Summit Midstream Partners
Annual Report 2020

Plain-text annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K ☒ ☐ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2020 or TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number: 001-35666 Summit Midstream Partners, LP (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 910 Louisiana Street, Suite 4200 Houston, TX (Address of principal executive offices) 45-5200503 (I.R.S. Employer Identification No.) 77002 (Zip Code) (832) 413-4770 (Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Securities Act: Title of each class Common Units Trading Symbol(s) Name of each exchange on which registered SMLP New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☐ Yes ☒ No Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Act. ☐ Yes ☒ No Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).☒ Yes ☐ No Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer Non-accelerated filer Emerging growth company ☐ ☒ ☐ Accelerated filer ☐ Smaller reporting company ☒ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No The aggregate market value of the common units held by non-affiliates of the registrant as of June 30, 2020, was $45,998,000. Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: Class Common Units As of February 26, 2021 6,110,092 units DOCUMENTS INCORPORATED BY REFERENCE None Table of Contents TABLE OF CONTENTS PART I Item 1. Business. Item 1A. Risk Factors. Item 1B. Unresolved Staff Comments. Item 2. Item 3. Item 4. PART II Item 5. Properties. Legal Proceedings. Mine Safety Disclosures. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Item 7A. Quantitative and Qualitative Disclosures about Market Risk. Item 8. Item 9. Financial Statements and Supplementary Data. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. Item 9A. Controls and Procedures. Item 9B. Other Information. Part III Item 10. Item 11. Item 12. Item 13. Directors, Executive Officers and Corporate Governance. Executive Compensation. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. Certain Relationships and Related Transactions, and Director Independence. Item 14. Principal Accounting Fees and Services. Part IV Item 15. Item 16. Signature Page Exhibits, Financial Statement Schedules. Form 10-K Summary. 2 10 10 31 65 65 66 66 67 67 70 97 98 134 134 137 138 138 143 157 159 161 162 162 166 167 Table of Contents CAUTIONARY STATEMENT REGARDING 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 or our subsidiaries 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 Annual Report on Form 10- K (this “Annual Report”). Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this paragraph. These risks and uncertainties include, among others: • • • • • • • • • • • • • • • • • • • our decision whether to pay, or our ability to grow, our cash distributions; fluctuations in natural gas, NGLs and crude oil prices, including as a result of political or economic measures taken by various countries or OPEC; the extent and success of our customers' drilling efforts, as well as the quantity of natural gas, crude oil and produced water volumes produced within proximity of our assets; the current and potential future impact of the COVID-19 pandemic on our business, results of operations, financial position or cash flows; failure or delays by our customers in achieving expected production in their natural gas, crude oil and produced water projects; competitive conditions in our industry and their impact on our ability to connect hydrocarbon supplies to our gathering and processing assets or systems; actions or inactions taken or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers; our ability to divest of certain of our assets to third parties on attractive terms, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets; the ability to attract and retain key management personnel; commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets; changes in the availability and cost of capital and the results of our financing efforts, including availability of funds in the credit and/or capital markets; restrictions placed on us by the agreements governing our debt and preferred equity instruments; the availability, terms and cost of downstream transportation and processing services; natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control; operational risks and hazards inherent in the gathering, compression, treating and/or processing of natural gas, crude oil and produced water; weather conditions and terrain in certain areas in which we operate; any other issues that can result in deficiencies in the design, installation or operation of our gathering, compression, treating and processing facilities; timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule; our ability to finance our obligations related to capital expenditures, including through opportunistic asset divestitures or joint ventures and the impact any such divestitures or joint ventures could have on our results; 3 Table of Contents • • • • • 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; changes in tax status; the effects of litigation; changes in general economic conditions; and certain factors discussed elsewhere in this report. Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of our common units, 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. Risk Factors Summary This summary briefly lists the principal risks and uncertainties facing our business, which are only a select portion of those risks. A more complete discussion of those risks and uncertainties is set forth in Part I, Item 1A of this Annual Report. Additional risks not presently known to us or that we currently deem immaterial may also affect us. If any of these risks occur, our business, financial condition or results of operations could be materially and adversely affected. Our business is subject to the following principal risks and uncertainties: Risks Related to COVID-19 • The COVID-19 pandemic, coupled with other current pressures on oil and gas prices resulting from the OPEC price war, has had, and is expected to continue to have, an adverse impact on our business, results of operations, financial position and cash flows. Risks Related to Our Operations • We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay distributions to holders of our common units. • We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of our customers could materially adversely affect our revenues, cash flows and ability to make cash distributions to our unitholders. • We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties and any material nonpayment or nonperformance by one or more of these parties could materially adversely affect our financial and operating results. • • • • Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders. Significant prolonged weakness in natural gas, NGL and crude oil prices could reduce throughput on our systems and materially adversely affect our revenues and ability to make cash distributions to our unitholders. Any significant decrease in the demand for natural gas and crude oil could reduce the volumes of natural gas and crude oil that we gather and process, which could adversely affect our business and operating results. Our industry is highly competitive, and increased competitive pressure could materially adversely affect our business and operating results. • We may not be able to renew or replace expiring contracts at favorable rates or on a long term basis. • • Interruptions in operations at any of our facilities may adversely affect our operations and cash flows and our ability to make cash distributions to our unitholders. Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could materially adversely affect our operational and financial results. 4 Table of Contents • We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations. Risks Related to Our Financing • Limited access to and/or availability of the commercial bank market, debt and equity capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements. • We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects, and may limit our flexibility to obtain financing. • We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful. • A portion of our revenues are directly exposed to changes in crude oil, natural gas and NGL prices, and our exposure may increase in the future. Regulatory and Environmental Policy Risks • We are under investigation by federal and state regulatory agencies over a pipeline rupture and release of produced water by one of our subsidiaries. The resolution of this matter could have a material adverse effect on our results of operations or cash flows. • We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. As a result, we may be required to expend significant funds for legal defense or to settle claims. Any such loss, if incurred, could be material. • • A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenues to decline or our operation and maintenance expenses to increase. Increased regulation of hydraulic fracturing could result in reductions or delays in customer production, which could materially adversely impact our revenues. • We are subject to FERC jurisdiction, federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements and state and local regulation, and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced. • We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities. • We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from various groups. Risks Inherent in an Investment in Us • • Because our common units are yield-oriented securities, increases in interest rates could materially adversely impact our unit price, our ability to issue equity or incur debt and our ability to make cash distributions to our unitholders. The market price of our common units may fluctuate significantly and, due to limited daily trading volumes, an investor could lose all or part of its investment in us. • We may issue additional units without unitholder approval, which would dilute existing ownership interests. Tax Risks • • Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced. The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations of applicable law, possibly on a retroactive basis. • We have engaged in recent transactions that generated substantial cancellation of debt (“COD”) income on a per unit basis relative to the trading price of our common units. We may engage in other transactions that result in substantial COD income or other gains in the future, and such events may cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to the unitholder. 5 Table of Contents The following chart provides a summarized view of our legal entity structure at December 31, 2020: ORGANIZATIONAL CHART 6 Table of Contents 2016 Drop Down 2022 Senior Notes 2025 Senior Notes AMI associated natural gas ASC ASU Audit Committee Bbl Bcf Bcfe/d Bison Midstream Board of Directors CAA CEA CERCLA CFTC Compensation Committee Compensation Consultant condensate Conflicts Committee CWA Deferred Purchase Price Obligation DFW Midstream DJ Basin Dodd-Frank Act DOT Double E Double E Project dry gas Energy Capital Partners EPA Epping EPU Equity Restructuring COMMONLY USED OR DEFINED TERMS the Partnership's March 3, 2016 acquisition from SMP Holdings of substantially all of (i) the issued and outstanding membership interests in Summit Utica, Meadowlark Midstream and Tioga Midstream and (ii) SMP Holdings’ 40% ownership interest in Ohio Gathering Summit Holdings' and Finance Corp.’s 5.5% senior unsecured notes due August 2022 Summit Holdings' and Finance Corp.’s 5.75% senior unsecured notes due April 2025 area of mutual interest; AMIs require that any production from wells drilled by our customers within the AMI be shipped on and/or processed by our gathering systems a form of natural gas which is found with deposits of petroleum, either dissolved in the crude oil or as a free gas cap above the crude oil in the reservoir Accounting Standards Codification Accounting Standards Update the audit committee of the Board of Directors one barrel; used for crude oil and produced water and equivalent to 42 U.S. gallons one billion cubic feet the equivalent of one billion cubic feet per day; generally calculated when liquids are converted into natural gas; determined using a ratio of six thousand cubic feet of natural gas to one barrel of liquids Bison Midstream, LLC the board of directors of our General Partner Clean Air Act Commodity Exchange Act Comprehensive Environmental Response, Compensation and Liability Act Commodity Futures Trading Commission the compensation committee of the Board of Directors Willis Towers Watson a natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions the conflicts committee of the Board of Directors Clean Water Act the deferred payment liability recognized in connection with the 2016 Drop Down, as subsequently amended; also referred to as DPPO DFW Midstream Services LLC Denver-Julesburg Basin Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 U.S. Department of Transportation Double E Pipeline, LLC the development and construction of a long-haul natural gas pipeline with an initial throughput capacity of 1.35 billion cubic feet per day that will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas natural gas primarily composed of methane where heavy hydrocarbons and water either do not exist or have been removed through processing or treating Energy Capital Partners II, LLC and its parallel and co-investment funds Environmental Protection Agency Epping Transmission Company, LLC earnings or loss per unit a series of transactions consummated on March 22, 2019, pursuant to which the Partnership cancelled its IDRs and converted its 2% economic GP interest to a non-economic GP interest in exchange for 8,750,000 SMLP common units, which were issued to SMP Holdings 7 Table of Contents Exchange Act FASB FERC Finance Corp. FTC GAAP General Partner GHG GP GP interest Grand River Guarantor Subsidiaries hub ICA IDRs IPO IRS LIBOR Mbbl Mbbl/d Mcf MD&A Meadowlark Midstream MMBtu MMcf MMcf/d Mountaineer Midstream MVC NAAQS NEPA NGA NGLs NGPA Niobrara G&P Non-Guarantor Subsidiaries NYSE OCC OGC Ohio Gathering OPA OpCo PHMSA play Permian Finance Permian Holdco Polar and Divide Polar Midstream Securities Exchange Act of 1934, as amended Financial Accounting Standards Board Federal Energy Regulatory Commission Summit Midstream Finance Corp. Federal Trade Commission accounting principles generally accepted in the United States of America Summit Midstream GP, LLC greenhouse gas(es) general partner 2.0% general partner interest of GP in the Partnership prior to the Equity Restructuring and a non-economic general partner interest after the Equity Restructuring Grand River Gathering, LLC Bison Midstream and its subsidiaries, Grand River and its subsidiaries, DFW Midstream, Summit Marketing, Summit Permian, Permian Finance, OpCo, Summit Utica, Meadowlark Midstream, Summit Permian II and Mountaineer Midstream geographic location of a storage facility and multiple pipeline interconnections Interstate Commerce Act incentive distribution rights initial public offering Internal Revenue Service London Interbank Offered Rate one thousand barrels one thousand barrels per day one thousand cubic feet Management's Discussion and Analysis of Financial Condition and Results of Operations Meadowlark Midstream Company, LLC one million British Thermal Units one million cubic feet one million cubic feet per day Mountaineer Midstream Company, LLC minimum volume commitment national ambient air quality standard National Environmental Policy Act Natural Gas Act natural gas liquids; the combination of ethane, propane, normal butane, iso-butane and natural gasolines that when removed from unprocessed natural gas streams become liquid under various levels of higher pressure and lower temperature Natural Gas Policy Act of 1978 Niobrara Gathering and Processing system Permian Holdco and Summit Permian Transmission New York Stock Exchange Ohio Condensate Company, L.L.C. Ohio Gathering Company, L.L.C. Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C. Oil Pollution Control Act Summit Midstream OpCo, LP Pipeline and Hazardous Materials Safety Administration a proven geological formation that contains commercial amounts of hydrocarbons Summit Midstream Permian Finance, LLC Summit Permian Transmission Holdco, LLC the Polar and Divide system; collectively Polar Midstream and Epping Polar Midstream, LLC 8 Table of Contents produced water PSD RCRA Red Rock Gathering Revolving Credit Facility SEC Securities Act segment adjusted EBITDA Senior Notes Series A Preferred Units shortfall payment SMLP SMLP Holdings SMLP LTIP SMP Holdings SPCC Sponsor Subsidiary Series A Preferred Units Summit Holdings Summit Investments Summit Niobrara Summit Marketing Summit Permian Summit Permian II Summit Permian Transmission Summit Utica Tcfe the Partnership throughput volume Tioga Midstream unconventional resource basin VOC wellhead water from underground geologic formations that is a by-product of natural gas and crude oil production Prevention of Significant Deterioration Resource Conservation and Recovery Act Red Rock Gathering Company, LLC the Fourth Amended and Restated Credit Agreement dated as of December 18,2020, as amended by the Third Amended and Restated Credit Agreement dated as of May 26, 2017, as amended by the First Amendment to Third Amended and Restated Credit Agreement dated as of September 22, 2017, the Second Amendment to Third Amended and Restated Credit Agreement dated as of June 26, 2019 and the Third Amendment to Third Amended and Restated Credit Agreement dated as of December 24, 2019 Securities and Exchange Commission Securities Act of 1933, as amended total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) unit- based and noncash compensation, (vii) impairments and (viii) other noncash expenses or losses, less other noncash income or gains The 5.5% Senior Notes and the 5.75% Senior Notes, collectively Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units the payment received from a counterparty when its volume throughput does not meet its MVC for the applicable period Summit Midstream Partners, LP SMLP Holdings, LLC SMLP Long-Term Incentive Plan Summit Midstream Partners Holdings, LLC, also known as SMPH Spill Prevention Control and Countermeasure Energy Capital Partners II, LLC and its parallel and co-investment funds; also known as Energy Capital Partners Series A Fixed Rate Cumulative Redeemable Preferred Units issued by Permian Holdco Summit Midstream Holdings, LLC Summit Midstream Partners, LLC Summit Midstream Niobrara, LLC Summit Midstream Marketing, LLC Summit Midstream Permian, LLC Summit Midstream Permian II, LLC Summit Permian Transmission, LLC Summit Midstream Utica, LLC the equivalent of one trillion cubic feet Summit Midstream Partners, LP and its subsidiaries the volume of natural gas, crude oil or produced water gathered, transported or passing through a pipeline, plant or other facility during a particular period; also referred to as volume throughput Tioga Midstream, LLC a basin where natural gas or crude oil production is developed from unconventional sources that require hydraulic fracturing as part of the completion process, for instance, natural gas produced from shale formations and coalbeds; also referred to as an unconventional resource play volatile organic compound(s) the equipment at the surface of a well, used to control the well's pressure; also, the point at which the hydrocarbons and water exit the ground 9 Table of Contents PART I Under GAAP, the GP Buy-In Transaction (as defined below) whereby the Partnership acquired Summit Investments, the parent company of the General Partner, and the General Partner became a wholly-owned subsidiary of the Partnership, the GP Buy-In Transaction was deemed a transaction between entities under common control with a change in reporting entity. As a result, the Partnership recast its financial statements for the periods preceding the GP Buy-In Transaction, during which the entities were under the common control of Summit Investments, to retrospectively reflect the GP Buy-In Transaction. 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 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 financial data included in this Annual Report 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, Summit Investments, for accounting purposes. ITEM 1. BUSINESS Summit Midstream Partners, LP, a Delaware limited partnership (including its subsidiaries, collectively, “we”, “our”, “us”, "SMLP", or “the Partnership”), is 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. Our common units are listed and traded on the NYSE under the ticker symbol “SMLP.” The Partnership was formed in May 2012. The Partnership’s executive offices are located at 910 Louisiana Street, Suite 4200, Houston, Texas 77002, and can be reached by phone at 832-413-4770. The Partnership also maintains regional field offices in close proximity to our areas of operation to support the operation and development of our midstream assets. As a result of the GP Buy-In Transaction (as described below), the Partnership indirectly owns its General Partner, and the General Partner’s Board of Directors is comprised of a majority of independent directors. The Partnership’s Fourth Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”) provides the Partnership’s common unitholders with voting rights in the election of the members of the Board of Directors on a staggered basis beginning in 2022. Our Business Strategies We operate a differentiated midstream platform that is built for long-term, sustainable value creation. Our integrated assets are strategically located in premier production basins and core demand centers, including the Williston Basin, DJ Basin, Utica Shale, Marcellus Shale, and Permian Basin. Our primary business objective is to provide cash flow stability for our stakeholders while growing prudently and profitably. We intend to accomplish this objective by executing the following strategies: • • Liability management. We seek to maximize unitholder value by reducing and extending, where appropriate, the Partnership’s indebtedness and other fixed capital obligations through a combination of opportunistic liability management transactions, operating cash flow, and other corporate transactions. Portfolio management. We seek to maximize unitholder value by strategically managing our portfolio of midstream assets and allocating capital based on appropriate risk-informed cash flow assumptions. This may include opportunistic divestitures, re-allocation of capital to new or existing areas, and development of joint ventures involving our existing midstream assets or new investment opportunities. • Maintaining our focus on fee-based revenue with minimal direct commodity price exposure. We intend to maintain our focus on providing midstream services under primarily long-term and fee-based contracts. We believe that our focus on fee-based revenues with minimal direct commodity price exposure is essential to maintaining stable cash flows. • Maintaining strong producer relationships to maximize utilization of all of our midstream assets. We have cultivated strong producer relationships by focusing on customer service, reliable project execution and by operating our assets safely and reliably over time. We believe that our strong producer relationships will create future opportunities to optimize the utilization of the gathering systems in our Legacy Areas and develop new midstream infrastructure in our Core Focus Areas. 10 Table of Contents • Continuing to prioritize safe and reliable operations. We believe that providing safe, reliable and efficient operations is a key component of our business strategy. We place a strong emphasis on employee training, operational procedures and enterprise technology, and we intend to continue promoting a high standard with respect to the efficiency of our operations and the safety of all of our constituents. Recent Developments and Highlights The following is a brief listing of significant developments since December 31, 2019. Additional information regarding these items may be found elsewhere in this Annual Report. • • • • • • GP Buy-In Transaction. In May 2020, the Partnership completed a simplification transaction (the “GP Buy-In Transaction”) whereby the Partnership acquired from its then private equity sponsor, Energy Capital Partners (“ECP”), (i) Summit Midstream Partners, LLC (“Summit Investments”), which owned the Partnership’s General Partner, (ii) through its indirect ownership of Summit Midstream Partners Holdings, LLC (“SMP Holdings”), 3,415,646 of its common units and (iii) the Deferred Purchase Price obligation receivable owed by the Partnership. Consideration paid to ECP included a $35.0 million cash payment and the issuance of warrants to purchase up to 666,667 common units. In connection with the closing of the GP Buy-In Transaction, ECP’s management resigned from the Board of Directors and ECP fully exited its investment in the Partnership (other than retaining the aforementioned warrants). Suspension of common and preferred unit distributions. In May 2020, and in conjunction with the GP Buy-In Transaction, the Partnership suspended distributions to holders of its common units and its Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. The suspension of distributions enabled the Partnership to retain an incremental $76.0 million per annum of operating cash flow and reallocate this retained cash to indebtedness reduction, liability management transactions and other corporate initiatives. The unpaid cash distributions on the Series A Preferred Units continue to accrue semi-annually, until paid. Liability Management - Open Market Repurchases. Throughout 2020, the Partnership completed multiple open market repurchases of the 2022 Senior Notes and 2025 Senior Notes that resulted in the extinguishment of $32.4 million of face value of the 2022 Senior Notes and $201.8 million of face value of the 2025 Senior Notes (the “Open Market Repurchases”). Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 Senior Notes and 2025 Senior Notes, plus accrued interest totaled $150.3 million and the Partnership recognized an $86.5 million gain on the extinguishment of debt related to these Open Market Repurchases during 2020. Liability Management - Debt Tender Offers. In September 2020, Summit Holdings and Finance Corp. (together with Summit Holdings, the “Co-Issuers”) completed cash tender offers (the “Debt Tender Offers”) to purchase a portion of their 2022 Senior Notes and 2025 Senior Notes. Upon completion of the Debt Tender Offers, the Co-Issuers repurchased $33.5 million principal amount of the 2022 Senior Notes and $38.7 million principal amount of the 2025 Senior Notes. Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 and 2025 Senior Notes, plus accrued interest, totaled $48.7 million, and the Partnership recognized a $23.3 million gain on the extinguishment of debt related to the Debt Tender Offers during 2020. Liability Management - SMPH Term Loan Restructuring. In November 2020, the Partnership completed a consensual debt discharge and restructuring (the “TL Restructuring”) of SMP Holdings’ $155.2 million term loan (“SMPH Term Loan”). All of the lenders under the SMPH Term Loan (the “Term Loan Lenders”) participated in the TL Restructuring. As part of the TL Restructuring, the Partnership paid SMP Holdings $26.5 million in cash as consideration to fully settle the deferred purchase price obligation, which SMP Holdings then paid to the Term Loan Lenders. In addition, the Term Loan Lenders executed a strict foreclosure (the “Strict Foreclosure”) on the 2,306,972 common units pledged as collateral under the SMPH Term Loan in full satisfaction of SMP Holdings’ outstanding obligations under the SMPH Term Loan. Reverse Unit Split. On November 9, 2020, after the close of trading on the NYSE, the Partnership effected a 1-for-15 reverse unit split (the “Reverse Unit Split”) of its common units. The common units began trading on a split-adjusted basis on November 10, 2020. Pursuant to the Reverse Unit Split, common unitholders received one common unit for every 15 common units owned at the close of business on November 9, 2020. Immediately prior to the 11 Table of Contents • • • Reverse Unit Split, there were 56,624,887 common units issued and outstanding and immediately after the Reverse Unit Split, the number of issued and outstanding common units decreased to 3,774,992. July 2020 Series A Preferred Unit Exchange. In July 2020, the Partnership completed an offer to exchange its Series A Preferred Units for newly issued common units (the “Preferred Exchange Offer”), whereby it issued 837,547 SMLP common units in exchange for 62,816 Series A Preferred Units. Upon closing the Preferred Exchange Offer, it eliminated $66.5 million of the Series A Preferred Unit liquidation preference amount due as of the settlement date. December 2020 Series A Preferred Unit Tender. In December 2020, the Partnership completed a cash tender offer for its Series A Preferred Units (the “Preferred Tender Offer”) whereby it accepted 75,075 Series A Preferred Units for a purchase price of $333.00 per Series A Preferred Unit and an aggregate purchase price of $25.0 million. Upon closing the Preferred Tender Offer, it eliminated $82.7 million of the Series A Preferred Unit liquidation preference amount due as of the settlement date. Double E Project FERC approval. In January 2021, Double E, a joint venture focused on the development of an interstate natural gas pipeline in which the Partnership indirectly owns a 70% equity interest and serves as the pipeline's operator and construction manager, received its Notice to Proceed (“NTP”) with construction, as well as approval of its implementation plan, from FERC. Prior to this, in October 2020, Double E received FERC approval of its application to construct and operate the Double E Project, pursuant to Section 7(c) of the Natural Gas Act. With the receipt of the 7(c) certificate and the NTP, construction on the Double E pipeline commenced in February 2021, and the pipeline is expected to be in-service by the end of 2021. Our Midstream Assets Our systems gather natural gas from pad sites, wells and central receipt points connected to our systems. Gathered natural gas volumes are then compressed, dehydrated, treated and/or processed for delivery to downstream pipelines serving processing plants and/or end users. We also contract with producers to gather crude oil and produced water from wells connected to our systems for delivery to downstream pipelines and third-party rail terminals in the case of crude oil and to third-party disposal wells in the case of produced water. We generally refer to all of the services our systems provide as gathering services. We classify our midstream energy infrastructure assets into two categories, our Core Focus Areas and our Legacy Areas. Further details on our Focus Areas and Legacy Areas are summarized below. • • 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 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 decrease our near-term capital expenditures in these Legacy Areas. Our Piceance Basin, Barnett Shale and Marcellus Shale reportable segments comprise our Legacy Areas. 12 Table of Contents Industry Overview and Commercial Arrangements We compete with other midstream companies, producers and intrastate and interstate pipelines. Competition for volumes is primarily based on reputation, commercial terms, service levels, access to end-use markets, geographic proximity of existing assets to a producer's acreage and available capacity. We may also face competition to gather production outside of our AMIs and attract producer volumes to our gathering systems. Additionally, we could face incremental competition to the extent we make acquisitions. We earn revenue by providing gathering, compression, treating and/or processing services pursuant to primarily long-term and fee-based gathering and processing agreements with some of the largest and most active producers in North America. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure. The significant features of our gathering and processing agreements and the gathering systems to which they relate are discussed in more detail below. For additional operating and financial performance information, on a consolidated basis and by reportable segment, see the "Results of Operations" section in Item 7. MD&A. Areas of Mutual Interest. The vast majority of our gathering and processing agreements contain AMIs, some of which extend through 2036. The AMIs generally require that any production by our customers within the AMIs will be shipped on and/or processed by our assets. In general, our customers have not leased acreage that cover our entire AMIs but, to the extent that they have leased acreage, or lease additional acreage in the future, within our AMIs, any production from wells drilled by them within that AMI will be dedicated to our systems. Under certain of our gathering agreements, we have agreed to construct pipeline laterals to connect our gathering systems to producer pad sites located within the AMI. However, in certain circumstances we may choose not to fund a pad connection opportunity presented by a customer or we may choose not to fund capital calls in Ohio Gathering if we believe that the investment would not meet our internal return expectations. Under this scenario, the customer may, in certain circumstances, construct the infrastructure itself and sell it to us at a price equal to their cost plus an applicable profit margin, or, in some cases, we may release the relevant acreage dedication from the AMI. For Ohio Gathering, our joint venture partner may elect to fund 100% of the capital calls, if we choose not to fund our proportionate share of a given capital call, which could reduce our ownership interests in OGC and/or OCC. For example, in 2020, we chose not to fund capital calls at OGC and OCC, and as a result, our ownership interest in those ventures was reduced from 40% to 38.2% and 40% to 38.2%, respectively, as of December 31, 2020. Minimum Volume Commitments. Certain of our gathering and/or processing agreements contain MVCs which, like AMIs, benefit the development and ongoing operation of a gathering system because they provide a minimum contracted monthly or annual revenue stream. As of December 31, 2020, we had remaining MVCs totaling 1.4 Tcfe. Our MVCs had a weighted-average remaining life of 4.9 years (assuming contracted MVCs for the remainder of the term) and average approximately 0.9 Bcfe/d through 2023. In addition, certain of our customers have an aggregate MVC, which is a total amount of volume throughput that the customer has agreed to ship and/or process on our systems (or an equivalent monetary amount) over the MVC term. In these cases, once a customer achieves its aggregate MVC, any remaining future MVCs will terminate and the customer will then simply pay the applicable gathering or processing rate multiplied by the actual throughput volumes shipped or processed, pursuant to the contract. As a result of this mechanism, in many cases, the weighted-average remaining period for which our MVCs apply is less than the weighted-average of the remaining contract life. For additional information on our MVCs, see Notes 3 and 8 to the consolidated financial statements. Our financial results are primarily driven by volume throughput across our gathering systems and by expense management. During 2020, aggregate natural gas volume throughput averaged 1,375 MMcf/d and crude oil and produced water volume throughput averaged 79 Mbbl/d. 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 or volatility. We also earn a portion of our 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 in the Williston Basin, Piceance Basin, and Permian Basin segments, (ii) the sale of natural gas we retain from certain Barnett Shale customers and (iii) the sale of condensate we retain from our gathering services in the Piceance Basin segment. During the year ended December 31, 2020, these additional activities accounted for approximately 13% of total revenues. 13 Table of Contents In addition, the vast majority of our gathering and/or processing agreements in both our Core Focus Areas and our Legacy Areas include AMIs. Our AMIs cover approximately 2.8 million surface acres in the aggregate, which includes more than 0.8 million surface acres associated with Ohio Gathering. Certain of our gathering and processing agreements also include MVCs. To the extent the customer does not meet its MVC, it is contractually obligated to make an MVC shortfall payment to cover the shortfall of required volume throughput not shipped or processed, either on a monthly or annual basis. We have designed our MVC provisions to ensure that we will generate a minimum amount of revenue from each customer over the life of the associated gathering and/or processing agreement, by collecting gathering or processing fees on actual throughput or from cash payments to cover any MVC shortfall. As of December 31, 2020, we had remaining MVCs totaling 1.4 Tcfe. Our MVCs have a weighted-average remaining life of 4.9 years (assuming contracted MVCs for the remainder of the term) and average approximately 0.9 Bcfe/d through 2023. We use a variety of financial and operational metrics to analyze our performance, including among others, throughput volume, revenues, operation and maintenance expenses and segment adjusted EBITDA. We view each of these operational and/or GAAP metrics as important factors in evaluating our profitability and determining whether, and what amount of cash distributions, we pay to our unitholders. For additional information on our results of operations, see the “Results of Operations” section included in Item 7. MD&A. 14 Table of Contents Overview of Core Focus Areas and Legacy Areas Utica Shale (Core Focus Area). The following table provides operating information regarding our Utica Shale reportable segment as of December 31, 2020. Utica Shale Aggregate throughput capacity (MMcf/d) 720 Average daily MVCs through 2023 (MMcf/d) n/a Weighted- average remaining contract life (Years) Weighted- average remaining MVC life (Years) Remaining MVCs (Bcf) n/a 12.2 n/a The Summit Utica system is a natural gas gathering system located in Belmont and Monroe counties in southeastern Ohio and serves producers targeting the dry gas window of the Utica and Point Pleasant shale formations. The Summit Utica system gathers and delivers natural gas, primarily under long-term, fee-based gathering agreements, which include acreage dedications. XTO and Ascent are the key customers of Summit Utica. We have connected a substantial number of our customers’ pad sites to our gathering system and we expect to benefit in the near-term from incremental volumes arising from drilling and completion activity that is occurring and will continue to occur on previously connected pad sites. Over time, we intend to expand our midstream service offering for the Summit Utica system to connect additional customer pad sites and install centralized compression facilities. Centralized compression services have been dedicated to us in our gathering agreements and will eventually constitute a new revenue stream from our customers; however, to date, this service has not been required given the relatively high downhole pressures exhibited by dry gas wells in the Utica Shale compared to other unconventional shale plays. The Summit Utica system interconnects with the Ohio River System pipeline, which provides access to the Clarington Hub and Rover Pipeline. The Summit Utica system currently provides natural gas midstream services for the Utica Shale reportable segment. Ohio Gathering (Core Focus Area). Ohio Gathering comprises a natural gas gathering system and condensate stabilization facility located in the core of the Utica Shale in southeastern Ohio. The gathering system spans the condensate, liquids-rich and dry gas windows of the Utica Shale for multiple producers that are targeting production from the Utica and Point Pleasant shale formations across Belmont, Monroe, Guernsey, Harrison and Noble counties in southeastern Ohio and is operated by our partner, MPLX LP (“MPLX”). Substantially all gathering services on the Ohio Gathering system are provided pursuant to long-term, fee-based gathering agreements. Ascent and Gulfport are Ohio Gathering's key customers. AMIs for Ohio Gathering total approximately 825,000 surface acres in the aggregate. Condensate and liquids-rich natural gas production is gathered, compressed, dehydrated and delivered to the Cadiz and Seneca processing complexes, which offer approximately 1.3 Bcf/d of processing capacity and are owned by a joint venture between MPLX and The Energy and Minerals Group. Dry gas production is gathered, dehydrated, compressed, and delivered to third-party pipelines serving the northeast and midwest markets. As of December 31, 2020, we owned a 38.2% ownership interest in Ohio Gathering, which includes our ownership in OGC and OCC. For additional information, see Note 7 to the consolidated financial statements. 15 Table of Contents Williston Basin (Core Focus Area). The following table provides operating information regarding our Williston Basin reportable segment as of December 31, 2020. Williston Basin Aggregate throughput capacity - liquids (Mbbl/d) 255 Aggregate throughput capacity - natural gas (MMcf/d) 34 Average daily MVCs through 2023 (MMcfe/d)(1) 64 Remaining MVCs (Bcfe) (1) 70 Weighted- average remaining contract life (Years)(1)(2) 5.4 Weighted- average remaining MVC life (Years)(1)(2) 2.0 (1) Contract terms related to MVCs are presented for liquids and natural gas on a combined basis. (2) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate). AMIs for the Williston Basin reportable segment total approximately 1.2 million surface acres in the aggregate. Polar and Divide. The Polar and Divide system, which is located primarily in Williams and Divide counties in northwestern North Dakota, owns, operates and is currently developing crude oil and produced water gathering systems and transmission pipelines serving multiple customers that are targeting crude oil production from the Bakken and Three Forks shale formations. The Polar and Divide system is underpinned by long-term, fee-based gathering agreements, which include acreage dedications. Whiting, Zavanna and Bruin are the key customers of the Polar and Divide system. Crude oil that is gathered by the Polar and Divide system is delivered to interconnects with (i) the Dakota Access Pipeline, (ii) the COLT Hub rail facility, (iii) Enbridge Inc’s North Dakota Pipeline System and (iv) Global Partners LP's Basin Transload rail terminal. Produced water is delivered to third-party disposal facilities. The Polar and Divide system currently provides crude oil and produced water midstream services for the Williston Basin reportable segment. Bison Midstream. The Bison Midstream system is located in Mountrail and Burke counties in northwestern North Dakota. Bison Midstream gathers, compresses and treats associated natural gas that exists in the crude oil stream produced from the Bakken and Three Forks shale formations. Our gathering agreements for the Bison Midstream system include long-term, fee-based or percent-of-proceeds contracts. Volume throughput on the Bison Midstream system is underpinned by acreage dedications and MVCs from its key customers. A large U.S. independent crude oil and natural gas company and Oasis are the key customers of Bison Midstream. Natural gas gathered on the Bison Midstream system is delivered to Aux Sable Midstream LLC's (“Aux Sable”) Palermo Conditioning Plant in Palermo, North Dakota and then delivered to downstream pipelines serving Aux Sable’s 2.1 Bcf/d natural gas processing plant in Channahon, Illinois. The Bison Midstream system currently provides associated natural gas midstream services for the Williston Basin reportable segment. 16 Table of Contents DJ Basin (Core Focus Area). The following table provides operating information regarding our DJ Basin reportable segment as of December 31, 2020. DJ Basin Aggregate throughput capacity (MMcf/d) 60 Average daily MVCs through 2023 (MMcf/d) 8 Remaining MVCs (Bcf) 9 Weighted- average remaining contract life (Years)(1) 6.0 Weighted- average remaining MVC life (Years)(1) 2.2 (1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate). AMIs for the DJ Basin reportable segment total approximately 185,000 surface acres in the aggregate. The Niobrara G&P system is located near Hereford, Colorado, in Weld County, the largest crude oil and natural gas producing county in the state. Gathering and processing services on the Niobrara G&P system are provided pursuant to long-term, fee-based gathering agreements with producers that are primarily targeting crude oil production from the Niobrara and Codell shale formations. HighPoint and a large U.S. independent crude oil and natural gas company are the key customers of the Niobrara G&P system and have underpinned our volume throughput with acreage dedications and MVCs. The Niobrara G&P system operates a low-pressure associated natural gas gathering system, and a cryogenic natural gas processing plant with processing capacity of 60 MMcf/d. The Niobrara G&P system also processes liquids-rich natural gas that is produced by a customer in Laramie County, Wyoming and is delivered to the inlet of our processing plant by a third-party gathering system. Residue gas is delivered to the Colorado Interstate Gas and Trailblazer Pipeline and processed NGLs are delivered to the Overland Pass Pipeline. The Niobrara G&P system currently provides midstream services for the DJ Basin reportable segment. 17 Table of Contents Permian Basin (Core Focus Area). The following table provides operating information regarding our Permian Basin reportable segment as of December 31, 2020. Permian Basin(1) (1) Contract terms related to MVCs are excluded for confidentiality purposes. Aggregate throughput capacity (MMcf/d) 60 Average daily MVCs through 2023 (MMcf/d) n/a Weighted- average remaining contract life (Years) Weighted- average remaining MVC life (Years) Remaining MVCs (Bcf) n/a 7.5 n/a AMIs for the Permian Basin reportable segment total approximately 89,000 surface acres in the aggregate. The Summit Permian system is an associated natural gas gathering and processing system operating in the northern Delaware Basin in Eddy and Lea counties in New Mexico. Gathering and processing services on the Summit Permian system are provided pursuant to long-term, fee-based gathering agreements with producers that are primarily targeting crude oil production from the Bone Spring and Wolfcamp shale formations. XTO is the key customer of the Summit Permian system. The Summit Permian system operates a low-pressure natural gas gathering system and a 60 MMcf/d cryogenic processing plant. Residue natural gas is delivered to the Transwestern Pipeline and processed NGLs are delivered to the Lone Star NGL Pipeline. Summit Permian provides services for the Permian Basin reportable segment. 18 Table of Contents Double E (Core Focus Area). Double E is a 1.35 Bcf/d interstate 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. The Partnership owns 70% of Double E, is leading the development, permitting and construction of the pipeline, and will operate Double E upon commissioning. In January 2021, Double E received its Notice to Proceed with construction, as well as approval of its implementation plan, from FERC and expects the pipeline will be in-service by the end of 2021. Due to Double E’s early development status, its assets and operations are not included in a reportable segment. 19 Table of Contents Piceance Basin (Legacy Area). The following table provides operating information regarding our Piceance Basin reportable segment as of December 31, 2020. Piceance Basin Aggregate throughput capacity (MMcf/d) 1,151 Average daily MVCs through 2023 (MMcf/d) 369 Remaining MVCs (Bcf) 603 Weighted- average remaining contract life (Years)(1) 9.1 Weighted- average remaining MVC life (Years)(1) 4.9 (1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate). AMIs for the Piceance Basin reportable segment total approximately 654,000 surface acres in the aggregate. Grand River is primarily located in Garfield County, one of the largest natural gas producing counties in Colorado. The Grand River system provides natural gas gathering services pursuant to primarily long-term and fee-based agreements with multiple producers, including its key customers, Caerus Oil and Gas and Terra Energy Partners. Volume throughput on the Grand River system is underpinned with acreage dedications and MVCs. The Grand River system is primarily a low-pressure gathering system located in western Colorado that gathers natural gas produced from directional wells targeting the liquids-rich Mesaverde formation. The Grand River system also gathers natural gas produced from the Mancos and Niobrara shale formations. Natural gas gathered and/or processed on the Grand River system is compressed, dehydrated, processed and/or discharged to downstream pipelines serving (i) the Meeker Processing Complex, (ii) the Williams Processing Complex and (iii) the TransColorado Pipeline system. Processed NGLs from Grand River are injected into the Mid-America Pipeline system or delivered to local markets. In addition, certain of our gathering agreements with our customers on the Grand River system permit us to retain, and monetize for our own account, condensate volumes that naturally discharge from the liquids-rich natural gas as it moves across our system. The Grand River system currently provides midstream services for the Piceance Basin reportable segment. 