EXHIBIT 99.2

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 7. 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 have been retrospectively recast for all periods presented in order to present the financial results of the surviving entity for accounting purposes.

EX 99.2-1

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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. As a result, the following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in this report. Among other things, the consolidated 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. You should read the following discussion and analysis of financial condition and results of operations in conjunction with the financial statements, and the notes thereto, included in Item 8, “Financial Statements and Supplementary Data” of this Current Report on Form 8-K.

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-driven 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 99.2-2

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 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 year ended December 31, 2019, these additional activities accounted for approximately 20% of total revenues including marketing transactions, and approximately 14% of total revenues excluding marketing transactions.

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 99.2-3

The following table presents certain consolidated and reportable segment financial data. For additional information on our reportable segments, see the “Segment Overview for the Years Ended December 31, 2019, 2018 and 2017” section herein.

	Year ended December 31,
	2019			2018			2017
	(In thousands)
Net (loss) income	$	(393,726	)	$	34,320		$	(136,914	)
Reportable segment adjusted EBITDA
Utica Shale	$	29,292		$	30,285		$	34,011
Ohio Gathering		39,126			39,969			41,246
Williston Basin		69,437			76,701			66,413
DJ Basin		18,668			7,558			6,624
Permian Basin		(879	)		(1,200	)		—
Piceance Basin		98,765			111,042			111,113
Barnett Shale		43,043			43,268			46,232
Marcellus Shale		20,051			24,267			23,888
Net cash provided by operating activities	$	161,741		$	206,230		$	213,048
Capital expenditures (1)		182,291			200,586			124,215
Contributions to equity method investees		—			4,924			25,513
Investment in equity method investee		18,316			—			—
Distributions to noncontrolling interest SMLP unitholders	$	68,874		$	109,101		$	107,598
Distributions to Series A Preferred unitholders		28,500			28,500			2,375
Distributions to Energy Capital Partners		120,730			11,800			301,672
Issuance of senior notes		—			—			500,000
Tender and redemption of senior notes		—			—			(300,000	)
Net borrowings (repayments) under Revolving Credit Facility		211,000			205,000			(387,000	)
Issuance of SMP Holdings term loan		—			—			300,000
Repayments under SMP Holdings term loan		(65,250	)		(49,250	)		(24,000	)
Proceeds from issuance of Series A preferred units, net of costs (2)		27,392			—			293,238
Proceeds from ATM Program common unit issuances, net of costs		—			—			17,078

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

(2) Reflects proceeds from the issuance of Series A preferred units.

Year ended December 31, 2019. The following items are reflected in our financial results:

• In December 2019, we identified certain triggering events which indicated that our equity method investment in Ohio Gathering could be impaired. We completed an other-than-temporary impairment analysis to determine the potential equity method impairment charge to be recorded on our consolidated financial statements. As a result, an impairment charge of approximately $329.7 million was recorded in the loss from equity method investees caption on the consolidated statement of operations.

• In September 2019, in connection with our annual impairment evaluation, we determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value and we recognized a goodwill impairment charge of $16.2 million.

EX 99.2-4

• 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 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 and we recorded an impairment charge of $10.2 million related to these assets.

• In December 2019, as part of our financing for the Double E Project, we formed Permian Holdco, a newly created, unrestricted subsidiary of SMLP that indirectly owns SMLP’s 70% interest in Double E. In connection with the formation of Permian Holdco, we entered into an agreement with TPG Energy Solutions Anthem, L.P. (“TPG”) on December 24, 2019 to fund up to $80 million of Permian Holdco’s future capital calls associated with the Double E Project. Simultaneously, on December 24, 2019, Permian Holdco issued 30,000 Subsidiary Series A Preferred Units to TPG for net proceeds of $27.4 million.

• In June 2019, we continued development of the Double E Project after securing firm 10-year commitments under binding precedent agreements for a substantial majority of the pipeline’s initial throughput capacity of 1.35 Bcf of gas per day and executing the JV Agreement with an affiliate of Double E’s foundation shipper. The Double E Project, which consists of an approximately 116-mile mainline and related facilities, will provide interstate natural gas transportation service from the Delaware Basin production area to the Waha Hub in Texas. Double E filed its application under Section 7(c) of the NGA with the FERC on July 31, 2019 to obtain a certificate of public convenience and necessity authorizing the construction and operation of the pipeline.

In connection with the Double E Project, Summit Permian Transmission contributed total assets of approximately $23.6 million for a 70% ownership interest in Double E. Concurrent with this contribution, Double E distributed $7.3 million to the Partnership. 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 FERC certificate) and no material delays in construction, we expect that the Double E Project will be placed into service in the third quarter of 2021.

• In December 2019, Red Rock Gathering and certain affiliates of SMLP (collectively, “the Red Rock Parties”) entered into a Purchase and Sale Agreement (the “Red Rock PSA”) pursuant to which the Red Rock Parties agreed to sell certain Red Rock Gathering system assets for a cash purchase price of $12.0 million (the “Red Rock Sale”). Prior to closing, we recorded an impairment charge of $14.2 million based on the expected consideration and the carrying value for the Red Rock Gathering system assets. On December 2, 2019, we closed the Red Rock Sale. The impairment is included in the Long-lived asset impairment caption on the consolidated statement of operations. The financial contribution of these assets (a component of the Piceance Basin reportable segment) are included in our consolidated financial statements and footnotes for the period from January 1, 2019 through December 1, 2019.

• Until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system in the Williston Basin. On March 22, 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 consolidated statement of operations. The financial results of Tioga Midstream (a component of the Williston Basin reportable segment) are included in our consolidated financial statements and footnotes for the historical periods through March 22, 2019. Refer to Note 17 to the consolidated financial statements for details on the sale of Tioga Midstream.

EX 99.2-5

• In the third quarter of 2019, we began an internal initiative to evaluate and transform our cost structure, enhance margins and improve our competitive position in response to a weakening commodity price backdrop. For the year ended December 31, 2019, we incurred approximately $5.0 million in restructuring costs relating to this initiative (included in general and administrative expense).

Year ended December 31, 2018. The following items are reflected in our financial results:

• Increased natural gas, NGLs and condensate sales and cost of natural gas and NGLs associated with increased marketing related activities.

• During the year ended December 31, 2018, we recognized $6.0 million in gathering services and related fees from MVC shortfall adjustments. Under Topic 606, we recognize customer obligations under their MVCs as revenue and contract assets when (i) we consider it remote that the customer will utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods; (ii) the customer incurs a shortfall in a contract with no banking mechanism or claw back provision; (iii) the customer’s banking mechanism has expired; or (iv) it is remote that the customer will use its unexercised right.

• In December 2018, in connection with certain strategic initiatives, we performed a recoverability assessment of certain assets within the Williston Basin reporting segment. Based on the results, we concluded that the carrying value of certain long-lived assets related to the Tioga Midstream system in the Williston Basin were not fully recoverable and we recorded an impairment charge of $3.9 million.

Year ended December 31, 2017. The following items are reflected in our financial results:

• In February 2017, we completed a public offering of $500.0 million principal amount of 5.75% Senior Notes. Concurrent with and following the offering, we initiated a tender offer for the outstanding 7.5% Senior Notes. All 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 amount of 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.

• In March 2017, we closed on a $300.0 million senior secured term loan facility, (the “Term Loan B”) with the maturity date of May 15, 2022. Borrowings under the Term Loan B bear interest at LIBOR plus 6.00% or ABR plus 5.00%, as defined in the Term Loan B Facility. We used the net proceeds of the Term Loan B to redeem the Class C Redemption Units and to make a distribution to the Sponsor.

• In March 2017, we recognized $37.7 million of gathering services and related fees revenue that had been previously deferred, and recorded on our consolidated balance sheet as deferred revenue, 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.

• In November 2017, we issued 300,000 Series A Preferred Units representing limited partner interests in the Partnership at a price of $1,000 per unit. We used the net proceeds of $293.2 million to repay outstanding borrowings under our Revolving Credit Facility.

• In December 2017, in connection with certain strategic initiatives, we performed a financial review of certain assets within the Williston Basin reporting segment. This resulted in a triggering event that required us to perform a recoverability test. Based on the results of the test, we concluded that the carrying value of certain intangible and long-lived assets related to the Bison Midstream system in the Williston Basin were not fully recoverable and we recorded an impairment charge of $187.1 million.

