 to the unaudited condensed consolidated financial statements for additional information on capital expenditures.

(2) Reflects proceeds from the issuance of Subsidiary Series A Preferred Units.

Three months ended March 31, 2020. The following items are reflected in our financial results:

• In March 2020, in connection with the cancellation of a compressor station project in the DJ Basin due to delays in customer drilling plans, we recorded an impairment charge of $3.6 million for the related soft project costs.

Three months ended March 31, 2019. The following items are reflected in our financial results:    

• In March 2019, we sold the Tioga Midstream system to affiliates of Hess Infrastructure Partners LP for a combined cash purchase price of approximately $90 million and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the carrying value for Tioga Midstream at closing. The gain is included in the Gain on asset sales, net caption on the unaudited condensed consolidated statement of operations. The financial results of Tioga Midstream (a component of the Williston Basin reportable segment) are included in our unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through March 22, 2019.

• In March 2019, certain events occurred which indicated that certain long-lived assets in the DJ Basin and Barnett Shale reporting segments could be impaired. Consequently, we performed a recoverability assessment of certain assets within these reporting segments. In the DJ Basin, we determined certain processing plant assets related to our existing 20 MMcf/d plant would no longer be operational due to our expansion plans for the Niobrara G&P system and we recorded an impairment charge of $34.7 million related to these assets. In the Barnett Shale, we determined certain compressor station assets would be shut down and de-commissioned beginning in the second quarter of 2019 and we recorded an impairment charge of $10.2 million related to these assets.

EX 99.5-4

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;

• Production from U.S. shale plays;

• Capital markets availability and cost of capital;

• Shifts in operating costs and inflation; and

• Ongoing impact of the COVID-19 pandemic and reduced demand and prices for oil.

We are closely monitoring the impact of the outbreak of COVID-19 on all aspects of our business, including how it will impact our customers, employees, supply chain and distribution network. While COVID-19 did not have a material adverse effect on our reported results for the first quarter of 2020, only one month of the quarter was affected by COVID-19 and if the current conditions continue, subsequent quarters may reflect these conditions for a full quarter. We are unable to predict the ultimate impact that COVID-19 and related factors may have on our business, future results of operations, financial position or cash flows. The extent to which our operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including new information which may emerge concerning the severity of the outbreak and actions by government authorities to contain the outbreak or treat its impact. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.

In response to the COVID-19 pandemic, we have modified our business practices, including restricting employee travel, modifying employee work locations, implementing social distancing and enhanced sanitary measures in our facilities. Many of our suppliers, vendors and service providers have made similar modifications. The resources available to employees working remotely may not enable them to maintain the same level of productivity and efficiency, and these and other employees may face additional demands on their time. Our increased reliance on remote access to our information systems increases our exposure to potential cybersecurity breaches. We may take further actions as government authorities require or recommend or as we determine to be in the best interests of our employees, customers, partners and suppliers. There is no certainty that such measures will be sufficient to mitigate the risks posed by the virus, in which case our employees may become sick, our ability to perform critical functions could be harmed, and we may be unable to respond to the needs of our business. The resumption of normal business operations after such interruptions may be delayed or constrained by lingering effects of COVID-19 on our suppliers, third-party service providers, and/or customers.

In addition, the COVID-19 pandemic has significantly reduced the global demand for oil and natural gas. This significant decline in demand has been met with a sharp decline in oil prices following the announcement of price reductions and production increases in March 2020 by members of the Organization of Petroleum Exporting Countries, or OPEC, and other foreign, oil-exporting countries. The resulting supply and demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. Although OPEC agreed in April to cut production, the responses of oil and gas producers to the lower demand for, and price of, natural gas, NGLs and crude oil are constantly evolving and remain uncertain. Such responses could cause our pipelines and storage tanks and other third-party storage facilities to reach capacity, thereby forcing producers to experience shut-ins or look to alternative methods of transportation for their products.

Over the past several weeks we have collaborated extensively with our customer base regarding reductions and delays to drilling and completion activities in light of the current commodity price backdrop and COVID-19 pandemic. Given further deterioration of market conditions in March and April and based on recently updated production forecasts and revised 2020 development plans from our customers, we currently expect our 2020 results to be affected by decreased drilling activity and the deferral of well completions from customers and, on a limited scale, temporary production curtailments predominantly in the Williston Basin and DJ Basin reportable segments. Accordingly, we now expect 2020 total capital expenditures to range from of $30 million to $50 million.

EX 99.5-5

The full extent to which our operations may be impacted by the COVID-19 pandemic and reduced demand and pricing for oil will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including new information which may emerge concerning the severity of the outbreak and actions by government authorities to contain the outbreak or treat its impact. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.

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 2019 Annual Report in addition to the exhibits contained within this Form 8-K.

How We Evaluate Our Operations

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

• 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 Polar and Divide and Bison Midstream;

• the DJ Basin, which is served by Niobrara G&P;

• the Permian Basin, which is served by Summit Permian;

• the Piceance Basin, which is served by Grand River;

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

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

Additionally, until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Refer to Note 16 to the unaudited condensed consolidated financial statements for details on the sale of Tioga 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 4 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, 2020.

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 2019 Annual Report in addition to the exhibits contained within this Form 8-K. 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.