20 Table of Contents Barnett Shale (Legacy Area). The following table provides operating information regarding our Barnett Shale reportable segment as of December 31, 2020. Barnett Shale Throughput capacity (MMcf/d) 450 Average daily MVCs through 2023 (MMcf/d) Remaining MVCs (Bcf) Weighted- average remaining contract life (Years)(1) Weighted- average remaining MVC life (Years)(1) n/a n/a 6.1 n/a (1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate). AMIs for the Barnett Shale reportable segment total approximately 124,000 surface acres. The DFW Midstream system is primarily located in southeastern Tarrant County, in north-central Texas. We consider this area to be the core of the core of the Barnett Shale because of the quality of the geology and the high production profile of the wells drilled to date. The DFW Midstream system is underpinned by a long-term, fee-based gathering agreement with Total and additional customers. The DFW Midstream system includes natural gas gathering pipelines located under both private and public property and is partially located along existing electric transmission corridors. Compression on the system is powered by electricity. To offset the costs we incur to operate the system's electric-drive compressors, we either pass through a portion of the power expense to our customers or retain a fixed percentage of the natural gas that we gather. The DFW Midstream system currently has six primary interconnections with third-party, primarily intrastate pipelines. These interconnections enable us to connect our customers, directly or indirectly, with the major natural gas market hubs in Texas and Louisiana. Total Gas & Power North America, Inc. ("Total") is the key customer for DFW Midstream. The DFW Midstream system currently provides midstream services for the Barnett Shale reportable segment. 21 Table of Contents Marcellus Shale (Legacy Area). The following table provides operating information regarding our Marcellus Shale reportable segment as of December 31, 2020. Marcellus Shale(1) (1) Contract terms related to MVCs are excluded for confidentiality purposes. Throughput capacity (MMcf/d) 1,050 Average daily MVCs through 2023 (MMcf/d) n/a Weighted- average remaining contract life (Years) Weighted- average remaining MVC life (Years) Remaining MVCs (Bcf) n/a n/a n/a The Mountaineer Midstream system is located in Doddridge and Harrison counties in West Virginia where it gathers natural gas under a long-term, fee- based contract with Antero, which is targeting liquids-rich natural gas production from the Marcellus Shale formation in the Appalachian Basin. Volume throughput on the Mountaineer Midstream system is underpinned by minimum revenue commitments from Antero. The Mountaineer Midstream system consists of a high-pressure natural gas gathering system and two compressor stations. This system gathers high- pressure natural gas received from upstream pipeline interconnections with Antero Midstream Corporation and Crestwood Equity Partners LP. Mountaineer Midstream serves as a critical inlet to the Sherwood Processing Complex, a primary destination for liquids-rich natural gas in northern West Virginia and one of the largest natural gas processing facilities in the United States. The Mountaineer Midstream system currently provides midstream services for the Marcellus Shale reportable segment. For additional information relating to our business and gathering systems, see the "Trends and Outlook" and "Results of Operations" sections in Item 7. MD&A. Our Customers The systems that we operate and/or have significant ownership interests in have a diverse group of customers and counterparties comprising affiliates and/or subsidiaries of some of the largest natural gas and crude oil producers in North America. We believe that our gathering systems in the Core Focus Areas are positioned for long-term growth through further development by our customers and increased utilization of our gathering systems. We intend to continue expanding our operations and creating additional scale in our Core Focus Areas through the execution of new, and the expansion of existing, strategic partnerships with our existing and prospective customers. We believe that our customers in our Legacy Areas will pursue a slower pace of drilling and completion activity than customers in our Core Focus Areas. As a result, volume throughput in our Legacy Areas could decline or experience a lower rate of growth than our gathering systems in our Core Focus Areas. In general, our gathering systems in our Legacy Areas have a more mature base of connected wells, larger and longer-lived MVCs and experience lower volume throughput decline rates as compared to our gathering systems in our Core Focus Areas. We will continue to evaluate divestitures or joint ventures of certain of our gathering systems included in our Core Focus Areas or our Legacy Areas, which could result in a reallocation of capital or other resources to repay outstanding debt and other liabilities and fixed capital obligations, or re-invest in our Core Focus Areas. Regulation of the Natural Gas and Crude Oil Industries General. Sales by producers of natural gas, crude oil, condensate and NGLs are currently made at market prices. However, gathering and transportation services are subject to various types of regulation, which may affect certain aspects of our business and the market for our services. FERC regulates the transportation of natural gas in interstate commerce and the interstate transportation of crude oil, petroleum products and NGLs. FERC regulation includes reviewing and accepting or approving rates and other terms and conditions for such transportation services and authorizing and regulating the construction and operation of interstate natural gas pipelines. FERC is also authorized to prevent and sanction market manipulation in natural gas markets while the FTC is authorized to prevent and sanction market manipulation in petroleum markets and the CFTC is authorized to prevent and sanction fraud and price manipulations in the commodity and futures markets, including the energy futures markets. State and municipal regulations may apply to the production and gathering of certain natural gas, the construction and operation of natural gas and crude oil facilities and the rates and practices of gathering systems and intrastate pipelines. 22 Table of Contents Regulation of Crude Oil and Natural Gas Exploration, Production and Sales. Sales of crude oil and NGLs are not currently regulated and are transacted at market prices. In 1989, the U.S. Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas. FERC, which has the authority under the NGA to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to its regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or FERC (with respect to the resale of gas in interstate commerce), however, could re-impose price controls in the future. Exploration and production operations are subject to various types of federal, state and local regulation, including, but not limited to, permitting, well location, methods of drilling, well operations and conservation of resources. While these regulations do not directly apply to our business, they may affect our customers' ability to produce natural gas. Regulation of the Gathering and Transportation of Natural Gas and Crude Oil. We believe that the majority of our natural gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC. Our Epping Pipeline interstate crude oil pipeline in North Dakota, which is owned and operated by Epping, is subject to FERC’s jurisdiction and oversight pursuant to FERC's authority under the ICA, and Epping has on file with FERC a tariff for interstate movements of crude oil on the pipeline. Additionally, in October 2020, Double E received FERC approval of its application to construct and operate the Double E Project, pursuant to Section 7(c) of the Natural Gas Act. The Double E Project is anticipated to provide interstate natural gas transmission service from the Delaware Basin in southeastern New Mexico to delivery points in and around the Waha Hub in Texas, will be subject to FERC jurisdiction. In 2018, FERC solicited public comment on its current policy on the certification of construction of new pipeline facilities, although it has not made any determinations yet on whether to make any changes to that policy. In addition to approving and regulating the construction and operation of interstate natural gas pipelines, FERC also regulates such pipelines’ rates and terms and conditions of service, including transportation service agreements and negotiated rate agreements. Under FERC’s ICA jurisdiction, rates for interstate movements of liquids by pipeline are currently regulated primarily through an annual indexing methodology, under which pipelines increase or decrease their existing rates in accordance with a FERC-specified adjustment that sets a rate ceiling. This adjustment, which may be positive or negative in a given year, is subject to review every five years. For the five-year period beginning on July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. In 2016, FERC proposed a policy change that would deny proposed index increases for pipelines under certain circumstances where revenues exceed cost-of-service by a certain percentage or where the proposed index increases exceed certain annual cost changes reported to FERC. FERC terminated this rulemaking on February 20, 2020 without adopting any part of the proposal. FERC completed its five-year review of its index adjustment by issuing an order on December 17, 2020 adopting a new annual index adjustment of the producer price index for finished goods plus 0.78% to become effective starting July 1, 2021. FERC’s order is subject to rehearing and possible judicial review. Under current FERC regulations, liquids pipelines can request a rate increase that exceeds the rate obtained through the indexing methodology by using a cost-of-service approach, but a pipeline must establish that a substantial divergence exists between its actual costs and the rates resulting from the indexing methodology. The rates charged by Epping may also be affected by FERC’s March 15, 2018 announcement of a revised policy eliminating the recovery of an income tax allowance in cost-of-service-based rates by FERC-jurisdictional crude oil and natural gas pipelines owned by master limited partnerships. FERC has not required oil pipelines on an industry-wide basis to decrease their rates to implement the new policy, but FERC has stated that the effects of the revised policy statement must be incorporated in annual FERC financial reports made by oil pipelines. The effect of the elimination of the income tax allowance for MLP pipelines, as well as the reduction in the corporate income tax rate resulting from the Tax Cuts and Jobs Act of 2017 (the “Tax Reform Legislation”), was considered in FERC’s five-year review of index rate adjustments which resulted in the December 17, 2020 order adopting a new annual index adjustment for the five-year period starting July 1, 2021. The ICA permits interested persons to challenge proposed new or changed rates and authorizes FERC to suspend the effectiveness of such rates for up to seven months and investigate such rates. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rate during the term of the investigation. FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Under certain circumstances, FERC could limit 23 Table of Contents Epping’s ability to set rates based on costs or could order reduced rates and reparations to complaining shippers for up to two years prior to the date of a complaint. FERC also has the authority to change terms and conditions of service if it determines that they are unjust and unreasonable or unduly discriminatory or preferential. The ICA also imposes potential criminal liability for certain violations of the statute. Intrastate pipelines, which may include some pipelines that perform gathering functions, may be subject to safety regulation by the DOT, although typically state regulatory authorities (operating under a federal certification) perform this function. State regulatory authorities also have jurisdiction over the rates and practices of intrastate pipelines and gathering systems, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight of gathering systems and intrastate pipelines varies from state to state. In Texas, we are regulated as a gas utility and have filed tariffs with the Railroad Commission of Texas to establish rates and terms of service for our DFW Midstream system assets. We have not been required to file tariffs in the other states in which we operate, although we are required to submit shape files and other information regarding the location and construction of underground gathering pipelines in North Dakota. The states in which we operate have adopted complaint-based regulation that allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve access issues and rate grievances, among other matters. State authorities in the states in which we operate generally have not initiated investigations of the rates or practices of gathering systems or intrastate pipelines in the absence of a complaint. State regulation of intrastate pipelines continues to evolve and may become more stringent in the future. For example, the North Dakota Industrial Commission (“NDIC”) recently adopted rule changes that resulted in additional construction and monitoring requirements for all pipelines, including, but not limited to, those that transport produced water, and has recently adopted reclamation bonding requirements for certain underground gathering pipelines in North Dakota. Natural gas, crude oil and produced water production, gathering and transportation, including the construction of new gathering facilities and expansion of existing gathering facilities may also be subject to local regulation, such as approval and permit requirements. Anti-Market Manipulation Rules. We are subject to the anti-market manipulation provisions in the NGA and the NGPA, as amended by the Energy Policy Act of 2005, which authorize FERC to impose fines of up to $1,307,164 per day per violation of the NGA, the NGPA, or their implementing regulations, subject to future adjustments for inflation. In addition, the FTC holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1,246,249 per violation, subject to future adjustment for inflation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The CFTC is directed under the CEA to prevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to statutory authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,227,202 per day per violation, subject to future adjustment for inflation, or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation. Safety and Maintenance. We are subject to regulation by the DOT, which establishes federal safety standards for the design, construction, operation and maintenance of natural gas and crude oil pipeline facilities. In the Pipeline Safety Act of 1992, Congress expanded the DOT's regulatory authority to include regulated gathering lines that had previously been exempt from federal jurisdiction. Additional legislation has been passed over the years to reauthorize federal funding for federal pipeline programs, increase penalties for safety violations and establish additional safety requirements. For example, in December 2020, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020 became law, reauthorizing PHMSA for funding through 2023 and requiring, among other things, rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines. The DOT has delegated the implementation of pipeline safety requirements to PHMSA, which has adopted and enforces safety standards and procedures applicable to a limited number of our pipelines. In addition, many states, including the states in which we operate, have adopted regulations that are identical to or more restrictive than existing PHMSA regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management 24 Table of Contents programs for certain pipelines located in high consequence areas, which include high-population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream system is located. While the majority of our pipelines meet the DOT definition of gathering lines and are thus currently exempt from the integrity management requirements of PHMSA, we also operate a limited number of pipelines that are subject to the integrity management requirements. Those regulations require operators, including us, to: • • • • • • perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; maintain processes for data collection, integration and analysis; repair and remediate pipelines as necessary; adopt and maintain procedures, standards and training programs for control room operations; and implement preventive and mitigating actions. In October 2019, the PHMSA issued three new final rules. One rule, which became effective in December 2019, establishes procedures to implement the expanded emergency order enforcement authority set forth in an October 2016 interim final rule. Among other things, this rule allows the PHMSA to issue an emergency order without advance notice or opportunity for a hearing. The other two rules, which became effective in July 2020, impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extends the requirement to conduct integrity assessments beyond “high consequence areas” (“HCAs”) to pipelines in “moderate consequence areas” (“MCAs”). It also includes requirements to reconfirm Maximum Allowable Operating Pressure (“MAOP”), report MAOP exceedances, consider seismicity as a risk factor in integrity management, and use certain safety features on in-line inspection equipment. PHMSA modified the rule in July 2020, in response to a petition for reconsideration, to limit the rule’s recordkeeping requirement related to class location changes to gas transmission pipelines (not gas distribution pipelines) and to clarify that the rule’s reconfirmation requirements related to MAOP is limited to segments without traceable, verifiable and complete pressure test records. The rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events, and adds a requirement to make all lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. Gathering systems like ours are also subject to a number of federal and state laws and regulations, including the Federal Occupational Safety and Health Act and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the Occupational Safety and Health Administration hazard communication standard, EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and the public. Environmental Matters General. Our operation of pipelines and other assets for the gathering, treating and/or processing of natural gas and the gathering of crude oil and produced water is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these assets, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as: • • • • requiring the installation of pollution-control equipment or otherwise restricting the way we operate; limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species; delaying system modification or upgrades during permit reviews; requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and 25 Table of Contents • enjoining the operations of facilities deemed to be in non-compliance with permits or permit requirements issued pursuant to or imposed by such environmental laws and regulations. Failure to comply with these laws and regulations may trigger administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. The trend in environmental regulation is to place more stringent requirements, resulting in more restrictions and limitations, on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing and future regulations. The following is a discussion of the material environmental laws and regulations that relate to our business. Hazardous Substances and Waste. Our operations are subject to environmental laws and regulations relating to the management and release of solid and hazardous wastes and other substances, including hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. Furthermore, the Toxic Substances Control Act and analogous state laws, impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities. CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. We also generate industrial wastes that are subject to the requirements of the RCRA and comparable state statutes. While the RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Although we generate minimal hazardous waste, it is possible that non-hazardous wastes, which could include wastes currently generated during our operations, will in the future be designated as hazardous wastes and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes. We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although we believe that the previous operators utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal, without our knowledge. These properties and the wastes disposed thereon may be subject to CERCLA, the RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition. Air Emissions. Our operations are subject to the federal CAA and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and also impose various monitoring, control and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and criminal enforcement actions. Furthermore, we may be required to incur certain capital expenditures in the future to obtain and maintain operating permits and approvals for air pollutant emitting sources. 26 Table of Contents In October 2015, the EPA issued a new lower NAAQS for ozone. The previous ozone standard was set at 75 parts per billion ("ppb"). The revised standard has been lowered to 70 ppb. The lowered ozone NAAQS could subject us to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements and increased permitting delays and costs. Impacts from the 2015 standard have not yet been determined, as states are still in the process of incorporating the new standard into their respective state implementation plans. We will continue to monitor developments to determine if any adverse effects on our operations can be expected. On June 3, 2016, the EPA finalized revisions to its 2012 New Source Performance Standard ("NSPS") OOOO for the oil and gas industry, to reduce emissions of greenhouse gases - most notably methane - along with smog-forming VOCs. The revisions, which are published in the Federal Register under Subpart OOOOa, included the addition of methane to the pollutants covered by the rule, along with requirements for detecting and repairing leaks at gathering and boosting stations. The revised rule applies to sources that have been modified, constructed, or reconstructed after September 18, 2015. In August 2020, the EPA issued two final rules that rescinded the methane-specific requirements of NSPS OOOO and OOOOa applicable to sources in the production and processing segments and removed the transmission and storage segment from the source category. However, these 2020 rules are being challenged in the U.S. Court of Appeals for the D.C. Circuit. In addition, President Biden’s January 20, 2021 Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directed EPA to consider publishing a proposed rule suspending, revising, or rescinding the 2020 rules, as well as to consider establishing methane and VOC emission standards for existing sources in the oil and gas sector, including the transportation and storage segments. On November 16, 2016 the Bureau of Land Management ("BLM") issued a final rule to reduce venting and flaring of natural gas on public and Indian lands. The final rule mirrors many of the requirements found in NSPS OOOOa, with additional natural gas royalty requirements for flared volumes at sites already connected to gas capture infrastructure. In September 2018, the BLM published a final rule that rescinded several requirements of this rule. However, in July 2020, the U.S. District Court for the Northern District of California vacated BLM’s 2018 revision rule. In addition, in October 2020, a Wyoming federal district judge vacated the 2016 venting and flaring rule. Environmental groups appealed the October 2020 decision in December 2020 and litigation is ongoing. While the rule, if implemented, is expected to have little or no direct impact on our operations, our customers that are primarily upstream wellhead operators may be impacted by the requirements in this rule. In recent years, the EPA has also demonstrated an increased focus on CAA compliance for natural gas gathering operations. For example, in September 2019, EPA issued an enforcement alert noting that EPA identified CAA noncompliance caused by unauthorized and/or excess emissions from depressurizing pig launchers and receivers in natural gas gathering operations. The alert discussed engineering, design, operations, and maintenance practices that EPA found that can cause noncompliance and summarizes engineering solutions to reduce emissions. This increased focus on natural gas gathering operations and any resulting enforcement actions by EPA or state agencies could subject us to monetary penalties, injunctions, conditions or restrictions on operations. Water Discharges. The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into regulated waters, which impacts our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits require us to control storm water runoff from some of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. Except as otherwise disclosed in this annual report, we believe that we are in substantial compliance with all applicable requirements of the CWA and analogous state laws and regulations relating to water discharges. Oil Pollution Control Act. The OPA requires the preparation of an SPCC plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility's operations comply with the requirements. To be in compliance, the facility's SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations 27 Table of Contents (intrafacility piping), inspections and records, security and training. Certain of our facilities are classified as SPCC-regulated facilities. We believe that they are in substantial compliance with all applicable requirements of OPA. Hydraulic Fracturing. Hydraulic fracturing is an important and increasingly common practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations and is primarily presently regulated by state agencies. However, Congress has in the past and may in the future consider legislation to regulate hydraulic fracturing by federal agencies or limit the ability of companies to engage in hydraulic fracturing. Many states have already adopted laws and/or regulations that require disclosure of the chemicals used in hydraulic fracturing. A number of states have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure and well construction requirements on oil and/or natural gas drilling activities. For example, a Colorado ballot initiative, Proposition 112, would have substantially increased setback distances for various upstream activities, thereby substantially restricting new oil and gas development in the state. Although Proposition 112 was defeated in the November 2018 elections, similar ballot initiatives have been circulated by interested groups for potential consideration in elections. Further, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the Colorado Oil and Gas Conservation Commission (“COGCC”), the state’s oil and gas regulator from fostering oil and gas development to regulating oil and gas development in a reasonable manner to protect public health and the environment. The new law also allows local governments to impose more restrictive requirements on oil and gas operations than those issued by the state and reduced the oil and gas representation on the COGCC. Further, in November 2020, the COGCC adopted new regulations that increase oil and gas setbacks to a minimum of 2,000 feet from schools and childcare facilities, prohibit routine venting and flaring, increase wildlife protections, and alter certain aspects of the permitting process. These regulations and similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. States also could elect to prohibit hydraulic fracturing altogether, as New York, Maryland, and Vermont have done. In addition, certain local governments have adopted, and additional local governments may adopt, ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. The EPA has also moved forward with various regulatory actions, including approving new regulations requiring green completions of hydraulically- fractured wells and corresponding reporting requirements that went into effect in 2015. Revisions to the green completion regulations were finalized in June 2016 and include additional requirements to reduce methane and VOCs. In August 2020, the EPA issued two final rules that rescinded the methane- specific requirements of these regulations applicable to sources in the production and processing segments and removed the transmission and storage segment from the source category. However, these 2020 rules are being challenged in the U.S. Court of Appeals for the D.C. Circuit. In addition, President Biden’s January 20, 2021 Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directed EPA to consider publishing a proposed rule suspending, revising, or rescinding the 2020 rules as well as to consider establishing methane and VOC emission standards for existing sources in the oil and gas sector, including the transportation and storage segments. The BLM has also asserted regulatory authority over aspects of the hydraulic fracturing process, and issued a final rule in March 2015 that established more stringent standards for performing hydraulic fracturing on federal and Indian lands. However, in December 2017, the BLM published a final rule rescinding the 2015 rule. The U.S. District Court for the Northern District of California upheld the December 2017 rescission rule in a March 2020 decision. The State of California and environmental plaintiffs then appealed the decision in June 2020. Litigation is currently ongoing. Further, several federal governmental agencies have conducted reviews and studies on the environmental aspects of hydraulic fracturing, including the EPA. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing. State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. Some state regulatory agencies, including those in Colorado, Ohio, and Texas, have modified their regulations or guidance to account for induced seismicity. These developments could result in additional regulation and restrictions on the use of injection disposal wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on our customers. Additionally, certain of our customers produce oil and gas on federal lands. On January 20, 2021, the Acting Secretary for the Department of the Interior signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. Then on January 27, 2021, President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. 28 Table of Contents If new or more stringent federal, state or local legal restrictions relating to drilling activities or to the hydraulic fracturing process are adopted, this could result in a reduction in the supply of natural gas and/or crude oil that our customers produce, and could thereby adversely affect our revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for our customers, which could ultimately decrease end-user demand for our services and could have a material adverse effect on our business. Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species. National Environmental Policy Act. The NEPA establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. Major projects having the potential to significantly impact the environment require review under NEPA. Many of our activities are covered under categorical exclusions which results in an expedited NEPA review process. Large upstream and downstream projects with significant cumulative impacts may be subject to longer NEPA review processes, which could impact the timing of those projects and our services associated with them. Climate Change. The EPA has adopted regulations under the CAA that, among other things, establish GHG emission limits from motor vehicles as well as establish PSD construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. EPA rules also require the reporting of GHG emissions from specified large GHG-emitting sources in the United States, including onshore and offshore oil and natural gas systems. We are required to report under these rules for our assets that have GHG emissions above the reporting thresholds. In October 2015, the EPA issued revisions to Subpart W of the GHG reporting rule to include reporting requirements for gathering and booster stations, onshore natural gas transmission pipelines, and completions and workovers of oil wells with hydraulic fracturing. This development resulted in increased monitoring and reporting for our operations and for upstream producers for whom we provide midstream services. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. In general, the number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that certain components of our operations, such as our gas-fired compressors, could become subject to state-level GHG-related regulation. Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions. The agreement entered into force in November 2016, after over 70 countries, including the United States, ratified or otherwise consented to be bound by the agreement. In November 2019, the United States submitted formal notification to the United Nations that it intended to withdraw from the agreement. However, on January 20, 2021, President Biden signed an “Acceptance on Behalf of the United States of America” that reversed the prior withdrawal, and the United States officially rejoined the Paris Agreement on February 19, 2021. In addition, shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change. Reentry into the Paris Agreement and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations, which could have a material adverse effect on our business and that of our customers. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG-emitting energy sources, our products would become more desirable in the market with more stringent limitations on GHG emissions. Conversely, to the extent that our products are competing with lower GHG-emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions. 29 Table of Contents Other Information Human Capital Resources. We recognize that our continued ability to attract, retain and motivate exceptional employees is vital to ensuring our long-term competitive advantage and the ability to create value for our unitholders. Our employees are critical to our long-term success and are essential to helping us meet our goals. Among other things, we support and incentivize our employees in the following ways: • • • Talent development, compensation and retention – We strive to provide our employees with a rewarding work environment, including the opportunity for success and a platform for personal and professional development. We provide a competitive benefits package designed to attract and retain a skilled and diverse workforce. We offer our employees a comprehensive benefits package, which includes company funded health plan options, vision and dental coverage, healthcare savings account, paid time off, parental leave and flexible spending accounts. We also provide professional training and development opportunities as well as education reimbursement. We also offer employees immediate eligibility in our 401(k) plan with company matching program. Health and safety – Employee health and safety in the workplace is one of our core values. Some of the ways in which we support the health and safety of our employees include wellness programs with incentives and employee assistance programs. Inclusion and diversity – We are committed to efforts to increase diversity and foster an inclusive work environment that supports our workforce. In addition to the variety of support services we provide to our employees under normal circumstances, our top priority during the ongoing COVID-19 pandemic remains protecting the health and well-being of our employees, customers, partners and communities. Since the onset of the COVID-19 pandemic, we have maintained a work-from-home policy for substantially all our employees, significantly limited business travel, and we have taken an integrated approach to helping our employees manage their work and personal responsibilities, with a strong focus on employee physical and mental health. As of December 31, 2020, the Partnership employed 220 people who provide direct, full-time support to our operations. None of our employees are covered by collective bargaining agreements, and we have never experienced any business interruption as a result of any labor disputes. Availability of Reports. We make certain filings with the SEC, including, among other filings, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through our website, www.summitmidstream.com, as soon as reasonably practicable after the date they are filed with, or furnished to, the SEC. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC through the SEC’s website, http://www.sec.gov. Our press releases and recent investor presentations are also available on our website. 30 Table of Contents Item 1A. Risk Factors. You should carefully consider the following risk factors in addition to the other information included in this Annual Report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common units: Risks Related to COVID-19 The COVID-19 pandemic, coupled with other current pressures on oil and gas prices resulting from the OPEC price war, has had, and is expected to continue to have, an adverse impact on our business, results of operations, financial position and cash flows. The ongoing COVID-19 outbreak continues to be a rapidly evolving situation. As of February 20, 2021, the CDC had recorded over 27.8 million cases in the United States and over 490,000 deaths. The pandemic has resulted in widespread adverse impacts on the global economy and on our business, including our customers, employees, supply chain, and distribution network. We are currently unable to predict the ultimate impact that it may have on our business, future results of operations, financial position or cash flows. The extent to which our operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including changes in the severity of the pandemic, countermeasures taken by governments, businesses and individuals to slow the spread of the pandemic, and the development and availability of treatments and vaccines and the extent to which these treatments and vaccines may remain effective as potential new strains of the coronavirus emerge. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown. In response to the COVID-19 pandemic, we have modified our business practices, including restricting employee travel, modifying employee work locations, implementing social distancing and enhancing sanitary measures in our facilities. Many of our suppliers, vendors and service providers have made similar modifications. The resources available to employees working remotely may not enable them to maintain the same level of productivity and efficiency, and these and other employees may face additional demands on their time. Our increased reliance on remote access to our information systems increases our exposure to potential cybersecurity breaches. We may take further actions as government authorities require or recommend or as we determine to be in the best interests of our employees, customers, partners and suppliers. There is no certainty that such measures will be sufficient to mitigate the risks posed by the virus, in which case our employees may become sick, our ability to perform critical functions could be impaired, and we may be unable to respond to the needs of our business. The resumption of normal business operations after such interruptions may be delayed or constrained by lingering effects of COVID-19 on our suppliers, third-party service providers, and/or customers. In the first half of 2020, oil prices declined significantly due to increases in supply emanating from a disagreement on production cuts among members of OPEC and certain non-OPEC, oil-producing countries and subsequent hydrocarbon commodity price declines. The resulting supply and demand imbalance disrupted the oil and natural gas exploration and production industry and other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. Although OPEC agreed in April 2020 to cut oil production and extended such production cuts through December 2020, there is no assurance that the agreement will continue to be observed by its members, and the responses of oil and gas producers to the lower demand for, and price of, natural gas, NGLs and crude oil are constantly evolving and remain uncertain. Continued pressure on demand. Such responses could cause our pipelines and storage tanks to reach capacity, thereby forcing producers to experience shut-ins or look to alternative methods of transportation for their products. In addition, the dramatic decrease in oil and gas prices could have substantial negative implications for our revenue sources that are related to or underpinned by commodity prices. As a result, these factors could have a material adverse effect on our business, future results of operations, financial position or cash flows. At this point, we cannot accurately predict the long-term effects current market conditions due to the COVID-19 pandemic and failed OPEC negotiations will have on our business, which will depend on, among other factors, the duration of the outbreak and the extent and overall economic effects of the governmental response to the pandemic. The impact of COVID-19 and the OPEC price war may also exacerbate other risks discussed below, any of which could have a material effect on us. This situation is changing rapidly, and additional impacts may arise that we are not aware of currently. 31 Table of Contents Risks Related to Our Operations We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, to enable us to pay distributions to holders of our common units. We may not have sufficient available cash from operating surplus each quarter to pay the distributions to holders of our common units. In May 2020, we suspended distributions to holders of our common units and our Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. We did not make a distribution on our common units with respect to any quarter in 2020, nor did we make a distribution on our Series A Preferred Units on June 15, 2020 or December 15, 2020. Further, we may not pay distributions on the common units or Series A Preferred Units in the foreseeable future, and there are restrictions on our ability to pay distributions under our outstanding indebtedness that restrict our ability to pay cash distributions on any of our equity securities. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things: • • • • • • • • • • • the volumes we gather, treat and process; the level of production of natural gas and crude oil (and associated volumes of produced water) from wells connected to our gathering systems, which is dependent in part on the demand for, and the market prices of, crude oil, natural gas and NGLs; damage to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters, accidents and acts of terrorism; leaks or accidental releases of hazardous materials into the environment; weather conditions and seasonal trends; changes in the fees we charge for our services; changes in contractual MVCs and our customer’s capacity to make MVC shortfall payments when due; the level of competition from other midstream energy companies in our areas of operation; changes in the level of our operating, maintenance and general and administrative expenses; regulatory action affecting the supply of, or demand for, crude oil, natural gas and NGLs, the fees we can charge, how we contract for services, our existing contracts, our operating and maintenance costs or our operating flexibility; and prevailing economic and market conditions. In addition, the actual amount of cash we have available for distribution to our common unitholders depends on other factors, some of which are beyond our control, including: • • • • • • • • • • the level and timing of capital expenditures we make; the level of our operating, maintenance and general and administrative expenses, including reimbursements of expenses incurred on our behalf by our General Partner; the cost of acquisitions, if any; our ability to sell assets, if any, and the price that we may receive for such assets; our debt service requirements and other liabilities; fluctuations in our working capital needs; our ability to borrow funds and access the debt and equity capital markets; restrictions contained in our debt agreements; the amount of cash reserves established by our General Partner; not receiving anticipated shortfall payments from our customers; 32 Table of Contents • • • adverse legal judgments, fines and settlements; distributions paid on our Series A Preferred Units, if any, or on the preferred stock of our subsidiaries; and other business risks affecting our cash levels. We depend on a relatively small number of customers for a significant portion of our revenues. For example, Caerus, a customer on our Piceance Basin gathering system accounts for over 10% of our aggregated revenue. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of our customers could materially adversely affect our revenues, cash flows and ability to make cash distributions to our unitholders. Certain of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our customers could have a material adverse effect on our revenues and cash flows and our ability to make cash distributions to our unitholders. We expect our exposure to concentrated risk of nonpayment or nonperformance to continue as long as we remain substantially dependent on a relatively small number of customers for a significant portion of our revenues. If any of our customers curtail or reduce production in our areas of operation, it could reduce throughput on our systems and, therefore, materially adversely affect our revenues, cash flows and ability to make cash distributions to our unitholders. Further, we are subject to the risk of non-payment or non-performance by our larger customers. We cannot predict the extent to which our customers’ businesses would be impacted if conditions in the energy industry deteriorate, nor can we estimate the impact such conditions would have on any of our customers’ abilities to execute their drilling and development programs or perform under our gathering and processing agreements. The low commodity price environment has negatively impacted natural gas producers causing some producers in the industry significant economic stress, including, in certain cases, to file for bankruptcy protection or to renegotiate contracts. To the extent that any customer is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any material non-payment or non-performance by our customers could adversely affect our business and operating results. We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties and any material nonpayment or nonperformance by one or more of these parties could materially adversely affect our financial and operating results. Although we attempt to assess the creditworthiness and associated liquidity of our customers, suppliers and contract counterparties, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. In addition, there can be no assurance that our contract counterparties will perform or adhere to existing or future contractual arrangements, including making any required shortfall payments or other payments due under their respective contracts. The policies and procedures we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, if necessary, requiring credit support, cannot fully eliminate counterparty credit risks. To the extent our policies and procedures prove to be inadequate, our financial and operational results may be negatively impacted. Some of our counterparties may be highly leveraged, have limited financial resources and/or have recently experienced a rating agency downgrade and will be subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. In addition, volatility in commodity prices could have a negative impact on our counterparties, which, in turn, could have a negative impact on their ability to meet their obligations to us. Any material nonpayment or nonperformance by any of our counterparties or suppliers could require us to pursue substitute counterparties or suppliers for the affected operations or reduce our operations. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results. 33 Table of Contents Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders. Our operations are focused on gathering, treating and processing services in the following unconventional resource basins, primarily shale formations: the Utica Shale, the Williston Basin, the DJ Basin, the Permian Basin, the Piceance Basin, the Barnett Shale and the Marcellus Shale. Due to our limited industry diversity, adverse developments in the natural gas and crude oil industries or in our existing areas of operation could have a significantly greater impact on our financial condition, results of operations and cash flows than if we did not have such limited diversity. Significant prolonged weakness in natural gas, NGL and crude oil prices could reduce throughput on our systems and materially adversely affect our revenues and cash available to make cash distributions to our unitholders. Lower natural gas, NGL and crude oil prices could negatively impact exploration, development and production of natural gas and crude oil, thereby resulting in reduced throughput on our gathering systems. Additionally, certain of our customers in each of our areas of operations have reduced, and others could reduce, drilling activity and capital expenditure budgets. If natural gas, NGL and/or crude oil prices remain at current levels or decrease, it could cause sustained reductions in exploration or production activity in our areas of operation and result in a further reduction in throughput on our systems, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders. Because of the natural decline in production from our customers' existing wells, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes that we gather and process could materially adversely affect our business and operating results. The customer volumes that support our business depend on the level of production from natural gas and crude oil wells connected to our systems, the production from which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our systems, we must obtain new sources of volume throughput. The primary factors affecting our ability to obtain new sources of volume throughput include (i) the level of successful drilling activity in our areas of operation and (ii) our ability to compete for new volumes on our systems. We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling and production decisions, which are affected by, among other things: • • • • • • • the availability and cost of capital; prevailing and projected hydrocarbon commodity prices; demand for crude oil, natural gas and other hydrocarbon products, including NGLs; levels of reserves; geological considerations; environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and the availability of drilling rigs and other costs of production and equipment. 34 Table of Contents Fluctuations in energy prices can also greatly affect the development of new crude oil and natural gas reserves. Drilling and production activities generally decrease as commodity prices decrease. In general terms, the prices of crude oil, natural gas and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include: • • • • • • • • • • • • worldwide economic and geopolitical conditions; global or national health concerns, including the outbreak of pandemic or contagious disease, such as COVID-19, which may continue to reduce demand for crude oil, natural gas and NGLs because of reduced global or national economic activity; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported liquefied natural gas (“LNG”); the ability to export LNG; the availability of transportation and storage systems with adequate capacity; the volatility and uncertainty of regional pricing differentials and premiums; the price and availability of alternative fuels, including alternative fuels that benefit from government subsidies; the effect of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of crude oil, natural gas and other hydrocarbon products, including NGLs. Because of these factors, even if new crude oil or natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, those reductions could reduce our revenues and cash flows and materially adversely affect our ability to make cash distributions to our unitholders. In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems, as several of the formations in the unconventional resource plays in which we operate generally have higher initial production rates and steeper production decline curves than wells in more conventional basins and may have steeper production decline curves than initially anticipated. Should we determine that the economics of our gathering, treating and processing assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, revenues associated with these assets will decline over time. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time, which will reduce our cash available for distribution. Many of our costs are fixed and do not vary with our throughput. These costs will not decline ratably or at all should we experience a reduction in throughput, which could result in a decline in our revenues and cash flows and materially adversely affect our ability to make cash distributions to our unitholders. Any significant decrease in the demand for natural gas and crude oil could reduce the volumes of natural gas and crude oil that we gather and process, which could adversely affect our business and operating results. The volumes of natural gas and crude oil that we gather and process depend on the supply and demand for natural gas and crude oil and other hydrocarbon products in the areas served by our assets. Natural gas and crude oil compete with other forms of energy available to users, including electricity, coal, other fuels and alternative energy sources. Increased demand for such forms of energy at the expense of natural gas and crude oil could lead to a reduction in demand for our services. Any such reduction could result in a decline in our revenues and cash flows and materially adversely affect our ability to make cash distributions to our unitholders. 35 Table of Contents If our customers do not increase the volumes they provide to our gathering systems, our ability to make cash distributions to our unitholders may be materially adversely affected. If we are unsuccessful in attracting new customers and/or new gathering opportunities with existing customers, our ability to make cash distributions to our unitholders will be impaired. Our customers are not obligated to provide additional volumes to our gathering systems, and they may determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. Reductions by our customers in our areas of mutual interest could result in reductions in throughput on our systems and materially adversely impact our ability to make cash distributions to our unitholders. Certain of our gathering and processing agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve. We designed those gathering and processing agreements that contain MVC provisions to generate stable cash flows for us over the life of the MVC contract term while also minimizing our direct commodity price risk. Under certain of these MVCs, our customers agree to ship a minimum volume on our gathering systems or send a minimum volume to our processing plants or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. In addition, our gathering and processing agreements may also include an aggregate MVC, which represents the total amount that the customer must flow on our gathering system or send to our processing plants (or an equivalent monetary amount) over the MVC term. If such customer’s actual throughput volumes are less than its MVC for the contracted measurement period, it must make a shortfall payment to us at the end of the applicable measurement period. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped or processed for the applicable period and the MVC for the applicable period, multiplied by the applicable fee. To the extent that a customer’s actual throughput volumes are above or below its MVC for the applicable contracted measurement period, certain of our gathering agreements contain provisions that allow the customer to use the excess volumes or the shortfall payment to credit against future excess volumes or future shortfall payments, which could have a material adverse effect on our results of operations, financial condition and cash flows and our ability to make cash distributions to our unitholders. We have not obtained independent evaluations of all of the reserves connected to our gathering systems; therefore, in the future, customer volumes on our systems could be less than we anticipate. We do not routinely obtain or update independent evaluations of the reserves connected to our systems. Moreover, even if we did obtain independent evaluations of all of the reserves connected to our systems, such evaluations may prove to be incorrect. Crude oil and natural gas reserve engineering requires subjective estimates of underground accumulations of crude oil and natural gas and assumptions concerning future crude oil and natural gas prices, future production levels and operating and development costs. Accordingly, we may not have accurate estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional volumes, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders. Our industry is highly competitive, and increased competitive pressure could materially adversely affect our business and operating results. We compete with other midstream companies in our areas of operations, some of which are large companies that have greater financial, managerial and other resources than we do. In addition, some of our competitors may have assets in closer proximity to natural gas and crude oil supplies and may have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct gathering systems that would create additional competition for the services we provide to our customers. Because our customers do not have leases that cover the entirety of our areas of mutual interest, non-customer producers that lease acreage within any of our areas of mutual interest may choose to use one of our competitors for their gathering and/or processing service needs. In addition, our customers may develop their own gathering systems outside of our areas of mutual interest. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be materially adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. 36 Table of Contents We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis. Our gathering, treating and processing contracts have terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing customers or enter into new contracts with other customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. Moreover, we may be unable to obtain areas of mutual interest from new customers in the future, and we may be unable to renew existing areas of mutual interest with current customers as and when they expire. The extension or replacement of existing contracts depends on a number of factors beyond our control, including: • • • • • the level of existing and new competition to provide gathering and/or processing services in our areas of operation; the macroeconomic factors affecting gathering, treating and processing economics for our current and potential customers; the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets; the extent to which the customers in our areas of operation are willing to contract on a long-term basis; and the effects of federal, state or local regulations on the contracting practices of our customers. To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenues and cash flows could decline and our ability to make cash distributions to our unitholders could be materially adversely affected. If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, our revenues and cash flows and our ability to make cash distributions to our unitholders could be materially adversely affected. Our gathering systems connect to third-party pipelines and other midstream facilities, such as processing plants, rail terminals and produced water disposal facilities. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable due to issues including, but not limited to, testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from other hazards. In addition, we do not have interconnect agreements with all of these pipelines and other facilities and the agreements we do have may be terminated in certain circumstances and/or on short notice. If any of these pipelines or other midstream facilities become unavailable for any reason, or, if these third parties are otherwise unwilling to receive or transport the natural gas, crude oil and produced water that we gather and/or process, our revenues, cash flows and ability to make cash distributions to our unitholders could be materially adversely affected. We have a relatively limited ownership history with respect to certain of our assets. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines and/or processing facilities that could have a material adverse effect on our business and operating results. We have a relatively limited history of operating certain of our assets. There may be historical occurrences or latent issues regarding certain of our pipeline systems of which we may be unaware and that may have a material adverse effect on our business and results of operations. Any significant increase in maintenance and repair expenditures or loss of revenue due to the condition of our pipeline systems could materially adversely affect our business and results of operations and our ability to make cash distributions to our unitholders. Crude oil and natural gas production and gathering may be adversely affected by weather conditions and terrain, which in turn could negatively impact the operations of our gathering, treating and processing facilities and our construction of additional facilities. Extended periods of below freezing weather and unseasonably wet weather conditions, especially in North Dakota, Ohio and West Virginia, can be severe and can adversely affect crude oil and natural gas operations due to the potential shut-in of producing wells or decreased drilling activities. These types of interruptions could result in a decrease in the volumes supplied to our gathering systems. Further, delays and shutdowns caused by severe weather may have a material negative impact on the 37 Table of Contents continuous operations of our gathering, treating and processing systems, including interruptions in service. These types of interruptions could negatively impact our ability to meet our contractual obligations to our customers and thereby give rise to certain termination rights and/or the release of dedicated acreage. Any resulting terminations or releases could materially adversely affect our business and results of operations. We also may be required to incur additional costs and expenses in connection with the design and installation of our facilities due to their locations and surrounding terrain. We may be required to install additional facilities, incur additional capital and operating expenditures, or experience interruptions in or impairments of our operations to the extent that the facilities are not designed or installed correctly. For example, certain of our pipeline facilities are located in mountainous areas such as our Utica Shale and Marcellus Shale operations, which may require specially designed facilities and special installation considerations. If such facilities are not designed or installed correctly, do not perform as intended, or fail, we may be required to incur significant expenditures to correct or repair the deficiencies, or may incur significant damages to or loss of facilities, and our operations may be interrupted as a result of deficiencies or failures. In addition, such deficiencies may cause damage to the surrounding environment, including slope failures, stream impacts and other natural resource damages, and we may as a result also be subject to increased operating expenses or environmental penalties and fines. Interruptions in operations at any of our facilities may adversely affect our operations and cash flows available for distribution to our unitholders. Our operations depend upon the infrastructure that we have developed and constructed. Any significant interruption at any of our gathering, treating or processing facilities, or in our ability to provide gathering, treating or processing services, could adversely affect our operations and cash flows available for distribution to our unitholders. Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as: • • • • • • unscheduled turnarounds or catastrophic events at our physical plants or pipeline facilities; restrictions imposed by governmental authorities or court proceedings; labor difficulties that result in a work stoppage or slowdown; a disruption in the supply of resources necessary to operate our midstream facilities; damage to our facilities resulting from production volumes that do not comply with applicable specifications; and inadequate transportation and/or market access to support production volumes, including lack of pipeline, rail terminals, produced water disposal facilities and/or third-party processing capacity. Any significant interruption at any of our gathering, treating or processing facilities, or in our ability to provide gathering, treating or processing services, could adversely affect our operations and cash flows available for distribution to our unitholders. Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant incident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant incidents or events for which we are insured, our operations and financial results could be materially adversely affected. Our operations are subject to all of the risks and hazards inherent in the operation of gathering, treating and processing systems, including: • • • • • damage to pipelines, processing plants, compression assets, related equipment and surrounding properties caused by tornadoes, floods, fires and other natural disasters and acts of terrorism; inadvertent damage from construction, vehicles, farm and utility equipment; leaks or losses resulting from the malfunction of equipment or facilities; ruptures, fires and explosions; and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. 38 Table of Contents These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of certain of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from such events. These events may also result in curtailment or suspension of our operations. A natural disaster or any event such as those described above affecting the areas in which we and our customers operate could have a material adverse effect on our operations. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on portions or all of our gathering systems. Potential customer impacts arising from service interruptions on segments of our gathering systems could include limitations on our ability to satisfy customer requirements, obligations to temporarily waive MVCs during times of constrained capacity, temporary or permanent release of production dedications, and solicitation of existing customers by others for potential new projects that would compete directly with our existing services. Such circumstances could materially adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business and results of operations and our ability to make cash distributions to our unitholders. Although we have a range of insurance programs providing varying levels of protection for public liability, damage to property, loss of income and certain environmental hazards, we may not be insured against all causes of loss, claims or damage that may occur. If a significant incident or event occurs for which we are not fully insured, it could materially adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of industry or market conditions, some of which are beyond our control, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, with regard to the assets we have acquired, we have limited indemnification rights to recover from the seller of the assets in the event of any potential environmental liabilities. We may fail to successfully integrate gathering system acquisitions into our existing business in a timely manner, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders, or fail to realize all of the expected benefits of the acquisitions, which could negatively impact our future results of operations. Integration of future gathering system acquisitions could be a complex, time-consuming and costly process, particularly if the acquired assets significantly increase our size and/or (i) diversify the geographic areas in which we operate or (ii) the service offerings that we provide. The failure to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. If any of the risks described above or in the immediately preceding risk factor or unanticipated liabilities or costs were to materialize with respect to future acquisitions or if the acquired assets were to perform at levels below the forecasts we used to evaluate them, then the anticipated benefits from the acquisition may not be fully realized, if at all, and our future results of operations and ability to make cash distributions to unitholders could be negatively impacted. Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could materially adversely affect our results of operations and financial condition. The construction of new assets, including for example Double E, involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such construction projects may also require the expenditure of significant amounts of capital, and financing, traditional or otherwise, may not be available on economically acceptable terms or at all. If we undertake these projects, our revenue may not increase immediately upon the expenditure of funds for a particular project and they may not be completed on schedule, at the budgeted cost, or at all. Moreover, we could construct facilities to capture anticipated future production growth in a region where such growth does not materialize or only materializes over a period materially longer than expected. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate due to the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput 39 Table of Contents to achieve our expected investment return, which could materially adversely affect our results of operations and financial condition. In addition, the construction of additions or modifications to our existing gathering, treating and processing assets and the construction of new midstream assets may require us to obtain federal, state and local regulatory environmental or other authorizations. The approval process for gathering, treating and processing activities has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering, treating and processing activities in new production areas. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions. As a result, we may be unable to obtain such authorizations and may, therefore, be unable to connect new volumes to our systems or capitalize on other attractive expansion opportunities. A future government shutdown could delay the receipt of any federal regulatory approvals. Additionally, it may become more expensive for us to obtain authorizations or to renew existing authorizations. If the cost of renewing or obtaining new authorizations increases materially, our cash flows could be materially adversely affected. We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations. We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate or if our pipelines are not properly located within the boundaries of such rights-of-way. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies either perpetually or for a specific period of time. If we were to be unsuccessful in renegotiating rights-of-way, we might have to relocate our facilities. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. Our ability to operate our business effectively could be impaired if we fail to attract and retain key personnel. Our ability to operate our business and implement our strategies depends on our continued ability to attract and retain highly skilled personnel with midstream energy industry experience and competition for these persons in the midstream energy industry is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business. A shortage of skilled labor in the midstream energy industry could reduce employee productivity and increase costs, which could have a material adverse effect on our business and results of operations. The operation of gathering, treating and processing systems requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our General Partner's employees, our business and results of operations and our ability to make cash distributions to our unitholders could be materially adversely affected. 40 Table of Contents Risks Related to Our Finances Limited access to and/or availability of the debt and equity capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements. To expand our asset base, whether through acquisitions or organic growth, we will need to make expansion capital expenditures. We also frequently consider and enter into discussions with third parties regarding potential acquisitions. In addition, the terms of certain of our gathering and processing agreements also require us to spend significant amounts of capital, over a short period of time, to construct and develop additional midstream assets to support our customers' development projects. Depending on our customers' future development plans, it is possible that the capital required to construct and develop such assets could exceed our ability to finance those expenditures using our cash reserves or available capacity under our Revolving Credit Facility. We plan to use cash from operations, incur borrowings and/or sell additional common units or other securities to fund our future expansion capital expenditures. Using cash from operations to fund expansion capital expenditures will directly reduce any cash available for distribution to unitholders. Our ability to obtain financing or to access the capital markets for future debt or equity offerings may be limited by (i) our financial condition at the time of any such financing or offering, (ii) covenants in our debt agreements, (iii) restrictions imposed by our Series A Preferred Units, (iv) general economic conditions and contingencies, (v) increasing disfavor among many investors towards investments in fossil fuel companies and (vi) general weakness in the debt and equity capital markets and other uncertainties that are beyond our control. In addition, lenders are facing increasing pressure to curtail their lending activities to companies in the oil and natural gas industry. 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 expansion capital expenditures and acquisition capital expenditures with the issuance of additional equity. We did not make a distribution on our common units with respect to any quarter in 2020, nor did we make a distribution on our Series A Preferred Units on June 15, 2020 or December 15, 2020, and these suspensions of distributions may further reduce demand for our common units or Series A Preferred Units. Further, we may not pay distributions on the common units or Series A Preferred Units in the foreseeable future, and there are restrictions on our ability to pay distributions under our outstanding indebtedness that restrict our ability to pay cash distributions on any of our equity securities. As such, if we are unable to raise expansion capital, we may lose the opportunity to make acquisitions, pursue new organic development projects, or to gather, treat and process new production volumes from our customers with whom we have agreed to construct and develop midstream assets in the future. Even if we are successful in obtaining external funds for expansion capital expenditures through the capital markets, the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional units representing limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to pay distributions to our unitholders, which could materially decrease our ability to pay such distributions. We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects, and may limit our flexibility to obtain financing and to pursue other business opportunities. At December 31, 2020, we had $1.3 billion of indebtedness outstanding and the unused portion of our $1.1 billion Revolving Credit Facility totaled $238.9 million, subject to an issued but undrawn letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of December 31, 2020 was approximately $105 million. See Note 9 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our debt obligations, including debt maturities for the next five years and thereafter. Our existing and future debt services obligations could have significant consequences, including among other things: • • • • limiting our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes and/or obtaining such financing on favorable terms; reducing our funds available for operations, future business opportunities and cash distributions to unitholders by that portion of our cash flow required to make interest payments on our debt; increasing our vulnerability to competitive pressures or a downturn in our business or the economy generally; and limiting our flexibility in responding to changing business and economic conditions. 41 Table of Contents Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control, such as commodity prices and governmental regulation. Restrictions in our Revolving Credit Facility and Senior Notes indentures could materially adversely affect our business, financial condition, results of operations, ability to make cash distributions to unitholders and value of our common units. We are dependent upon the earnings and cash flows generated by our operations to meet our debt service obligations and to make cash distributions to our unitholders, if any. The operating and financial restrictions and covenants in our Revolving Credit Facility, our Senior Notes indentures and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders. For example, our Revolving Credit Facility and Senior Notes indentures, taken together, restrict our ability to, among other things: • • • • • • • • • incur or guarantee certain additional debt; make certain cash distributions on or redeem or repurchase certain units; make certain investments and acquisitions; make certain capital expenditures; incur certain liens or permit them to exist; enter into certain types of transactions with affiliates; enter into sale and lease-back transactions and certain operating leases; merge or consolidate with another company or otherwise engage in a change of control transaction; and transfer, sell or otherwise dispose of certain assets. Our Revolving Credit Facility and Senior Notes indentures also contain covenants requiring us to maintain certain financial ratios and meet certain tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot guarantee that we will meet those ratios and tests. Based upon the terms of our Revolving Credit Facility and total outstanding debt of $1.3 billion (inclusive of $494 million of senior unsecured notes, net of debt issuance costs), our total leverage ratio first lien secured leverage ratio (as defined in the credit agreement) as of December 31, 2020, were 5.1 to 1.0 and 3.2 to 1.0, respectively, relative to maximum threshold limits of 5.75x and 3.5x. The provisions of our Revolving Credit Facility and Senior Notes indentures may affect our ability to obtain future financing and pursue attractive business opportunities as well as affect our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our Revolving Credit Facility or Senior Notes indentures could result in a default or an event of default that could enable our lenders and/or senior noteholders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, the lenders under our Revolving Credit Facility could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. The Revolving Credit Facility also has cross default provisions that apply to any other indebtedness we may have and the Senior Notes indentures have cross default provisions that apply to certain other indebtedness. Any of these restrictions in our Revolving Credit Facility and Senior Notes indentures could materially adversely affect our business, financial condition, cash flows and results of operations. We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful. Our ability to make scheduled payments on, or to refinance, our indebtedness obligations, including our Revolving Credit Facility and our Senior Notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. 42 Table of Contents If our operating cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to adopt alternative financing strategies, such as reducing or delaying investments and capital expenditures, selling assets, seeking additional capital or restructuring or refinancing our indebtedness, some or all of which may not be available to us on terms acceptable to us, if at all, or such alternative strategies may yield insufficient funds to make required payments on our indebtedness. Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets, including the market for senior unsecured notes, and our financial condition at the time. Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our Revolving Credit Facility and the indentures governing our Senior Notes place certain restrictions on our ability to dispose of assets and our use of the proceeds from such dispositions. We may not be able to consummate those dispositions on terms acceptable to us, if at all, and the proceeds of any such dispositions may not be adequate to meet any debt service obligations then due. Further, if for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors under those agreements to declare all outstanding indebtedness thereunder to be due and payable (which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements), the lenders under our Revolving Credit Facility could terminate their commitments to extend credit, and the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. If the amounts outstanding under our Revolving Credit Facility or our Senior Notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to our creditors. A downgrade of our credit rating could impact our liquidity, access to capital and our costs of doing business, and independent third parties determine our credit ratings outside of our control. A downgrade of our credit rating could increase our cost of borrowing under our Revolving Credit Facility and could require us to post collateral with third parties, including our hedging arrangements, which could negatively impact our available liquidity and increase our cost of debt. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when we are experiencing significant working capital requirements or otherwise lacking liquidity, our results of operations, financial condition and cash flows could be adversely affected. We have in the past and may in the future incur losses due to impairment in the carrying value of our long-lived assets or equity method investments. We recorded long-lived asset impairments of $13.1 million and $60.5 million in 2020 and 2019, respectively. In 2019, we also recorded an impairment of our equity method investment in Ohio Gathering of $329.7 million and a loss of $6.3 million related to a long-lived asset impairment on OCC. 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 long-lived assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. 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 either a market-based approach, an income-based approach in which we discount the asset's expected future cash flows to reflect the risk associated with achieving the underlying cash flows, or a mixture of both market- and income-based approaches. We evaluate our equity method investment for impairment whenever events or circumstances indicate that a decline in fair value is other than temporary. Any impairment determinations involve significant assumptions and judgments. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to impairment charges. Adverse changes in our business or the overall operating environment, such as lower commodity prices, may affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows. 43 Table of Contents A portion of our revenues are directly exposed to changes in crude oil, natural gas and NGL prices, and our exposure may increase in the future. During the year ended December 31, 2020, we derived 13% of our revenues from (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds arrangements with certain of our customers on the Williston Basin, Piceance Basin, and Permian Basin segments, (ii) natural gas and crude oil marketing services in and around our gathering systems, (iii) the sale of natural gas we retain from certain Barnett Shale customers and (iv) the sale of condensate we retain from our gathering services in the Piceance Basin segment. Consequently, our existing operations and cash flows have direct exposure to commodity price risk. Although we will seek to limit our commodity price exposure with new customers in the future, our efforts to obtain fee-based contractual terms may not be successful or the local market for our services may not support fee-based gathering and processing agreements. For example, we have percent-of-proceeds contracts with certain natural gas producer customers and we may, in the future, enter into additional percent-of-proceeds contracts with these customers or other customers or enter into keep-whole arrangements, which would increase our exposure to commodity price risk, as the revenues generated from those contracts directly correlate with the fluctuating price of the underlying commodities. Furthermore, we may acquire or develop additional midstream assets in the future that have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatility of natural gas and crude oil prices could have a material adverse effect on our business, results of operations and financial condition. For example, for a small portion of the natural gas gathered on our systems, we purchase natural gas from producers prior to delivering the natural gas to pipelines where we typically resell the natural gas under arrangements including sales at index prices. Generally, the gross margins we realize under these arrangements decrease in periods of low natural gas prices. If we expand the implementation of such natural gas purchase and sale arrangements within our business, such fluctuations could materially affect our business. If we fail to maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud, which would likely have a negative impact on the market price of our common units. As a publicly traded partnership, we are subject to the public reporting requirements of the Exchange Act, including the rules thereunder that will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Effective internal controls are necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We prepare our consolidated financial statements in accordance with GAAP. Our efforts to maintain our internal controls may not be successful and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Given the difficulties inherent in the design and operation of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our or our independent registered public accounting firm’s future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls over financial reporting could subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units. Regulatory and Environmental Policy Risks We are under investigation by federal and state regulatory agencies over a pipeline rupture and release of produced water by one of our subsidiaries. The resolution of this matter could have a material adverse effect on our results of operations or cash flows. As further described in Item 3. Legal Proceedings, an incident involving a produced water disposal pipeline owned by Meadowlark Midstream that resulted in a discharge of materials into the environment is under investigation by federal and state agencies pursuant to various laws that may give rise to criminal and civil liability. A loss arising from this incident is probable, and the ultimate outcome could have a material adverse effect on our results of operations or cash flows. We have accrued a loss contingency for this incident but cannot predict whether any actual loss, if one were to occur, would be materially higher or lower than such accrual. 44 Table of Contents We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. As a result, we may be required to expend significant funds for legal defense or to settle claims. Any such loss, if incurred, could be material. Expenditures made by the Partnership for the payment of litigation related costs, including legal defense costs and settlement payments, if any, reduce our cash flows available for debt service and distributions to our unitholders, if any. Any such expenditures, if incurred, could be material. See Item 3. Legal Proceedings for additional disclosure by the Partnership regarding its ongoing litigation and claims. A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenues to decline or our operation and maintenance expenses to increase. Various aspects of our operations are subject to regulation by the various federal, state and local departments and agencies that have jurisdiction over participants in the energy industry. The regulation of our activities and the natural gas and crude oil industries frequently change as they are reviewed by legislators and regulators. In 2016, the NDIC adopted rule changes that resulted in additional construction and monitoring requirements for certain underground gathering pipelines, including, but not limited to, those that transport produced water. The NDIC also adopted reclamation bonding requirements for certain underground gathering pipelines. At the federal level, PHMSA has issued new proposed and final rules concerning pipeline safety in recent years. To that extent these proposed or final rules create additional requirements for our pipelines, they could have a material adverse effect on our operations, operating and maintenance expenses and revenues. For additional information on the potential risks associated with PHMSA requirements, see the “We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements” section of Item 1.A. Risk Factors. In addition, the adoption of proposals for more stringent legislation, regulation or taxation of drilling activity could directly curtail such activity or increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for our services. For example, in 2018 the Colorado state ballot included a proposed 2,500 foot setback for oil and gas development from occupied structures and certain other areas. While the proposal did not pass, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the COGCC from fostering oil and gas development to regulating oil and gas development in a reasonable manner to protect public health and the environment. The new law also allows local governments to impose more restrictive requirements on oil and gas operations than those issued by the state. Further, in November 2020, the COGCC adopted new regulations that increase oil and gas setbacks to a minimum of 2,000 feet from schools and childcare facilities, prohibit routine venting and flaring, increase wildlife protections, and alter certain aspects of the permitting process. These regulations and similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. Regulatory agencies establish and, from time to time, change priorities, which may result in additional burdens on us, such as additional reporting requirements and more frequent audits of operations. Our operations and the markets in which we participate are affected by these laws, regulations and interpretations and may be affected by changes to them or their implementation, which may cause us to realize materially lower revenues or incur materially increased operation and maintenance costs or both. 45 Table of Contents Increased regulation of hydraulic fracturing could result in reductions or delays in customer production, which could materially adversely impact our revenues. Hydraulic fracturing is an important and increasingly common practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations, and is primarily regulated by state agencies. However, Congress has in the past, and may in the future consider legislation to regulate hydraulic fracturing by federal agencies. Many states have already adopted laws and/or regulations that require disclosure of the chemicals used in hydraulic fracturing. A number of states have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure and well construction requirements on crude oil and/or natural gas drilling activities. For example, a Colorado ballot initiative, Proposition 112, would have substantially increased setback distances for various upstream activities, thereby substantially restricting new oil and gas development in the state. Although Proposition 112 was defeated in the November 2018 elections, similar ballot initiatives have been circulated by interested groups for potential consideration in elections. Further, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the COGCC from fostering oil and gas development to regulating oil and gas development in a reasonable manner to protect public health and the environment. The new law also allows local governments to impose more restrictive requirements on oil and gas operations than those issued by the state. Further, in November 2020, the COGCC adopted new regulations that increase oil and gas setbacks to a minimum of 2,000 feet from schools and childcare facilities, prohibit routine venting and flaring, increase wildlife protections, and alter certain aspects of the permitting process. These regulations and similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. States also could elect to prohibit hydraulic fracturing altogether, as New York, Maryland, and Vermont have done. In addition, certain local governments have adopted, and additional local governments may adopt, ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. The EPA has also moved forward with various regulatory actions, including approving regulations requiring green completions of hydraulically-fractured wells and corresponding reporting requirements (NSPS OOOO) that went into effect in 2015. Revisions to the green completion regulations (NSPS OOOOa) were finalized in June 2016 and include additional requirements to reduce methane and VOCs. In August 2020, the EPA issued two final rules that rescinded the methane-specific requirements of NSPS OOOO and OOOOa applicable to sources in the production and processing segments and removed the transmission and storage segment from the source category. However, these 2020 rules are being challenged in the U.S. Court of Appeals for the D.C. Circuit. In addition, President Biden’s January 20, 2021 Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directed EPA to consider publishing a proposed rule suspending, revising, or rescinding the 2020 rules, as well as to consider establishing methane and VOC emission standards for existing sources in the oil and gas sector, including the transportation and storage segments. The BLM has also asserted regulatory authority over aspects of the hydraulic fracturing process, and issued a final rule in March 2015 that established more stringent standards for performing hydraulic fracturing on federal and Indian lands. However, in December 2017, the BLM published a final rule rescinding the 2015 rule. The U.S. District Court for the Northern District of California upheld the December 2017 rescission rule in a March 2020 decision. The State of California and environmental plaintiffs then appealed the decision in June 2020. Litigation is currently ongoing. Further, several federal governmental agencies have conducted reviews and studies on the environmental aspects of hydraulic fracturing, including the EPA. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing. State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. Some state regulatory agencies, including those in Colorado, Ohio, and Texas, have modified their regulations or guidance to account for induced seismicity. These developments could result in additional regulation and restrictions on the use of injection disposal wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on our customers. Additionally, certain of our customers produce oil and gas on federal lands. On January 20, 2021, the Acting Secretary for the Department of the Interior signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. Then on January 27, 2021, President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. 46 Table of Contents If new or more stringent federal, state or local legal restrictions relating to drilling activities or to the hydraulic fracturing process are adopted, this could result in a reduction in the supply of natural gas and/or crude oil that our customers produce, and could thereby adversely affect our revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for our customers, which could ultimately decrease end-user demand for our services and could have a material adverse effect on our business. We are subject to FERC jurisdiction, federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements and state and local regulation and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced. We believe that our natural gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC under the NGA and the NGPA. Interstate movements of crude oil on the Epping Pipeline in North Dakota are subject to FERC jurisdiction under the ICA, and the rates, terms and conditions of service, and practices on the pipeline are subject to review and challenge before FERC. Additionally, our proposed Double E Project, for which FERC approved the implementation plan in January 2021, and which is anticipated to provide natural gas transmission service from southeastern New Mexico to the Waha Hub in Texas, will be subject to FERC jurisdiction once completed. FERC may include conditions on its issuance of the certificate that make a project impracticable or too costly, or may ultimately determine not to issue the certificate required for us to pursue the project. Typically, a pipeline project requires review by a number of governmental agencies, including FERC, and other federal, state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any delay or refusal by an agency to issue authorizations or permits as requested for the project may mean that they will be constructed in a manner or with capital requirements that we did not anticipate or that we will not be able to pursue the project. Such delay, modification or refusal could materially and negatively impact the additional revenues expected from the project. In addition to approving and regulating the construction and operation of interstate natural gas pipelines, FERC also regulates such pipelines’ rates and terms and conditions of service, including transportation service agreements and negotiated rate agreements. We are also generally subject to the anti-market manipulation provisions in the NGA, as amended by the Energy Policy Act of 2005, and to FERC’s regulations thereunder, which authorize FERC to impose fines of up to $1,307,164 per day per violation of the NGA or its implementing regulations, subject to future adjustment for inflation. In addition, the FTC holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in oil markets, and has adopted broad rules and regulations prohibiting fraud and market manipulation. The FTC is also authorized to seek fines of up to $1,246,249 per violation, subject to future adjustment for inflation. The CFTC is directed under the CEA to prevent price manipulation in the commodity, futures and swaps markets, including the energy markets. Pursuant to the Dodd-Frank Act, and other authority, the CFTC has adopted additional anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity, futures and swaps markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,227,202 per violation, subject to future adjustment for inflation, or triple the monetary gain to the violator for each violation of the anti-market manipulation provisions of the CEA. The distinction between federally unregulated natural gas and crude oil pipelines and FERC-regulated natural gas and crude oil pipelines has been the subject of extensive litigation and is determined by FERC on a case-by-case basis. FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC, Congress or the courts. If our natural gas gathering operations or crude oil operations beyond the Epping Pipeline become subject to FERC jurisdiction under the NGA, the NGPA or the ICA, the result may materially adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, the NGPA or the ICA, this could result in the imposition of civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by FERC. We are subject to state and local regulation regarding the construction and operation of our gathering, treating and processing systems, as well as state ratable take statutes and regulations. Regulation of the construction and operation of our facilities may affect our ability to expand our facilities or build new facilities and such regulation may cause us to incur additional operating costs or limit the quantities of natural gas and crude oil we may gather, treat and process. Ratable take statutes and regulations generally require gatherers to take natural gas and crude oil production that may be tendered for gathering without undue discrimination. These requirements restrict our right to decide whose production we gather, treat and process. Many states have adopted complaint-based regulation of gathering, treating and processing activities, which allows producers and shippers to file 47 Table of Contents complaints with state regulators in an effort to resolve access issues, rate grievances and other matters. Other state and municipal regulations do not directly apply to our business, but may nonetheless affect the availability of natural gas and crude oil for gathering, treating and processing, including state regulation of production rates, maximum daily production allowable from wells, and other activities related to drilling and operating wells. While our facilities currently are subject to limited state and local regulation, there is a risk that state or local laws will be changed or reinterpreted, which may materially affect our operations, operating costs and revenues. Recent actions by the FERC may affect rates on Epping Pipeline and other future FERC-regulated pipelines. On March 15, 2018, FERC announced a revised policy prohibiting FERC-jurisdictional natural gas and liquids pipelines owned by master limited partnerships from including an allowance for income taxes in the cost of service used to calculate tariff rates. Most of our pipelines are not subject to FERC regulation and so will not be affected by the revised policy statement. However, rates for interstate movements of crude oil on our Epping Pipeline in North Dakota and any future FERC-regulated pipelines may be affected by the application of the revised policy statement in subsequent FERC proceedings. FERC has not required regulated interstate oil pipelines to decrease their rates on an industry-wide basis to implement the new policy. However, FERC stated that the effects of the revised policy statement must be incorporated in annual FERC financial reports made by regulated interstate oil pipelines. These reports, which also reflected the impact of the corporate income tax reduction enacted as part of the Tax Reform Legislation, were considered by FERC in its five-year review and determination of the index rate adjustment, which resulted in the December 17, 2020 order adopting a new annual index adjustment for the five-year period starting July 1, 2021. FERC ultimately removed the effect of the income tax allowance policy change from its index calculation, although the December 17, 2020 order is subject to rehearing and possible judicial review. The impact of these future proceedings on Epping Pipeline and any future FERC-regulated pipelines is uncertain at this time. Until FERC sets the next index rate adjustment, Epping Pipeline and any future FERC-regulated pipelines may face an increased risk of shipper complaints seeking FERC review of its rates. FERC can also initiate review of rates on its own initiative. We could also propose new cost-of-service rates or changes to our existing rates that would be subject to review by FERC under its new policy. No such proceedings have occurred at this time, however, and the potential outcome of any such proceedings, should any materialize, is uncertain. As a result of any such proceedings, Epping Pipeline and any future FERC-regulated pipelines may be required to modify their rates, which could affect the revenues we generate with our Epping Pipeline and any future FERC-regulated pipelines. At this time, we do not expect any such proceedings would have a material adverse effect, but we intend to monitor FERC developments and provide updated disclosure, as necessary. We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities. Our gathering, treating and processing operations are subject to stringent and complex federal, state and local environmental laws and regulations, including laws and regulations regarding the discharge of materials into the environment or otherwise relating to environmental protection, including, for example, the CAA, CERCLA, the CWA, the OPA, the RCRA, the Endangered Species Act and the Toxic Substances Control Act. These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. For additional information on specific laws and regulations, see the "Environmental Matters " section of Item 1. Business. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and requisite permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue. There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbons and other wastes and potential emissions and 48 Table of Contents discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering systems pass, and on which certain of our facilities are located, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. In addition, changes in environmental laws occur frequently, and any such changes that result in additional permitting obligations or more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance. The new presidential administration and Democratic control of Congress resulting from the 2020 elections may result in increased restrictions on oil and gas production activities, which could materially adversely affect our industry and our financial condition and results of operations. We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements. The DOT, through PHMSA, has adopted and enforces safety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations that are identical to or more restrictive than existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream system is located. While the majority of our pipelines meet the DOT definition of gathering lines and are thus currently exempt from PHMSA's integrity management requirements, we also operate a limited number of pipelines that are subject to the integrity management requirements. The regulations require operators, including us, to: • • • • • • perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; maintain processes for data collection, integration and analysis; repair and remediate pipelines as necessary; adopt and maintain procedures, standards and training programs for control room operations; and implement preventive and mitigating actions. For additional information on PHMSA regulations relating to pipeline safety, see the "Regulation of the Natural Gas and Crude Oil Industries—Safety and Maintenance" section of Item 1. Business. In July 2018, the PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline. The associated notice of proposed rulemaking, issued October 14, 2020, proposes to amend the requirements for gas transmission pipeline segments that experience a change in class location by offering an alternative set of requirements operators could use, based on implementing integrity management principles and pipe eligibility criteria, to manage certain pipeline segments where the class location has changed from a Class 1 location to a Class 3 location. In October 2019, the PHMSA issued three new final rules. One rule, which became effective in December 2019, establishes procedures to implement the expanded emergency order enforcement authority set forth in an October 2016 interim final rule. Among other things, this rule allows the PHMSA to issue an emergency order without advance notice or opportunity for a hearing. The other two rules, which became effective in July 2020, impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extends the requirement to conduct integrity assessments beyond “high consequence areas” (HCAs) to pipelines in “moderate consequence areas” (MCAs). It also includes requirements to reconfirm Maximum Allowable Operating Pressure (MAOP), report MAOP exceedances, consider seismicity as a risk factor in integrity management, and use certain safety features on in-line inspection equipment. The 49 Table of Contents rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events, and adds a requirement to make all lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. Further, in December 2020, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020 became law, reauthorizing PHMSA for funding through 2023 and requiring, among other things, rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines. While we believe that we are in compliance with existing safety laws and regulations, increased penalties for safety violations and potential regulatory changes could have a material adverse effect on our operations, operating and maintenance expenses and revenues. Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the services we provide. In recent years, the U.S. Congress has considered legislation to restrict or regulate emissions of GHGs, such as carbon dioxide and methane that may be contributing to global warming and energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. For example, the revisions to the NSPS found in 40 CFR 60 subpart OOOO (and OOOOa) include emission reduction requirements. In August 2020, the EPA issued two final rules that rescinded the methane-specific requirements of NSPS OOOO and OOOOa applicable to sources in the production and processing segments and removed the transmission and storage segment from the source category. However, these 2020 rules are being challenged in the U.S. Court of Appeals for the D.C. Circuit. In addition, President Biden’s January 20, 2021 Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directed EPA to consider publishing a proposed rule suspending, revising, or rescinding the 2020 rules, as well as to consider establishing methane and VOC emission standards for existing sources in the oil and gas sector, including the transportation and storage segments. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. In general, the number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). It is possible that certain components of our operations, such as our gas-fired compressors, could become subject to state-level GHG-related regulation. For example, in January 2019, the governor of New Mexico signed an executive order that includes a goal of reducing statewide GHG emissions by at least 45% by 2030. The executive order directs the New Mexico Energy, Minerals and Natural Resources Department (“EMNRD”) and the New Mexico Environment Department (“NMED”) to jointly develop a statewide, enforceable regulatory framework to secure reductions in oil and gas sector methane emissions. The executive order also creates a Climate Change Task Force to evaluate and develop regulatory strategies to reach the 45% reduction goal. In July 2020, NMED released draft rules that would establish emissions standards for VOCs and nitrogen oxides for oil and gas production and processing sources located in certain areas of the state with high ozone concentrations. Similarly, EMNRD released draft rules concerning venting and flaring of natural gas. Neither agency has yet issued a final rule. Although we cannot currently determine the effect of the proposed regulations developed by the EMNRD and the NMED or other potential regulatory strategies that may be suggested by the Climate Change Task Force, if implemented they could be material to the business, reputation, financial condition or results of operations of our Summit Permian system. Independent of Congress, the EPA has adopted regulations under its existing CAA authority. In 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources of GHG emissions. For additional information on EPA regulations adopted under the CAA, see the "Environmental Matters—Climate Change" section of Item 1. Business. Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions. The agreement entered into force in November 2016 after over 70 50 Table of Contents countries, including the United States, ratified or otherwise consented to be bound by the agreement. In November 2019, the United States submitted formal notification to the United Nations that it intended to withdraw from the agreement. However, on January 20, 2021, President Biden signed an “Acceptance on Behalf of the United States of America” that, reversed the prior withdrawal, and the United States officially rejoined the Paris Agreement on February 19, 2021. In addition, shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change. Reentry into the Paris Agreement and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations, which could have a material adverse effect on our business and that of our customers. Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal or state laws or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could materially adversely affect demand for our services. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of GHG could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions, adhere to alternative energy requirements and administer and manage a GHG emissions program. While we may be able to include some or all of such increased costs in the rates we charge, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations. Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. We cannot predict with any certainty at this time how these possibilities may affect our operations. The implementation of statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities. Congress adopted comprehensive financial reform legislation under the Dodd-Frank Act that establishes federal oversight and regulation of the over-the- counter derivatives market and entities, such as us, that participate in that market. This legislation requires the CFTC and the SEC and other regulatory authorities to promulgate certain rules and regulations, including rules and regulations relating to the regulation of certain swaps market participants, such as swap dealers, the clearing of certain swaps through central counterparties, the execution of certain swaps on designated contract markets or swap execution facilities, mandatory margin requirements for uncleared swaps, and the reporting and recordkeeping of swaps. While most of the regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing. Moreover, CFTC continues to refine its initial rulemakings under the Dodd-Frank Act. As a result, we cannot yet predict the ultimate effect of the rules and regulations on our business and while most of the regulations have been adopted, any new regulations or modifications to existing regulations could increase the cost of derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. The CFTC has proposed federal position limits on certain core futures and equivalent swaps contracts in the major energy and other markets, with exceptions for certain bona fide hedging transactions provided that various conditions are satisfied. If finalized, the position limits rule and its companion rule on aggregation among entities under common ownership or control may have an impact on our ability to hedge our exposure to certain enumerated commodities. 51 Table of Contents In 2013, the CFTC implemented final rules regarding mandatory clearing of certain classes of interest rate swaps and certain classes of index credit default swaps. Mandatory trading on designated contract markets or swap execution facilities of certain interest rate swaps and index credit default swaps also began in 2014. At this time, the CFTC has not proposed any rules designating other classes of swaps, including physical commodity swaps, for mandatory clearing. The CFTC and prudential banking regulators also recently adopted mandatory margin requirements on uncleared swaps between swap dealers and certain other counterparties. Although we may qualify for a commercial end-user exception from the mandatory clearing, trade execution and uncleared swaps margin requirements, mandatory clearing and trade execution requirements and uncleared swaps margin requirements applicable to other market participants, such as swap dealers, may affect the cost and availability of the swaps that we use for hedging. Under the Dodd-Frank Act, the CFTC is also directed generally to prevent price manipulation and fraud in the following two markets: (a) physical commodities traded in interstate commerce, including physical energy and other commodities, as well as (b) financial instruments, such as futures, options and swaps. Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-market manipulation, anti-fraud and disruptive trading practices regulations that prohibit, among other things, fraud and price manipulation in the physical commodities, futures, options and swaps markets. Should we violate these laws and regulations, we could be subject to CFTC enforcement action and material penalties, and sanctions. We currently enter into forward contracts with third parties to buy power and sell natural gas in an attempt to mitigate our exposure to fluctuations in the price of natural gas with respect to those volumes. The CFTC has finalized an interpretation clarifying whether certain forwards with volumetric optionality are regulated as forwards or qualify as options on commodities and therefore swaps. This interpretation may have an impact on our ability to enter into certain forwards or may impose additional requirements with respect to certain transactions. In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing local reforms generally comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties and may make any transactions involving cross-border swaps more expensive and burdensome. Additionally, the lack of regulatory equivalency across jurisdictions may increase compliance costs and make it more costly to satisfy regulatory obligations. 52 Table of Contents We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from various groups. We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from environmental groups, landowners, local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or other facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to our unitholders and, accordingly, have a material adverse effect on our business, financial condition and results of operations. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business. For example, in an April 15, 2020 ruling, amended May 11, 2020, the U.S. District Court for the District of Montana issued an order invalidating the U.S. Army Corps of Engineers (“Corps”) 2017 reissuance of Nationwide Permit 12 (“NWP 12”), the general permit governing dredge-and-fill activities for pipeline and other utility line construction projects, to the extent it was used to authorize construction of new oil and gas pipelines. Environmental groups had alleged that the Corps failed to consult with federal wildlife agencies as required by the Endangered Species Act. The court’s decision vacated NWP 12 until the Corps completes consultation with the applicable federal wildlife agencies. On July 6, 2020, the U.S. Supreme Court granted in part the Corps’ request to stay the U.S. District Court’s decision to allow the use of NWP 12 for utility line activities, including new oil and gas pipelines, pending the outcome of the appeal to the U.S. Court of Appeals for the Ninth Circuit and any subsequent petition for review to the U.S. Supreme Court. Litigation is currently ongoing. In addition, in January 2021, the EPA and Corps reissued NWP 12 as a general permit specific to oil and gas pipelines, moving other utility line activities into separate general permits. However, the NWP reissuance is among the agency actions listed for review in accordance with the January 20, 2021 Executive Order: “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.” Limitations on the use of NWP 12 may make it more difficult to permit our projects, require consideration of alternative construction or siting, which may impose additional costs and delays, and could cause us to lose potential and current customers and limit our growth and revenue. In addition, on July 6, 2020, the U.S. District Court for the District of Columbia issued an order vacating a Corps Mineral Leasing Act easement for the Dakota Access Pipeline in a lawsuit filed by American Indian Tribes. The court’s decision requires the pipeline to shut down operations by August 5, 2020, but was stayed by the U.S. Court of Appeals for the District of Columbia Circuit. On January 26, 2021, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision affirming the district court’s holding that the easement should be vacated, but reversing the requirement to shut down the pipeline. The Court of Appeals left it to the Corps to determine how to proceed after the loss of the easement, and the District Court has received briefing on whether to enjoin the operation of the pipeline as a result. The Dakota Access Pipeline continues to operate pending the District Court’s ruling or a decision by the Corps to order the pipeline to shut down. If the Dakota Access Pipeline is forced to shut down, this could have a material adverse effect on our business, financial condition and results of operations associated with the Polar and Divide System, which interconnects with the Dakota Access Pipeline. 53 Table of Contents Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in an increasing number of financial institutions, funds, individual investors and other sources of capital restricting or eliminating their investment in fossil fuel-related activities. In addition, financial institutions have begun to screen companies such as ours for sustainability performance, including practices related to GHGs and climate change, before providing loans or investing in our common units. There is also a risk that financial institutions may adopt policies that have the effect of reducing the funding provided to the fossil fuel sector, such as the adoption of net zero financed emissions targets. Such policies may be hastened by actions under the Biden Administration, including the implementation by the Federal Reserve of any recommendations made by the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate- related risks in the financial sector. Ultimately, this could make it more difficult to secure funding for exploration and production activities or energy infrastructure related projects, and consequently could both indirectly affect demand for our services and directly affect our ability to fund construction or other capital projects. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable in order to improve our sustainability performance and to meet the specific requirements to maintain access to capital or perform services for certain customers. Our business is subject to complex and evolving U.S. and International laws and regulations regarding privacy and data protection (“data protection laws”). Many of these laws and regulations are subject to change and uncertain interpretation, and could result in claims, increased cost of operations or otherwise harm our business. Along with our own data and information in the normal course of our business, we and our partners collect and retain significant volumes of certain types of data, some of which are subject to specific laws and regulations. The transfer and use of this data both domestically and across international borders is becoming increasingly complex. The regulatory environment surrounding and the transfer and protection of such data is constantly evolving and can be subject to significant change. New data protection laws at the federal, state, international, national, provincial and local levels, including recent Colorado legislation, the European Union General Data Protection Regulation (“GDPR”) and the California Consumer Privacy Act (“CCPA”), pose increasingly complex compliance challenges and potentially elevate our costs. Complying with these jurisdictional requirements could increase the costs and complexity of compliance, and violations of applicable data protection laws can result in significant penalties. For example, the GDPR applies to activities regarding personal data that may be conducted by us, directly or indirectly through vendors and subcontractors, from an establishment in the European Union. Failure to comply could result in significant penalties of up to a maximum of 4% of our global turnover that may materially adversely affect our business, reputation, results of operations, and cash flows. Similarly, the CCPA, which came into effect on January 1, 2020, gives California residents specific rights in relation to their personal information, requires that companies take certain actions, including notifications for security incidents and may apply to activities regarding personal information that is collected by us, directly or indirectly, from California residents. As interpretation and enforcement of the CCPA evolves, it creates a range of new compliance obligations, which could cause us to change our business practices, with the possibility for significant financial penalties for noncompliance that may materially adversely affect our business, reputation, results of operations, and cash flows. As noted above, we are also subject to the possibility of information security breaches, which themselves may result in a violation of these laws. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result. Risks Inherent in an Investment in Us Because our common units are yield-oriented securities, increases in interest rates could materially adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions to our unitholders. Interest rates are generally near historic lows and may increase in the future. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have a material adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels. 54 Table of Contents The amount of cash we have available for distribution to holders of our units depends primarily on our cash flows rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income. The amount of cash we have available for distribution depends primarily upon our cash flows and not solely on profitability, which will be affected by non- cash items. As a result, we may make cash distributions during periods when we report net losses for GAAP purposes and may not make cash distributions during periods when we report net income for GAAP purposes. The market price of our common units may fluctuate significantly and, due to limited daily trading volumes, an investor could lose all or part of its investment in us. An investor may not be able to resell its common units at or above its acquisition price. Additionally, limited liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units. The market price of our common units may decline and be influenced by many factors, some of which are beyond our control, including among others: • • • • • • • • • our quarterly distributions, if any; our quarterly or annual earnings or those of other companies in our industry; the loss of a large customer; announcements by our customers or others regarding our customers or changes in our customers’ credit ratings, liquidity position, leverage profile and/or other financial or credit-related metrics; announcements by our competitors of significant contracts or acquisitions; changes in accounting standards, policies, guidance, interpretations or principles; general economic and geopolitical conditions; the failure of securities analysts to cover our common units or changes in financial estimates by analysts; and other factors described in these Risk Factors. Our Partnership Agreement replaces our General Partner’s fiduciary duties to unitholders and those of our officers and directors with contractual standards governing their duties. Our Partnership Agreement contains provisions that eliminate fiduciary duties to which our General Partner and its officers and directors would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the Partnership Agreement, including the provisions discussed above. Our Partnership Agreement limits the liabilities of our General Partner and its officers and directors and the rights of our unitholders with respect to actions taken by our General Partner and its officers and directors that might otherwise constitute breaches of fiduciary duty. Our Partnership Agreement contains provisions that limit the liability of our General Partner and the rights of our unitholders with respect to actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement provides that: • • whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in our best interests, and will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity; our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as such decisions are made in good faith; 55 Table of Contents • • our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and our General Partner will not be in breach of its obligations under the Partnership Agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is: i. ii. iii. iv. approved by the Conflicts Committee, although our General Partner is not obligated to seek such approval; approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates; on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our General Partner or the Conflicts Committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the Conflicts Committee and the Board of Directors determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the final two subclauses above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Our Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units. Unitholders' voting rights are further restricted by a provision of our Partnership Agreement providing that any person or group that owns 20% or more of any class of units then outstanding cannot vote on any matter, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board of Directors. We may issue additional units without unitholder approval, which would dilute existing ownership interests. Except in the case of the issuance of units that rank equal to or senior to the Series A Preferred Units, our Partnership Agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units that we may issue at any time without the approval of our unitholders. We may issue additional Series A Preferred Units and any securities in parity with the Series A Preferred Units without any vote of the holders of the Series A Preferred Units (except where the cumulative distributions on the Series A Preferred Units or any parity securities are in arrears and in certain other circumstances) and without the approval of our common unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will decrease our existing unitholders' proportionate ownership interest in us. In addition, the issuance by us of additional common units or other equity securities of equal or senior rank may have the following effects: • • • • decreasing the amount of cash available for distribution on each unit; increasing the ratio of taxable income to distributions; diminishing the relative voting strength of each previously outstanding unit; and causing the market price of the common units to decline. Future issuances and sales of parity securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for our common units and the Series A Preferred Units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us. 56 Table of Contents Furthermore, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, including units issued to third parties at a subsidiary level, their issuance will increase the uncertainty of the payment of distributions on our common units. Holders of Series A Preferred Units have limited voting rights, which may be diluted. Although holders of the Series A Preferred Units are entitled to limited voting rights with respect to certain matters, the Series A Preferred Units generally vote separately as a class along with any other series of our parity securities that we may issue upon which like voting rights have been conferred and are exercisable. As a result, the voting rights of holders of Series A Preferred Units may be significantly diluted, and the holders of such other series of parity securities that we may issue may be able to control or significantly influence the outcome of any vote. Our General Partner has a limited call right that may require an investor to sell its units at an undesirable time or price. If at any time our General Partner and its affiliates own more than 80% of our outstanding common units, our General Partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our Partnership Agreement. As a result, an investor may be required to sell its common units at an undesirable time or price and may not receive any return on its investment. An investor may also incur a tax liability upon a sale of its units. An investor's liability may not be limited if a court finds that unitholder action constitutes control of our business. A General Partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the General Partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. An investor could be liable for any and all of our obligations as if it was a General Partner if a court or government agency were to determine that: • • we were conducting business in a state but had not complied with that particular state's partnership statute; or an investor's right to act with other unitholders to remove or replace our General Partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute control of our business. Our Partnership Agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which limits our unitholders’ ability to choose the judicial forum for disputes with us or our General Partner’s directors, officers or other employees. Our Partnership Agreement provides that, with certain limited exceptions, the Court of Chancery of the State of Delaware is the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our Partnership Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our Partnership Agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty (including a fiduciary duty) owed by any of our, or our General Partner’s, directors, officers, or other employees, or owed by our General Partner, to us or our partners, (4) asserting a claim against us arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act or (5) asserting a claim against us governed by the internal affairs doctrine. Any person or entity purchasing or otherwise acquiring any interest in our common units is deemed to have received notice of and consented to the foregoing provisions. This exclusive forum provision does not apply to a cause of action brought under federal or state securities laws. Although management believes this choice of forum provision benefits us by providing increased consistency in the application of Delaware law in the types of lawsuits to which it applies, the provision may have the effect of discouraging lawsuits against us and our General Partner’s directors and officers. The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings and it is possible that in connection with any action a court could find the choice of forum provisions contained in our Partnership Agreement to be inapplicable or unenforceable in such action. If a court were to find this choice of forum provision inapplicable 57 Table of Contents to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our financial position, results of operations and ability to make cash distributions to our unitholders. Unitholders may have liability to repay distributions that were wrongfully distributed to them. Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Delaware law, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the Partnership Agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted. If an investor is not an eligible holder, it may not receive distributions or allocations of income or loss on those common units and those common units will be subject to redemption. We have adopted certain requirements regarding those investors who may own our common units and Series A Preferred Units. Eligible holders are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity's owners are U.S. individuals or entities subject to such taxation. If an investor is not an eligible holder, our General Partner may elect not to make distributions or allocate income or loss on that investor's units, and it runs the risk of having its units redeemed by us at the lower of purchase price cost or the then-current market price. The redemption price may be paid in cash or by delivery of a promissory note, as determined by our General Partner. Our Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units. The Series A Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units or could make it more difficult for us to sell our common units in the future. In addition, (i) prior to December 15, 2022, distributions on the Series A Preferred Units accumulate and are cumulative at the rate of 9.50% per annum of $1,000, the liquidation preference of the Series A Preferred Units and (ii) on and after December 15, 2022, distributions on the Series A Preferred Units will accumulate for each distribution period at a percentage of $1,000 equal to the three-month LIBOR plus a spread of 7.43%. On May 3, 2020, we announced the suspension of distributions payable on both our common units and our Series A Preferred Units. We did not make a distribution on our common units with respect to any quarter in 2020, nor did we make a distribution on our Series A Preferred Units on June 15, 2020 or December 15, 2020. As of December 31, 2020, the amount of accrued and unpaid distributions on the Series A Preferred Units was $15.8 million. Unpaid distributions on the Series A Preferred Units will continue to accrue. In addition, our Subsidiary Series A Preferred Units issued by Permian Holdco have priority over the common unitholders with respect to the cash flow from Permian Holdco. The distribution rate of the Subsidiary Series A Preferred Units is 7.00% per annum of the $1,000 issue amount per outstanding Subsidiary Series A Preferred Unit. Permian Holdco has the option to pay this distribution in-kind until the earlier of June 30, 2022 or the first full quarter following the date the Double E pipeline is placed in service. Our obligation to pay distributions on our Series A Preferred Units and Permian Holdco’s obligation to pay the distributions on the Subsidiary Series A Preferred Units could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general partnership purposes. Our obligations to the holders of the Series A Preferred Units and Permian Holdco’s obligations to the holders of the Subsidiary Series A Preferred Units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition. 58 Table of Contents Our Series A Preferred Units contain covenants that may limit our business flexibility. Our Series A Preferred Units contain covenants preventing us from taking certain actions without the approval of the holders of 66 2/3% of the Series A Preferred Units. The need to obtain the approval of holders of the Series A Preferred Units before taking these actions could impede our ability to take certain actions that management or the Board of Directors may consider to be in the best interests of our unitholders. The affirmative vote of 66 2/3% of the outstanding Series A Preferred Units, voting as a single class, is necessary to amend the Partnership Agreement in any manner that would have a material adverse effect on the existing preferences, rights, powers, duties or obligations of the Series A Preferred Units. The affirmative vote of 66 2/3% of the outstanding Series A Preferred Units and any outstanding series of other preferred units, voting as a single class, is necessary to (A) under certain circumstances, create or issue certain equity securities that are senior to our common units, (B) declare or pay any distribution to common unitholders out of capital surplus or (C) take any action that would result in an event of default for failure to comply with any covenant in the indentures governing the 5.5% Senior Notes or the 2025 Senior Notes co-issued by Summit Holdings and its 100% owned finance subsidiary, Finance Corp. Although holders of the Series A Preferred Units are entitled to limited voting rights with respect to certain matters, the Series A Preferred Units generally vote as a class, separate from our common unitholders, along with any other series of our parity securities that we may issue upon which like voting rights have been conferred and are exercisable. Tax Risks Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced. The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently 21%, and would likely pay state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be material reductions in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units. This could adversely affect our financial position, results of operations and ability to make distributions to our unitholders. If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders. Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution. The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations of applicable law, possibly on a retroactive basis. The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. 59 Table of Contents Any modification to the U.S. federal income tax laws and interpretations could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our units. Our unitholders are required to pay income taxes on their share of our taxable income even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, transactions in which we engage or changes in law and may be substantially different from any estimate we make in connection with a unit offering. A unitholder’s allocable share of our taxable income will be taxable to it, which may require the unitholder to pay federal income taxes and, in some cases, state and local income taxes, even if the unitholder receives cash distributions from us that are less than the actual tax liability that results from that income or no cash distributions at all. A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, which may be affected by numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control, and certain transactions in which we might engage. For example, we may engage in transactions that produce substantial taxable income allocations to some or all of our unitholders without a corresponding increase in cash distributions to our unitholders, such as a sale or exchange of assets, the proceeds of which are reinvested in our business or used to reduce our debt, or an actual or deemed satisfaction of our indebtedness for an amount less than the adjusted issue price of the debt. A unitholder’s ratio of its share of taxable income to the cash received by it may also be affected by changes in law. For instance, under Tax Reform Legislation, the net interest expense deductions of certain business entities, including us, are limited to 30% of such entity’s “adjusted taxable income,” which is generally taxable income with certain modifications. If the limit applies, a unitholder’s taxable income allocations will be more (or its net loss allocations will be less) than would have been the case absent the limitation. From time to time, in connection with an offering of our common units, we may state an estimate of the ratio of federal taxable income to cash distributions that a purchaser of common units in that offering may receive in a given period. These estimates depend in part on factors that are unique to the offering with respect to which the estimate is stated, so the expected ratio applicable to other common units will be different, and in many cases less favorable, than these estimates. Moreover, even in the case of common units purchased in the offering to which the estimate relates, the estimate may be incorrect, due to the uncertainties described above, challenges by the IRS to tax reporting positions which we adopt, or other factors. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. 60 Table of Contents We have engaged in recent transactions that generated substantial COD income on a per unit basis relative to the trading price of our common units. We may engage in other transactions that result in substantial COD income or other gains in the future, and such events may cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to the unitholder. A unitholder’s share of our taxable income will include any COD income recognized upon the satisfaction of our outstanding indebtedness for total consideration less than the adjusted issue price (and any accrued but unpaid interest) of such indebtedness. In 2020, we engaged in various liability management transactions that resulted in substantial COD income. We may engage in other transactions that result in substantial COD income or other gains, such as gains upon assets sales, in the future. Depending upon the net amount of other items related to our loss (or income) allocable to a unitholder, any COD income or other gains may cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to the unitholder. Furthermore, such COD income event or other gain event may not be fully offset, either now or in the future, by capital losses, which are subject to significant limitations, or other losses. Accordingly, a COD income event or other gain event could cause a unitholder to realize taxable income without corresponding future economic benefits or offsetting tax deductions. If the IRS contests the federal income tax positions we take, the market for our units may be adversely impacted and the cost of any IRS contest would likely reduce our cash available for distribution to our unitholders. The IRS may adopt positions that differ from the conclusions of our counsel expressed in a prospectus or from the positions we take, and the IRS's positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse effect on the market for our units and the price at which they trade. In addition, our costs of any contest with the IRS would be borne indirectly by our unitholders because the costs would likely reduce our cash available for distribution. Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us. In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Reform Legislation, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years, beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. For our 2020 taxable year, the Coronavirus Aid, Relief, and Economic Security Act increases the 30% adjusted taxable income limitation to 50%, unless we elect not to apply such increase, and for purposes of determining our 50% adjusted taxable income limitation, we may elect to substitute our 2020 adjusted taxable income with our 2019 adjusted taxable income. Tax gain or loss on the disposition of our units could be more or less than expected. If a unitholder sells its units, a gain or loss will be recognized for federal income tax purposes equal to the difference between the amount realized and the unitholder's tax basis in those units. Because distributions in excess of a unitholder's allocable share of its net taxable income decrease its tax basis in its units, the amount, if any, of such prior excess distributions with respect to the units it sells will, in effect, become taxable income to the unitholder if it sells such units at a price greater than its tax basis in those units, even if the price it receives is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale or other disposition of a unitholder's units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if a unitholder sells its units, it may incur a tax liability in excess of the amount of cash it receives from the sale. 61 Table of Contents Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax consequences to them. Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to an organization that is exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income (“UBTI”) and will be taxable to the exempt organization as UBTI on the exempt organization’s tax return in the year the exempt organization is allocated the income. Under the Tax Reform Legislation, an exempt organization is required to independently compute its UBTI from each separate unrelated trade or business which may prevent an exempt organization from utilizing losses we allocate to the organization against the organization’s UBTI from other sources and vice versa. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and applicable state tax returns and pay tax on their share of our taxable income. Under the Tax Reform Legislation, if a unitholder sells or otherwise disposes of a unit, the transferee is required to withhold 10.0% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. However, the U.S. Treasury and the IRS have suspended these rules for transfers of certain publicly traded partnership interests, including transfers of our common units, that occur before January 1, 2022. Under recently finalized Treasury Regulations, such withholding will be required on open market transactions, but in the case of a transfer made through a broker, a partner’s share of liabilities will be excluded from the amount realized. In addition, the obligation to withhold will be imposed on the broker instead of the transferee (and we will generally not be required to withhold from the transferee amounts that should have been withheld by the transferee but were not withheld). These withholding obligations will apply to transfers of our common units occurring on or after January 1, 2022. We treat each holder of our common units as having the same tax benefits without regard to the actual common units held. The IRS may challenge this treatment, which could adversely affect the value of the common units. Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. A successful IRS challenge also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns. Treatment of distributions on our Series A Preferred Units as guaranteed payments for the use of capital creates a different tax treatment for the holders of our Series A Preferred Units than the holders of our common units and such distributions are not eligible for the 20% deduction for qualified publicly traded partnership income. The tax treatment of distributions on our Series A Preferred Units is uncertain. We will treat the holders of Series A Preferred Units as partners for tax purposes and will treat distributions on the Series A Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of Series A Preferred Units as ordinary income. Although a holder of Series A Preferred Units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making the guaranteed payment distributions semi-annually on the 15th day of June and December through December 15, 2022, and quarterly on the 15th day of March, June, September and December thereafter. Because the guaranteed payment for each unit must accrue as income to a holder during the taxable year of the accrual, the guaranteed payment attributable to the period beginning December 15th and ending December 31st will accrue to the holder of record of a Series A Preferred Unit on December 31st for such period. Otherwise, except in the case of our liquidation, the holders of Series A Preferred Units are generally not anticipated to share in our items of income, gain, loss or deduction. We will not allocate any share of its nonrecourse liabilities to the holders of Series A Preferred Units. Treasury Regulations provide that a guaranteed payment for the use of capital generally is not taken into account for purposes of computing qualified business income for purposes of the 20% deduction for qualified publicly traded partnership will not constitute an allocable or distributive share of such income. As a result, the guaranteed payment for use of capital received by holders of our Series A Preferred Units may not be eligible for the 20% deduction for qualified publicly traded partnership income. 62 Table of Contents A holder of Series A Preferred Units will be required to recognize gain or loss on a sale of units equal to the difference between the holder’s amount realized and tax basis in the units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such Series A Preferred Units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a Series A Preferred Unit will generally be equal to the sum of the cash and the fair market value of other property paid by the holder to acquire such Series A Preferred Unit. Gain or loss recognized by a holder on the sale or exchange of a Series A Preferred Unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of Series A Preferred Units will not generally be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules. Investment in the Series A Preferred Units by tax-exempt investors, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. Although the issue is not free from doubt, we will treat distributions to non-U.S. holders of the Series A Preferred Units as “effectively connected income” (which will subject holders to U.S. net income taxation and possibly the branch profits tax) that are subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. holders. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders may be required to file U.S. federal income tax returns in order to seek a refund of such excess. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes. All holders of our Series A Preferred Units are urged to consult a tax advisor with respect to the consequences of owning our Series A Preferred Units. We prorate our items of income, gain, loss and deduction for U.S, federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders. We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Treasury Regulations allow a similar monthly simplifying convention, but do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method, or if new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. We have adopted certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction among our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our units. When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction. 63 Table of Contents A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders' sale of units and could have a negative impact on the value of the units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions. If the IRS makes audit adjustments to our income tax returns, the IRS (and some states) may collect any resulting taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear such payment, our cash available for distribution to our unitholders could be substantially reduced. If the IRS makes audit adjustments to our income tax returns, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (and will choose to do so) under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If, we make payments of taxes, penalties and interest resulting from audit adjustments, we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear such payment, our cash available for distribution to our unitholders could be substantially reduced. Additionally, we may be required to allocate an adjustment disproportionately among our unitholders, causing the publicly traded units to have different capital accounts, unless the IRS issues further guidance. In the event the IRS makes an audit adjustment to our income tax returns and we do not or cannot shift the liability to our unitholders in accordance with their interests in us during the year under audit, we will generally have the ability to request that the IRS reduce the determined underpayment by reducing the suspended passive loss carryovers of our unitholders (without any compensation from us to such unitholders), to the extent such underpayment is attributable to a net decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected unitholders. As a result of investing in our units, our unitholders will likely be subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties. In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if the unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. Some of the states in which we conduct business currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is the unitholder's responsibility to file all federal, state and local tax returns. Compliance with and changes in tax laws could adversely affect our performance. We are subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties. Risks Related to Terrorism and Cyberterrorism Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war could have a material adverse effect on our business, financial condition or results of operations. Terrorist attacks and threats, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or 64 Table of Contents military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Our insurance may not protect us against such occurrences. Our operations depend on the use of information technology (“IT”) systems that could be the target of a cyberattack. The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems now control large scale processes that can include multiple sites and long distances, such as oil and gas pipelines. Our operations depend on the use of sophisticated IT systems. Our IT systems and networks, as well as those of our customers, vendors and counterparties, may become the target of cyber-attacks or information security breaches, which in turn could result in the unauthorized release and misuse of sensitive or proprietary information as well as disrupt our operations, damage our reputation or damage our facilities or those of third parties, which could have a material adverse effect on our revenues and increase our operating and capital costs, which could reduce the amount of cash otherwise available for distribution. In addition, certain cyber-incidents, such as surveillance, may remain undetected for an extended period. We may be required to incur additional costs to modify or enhance our IT systems or to prevent or remediate any such attacks. A cyber-incident involving our IT systems and related infrastructure, or that of our customers, venders and counterparties, could disrupt our business plans and negatively impact our operations in the following ways, among others: • • • • • a cyber-attack on a vendor or service provider could result in supply chain disruptions, which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project; a cyber-attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues; a cyber-attack on a communications network or power grid could cause operational disruption, resulting in loss of revenues; a deliberate corruption of our financial or operational data could result in events of non-compliance, which could lead to regulatory fines or penalties; and business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation or a negative impact on the price of our units. Item 1B. Unresolved Staff Comments. Not applicable. Item 2. Properties. A description of our properties is included in Item 1. Business, and is incorporated herein by reference. For additional information on our midstream assets and their capacities, see Item 1. Business. Our real property falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our gathering systems and other major facilities are located are owned by us in fee title, and we believe that we have valid title to these lands. The remainder of the land on which our major facilities are located are held by us pursuant to long-term leases or easements between us and the underlying fee owner or permits with governmental authorities. We believe that we have valid leasehold estates or fee ownership in such lands or valid permits with governmental authorities. We have no knowledge of any material challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or license. We believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses with the 65 Table of Contents exception of certain ordinary course encumbrances and permits with governmental entities that have been applied for, but not yet issued. In addition, we lease various office space under leases to support our operations. Item 3. Legal Proceedings. Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any significant legal or governmental proceedings, except as noted below. In addition, we are not aware of any significant legal or governmental proceeding contemplated to be brought against us, under the various environmental protection statutes to which we are subject, except as noted below. Beginning in 2015, the U.S. Department of Justice (“DOJ”) issued grand jury subpoenas to Summit Investments, the Partnership, our General Partner and Meadowlark Midstream requesting certain materials related to an incident involving a produced water disposal pipeline owned by Meadowlark Midstream that resulted in a discharge of materials into the environment (“Meadowlark Rupture”). On June 19, 2015, Meadowlark Midstream and Summit Investments received a complaint from the North Dakota Industrial Commission seeking approximately $2.5 million in fines and other fees related to the incident. This matter is also under investigation by the U.S. Environmental Protection Agency, the North Dakota Office of the Attorney General, the North Dakota Department of Environmental Quality, and the North Dakota Game and Fish Department. The government’s investigation is still ongoing. During this time, the Partnership has entered into tolling agreements with both the DOJ and the North Dakota attorney general, which were most recently extended to May 7, 2021. There can be no assurance that these tolling agreements will be extended. Discussions with the DOJ and other agencies regarding a resolution of this matter are ongoing. Liability for this incident could arise under civil and misdemeanor and felony criminal statutes, including under the Clean Water Act. In accordance with GAAP, the Partnership has accrued a $17.0 million loss contingency for this matter as of December 31, 2020. While the Partnership believes a loss for claims and/or actions arising from the Meadowlark Rupture, whether in a negotiated settlement or as a result of litigation, is probable, due to the complexity of resolving the numerous issues surrounding this matter, at this time we cannot reasonably predict whether any actual loss, if incurred, would be materially higher or lower than the accrued amount. The following additional matters are disclosed pursuant to requirements of Item 103 of the SEC’s Regulation S-K. We do not currently believe that the eventual outcome of such matters could have a material adverse effect on our business, financial condition, results of operations or cash flows. A petition was filed in the District Court of Arapahoe County, Colorado, by Samuel Engineering, Inc. against Meadowlark Midstream and Summit Niobrara. The matter was later transferred to the District Court of Denver County, Colorado, where it is currently pending. The plaintiff was a contractor hired to perform engineering, procurement, and construction services for Summit Niobrara’s gas processing plant located in Weld County, Colorado. The plaintiff is seeking damages for alleged non-payment for such services. Separately, a demand for arbitration was filed in Houston, Texas by Moore Control Systems, Inc. against Summit Permian. The claimant in that matter was a contractor hired to perform engineering, procurement, and construction services for Summit Permian’s gas processing plant located in Eddy County, New Mexico. The claimant is seeking damages for alleged non-payment for such services. We previously disclosed a legal proceeding initiated in the District Court of Tarrant County, Texas by Sage Natural Resources, LLC against us and certain of our affiliates. That legal proceeding was terminated by the court’s dismissal of the lawsuit with prejudice. Item 4. Mine Safety Disclosures. Not applicable. 66 Table of Contents PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. Our limited partner common units, ticker symbol “SMLP,” trade on the NYSE. As of December 31, 2020, there were approximately 8,489 common unitholders, including beneficial owners of common units held in street name. On January 29, 2020, the Board of Directors declared a distribution of $0.125 per unit (an amount before giving effect to the Reverse Unit Split) for the quarterly period ended December 31, 2019. The distribution, which totaled $11.7 million, was paid on February 14, 2020, prior to the GP Buy-In Transaction, to unitholders of record at the close of business on February 7, 2020. In May 2020, the Partnership suspended distributions to holders of its common units and its Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. We did not make a distribution on our common units with respect to any quarter in 2020, nor did we make a distribution on our Series A Preferred Units on June 15, 2020 or December 15, 2020. Our Cash Distribution Policy and Restrictions on Distributions General Suspension of Distributions. In May 2020, the Partnership suspended distributions to holders of its common units and suspended payments of distributions to holders of its Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. Because our Series A Preferred Units rank senior to our common units with respect to distribution rights, any accrued amounts on our Series A Preferred Units must first be paid prior to our resumption of distributions to our common unitholders. As of December 31, 2020, the amount of accrued and unpaid distributions on the Series A Preferred Units totaled $15.8 million. At this time, the Partnership is unable to forecast when it will resume distributions to holders of its common units and Series A Preferred Units. Our Cash Distribution Policy. Our Partnership Agreement requires us to distribute all of our available cash quarterly, subject to reserves established by our General Partner. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax. Upon a resumption of the Partnership’s distributions, we will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about seven days prior to such distribution date. We make the distribution on the business day immediately preceding the indicated distribution date if the distribution date falls on a holiday or non-business day. The Board of Directors plans on making decisions with respect to payment of distributions on the common units and Series A Preferred Units on a semi- annual or quarterly basis, as applicable, based on the required payment date. We may not pay distributions on the common units or Series A Preferred Units in the foreseeable future, and there are restrictions on our ability to pay distributions under our outstanding indebtedness that restrict our ability to pay cash distributions on any of our equity securities. Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy. There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay any distribution except to the extent we have available cash as defined in our Partnership Agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following: • • Our cash distribution policy is subject to restrictions on distributions under our Revolving Credit Facility. Our Revolving Credit Facility contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions notwithstanding our stated cash distribution policy. Our cash distribution policy is subject to restrictions on distributions under our Series A Preferred Units. Our Series A Preferred Units contain covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions notwithstanding our stated cash distribution policy. 67 Table of Contents • • • • Our General Partner has the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those cash reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our General Partner in good faith will be binding on our unitholders. Although our Partnership Agreement requires us to distribute all of our available cash, our Partnership Agreement, including the provisions requiring us to distribute all of our available cash, may be amended. We can amend our Partnership Agreement with the consent of our General Partner and the approval of a majority of the outstanding common units. Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our General Partner, taking into consideration the terms of our Partnership Agreement. Under Delaware law, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. • We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. • If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly distribution rate to service or repay our debt or fund expansion capital expenditures. Preferred Unit Distributions Series A Preferred Units In November 2017, we issued 300,000 Series A Preferred Units at a price to the public of $1,000. During the year ended December 31, 2020, we exchanged 62,816 Series A Preferred Units for 837,547 SMLP common units and completed a cash tender offer whereby we tendered 75,075 Series A Preferred Units for $25.0 million in cash. As of December 31, 2020, we have 162,109 Series A Preferred Units outstanding. In May 2020, the Partnership suspended payments of distributions to holders of its Series A Preferred Units, and we did not make a distribution on our Series A Preferred Units on June 15, 2020 or December 15, 2020. Distributions on the Series A Preferred Units are cumulative and compounding and are payable semi-annually in arrears on the 15th day of each June and December through and including December 15, 2022, and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year (each, a “Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Distribution Payment Date, in each case, when, as, and if declared by the General Partner out of legally available funds for such purpose. The initial distribution rate for the Series A Preferred Units is 9.50% per annum of the $1,000 liquidation preference per Series A Preferred Unit. On and after December 15, 2022, distributions on the Series A Preferred Units will accumulate for each distribution period at a percentage of the liquidation preference equal to the three-month LIBOR plus a spread of 7.43%. See Note 13 to the consolidated financial statements for additional details. Subsidiary Series A Preferred Units In December 2019 and during the year ended December 31, 2020, Permian Holdco issued 30,000 and 55,251 Subsidiary Series A Preferred Units, respectively, representing limited partner interests in Permian Holdco at a price of $1,000 per unit. Permian Holdco used the net proceeds of $48.7 million and $27.4 million, respectively, (after deducting offering expenses) to fund capital calls associated with the Double E Project. 68 Table of Contents Distributions on the Subsidiary Series A Preferred Units are cumulative and compounding and are payable quarterly in arrears 21 days after the quarter ending March, June, September and December of each year (each, a “Subsidiary Series A Preferred Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Subsidiary Series A Preferred Distribution Payment Date, in each case, when, as, and if declared by the board of directors of Permian Holdco out of legally available funds for such purpose. The distribution rate is 7.00% per annum of the $1,000 issue amount per outstanding Permian Holdco Subsidiary Series A Preferred Unit. Permian Holdco has the option to pay this distribution in-kind until the earlier of June 30, 2022 or the first full quarter following the date the Double E pipeline is placed in service. See Note 13 to the consolidated financial statements for additional details. Unregistered Sales of Equity Securities In July 2020, the Partnership completed the Preferred Exchange Offer. The Preferred Exchange Offer expired on July 28, 2020, and on July 31, 2020, the Partnership issued 837,547 SMLP common units in exchange for 62,816 Series A Preferred Units. Upon closing the Preferred Exchange Offer, we eliminated $66.5 million of the Series A Preferred Unit liquidation preference amount, inclusive of accrued distributions due as of the settlement date. The Partnership did not receive any cash proceeds from the Preferred Exchange Offer. The Partnership relied on Section 3(a)(9) of the Securities Act to exempt the Preferred Exchange Offer from the registration requirements of the Securities Act. Section 3(a)(9) offers exemptions from the registration requirements of the Securities Act for exchange offers in which (i) the issuer of the securities offered is the same as the issuer of the securities being surrendered, (ii) the holders are not being asked to surrender anything of value other than the outstanding securities, (iii) the exchange offer is made exclusively to existing holders of the issuer’s outstanding securities, and (iv) the issuer does not pay any commission or remuneration for solicitation of the exchange. Because the Partnership offered only its own common units exclusively to the holders of and in exchange for its outstanding Series A Preferred Units, and because it neither paid nor received anything of value other than the subject securities, the Partnership was able to rely on the exemption afforded by Section 3(a)(9) of the Securities Act. Issuer Purchases of Equity Securities In May 2020, the Partnership closed the GP Buy-In Transaction whereby the Partnership acquired from its then private equity sponsor, ECP, (i) Summit Investments, which owned the Partnership’s General Partner, and (ii) through its indirect ownership of SMP Holdings, 3,415,646 of its common units. Consideration paid to ECP included a $35.0 million cash payment and warrants to purchase up to 666,667 common units. Equity Compensation Plans The information relating to SMLP’s equity compensation plans required by Item 5 is included in Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. 69 Table of Contents Item 7. 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 the Partnership and its subsidiaries. As a result, the following discussion for the year ended December 31, 2020 should be read in conjunction with the consolidated financial statements and notes thereto included in this Annual 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. The discussion of our financial condition and results of operations for the years ended December 31, 2019 and December 31, 2018 included in Exhibit 99.2, Updated 2019 Annual Report on Form 10-K - Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, of our Form 8-K dated August 7, 2020, is incorporated by reference into this MD&A. 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, our Core Focus Areas and our Legacy Areas. Further details on our Focus Areas and Legacy Areas are summarized below. • • 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 decrease 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. 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 a portion of our 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 in the Williston Basin, Piceance Basin, and Permian Basin segments, (ii) the sale of natural gas we retain from certain Barnett Shale customers and (iii) the sale of condensate we retain from our gathering services in the Piceance Basin segment. During the year ended December 31, 2020, these additional activities accounted for approximately 13% of total revenues. We also have indirect exposure to changes in commodity prices in that persistently low commodity prices may cause our customers to delay and/or cancel drilling and/or completion activities or temporarily shut-in production, which would reduce the volumes of natural gas and crude oil (and associated volumes of produced water) that we gather. If certain of our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, the associated MVCs, if any, ensure that we will earn a minimum amount of revenue. 70 Table of Contents 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, 2020 and 2019” section herein. Net income (loss) Reportable segment adjusted EBITDA Utica Shale Ohio Gathering Williston Basin DJ Basin Permian Basin Piceance Basin Barnett Shale Marcellus Shale Net cash provided by operating activities Capital expenditures(1) Investment in Double E equity method investee Net cash distributions to noncontrolling interest SMLP unitholders Series A Preferred Unit distributions Net borrowings under Revolving Credit Facility Repayments on SMPH term loan Open Market Repurchases of 2022 and 2025 Senior Notes (Note 9) Tender Offers of 2022 and 2025 Senior Notes (Note 9) TL Restructuring (Note 9) Proceeds from issuance of Subsidiary Series A preferred units, net of issuance costs Preferred Tender (Note 9) Purchase of common units in GP Buy-In Transaction $ $ $ $ Year ended December 31, 2020 2019 (In thousands) 189,078 $ (393,726) 32,783 $ 31,056 52,060 19,449 4,426 88,820 32,093 22,015 198,589 $ 43,128 99,927 6,037 $ — 180,000 (6,300) (145,567) (47,530) (26,500) 48,710 (25,000) (41,778) 29,292 39,126 69,437 18,668 (879) 98,765 43,043 20,051 161,741 182,291 18,316 68,874 28,500 211,000 (65,250) — — — 27,392 — — (1) See "Liquidity and Capital Resources" herein and Note 20 to the consolidated financial statements for additional information on capital expenditures. 71 Table of Contents Key Matters for the Year ended December 31, 2020. The following items are reflected in our financial results for the fiscal year ended December 31, 2020: • • • • • • • • • GP Buy-In Transaction. In May 2020, the Partnership completed the GP Buy-In Transaction whereby the Partnership acquired from its then private equity sponsor, ECP, (i) Summit Investments, which indirectly owned the Partnership’s General Partner, (ii) through its ownership of SMP Holdings, 3,415,646 of its common units and (iii) a deferred purchase price obligation receivable owed by the Partnership. Consideration paid to ECP included a $35.0 million cash payment and warrants to purchase up to 666,667 common units. In connection with the closing of the GP Buy-In Transaction, ECP’s management resigned from the Board of Directors and fully exited its investment in the Partnership (other than retaining the aforementioned warrants). Refer to Note 1 – Organization, Business Operations and Presentation and Consolidation for details. Suspension of common and preferred unit distributions. In May 2020, and in conjunction with the GP Buy-In Transaction, the Partnership suspended distributions to holders of its common units and its Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. The suspension of distributions enabled the Partnership to retain an incremental $76 million per annum of operating cash flow and reallocate this retained cash to indebtedness reduction, liability management transactions and other corporate initiatives. The unpaid cash distributions on the Series A Preferred Units continue to accrue semi-annually, until paid. July 2020 Series A Preferred Unit Exchange. In July 2020, the Partnership completed the Preferred Exchange Offer, whereby it issued 837,547 SMLP common units in exchange for 62,816 Series A Preferred Units. Upon closing the Preferred Exchange Offer, it eliminated $66.5 million of the Series A Preferred Unit liquidation preference amount, inclusive of $3.7 million of accrued distributions due as of the settlement date. Open Market Repurchase of Senior Notes. Throughout 2020, the Partnership completed its Open Market Repurchases, which resulted in the extinguishment of $32.4 million of face value of the 2022 Senior Notes and $201.8 million of face value of the 2025 Senior Notes. Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 Senior Notes and 2025 Senior Notes, plus accrued interest totaled $150.3 million and the Partnership recognized a $86.4 million gain on the extinguishment of debt related to these Open Market Repurchases during 2020. Debt Tender Offers. In September 2020, the Co-Issuers completed the Debt Tender Offers to purchase a portion of their 2022 Senior Notes and 2025 Senior Notes. Upon completion of the Debt Tender Offers, the Co-Issuers repurchased $33.5 million principal amount of the 2022 Senior Notes and $38.7 million principal amount of the 2025 Senior Notes. Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 and 2025 Senior Notes, plus accrued interest, totaled $48.7 million, and the Partnership recognized a $23.3 million gain on the extinguishment of debt related to the Debt Tender Offers during 2020. TL Restructuring. In November 2020, the Partnership completed the TL Restructuring. All of the Term Loan Lenders participated in the TL Restructuring. As part of the TL Restructuring, the Partnership paid SMP Holdings $26.5 million in cash as consideration to fully settle the deferred purchase price obligation, which SMP Holdings then paid to the Term Loan Lenders. In addition, the Term Loan Lenders executed the Strict Foreclosure on the 2,306,972 common units pledged as collateral under the SMPH Term Loan in full satisfaction of SMP Holdings’ outstanding obligations under the SMPH Term Loan. December 2020 Series A Preferred Unit Tender. On December 29, 2020, the Partnership completed the Preferred Tender Offer, whereby it accepted 75,075 Series A Preferred Units for a purchase price of $333.00 per Series A Preferred Unit and an aggregate purchase price of $25.0 million. Upon closing the Preferred Tender Offer, it eliminated $82.7 million of the Series A Preferred Unit liquidation preference due as of the settlement date, inclusive of $7.6 million of accrued distributions. Double E Project. For the year ended December 2020, the Partnership’s proportionate share of capital calls due in 2020 totaled $99.9 million, which includes $2.7 million in capitalized interest, and was funded with $20.6 million of Partnership generated funds and the issuance of $85.3 million of Subsidiary Series A Preferred Units. 2020 Restructuring Costs. In the fourth quarter of 2020, we completed an internal initiative to evaluate and transform our cost structure, enhance margins and improve our competitive position in response to COVID-19 and the related weakening of the economy. For the year ended December 31, 2020, we incurred approximately $5.6 million in restructuring costs relating to this initiative (included in general and administrative expense). 72 Table of Contents • 2020 Impairments. In the fourth quarter of 2020, we recorded $8.6 million of impairments related to certain long-lived assets, of which $5.1 million related to a January 2021 sale of compressor equipment for a total cash purchase price of $8.0 million. Key Matters for the Year ended December 31, 2019. The following items are reflected in our financial results for the fiscal year ended 2019: • • • • • • • • Equity Method Investment Impairment. 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. Goodwill Impairment. 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. Disposition. In March 2019, we identified certain triggering events 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 $9.7 million related to these assets. Double E Project. 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 joint venture agreement (described below) 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. Summit Permian Transmission. 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. Double E Financing. 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. Red Rock. 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. Tioga Midstream. 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 18 to the consolidated financial statements for details on the sale of Tioga Midstream. 73 Table of Contents • 2019 Restructuring Costs. 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). For the year ended December 31, 2020, we incurred an additional $3.5 million related to this initiative. Trends and Outlook Our business has been, and we expect our future business to continue to be, affected by the following key trends: • • • • • Ongoing impact of the COVID-19 pandemic and reduced demand and prices for oil; 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. Ongoing impact of the COVID-19 pandemic and reduced demand and prices for oil. We are closely monitoring the impact of the outbreak of COVID-19 on all aspects of our business, including how it has impacted and will impact our customers, employees, supply chain and distribution network. We are unable to predict the ultimate impact that COVID-19 and related factors may have on our business, future results of operations, financial position or cash flows. Given the dynamic nature of the COVID-19 pandemic and related market conditions, we cannot reasonably estimate the period of time that these events will persist or the full extent of the impact they will have on our business. The extent to which our operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including changes in the severity of the pandemic, countermeasures taken by governments, businesses and individuals to slow the spread of the pandemic, and the development and availability of treatments and vaccines and the extent to which these treatments and vaccines may remain effective as potential new strains of the coronavirus emerge. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown. In response to the COVID-19 pandemic, we have modified our business practices, including restricting employee travel, modifying employee work locations, implementing social distancing and enhancing sanitary measures in our facilities. Many of our suppliers, vendors and service providers have made similar modifications. The resources available to employees working remotely may not enable them to maintain the same level of productivity and efficiency, and these and other employees may face additional demands on their time. Our increased reliance on remote access to our information systems increases our exposure to potential cybersecurity breaches. We may take further actions as government authorities require or recommend or as we determine to be in the best interests of our employees, customers, partners and suppliers. There is no certainty that such measures will be sufficient to mitigate the risks posed by the virus, in which case our employees may become sick, our ability to perform critical functions could be impaired, and we may be unable to respond to the needs of our business. The resumption of normal business operations after such interruptions may be delayed or constrained by lingering effects of COVID-19 on our suppliers, third-party service providers, and/or customers. In addition to the significant reduction in global demand for oil and natural gas caused by the economic effects of the COVID-19 pandemic, there were also volatile oil prices during 2020 largely due to a supply and demand imbalance and actions by members of OPEC and other foreign, oil-exporting countries. This disrupted the oil and natural gas exploration and production industry and other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. Over the past several months, we have collaborated extensively with our customer base regarding production reductions and delays to drilling and completion activities in light of the current commodity price backdrop and COVID-19 pandemic. Given 74 Table of Contents continued volatility in market conditions since March 2020, and based on recently updated production forecasts and 2021 development plans from our customers, we currently expect our 2021 results to be affected by decreased drilling activity. 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 21% from 2020 to 2019, primarily due to natural gas supply exceeding demand. The average daily Henry Hub Natural Gas Spot Price was $2.03 per MMBtu during 2020, compared with $2.56 per MMBtu during 2019. Henry Hub closed at $2.36 per MMBtu on December 31, 2020. As of February 18, 2021, Henry Hub 12-month strip pricing closed at $3.11 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 3.05 Tcfe in 2020, which was 23.4% higher than in 2019. 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 2020, with the average daily Cushing, Oklahoma West Texas Intermediate crude oil spot price decreasing from an average $56.99 per barrel during 2019 to an average of $39.16 per barrel during 2020, representing a 31.3% 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 677 in December 2019 to 267 in December 2020, 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 from their underlying assets. In general, we expect our producer customers to maintain moderate completion and production activities across many of our systems relative to our previous expectations as a result of the 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 announced the elimination of our common unit distribution in May 2020 beginning with the distribution paid in respect of the second quarter of 2020, and this action 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. 75 Table of Contents 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. 76 Table of Contents How We Evaluate Our Operations We conduct and report our operations in the midstream energy industry through eight reportable segments: Utica Shale, Ohio Gathering, Williston Basin, DJ Basin, Permian Basin, Piceance Basin, Barnett Shale, and Marcellus Shale. Each of our reportable segments provides midstream services in a specific geographic area and 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 20 to the consolidated financial statements). Our management uses a variety of financial and operational metrics to analyze our consolidated and segment performance and we view these metrics as important factors in evaluating our profitability. These metrics include (i) throughput volume, (ii) revenues, (iii) operation and maintenance expenses, and (iv) 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. 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. 77 Table of Contents 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 MVC 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. 78 Table of Contents Results of Operations Consolidated Overview for the Years Ended December 31, 2020 and 2019 The following table presents certain consolidated data and volume throughput for the years ended December 31, 2020 and 2019. Year ended December 31, 2020 2019 Percentage change Revenues: Gathering services and related fees Natural gas, NGLs and condensate sales Other revenues Total revenues Costs and expenses: Cost of natural gas and NGLs Operation and maintenance General and administrative Depreciation and amortization Transaction costs Gain on asset sales, net Long-lived asset impairment Goodwill impairment Total costs and expenses Other income Interest expense Gain on early extinguishment of debt Income (loss) before income taxes and equity method investment income (loss) Income tax benefit (expense) Income (loss) from equity method investees Net income (loss) Volume throughput (1): Aggregate average daily throughput - natural gas (MMcf/d) Aggregate average daily throughput - liquids (Mbbl/d) $ $ (In thousands) 302,792 $ 49,319 31,362 383,473 36,653 86,030 73,438 118,132 2,993 (307) 13,089 — 330,028 48 (78,894) 203,062 177,661 146 11,271 189,078 $ 326,747 86,994 29,787 443,528 63,438 98,719 55,947 110,354 3,017 (1,536) 60,507 16,211 406,657 451 (91,966) — (54,644) (1,231) (337,851) (393,726) (7%) (43%) 5% (14%) (42%) (13%) 31% 7% (1%) (80%) (78%) * (19%) (89%) * * * * * 1,375 79 1,397 (2%) 105 (25%) * Not considered meaningful (1) Exclusive of volume throughput for Ohio Gathering. For additional information, see the "Ohio Gathering" section herein. Volumes – Gas. Natural gas throughput volumes decreased 22 MMcf/d for the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily reflecting: • • • • • a volume throughput increase of 5 MMcf/d for the Marcellus Shale segment. a volume throughput decrease of 88 MMcf/d for the Piceance Basin segment. a volume throughput increase of 85 MMcf/d for the Utica Shale segment. a volume throughput increase of 14 MMcf/d for the Permian Basin segment. a volume throughput decrease of 39 MMcf/d for the Barnett Shale segment. Volumes – Liquids. Crude oil and produced water throughput volumes at the Williston segment decreased 26 Mbbl/d for the year ended December 31, 2020 compared to the year ended December 31, 2019. For additional information on volumes, see the "Segment Overview for the Years Ended December 31, 2020 and 2019" section herein. 