EX 99.2-6

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; 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.

Natural gas, NGL and crude oil supply and demand dynamics. Natural gas continues to be a critical component of energy supply and demand in the United States. The average spot price of natural gas decreased by approximately 19% from 2018 to 2019, primarily due to natural gas supply exceeding demand. The average daily Henry Hub Natural Gas Spot Price was $2.56 per MMBtu during 2019, compared with $3.15 per MMBtu during 2018. Henry Hub closed at $2.09 per MMBtu on December 31, 2019 and as of February 10, 2020, closed at $1.85 per MMBtu. Natural gas prices continue to trade at lower-than-average historical prices due in part to increased natural gas production and an elevated level of natural gas in storage in the continental United States. The average amount of working natural gas in underground storage in the continental U.S. was 2.47 Tcf in 2019, which was 9.5% higher than in 2018. In the near term, we believe that until the supply of natural gas in storage has been reduced, natural gas prices are likely to remain constrained. Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven primarily by global population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation. However, we note that over the last several years there has been an increasing societal opposition to the production of hydrocarbons generally, which may be reflected in legislation, executive orders or regulations that may significantly restrict the domestic production of fossil fuels, including natural gas.

In addition, certain of our gathering systems are directly affected by crude oil supply and demand dynamics. Crude oil prices decreased in 2019, with the average daily Cushing, Oklahoma West Texas Intermediate (“WTI”) crude oil spot price decreasing from an average $65.23 per barrel during 2018 to an average of $56.98 per barrel during 2019, representing a 12.6% decrease, reflecting broader market concerns for global oil supply and demand dynamics. In response to the general decrease in crude oil prices, the number of active crude oil drilling rigs in the continental United States decreased from 885 in December 2018 to 677 in December 2019, according to Baker Hughes. Over the next several years, we expect that crude oil prices will support continued drilling activity and increasing production in the Williston Basin, Permian Basin and, given the current regulatory environment in Colorado, in rural parts of the DJ Basin.

Growth in production from U.S. shale plays. Over the past several years, natural gas production from unconventional shale resources has increased significantly due to advances in technology that allow producers to extract significant volumes of natural gas from unconventional shale plays on favorable economic terms relative to most conventional plays. In recent years, a number of producers and their joint venture partners, including large international operators, industrial manufacturers and private equity sponsors, have committed significant capital to the development of these unconventional resources, including the Piceance, Barnett, Bakken, Marcellus, Utica and Permian Basin shale plays in which we operate, and we believe that these long-term capital investments will support drilling activity in unconventional shale plays over the long term.

Rate of growth in production from U.S. shale plays. Some of our producer customers have adjusted their drilling and completion activities and schedules to manage drilling and completion costs at levels that are achievable using internally generated cash flow from their underlying operations. Historically, as part of a strategy to accelerate production growth, these producers would raise external capital to fund drilling and completion costs in excess of the cash flows generated

EX 99.2-7

from their underlying assets. In general, we expect our producer customers to reduce completion and production activities across many of our systems relative to our previous expectations as a result of a weakening commodity price environment and a continuation of the general trend of producers constraining drilling and completion activity to levels that can be satisfied with internally generated cash flow.

Capital markets availability and cost of capital. Credit markets were volatile throughout 2019, as borrowing costs increased and investors assessed the impact of rising rates on broader economic activity. Capital markets conditions, including but not limited to availability and higher borrowing costs, could affect our ability to access the debt capital markets to the extent necessary, to fund our future growth. Furthermore, market demand for equity issued by master limited partnerships has been significantly lower in recent years than it has been historically, which may make it more challenging for us to finance our capital expenditures with the issuance of additional equity. We recently announced a reduction in our common unit distribution to $0.125 per quarter, beginning with the distribution paid in respect of the fourth quarter of 2019, and this reduction may further reduce demand for our common units. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

Shifts in operating costs and inflation. Throughout most of the last five years, high levels of crude oil and natural gas exploration, development and production activities across the United States resulted in increased competition for personnel and equipment as well as higher prices for labor, supplies, equipment and other services. Beginning in 2015, this dynamic began to shift as prices for crude oil and natural gas-related services decreased in line with overall decline in demand for these goods and services. While we expect lower service-related costs in the near term, we expect that over the longer term, these costs will continue to have a high correlation to changes in the prevailing price of crude oil and natural gas.

EX 99.2-8

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 17 to the 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 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.

Throughput Volume

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

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

• successful drilling activity within our AMIs;

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

• the number of new pad sites in our AMIs awaiting connections;

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

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

EX 99.2-9

We report volumes gathered for natural gas in cubic feet per day. We aggregate crude oil and produced water gathering and report volumes gathered in barrels per day.

Revenues

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

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

Operation and Maintenance Expenses

We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating our assets. Direct labor costs, compression costs, ad valorem taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are largely independent of volumes delivered through our gathering systems but may fluctuate depending on the activities performed during a specific period.

Segment Adjusted EBITDA

Segment adjusted EBITDA is a supplemental financial measure used by management and by external users of our financial statements such as investors, commercial banks, research analysts and others.

Segment adjusted EBITDA is used to assess:

• the ability of our assets to generate cash sufficient to make cash distributions and support our indebtedness;

• the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

• our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure;

• the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities; and

• the financial performance of our assets without regard to (i) income or loss from equity method investees, (ii) the impact of the timing of minimum volume commitment shortfall payments under our gathering agreements or (iii) the timing of impairments or other noncash income or expense items.

Additional Information. For additional information, see the “Results of Operations” section herein and the notes to the consolidated financial statements. For information on pending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 to the consolidated financial statements.

EX 99.2-10

Results of Operations

Our financial results are recognized as follows:

Gathering services and related fees. Revenue earned from the gathering, compression, treating and processing services that we provide to our customers.

Natural gas, NGLs and condensate sales. Revenue earned from (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds arrangements with certain of our customers on the Bison Midstream, Grand River and Summit Permian systems, (ii) natural gas and crude oil marketing services in and around our gathering systems, (iii) the sale of natural gas we retain from certain DFW Midstream customers and (iv) the sale of condensate we retain from our gathering services at Grand River.

Other revenues. Revenue earned primarily from (i) certain costs for which certain of our customers have agreed to reimburse us and (ii) connection fees for customers of the Polar and Divide system.

Cost of natural gas and NGLs. The cost of natural gas and NGLs represents (i) the purchase of natural gas and NGLs associated with marketing activity surrounding certain of our natural gas and crude oil-related operations and (ii) the costs associated with the percent-of-proceeds arrangements under which we sell natural gas and NGLs purchased from certain of our customers on the Bison Midstream and Grand River systems.

Operation and maintenance. Operation and maintenance primarily comprises direct labor costs, compression costs, ad valorem taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services. These items represent the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are largely independent of variations in throughput volumes but may fluctuate depending on the activities performed during a specific period.

General and administrative. Expenses associated with our operations that are not specifically associated with the operation and maintenance of a particular system or another cost and expense line item. These expenses largely reflect salaries, benefits and incentive compensation, professional fees, insurance and rent.

Depreciation and amortization. The depreciation of our property, plant and equipment and the amortization of our contract and right-of-way intangible assets.

Transaction costs. Financial and legal advisory costs associated with completed acquisitions and divestitures and restructuring activities.

Other income or expense. Generally represents other items of gain or loss but may also include interest income.

Interest expense. Interest expense associated with our Revolving Credit Facility, Term Loan B and our Senior Notes as well as amortization expense associated with debt issuance costs.

Income tax expense or benefit. Represents the expense or benefit associated with the Texas Margin Tax.

Income or loss from equity method investees. Represents the income or loss and other-than-temporary impairment associated with our ownership interest in Ohio Gathering.

EX 99.2-11

Consolidated Overview for the Years Ended December 31, 2019, 2018 and 2017

The following table presents certain consolidated data and volume throughput for the years ended December 31.