EX 99.5-6

Results of Operations

Consolidated Overview for the Three Months Ended March 31, 2020 and 2019

The following table presents certain consolidated and operating data.

	Three months ended March 31,
	2020			2019
	(In thousands)
Revenues:
Gathering services and related fees	$	83,792		$	86,964
Natural gas, NGLs and condensate sales		13,780			37,928
Other revenues		7,331			6,516
Total revenues		104,903			131,408
Costs and expenses:
Cost of natural gas and NGLs		8,225			31,759
Operation and maintenance		21,811			24,222
General and administrative		16,561			18,385
Depreciation and amortization		29,666			27,764
Transaction costs		11			2,337
Loss (gain) on asset sales, net		115			(961	)
Long-lived asset impairment		3,821			44,951
Total costs and expenses		80,210			148,457
Other (expense) income		(427	)		209
Interest expense		(23,828	)		(22,742	)
Income (loss) before income taxes and income (loss) loss from equity method investees		438			(39,582	)
Income tax benefit (expense)		13			(257	)
Income (loss) from equity method investees		3,311			(441	)
Net income (loss)	$	3,762		$	(40,280	)
Volume throughput (1):
Aggregate average daily throughput – natural gas (MMcf/d)		1,281			1,462
Aggregate average daily throughput – liquids (Mbbl/d)		98			103

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

Volumes – Gas. Natural gas throughput volumes decreased 181 MMcf/d for the three months ended March 31, 2020 compared to the three months ended March 31, 2019, primarily reflecting:

• a volume throughput decrease of 102 MMcf/d for the Piceance Basin segment.

• a volume throughput decrease of 64 MMcf/d for the Utica Shale segment.

• a volume throughput decrease of 27 MMcf/d for the Barnett Shale segment.

• a volume throughput decrease of 15 MMcf/d for the Marcellus Shale segment.

• a volume throughput increase of 18 MMcf/d for the Permian Basin segment.

• a volume throughput increase of 11 MMcf/d for the DJ Basin segment.

Volumes – Liquids. Crude oil and produced water throughput volumes at the Williston segment decreased 5 Mbbl/d for the three months ended March 31, 2020 compared to the three months ended March 31, 2019.

For additional information on volumes, see the “Segment Overview for the Three Months Ended March 31, 2020 and 2019” section herein.

EX 99.5-7

Revenues. Total revenues decreased $26.5 million during the three months ended March 31, 2020 compared to the prior year period primarily comprised of a $24.1 million decrease in natural gas, NGLs and condensate sales and a $3.2 million decrease in gathering services and related fees.

Gathering Services and Related Fees. Gathering services and related fees decreased $3.2 million compared to the three months ended March 31, 2019, primarily reflecting:

• a $2.6 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting natural production declines partially offset by new volumes from well completion activity through the third quarter of 2019. Also impacting 2020 revenues was the presentation of $1.5 million of gathering services as a reduction to cost of natural gas and NGLs due to the assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream operations that occurred in June 2019.

• a $4.7 million decrease in gathering services and related fees in the Piceance Basin relating to lower volume throughput due to a lack of drilling and completion activity and natural production declines in addition to the sale of certain assets from our Red Rock Gathering system in December 2019.

• a $0.5 million decrease in gathering services and related fees in the Utica Shale as a result of natural production declines on existing wells partially offset by the completion of new wells throughout 2019 and in the first quarter of 2020, and a more favorable volume and gathering rate mix from customers.

• a $1.9 million decrease in gathering services and related fees in the Williston Basin primarily reflecting a $1.5 million decrease in gathering services and related fees attributable to natural production declines and the sale of the Tioga Midstream system on March 22, 2019, whose 2019 financial results are included for the period from January 1, 2019 through March 22, 2019.

• a $3.1 million increase in gathering services and related fees in the DJ Basin relating to higher volume throughput due to increased drilling activity and a more favorable volume and gathering rate mix from customers, partially offset by natural production declines.

• a $1.9 million increase in gathering services and related fees in the Permian Basin due to higher volume growth from ongoing drilling and completion activity.

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales decreased $24.1 million compared to the three months ended March 31, 2019, primarily reflecting lower natural gas, NGL and crude oil marketing services. The majority of the decrease in revenue is offset by a $23.5 million decrease in natural gas, NGL and condensate purchases.

Costs and Expenses. Total costs and expenses decreased $68.2 million during the three months ended March 31, 2020 compared to the three months ended March 31, 2019, primarily reflecting:

• the impact of the March 2019 recognition of $34.9 million of certain long-lived asset impairments in the DJ Basin.

• a $23.5 million decrease in natural gas, NGLs and condensate purchases primarily driven by lower natural gas, NGL and crude oil marketing activity.

• the impact of the March 2019 recognition of $10.2 million of certain long-lived asset impairments in the Barnett Shale.

• the recognition in March 2020 of $3.6 million of certain long-lived asset impairments in the DJ Basin.

• a $2.4 million decrease in operation and maintenance expense primarily due to a $1.4 million decrease in salaries and benefits costs and a $0.9 million decrease in property taxes.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs decreased $23.5 million during the three months ended March 31, 2020 compared to the three months ended March 31, 2019, primarily driven by lower natural gas, NGL and crude oil marketing activity.