79 Table of Contents Revenues. Total revenues decreased $60.1 million during the year ended December 31, 2020 compared to the prior year primarily comprised of a $24.0 million decrease in gathering services and related fees and a $37.7 million decrease in natural gas, NGLs and condensate sales. Gathering services and related fees. Gathering services and related fees decreased $24.0 million compared to the year ended December 31, 2019, primarily reflecting: • • • • • • a $7.2 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting $7.5 million in lower gas gathering revenue attributable to a MVC with a customer in 2019 that expired in 2020. a $14.7 million decrease in gathering services and related fees in the Piceance Basin relating to lower volume throughput due to a lack of drilling and completion activity and natural production declines. a $4.6 million increase in gathering services and related fees in the Utica Shale primarily due to the completion of new wells throughout 2019, and in 2020, and a more favorable volume and gathering rate mix from customers, partially offset by natural production declines from existing wells. a $18.4 million decrease in gathering services and related fees in the Williston Basin primarily reflecting a 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 as well as lower liquids volume throughput, partially offset by the completion of new wells through 2019 and 2020. a $1.9 million increase in gathering services and related fees in the DJ Basin primarily as a result of ongoing drilling and completion activity across our service area, a more favorable volume and gathering rate mix from customers and the commissioning of our new natural gas processing plant in June 2019, partially offset by natural production declines and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic. a $6.5 million increase in gathering services and related fees in the Permian Basin primarily as a result of an uptick in customer volumes, partially offset by natural production declines from wells previously put in service. Costs and expenses. Total costs and expenses decreased $76.6 million during the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily reflecting: • • • a $31.2 million decrease in long-lived asset impairments in the DJ Basin in 2019. a $16.2 million decrease in goodwill impairment charge relating to the Mountaineer Midstream system in the Marcellus Basin in 2019. a $14.2 million decrease in long-lived asset impairments relating to the sale of certain Red Rock Gathering system assets in the Piceance Basin in 2019. Cost of natural gas and NGLs. Cost of natural gas and NGLs decreased $26.8 million during the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily driven by lower natural gas, NGL and crude oil marketing activity. Operation and maintenance. Operation and maintenance expense decreased $12.7 million for the year ended December 31, 2020 compared to the year ended December 31, 2019. Depreciation and amortization. The increase in depreciation and amortization expense during 2020 compared to the year ended December 31, 2019 was primarily due to the assets placed into service in the Permian Basin. Interest Expense. The decrease in interest expense in the year ended December 31, 2020 compared to the year ended December 31, 2019, was primarily a result of our liability management initiatives which included our Open Market Repurchases and Tender Offers, partially offset by a higher outstanding balance on the Revolving Credit Facility. Gain on early extinguishment of debt. The $203.1 million gain on the early extinguishment of debt is primarily related to liability management initiatives undertaken during 2020 that resulted in a $86.4 million gain from the Open Market Repurchases, a $23.3 million gain from the Debt Tender Offers, and a $93.9 million gain from our TL Restructuring. Further details of our liability management results are summarized below. 80 Table of Contents ECP Loan Repayment Open Market Repurchases Tender Offers TL Restructuring Total 2022 2025 2022 2025 Senior Notes Senior Notes Senior Notes Senior Notes (in thousands) Gain on Repurchases of Senior Notes and TL Restructuring Debt issue costs Transaction cost Gain (loss) on debt extinguishment $ $ — $ (361) (249) (610) $ 11,554 $ (143) (105) 11,306 $ 76,789 $ (1,541) (105) 75,143 $ 9,223 $ (125) (467) 8,631 $ 15,479 $ (351) (467) 14,661 $ 99,175 $ (2,724) (2,520) 93,931 $ 212,220 (5,245) (3,913) 203,062 81 Table of Contents Segment Overview for the Years Ended December 31, 2020 and 2019 Utica Shale. The Utica Shale reportable segment includes the Summit Utica system. Volume throughput for our Summit Utica system follows. Average daily throughput (MMcf/d) Year ended December 31, Utica Shale 2020 2019 358 273 Percentage Change 31% Volume throughput increased compared to the year ended December 31, 2020 primarily due to new wells that came online in the fourth quarter of 2019 and through the first three quarters of 2020. In addition, volume throughput was impacted by an increase in temporary production curtailments, completion activity and other operational downtime associated with customers on existing pad sites. Financial data for our Utica Shale reportable segment follows. Revenues: Gathering services and related fees Other revenues Total revenues Costs and expenses: Operation and maintenance General and administrative Depreciation and amortization Gain on asset sales, net Total costs and expenses Add: Depreciation and amortization Adjustments related to capital reimbursement activity Gain on asset sales, net Segment adjusted EBITDA * Not considered meaningful Utica Shale Year ended December 31, 2020 2019 (Dollars in thousands) $ $ 36,509 $ — $ 36,509 3,396 301 7,696 (35) 11,358 7,696 (29) (35) 32,783 $ Percentage Change 14% 7% (18%) (43%) 0% * (8%) 12% 31,926 2,065 33,991 4,151 530 7,659 — 12,340 7,659 (18) — 29,292 Year ended December 31, 2020. Segment adjusted EBITDA increased $3.5 million compared to the year ended December 31, 2019, primarily due to the volume throughput previously discussed. 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. Average daily throughput (MMcf/d) * Not considered meaningful Year ended December 31, Ohio Gathering 2020 2019 571 732 Percentage Change (22%) Volume throughput for the Ohio Gathering system in 2020 decreased compared to the year ended December 31, 2019 as a result of natural production declines on existing wells on the system, fewer well connections, temporary production shut-ins and was partially offset by the completion of new wells. 82 Table of Contents Financial data for our Ohio Gathering reportable segment, based on a one-month lag follows. Proportional adjusted EBITDA for equity method investees Segment adjusted EBITDA Year ended December 31, Ohio Gathering 2020 2019 (Dollars in thousands) Percentage Change $ $ 31,056 $ 31,056 $ 39,126 39,126 (21%) (21%) Year ended December 31, 2020. Segment adjusted EBITDA for equity method investees decreased $8.1 million compared to the year ended December 31, 2019, primarily related to lower volume throughput described above. 83 Table of Contents Williston Basin. The Polar and Divide, Tioga Midstream (through March 22, 2019; refer to Note 18 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. Aggregate average daily throughput - natural gas (MMcf/d) Aggregate average daily throughput - liquids (Mbbl/d) Year ended December 31, Williston Basin 2020 14 79 2019 12 105 Percentage Change 17% (25%) Natural gas. Natural gas volume throughput in 2020 increased compared to the year ended December 31, 2019, primarily reflecting the completion of new wells behind the Bison Midstream system in the fourth quarter of 2019 and through 2020 partially offset by natural production declines and the sale of Tioga Midstream. Liquids. Liquids volume throughput in 2020 decreased compared to the year ended December 31, 2019, primarily associated with natural production declines, deferral of completion activities, shut-ins and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic, partially offset by the completion of new wells throughout 2019 and 2020. Financial data for our Williston Basin reportable segment follows. Revenues: Gathering services and related fees Natural gas, NGLs and condensate sales Other revenues Total revenues Costs and expenses: Cost of natural gas and NGLs Operation and maintenance General and administrative Depreciation and amortization Gain on asset sales, net Long-lived asset impairment Total costs and expenses Add: Depreciation and amortization Adjustments related to capital reimbursement activity Gain on asset sales, net Long-lived asset impairment Segment adjusted EBITDA * Not considered meaningful Williston Basin Year ended December 31, 2020 2019 (Dollars in thousands) Percentage Change 59,239 $ 20,018 13,438 92,695 12,741 23,793 1,738 25,911 (50) 2,421 66,554 25,911 (2,363) (50) 2,421 52,060 $ 77,626 16,461 11,564 105,651 5,821 27,172 1,493 19,829 (1,177) 10 53,148 19,829 (1,728) (1,177) 10 69,437 (24%) 22% 16% (12%) 119% (12%) 16% 31% (96%) * 25% (25%) $ $ Year ended December 31, 2020. Segment adjusted EBITDA decreased $17.4 million compared to the year ended December 31, 2019 primarily associated with the decreased liquid volume throughput described above, and the sale of Tioga Midstream in March of 2019. The decrease was partially offset by the increased natural gas volume throughput described above. 84 Table of Contents 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. Average daily throughput (MMcf/d) Year ended December 31, DJ Basin 2020 2019 Percentage Change 26 27 (4%) Volume throughput in 2020 decreased compared to the year ended December 31, 2019, primarily as a result of natural production declines, shut-ins and fewer well connection through 2020. Financial data for our DJ Basin reportable segment follows. Revenues: Gathering services and related fees Natural gas, NGLs and condensate sales Other revenues Total revenues Costs and expenses: Cost of natural gas and NGLs Operation and maintenance General and administrative Depreciation and amortization Loss on asset sales, net Long-lived asset impairment Total costs and expenses Add: Depreciation and amortization Adjustments related to capital reimbursement activity Loss on asset sales, net Long-lived asset impairment Segment adjusted EBITDA * Not considered meaningful DJ Basin Year ended December 31, 2020 2019 (Dollars in thousands) $ $ 23,868 $ 245 3,957 28,070 67 9,579 1,088 6,146 20 3,692 20,592 6,146 2,113 20 3,692 19,449 $ 21,940 389 3,721 26,050 34 7,616 315 3,732 — 34,913 46,610 3,732 583 — 34,913 18,668 Percentage Change 9% (37%) 6% 8% 97% 26% 245% 65% * (89%) (56%) 4% Year ended December 31, 2020. Segment adjusted EBITDA increased $0.8 million compared to the year ended December 31, 2019, primarily associated with a more favorable volume and gathering rate mix from customers. 85 Table of Contents 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. Average daily throughput (MMcf/d) Year ended December 31, Permian Basin 2020 2019 33 19 Percentage Change 74% Volume throughput in 2020 increased compared to the year ended December 31, 2019, primarily as a result of new well connections in the fourth quarter of 2019 and through the first quarter of 2020, partially offset by natural production declines from wells previously in service. Financial data for our Permian Basin reportable segment follows. Revenues: Gathering services and related fees Natural gas, NGLs and condensate sales Other revenues Total revenues Costs and expenses: Cost of natural gas and NGLs Operation and maintenance General and administrative Depreciation and amortization Gain on asset sales, net Long-lived asset impairment Total costs and expenses Add: Depreciation and amortization Gain on asset sales, net Long-lived asset impairment Segment adjusted EBITDA * Not considered meaningful Permian Basin Year ended December 31, 2020 2019 (Dollars in thousands) $ $ 10,091 $ 18,857 585 29,533 18,785 6,038 284 5,455 — 324 30,886 5,455 — 324 4,426 $ 3,610 16,383 310 20,303 15,113 5,755 314 4,868 (148) 1,327 27,229 4,868 (148) 1,327 (879) Percentage Change 180% 15% 89% 45% 24% 5% (10%) 12% * (76%) 13% * Year ended December 31, 2020. Segment adjusted EBITDA increased $5.3 million compared to the year ended December 31, 2019, primarily as a result of higher volumes throughput described above. 86 Table of Contents Piceance Basin. The Grand River system provides midstream services for the Piceance Basin reportable segment. Volume throughput for our Piceance Basin reportable segment follows. Aggregate average daily throughput (MMcf/d) Year ended December 31, Piceance Basin 2020 2019 Percentage Change 364 452 (19%) Volume throughput decreased in 2020 compared to the year ended December 31, 2019, as a result of natural production declines. Financial data for our Piceance Basin reportable segment follows. Revenues: Gathering services and related fees Natural gas, NGLs and condensate sales Other revenues Total revenues Costs and expenses: Cost of natural gas and NGLs Operation and maintenance General and administrative Depreciation and amortization (Gain) loss on asset sales, net Long-lived asset impairment Total costs and expenses Add: Depreciation and amortization Adjustments related to MVC shortfall payments Adjustments related to capital reimbursement activity (Gain) loss on asset sales, net Long-lived asset impairment Segment adjusted EBITDA * Not considered meaningful Piceance Basin Year ended December 31, 2020 2019 (Dollars in thousands) Percentage Change $ 106,657 $ 121,357 2,612 4,621 113,890 1,717 21,064 1,053 45,203 (190) 7 68,854 45,203 — (1,236) (190) 7 $ 88,820 $ 7,954 4,327 133,638 5,612 27,306 1,009 47,018 104 14,162 95,211 47,018 (103) (843) 104 14,162 98,765 (12%) (67%) 7% (15%) (69%) (23%) 4% (4%) * * (28%) (10%) Year ended December 31, 2020. Segment adjusted EBITDA decreased $9.9 million compared to the year ended December 31, 2019, primarily associated with the volume throughput decrease described above, and a decrease in operations and maintenance expense primarily due to lower compensation expense associated with lower headcount from our cost cutting initiatives. 87 Table of Contents 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. Average daily throughput (MMcf/d) Year ended December 31, Barnett Shale 2020 2019 212 251 Percentage Change (16%) Volume throughput decreased in 2020 compared to the year ended December 31, 2019 reflecting natural production declines partially offset by new volumes from well recompletion and workover activity throughout 2020. Financial data for our Barnett Shale reportable segment follows. Revenues: Gathering services and related fees Natural gas, NGLs and condensate sales Other revenues (1) Total revenues Costs and expenses: Cost of natural gas and NGLs Operation and maintenance General and administrative Depreciation and amortization Gain on asset sales, net Long-lived asset impairment Total costs and expenses Add: Depreciation and amortization Adjustments related to MVC shortfall payments Adjustments related to capital reimbursement activity Gain on asset sales, net Long-lived asset impairment Segment adjusted EBITDA Barnett Shale Year ended December 31, 2020 2019 (Dollars in thousands) Percentage Change 40,687 $ 7,587 6,185 54,459 3,341 18,814 1,306 15,174 (19) 4,902 43,518 47,862 17,147 6,793 71,802 10,751 21,729 968 15,354 (325) 10,095 58,572 16,112 16,575 — 157 (19) 4,902 32,093 $ 3,579 (111) (325) 10,095 43,043 (15%) (56%) (9%) (24%) (69%) (13%) 35% (1%) (94%) (51%) (26%) (25%) $ $ *Not considered meaningful (1) Includes the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues. Year ended December 31, 2020. Segment adjusted EBITDA decreased $10.9 million compared to the year ended December 31, 2019 primarily related to the decreased volume throughput described above. 88 Table of Contents 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. Average daily throughput (MMcf/d) Year ended December 31, Marcellus Shale 2020 2019 368 363 Percentage Change 1% Volume throughput increased in 2020 compared to the year ended December 31, 2019, primarily due to new well connection in the third quarter of 2020, partially offset by natural production declines. Financial data for our Marcellus Shale reportable segment follows. Revenues: Gathering services and related fees Total revenues Costs and expenses: Operation and maintenance General and administrative Depreciation and amortization Gain on asset sales, net Goodwill impairment Total costs and expenses Add: Depreciation and amortization Goodwill impairment Adjustments related to capital reimbursement activity Gain on asset sales, net Segment adjusted EBITDA *Not considered meaningful Marcellus Shale Year ended December 31, 2020 2019 (Dollars in thousands) $ 25,741 $ 25,741 3,343 345 9,195 (8) — 12,875 9,195 — (38) (8) 22,015 $ $ 24,471 24,471 3,861 521 9,141 — 16,211 29,734 9,141 16,211 (38) — 20,051 Percentage Change 5% 5% (13%) (34%) 1% * * (57%) 10% Year ended December 31, 2020. Segment adjusted EBITDA increased $2.0 million compared to the year ended December 31, 2019, primarily associated with the increased volume throughput described above. 89 Table of Contents Corporate and Other Overview for the Years Ended December 31, 2020 and 2019 Corporate and Other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, natural gas and crude oil marketing services, transaction costs, interest expense and early extinguishment of debt. Revenues: Total revenues Costs and expenses: Cost of natural gas and NGLs General and administrative Transaction costs Interest expense Gain on asset sales or disposals Long-lived asset impairment Gain on early extinguishment of debt * Not considered meaningful Corporate and Other Year ended December 31, 2020 2019 (Dollars in thousands) $ 2,575 $ 27,622 — 67,324 2,993 78,894 (21) 1,740 (203,062) 26,107 50,797 3,017 91,966 — — — Percentage Change (91%) * 33% (1%) (14%) * * * Total Revenues. Total revenues attributable to Corporate and Other was due to gathering services, natural gas, and condensate sales. The decrease of $25.0 million compared to the year ended December 31, 2019 was primarily attributable to the wind down of our marketing group in 2020 as well as lower natural gas 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 in 2019. The decrease of $26.1 million compared to the year ended December 31, 2019 was attributable to the wind down of our marketing group in 2020. General and administrative. General and administrative expense attributable to Corporate and Other increased by $16.5 million, primarily related to a $17.0 million loss contingency accrual in 2020, see note 11 of the consolidated financial statements for additional information. Transaction costs. Transaction costs recognized during the year ended December 31, 2020 are primarily related to costs associated with our liability management initiatives. Interest Expense. Interest expense decreased $13.1 million compared to the year ended December 31, 2019 primarily as a result of our liability management initiatives which included our Open Market Repurchases and Tender Offers, partially offset by a higher outstanding balance on the Revolving Credit Facility. Gain on Early Extinguishment of Debt. The gain on the early extinguishment of debt is primarily related to liability management initiatives undertaken during 2020 that resulted in a $86.4 million gain from the Open Market Repurchases, a $23.3 million gain from the Debt Tender Offers, and a $93.9 million gain from our TL Restructuring. Liquidity and Capital Resources We depend primarily on funds generated from our operations, our Revolving Credit Facility, our cash and cash equivalents balance, and capital markets as our primary sources of liquidity. Looking forward to 2021, we will seek to reduce indebtedness and extend our indebtedness maturities. As a result, we expect to fund future expenditures from cash generated by our operations, our Revolving Credit Facility, our cash equivalents on hand. If optimal, we may also consider accessing the capital markets, opportunistic divestitures or joint ventures involving our existing midstream assets. Debt Revolving Credit Facility. We have a $1.1 billion senior secured Revolving Credit Facility with a maturity of May 2022 (see Note 9 to the consolidated financial statements). As of December 31, 2020, the outstanding balance of the Revolving Credit Facility was $857.0 million and the unused portion totaled $238.9 million, after giving effect to the issuance thereunder of a $4.1 million 90 Table of Contents 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, 2020 was approximately $105 million. There were no defaults or events of default during 2020, and as of December 31, 2020, we were in compliance with the financial covenants in the Revolving Credit Facility. Our total leverage ratio and senior secured leverage ratio (as defined in the Revolving Credit Agreement) was 5.1 to 1.0 and 3.2 to 1.0, respectively, relative to maximum threshold limits of 5.75 to 1.0 and 3.5 to 1.0. Given further deterioration of market conditions, decreased drilling activity, the deferral of well completions from customers, limitations on our ability to access the capital markets at a competitive cost to fund our capital expenditures and, on a limited scale, temporary production curtailments, we could have total leverage and senior secured leverage ratios that are higher than the levels prescribed in the applicable indebtedness agreements. Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations and cash flows. See Note 9 to the consolidated financial statements for more information on the Revolving Credit Facility and the issuance of the $4.1 million letter of credit. 2022 Senior Notes. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Finance Corp. (together with Summit Holdings, the "Co- Issuers") co-issued $300.0 million of 5.5% senior unsecured notes maturing August 15, 2022 (the "2022 Senior Notes" and, together with the 2025 Senior Notes (defined below), the “Senior Notes”). As of December 31, 2020, the outstanding balance of the 2022 Senior Notes is $234.0 million. We pay interest on the 2022 Senior Notes semi-annually in cash in arrears on February 15 and August 15 of each year. The 2022 Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 2022 Senior Notes are effectively subordinated in right of payment to all secured indebtedness, to the extent of the collateral securing such indebtedness. The Co-Issuers may redeem all or part of the 2022 Senior Notes at a redemption price of 100.000%, plus accrued and unpaid interest, if any. Debt issuance costs of $5.1 million are being amortized over the life of the 2022 Senior Notes. As of and during the year ended December 31, 2020, we were in compliance with the financial covenants governing our 2022 Senior Notes. 2025 Senior Notes. In February 2017, the Co-Issuers co-issued $500.0 million of 5.75% senior unsecured notes maturing April 15, 2025 (the “2025 Senior Notes”). As of December 31, 2020, the outstanding balance of the 2025 Senior Notes was $259.5 million. We pay interest on the 2025 Senior Notes semi- annually in cash in arrears on April 15 and October 15 of each year. The 2025 Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 2025 Senior Notes are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness. The Co-Issuers may redeem all or part of the 2025 Senior Notes at a redemption price of 104.313% (with the redemption price declining ratably each April 15 to 100.000% on April 15, 2023), plus accrued and unpaid interest, if any, to, but not including, the redemption date. Debt issuance costs of $7.7 million are being amortized over the life of the 2025 Senior Notes. As of and during the year ended December 31, 2020, we were in compliance with the financial covenants governing our 2025 Senior Notes. For additional information on our long-term debt, see Note 9 to the consolidated financial statements. Cash Flows Year ended December 31, 2020 2019 (In thousands) 198,589 $ (140,569) (79,398) (21,378) $ 161,741 (90,870) (50,122) 20,749 $ $ Net cash provided by operating activities Net cash used in investing activities Net cash provided by (used in) financing activities Net change in cash, cash equivalents and restricted cash The components of the net change in cash, cash equivalents and restricted cash were as follows: Operating activities. Details of cash flows from operating activities follow. Cash flows from operating activities for the year ended December 31, 2020, primarily reflected: • • net income of $189.1 million plus adjustments of $40.5 million for non-cash items; and $50.0 million increase in working capital accounts. Cash flows from operating activities for the year ended December 31, 2019, primarily reflected: 91 Table of Contents • • a $7.3 million increase in cash interest payments; 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, 2020 primarily reflected: • • $99.9 million of investments in our equity method investee; and $43.1 million of capital expenditures primarily attributable to the ongoing development of our Williston, DJ, Utica and Permian segments. 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. Financing activities. Details of cash flows from financing activities follow. Cash flows used in financing activities during the year ended December 31, 2020 primarily reflected: • • • • • • • • • • • $145.6 million paid for open market repurchases of the 2022 and 2025 Notes; $47.5 million paid for tender offer of 2022 and 2025 Senior Notes; $41.8 million for the purchase of common units in the GP Buy-In Transaction; $35.0 million for the repayment of the ECP Loan; $26.5 million for cash paid in connection with the TL Restructuring; $25.0 million of cash paid for in connection with the Preferred Tender Offer; $6.3 million of cash repayments on the SMPH Term loan; and $6.0 million of distributions offset by; $180.0 million of net proceeds from borrowings on our Revolving Credit Facility; $48.7 million in proceeds from the issuance of our Subsidiary Series A Preferred Units and; $35.0 million in proceeds from the ECP Loan. 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 payment on Term Loan B; and $27.4 of net proceeds from the issuance of Subsidiary Series A Preferred Units. Contractual Obligations Update The Partnership's cash flows generated from operations are also the primary source for funding various contractual obligations. The table below summarizes the Partnership's major commitments as of December 31, 2020 (in thousands): Revolving Credit Facility, due May 2022 (2) 2022 Senior Notes, due August 2022 (2) 2025 Senior Notes, due April 2025 (2) Capital contributions to Double E equity method investment(1) Lease obligations Total $ Total 892,208 $ 255,502 309,193 2021 24,853 $ 12,873 14,919 2022 867,355 $ 242,629 14,919 2023 2024 — $ — 14,919 — $ — 14,919 2025 — — 264,436 172,410 5,772 $ 1,635,085 $ 147,710 2,405 24,700 1,434 202,760 $ 1,151,037 $ — 896 15,815 $ — 573 15,492 $ — 464 264,900 92 Table of Contents (1) (2) The Partnership issued a parental guaranty on behalf of its wholly owned subsidiary to fund the subsidiary’s pro rata share of required Double E construction project capital calls. As of December 31, 2020, this amount represents the Partnership's best estimate of its remaining obligation to fund Double E for the construction of the Double E Project. For the purposes of calculating future interest payments we assumed no change in balance or rate from December 31, 2020. See Note 9 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, 2020, cash paid for capital expenditures totaled $43.1 million which included $14.1 million of maintenance capital expenditures. For the year ended December 31, 2020, we contributed $99.9 million to Double E. 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 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 next twelve months 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 and continued throughout 2020. 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 positive to Summit. We are currently targeting a financing structure that limits cash payments by us during 2021, and which shifts a substantial majority of our Double E capital commitments to third parties, including commercial banks. On December 24, 2019, we entered into an agreement with TPG to fund up to $80.0 million of Permian Holdco’s future capital calls associated with the Double E Project. For the years ended December 31, 2020 and 2019, Permian Holdco issued 55,251 and 30,000 Subsidiary Series A Preferred Units to TPG for net proceeds of $48.7 million and $27.4 million, respectively. We estimate that our 2021 capital program will range from $20.0 million to $35.0 million, including approximately $10.0 million of maintenance capital expenditures. 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 NGL 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. 93 Table of Contents 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. Off-Balance Sheet Arrangements We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2020, our material off-balance sheet arrangements and transactions include (i) a parental guaranty issued on behalf of a wholly owned subsidiary to fund the subsidiary’s pro rata share of required Double E Project construction related capital calls, with the wholly owned subsidiary having an estimated $172.4 million of remaining capital calls due for construction based on the Partnership’s best estimate at December 31, 2020, (ii) letters of credit outstanding against our Revolving Credit Facility aggregating to $4.1 million, and (iii) outstanding surety bonds aggregating to $7.1 million. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. 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 - Debt). SMLP has concluded that it is eligible to provide Alternative Disclosures under the amended disclosure requirements and has early adopted Release 33-10762. The supplemental summarized financial information below reflects SMLP’s separate accounts, the combined accounts of 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 Non- Guarantor Subsidiaries, 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. 94 Table of Contents 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 this Annual Report. Summarized Balance Sheet Information. Summarized balance sheet information as of December 31, 2020 and December 31, 2019 follow. Assets Current assets Noncurrent assets Liabilities Current liabilities Noncurrent liabilities Assets Current assets Noncurrent assets Liabilities Current liabilities Noncurrent liabilities December 31, 2020 SMLP Obligor Group (In thousands) 2,265 $ 6,952 13,339 $ 19,987 78,304 2,277,807 50,192 1,398,872 December 31, 2019 SMLP Obligor Group (In thousands) 2,311 $ 9,572 9,662 $ 184,088 109,664 2,389,032 73,877 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 years ended December 31, 2020 and 2019 follow. Total revenues Total costs and expenses Income (loss) before income taxes and income from equity method investees Income from equity method investees Net income (loss) Total revenues Total costs and expenses Loss before income taxes and income from equity method investees Income from equity method investees Net loss Critical Accounting Estimates Year ended December 31, 2020 SMLP Obligor Group (In thousands) $ $ — $ 26,169 (26,000) — (26,016) $ 383,473 302,989 122,108 13,073 135,181 Year ended December 31, 2019 SMLP Obligor Group (In thousands) — $ 4,401 (1,968) — (3,142) $ 443,528 397,939 (28,840) (336,950) (365,790) $ $ The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the amounts of assets, liabilities, 95 Table of Contents revenues and expenses and related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis, based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following describes significant judgments and estimates used in the preparation of our consolidated financial statements. Impairment of Long-Lived Assets. As of December 31, 2020, we had net property, plant and equipment with a carrying value of approximately $1.8 billion and net amortizing intangible assets with a carrying value of approximately $200.0 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. 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 would recognize an impairment loss equal to the amount by which the carrying value exceeds the asset's fair value. We determine fair value using a combination of approaches, including a market-based approach and an income-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. We evaluate our equity method investments for impairment when we believe the current fair value may be less than the carrying amount and record an impairment if we believe the decline in value is other than temporary. Adjustments for MVC Shortfall Payments. For our calculation of segment adjusted EBITDA, we estimate the impact of expected MVC shortfall payments based on assumptions that include, but are not limited to, contract terms, historical volume throughput data, and expectations regarding future investment expenditures, customer drilling activities, and customer production volumes. 96 Table of Contents Item 7A. Quantitative and Qualitative Disclosures About Market Risk. Interest Rate Risk Our current interest rate risk exposure is largely related to our indebtedness. As of December 31, 2020, we had $493.5 million principal of fixed-rate Senior Notes and $857.0 million outstanding under our variable rate Revolving Credit Facility. While existing fixed-rate debt mitigates the downside impact of fluctuations in interest rates, future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher overall interest costs. In addition, the borrowings under our Revolving Credit Facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. For the year ended December 31, 2020, a hypothetical 1% increase (decrease) in interest rates would have increased (decreased) our interest expense by approximately $7.7 million assuming no changes in amounts drawn or other variables under our Revolving Credit Facility or Senior Notes. Commodity Price Risk We generate a majority of our revenues pursuant to primarily long-term and fee-based gathering agreements, many of which include MVCs and areas of mutual interest. Our direct commodity price exposure relates to (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds and other processing arrangements with certain of our customers in the Williston Basin, Piceance Basin, and Permian Basin segments, (ii) the sale of natural gas we retain from certain Barnett Shale segment customers and (iii) the sale of condensate we retain from certain gathering services in the Piceance Basin segment. Our gathering agreements with certain Barnett Shale customers permit us to retain a certain quantity of natural gas that we sell to offset the power costs we incur to operate our electric-drive compression assets. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices on the Henry Hub Index. We sell retainage natural gas at prices that are based on the Atmos Zone 3 Index. By basing the power prices on a system and basin-relevant market, we are able to closely associate the relationship between the compression electricity expense and natural gas retainage sales. We do not enter into risk management contracts for speculative purposes. 97 Table of Contents Item 8. Financial Statements and Supplementary Data. Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets Consolidated Statements of Operations Consolidated Statements of Partners' Capital Consolidated Statements of Cash Flows Notes to Consolidated Financial Statements 98 99 101 102 103 104 105 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors of Summit Midstream, GP, LLC and the unitholders of Summit Midstream Partners, LP Houston, Texas Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Summit Midstream Partners, LP and subsidiaries (the "Partnership") as of December 31, 2020 and 2019, the related consolidated statements of operations, partners' capital and cash flows, for the years then ended, and the related notes (collectively referred to as the "financial statements"). In our opinion, based on our audits and the report of the other auditors, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the years then ended in conformity with accounting principles generally accepted in the United States of America. We did not audit the financial statements of Ohio Gathering Company, L.L.C. (“Ohio Gathering”) as of and for the year ended December 31, 2019, the Partnership’s investment in which is accounted for by use of the equity method. The accompanying financial statements of the Partnership include its equity investment in Ohio Gathering of $275,000,000 as of December 31, 2019, and its loss from equity method investee in Ohio Gathering of $329,736,000 for the year then ended. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Ohio Gathering for 2019, prior to the 2019 impairment loss discussed in Note 7, which was audited by us, is based solely on the report of the other auditors. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 4, 2021 expressed an unqualified opinion on the Partnership's internal control over financial reporting. Basis for Opinion These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate. GP Buy-In Transaction — Refer to Notes 1 and 14 to the financial statements Critical Audit Matter Description As described in Note 1 to the consolidated financial statements, on May 28, 2020, the transactions contemplated by the Purchase Agreement (the “GP Buy-In Transaction”) closed. As a result of the GP Buy-In Transaction, the Partnership now indirectly owns its General Partner, Summit Midstream Partners LLC (“Summit Investments”). 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 included herein prior to the GP Buy-In Transaction are those of Summit Investments. We identified the GP Buy-In Transaction as a significant and unusual transaction and as a critical audit matter because of the significant audit effort necessary to perform procedures and evaluate the audit evidence obtained relating to management’s accounting for the GP Buy-In Transaction due to the pervasive nature of the GP Buy-In Transaction on the composition of the Partnership’s consolidated financial statements and disclosures, including judgements necessary to combine legacy Summit Investments into the Partnership. 99 Table of Contents How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to evaluating the accounting treatment of the GP Buy-in Transaction included the following, among others: • • • We tested the effectiveness of controls over the Partnership’s accounting for significant unusual transactions, including management’s controls over the identification and application of relevant GAAP, and over the combination and presentation of the historical carrying amounts in the consolidated financial statements. We read the GP Buy-In Transaction agreements and evaluated the reasonableness of management’s assessment of the accounting associated with the transaction between entities under common control and the completeness and accuracy of the consolidated financial statements, including the retrospective consolidation of Summit Investments within the Partnership’s consolidated financial statements. We evaluated the sufficiency of the disclosures in the consolidated financial statements of the Partnership with respect to this matter. Commitments and Contingencies — Environmental Matters — Refer to Notes 2 and 11 to the financial statements Critical Audit Matter Description In 2015, the Partnership learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream Company, LLC (“Meadowlark Midstream”) system near Williston, North Dakota (“Meadowlark Rupture”). The U.S. Department of Justice (“DOJ”) issued grand jury subpoenas to Summit Investments, the Partnership, the Partnership’s General Partner and Meadowlark Midstream requesting certain materials related to the Meadowlark Rupture. Meadowlark Midstream and Summit Investments received a complaint from the North Dakota Industrial Commission seeking fines and other fees related to the incident, and this matter is also under investigation by the U.S. Environmental Protection Agency, the North Dakota Office of the Attorney General, the North Dakota Department of Environmental Quality, and the North Dakota Game and Fish Department. Discussions with the DOJ and other agencies regarding a resolution of this matter are ongoing. Liability for this incident could arise under civil and misdemeanor and felony criminal statutes, including the Clean Water Act. When required, the Partnership records accruals for loss contingencies in accordance with FASB ASC 450, Contingencies. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. As of December 31, 2020, the Partnership has accrued a $17.0 million loss contingency for this matter. While the Partnership believes a loss for claims and/or actions arising from the Meadowlark Rupture, whether in a negotiated settlement or as a result of litigation, is probable, due to the complexity of resolving the numerous issues surrounding this matter, at this time the Partnership cannot reasonably predict whether any actual loss, if incurred, would be materially higher or lower than the accrued amount. We identified the accrued loss contingency for the Meadowlark Rupture as a critical audit matter because of the challenges of auditing management’s judgments applied in determining the accrued loss contingency as of December 31, 2020. Specifically, auditing management’s interpretations of the current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events is subjective and requires significant judgment due to the complexity of resolving the numerous issues surrounding this matter. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to evaluating the accrued loss contingency for the Meadowlark Rupture included the following, among others: • • • We evaluated management’s analysis of claims and/or actions arising from the Meadowlark Rupture, read Board of Directors meeting minutes, including relevant sub-committee meeting minutes, and compared to responses from internal and external counsel. We obtained letters from the Partnership’s internal and external legal counsel as it relates to potential claims and/or actions arising from the Meadowlark Rupture. We evaluated any events subsequent to December 31, 2020, that might impact our evaluation of claims and/or actions arising from the Meadowlark Rupture, including any related accrual or disclosure. /s/ Deloitte & Touche LLP Houston, Texas March 4, 2021 We have served as the Partnership's auditor since 2009. 100 Table of Contents SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS December 31, December 31, 2020 2019 (In thousands, except unit amounts) ASSETS Cash and cash equivalents Restricted cash Accounts receivable Other current assets Total current assets Property, plant and equipment, net Intangible assets, net Investment in equity method investees Other noncurrent assets TOTAL ASSETS LIABILITIES AND CAPITAL Trade accounts payable Accrued expenses Deferred revenue Ad valorem taxes payable Accrued compensation and employee benefits Accrued interest Accrued environmental remediation Other current liabilities Current portion of SMPH term loan Total current liabilities Long-term debt Noncurrent deferred revenue Noncurrent accrued environmental remediation Other noncurrent liabilities Total liabilities Commitments and contingencies (Note 11) $ $ $ 15,544 $ — 61,932 4,623 82,099 1,817,546 199,566 392,740 7,866 2,499,817 $ 11,878 $ 13,036 9,988 9,086 9,658 8,007 1,392 5,363 — 68,408 1,347,326 48,250 1,537 21,747 1,487,268 9,530 27,392 97,418 5,521 139,861 1,882,489 232,278 309,728 9,742 2,574,098 24,415 11,339 13,493 8,477 8,719 12,346 1,725 3,487 5,546 89,547 1,622,279 38,709 2,926 7,951 1,761,412 Mezzanine Capital Subsidiary Series A Preferred Units (55,251 and 30,058 units issued and outstanding at December 31, 2020 and December 31, 2019, respectively) 89,658 27,450 Partners' Capital Series A Preferred Units (162,109 and 300,000 units issued and outstanding at December 31, 2020 and December 31, 2019, respectively) Common limited partner capital (6,110,092 and 3,021,258 units issued and outstanding at December 31, 2020 and December 31, 2019, respectively) Noncontrolling interest Total partners' capital TOTAL LIABILITIES AND CAPITAL 174,425 293,616 748,466 — 922,891 2,499,817 $ 305,550 186,070 785,236 2,574,098 $ The accompanying notes are an integral part of these consolidated financial statements. 101 Table of Contents SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Year ended December 31, 2020 2019 (In thousands, except per-unit amount) Revenues: Gathering services and related fees Natural gas, NGLs and condensate sales Other revenues Total revenues Costs and expenses: Cost of natural gas and NGLs Operation and maintenance General and administrative Depreciation and amortization Transaction costs Gain on asset sales, net Long-lived asset impairment Goodwill impairment Total costs and expenses Other income Interest expense Gain on early extinguishment of debt Income (loss) before income taxes and equity method investment income (loss) Income tax benefit (expense) Income (loss) from equity method investees Net income (loss) Less: Net income (loss) attributable to noncontrolling interest Net income (loss) attributable to limited partners Net income attributable to Series A Preferred Units Net income attributable to Subsidiary Series A Preferred Units Add: Deemed contribution from preferred unit exchange and purchase Net income (loss) attributable to common limited partners Net income (Loss) per limited partner unit: Common unit – basic Common unit – diluted Weighted-average limited partner units outstanding: Common units – basic Common units – diluted $ $ $ $ $ 302,792 $ 49,319 31,362 383,473 36,653 86,030 73,438 118,132 2,993 (307) 13,089 — 330,028 48 (78,894) 203,062 177,661 146 11,271 189,078 $ (3,274) 192,352 26,529 13,498 110,669 262,994 $ 73.22 $ 71.19 $ 3,592 3,694 326,747 86,994 29,787 443,528 63,438 98,719 55,947 110,354 3,017 (1,536) 60,507 16,211 406,657 451 (91,966) — (54,644) (1,231) (337,851) (393,726) (209,275) (184,451) 28,500 58 — (213,009) (70.50) (70.50) 3,021 3,021 The accompanying notes are an integral part of these consolidated financial statements. 102 Table of Contents SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL Noncontrolling Interest Partners' Capital Series A Preferred Units Common Noncontrolling Interests (1) Series A Preferred Units (In thousands) Partners' Capital Total $ — — — — — — — — (2,614) 2,664 (2,664) (2,614) 48,203 (48,203) — — — — — 8,171 (120,730) 8,171 (120,730) — — $ — — 1,391,567 (393,784) (97,374) 293,616 $ 28,500 (28,500) 543,479 $ (213,009) — 554,472 $ (209,275) (68,874) Partners' capital, December 31, 2018 Net income (loss) Net cash distributions SMLP unitholders Net cash distributions to Energy Capital Partners Unit-based compensation Effect of common unit issuances under SMLP LTIP Tax withholdings and associated payments on vested SMLP LTIP awards Conversion of noncontrolling interest related to cancellation of subsidiary incentive distribution rights Conversion of noncontrolling interest related to partial cancellation of subsidiary of payable Partners' capital, December 31, 2019 Net income Unit-based compensation Tax withholdings and associated payments on vested SMLP LTIP awards Tax withholdings on Series A Preferred Unit Exchange Net cash distribution to SMLP unitholders Effect of common issuances under SMLP LTIP GP-Buy-In Transaction assumption of noncontrolling interest in SMLP Repurchase of common units under GP Buy-In Transaction Common unit issuance due to TL Restructuring Effect of Exchange Offer and Preferred Tender(2) Other Partners' capital December 31, 2020 (1) Prior to the GP Buy-in Transaction, common noncontrolling interests reported by Summit Investments included equity interests in SMLP that were not owned by Summit Investments. (2) Includes deemed contributions of $54.9 million and $55.7 million related to the Exchange Offer and Tender Offer, respectively. 50,271 305,550 152,325 4,057 (50,271) 186,070 (3,274) 4,054 — 293,616 11,875 — 120,720 251 748,466 $ — — 14,654 — — 785,236 175,580 8,111 (25,000) 251 922,891 — — — $ — — — $ (145,720) — 174,425 $ (305,491) (182,117) 305,491 182,117 (44,078) 30,521 (1,018) (2,322) (6,037) (44,078) 2,322 30,521 (1,456) (6,037) (237) (438) (237) — — — — — — — — — — — — — — — — — — — $ The accompanying notes are an integral part of these consolidated financial statements. 