	Year ended December 31,									Percentage Change
	2019			2018			2017			2019 v. 2018			2018 v. 2017
	(In thousands)
Revenues:
Gathering services and related fees	$	326,747		$	344,616		$	394,427			(5	%)		(13	%)
Natural gas, NGLs and condensate sales		86,994			134,834			68,459			(35	%)		97	%
Other revenues		29,787			27,203			25,855			9	%		5	%
Total revenues		443,528			506,653			488,741			(12	%)		4	%
Costs and expenses:
Cost of natural gas and NGLs		63,438			107,661			57,237			(41	%)		88	%
Operation and maintenance		98,719			100,978			93,882			(2	%)		8	%
General and administrative		55,947			54,991			56,351			2	%		(2	%)
Depreciation and amortization		110,354			107,263			115,737			3	%		(7	%)
Transaction costs		3,017			—			50			*			*
(Gain) loss on asset sales, net		(1,536	)		—			527			*			*
Long-lived asset impairment		60,507			7,186			188,702			*			(96	%)
Goodwill impairment		16,211			—			—			*			*
Total costs and expenses		406,657			378,079			512,486			8	%		(26	%)
Other income (expense)		451			(169	)		298			*			*
Interest expense		(91,966	)		(82,830	)		(88,701	)		11	%		(7	%)
Early extinguishment of debt		—			—			(22,039	)		*			*
(Loss) income before income taxes and loss from equity method investees		(54,644	)		45,575			(134,187	)		*			*
Income tax expense		(1,231	)		(367	)		(504	)		*			*
Loss from equity method investees		(337,851	)		(10,888	)		(2,223	)		*			*
Net (loss) income	$	(393,726	)	$	34,320		$	(136,914	)		*			*
Volume throughput (1):
Aggregate average daily throughput - natural gas (MMcf/d)		1,397			1,673			1,748			(16	%)		(4	%)
Aggregate average daily throughput - liquids (Mbbl/d)		105.3			94.9			75.2			11	%		26	%

* Not considered meaningful

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

EX 99.2-12

Volumes – Gas. Natural gas throughput volumes decreased 276 MMcf/d for the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily reflecting:

• a volume throughput decrease of 111 MMcf/d for the Marcellus Shale segment.

• a volume throughput decrease of 99 MMcf/d for the Piceance Basin segment.

• a volume throughput decrease of 86 MMcf/d for the Utica Shale segment.

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

• a volume throughput increase of 10 MMcf/d for the DJ Basin segment.

Natural gas throughput volumes decreased 75 MMcf/d for the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily reflected:

• a volume throughput decrease of 31 MMcf/d for the Piceance Basin segment.

• a volume throughput decrease of 28 MMcf/d for the Marcellus Shale segment.

• a volume throughput decrease of 14 MMcf/d for the Barnett Shale segment.

• a volume throughput decrease of 6 MMcf/d for the Utica Shale segment.

• a volume throughput increase of 4 MMcf/d for the DJ Basin segment.

Volumes – Liquids. Crude oil and produced water throughput volumes at the Williston segment increased 10.4 Mbbl/d for the year ended December 31, 2019 compared to the year ended December 31, 2018.

Crude oil and produced water throughput volumes at the Williston segment increased 19.7 Mbbl/d for the year ended December 31, 2018 compared to the year ended December 31, 2017.

For additional information on volumes, see the “Segment Overview for the Years Ended December 31, 2019, 2018 and 2017” section herein.

Revenues. Total revenues decreased $63.1 million during the year ended December 31, 2019 compared to the prior year primarily comprised of a $47.8 million decrease in natural gas, NGLs and condensate sales and a $17.9 million decrease in gathering services and related fees.

Gathering Services and Related Fees. Gathering services and related fees decreased $17.9 million compared to the year ended December 31, 2018, primarily reflecting:

• a $11.2 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting $5.1 million in lower MVC shortfall revenue attributable to the timing of revenue recognition and an unfavorable gathering rate mix on certain gathering services and related fees. Also impacting 2019 revenues was the presentation of $4.5 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.

• a $14.5 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.

• a $5.1 million decrease in gathering services and related fees in the Marcellus Shale relating to lower volume throughput due to natural production declines partially offset by additional drilling and completion activities.

• a $3.3 million decrease in gathering services and related fees in the Utica Shale due to a combination of natural production declines on existing wells together with increased temporary production curtailments associated with infill drilling, completion activity and other operational downtime partially offset by the completion of new wells at the end of the fourth quarter of 2018 and throughout 2019 and a more favorable volume and gathering rate mix from customers.

EX 99.2-13

• a $2.0 million decrease in gathering services and related fees in the Williston Basin primarily reflecting a $9.8 million decrease in gathering services and related fees attributable to 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. This was partially offset by higher liquids volume throughput due to increased drilling and completion activity.

• a $10.7 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 $3.5 million increase in gathering services and related fees in the Permian Basin (commissioned in the fourth quarter of 2018).

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales decreased $47.8 million compared to the year ended December 31, 2018, primarily reflecting lower natural gas, NGL and crude oil marketing services. The majority of the decrease in revenue is offset by a $44.2 million decrease in natural gas, NGL and condensate purchases.

Total revenues for the year ended December 31, 2018 increased $17.9 million compared to the year ended December 31, 2017 primarily comprised of a $66.4 million increase in natural gas, NGLs and condensate sales and a $49.8 million decrease in gathering services and related fees.

Gathering Services and Related Fees. Gathering services and related fees decreased $49.8 million compared to the year ended December 31, 2017, as compared to the prior year, primarily reflecting:

• the impact of the 2017 recognition of $37.7 million of previously deferred revenue related to a certain Williston Basin customer.

• a $13.3 million decrease in gathering services and related fees for the Williston Basin segment due to the reclassification of amounts under certain percent-of-proceeds arrangements currently recognized on a net basis in cost of natural gas and NGLs under Topic 606.

• a $3.6 million decrease in gathering services and related fees for the Barnett Shale segment largely as a result of the expiration of an MVC during 2017.

• a $6.0 million increase from the recognition of MVC shortfall adjustments for the Barnett Shale segment under Topic 606 (see Note 3 in the consolidated financial statements).

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales increased $66.4 million compared to the year ended December 31, 2017, primarily reflecting the addition of natural gas, NGL and crude oil marketing services provided for the Piceance Basin, DJ Basin, Barnett Shale and Williston Basin segments.

Costs and Expenses. Total costs and expenses increased $28.6 million during the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily reflecting:

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

• a goodwill impairment charge of $16.2 million relating to the Mountaineer Midstream system in the Marcellus Shale.

• the recognition of $14.2 million of long-lived asset impairments relating to the sale of certain Red Rock Gathering system assets in the Piceance Basin.

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

• the recognition of $1.3 million of certain long-lived asset impairments in the Permian Basin.

• a $44.2 million decrease in natural gas, NGLs and condensate purchases primarily driven by lower natural gas, NGL and crude oil marketing activity.

EX 99.2-14

Total costs and expenses decreased $134.4 million during the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily reflecting:

• the impact of the 2017 recognition of $187.1 million of certain intangible and long-lived asset impairments relating to the Bison Midstream system in the Williston Basin segment.

• a $63.7 million increase in natural gas, NGLs and condensate purchases primarily driven by increased natural gas, NGL and crude oil marketing activity for the Piceance Basin, DJ Basin, Barnett Shale and Williston Basin segments.

• a $7.1 million increase in operation and maintenance expense primarily due to a $3.1 million increase in planned compressor overhaul maintenance and a $4.0 million increase in remediation expenses.

• a $13.3 million decrease in the cost of natural gas and NGLs for the Williston Basin segment due to the reclassification of amounts under certain percent-of-proceeds arrangements under Topic 606 that were previously recognized in gathering services and related fees.

• a $8.5 million decrease in depreciation and amortization primarily due to the impairment of certain intangible and long-lived assets relating to the Bison Midstream system in the Williston Basin segment recognized in the fourth quarter of 2017.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs decreased $44.2 million during the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily driven by lower natural gas, NGL and crude oil marketing activity.

Cost of natural gas and NGLs increased $50.4 million during the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily reflecting:

• a $63.7 million increase in natural gas, NGLs, crude oil and condensate purchases driven by increased natural gas, NGL and crude oil marketing activity for the Piceance Basin, DJ Basin, Barnett Shale and Williston Basin segments.

• the reclassification of $13.3 million in cost of natural gas and NGLs for the Williston Basin segment under certain percent-of-proceeds arrangements previously recognized in gathering services and related fees, which is presented net in cost of natural gas and NGLs under Topic 606.