EX 99.5-8

Operation and Maintenance. Operation and maintenance expense decreased $2.4 million for the three months ended March 31, 2020 compared to the three months ended March 31, 2019 primarily due to a $1.3 million decrease in salaries and benefits costs and a $0.9 million decrease in property taxes.

General and Administrative. General and administrative expense decreased $1.8 million for the three months ended March 31, 2020 compared to the three months ended March 31, 2019 primarily due to lower headcount associated with our cost cutting initiatives and lower performance-based compensation.

Depreciation and Amortization. The increase in depreciation and amortization expense during the three months ended March 31, 2020 compared to the three months ended March 31, 2019 was primarily due to the acceleration of depreciation on certain Williston Basin assets.

Transaction Costs. The decrease in transaction costs recognized during the three months ended March 31, 2020 compared to the three months ended March 31, 2019 was due to the financial advisory costs associated primarily with restructuring the equity structure of certain subsidiaries in 2019.

Interest Expense. The increase in interest expense for the three months ended March 31, 2020 compared to the three months ended March 31, 2019, was primarily due to a higher average outstanding balance on the Revolving Credit Facility. The increase was partially offset by a lower outstanding balance on the Term Loan B.

For additional information, see the “Segment Overview for the Three Months Ended March 31, 2020 and 2019” and “Corporate and Other Overview for the Three Months Ended March 31, 2020 and 2019” sections herein.

Segment Overview for the Three Months Ended March 31, 2020 and 2019

Utica Shale. The Utica Shale reportable segment includes the Summit Utica system. Volume throughput for our Summit Utica system follows.

	Utica Shale
	Three months ended March 31,
	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		222		286		(22	%)

Volume throughput declined compared to the three months ended March 31, 2019 as a result of natural production declines from existing wells partially offset by the completion of new wells throughout 2019 and in the first quarter of 2020, and a more favorable volume and gathering rate mix from customers.

Financial data for our Utica Shale reportable segment follows.

	Utica Shale
	Three months ended March 31,
	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	6,962		$	7,495			(7	%)
Total revenues		6,962			7,495			(7	%)
Costs and expenses:
Operation and maintenance		941			1,216			(23	%)
General and administrative		88			81			9	%
Depreciation and amortization		1,927			1,908			1	%
Loss on asset sales, net		16			—				*
Total costs and expenses		2,972			3,205			(7	%)
Add:
Depreciation and amortization		1,927			1,908
Adjustments related to capital reimbursement activity		(5	)		(5	)
Loss on asset sales, net		16			—
Segment adjusted EBITDA	$	5,928		$	6,193			(4	%)

EX 99.5-9

* Not considered meaningful

Three months ended March 31, 2020. Segment adjusted EBITDA decreased $0.3 million compared to the three months ended March 31, 2019.

Ohio Gathering. The Ohio Gathering reportable segment includes OGC and OCC. We account for our investment in Ohio Gathering using the equity method. We recognize our proportionate share of earnings or loss in net income on a one-month lag based on the financial information available to us during the reporting period.

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

	Ohio Gathering
	Three months ended March 31,
	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		610		711		(14	%)

Volume throughput for the Ohio Gathering system in 2020 decreased compared to the year ended December 31, 2019 as a result of natural production declines on existing wells on the system partially offset by the completion of new wells throughout 2019.

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

	Ohio Gathering
	Three months ended March 31,
	2020		2019		Percentage Change
	(Dollars in thousands)
Proportional adjusted EBITDA for equity method investees	$	7,939	$	9,210		(14	%)
Segment adjusted EBITDA	$	7,939	$	9,210		(14	%)

Segment adjusted EBITDA for equity method investees decreased $1.3 million compared to the three months ended March 31, 2019 primarily as a result of the lower volume throughput described above.

Williston Basin. The Polar and Divide, Bison Midstream and Tioga Midstream (through March 22, 2019; refer to Note 16 to the unaudited condensed consolidated financial statements for details on the sale of Tioga Midstream) systems provide our midstream services for the Williston Basin reportable segment. Volume throughput for our Williston Basin reportable segment follows.

	Williston Basin
	Three months ended March 31,
	2020		2019		Percentage Change
Aggregate average daily throughput – natural gas (MMcf/d)		14		16		(13	%)
Aggregate average daily throughput – liquids (Mbbl/d)		98		103		(5	%)

Natural gas. Natural gas volume throughput decreased compared to the three months ended March 31, 2019, primarily reflecting natural production declines and the sale of Tioga Midstream partially offset by the completion of new wells behind the Bison Midstream system in 2019 and 2020.

Liquids. The decrease in liquids volume throughput compared to the three months ended March 31, 2019, primarily reflected natural production declines and the sale of Tioga Midstream partially offset by the completion of new wells throughout 2019.

EX 99.5-10

Financial data for our Williston Basin reportable segment follows.