103 Table of Contents SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Cash flows from operating activities: Net income (loss) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation and amortization Noncash lease expense Amortization of debt issuance costs Unit-based and noncash compensation (Income) loss from equity method investees Distributions from equity method investees Gain on asset sales, net Gain on early extinguishment of debt Gain on fair value of warrants Settlement of interest rate derivative Long-lived asset impairment Goodwill impairment Changes in operating assets and liabilities: Accounts receivable Trade accounts payable Accrued expenses Deferred revenue, net Ad valorem taxes payable Accrued interest Accrued environmental remediation, net Other, net Net cash provided by operating activities Cash flows from investing activities: Capital expenditures Proceeds from asset sale (net of cash of $1,475 for the year ended December 31, 2019) Distribution from equity method investment Investment in Double E equity method investee Other, net Net cash used in investing activities Cash flows from financing activities: Net cash distributions to noncontrolling interest SMLP unitholders Series A Preferred Unit distributions Net cash distributions to Energy Capital Partners Borrowings under Revolving Credit Facility Repayments on Revolving Credit Facility Transaction costs Repayments on SMPH Term Loan before TL Restructuring Open Market Repurchases of 2022 and 2025 Senior Notes Tender Offers of 2022 and 2025 Senior Notes TL Restructuring Proceeds from issuance of Subsidiary Series A preferred units, net of issuance costs Preferred Tender Borrowings under ECP Loans Repayment of ECP Loans Purchase of common units in GP Buy-In Transaction Debt issuance costs Proceeds from asset sale Other, net Net cash used in financing activities Net change in cash, cash equivalents and restricted cash Cash, cash equivalents and restricted cash, beginning of period Cash, cash equivalents and restricted cash, end of period Year ended December 31, 2020 2019 (In thousands) $ 189,078 $ (393,726) 119,070 3,242 6,608 8,111 (11,271) 28,185 (307) (206,975) (393) 134 13,089 — 35,352 (4,063) 2,841 6,036 609 (3,343) (1,996) 14,582 198,589 (43,128) — — (99,927) 2,486 (140,569) (6,037) — — 249,300 (69,300) (4,221) (6,300) (145,567) (47,530) (26,500) 48,710 (25,000) 35,000 (35,000) (41,778) (2,558) 288 (2,905) (79,398) (21,378) 36,922 15,544 $ 111,574 3,086 6,313 8,171 337,851 37,300 (1,536) — — — 60,507 16,211 (5,466) (96) (10,572) 1,683 (1,525) 7 (1,152) (6,889) 161,741 (182,291) 102,111 7,313 (18,316) 313 (90,870) (68,874) (28,500) (120,730) 369,000 (158,000) — (65,250) — — — 27,392 — — — — (673) — (4,487) (50,122) 20,749 16,173 36,922 $ The accompanying notes are an integral part of these consolidated financial statements. 104 Table of Contents SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION Organization. Summit Midstream Partners, LP (including its subsidiaries, collectively “SMLP” or the “Partnership”) is a Delaware limited partnership that was formed in May 2012 and began operations in October 2012. SMLP is a value-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in unconventional resource basins, primarily shale formations, in the continental United States. The Partnership’s business activities are conducted through various operating subsidiaries, each of which is owned or controlled by its wholly owned subsidiary holding company, Summit Holdings, a Delaware limited liability company. As of December 31, 2020, the Partnership indirectly owns its General Partner, and the General Partner is a wholly owned, indirect subsidiary of the Partnership. The General Partner has no assets or liabilities and holds the non-economic general partner interest in the Partnership. GP Buy-In Transaction. On May 28, 2020, the Partnership closed the transactions contemplated by the Purchase Agreement (the “Purchase Agreement”), dated May 3, 2020, with affiliates of its then private equity sponsor, Energy Capital Partners II, LLC (“ECP”), to acquire Summit Investments. The acquisition of Summit Investments resulted in the Partnership acquiring (a) 2.3 million SMLP common units that were pledged as collateral under the SMPH Term Loan, (b) 0.7 million SMLP common units that were not pledged as collateral under the SMPH Term Loan and (c) a deferred purchase price obligation receivable owed by the Partnership. In addition, the Partnership acquired 0.4 million SMLP common units held by an affiliate of ECP. The total purchase price was $35.0 million in cash and warrants giving ECP the right to purchase up to 0.7 million SMLP common units (refer to Note 13 – Partners’ Capital and Mezzanine Capital for additional details). Pursuant to the Purchase Agreement, the Partnership retained any liabilities stemming from the release of produced water from a produced water pipeline operated by Meadowlark Midstream, a subsidiary of the Partnership, that occurred near Williston, North Dakota and was discovered on January 6, 2015. These transactions are collectively referred to as the “GP Buy-In Transaction.” As a result of the GP Buy-In Transaction, the Partnership indirectly owns its General Partner. Following the closing of the GP Buy-In Transaction, the Partnership retired 1.1 million SMLP common units it acquired that were not pledged as collateral under the SMPH Term Loan. The 2.3 million SMLP common units that were pledged as collateral under the SMPH Term Loan were not considered outstanding with respect to voting and distributions under the Partnership Agreement until the closing of the TL Restructuring on November 17, 2020 (refer to Note 10). Under GAAP, the GP Buy-In Transaction was deemed a transaction among entities under common control with a change in reporting entity. Although SMLP is the surviving entity for legal purposes, Summit Investments is the surviving entity for accounting purposes; therefore, the historical financial results included herein, prior to the GP Buy-In Transaction are those of Summit Investments. Prior to the GP Buy-In Transaction, Summit Investments controlled SMLP and SMLP’s financial statements were consolidated into Summit Investments. Reverse Unit Split. On November 9, 2020, after the close of trading on the NYSE, the Partnership effected a 1-for-15 reverse unit split (the “Reverse Unit Split”) of its common units. The common units began trading on a split-adjusted basis on November 10, 2020. Pursuant to the Reverse Unit Split, common unitholders received one common unit for every 15 common units owned at the close of business on November 9, 2020. Immediately prior to the Reverse Unit Split, there were 56,624,887 common units issued and outstanding and immediately after the Reverse Unit Split, the number of issued and outstanding common units decreased to 3,774,992. Business Operations. The Partnership provides natural gas gathering, compression, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term, fee-based agreements with its customers. The Partnership’s results are primarily driven by the volumes of natural gas that it gathers, compresses, treats and/or processes as well as by the volumes of crude oil and produced water that it gathers. Other than the Partnership’s investments in Double E and Ohio Gathering, all of its business activities are conducted through wholly owned operating subsidiaries Presentation and Consolidation. The Partnership prepares its consolidated financial statements in accordance with GAAP as established by the FASB. The Partnership makes estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, including fair value measurements, the reported amounts of revenues and expenses and the 105 Table of Contents disclosure of commitments and contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates. The consolidated financial statements include the assets, liabilities and results of operations of SMLP and its subsidiaries. All intercompany transactions among the consolidated entities have been eliminated in consolidation. Comprehensive income or loss is the same as net income or loss for all periods presented. Risks and Uncertainties. The Partnership is closely monitoring the impact of the outbreak of COVID-19 on all aspects of its business, including how it has impacted and will impact its customers, employees, supply chain and distribution network. The Partnership is unable to predict the ultimate impact that COVID-19 may have on its business, future results of operations, financial position or cash flows. Given the dynamic nature of the COVID-19 pandemic and related market conditions, the Partnership cannot reasonably estimate the period of time that these events will persist or the full extent of the impact they will have on its business. The full extent to which the Partnership’s operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including changes in the severity of the pandemic, countermeasures taken by governments, businesses and individuals to slow the spread of the pandemic, and the ability of pharmaceutical companies to develop effective and safe vaccines and therapeutic drugs. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cash, Cash Equivalents and Restricted Cash. The Partnership considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. Accounts Receivable. Accounts receivable relate to gathering and other services provided to the Partnership’s customers and other counterparties. The Partnership evaluates the collectability of accounts receivable and the need for an allowance for doubtful accounts based on customer-specific facts and circumstances. To the extent the collectability of a specific customer or counterparty receivable is doubtful, the Partnership recognizes an allowance for doubtful accounts. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or a receivable amount is deemed otherwise unrealizable. Property, Plant and Equipment. The Partnership records property, plant and equipment at historical cost of construction or fair value of the assets at acquisition. The Partnership capitalizes expenditures that extend the useful life of an asset or enhance its productivity or efficiency from its original design over the expected remaining period of use. For maintenance and repairs that do not add capacity or extend the useful life of an asset, the Partnership recognizes expenditures as an expense as incurred. The Partnership capitalizes project costs incurred during construction, including interest on funds borrowed to finance the construction of facilities, as construction in progress. Accrued capital expenditures are reflected in trade accounts payable. The Partnership records depreciation on a straight-line basis over an asset’s estimated useful life and bases its estimates for useful life on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Estimates of useful lives follow. Gathering and processing systems and related equipment Other Useful lives (In years) (In years) 12-30 4-15 Construction in progress is depreciated consistent with its applicable asset class once it is placed in service. Land and line fill are not depreciated. The Partnership bases an asset’s carrying value on estimates, assumptions and judgments for useful life and salvage value. Upon sale, retirement or other disposal, the Partnership removes the carrying value of an asset and its accumulated depreciation from its balance sheet and recognizes the related gain or loss, if any. Asset Retirement Obligations. The Partnership records a liability for asset retirement obligations only if and when a future asset retirement obligation with a determinable life is identified. For identified asset retirement obligations, the Partnership evaluates 106 Table of Contents whether the expected retirement date and related costs of retirement can be estimated. The Partnership has concluded that its gathering and processing assets have an indeterminate life because they are owned and will operate for an indeterminate period when properly maintained. Because the Partnership does not have sufficient information to reasonably estimate the amount or timing of such obligations and does not have any current plan to discontinue use of any significant assets, the Partnership did not provide for any asset retirement obligations as of December 31, 2020 or 2019. Amortizing Intangibles. The Partnership has certain acquired gas gathering contracts that had above-market pricing structures at the acquisition date and the Partnership amortizes these favorable contracts using a straight-line method over the contract’s estimated useful life. The Partnership defines useful life as the period over which the contract is expected to contribute to the Partnership’s future cash flows. These favorable contracts have original terms ranging from 10 years to 20 years and the Partnership recognizes the amortization expense associated with these contracts in Other revenues. The Partnership amortizes all other gas gathering contracts, or contract intangibles, over the period of economic benefit based upon expected revenues over the life of the contract. The useful life of these contracts ranges from 3 years to 25 years. The Partnership recognizes the amortization expense associated with these contracts in Depreciation and amortization expense. The Partnership also has rights-of-way associated with municipal easements and easements granted within existing rights-of-way. The Partnership amortizes these intangible assets over the shorter of the contractual term of the rights-of-way or the estimated useful life of the gathering system. The contractual terms of the rights-of-way range from 20 years to 30 years and the Partnership recognizes the amortization expense associated with these rights- of-way assets in Depreciation and amortization expense. Equity Method Investments. The Partnership accounts for investments in which it exercises significant influence using the equity method so long as it (i) does not control the investee and (ii) is not the primary beneficiary. The Partnership reflects these investments in its consolidated balance sheets under the caption titled “investment in equity method investees.” The Partnership recognizes an other-than-temporary impairment for losses in the value of equity method investees when evidence indicates that the carrying amount is no longer supportable. Evidence of a loss in value might include, but is not limited to, absence of an ability to recover the carrying amount of the investment or an inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. The Partnership evaluates its equity method investments whenever a triggering event exists that would indicate a need to assess the investment for potential impairment. Impairment of Long-Lived Assets. The Partnership tests assets for impairment when events or circumstances indicate the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset (except goodwill) is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If the Partnership concludes that an asset's carrying value will not be recovered through future cash flows, the Partnership recognizes an impairment loss on the long-lived asset equal to the amount by which the carrying value exceeds its fair value. The Partnership determines fair value using a combination of market-based and income-based approaches. Environmental Matters. The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. The Partnership accrues for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Such accruals are adjusted as further information develops or circumstances change. Recoveries of environmental remediation costs from other parties or insurers are recorded as assets when their realization is assured beyond a reasonable doubt. Commitments and Contingencies. When required, the Partnership records accruals for loss contingencies in accordance with FASB ASC 450, Contingencies. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. Noncontrolling Interest and Mezzanine Capital. A noncontrolling interest represents the portion of a consolidated subsidiary that is owned by a third party. Amounts are adjusted by the noncontrolling interest holder’s proportionate share of the subsidiary’s earnings or losses each period and any distributions that are paid. A noncontrolling interest is reported as a 107 Table of Contents component of equity unless the noncontrolling interest is considered redeemable, in which case the noncontrolling interest is recorded between liabilities and equity (mezzanine or temporary equity) in the Partnership’s consolidated balance sheet. Revenue Recognition. The Partnership provides gathering and/or processing services principally under contracts that contain one or more of the following arrangements described below: • • Fee-based arrangements. Under fee-based arrangements, the Partnership receives a fee or fees for one or more of the following services (i) natural gas gathering, treating, compressing and/or processing and (ii) crude oil and/or produced water gathering. Percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, the Partnership generally purchases natural gas from producers at the wellhead, or other receipt points, gathers the wellhead natural gas through its gathering system, treats and compresses the natural gas, processes the natural gas and/or sells the natural gas to a third party for processing. The Partnership then remits to its producers an agreed-upon percentage of the actual proceeds received from sales of the residue natural gas and NGLs. Certain of these arrangements may also result in returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. The margins earned are directly related to the volume of natural gas that flows through the system and the price at which the Partnership is able to sell the residue natural gas and NGLs. For the contracts described above, the Partnership reflects its revenues in the financial statement captions described below. Financial statement caption: Revenue description: Revenues: Gathering services and related fees Natural gas, NGLs and condensate sales Other revenues • Revenue earned from fee-based gathering, compression, treating and processing services; • Revenue from the sale of physical natural gas purchased from customers percent-of-proceeds arrangements (Costs are presented within cost of natural gas and NGLs); • Revenue from sale of condensate and NGLs retained from gathering services (Costs are presented within operation and maintenance expense); and • Customer reimbursements to the Partnership for costs incurred by the Partnership on customer’s behalf (Recorded on a gross basis). Certain of the Partnership’s gathering and/or processing agreements provide for monthly or annual MVCs. Under these MVCs, customers agree to ship and/or process a minimum volume of production on its gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to the Partnership at the end of the contracted measurement period if its actual throughput volumes are less than its contractual MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that contracted measurement period. The Partnership recognizes customer obligations under their MVCs as revenue and contract assets when (i) it considers 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 making this determination, the Partnership considers both quantitative and qualitative facts and circumstances, including, but not limited to, contract terms, capacity of the associated pipeline or receipt point and/or expectations regarding future investment, drilling and production. 108 Table of Contents Unit-Based Compensation. For awards of unit-based compensation, the Partnership determines a grant date fair value and recognizes the related compensation expense in the statements of operations over the vesting period for each respective award. Income Taxes. The Partnership is generally not subject to federal and state income taxes, except as noted below. However, its unitholders are individually responsible for paying federal and state income taxes on their share of its taxable income. Net income or loss for GAAP purposes may differ significantly from taxable income reportable to its unitholders as a result of differences between the tax basis and the GAAP basis of assets and liabilities and the taxable income allocation requirements of the Partnership’s governing documents. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined as the Partnership does not have access to the information about each partner’s tax attributes related to the Partnership. In general, legal entities that are chartered, organized or conducting business in the state of Texas are subject to a franchise tax (the "Texas Margin Tax"). The Texas Margin Tax has the characteristics of an income tax because it is determined by applying a tax rate to a tax base that considers both revenues and expenses. The Partnership’s financial statements reflect provisions for these tax obligations. New accounting standards implemented in this Annual Report. ASU No. 2018-13 Fair Value Measurement (“ASU 2018-13”). ASU 2018-13 updates the disclosure requirements on fair value measurements including new disclosures for the changes in unrealized gains and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. ASU 2018-13 modifies existing disclosures including clarifying the measurement uncertainty disclosure. ASU 2018-13 removes certain existing disclosure requirements including the amount and reasons for transfers between Level 1 and Level 2 fair value measurements and the policy for the timing of transfer between levels. The adoption of ASU 2018-13 on January 1, 2020 did not have a material impact on the Partnership’s consolidated financial statements or disclosures. ASU No. 2016-13 Financial Instruments – Credit Losses (“ASU 2016-13”). ASU 2016-13 requires the use of a current expected loss model for financial assets measured at amortized cost and certain off-balance sheet credit exposures. Under this model, entities will be required to estimate the lifetime expected credit losses on such instruments based on historical experience, current conditions, and reasonable and supportable forecasts. This amended guidance also expands the disclosure requirements to enable users of financial statements to understand an entity’s assumptions, models and methods for estimating expected credit losses. The changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied using a modified retrospective approach. The adoption of ASU 2016-13 on January 1, 2020 did not have a material impact on the Partnership’s consolidated financial statements or disclosures. New accounting standards not yet implemented in this Annual Report. ASU No. 2020-06 Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815 – 40) (“ASU 2020-06”). ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. The ASU is part of the FASB’s simplification initiative, which aims to reduce unnecessary complexity in U.S. GAAP. The ASU’s amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within those fiscal years. The Partnership is currently evaluating the provisions of ASU 2020-06 to determine its impact on the Partnership’s consolidated financial statements and disclosures. ASU No. 2020-04 Reference Rate Reform (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform on financial reporting. The amendments in ASU 2020-04 are effective as of March 12, 2020 through December 31, 2022. The Partnership is currently evaluating the provisions of ASU 2020-04 to determine its impact on the Partnership’s consolidated financial statements and disclosures. 3. REVENUE The majority of the Partnership’s revenue is derived from long-term, fee-based contracts with its customers, which include original terms of up to 25 years. The Partnership recognizes revenue earned from fee-based gathering, compression, treating and processing services in gathering services and related fees. The Partnership also earns revenue in the Williston Basin and Permian 109 Table of Contents Basin reporting segments from the sale of physical natural gas purchased from its customers under certain percent-of-proceeds arrangements. Under ASC Topic 606, these gathering contracts are presented net within cost of natural gas and NGLs. The Partnership sells natural gas that it retains from certain customers in the Barnett Shale reporting segment to offset the power expenses of the electric-driven compression on the DFW Midstream system. The Partnership also sells condensate and NGLs retained from certain of its gathering services in the Piceance Basin and Permian Basin reporting segments. Revenues from the sale of natural gas and condensate are recognized in Natural gas, NGLs and condensate sales; the associated expense is included in Operation and maintenance expense. Certain customers reimburse the Partnership for costs incurred on their behalf. The Partnership records costs incurred and reimbursed by its customers on a gross basis, with the revenue component recognized in Other revenues. The transaction price in the Partnership’s contracts is primarily based on the volume of natural gas, crude oil or produced water transferred by its gathering systems to the customer’s agreed upon delivery point multiplied by the contractual rate. For contracts that include MVCs, variable consideration up to the MVC will be included in the transaction price. For contracts that do not include MVCs, the Partnership does not estimate variable consideration because the performance obligations are completed and settled on a daily basis. For contracts containing noncash consideration such as fuel received in-kind, the Partnership measures the transaction price at the point of sale when the volume, mix and market price of the commodities are known. The Partnership has contracts with MVCs that are variable and constrained. Contracts with longer than monthly MVCs are reviewed on a quarterly basis and adjustments to those estimates are made during each respective reporting period, if necessary. The transaction price is allocated if the contract contains more than one performance obligation such as contracts that include MVCs. The transaction price allocated is based on the MVC for the applicable measurement period. Performance obligations. The majority of the Partnership’s contracts have a single performance obligation which is either to provide gathering services (an integrated service) or sell natural gas, NGLs and condensate, which are both satisfied when the related natural gas, crude oil and produced water are received and transferred to an agreed upon delivery point. The Partnership also has certain contracts with multiple performance obligations. They include an option for the customer to acquire additional services such as contracts containing MVCs. These performance obligations would also be satisfied when the related natural gas, crude oil and produced water are received and transferred to an agreed upon delivery point. In these instances, the Partnership allocates the contract’s transaction price to each performance obligation using its best estimate of the standalone selling price of each service in the contract. Performance obligations for gathering services are generally satisfied over time. The Partnership utilizes either an output method (i.e., measure of progress) for guaranteed, stand-ready service contracts or an asset/system delivery time estimate for non-guaranteed, as-available service contracts. Performance obligations for the sale of natural gas, NGLs and condensate are satisfied at a point in time. There are no significant judgments for these transactions because the customer obtains control based on an agreed upon delivery point. Certain of the Partnership’s gathering and/or processing agreements provide for monthly or annual MVCs. Under these MVCs, the Partnership’s customers agree to ship and/or process a minimum volume of production on its gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to the Partnership at the end of the contracted measurement period if its actual throughput volumes are less than its contractual MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that contracted measurement period. The Partnership recognizes customer obligations under their MVCs as revenue and contract assets when (i) it is considered 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. Services are typically billed on a monthly basis and the Partnership does not offer extended payment terms. The Partnership does not have contracts with financing components. 110 Table of Contents The following table presents estimated revenue expected to be recognized over the remaining contract period related to performance obligations that are unsatisfied and are comprised of estimated MVC shortfall payments. The Partnership applies the practical expedient in paragraph 606-10-50-14 of Topic 606 for certain arrangements that are considered optional purchases (i.e., there is no enforceable obligation for the customer to make purchases) and those amounts are therefore excluded from the table. Gathering services and related fees $ 100,182 $ 84,215 $ 66,330 $ 49,872 $ 32,996 $ 22,706 Revenue by Category. In the following table, revenue is disaggregated by geographic area and major products and services. For more detailed information about reportable segments, see Note 20. 2021 2022 2023 2024 2025 Thereafter Gathering services and related fees Natural gas, NGLs and condensate sales Other revenues Total Year ended December 31, 2020 Reportable Segments: Utica Shale Williston Basin DJ Basin Permian Basin Piceance Basin Barnett Shale Marcellus Shale Total reportable segments All other segments Total Reportable Segments: Utica Shale Williston Basin DJ Basin Permian Basin Piceance Basin Barnett Shale Marcellus Shale Total reportable segments All other segments Total $ $ $ $ 36,509 $ 59,239 23,868 10,091 106,657 40,687 25,741 302,792 — 302,792 $ (in thousands) — $ 20,018 245 18,857 2,612 7,587 — 49,319 — 49,319 $ — $ 13,438 3,957 585 4,621 6,185 — 28,786 2,576 31,362 $ Gathering services and related fees Natural gas, NGLs and condensate sales Other revenues Total Year ended December 31, 2019 (in thousands) — $ 16,461 389 16,383 7,954 17,147 — 58,334 28,660 86,994 $ 2,065 $ 11,564 3,721 310 4,327 6,793 — 28,780 1,007 29,787 $ 31,926 $ 77,626 21,940 3,610 121,357 47,862 24,471 328,792 (2,045) 326,747 $ 111 36,509 92,695 28,070 29,533 113,890 54,459 25,741 380,897 2,576 383,473 33,991 105,651 26,050 20,303 133,638 71,802 24,471 415,906 27,622 443,528 Table of Contents Contract balances. Contract assets relate to the Partnership’s rights to consideration for work completed but not billed at the reporting date and consist of the estimated MVC shortfall payments expected from its customers and unbilled activity associated with contributions in aid of construction. Contract assets are transferred to trade receivables when the rights become unconditional. The following table provides information about contract assets from contracts with customers: Contract assets, January 1, 2020 Additions Transfers out Contract assets, December 31, 2020 December 31, 2020 December 31, 2019 (In thousands) $ $ 3,902 $ 18,834 (20,710) 2,026 $ 8,755 18,077 (22,930) 3,902 As of December 31, 2020, receivables with customers totaled $57.5 million and contract assets totaled $2.0 million which were included in the Accounts receivable caption on the consolidated balance sheet. As of December 31, 2019, receivables with customers totaled $90.4 million and contract assets totaled $3.9 million which were included in the Accounts receivable caption on the consolidated balance sheet. Contract liabilities (deferred revenue) relate to the advance consideration received from customers primarily for contributions in aid of construction. The Partnership recognizes contract liabilities under these arrangements in revenue over the contract period. For the years ended December 31, 2020 and 2019, the Partnership recognized $4.0 million and $10.1 million, respectively, of gathering services and related fees which was included in the contract liability balance as of the beginning of the period. See Note 8 for additional details. 4. PROPERTY, PLANT AND EQUIPMENT, NET Details on the Partnership’s property, plant and equipment follow. Gathering and processing systems and related equipment Construction in progress Land and line fill Other Total Less accumulated depreciation Property, plant and equipment, net December 31, 2020 December 31, 2019 $ $ (In thousands) 2,213,501 60,443 10,440 61,340 2,345,724 (528,178) 1,817,546 $ $ 2,182,950 78,716 10,137 54,595 2,326,398 (443,909) 1,882,489 When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs under GAAP’s fair value hierarchy. The Partnership recognized $13.1 million and $59.4 million of impairments during the fiscal years ended December 31, 2020 and 2019, respectively. Due to the volatility of the inputs used, the Partnership cannot predict the likelihood of any future impairment. The details on significant impairments recognized during the years ended December 31, 2020 and 2019 are provided below. Significant 2020 Impairments. The Partnership recognized a $5.1 million impairment related to the 2021 sale of compressor equipment in which the carrying value of the equipment exceeded the sale price, and a $3.6 million impairment related to the cancellation of a DJ Basin compressor station construction project due to delays in customer drilling plans. Significant 2019 Impairments. The Partnership recognized a $34.7 million impairment resulting from the expansion of a processing plant in the DJ Basin that caused a significant reduction in the utilization of the original processing plant’s infrastructure, a $14.2 million impairment resulting from the sale of gathering system in the Piceance Basin in which the carrying value of the system exceeded the sale price, and a $9.7 million impairment of compressor equipment in the Barnett Shale. Depreciation expense and capitalized interest for the Partnership follow. 112 Table of Contents Depreciation expense Capitalized interest 5. AMORTIZING INTANGIBLE ASSETS Details regarding the Partnership’s intangible assets, all of which are subject to amortization, follow. Year ended December 31, 2020 2019 $ (In thousands) 86,263 $ 3,878 $ 78,489 6,974 Favorable gas gathering contracts Contract intangibles Rights-of-way Total intangible assets Favorable gas gathering contracts Contract intangibles Rights-of-way Total intangible assets Gross carrying amount December 31, 2020 Accumulated amortization (In thousands) $ $ 24,195 $ 278,448 157,271 459,914 $ (16,064) $ (195,243) (49,041) (260,348) $ Gross carrying amount December 31, 2019 Accumulated amortization (In thousands) $ $ 24,195 $ 278,448 157,175 459,818 $ (15,125) $ (169,549) (42,866) (227,540) $ Net 8,131 83,205 108,230 199,566 Net 9,070 108,899 114,309 232,278 The Partnership recognized amortization expense of its favorable gas gathering contracts in Other revenues as follows: Amortization expense – favorable gas gathering contracts Year ended December 31, 2019 2020 $ (In thousands) (938) $ (1,220) The Partnership recognized amortization expense of its contract and right of way intangibles in costs and expenses as follows: Amortization expense – contract intangibles Amortization expense – rights-of-way Year ended December 31, 2019 2020 $ (In thousands) 25,694 $ 6,175 25,587 6,278 The Partnership’s estimated aggregate annual amortization expected to be recognized as of December 31, 2020 for each of the five succeeding fiscal years follows. 2021 2022 2023 2024 2025 Intangible assets (In thousands) $ 28,212 25,145 25,091 14,920 14,898 113 Table of Contents 6. GOODWILL The Partnership evaluates goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value, including goodwill. If the reporting unit’s fair value exceeds its carrying value, including goodwill, the Partnership concludes that the goodwill of the reporting unit has not been impaired and no further work is performed. If it is determined that the reporting unit’s carrying value, including goodwill, exceeds its fair value, an impairment loss is recognized in the amount of the excess of the carrying value over the fair value. The Partnership’s impairment determinations, in the context of (i) its annual impairment evaluations and (ii) other-than-annual impairment evaluations involved significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. As of September 30, 2019, the Partnership performed its annual goodwill impairment testing for the Mountaineer Midstream reporting unit, a reporting unit included in the Marcellus Shale reportable segment, using a combination of the income and market approaches. It was determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value, including goodwill. As a result, a goodwill impairment charge of $16.2 million was recorded for the year ended December 31, 2019 that reduced the goodwill balance on the Partnership’s consolidated balance sheet to zero. The Partnership did not have a transaction in 2020 that resulted in the establishment of a goodwill balance. 7. EQUITY METHOD INVESTMENTS Double E. In June 2019, the Partnership formed Double E in connection with (the “Double E Project”). Effective June 26, 2019, Summit Permian Transmission, a wholly owned, indirect and consolidated subsidiary of the Partnership, and an affiliate of Double E’s foundation shipper (the “JV Partner”), executed a definitive joint venture agreement (“Double E Agreement”) to fund the capital expenditures associated with the development of the Double E Project. In connection with the Double E Agreement and the related Double E Project, the Partnership contributed total assets of approximately $23.6 million in exchange for a 70% ownership interest in Double E and the JV Partner contributed $7.3 million of cash in exchange for a 30% ownership interest in Double E. Concurrent with these contributions, and in accordance with the Double E Agreement, Double E distributed $7.3 million to the Partnership. Subsequent to the formation of Double E, the Partnership made additional cash investments to Double E of $99.9 million, which includes $2.7 million in capitalized interest, and $18.3 million, which includes $1.1 million in capitalized interest and $0.7 million in capitalized legal costs, in 2020 and 2019, respectively. Double E is deemed to be a variable interest entity as defined in GAAP. As of the date of the Double E Agreement, Summit Permian Transmission was not deemed to be the primary beneficiary of Double E due to the JV Partner’s voting rights on significant matters. The Partnership accounts for its ownership interest in Double E as an equity method investment because it has significant influence over Double E. The Partnership’s portion of Double E’s net assets, which was $132.9 million and $34.7 million at December 31, 2020 and 2019, respectively, is reported under the caption Investment in equity method investees on the consolidated balance sheet. For the years ended December 31, 2020 and 2019, other than the investment activity noted above, Double E did not have any results of operations given that the Double E Project is currently under development. Ohio Gathering. The Partnership has investments in OGC and OCC that it collectively refers to as Ohio Gathering. Ohio Gathering is accounted for as an equity method investment because it has joint control with non-affiliated owners, which gives the Partnership significant influence. Ohio Gathering owns, operates and is currently developing midstream infrastructure consisting of a liquids-rich natural gas gathering system, a dry natural gas gathering system and a condensate stabilization facility in the Utica Shale in southeastern Ohio. Ohio Gathering provides gathering services pursuant to primarily long-term, fee-based gathering agreements, which include acreage dedications. The Partnership made its initial investment in Ohio Gathering in 2014 and owned 38.2% and 38.5% of Ohio Gathering at December 31, 2020 and 2019, respectively. In December 2019, the Partnership identified certain triggering events which indicated that its equity method investment in Ohio Gathering could be impaired. In accordance with ASC Topic 323, an equity method impairment analysis was performed and determined the equity method impairment charge to be recorded on its consolidated financial statements resulting from an 114 Table of Contents other-than-temporary impairment. As a result of the analysis, an impairment charge of $329.7 million was recorded in 2019 in Loss from equity method investments on the accompanying consolidated statements of operations. The fair value of the Partnership’s investment in Ohio Gathering was determined based upon applying the discounted cash flow method, which is an income approach, and the guideline public company method, which is a market approach. The discounted cash flow fair value estimate is based on known or knowable information at the measurement date. The significant assumptions that were used to develop the estimate of the fair value under the discounted cash flow method include management’s best estimates of the expected future results using a probability weighted average set of cash flow forecasts and a discount rate of approximately 9.0%. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As such, the fair value of the Ohio Gathering equity method investment represents a Level 3 measurement. As a result, actual results may differ from the estimates and assumptions made for purposes of this impairment analysis. Also in December 2019, an impairment loss of long-lived assets was recognized by OCC. Although the Partnership recognized activity for Ohio Gathering on a one-month lag, an impairment loss of $6.3 million was recorded in Loss from equity method investees in the consolidated statements of operations because the information was available to the Partnership. A reconciliation of the difference between the carrying amount of the Partnership’s interest in Ohio Gathering and the Partnership’s underlying investment in Ohio Gathering, per Ohio Gathering’s books and records, is shown below. Investment in Ohio Gathering, December 31, December cash distributions Impairment loss(1) Basis difference Investment in Ohio Gathering (Books and records), November 30, 2020 2019 (In thousands) 259,888 $ 2,748 — 216,591 479,227 $ 275,000 2,700 232,521 — 510,221 $ $ (1) Amount is comprised of (i) a $329.7 million impairment of the Partnership’s equity method investment in Ohio Gathering; (ii) the write-off of the Partnership’s basis difference of $103.5 million in Ohio Gathering as a result of the impairment in the Partnership’s equity method investment in Ohio Gathering; and (iii) a $6.3 million impairment of long-lived assets in OCC. Summarized balance sheet information for OGC and OCC follows (amounts represent 100% of investee financial information). November 30, 2020 November 30, 2019 OGC OCC OGC OCC Current assets Noncurrent assets Total assets Current liabilities Noncurrent liabilities Total liabilities $ 32,404 $ 1,240,090 $ 1,272,494 $ $ (In thousands) 4,902 290 5,192 41,972 $ 1,281,171 $ 1,323,143 $ $ $ 8,424 $ 8,441 16,865 $ 2,982 5,146 8,128 $ $ 21,798 $ 4,113 25,911 $ 2,187 28,323 30,510 4,016 6,683 10,699 Summarized statements of operations information for OGC and OCC follow (amounts represent 100% of investee financial information). Total revenues Total operating expenses Net income (loss) 8. DEFERRED REVENUE Twelve months ended November 30, 2020 Twelve months ended November 30, 2019 OGC OCC OGC OCC $ 114,524 $ 103,020 11,496 (In thousands) $ 12,931 38,502 (25,571) 142,138 $ 108,234 33,897 8,601 38,815 (30,214) Certain of the Partnership’s gathering and/or processing agreements provide for monthly or annual MVCs. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped and/or processed for the applicable period and the MVC for the applicable period, multiplied by the applicable gathering or processing fee. 115 Table of Contents Many of the Partnership’s gas gathering agreements contain provisions that can reduce or delay the cash flows that it expects to receive from MVCs to the extent that a customer's actual throughput volumes are above or below its MVC for the applicable contracted measurement period. These provisions include the following: • • • To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it may be entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, the Partnership would not receive gathering fees on throughput in excess of that customer's MVC (depending on the terms of the specific gas gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding measurement periods (as applicable). To the extent that a customer's throughput volumes exceed its MVC in the applicable contracted measurement period, it may be entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. As a result of this mechanism, the weighted-average remaining period for which the Partnership’s MVCs apply will be less than the weighted-average of the originally stated MVC contractual terms. To the extent that certain of the Partnership’s customers' throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a bank of credits that it can utilize in the future to reduce shortfall payments owed in subsequent periods, subject to expiration if there is no shortfall in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular gas gathering agreement. A rollforward of current deferred revenue follows. Current deferred revenue, January 1, 2020 Additions Less: revenue recognized Current deferred revenue, December 31, 2020 A rollforward of noncurrent deferred revenue follows. Noncurrent deferred revenue, January 1, 2020 Additions Less: reclassification to current deferred revenue Noncurrent deferred revenue, December 31, 2020 116 Total (In thousands) 13,493 2,731 6,236 9,988 Total (In thousands) 38,709 19,384 9,843 48,250 $ $ $ $ Table of Contents 9. DEBT Debt for the Partnership at December 31, 2020 and 2019 follows. Revolving Credit Facility: Summit Holdings' variable rate senior secured Revolving Credit Facility (2.90% at December 31, 2020 and 4.55% at December 31, 2019) due May 2022 ECP Loans: Summit Holdings' 8.00% senior secured term loan obtained in May 2020 and fully repaid in August 2020 2022 Senior Notes: Summit Holdings' 5.5% senior unsecured notes due August 2022 Less: unamortized debt issuance costs (1) 2025 Senior Notes: Summit Holdings' 5.75% senior unsecured notes due April 2025 Less: unamortized debt issuance costs (1) SMPH Term Loan: SMP Holdings' variable rate senior secured term loan (7.80% at December 31, 2019) due May 2022 and extinguished in November 2020 Less: unamortized debt issuance costs (1) Total debt Less: current portion Total long-term debt December 31, 2020 December 31, 2019 $ (In thousands) 857,000 $ — 234,047 (859) 259,463 (2,325) — — 1,347,326 — 1,347,326 $ $ 677,000 — 300,000 (1,686) 500,000 (5,015) 161,500 (3,974) 1,627,825 (5,546) 1,622,279 — 1,091,047 — — 259,463 — 1,350,510 (1) Issuance costs are being amortized over the life of the notes. The aggregate amount of Partnership’s debt maturing during each of the years after December 31, 2020 are as follows (in thousands): 2021 2022 2023 2024 2025 Thereafter $ Total long-term debt $ Revolving Credit Facility. The Partnership’s subsidiary, Summit Holdings, has a senior secured revolving credit facility (the “Revolving Credit Facility”) which allows for revolving loans, letters of credit and swingline loans. SMLP and the Guarantor Subsidiaries fully and unconditionally and jointly and severally guarantee, and pledge substantially all of their assets in support of the indebtedness outstanding under the Revolving Credit Facility. At December 31, 2020, the Revolving Credit Facility has a $1.1 billion borrowing capacity and matures in May 2022. On December 18, 2020, Summit Holdings entered into the Fourth Amendment to the Third Amended and Restated Credit Agreement which amended the Revolving Credit Facility to: (i) reduce the commitments from $1.25 billion to $1.1 billion; (ii) eliminate the $250.0 million accordion feature; (iii) add a basket for the potential issuance of up to $400.0 million of junior lien indebtedness; (iv) revise restrictions on the Partnership’s ability to use operating cash flow to repurchase junior debt and equity securities; (v) increase the total leverage covenant from 5.50x to 5.75x at all times going forward; (vi) replace the 3.75x senior secured leverage covenant with a new 3.50x first lien leverage covenant; (vii) add a new pricing tier of L + 325 bps if the total leverage ratio is greater than 5.00x; and (viii) restrict the Partnership’s ability to resume distributions on preferred and common units, subject to achieving certain financial and liquidity thresholds. Borrowings under the Revolving Credit Facility bear interest, at the election of Summit Holdings, at a rate based on the alternate base rate (as defined in the credit agreement) plus an applicable margin ranging from 0.75% to 2.25% or the adjusted Eurodollar rate (as defined in the credit agreement) plus an applicable margin ranging from 1.75% to 3.25%, with the commitment fee ranging from 0.30% to 0.50% in each case based on the Partnership’s relative leverage at the time of determination. At December 31, 2020, the applicable margin under LIBOR borrowings was 2.75%, the interest rate was 2.9% and the unused portion of the 117 Table of Contents Revolving Credit Facility totaled $238.9 million, subject to a commitment fee of 0.50%, after giving effect to the issuance thereunder of a $4.