Operation and Maintenance. Operation and maintenance expense decreased $2.3 million for the year ended December 31, 2019 compared to the year ended December 31, 2018.

Operation and maintenance expense increased $7.1 million for the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily due to a $3.1 million increase in planned compressor overhaul maintenance and a $4.0 million increase in remediation expenses.

General and Administrative. General and administrative expense increased $1.0 million for the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily due to a $7.5 million increase in severance and restructuring expenses partially offset by lower headcount associated with our cost cutting initiatives and lower performance-based compensation.

General and administrative expense decreased $1.4 million for the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily reflecting a decrease in information technology expense of $1.3 million and an increase in capitalized labor of $0.7 million associated with the continued development of Summit Permian and the DJ Basin. For additional information, see the “Corporate and Other Overview of the Years Ended December 31, 2019, 2018 and 2017” sections herein.

Depreciation and Amortization. The increase in depreciation and amortization expense during 2019 compared to the year ended December 31, 2018 was primarily due to the assets placed into service in the Permian Basin. The decrease in depreciation and amortization expense during 2018 compared to the year ended December 31, 2017 was primarily due to the impairment of certain intangible and long-lived assets on the Bison Midstream system in the Williston Basin segment recognized in the fourth quarter of 2017.

EX 99.2-15

Transaction Costs. Transaction costs recognized during the year ended December 31, 2019 primarily relate to $2.1 million in financial advisory costs associated with restructuring the equity of certain subsidiaries in 2019.

Interest Expense. The increase in interest expense in the year ended December 31, 2019 compared to the year ended December 31, 2018, 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.

The decrease in interest expense in 2018 compared to the year ended December 31, 2017, was as a result of (i) the tender and redemption of the $300.0 million principal 7.5% Senior Notes, (ii) the issuance of 300,000 Series A Preferred Units in November 2017 whereby the net proceeds were used to repay outstanding borrowings under our Revolving Credit Facility, (iii) a lower average outstanding balance on the Revolving Credit Facility and (iv) a lower outstanding balance on the Term Loan B. The decrease was partially offset by the interest associated with issuance of the $500.0 million principal 5.75% Senior Notes and an increase in the interest rate on the Revolving Credit Facility.

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

For additional information, see the “Segment Overview for the Years Ended December 31, 2019, 2018 and 2017” and “Corporate and Other Overview for the Years Ended December 31, 2019, 2018 and 2017” sections herein and “Business – Recent Developments.”

Segment Overview for the Years Ended December 31, 2019, 2018 and 2017

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

	Utica Shale
	Year ended December 31,						Percentage Change
	2019		2018		2017		2019 v. 2018			2018 v. 2017
Average daily throughput (MMcf/d)		273		359		365		(24	%)		(2	%)

Volume throughput declined compared to the year ended December 31, 2018 due to natural production declines from existing wells on pad sites connected to the Summit Utica, partially offset by the completion of new wells at the end of the fourth quarter of 2018 and throughout 2019. In addition, volume throughput was impacted by an increase in temporary production curtailments associated with infill drilling, completion activity and other operational downtime associated with customers on existing pad sites.

Volume throughput decreased during 2018 due to natural declines from existing wells on pad sites connected to the Summit Utica system together with temporary production curtailments associated with infill drilling and completion activity from customers on existing pad sites, partially offset by the completion of new wells during 2017 and in 2018. In addition, the TPL-7 connector project was commissioned in the first quarter of 2017 which partially offset volume declines in 2018 due to a full year of operations.

EX 99.2-16

Financial data for our Utica Shale reportable segment follows.

	Utica Shale
	Year ended December 31,								Percentage Change
	2019			2018			2017		2019 v. 2018			2018 v. 2017
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	31,926		$	35,233		$	38,907		(9	%)		(9	%)
Other revenues		2,065			—			—		*			*
Total revenues		33,991			35,233			38,907		(4	%)		(9	%)
Costs and expenses:
Operation and maintenance		4,151			4,556			4,487		(9	%)		2	%
General and administrative		530			374			409		42	%		(9	%)
Depreciation and amortization		7,659			7,672			7,009		(0	%)		9	%
Loss on asset sales, net		—			5			542		*			*
Long-lived asset impairment		—			1,440			878		*			*
Total costs and expenses		12,340			14,047			13,325		(12	%)		5	%
Add:
Depreciation and amortization		7,659			7,672			7,009
Adjustments related to capital reimbursement activity		(18	)		(18	)		—
Loss on asset sales, net		—			5			542
Long-lived asset impairment		—			1,440			878
Segment adjusted EBITDA	$	29,292		$	30,285		$	34,011		(3	%)		(11	%)

* Not considered meaningful

Year ended December 31, 2019. Segment adjusted EBITDA decreased $1.0 million compared to the year ended December 31, 2018, primarily reflecting:

• a $3.3 million decrease in gathering services and related fees due to the volume throughput declines discussed above partially offset by a more favorable volume and gathering rate mix from customers.

• a $2.1 million increase in other revenues due to the release of an acreage dedication to one of our customers.

Year ended December 31, 2018. Segment adjusted EBITDA decreased $3.7 million compared to the year ended December 31, 2017, primarily reflecting:

• a $3.7 million decrease in gathering services and related fees from a lower gathering rate mix associated with increasing volumes from the TPL-7 connector project, which was commissioned in the first quarter of 2017, along with a decrease in volume throughput from wells that we gather from pad sites on the Summit Utica system and temporary production curtailments. The decrease was partially offset by an increase in volume throughput associated with new wells completed in 2017 and 2018.

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
	Year ended December 31,						Percentage Change
	2019		2018		2017		2019 v. 2018			2018 v. 2017
Average daily throughput (MMcf/d)		732		769		766		(5	%)		*

* Not considered meaningful

Volume throughput for the Ohio Gathering system in 2019 decreased compared to the year ended December 31, 2018 as a result of natural production declines on existing wells on the system, partially offset by the completion of new wells.

EX 99.2-17

Volume throughput for the Ohio Gathering system in 2018 increased slightly compared to the year ended December 31, 2017 as a result of increased drilling activity from our customers during the second half of 2017 and in 2018, partially offset by natural production declines on existing wells on the system.

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

	Ohio Gathering
	Year ended December 31,						Percentage Change
	2019		2018		2017		2019 v. 2018			2018 v. 2017
	(Dollars in thousands)
Proportional adjusted EBITDA for equity method investees	$	39,126	$	39,969	$	41,246		(2	%)		(3	%)
Segment adjusted EBITDA	$	39,126	$	39,969	$	41,246		(2	%)		(3	%)

Year ended December 31, 2019. Segment adjusted EBITDA for equity method investees decreased $0.8 million compared to the year ended December 31, 2018.

Other items to note:

• In the fourth quarter of 2019, we impaired our equity method investment in Ohio Gathering (see Note 8 to the consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2019.

Year ended December 31, 2018. Segment adjusted EBITDA for equity method investees decreased $1.3 million compared to the year ended December 31, 2017, primarily as a result of higher expenses, partially offset by higher volumes at OGC and OCC.

Williston Basin. The Polar and Divide, Tioga Midstream (through March 22, 2019; refer to Note 17 to the consolidated financial statements for details on the sale of Tioga Midstream) and Bison Midstream systems provide our midstream services for the Williston Basin reportable segment. Volume throughput for our Williston Basin reportable segment follows.

	Williston Basin
	Year ended December 31,						Percentage Change
	2019		2018		2017		2019 v. 2018			2018 v. 2017
Aggregate average daily throughput - natural gas (MMcf/d)		12		18		19		(33	%)		(5	%)
Aggregate average daily throughput - liquids (Mbbl/d)		105.3		94.9		75.2		11	%		26	%

Natural gas. Natural gas volume throughput in 2019 decreased compared to the year ended December 31, 2018, primarily reflecting natural production declines, the sale of Tioga Midstream and operational downtime on the Bison Midstream system. Natural gas volume throughput in 2018 decreased compared to the year ended December 31, 2017, primarily reflecting natural production declines.

Liquids. The increase in liquids volume throughput in 2019 compared to the year ended December 31, 2018, primarily reflected well drilling and completion activity by existing customers on our Polar and Divide system in 2018 and in 2019 as well as the addition of a new customer, partially offset by the sale of Tioga Midstream and natural production declines.