	Williston Basin
	Three months ended March 31,
	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	23,797		$	25,706			(7	%)
Natural gas, NGLs and condensate sales		4,324			5,585			(23	%)
Other revenues		3,142			2,908			8	%
Total revenues		31,263			34,199			(9	%)
Costs and expenses:
Cost of natural gas and NGLs		1,663			2,709			(39	%)
Operation and maintenance		6,722			6,516			3	%
General and administrative		538			341			58	%
Depreciation and amortization		6,495			5,436			19	%
Loss (gain) on asset sales, net		49			(968	)			*
Long-lived asset impairment		—			10				*
Total costs and expenses		15,467			14,044			10	%
Add:
Depreciation and amortization		6,495			5,436
Adjustments related to MVC shortfall payments		(5,665	)		(5,549	)
Adjustments related to capital reimbursement activity		(483	)		(350	)
Loss (gain) on asset sales, net		49			(968	)
Long-lived asset impairment		—			10
Segment adjusted EBITDA	$	16,192		$	18,734			(14	%)

* Not considered meaningful

Three months ended March 31, 2020. Segment adjusted EBITDA decreased $2.5 million compared to the three months ended March 31, 2019 primarily reflecting:

• a decrease of $0.9 million of segment adjusted EBITDA contributed by the Tioga Midstream system compared to the three months ended March 31, 2019 due to the sale of Tioga Midstream on March 22, 2019. We also experienced lower natural gas volume throughput and lower liquids volume throughput on our systems.

Other items to note:

• On March 22, 2019, we sold the Tioga Midstream system and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the then carrying value for Tioga Midstream at closing. The financial results of Tioga Midstream are included in our unaudited condensed consolidated financial statements for the period from January 1, 2019 through March 22, 2019.

DJ Basin. The Niobrara G&P systems provide midstream services for the DJ Basin reportable segment. Volume throughput for our DJ Basin reportable segment follows.

	DJ Basin
	Three months ended March 31,
	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		32		21		52	%

Volume throughput increased compared to the three months ended March 31, 2019, primarily as a result of ongoing drilling and completion activity across our service area partially offset by natural production declines.

EX 99.5-11

Financial data for our DJ Basin reportable segment follows.

	DJ Basin
	Three months ended March 31,
	2020		2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	6,855	$	3,724			84	%
Natural gas, NGLs and condensate sales		70		85			(18	%)
Other revenues		1,034		1,007			3	%
Total revenues		7,959		4,816			65	%
Costs and expenses:
Cost of natural gas and NGLs		9		10				*
Operation and maintenance		2,516		1,849			36	%
General and administrative		82		72			14	%
Depreciation and amortization		1,527		799			91	%
Long-lived asset impairment		3,635		34,721				*
Total costs and expenses		7,769		37,451			(79	%)
Add:
Depreciation and amortization		1,527		799
Adjustments related to capital reimbursement activity		559		(212	)
Long-lived asset impairment		3,635		34,721
Segment adjusted EBITDA	$	5,911	$	2,673			121	%

* Not considered meaningful

Three months ended March 31, 2020. Segment adjusted EBITDA increased $3.2 million compared to the three months ended March 31, 2019, primarily reflecting:

• a $3.1 million increase in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity, a more favorable volume and gathering rate mix from customers, and the commissioning of our new natural gas processing plant in June 2019. This was partially offset by natural production declines.

Other items to note:

• During the quarter ended March 31, 2019, we impaired certain long-lived assets in the DJ Basin (see Note 5 to the unaudited condensed consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the three months ended March 31, 2020.

Permian Basin. The Summit Permian system provides our midstream services for the Permian Basin reportable segment. Volume throughput for our Permian Basin reportable segment follows.

	Permian Basin
	Three months ended March 31,
	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		33		15		120	%

Volume throughput increased compared to the three months ended March 31, 2019, primarily as a result of ongoing drilling and completion activity across our service area.

Financial data for our Permian Basin reportable segment follows.

EX 99.5-12

	Permian Basin
	Three months ended March 31,
	2020		2019			Percentage Change
	(In thousands)
Revenues:
Gathering services and related fees	$	2,311	$	366			531	%
Natural gas, NGLs and condensate sales		4,512		4,221			7	%
Other revenues		187		32			484	%
Total revenues		7,010		4,619			52	%
Costs and expenses:
Cost of natural gas and NGLs		4,149		4,245			(2	%)
Operation and maintenance		1,187		891			33	%
General and administrative		93		33			182	%
Depreciation and amortization		1,345		1,072			25	%
Loss on asset sales, net		4		—				*
Long-lived asset impairment		182		—				*
Total costs and expenses		6,960		6,241			12	%
Add:
Depreciation and amortization		1,345		1,072
Loss on asset sales, net		4		—
Long-lived asset impairment		182		—
Segment adjusted EBITDA	$	1,581	$	(550	)			*

* Not considered meaningful

Three months ended March 31, 2020. Segment adjusted EBITDA increased $2.1 million compared to the three months ended March 31, 2019, primarily reflecting a $1.9 million increase in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity.

Piceance Basin. The Grand River system provides midstream services for the Piceance Basin reportable segment. Volume throughput for our Piceance Basin reportable segment follows.

	Piceance Basin
	Three months ended March 31,
	2020		2019		Percentage Change
Aggregate average daily throughput (MMcf/d)		383		485		(21	%)

Volume throughput decreased compared to the three months ended March 31, 2019, as a result of a natural production declines.

EX 99.5-13

Financial data for our Piceance Basin reportable segment follows.