The increase in liquids volume throughput in 2018 compared to the year ended December 31, 2017 primarily reflected well completion activity by existing customers on our Polar and Divide system in the second half of 2017 and in 2018 as well as the addition of new customers.

EX 99.2-18

Financial data for our Williston Basin reportable segment follows.

	Williston Basin
	Year ended December 31,									Percentage Change
	2019			2018			2017			2019 v. 2018			2018 v. 2017
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	77,626		$	79,606		$	120,717			(2	%)		(34	%)
Natural gas, NGLs and condensate sales		16,461			31,840			29,724			(48	%)		7	%
Other revenues		11,564			12,204			11,062			(5	%)		10	%
Total revenues		105,651			123,650			161,503			(15	%)		(23	%)
Costs and expenses:
Cost of natural gas and NGLs		5,821			18,284			30,004			(68	%)		(39	%)
Operation and maintenance		27,172			25,300			25,058			7	%		1	%
General and administrative		1,493			2,089			2,335			(29	%)		(11	%)
Depreciation and amortization		19,829			22,642			33,772			(12	%)		(33	%)
(Gain) loss on asset sales, net		(1,177	)		63			(22	)		*			*
Long-lived asset impairment		10			3,972			187,127			*			*
Total costs and expenses		53,148			72,350			278,274			(27	%)		*
Add:
Depreciation and amortization		19,829			22,642			33,772
Adjustments related to MVC shortfall payments		—			—			(37,693	)
Adjustments related to capital reimbursement activity		(1,728	)		(1,276	)		—
(Gain) loss on asset sales, net		(1,177	)		63			(22	)
Long-lived asset impairment		10			3,972			187,127
Segment adjusted EBITDA	$	69,437		$	76,701		$	66,413			(9	%)		15	%

* Not considered meaningful

Year ended December 31, 2019. Segment adjusted EBITDA decreased $7.3 million compared to the year ended December 31, 2018 primarily reflecting:

• a decrease of $7.6 million of segment adjusted EBITDA contributed by the Tioga Midstream system compared to the year ended December 31, 2018 due to the sale of Tioga Midstream on March 22, 2019. We also experienced lower natural gas volume throughput primarily reflecting natural production declines and operational downtime on the Bison Midstream system. The operational downtime began with third party maintenance on infrastructure located downstream of the Bison Midstream system, which created an operational disruption on the Bison Midstream system for approximately 15 days during the second quarter and continued to impact throughput capacity through August 2019. This was partially offset by higher liquids volume throughput on our Polar and Divide system due to increased drilling and completion activity in 2018 and throughout 2019.

• a $1.9 million increase in operation and maintenance expense primarily related to an increase in environmental remediation costs.

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 consolidated financial statements for the period from January 1, 2019 through March 22, 2019.

EX 99.2-19

Year ended December 31, 2018. Segment adjusted EBITDA increased $10.3 million compared to the year ended December 31, 2017, primarily reflecting an increase in liquids volume throughput on our Polar and Divide system and $1.6 million in fees attributable to our Dakota Access Pipeline interconnect which was commissioned in the second quarter of 2017.

Other items to note:

• The decrease in the cost of natural gas and NGLs includes a $13.3 million reduction in expense due to the reclassification of amounts under certain percent-of-proceeds arrangements previously recognized in gathering services and related fees under Topic 606 (see Note 3 in the consolidated financial statements).

• In the fourth quarter of 2018, we impaired certain long-lived assets relating to the Tioga Midstream system in the Williston Basin (see Note 5 to the consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2018.

• Depreciation and amortization decreased during 2018 largely as a result of the long-lived asset impairment recognized in 2017.

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

	DJ Basin
	Year ended December 31,						Percentage Change
	2019		2018		2017		2019 v. 2018			2018 v. 2017
Average daily throughput (MMcf/d)		27		17		13		59	%		31	%

Volume throughput in 2019 increased compared to the year ended December 31, 2018, primarily as a result of ongoing drilling and completion activity across our service area partially offset by natural production declines.

Volume throughput in 2018 increased compared to the year ended December 31, 2017, primarily as a result of ongoing drilling and completion activity across our service area.

Financial data for our DJ Basin reportable segment follows.

	DJ Basin
	Year ended December 31,							Percentage Change
	2019		2018			2017		2019 v. 2018			2018 v. 2017
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	21,940	$	11,251		$	8,918		95	%		26	%
Natural gas, NGLs and condensate sales		389		371			398		5	%		(7	%)
Other revenues		3,721		3,672			2,544		1	%		44	%
Total revenues		26,050		15,294			11,860		70	%		29	%
Costs and expenses:
Cost of natural gas and NGLs		34		45			17		(24	%)		165	%
Operation and maintenance		7,616		6,482			5,001		17	%		30	%
General and administrative		315		647			218		(51	%)		197	%
Depreciation and amortization		3,732		3,133			2,636		19	%		19	%
Loss on asset sales		—		—			3		*			*
Long-lived asset impairment		34,913		9			—		*			*
Total costs and expenses		46,610		10,316			7,875		352	%		31	%
Add:
Depreciation and amortization		3,732		3,133			2,636
Adjustments related to capital reimbursement activity		583		(562	)		—
Loss on asset sales		—		—			3
Long-lived asset impairment		34,913		9			—
Segment adjusted EBITDA	$	18,668	$	7,558		$	6,624		147	%		14	%

* Not considered meaningful

EX 99.2-20

Year ended December 31, 2019. Segment adjusted EBITDA increased $11.1 million compared to the year ended December 31, 2018, primarily reflecting:

• a $10.7 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.

• a $1.1 million increase in operation and maintenance expense primarily due to higher costs to support volume growth.

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 consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2019.

Year ended December 31, 2018. Segment adjusted EBITDA increased $0.9 million compared to the year ended December 31, 2017, primarily reflecting:

• an increase in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity.

• a $1.5 million increase in operation and maintenance expense primarily due to $1.1 million of higher electricity expenses we pass through to certain customers (which is also included in the increase in Other revenues in the table above) in addition to higher operation and maintenance costs to support volume growth.

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
	Year ended December 31,				Percentage Change
	2019		2018		2019 v. 2018
Average daily throughput (MMcf/d)		19		1		*

EX 99.2-21

Financial data for our Permian Basin reportable segment follows.

	Permian Basin
	Year ended December 31,						Percentage Change
	2019			2018			2019 v. 2018
	(In thousands)
Revenues:
Gathering services and related fees	$	3,610		$	115			*
Natural gas, NGLs and condensate sales		16,383			843			*
Other revenues		310			—			*
Total revenues		20,303			958			*
Costs and expenses:
Cost of natural gas and NGLs		15,113			1,569			*
Operation and maintenance		5,755			428			*
General and administrative		314			161			*
Depreciation and amortization		4,868			243			*
Gain on asset sales, net		(148	)		—			*
Long-lived asset impairment		1,327			761			*
Total costs and expenses		27,229			3,162			*
Add:
Depreciation and amortization		4,868			243
Gain on asset sales, net		(148	)		—
Long-lived asset impairment		1,327			761
Segment adjusted EBITDA	$	(879	)	$	(1,200	)		*

* Not considered meaningful

Year ended December 31, 2019. Segment adjusted EBITDA totaled ($0.9) million primarily reflecting fixed operating costs associated with commissioning and operating the Lane processing plant and certain inefficiencies and higher fuel costs associated with lower plant utilization and initial production volumes.

Other items to note:

In December 2019, we impaired certain long-lived assets in the Permian Basin (see Notes 5 and 6 to the consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2019.

Year ended December 31, 2018. Segment adjusted EBITDA totaled ($1.2) million primarily reflecting less than one month’s volume throughput of the Summit Permian natural gas gathering and processing system commissioned in December 2018 as well as operational and general and administrative expenses incurred during the year.

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
	Year ended December 31,						Percentage Change
	2019		2018		2017		2019 v. 2018			2018 v. 2017
Aggregate average daily throughput (MMcf/d)		452		551		582		(18	%)		(5	%)

EX 99.2-22

Volume throughput decreased compared to the year ended December 31, 2018, as a result of natural production declines.