	Piceance Basin
	Three months ended March 31,
	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	27,189		$	31,840			(15	%)
Natural gas, NGLs and condensate sales		1,003			2,302			(56	%)
Other revenues		1,065			1,138			(6	%)
Total revenues		29,257			35,280			(17	%)
Costs and expenses:
Cost of natural gas and NGLs		457			1,473			(69	%)
Operation and maintenance		4,938			7,299			(32	%)
General and administrative		285			294			(3	%)
Depreciation and amortization		11,298			11,791			(4	%)
Gain on asset sales, net		(13	)		—				*
Total costs and expenses		16,965			20,857			(19	%)
Add:
Depreciation and amortization		11,298			11,791
Adjustments related to MVC shortfall payments		223			(103	)
Adjustments related to capital reimbursement activity		(243	)		(112	)
Gain on asset sales, net		(13	)		—
Segment adjusted EBITDA	$	23,557		$	25,999			(9	%)

* Not considered meaningful

Three months ended March 31, 2020. Segment adjusted EBITDA decreased $2.4 million compared to the three months ended March 31, 2019, primarily reflecting:

• a $4.7 million decrease in gathering services and related fees as a result of natural production declines.

• a $2.4 million decrease in operation and maintenance expense primarily due to $1.2 million in lower compensation expense and a $0.4 million decrease in property taxes.

Other items to note:

• In December 2019, we sold certain assets from our Red Rock Gathering system for $12 million. The financial contribution of these assets are included in our unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through December 1, 2019.

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,
	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		233		260		(10	%)

Volume throughput decreased compared to the three months ended March 31, 2019 reflecting natural production declines partially offset by new volumes from well completion activity through the third quarter of 2019.

Financial data for our Barnett Shale reportable segment follows.

EX 99.5-14

	Barnett Shale
	Three months ended March 31,
	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	10,443		$	13,025			(20	%)
Natural gas, NGLs and condensate sales		3,871			604			541	%
Other revenues (1)		1,260			1,656			(24	%)
Total revenues		15,574			15,285			2	%
Costs and expenses:
Cost of natural gas and NGLs		1,947			—				*
Operation and maintenance		4,695			5,498			(15	%)
General and administrative		378			228			66	%
Depreciation and amortization		3,797			3,941			(4	%)
Loss on asset sales, net		59			7				*
Long-lived asset impairment		4			10,220				*
Total costs and expenses		10,880			19,894			(45	%)
Add:
Depreciation and amortization		4,032			4,330
Adjustments related to MVC shortfall payments		—			1,453
Adjustments related to capital reimbursement activity		(29	)		(27	)
Loss on asset sales, net		59			7
Long-lived asset impairment		4			10,220
Segment adjusted EBITDA	$	8,760		$	11,374			(23	%)

* Not considered meaningful

(1) Includes the amortization expense associated with our favorable gas gathering contracts as reported in other revenues.

Three months ended March 31, 2020. Segment adjusted EBITDA decreased $2.6 million compared to the three months ended March 31, 2019 primarily reflecting:

• a $1.5 million decrease in adjustments related to MVC shortfall payments attributable to an MVC that expired in 2019 and a $1.7 million decrease in total revenues less cost of natural gas and NGLs which primarily reflects lower volume throughput.

Other items to note:

• In March 2019, we impaired certain long-lived assets in the Barnett Shale (see Note 5 to the unaudited condensed consolidated financial statements). The noncash impairment expense had no impact on segment adjusted EBITDA for the three months ended March 31, 2019.

• Also impacting total revenues and cost of natural gas and NGLs for the three months ended March 31, 2020, was the presentation of certain gathering services as a reduction to cost of natural gas and NGLs and the assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream operations that occurred in June 2019.

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,
	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		364		379		(4	%)

Volume throughput decreased compared to the three months ended March 31, 2019 primarily due to natural production declines partially offset by additional drilling and completion activities in the third quarter of 2019.

EX 99.5-15

Financial data for our Marcellus Shale reportable segment follows.

	Marcellus Shale
	Three months ended March 31,
	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	6,235		$	6,197			1	%
Total revenues		6,235			6,197			1	%
Costs and expenses:
Operation and maintenance		813			954			(15	%)
General and administrative		93			92			1	%
Depreciation and amortization		2,300			2,283			1	%
Total costs and expenses		3,206			3,329			(4	%)
Add:
Depreciation and amortization		2,300			2,283
Adjustments related to capital reimbursement activity		(9	)		(9	)
Segment adjusted EBITDA	$	5,320		$	5,142			3	%

* Not considered meaningful

Three months ended March 31, 2020. Segment adjusted EBITDA increased $0.2 million compared to the three months ended March 31, 2019.

Corporate and Other Overview for the Three Months Ended March 31, 2020 and 2019

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, construction management fees related to the Double E Project, transaction costs and interest expense.

	Corporate and Other
	Three months ended March 31,
	2020		2019		Percentage Change
	(Dollars in thousands)
Revenues:
Total revenues		643		23,517		(97	%)
Costs and expenses:
Cost of natural gas and NGLs		—		23,322			*
General and administrative		15,004		17,244		(13	%)
Transaction costs		11		2,337			*
Interest expense		23,828		22,742		5	%

* Not considered meaningful

Total Revenues. Total revenues attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services (primarily natural gas sales). The decrease of $22.9 million compared to the three months ended March 31, 2019 was attributable to lower natural gas, NGL and crude oil marketing activity.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services. The decrease of $23.3 million compared to the three months ended March 31, 2019 was attributable to lower marketing activity.