Volume throughput decreased compared to the year ended December 31, 2017, as a result of natural production declines, partially offset by drilling and completion activity that occurred across our service area during the second half of 2017 and through the third quarter of 2018.

Financial data for our Piceance Basin reportable segment follows.

	Piceance Basin
	Year ended December 31,								Percentage Change
	2019			2018		2017			2019 v. 2018			2018 v. 2017
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	121,357		$	135,810	$	136,834			(11	%)		(1	%)
Natural gas, NGLs and condensate sales		7,954			14,800		13,452			(46	%)		10	%
Other revenues		4,327			4,909		4,607			(12	%)		7	%
Total revenues		133,638			155,519		154,893			(14	%)		0	%
Costs and expenses:
Cost of natural gas and NGLs		5,612			9,591		7,952			(41	%)		21	%
Operation and maintenance		27,306			33,947		30,143			(20	%)		13	%
General and administrative		1,009			1,168		2,617			(14	%)		(55	%)
Depreciation and amortization		47,018			46,919		46,289			*			1	%
Loss on asset sales, net		104			—		—			*			*
Long-lived asset impairment		14,162			1,004		697			*			*
Total costs and expenses		95,211			92,629		87,698			3	%		6	%
Add:
Depreciation and amortization		47,018			46,919		46,289
Adjustments related to MVC shortfall payments		(103	)		10		(3,068	)
Adjustments related to capital reimbursement activity		(843	)		219		—
Loss on asset sales, net		104			—		—
Long-lived asset impairment		14,162			1,004		697
Segment adjusted EBITDA	$	98,765		$	111,042	$	111,113			(11	%)		(0	%)

* Not considered meaningful

Year ended December 31, 2019. Segment adjusted EBITDA decreased $12.3 million compared to the year ended December 31, 2018, primarily reflecting:

• a $14.5 million decrease in gathering services and related fees as a result of natural production declines.

• a $2.9 million decrease in natural gas, NGLs and condensate activity (sales and purchases) as a result of lower volume throughput and lower commodity prices associated with the sale of NGLs and condensate.

• a $6.6 million decrease in operation and maintenance expense primarily due to a $3.3 million reduction in planned compressor overhaul maintenance costs and $2.2 million in lower compensation expense.

Other items to note:

• In December 2019, we sold certain assets from our Red Rock Gathering system and recorded an impairment charge of $14.2 million based on the difference between the consideration received and the then carrying value of the assets at closing. The noncash impairment expense had no impact on segment adjusted EBITDA for the year ended December 31, 2019.

EX 99.2-23

Year ended December 31, 2018. Segment adjusted EBITDA decreased $0.1 million compared to the year ended December 31, 2017, primarily reflecting:

• a $3.8 million increase in operation and maintenance expense primarily due to planned compressor overhaul maintenance costs during the period.

• a $1.5 million decrease in general and administrative expenses.

• a $2.3 million increase, after taking into account the adjustments related to MVC shortfall payments and adjustments related to capital reimbursement activity, in gathering services and related fees primarily as a result of the drilling and completion activity that occurred across our service area by other customers during the second half of 2017 and through the third quarter of 2018, and a $1.0 million MVC shortfall payment received from a customer in 2018 that did not occur in 2017, partially offset by natural production declines.

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
	Year ended December 31,						Percentage Change
	2019		2018		2017		2019 v. 2018			2018 v. 2017
Average daily throughput (MMcf/d)		251		253		267		(1	%)		(5	%)

Volume throughput decreased slightly compared to the year ended December 31, 2018 reflecting natural production declines partially offset by new volumes from well completion activity throughout 2019.

Volume throughput declined compared to the year ended December 31, 2017 reflecting natural production declines, partially offset by new volumes from completion activity during the fourth quarter of 2017, first quarter of 2018 and the fourth quarter of 2018.

Financial data for our Barnett Shale reportable segment follows.

	Barnett Shale
	Year ended December 31,									Percentage Change
	2019			2018			2017			2019 v. 2018			2018 v. 2017
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	47,862		$	59,030		$	61,622			(19	%)		(4	%)
Natural gas, NGLs and condensate sales		17,147			2,523			1,946			580	%		30	%
Other revenues (1)		6,793			6,712			8,099			1	%		(17	%)
Total revenues		71,802			68,265			71,667			5	%		(5	%)
Costs and expenses:
Cost of natural gas and NGLs		10,751			—			—			*			*
Operation and maintenance		21,729			21,358			23,074			2	%		(7	%)
General and administrative		968			971			1,146			(0	%)		(15	%)
Depreciation and amortization		15,354			15,658			15,604			(2	%)		0	%
(Gain) loss on asset sales, net		(325	)		(68	)		4			*			*
Long-lived asset impairment		10,095			—			—			*			*
Total costs and expenses		58,572			37,919			39,828			54	%		(5	%)
Add:
Depreciation and amortization		16,575			15,325			15,001
Adjustments related to MVC shortfall payments		3,579			(3,642	)		(612	)
Adjustments related to capital reimbursement activity		(111	)		1,307			—
(Gain) loss on asset sales, net		(325	)		(68	)		4
Long-lived asset impairment		10,095			—			—
Segment adjusted EBITDA	$	43,043		$	43,268		$	46,232			(1	%)		(6	%)

* Not considered meaningful

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

EX 99.2-24

Year ended December 31, 2019. Segment adjusted EBITDA decreased $0.2 million compared to the year ended December 31, 2018.

Other items to note:

• Impacting 2019 revenues was the presentation of $4.5 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.

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

Year ended December 31, 2018. Segment adjusted EBITDA decreased $3.0 million compared to the year ended December 31, 2017, primarily reflecting:

• a $4.3 million decrease, after taking into account the adjustments related to MVC shortfall payments and adjustments related to capital reimbursement activity, in gathering services and related fees associated with the expiration of MVCs during 2017 of $3.6 million in addition to lower volume throughput.

• a $1.7 million decrease in operation and maintenance expense primarily from $1.3 million of lower electricity expenses associated with lower volume throughput and a decrease in tax expenses.

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
	Year ended December 31,						Percentage Change
	2019		2018		2017		2019 v. 2018			2018 v. 2017
Average daily throughput (MMcf/d)		363		474		502		(23	%)		(6	%)

Volume throughput decreased compared to the year ended December 31, 2018, primarily due to natural production declines partially offset by additional drilling and completion activities.

Volume throughput decreased compared to the year ended December 31, 2017, primarily due to natural production declines. These declines were partially offset by volumes generated by the completion, in the second half of 2017 and first quarter of 2018, of a number of drilled but uncompleted (“DUC”) wells.

EX 99.2-25

Financial data for our Marcellus Shale reportable segment follows.

	Marcellus Shale
	Year ended December 31,								Percentage Change
	2019			2018			2017		2019 v. 2018			2018 v. 2017
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	24,471		$	29,573		$	30,394		(17	%)		(3	%)
Total revenues		24,471			29,573			30,394		(17	%)		(3	%)
Costs and expenses:
Operation and maintenance		3,861			4,813			6,057		(20	%)		(21	%)
General and administrative		521			397			449		31	%		(12	%)
Depreciation and amortization		9,141			9,090			9,047		1	%		0	%
Goodwill impairment		16,211			—			—		*			*
Total costs and expenses		29,734			14,300			15,553		108	%		(8	%)
Add:
Depreciation and amortization		9,141			9,090			9,047
Goodwill impairment		16,211			—			—
Adjustments related to capital reimbursement activity		(38	)		(96	)		—
Segment adjusted EBITDA	$	20,051		$	24,267		$	23,888		(17	%)		2	%

* Not considered meaningful

Year ended December 31, 2019. Segment adjusted EBITDA decreased $4.2 million compared to the year ended December 31, 2018, primarily reflecting:

• a $5.1 million decrease in gathering services and related fees as a result of volume declines partially offset by additional drilling and completion activities.

• a $1.0 million decrease in operation and maintenance expense primarily due to a decrease in various operating expenses.

Other items to note:

• In September 2019, we recorded a goodwill impairment charge of $16.2 million relating to the Mountaineer Midstream system in the Marcellus Shale (see Note 7 to the consolidated financial statements). This noncash impairment expense had no impact on segment adjusted EBITDA for the year ended December 31, 2019.