General and Administrative. General and administrative expense decreased $2.2 million compared to the three months ended March 31, 2019 primarily due to a decrease in salaries and benefits costs associated with lower headcount from our cost cutting initiatives.

EX 99.5-16

Transaction costs. The decrease in transaction costs recognized during the three months ended March 31, 2020 compared to the three months ended March 31, 2019 was due to the financial advisory costs associated primarily with restructuring the equity structure of certain subsidiaries in 2019.

Interest Expense. Interest expense increased $2.7 million compared to the three months ended March 31, 2019 primarily as a result of a higher average outstanding balance on the Revolving Credit Facility. The increase was partially offset by a lower outstanding balance on the Term Loan B.

Summarized Financial Information

On March 2, 2020, the SEC issued Final Rule Release No. 33-10762, Financial Disclosures about Guarantors and Issuers of Guaranteed Securities and Affiliates Whose Securities Collateralize a Registrant’s Securities (“Release 33-10762”), that amends the disclosure requirements related to certain registered securities that are guaranteed and those that are collateralized by the securities of an affiliate.

Under Release 33-10762, an SEC registrant may continue to omit separate financial statements of subsidiary issuers and guarantors when (1) the subsidiary issuer is consolidated with the parent company and its security is either (a) co-issued jointly and severally with the parent company’s security or (b) the subsidiary issuer’s security is fully and unconditionally guaranteed by the parent company and (2) the parent company provides supplemental financial and non-financial disclosure about the subsidiary issuers and/or guarantors and the guarantees.

The rules become effective January 4, 2021, with voluntary compliance permitted immediately. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by SMLP and the Guarantor Subsidiaries (see Note 9 to the unaudited condensed consolidated financial statements). SMLP has concluded that it is eligible to provide Alternative Disclosures under the amended disclosure requirements and has early adopted Release 33-10762 as of and for the three months ended March 31, 2020.

The supplemental summarized financial information below reflects SMLP’s separate accounts, the combined accounts of Summit Holdings and its 100% owned finance subsidiary, Finance Corp (the “Co-Issuers”) and the Guarantor Subsidiaries (the Co-Issuers and, together with the Guarantor Subsidiaries, the “Obligor Group”) for the dates and periods indicated. The financial information of the Obligor Group is presented on a combined basis and intercompany balances and transactions between the Co-Issuers and Guarantor Subsidiaries have been eliminated. There were no reportable transactions between the Co-Issuers and Obligor Group and the subsidiaries that were not issuers or guarantors of the Senior Notes.

Payments to holders of the Senior Notes are affected by the composition of and relationships among the Co-Issuers, the Guarantor Subsidiaries and Permian Holdco and Summit Permian Transmission, who are unrestricted subsidiaries of SMLP and are not issuers or guarantors of the Senior Notes. The assets of our unrestricted subsidiaries are not available to satisfy the demands of the holders of the Senior Notes. In addition, our unrestricted subsidiaries are subject to certain contractual restrictions related to the payment of dividends, and other rights in favor of their non-affiliated stakeholders, that limit their ability to satisfy the demands of the holders of the Senior Notes.

A list of each of SMLP’s subsidiaries that is a guarantor, issuer or co-issuer of our registered securities subject to the reporting requirements in Release 33-10762 is filed as Exhibit 22.1 to our Quarterly Report for the three months ended March 31, 2020 on Form 10-Q filed with the Securities and Exchange Commission on May 8, 2020.

Summarized Balance Sheet Information. Summarized balance sheet information as of March 31, 2020 and December 31, 2019 follow.

EX 99.5-17

	March 31, 2020
	SMLP		Obligor Group
	(In thousands)
Assets
Current assets	$	10,732	$	145,901
Noncurrent assets		12,133		2,361,034
Liabilities
Current liabilities	$	15,604	$	61,675
Noncurrent liabilities		163,163		1,539,410

	December 31, 2019
	SMLP		Obligor Group
	(In thousands)
Assets
Current assets	$	7,396	$	104,964
Noncurrent assets		9,835		2,389,032
Liabilities
Current liabilities	$	14,527	$	69,177
Noncurrent liabilities		163,163		1,514,250

Summarized Statements of Operations Information. For the purposes of the following summarized statements of operations, we allocate a portion of general and administrative expenses recognized at the SMLP parent to the Obligor Group to reflect what those entities’ results would have been had they operated on a stand-alone basis. Summarized statements of operations for the three months ended March 31, 2020 and for the year ended December 31, 2019 follow.

	Three months ended March 31, 2020
	SMLP			Obligor Group
	(In thousands)
Total revenues	$	—		$	104,903
Total costs and expenses		1,172			78,990
(Loss) income before income taxes and income from equity method investees		(5,208	)		5,695
Income from equity method investees		—			3,762
Net (loss) income		(5,196	)		9,457

	Year ended December 31, 2019
	SMLP			Obligor Group
	(In thousands)
Total revenues	$	—		$	443,528
Total costs and expenses		8,719			397,939
Loss before income taxes and loss from equity method investees		(25,805	)		(28,840	)
Loss from equity method investees (1)		—			(336,950	)
Net loss		(27,036	)		(365,790	)

(1) Amount includes a $329.7 million impairment of our equity method investment in Ohio Gathering and a $6.3 million impairment of long-lived assets in OCC.

EX 99.5-18

Liquidity and Capital Resources

On May 3, 2020, we suspended distributions to holders of our common units and suspended payment of distributions to holders of our Series A Preferred Units commencing with respect to the quarter ending March 31, 2020 to enable us to retain an incremental approximately $76 million of cash in the business annually, which we plan to use to de-lever the balance sheet, enhance liquidity and increase financial flexibility. The unpaid distributions on the Series A Preferred Units will continue to accrue. We expect to fund future capital expenditures with cash and cash equivalents on hand, cash flows generated from our operations, borrowings under our Revolving Credit Facility, future issuances of debt, preferred equity and equity securities and proceeds from potential asset divestitures.

We are closely monitoring the impact of the outbreak of COVID-19 on all aspects of our business, including how it will impact our liquidity and capital resources. Considering the current commodity price backdrop and COVID-19 pandemic, we have collaborated extensively with our customer base over the past several weeks. Given further deterioration of market conditions, decreased drilling activity, the deferral of well completions from customers and, on a limited scale, temporary production curtailments predominantly in the Williston Basin and DJ Basin reportable segments, we now expect 2020 total capital expenditures to range from $30 million to $50 million.

We are currently in compliance with all covenants contained in our Revolving Credit Facility, Term Loan B and Senior Notes, and at March 31, 2020, SMLP’s total leverage ratio and senior secured leverage ratio (as defined in the Revolving Credit Agreement) were 5.05 to 1.0 and 2.26 to 1.0, respectively, relative to maximum threshold limits of 5.5x and 3.75x. Given further deterioration of market conditions, decreased drilling activity, the deferral of well completions from customers, limitations on access to capital markets to fund our capital expenditures and, on a limited scale, temporary production curtailments, we could have total leverage and senior secured leverage ratios that are higher than the levels prescribed in the applicable indebtedness agreements. Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations and cash flows.    

As we cannot predict the duration or scope of the COVID-19 pandemic and its impact on our customers and suppliers, the potential negative financial impact to our results cannot be reasonably estimated but could be material. We are actively managing the business to maintain cash flow and we have sufficient available liquidity. We believe that these factors will allow us to meet our anticipated funding requirements.

Capital Markets Activity

We had no capital markets activity during the three months ended March 31, 2020. For additional information, see the “Liquidity and Capital Resources – Capital Markets Activity” section of MD&A included in the 2019 Annual Report in addition to the exhibits contained within this Form 8-K.

Debt

Revolving Credit Facility. We have a $1.25 billion senior secured Revolving Credit Facility that matures in May 2022. As of March 31, 2020, the outstanding balance of the Revolving Credit Facility was $698.0 million and the unused portion totaled $542.9 million, after giving effect to the issuance thereunder of a $9.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of March 31, 2020 was approximately $120 million. There were no defaults or events of default during the three months ended March 31, 2020, and, as of March 31, 2020, we were in compliance with the financial covenants in the Revolving Credit Facility. See Notes 9 and 15 to the unaudited condensed consolidated financial statements for more information on the Revolving Credit Facility and the issuance of the $9.1 million letter of credit, respectively.

Senior Notes. In February 2017, the Co-Issuers co-issued $500.0 million of 5.75% Senior Notes. In July 2014, the Co-Issuers co-issued $300.0 million of 5.50% Senior Notes. There were no defaults or events of default as of and for the three months ended March 31, 2020 on either series of senior notes.

Term Loan B. At March 31, 2020, the outstanding balance of the Term Loan B was $160.8 million and we were in compliance the Term Loan B’s financial covenants. There were no defaults or events of default during the three months ended March 31, 2020.

EX 99.5-19

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

LIBOR Transition

LIBOR is the basic rate of interest widely used as a reference for setting the interest rates on loans globally. In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, a steering committee comprised of large U.S. financial institutions, is considering replacing U.S. dollar LIBOR with a new index, the Secured Overnight Financing Rate (“SOFR”), calculated using short-term repurchase agreements backed by Treasury securities. We are evaluating the potential impact of the eventual replacement of the LIBOR benchmark interest rate, however, we are not able to predict whether LIBOR will cease to be available after 2021, whether SOFR will become a widely accepted benchmark in place of LIBOR, or what the impact of such a possible transition to SOFR may be on our business, financial condition and results of operations.

We will need to renegotiate our Revolving Credit Facility to determine the interest rate to replace LIBOR with the new standard that is established. The potential effect of any such event on interest expense cannot yet be determined.

Cash Flows

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

	March 31,
	2020			2019
	(In thousands)
Net cash provided by operating activities	$	70,201		$	45,193
Net cash (used in) provided by investing activities		(76,399	)		28,493
Net cash provided by (used in) financing activities		46,657			(74,771	)
Net change in cash, cash equivalents and restricted cash	$	40,459		$	(1,085	)

Operating activities. Cash flows from operating activities for the three months ended March 31, 2020 primarily reflected:

• a $13.8 million increase in accounts receivable related to the timing of invoicing and cash collections;

• a $3.7 million increase in accounts payable due to the timing of payment obligations;

• a $2.8 million increase in deferred revenue for cash receipts not yet recognized as revenue; and

• other changes in working capital.