EX 99.2-26

Year ended December 31, 2018. Segment adjusted EBITDA increased $0.4 million compared to the year ended December 31, 2017, primarily reflecting:

• a $0.8 million decrease in gathering services and related fees as a result of volume declines.

• a $1.2 million decrease in operation and maintenance expense primarily due to declines in expenses for repairs to right-of-way of $0.9 million and lower property taxes of $0.7 million during the period.

Corporate and Other Overview for the Years Ended December 31, 2019, 2018 and 2017

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 and the early extinguishment of debt.

	Corporate and Other
	Year ended December 31,						Percentage Change
	2019		2018		2017		2019 v. 2018			2018 v. 2017
	(Dollars in thousands)
Revenues:
Total revenues	$	27,622	$	78,161	$	19,517		*			*
Costs and expenses:
Cost of natural gas and NGLs		26,107		78,172		19,264		*			*
General and administrative		50,797		49,175		49,162		3	%		0	%
Transaction costs		3,017		—		50
Interest expense		91,966		82,830		88,701		11	%		(7	%)
Early extinguishment of debt (1)		—		—		22,039		*			*

* Not considered meaningful

(1) 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.

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 $50.5 million compared to the year ended December 31, 2018 was attributable to lower natural gas, NGL and crude oil marketing activity.

The increase of $58.6 million compared to the year ended December 31, 2017 was attributable to higher 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 $52.1 million compared to the year ended December 31, 2018 was attributable to lower marketing activity.

The increase of $58.9 million compared to the year ended December 31, 2017 was attributable to higher marketing activity.

General and Administrative. General and administrative expense increased $1.6 million compared to the year ended December 31, 2018, primarily due to a $7.5 million increase in severance and restructuring expenses partially offset by lower headcount associated with our cost cutting initiatives and lower performance-based compensation.

General and administrative expense were flat compared to the year ended December 31, 2017.

Transaction costs. Transaction costs recognized during the year ended December 31, 2019 primarily relate to $2.1 million in financial advisory costs associated with restructuring the equity of certain subsidiaries in 2019.

EX 99.2-27

Interest Expense. Interest expense increased $9.1 million compared to the year ended December 31, 2018 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.

Interest expense decreased $5.9 million compared to the year ended December 31, 2017 as a result of (i) the tender and redemption of the $300.0 million principal 7.5% Senior Notes, (ii) the issuance of 300,000 Series A Preferred Units in November 2017 whereby the net proceeds were used to repay outstanding borrowings under our Revolving Credit Facility, (iii) a lower average outstanding balance on the Revolving Credit Facility and (iv) a lower outstanding balance on the Term Loan B. The decrease was partially offset by the interest associated with issuance of the $500.0 million principal 5.75% Senior Notes and an increase in the interest rate on the Revolving Credit Facility.

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

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 in this Exhibit 99.2 on Form 8-K as of and for the year ended December 31, 2019.

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.

EX 99.2-28

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

	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 year ended December 31, 2019 follow.

	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.

Liquidity and Capital Resources

Based on the terms of our Partnership Agreement, we expect that we will make distributions to our unitholders with 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, future issuances of debt, preferred equity and equity securities and proceeds from potential asset divestitures.

Capital Markets Activity

January 2020 Shelf Registration Statement. In November 2019, we filed the 2020 SRS which registered an indeterminate amount of common units, preferred units, warrants, rights, debt securities and guarantees. In January 2020, the SEC declared the 2020 SRS effective. There have been no transactions executed on the 2020 SRS.

July 2017 Shelf Registration Statement. In July 2017, we filed the 2017 SRS with the SEC to issue an indeterminate amount of debt, equity securities and guarantees. In November 2017, we filed a post-effective amendment to the 2017 SRS with the SEC to register, in addition to the classes of securities originally registered, an indeterminate amount of preferred units representing limited partner interests in the Partnership. The 2017 SRS expires in July 2020. However, we are no longer a well-known seasoned issuer and are therefore not able to use the 2017 SRS.

The following transaction was executed pursuant thereto:

• In November 2017, we issued 300,000 9.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership at a price to the public of $1,000 per unit. We used the net proceeds of $293.2 million (after deducting underwriting discounts and offering expenses) to repay outstanding borrowings under our Revolving Credit Facility.

EX 99.2-29

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 February 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 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 (the “ATM Program”). Sales of our common units may be made in negotiated transactions or transactions that are deemed to be at-the-market offerings as defined by SEC rules. During the years ended December 31, 2019 and 2018, we did not issue any units under the ATM Program. During the year ended December 31, 2017, we issued 763,548 units under the ATM Program for aggregate gross proceeds of $17.7 million, and paid approximately $0.2 million as compensation to the sales agents pursuant to the terms of the equity distribution agreement. Our General Partner made capital contributions to maintain its approximate 2% General Partner interest in SMLP.

The 2016 SRS expired in November 2019.

Debt

Revolving Credit Facility. We have a $1.25 billion senior secured Revolving Credit Facility. On May 26, 2017, Summit Holdings closed on the Third Amended and Restated Credit Agreement which extended the maturity from November 2018 to May 2022 (see Note 10 to the consolidated financial statements). As of December 31, 2019, the outstanding balance of the Revolving Credit Facility was $677.0 million and the unused portion totaled $563.9 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 December 31, 2019 was approximately $100 million. There were no defaults or events of default during 2019, and as of December 31, 2019, we were in compliance with the financial covenants in the Revolving Credit Facility. See Notes 10 and 16 to the 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 year ended December 31, 2019 on either series of senior notes.

SMP Holdings Term Loan. On March 21, 2017, SMP Holdings closed on a $300.0 million senior secured term loan facility, (the “Term Loan B”) with the maturity date of May 15, 2022. At December 31, 2019, the outstanding balance of the Term Loan B was $161.5 million and we were in compliance the Term Loan B’s financial covenants. There were no defaults or events of default during the year ended December 31, 2019.

For additional information on our long-term debt, see Notes 10 and 18 to the 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.

EX 99.2-30

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, cash equivalents and restricted cash were as follows:

	Year ended December 31,
	2019			2018			2017
	(In thousands)
Net cash provided by operating activities	$	161,741		$	206,230		$	213,048
Net cash used in investing activities		(90,870	)		(205,298	)		(147,886	)
Net cash (used in) provided by financing activities		(50,122	)		1,645			(63,129	)
Net change in cash, cash equivalents and restricted cash	$	20,749		$	2,577		$	2,033

Operating activities. Cash flows from operating activities for the year ended December 31, 2019, primarily reflected:

• a $7.3 million increase in cash interest payments; and

• other changes in working capital.

Cash flows from operating activities for the year ended December 31, 2018, primarily reflected:

• a $3.0 million decrease in cash interest payments primarily due to the extinguishment of the 7.5% Senior Notes in the first quarter of 2017;

• a decrease in distributions from equity method investees; and

• other changes in working capital.

Investing activities. Details of cash flows from investing activities follow.

Cash flows used in investing activities during the year ended December 31, 2019 primarily reflected:

• $182.3 million of capital expenditures primarily attributable to the ongoing development of the DJ Basin of $80.5 million, Summit Permian of $45.0 million, the Williston Basin of $30.9 million and Corporate and Other, which includes $17.7 million of capital expenditures relating to the Double E Project;

• $18.3 million for investments in the Double E joint venture relating to the Double E Project;

• $89.5 million of net proceeds from the Tioga Midstream sale and $12.0 million of proceeds from the Red Rock Gathering sale; and

• $7.3 million for a distribution from an equity method investment.

Cash flows used in investing activities during the year ended December 31, 2018 primarily reflected:

• $200.6 million of capital expenditures primarily attributable to the ongoing development of the Permian Basin of $83.8 million as well as the continued development in the DJ Basin of $64.9 million, and the Williston Basin of $25.2 million; and

• $4.9 million of capital contributions to Ohio Gathering.

Financing activities. Details of cash flows from financing activities follow.

Cash flows used in financing activities during the year ended December 31, 2019 primarily reflected:

• $218.1 million of distributions;

• $211.0 million of net borrowings under our Revolving Credit Facility;

• $65.3 million of payments on the Term Loan B; and

EX 99.2-31

• $27.4 of net proceeds from the issuance of Subsidiary Series A Preferred Units.

Cash flows used in financing activities during the year ended December 31, 2018 primarily reflected:

• $149.4 million of distributions;

• $205.0 million of net borrowings under our Revolving Credit Facility; and

• $49.3 million of payments on the Term Loan B.

Contractual Obligations Update

The table below summarizes our contractual obligations as of December 31, 2019.

	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(In thousands)
Long-term debt and interest payments (1)	$	1,936,866	$	91,481	$	1,273,510	$	57,500	$	514,375
Purchase obligations (2)		132,622		132,622		—		—		—
Finance leases (3)		1,991		1,299		692		—		—
Operating leases (3)		4,803		1,705		1,555		648		895
Total contractual obligations	$	2,076,282	$	227,107	$	1,275,757	$	58,148	$	515,270

(1) For the purpose of calculating future interest on the Revolving Credit Facility and the Term Loan B, assumes no change in balance or rate from December 31, 2019. Includes a 0.50% commitment fee on the unused portion of the Revolving Credit Facility and a 0.125% fronting fee on the outstanding but undrawn irrevocable standby letter of credit. See Note 10 to the consolidated financial statements.

(2) Represents agreements to purchase goods or services that are enforceable and legally binding.

(3) See Item 2. Properties and Note 16 to the consolidated financial statements.

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 year ended December 31, 2019, cash paid for capital expenditures totaled $182.3 million (see Note 4 to the consolidated financial statements) which included $14.2 million of maintenance capital expenditures. For the year ended December 31, 2019, there were no contributions to Ohio Gathering and we contributed $18.3 million to Double E (see Note 8 to the consolidated financial statements).

For the year ended December 31, 2018, cash paid for capital expenditures totaled $200.6 million, compared with $124.2 million for the year ended December 31, 2017 (see Note 4 to the consolidated financial statements). Maintenance capital expenditures totaled $21.4 million for the year ended December 31, 2018 compared to $15.6 million for the year ended December 31, 2017. For the year ended December 31, 2018, contributions to equity method investees totaled $4.9 million, compared with $25.5 million for the year ended December 31, 2017 (see Note 8 to the consolidated financial statements). The year-over-year increase in cash paid for capital expenditures primarily reflected the expansion of our existing gathering and processing complex in the DJ Basin with the addition of a new 60 MMcf/d cryogenic processing plant in addition to the development of our new associated natural gas gathering and processing system in the Permian Basin.

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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.

With the completion of our 60 MMcf/d DJ Basin processing plant and compression expansions in the Permian Basin, capital expenditures began to decline in the third and fourth quarter of 2019. 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 payments 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, Permian Holdco issued 30,000 Subsidiary Series A Preferred Units to TPG for net proceeds of $27.3 million.

We estimate that our 2020 capital program will range from $50 million to $70 million, including approximately $10 million related to our equity method investment in Double E.

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 agreement 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 and 11 to the consolidated financial statements.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the year ended December 31, 2019.

Critical Accounting Estimates

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

The estimates that we deem to be most critical to an understanding of our financial position and results of operations are those related to determination of fair value. The preparation and evaluation of these critical accounting estimates involve

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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. Our critical accounting estimates are as follows:

Recognition and Impairment of Long-Lived Assets

Our long-lived assets include property, plant and equipment and amortizing intangible assets.

Property, Plant and Equipment and Amortizing Intangible Assets. As of December 31, 2019, we had net property, plant and equipment with a carrying value of approximately $1.9 billion and net amortizing intangible assets with a carrying value of approximately $232.3 million.

When evidence exists that we will not be able to recover a long-lived asset’s carrying value through future cash flows, we write down the carrying value of the asset to its estimated fair value. We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable as well as in connection with any goodwill impairment evaluations.

With respect to property, plant and equipment and our amortizing intangible assets, the carrying value of a long-lived asset is not recoverable if the carrying value exceeds the sum of the undiscounted cash flows expected to result from the asset’s use and eventual disposal. In this situation, we recognize an impairment loss equal to the amount by which the carrying value exceeds the asset’s fair value. We determine fair value using an income-based and market-based approach in which we discount the asset’s expected future cash flows to reflect the risk associated with achieving the underlying cash flows. Any impairment determinations involve significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these estimates are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.

2019 Impairments. In the DJ Basin, we determined that certain processing plant assets related to our existing 20 MMcf/d plant would no longer be utilized due to our expansion plans for the Niobrara G&P system. Based on the results of the recoverability assessment and the conclusion that the carrying value was not fully recoverable, we recorded an impairment charge of $34.7 million related to these assets in the first quarter of 2019.

In the Piceance Basin, we sold certain Red Rock Gathering system assets for a cash purchase price of $12.0 million. Prior to closing, we recorded an impairment charge of $14.2 million in the fourth quarter of 2019 based on the expected consideration and the carrying value for the Red Rock Gathering system assets.

In the Barnett Shale, we determined that certain compressor station assets would be shut down and decommissioned. As a result, we recorded an impairment charge of $9.7 million related to these assets in the first quarter of 2019. Also in connection with this evaluation, we evaluated the related intangible assets associated therewith for impairment consisting of rights-of-way intangible assets. We concluded the rights-of-way intangible assets were also impaired and, as a result, we recorded an impairment charge of $0.5 million in the first quarter of 2019.

In the Permian Basin, in connection with the cancellation of a project, we determined certain processing plant assets and the related rights-of-way intangible assets would no longer be utilized. As a result, we recorded an impairment charge of $0.7 million and $0.6 million related to the processing plant assets and rights-of-way intangible assets, respectively, in the fourth quarter of 2019. See Notes 5 and 6 for additional details.

2018 Impairments. In December 2018, in connection with certain strategic initiatives, we performed a recoverability assessment of certain assets within the Williston Basin reporting segment. Based on the results, we concluded that the carrying value of certain long-lived assets related to the Tioga Midstream system within the Williston Basin were not fully recoverable. We recorded an impairment charge of $3.9 million related to these assets after comparing the fair value of the long-lived assets to their carrying values. In addition, we reviewed other assets that had been identified as potentially impaired and recognized long-lived asset impairments as detailed in Note 5 to the consolidated financial statements.

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2017 Impairments. In December 2017, in connection with certain strategic initiatives, we performed a financial review of certain assets within the Williston Basin reporting segment. This resulted in a triggering event that required us to perform a recoverability test. Based on the results of the test, we concluded that the carrying value of certain long-lived assets and the related intangible assets related to the Bison Midstream system in the Williston Basin were not fully recoverable. As a result, we recorded an impairment charge of $101.9 million related to the long-lived assets and $85.2 million related to contract intangibles assets.

For additional information, see Notes 2, 5 and 6 to the consolidated financial statements.

Goodwill. We evaluate goodwill for impairment annually on September 30 and whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value, including goodwill.

2019 Impairment Evaluation. We performed our annual goodwill impairment testing for the Mountaineer Midstream reporting unit as of September 30, 2019 using a combination of the income and market approaches. We determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value, including goodwill. As a result, we recognized a goodwill impairment charge of $16.2 million for the year ended December 31, 2019.

2018 and 2017 Impairment Evaluations. We performed our 2018 and 2017 annual goodwill impairment analysis as of September 30 and concluded that none of our goodwill had been impaired.

See Notes 2 and 7 for additional information.

Minimum Volume Commitments

Adjustments for MVC Shortfall Payments. We estimate the impact of expected MVC shortfall payments for inclusion in our calculation of segment adjusted EBITDA. Adjustments related to MVC shortfall payments account for:

• the net increases or decreases in deferred revenue for MVC shortfall payments and

• our inclusion of expected annual MVC shortfall payments. We also included a proportional amount of any historical and expected MVC shortfall payments in each quarter prior to the quarter in which we actually recognized the shortfall payment.

We estimate expected MVC shortfall payments based on assumptions including, but not limited to, contract terms, historical volume throughput data and expectations regarding future investment, drilling and production.

For additional information, see Notes 2, 4 and 9 to the consolidated financial statements and the “Results of Operations” and “Liquidity and Capital Resources—Credit and Counterparty Concentration Risks” sections herein.

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.

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

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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:

• our ability to sustain our current rate of cash distributions;

• 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, crude oil and produced water 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 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 its senior secured term loan facility;

• changes in tax status;

• the effects of litigation;

• changes in general economic conditions; and

• certain factors discussed elsewhere in this report.

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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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