Investing activities. Cash flows used in investing activities during the three months ended March 31, 2020 primarily reflected:

• $58.0 million for investments in the Double E joint venture relating to the Double E Project; and

• $18.6 million of capital expenditures primarily attributable to the DJ Basin of $6.3 million, the Williston Basin of $4.9 million and Summit Permian of $3.3 million.

Cash flows used in investing activities during the three months ended March 31, 2019 primarily reflected:

• $89.5 million of net proceeds from the Tioga Midstream sale; and

• $60.8 million of capital expenditures primarily attributable to the ongoing development of the DJ Basin of $28.4 million, Corporate and Other of $16.1 million (inclusive of capital expenditures of $15.8 million relating to the Double E Project), the Williston Basin of $8.0 million and Summit Permian of $7.1 million.

Financing activities. Cash flows used in financing activities during the three months ended March 31, 2020 primarily reflected:

• $33.9 million of net proceeds from the issuance of Subsidiary Series A Preferred Units;

• $21.0 million of net borrowings under our Revolving Credit Facility; and

EX 99.5-20

• $6.0 million of distributions.

Cash flows used in financing activities during the three months ended March 31, 2019 primarily reflected:

• $27.4 million of distributions;

• $32.0 million of net repayments under our Revolving Credit Facility.

Contractual Obligations Update

Double E Project

Upon completion of the Double E Project, we expect to own at least a 50% interest in the Double E Project, will lead the development, permitting and construction of the Double E Project and will operate the pipeline upon commissioning. At our current 70% interest, we estimate that our share of the capital expenditures required to develop the Double E Project will total approximately $350.0 million, and that more than 90% of those capital expenditures will be incurred in 2020 and 2021. Assuming timely receipt of the required regulatory approvals (including the Federal Energy Regulatory Commission’s issuance of the certificate required for us to pursue the Double E Project) and no material delays in construction, we expect that the Double E Project will be placed into service in the third quarter of 2021.

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, 2020, cash paid for capital expenditures totaled $18.6 million (see Note 4 to the unaudited condensed consolidated financial statements) which included $5.1 million of maintenance capital expenditures. For the three months ended March 31, 2020, there were no contributions to Ohio Gathering and we contributed $58.0 million to Double E (see Note 8 to the unaudited condensed consolidated financial statements).

We rely primarily on internally generated cash flow as well as external financing sources, including commercial bank borrowings and the issuance of debt, equity and preferred equity securities, and proceeds from potential asset divestitures to fund our capital expenditures. We believe that our Revolving Credit Facility, together with internally generated cash flow and access to debt or equity capital markets, will be adequate to finance our business for the foreseeable future without adversely impacting our liquidity.

Considering the current commodity price backdrop and COVID-19 pandemic, we will remain disciplined with respect to future capital expenditures, which will be primarily concentrated on the Double E Project and accretive expansions of our existing systems in our Core Focus Areas. We continue to advance our financing plans for our equity interest in Double E, which we intend to be credit neutral to Summit. We are currently targeting a financing structure that limits cash investments by us during 2020, and which shifts a substantial majority of our Double E capital commitments to third parties. On December 24, 2019, we entered into an agreement with TPG Energy Solutions Anthem, L.P. (“TPG”) to fund up to $80 million of Permian Holdco’s future capital calls associated with the Double E Project. Simultaneously, on December 24, 2019, we issued 30,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco to TPG for net proceeds of $27.3 million.

During the three months ended March 31, 2020, we issued an additional 35,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit. We used the net proceeds of $34.4 million (after deducting underwriting discounts and offering expenses) to fund Summit’s share of capital expenses associated with the Double E Project.

EX 99.5-21

There are a number of risks and uncertainties that could cause our current expectations to change, including, but not limited to, (i) the ability to reach agreements with third parties; (ii) prevailing conditions and outlook in the natural gas, crude oil and natural gas liquids industries and markets and (iii) our ability to obtain financing from commercial banks, the capital markets, or other financing sources.

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.

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 customers’ wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customers’ commodities flow and, in many cases, the only way for our customers to get their production to market.

We have exposure due to nonperformance under our MVC contracts whereby a customer, who was not meeting its 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 4, 9, 11 and 16 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, 2020.

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, 2019.

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 officers and employees 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, our subsidiaries, 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.

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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, including as of a result of political or economic measures taken by various countries in response to the OPEC price war;

• the extent and success of our customers’ drilling efforts, as well as the quantity of natural gas, crude oil and produced water volumes produced within proximity of our assets;

• the current and potential future impact of the COVID-19 pandemic on our business, results of operations, financial position or cash flows;

• 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 divest of certain of our assets to third parties on attractive terms, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets;

• 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 and preferred equity 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, compression, treating and/or processing of natural gas, crude oil and produced water;

• weather conditions and terrain in certain areas in which we operate;

• any other issues that can result in deficiencies in the design, installation or operation of our gathering, compression, 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;

• our ability to finance our obligations related to capital expenditures, including through opportunistic asset divestitures or joint ventures and the impact any such divestitures or joint ventures could have on our results;

• the effects of existing and future laws and governmental regulations, including environmental, safety and climate change requirements and federal, state and local restrictions or requirements applicable to oil and/or gas drilling, production or transportation;

• the ability of SMP Holdings to meet its obligations under the SMPH Term Loan;

• changes in tax status;

• the effects of litigation;

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• 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, preferred 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.

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