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, the available borrowing capacity under the Revolving Credit Facility as of December 31, 2020 was approximately $105 million. At December 31, 2020, the Revolving Credit Facility is secured by the membership interests of Summit Holdings and the membership interests of the Guarantor Subsidiaries of Summit Holdings and by substantially all of the assets of Summit Holdings and its Guarantor Subsidiaries (subject to exclusions set forth in the credit agreement). The credit agreement contains affirmative and negative covenants customary for credit facilities of its size and nature that, among other things, limit or restrict the ability (i) to incur additional debt; (ii) to make investments; (iii) to engage in certain mergers, consolidations, acquisitions or sales of assets; (iv) to enter into swap agreements and power purchase agreements; (v) to enter into leases that would cumulatively obligate payments in excess of $50.0 million over any 12 -month period; and (vi) of Summit Holdings to make distributions, with certain exceptions, including the distribution of Available Cash (as defined in the SMLP Partnership Agreement) if no default or event of default then exists or would result therefrom and Summit Holdings is in pro forma compliance with its financial covenants. In addition, the Revolving Credit Facility requires Summit Holdings to maintain (i) a ratio of consolidated trailing 12 -month earnings before interest, income taxes, depreciation and amortization ("EBITDA") to net interest expense of not less than 2.5 to 1.0 as defined in the credit agreement, (ii) a ratio of total net indebtedness to consolidated trailing 12 -month EBITDA of not more than 5.75 to 1.00 and, (iii) a ratio of first lien net indebtedness to consolidated trailing 12 -month EBITDA of not more than 3.75 to 1.00. As of December 31, 2020, the Partnership was in compliance with the Revolving Credit Facility's financial covenants and there were no defaults or events of default during the year ended December 31, 2020. As of December 31, 2020, the Partnership had $7.4 million of debt issuance costs attributable to its Revolving Credit Facility and related amendments, which are included in Other noncurrent assets on the consolidated balance sheet. ECP Loans. On May 28, 2020, in connection with the closing of the GP Buy-In Transaction, Summit Holdings, entered into (i) a Term Loan Credit Agreement (the “ECP NewCo Term Loan Credit Agreement”), with SMP TopCo, LLC, a Delaware limited liability company and affiliate of ECP (“ECP NewCo”), as lender and administrative agent, and Mizuho Bank (USA) (“Mizuho”), as collateral agent, in a principal amount of $28.2 million (the “ECP NewCo Loan”), and (ii) a Term Loan Credit Agreement (the “ECP Holdings Term Loan Credit Agreement” and together with the ECP NewCo Term Loan Credit Agreement, the “ECP Term Loan Credit Agreements”), with ECP Holdings, as lender, and ECP NewCo, as administrative agent and Mizuho, as collateral agent, in a principal amount of $6.8 million (the “ECP Holdings Loan” and together with the ECP NewCo Loan, the “ECP Loans”). The ECP Loans were set to mature on March 31, 2021 and bore interest at a fixed rate of 8.00% per annum, with the interest payment due at maturity of the ECP Loans. With borrowings under the Partnership’s Revolving Credit Facility, the Partnership fully repaid all amounts outstanding under the ECP Loans ($35 million of principal and $0.6 million of accrued interest) on August 7, 2020. 2022 Senior Notes. In July 2014, the Co-Issuers co-issued the 2022 Senior Notes. The Partnership pays interest on the 2022 Senior Notes semi-annually in cash in arrears on February 15 and August 15 of each year. The 2022 Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 2022 Senior Notes are effectively subordinated in right of payment to all secured indebtedness, to the extent of the collateral securing such indebtedness. The Co-Issuers may redeem all or part of the 2022 Senior Notes at a redemption price of 100.000%, plus accrued and unpaid interest, if any. Debt issuance costs of $5.1 million are being amortized over the life of the 2022 Senior Notes. As of and during the year ended December 31, 2020, we were in compliance with the financial covenants governing its 2022 Senior Notes. 2025 Senior Notes. In February 2017, the Co-Issuers co-issued the 2025 Senior Notes. The Partnership pays interest on the 2025 Senior Notes semi- annually in cash in arrears on April 15 and October 15 of each year. The 2025 Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of the Partnership’s existing and future senior obligations. The 2025 Senior Notes are effectively subordinated in right of payment to all of the Partnership’s secured indebtedness, to the extent of the collateral securing such indebtedness. The Co-Issuers have the right to redeem all or part of the 2025 Senior Notes at a redemption price of 104.313%. On and after April 15, 2021, the Co- Issuers may redeem all or part of the 2025 Senior Notes at a redemption price of 102.875% (with the redemption price declining ratably each year to 100.000% on April 15, 2023), plus accrued and unpaid interest, if any, to, but not including, the redemption date. Debt issuance costs of $7.7 million are being amortized over the life of the 2025 Senior Notes. 118 Table of Contents As of and during the year ended December 31, 2020, that Partnership was in compliance with the financial covenants governing its 2025 Senior Notes. SMPH Term Loan and TL Restructuring. Until November 17, 2020, a subsidiary of the Partnership, SMP Holdings, had a senior secured term loan facility with $155.2 million of principal outstanding and a maturity date of May 15, 2022. Borrowings under the SMPH Term Loan bore interest at LIBOR plus 6.00% or ABR plus 5.00%, as defined in the SMPH Term Loan, and were secured by the following collateral: (i) a perfected first-priority lien on, and pledge of (a) all of the capital stock issued by SMP Holdings, (b) 2.3 million SMLP units owned by SMP Holdings, (c) all of the equity interests owned by SMP Holdings in the General Partner, and (ii) substantially all other personal property of SMP Holdings. On September 29, 2020, SMP Holdings, Summit Investments and, for limited purposes, the Partnership, entered into the TL Restructuring. At the closing of the TL Restructuring on November 17, 2020, the Term Loan Agent executed a Strict Foreclosure on behalf of the Term Loan Lenders on the 2,306,972 common units held by SMP Holdings and pledged as collateral under the SMPH Term Loan, which was then distributed to all SMPH Term Loan Lenders on a pro rata basis. In addition to the Strict Foreclosure, SMP Holdings paid to each of the SMPH Term Loan Lenders its pro rata share of $26.5 million in cash that the Partnership paid to SMP Holdings to fully satisfy its obligation with respect to the deferred purchased price obligation. As of December 31, 2020, the SMPH Term Loan is fully satisfied and no longer exists. 10. LIABILITY MANAGEMENT TRANSACTIONS During the year ended December 31, 2020, the Partnership and its subsidiaries completed several liability management transactions, described below, that resulted in the early extinguishment of an aggregate $306.5 million face value of the Partnership’s indebtedness. Open Market Repurchases. During the year ended December 31, 2020, the Partnership made a number of open market repurchases of the 2022 Senior Notes and 2025 Senior Notes that resulted in the extinguishment of $32.4 million of face value of the 2022 Senior Notes and $201.8 million of face value of the 2025 Senior Notes (the “Open Market Repurchases”). Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 Senior Notes and 2025 Senior Notes, plus accrued interest totaled $150.3 million and the Partnership recognized a $86.4 million gain on the early extinguishment of debt during the year ended December 31, 2020. Debt Tender Offers. In September 2020, the Co-Issuers completed the Debt Tender Offers to purchase a portion of the 2022 Senior Notes and 2025 Senior Notes. Upon concluding the Debt Tender Offers, the Co-Issuers repurchased $33.5 million principal amount of the 2022 Senior Notes and $38.7 million principal amount of the 2025 Senior Notes. Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 and 2025 Senior Notes, plus accrued interest, totaled $48.7 million, and the Partnership recognized a $23.3 million gain on the early extinguishment of debt during the year ended December 31, 2020. SMPH Term Loan Restructuring. On November 17, 2020, the Partnership completed the TL Restructuring and recognized a gain of $94.0 million equal to the difference between the face value of the cancelled SMPH Term Loan and the fair value of the total consideration transferred, including unamortized debt issuance costs, and certain direct transaction costs related to the restructuring. The transaction was accounted for under ASC Topic 470-60 “Troubled Debt Restructuring with Debtors” and had a total impact of $26.15 per share. Summary of gain on extinguishment of debt. The Partnership recognized a $203.1 million gain on extinguishment of debt during the year ended December 31, 2020, the components of which are summarized in the table below. (in thousands) Gain on Repurchases of Senior Notes and TL Restructuring Debt issue costs Transaction costs Gain (loss) on debt extinguishment $ $ ECP Loan Repayment Open Market Repurchases Tender Offers TL Restructuring Total 2022 2025 2022 2025 Senior Notes Senior Notes Senior Notes Senior Notes — $ 11,554 $ 76,789 $ 9,223 $ 15,479 $ 99,175 $ 212,220 (361) (249) (610) $ (143) (105) 11,306 $ (1,541) (105) 75,143 $ (125) (467) 8,631 $ (351) (467) 14,661 $ (2,724) (2,520) 93,931 $ (5,245) (3,913) 203,062 119 Table of Contents 11. COMMITMENTS AND CONTINGENCIES Environmental Matters. Although the Partnership believes that it is in material compliance with applicable environmental regulations, the risk of environmental remediation costs and liabilities are inherent in pipeline ownership and operation. Furthermore, the Partnership can provide no assurances that significant environmental remediation costs and liabilities will not be incurred in the future. The Partnership is currently not aware of any material contingent liabilities that exist with respect to environmental matters, except as noted below. In 2015, the Partnership learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream system near Williston, North Dakota (“Meadowlark Rupture”). The Meadowlark Rupture, which was covered by Summit Investments’ insurance policies, was subject to maximum coverage of $25.0 million from its pollution liability insurance policy and $200.0 million from its property and business interruption insurance policy. The pollution liability policy was exhausted in 2015. Prior to the GP Buy-In Transaction, Summit Investments and SMP Holdings indemnified the Partnership for certain obligations and liabilities related to the incident. As a result of the GP Buy-In Transaction, the Partnership is no longer indemnified for these obligations. A rollforward of the Partnership’s undiscounted accrued environmental remediation liabilities related to the Meadowlark Rupture follows. Accrued environmental remediation, January 1, 2019 Payments made Additional accruals Accrued environmental remediation, December 31, 2019 Payments made Accrued environmental remediation, December 31, 2020 Total (In thousands) 5,636 (2,284) 1,299 4,651 (1,722) 2,929 $ $ $ As of December 31, 2020, the Partnership has recognized (i) a current liability for remediation effort expenditures expected to be incurred within the next 12 months and (ii) a noncurrent liability for estimated remediation expenditures expected to be incurred subsequent to December 31, 2021. Each of these amounts represent the Partnership’s best estimate for costs expected to be incurred. Neither of these amounts have been discounted to its present value. Beginning in 2015, the U.S. Department of Justice (“DOJ”) issued grand jury subpoenas to Summit Investments, the Partnership, our General Partner and Meadowlark Midstream requesting certain materials related to the Meadowlark Rupture. On June 19, 2015, Meadowlark Midstream and Summit Investments received a complaint from the North Dakota Industrial Commission seeking approximately $2.5 million in fines and other fees related to the incident. This matter is also under investigation by the U.S. Environmental Protection Agency, the North Dakota Office of the Attorney General, the North Dakota Department of Environmental Quality, and the North Dakota Game and Fish Department. The government’s investigation is still ongoing. During this time, the Partnership has entered into tolling agreements with both the DOJ and the North Dakota attorney general, which were most recently extended to May 7, 2021. There can be no assurance that these tolling agreements will be extended. Discussions with the DOJ and other agencies regarding a resolution of this matter are ongoing. Liability for this incident could arise under civil and misdemeanor and felony criminal statutes, including the Clean Water Act. In accordance with GAAP, the Partnership has accrued a $17.0 million loss contingency for this matter as of December 31, 2020. While the Partnership believes a loss for claims and/or actions arising from the Meadowlark Rupture, whether in a negotiated settlement or as a result of litigation, is probable, due to the complexity of resolving the numerous issues surrounding this matter, at this time we cannot reasonably predict whether any actual loss, if incurred, would be materially higher or lower than the accrued amount. Legal Proceedings. The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims or those arising in the normal course of business would not individually or in the aggregate have a material adverse effect on the Partnership's financial position or results of operations. 120 Table of Contents 12. FINANCIAL INSTRUMENTS Concentrations of Credit Risk. Financial instruments that potentially subject the Partnership to concentrations of credit risk consist of cash and cash equivalents, restricted cash and accounts receivable. The Partnership maintains its cash and cash equivalents and restricted cash in bank deposit accounts that frequently exceed federally insured limits. The Partnership has not experienced any losses in such accounts and does not believe it is exposed to any significant risk. Accounts receivable primarily comprise amounts due for the gathering, compression, treating and processing services the Partnership provides to its customers and also the sale of natural gas liquids resulting from its processing services. This industry concentration has the potential to impact its overall exposure to credit risk, either positively or negatively, in that the Partnerships customers may be similarly affected by changes in economic, industry or other conditions. The Partnership monitors the creditworthiness of its counterparties and can require letters of credit or other forms of credit assurance for receivables from counterparties that are judged to have substandard credit, unless the credit risk can otherwise be mitigated. The Partnerships top five customers or counterparties accounted for 51% of its total accounts receivable at December 31, 2020, compared to 46% as of December 31, 2019. Fair Value. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and trade accounts payable reported on the consolidated balance sheet approximates fair value due to their short-term maturities. A summary of the estimated fair value of the Partnerships debt financial instruments follows. 2022 Senior Notes 2025 Senior Notes December 31, 2020 December 31, 2019 Carrying Value, Net Estimated fair value (Level 2) Carrying Value, Net Estimated fair value (Level 2) $ 233,188 $ 257,138 215,713 $ 168,002 298,314 $ 494,985 266,750 382,708 (in thousands) The carrying value on the balance sheet of the Revolving Credit Facility is its fair value due to its floating interest rate. The fair value for the Senior Notes is based on an average of nonbinding broker quotes as of December 31, 2020 and 2019. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the Senior Notes. 13. PARTNERS' CAPITAL AND MEZZANINE CAPITAL Noncontrolling Interest. In March 2019, and prior to the GP Buy-In Transaction, a subsidiary of Summit Investments cancelled its incentive distribution rights agreement with SMLP and converted its 2% economic general partner interest to a non-economic general partner interest in exchange for 0.6 million SMLP common units. This exchange is reflected in the Consolidated Statements of Partners’ Capital as a reduction to noncontrolling interest and an increase to Partners’ Capital. Common Units. A rollforward of the number of common limited partner units follows for the period from December 31, 2018 to December 31, 2020. Units, December 31, 2018 2019 activity Units, December 31, 2019 GP Buy-In Transaction(1) Common units issued for SMLP LTIP, net TL Restructuring (Note 9) Series A Preferred Unit Exchange Offer, net of shares withheld for taxes Other Units, December 31, 2020 Common Units(2) 3,021,258 — 3,021,258 (132,687) 95,987 2,306,972 817,845 717 6,110,092 (1) The purchase price for the SMLP common units reflected in the consolidated statement of partners’ capital for the year ended December 31, 2020 is comprised of the (i) the $35.0 million cash payment to ECP, (ii) the $2.3 million fair value for the issuance of 0.7 million warrants, and (iii) $6.8 million of advisory fees and other direct costs related to closing the GP Buy-In Transaction. 121 Table of Contents (2) As adjusted for reverse unit split. Series A Preferred Units. In November 2017, the Partnership issued 300,000 Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series A Preferred Units”) representing limited partner interests in the Partnership at a price to the public of $1,000 per unit. The Partnership used the net proceeds of $293.2 million (after deducting underwriting discounts and offering expenses) to repay outstanding borrowings under the Revolving Credit Facility. The Series A Preferred Units rank senior to (i) common units representing limited partner interests in the Partnership and (ii) each other class or series of limited partner interests or other equity securities in the Partnership that may be established in the future that expressly ranks junior to the Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event (the “Junior Securities”). The Series A Preferred Units rank equal in all respects with each class or series of limited partner interests or other equity securities in the Partnership that may be established in the future that is not expressly made senior or subordinated to the Series A Preferred Units as to the payment of distributions and amounts payable on a liquidation event (the “Parity Securities”). The Series A Preferred Units rank junior to (i) all of the Partnership’s existing and future indebtedness and other liabilities with respect to assets available to satisfy claims against the Partnership and (ii) each other class or series of limited partner interests or other equity securities in the Partnership established in the future that is expressly made senior to the Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event. Income is allocated to the Series A Preferred Units in an amount equal to the earned distributions (whether these distributions are declared by the General Partner to be paid or not) for the respective reporting period. Distributions on the Series A Preferred Units are cumulative and compounding and are payable semi-annually in arrears on the 15th day of each June and December through and including December 15, 2022, and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year (each, a “Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Distribution Payment Date, in each case, when, as, and if declared by the General Partner out of legally available funds for such purpose. The initial distribution rate for the Series A Preferred Units is 9.50% per annum of the $1,000 liquidation preference per Series A Preferred Unit. On and after December 15, 2022, distributions on the Series A Preferred Units will accumulate for each distribution period at a percentage of the liquidation preference equal to the three-month LIBOR plus a spread of 7.43%. In connection with the GP Buy-In Transaction, the Partnership suspended its distributions to be paid to holders of its Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. A rollforward of the number of Series A Preferred Units follows for the period from December 31, 2018 to December 31, 2020. Series A Preferred Units, December 31, 2018 2019 activity Series A Preferred Units, December 31, 2019 Series A Preferred Unit Exchange Offer Series A Preferred Unit Tender Series A Preferred Units, December 31, 2020 Series A Preferred Units 300,000 — 300,000 (62,816) (75,075) 162,109 Series A Preferred Unit Exchange Offer. In July 2020, the Partnership completed an offer to exchange its Series A Preferred Units for newly issued common units, whereby it issued 837,547 SMLP common units in exchange for 62,816 Series A Preferred Units. Series A Preferred Tender Offer. In December 2020, the Partnership completed a cash tender offer for its Series A Preferred Units whereby it accepted 75,075 Series A Preferred Units for a purchase price of $333.00 per Series A Preferred Unit and an aggregate purchase price of $25.0 million. Subsidiary Series A Preferred Units. The Partnership has Subsidiary Series A Preferred Units that ranks senior to each other class or series of limited partner interests or other equity securities in Permian Holdco that may be established in the future that expressly ranks junior to the Subsidiary Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event (the “Junior Securities”). The Subsidiary Series A Preferred Units rank equal in all respects with each class or 122 Table of Contents series of limited partner interests or other equity securities in Permian Holdco that may be established in the future that is not expressly made senior or subordinated to the Subsidiary Series A Preferred Units as to the payment of distributions and amounts payable on a liquidation event (the “Parity Securities”). The Subsidiary Series A Preferred Units rank junior to (i) all of Permian Holdco’s or a subsidiary of Permian Holdco’s future indebtedness and other liabilities with respect to assets available to satisfy claims against Permian Holdco and (ii) each other class or series of limited partner interests or other equity securities in Permian Holdco established in the future that is expressly made senior to the Subsidiary Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event. Income is allocated to the Subsidiary Series A Preferred Units in an amount equal to the earned distributions for the respective reporting period. Distributions on the Subsidiary Series A Preferred Units are cumulative and compounding and are payable 21 days following the quarterly period ended March, June, September and December of each year (each, a “Series A Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Series A Distribution Payment Date, in each case, when, as, and if declared by Permian Holdco out of legally available funds for such purpose. The distribution rate for the Subsidiary Series A Preferred Units is 7.00% per annum of the $1,000 liquidation preference per Subsidiary Series A Preferred Unit. A pro-rated initial distribution on the Subsidiary Series A Preferred Units was Paid-in-kind (“PIK”) on January 21, 2020 in an amount equal to 7.00% per Subsidiary Series A Preferred Unit plus 1.00% per annum of the undrawn commitment units. In 2020, the Partnership issued 55,251 Subsidiary Series A Preferred Units at a price of $1,000 per unit for net proceeds of $48.7 million (after deducting underwriting discounts and offering expenses). All proceeds were used to fund capital expenses associated with the Double E Project. In 2019, the Partnership issued 30,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit. The net proceeds of $27.4 million (after deducting underwriting discounts and offering expenses) were used to fund capital expenses associated with the Double E Project. The proceeds associated with the issuance of Subsidiary Series A Preferred Units are classified as restricted cash on the accompanying consolidated balance sheets in accordance with the underlying agreement with TPG Energy Solutions Anthem, L.P. until the related funding is used for the Double E Project. These Subsidiary Series A Preferred Units are considered redeemable securities under GAAP due to the existence of certain redemption provisions that are outside of the Partnership’s control. Therefore, the securities are classified as temporary equity in the mezzanine section of the consolidated balance sheets. The Partnership records its Subsidiary Series A Preferred Units at fair value upon issuance, net of issuance costs, and subsequently records an effective interest method accretion amount each reporting period to accrete the carrying value to a most probable redemption value that is based on a predetermined internal rate of return measure. The Partnership also elected to make payment-in-kind (“PIK”) distributions to holders of the Subsidiary Series A Preferred Units during the year ended December 31, 2020 and these PIK distributions increase the liquidation preference on each Subsidiary Series A Preferred Unit. Ultimately, Net Income (Loss) Attributable to common limited partners includes adjustments for PIK distributions and redemption accretion. If the Subsidiary Series A Preferred Units were redeemed on December 31, 2020, the redemption amount would be $106.6 million, when considering the applicable multiple of invested capital metric and make-whole amount provisions contained in the Subsidiary Series A Preferred Unit agreement. The following table shows the change in the Partnership’s Subsidiary Series A Preferred Unit balance during the year ended December 31, 2020: Balance at December 31, 2019 New issuances PIK distributions Issuance costs Redemption accretion Balance at December 31, 2020(1) (1) Amount is net of $3.9 million of issuance costs at December 31, 2020. 123 December 31, 2020 (in thousands) 27,450 50,000 5,251 (1,290) 8,247 89,658 $ $ Table of Contents Warrants. On May 28, 2020 and in connection with the GP Buy-In Transaction, the Partnership issued (i) a warrant to purchase up to 0.5 million SMLP common units to ECP NewCo (the “ECP NewCo Warrant”) and (ii) a warrant to purchase up to 0.1 million SMLP common units to ECP Holdings (the “ECP Holdings Warrant” and together with the ECP NewCo Warrant, the “ECP Warrants”). The exercise price under the ECP Warrants is $15.35 per SMLP common unit and the Partnership may issue a maximum of 0.7 million SMLP common units under the ECP Warrants. Upon exercise of the ECP Warrants, each of ECP NewCo and ECP Holdings may receive, at its election: (i) a number of SMLP common units equal to the number of SMLP common units for which the ECP Warrants are being exercised, if exercising the ECP Warrants by cash payment of the exercise price; (ii) a number of SMLP common units equal to the product of the number of common units being exercised multiplied by (a) the difference between the average of the daily volume-weighted average price (“VWAP”) of the SMLP common units on the New York Stock Exchange (the “NYSE”) on each of the three trading days prior to the delivery of the notice of exercise (the “VWAP Average”) and the exercise price (the “VWAP Difference”), divided by (b) the VWAP Average; and/or (iii) an amount in cash, to the extent that the Partnership’s leverage ratio would be at least 0.5x less than the maximum applicable ratio set forth in the Revolving Credit Facility, equal to the product of (a) the number of SMLP common units exercised and (b) the VWAP Difference, subject to certain adjustments under the ECP Warrants. The ECP Warrants are subject to standard anti-dilution adjustments for stock dividends, stock splits (including reverse splits) and recapitalizations and are exercisable at any time on or before May 28, 2023. Upon exercise of the ECP Warrants, the proceeds to the holders of the ECP Warrants, whether in the form of cash or common units, will be capped at $30.00 per SMLP common unit above the exercise price. At issuance the ECP Warrants were valued at $2.3 million using a Black-Scholes model and accounted for as a liability instrument. At December 31, 2020, the ECP Warrants were valued at $1.9 million. Cash Distribution Policy. In connection with the GP Buy-In Transaction, the Partnership suspended its cash distributions to holders of its common units, commencing with respect to the quarter ending March 31, 2020. Upon the resumption of distributions, the Partnership Agreement requires that it distribute all available cash, subject to reserves established by its General Partner, within 45 days after the end of each quarter to unitholders of record on the applicable record date. The amount of distributions paid under this policy is subject to fluctuations based on the amount of cash the Partnership generates from its business and the decision to make any distribution is determined by the General Partner, taking into consideration the terms of the Partnership Agreement. Cash Distributions Paid and Declared. Prior to the GP Buy-In Transaction, SMLP paid the following per-unit cash distributions to its unitholders during the years ended December 31: Per-unit distributions to unitholders Year ended December 31, 2020 2019 $ 0.125 $ 1.4375 On January 29, 2020, the Board of Directors declared a distribution of $0.125 per unit for the quarterly period ended December 31, 2019. This distribution, which totaled $11.7 million, was paid on February 14, 2020 to unitholders of record at the close of business on February 7, 2020. 124 Table of Contents 14. EARNINGS PER UNIT The following table details the components of EPU. Numerator for basic and diluted EPU: Allocation of net income (loss) among limited partner interests: Net income (loss) attributable to limited partners Less: Net income attributable to Series A Preferred Units Net income attributable to Subsidiary Series A Preferred Units Add: Deemed capital contribution from Series A Preferred Unit Exchange Offer Deemed capital contribution from Series A Preferred Tender Offer Net income (loss) attributable to common limited partners Denominator for basic and diluted EPU: Weighted-average common units outstanding – basic(1) Effect of nonvested phantom units Weighted-average common units outstanding – diluted Net Income (Loss) per limited partner unit: Common unit – basic Common unit – diluted Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU Year ended December 31, 2019 2020 (In thousands, except per-unit amounts) $ 192,352 $ (184,451) $ 26,529 13,498 54,945 55,724 262,994 3,592 102 3,694 28,500 58 — $ (213,009) 3,021 — 3,021 $ $ 73.22 $ 71.19 $ (70.50) (70.50) 240 12 (1) As a result of the GP Buy-In Transaction, our historical results are those of Summit Investments. The number of common units of 3.0 million as of December 31, 2019 represents those of Summit Investments and has been used for the earnings per unit calculation presented herein. 15. SUPPLEMENTAL CASH FLOW INFORMATION Supplemental cash flow information: Cash interest paid Less capitalized interest Interest paid (net of capitalized interest) Cash paid for taxes Noncash investing and financing activities: Capital expenditures in trade accounts payable (period-end accruals) Warrant issuance for GP Buy-In Transaction Asset contribution to an equity method investment Right-of-use assets relating to ASC Topic 842 Fair value of SMLP equity for TL Restructuring Accretion of Subsidiary Series A Preferred Units 16. UNIT-BASED AND NONCASH COMPENSATION $ $ $ $ Year ended December 31, 2020 2019 (In thousands) 79,450 $ 3,878 75,572 $ 92,536 6,974 85,562 190 $ 150 6,154 $ 2,300 — 3,685 30,521 8,247 19,846 — 23,643 5,448 — — SMLP Long-Term Incentive Plan. The Partnership’s Long-Term Incentive Plan (“SMLP LTIP”) provides for equity awards to eligible officers, employees, consultants and directors of the Partnership, thereby linking the recipients' compensation directly to SMLP’s performance. The SMLP LTIP provides for the granting, from time to time, of unit-based awards, including common 125 Table of Contents units, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Grants are made at the discretion of the Board of Directors or Compensation Committee. A total of 1.0 million common units was reserved for issuance pursuant to and in accordance with the SMLP LTIP. As of December 31, 2020, approximately 0.4 million common units remained available for future issuance. The following table presents phantom unit activity for the periods presented: Nonvested phantom units, December 31, 2018 Phantom units granted Phantom units vested Phantom units forfeited Nonvested phantom units, December 31, 2019 Phantom units granted Phantom units vested Phantom units forfeited Nonvested phantom units, December 31, 2020 Units Weighted-average grant date fair value 57,608 $ 127,540 (40,174) (4,574) 140,400 345,997 (193,349) (1,357) 291,691 $ 256.65 97.20 251.70 193.05 115.35 9.20 54.07 119.24 26.57 A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. Distribution equivalent rights for each phantom unit provide for a lump sum cash amount equal to the accrued distributions from the grant date to be paid in cash upon the vesting date. Phantom units granted to date generally vest ratably over a three-year period. Grant date fair value is determined based on the closing price of SMLP’s common units on the date of grant multiplied by the number of phantom units awarded to the grantee. Forfeitures are recorded as incurred. Holders of all phantom units granted to date are entitled to receive distribution equivalent rights for each phantom unit, providing for a lump sum cash amount equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. Upon vesting, phantom unit awards may be settled, at the Partnership’s discretion, in cash and/or common units, but the current intention is to settle all phantom unit awards with common units. The intrinsic value of phantom units that vested during the years ended December 31, follows. Intrinsic value of vested LTIP awards Year ended December 31, 2020 2019 $ (In thousands) 2,602 $ 5,940 As of December 31, 2020, the unrecognized unit-based compensation related to the SMLP LTIP was $3.4 million. Incremental unit-based compensation will be recorded over the remaining weighted-average vesting period of approximately 1.4 years. Unit-based compensation recognized in general and administrative expense related to awards under the SMLP LTIP follows. SMLP LTIP unit-based compensation 17. LEASES Year ended December 31, 2020 2019 $ (In thousands) 8,111 $ 8,171 Leases. The Partnership leases certain office space and equipment under operating leases. The Partnership leases office space for terms of between 3 and 10 years. Office space leases limit exposure to risks related to ownership, such as fluctuations in real estate prices. The Partnership leases equipment primarily to support its operations in response to the needs of its gathering systems for terms of between 3 and 4 years. The Partnership also leases vehicles under finance leases to support its operations in response to the needs of its gathering systems for a term of 3 years. 126 Table of Contents Some of the Partnerships leases are subject to annual escalations relating to the Consumer Price Index (“CPI”). While lease liabilities are not remeasured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. In accordance with the provisions in the Revolving Credit Facility, the Partnership’s aggregate finance lease obligations cannot exceed $50.0 million in any period of twelve consecutive calendar months during the life of such leases. Significant assumptions or judgments include the determination of whether a contract contains a lease and the discount rate used in the lease liabilities. The rate implicit in the lease contracts are not readily determinable. In determining the discount rate used in for lease liabilities, the Partnership analyzed certain factors in its incremental borrowing rate, including collateral assumptions and the term used. The incremental borrowing rate on the Revolving Credit Facility was 2.90% at December 31, 2020, which reflects the fixed rate at which the Partnership could borrow a similar amount, for a similar term and with similar collateral as in the lease contracts at the commencement date. In connection with the adoption of Topic 842, the Partnership elected the package of practical expedients which permits them not to reassess under the new standard its prior conclusions about lease identification, lease classification and initial direct costs. The Company also elected the practical expedient to not separate the nonlease components from the associated lease components for all classes of underlying assets, as well as the short-term lease recognition exemption. ROU assets (included in the Property, plant and equipment, net caption on the Partnership’s consolidated balance sheet) and lease liabilities (included in the Other current liabilities and Other noncurrent liabilities captions on the Partnership’s consolidated balance sheet) follow: December 31, 2020 December 31, 2019 (In thousands) ROU assets Operating Finance Lease liabilities, current Operating Finance Lease liabilities, noncurrent Operating Finance Lease cost and Other information follow: Lease cost Finance lease cost: Amortization of ROU assets (included in depreciation and amortization) Interest on lease liabilities (included in interest expense) Operating lease cost (included in general and administrative expense) 127 $ $ $ $ $ $ 3,736 $ 1,748 5,484 $ 2,298 $ 618 2,916 $ 3,182 $ 154 3,336 $ Year ended December 31, 2020 2019 (In thousands) $ $ 1,274 52 2,644 3,970 $ $ 3,580 3,159 6,739 1,221 1,246 2,467 2,513 676 3,189 1,559 102 3,345 5,006 Table of Contents Other information Cash paid for amounts included in the measurement of lease liabilities Operating cash outflows from operating leases Operating cash outflows from finance leases Financing cash outflows from finance leases ROU assets obtained in exchange for new operating lease liabilities ROU assets obtained in exchange for new finance lease liabilities Weighted-average remaining lease term (years) - operating leases Weighted-average remaining lease term (years) - finance leases Weighted-average discount rate - operating leases Weighted-average discount rate - finance leases Year ended December 31, 2020 2019 (In thousands) $ $ 1,472 52 1,150 3,552 133 4.9 1.4 5% 4% 3,396 102 1,873 1,218 1,350 5.8 2.0 5% 4% The Partnership recognizes total lease expense incurred or allocated to us in general and administrative expenses. Lease expense related to operating leases, including lease expense incurred on the Partnership’s behalf and allocated to us, was as follows: Lease expense Future minimum lease payments due under noncancelable leases at December 31, 2020, were as follows: $ Year ended December 31, 2020 2019 (In thousands) 3,436 $ 4,038 2021 2022 2023 2024 2025 2026 Thereafter Total future minimum lease payments 18. DISPOSITIONS December 31, 2020 (In thousands) Operating Finance $ $ 1,750 $ 1,308 854 573 464 156 579 5,684 $ 655 126 42 — — — — 823 In 2019, the Partnership completed two divestitures described in further detail below. Red Rock Gathering Asset Disposition. In December 2019, the Partnership completed the sale of certain assets contained in its Piceance Basin reportable segment for a cash purchase price of $12.0 million. Prior to the sale, the Partnership recorded an impairment charge of $14.2 million based on the expected consideration and the carrying value for the disposed assets. The financial contribution of these assets in 2019 (a component of the Piceance Basin reportable segment) are included in the Partnership’s consolidated financial statements and footnotes for the period from January 1, 2019 through December 1, 2019. Tioga Midstream Disposition. In March 2019, the Partnership closed on the sale of certain assets contained in the Williston Basin reportable segment for a cash purchase price of $90.0 million. Upon closing the sale in March 2019, the Partnership recorded a gain on sale of $0.9 million based on the difference between the consideration received and the carrying value for disposed assets. The gain is included in the Gain on asset sales, net caption on the consolidated statement of operations. The financial contribution of these assets in 2019 (a component of the Williston Basin reportable segment) are included in the Partnership’s consolidated financial statements and footnotes for the period from January 1, 2019 through March 22, 2019. 128 Table of Contents 19. RESTRUCTURING 2020 Restructuring Activities. In 2020, management approved and initiated a plan to restructure its operations (“2020 Restructuring Plan”), resulting in certain management, facility and organizational changes. Under the 2020 Restructuring Plan, the Partnership expensed approximately $5.6 million in 2020 of costs associated with its restructuring activities. These activities consisted primarily of employee-related severance costs, and are included within the General and administrative caption on the consolidated statement of operations. 2019 Restructuring Activities. In 2019, management approved and initiated a plan to restructure its operations (“2019 Restructuring Plan”), resulting in certain management, facility and organizational changes. Under the 2019 Restructuring Plan, the Partnership expensed approximately $3.5 million and $4.9 million in 2020 and 2019, respectively, of costs associated with its restructuring activities. These activities consisted primarily of employee-related costs and consulting costs in support of the project. These costs are included within the General and administrative caption on the consolidated statement of operations. Details for the 2020 Restructuring Plan and the 2019 Restructuring Plan follow. Severance Charges Other Restructuring Charges Total Severance and Other 2020 2019 2020 2019 2020 2019 2020 Restructuring Plan 2019 Restructuring Plan $ $ 5,591 2,159 7,750 $ $ — 3,767 3,767 $ $ $ (In thousands) 56 1,293 1,349 $ — 1,187 1,187 $ $ 5,647 3,452 9,099 $ $ — 4,954 4,954 Accrued December 31, 2018 Charges Incurred Cash Payments Accrued December 31, 2019 Charges Incurred Cash Payments Accrued December 31, 2020 Employee-related costs Other $ Total restructuring costs $ — $ — — $ 3,767 $ 1,187 4,954 $ (951) $ (1,187) (2,138) $ 2,816 $ — 2,816 $ 7,750 $ 1,349 9,099 $ (7,018) $ (1,349) (8,367) $ 3,548 — 3,548 (In thousands) 20. SEGMENT INFORMATION As of December 31, 2020, the Partnership’s reportable segments are: • • • • • • • • the Utica Shale, which is served by Summit Utica; Ohio Gathering, which includes the Partnership’s ownership interest in OGC and OCC; the Williston Basin, which is served by Polar and Divide, Meadowlark Midstream 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. Until March 22, 2019, the Partnership owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Until December 1, 2019, the Partnership owned certain assets in the Red Rock Gathering system operating in the Piceance Basin. Refer to Note 16 to the consolidated financial statements for details on the sale of Tioga Midstream and on the sale of certain assets in the Red Rock Gathering system. Each of the Partnership’s reportable segments provides midstream services in a specific geographic area. Reportable segments reflect the way in which the Partnership internally report’s the financial information used to make decisions and allocate resources in connection with its operations. The Ohio Gathering reportable segment includes the Partnership’s investment in Ohio Gathering. Income or loss from equity method investees, as reflected on the statements of operations, relates to Ohio Gathering and is recognized and disclosed on a one-month lag see Note 7. 129 Table of Contents For the year ended December 31, 2020, other than the investment activity described in Note 7, Double E did not have any results of operations given that the Double E Project is currently under development. The Double E Project is expected to be operational in the fourth quarter of 2021. Corporate and Other represents those results that: (i) are not specifically attributable to a reportable segment; (ii) are not individually reportable (such as Double E); or (iii) have not been allocated to a reportable segments for the purpose of evaluating their performance, including certain general and administrative expense items, certain natural gas and crude oil marketing services and transaction costs. Assets by reportable segment follow. Assets(1): Utica Shale Ohio Gathering Williston Basin DJ Basin Permian Basin Piceance Basin Barnett Shale Marcellus Shale Total reportable segment assets Corporate and Other Total assets 2020 December 31, (in thousands) 2019 $ $ 209,425 $ 259,888 425,873 199,920 165,765 579,800 336,629 176,441 2,353,741 146,076 2,499,817 $ 206,368 275,000 452,152 205,308 185,708 631,140 350,638 184,631 2,490,945 83,153 2,574,098 (1) At December 31, 2020, Corporate and Other included $132.9 million relating to the Partnership’s investment in Double E (included in the Investment in equity method investees caption of the consolidated balance sheet). At December 31, 2019, Corporate and Other included $34.7 million relating to the Partnership’s investment in Double E (included in the Investment in equity method investees caption of the consolidated balance sheet). Revenues by reportable segment follow. Revenues: Utica Shale Williston Basin DJ Basin Permian Basin Piceance Basin Barnett Shale Marcellus Shale Total reportable segments revenue Corporate and Other Eliminations Total revenues Counterparties accounting for a significant portion of total revenues were as follows: Percentage of total revenues(1): Counterparty A - Piceance Basin Counterparty B - Williston Basin Counterparty C - Utica Shale Counterparty C - Permian Basin Counterparty C - Barnett Shale * Less than 10% 130 Year ended December 31, 2020 2019 (In thousands) $ $ 36,509 $ 92,695 28,070 29,533 113,890 54,459 25,741 380,897 2,576 — 383,473 $ Year ended December 31, 2020 2019 13% * 5% 5% 1% 33,991 105,651 26,050 20,303 133,638 71,802 24,471 415,906 30,552 (2,930) 443,528 11% 10% * * * Table of Contents Depreciation and amortization, including the amortization expense associated with the Partnership’s favorable and unfavorable gas gathering contracts as reported in other revenues, by reportable segment follows. Depreciation and amortization: Utica Shale Williston Basin DJ Basin Permian Basin Piceance Basin Barnett Shale(1) Marcellus Shale Total reportable segment depreciation and amortization Corporate and Other Total depreciation and amortization Year ended December 31, 2020 2019 (In thousands) $ $ 7,696 $ 25,911 6,146 5,455 45,203 16,112 9,195 115,718 3,352 119,070 $ 7,659 19,829 3,732 4,868 47,018 16,575 9,141 108,822 2,752 111,574 (1) Includes the amortization expense associated with the Partnership’s favorable and unfavorable gas gathering contracts as reported in Other revenues. Cash paid for capital expenditures by reportable segment follow. Cash paid for capital expenditures: Utica Shale Williston Basin DJ Basin Permian Basin Piceance Basin Barnett Shale(1) Marcellus Shale Total reportable segment capital expenditures Corporate and Other Total cash paid for capital expenditures Year ended December 31, 2020 2019 (In thousands) 6,957 8,767 12,829 7,014 1,370 1,878 700 39,515 3,613 43,128 $ $ 3,902 30,861 80,487 44,955 1,946 184 693 163,028 19,263 182,291 $ $ (1) For the year ended December 31, 2019, the amount includes sales tax reimbursements of $1.1 million. For the year ended December 31, 2019, Corporate and Other includes cash paid of $1.6 million for corporate purposes; the remainder represents capital expenditures relating to the Double E Project. The Partnership assesses the performance of its reportable segments based on segment adjusted EBITDA. The Partnership defines segment adjusted EBITDA as total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) unit-based and noncash compensation, (vii) impairments (vii) other noncash expenses or losses, less other noncash income or gains and (ix) restructuring expenses. Proportional adjusted EBITDA for the Partnership’s equity method investees is defined as the product of (i) total revenues less total expenses, excluding impairments and other noncash income or expense items, and amortization for deferred contract costs; and (ii) ownership interest in Ohio Gathering during the respective period. For the purpose of evaluating segment performance, the Partnership excludes the effect of Corporate and Other revenues and expenses, such as certain general and administrative expenses (including compensation-related expenses and professional services fees), certain natural gas and crude oil marketing services, transaction costs, interest expense and income tax expense or benefit from segment adjusted EBITDA. 131 Table of Contents Segment adjusted EBITDA by reportable segment follows. Reportable segment adjusted EBITDA Utica Shale Ohio Gathering Williston Basin DJ Basin Permian Basin Piceance Basin Barnett Shale Marcellus Shale Total of reportable segments' measures of profit Year ended December 31, 2020 2019 (In thousands) $ $ 32,783 $ 31,056 52,060 19,449 4,426 88,820 32,093 22,015 282,702 $ 29,292 39,126 69,437 18,668 (879) 98,765 43,043 20,051 317,503 A reconciliation of income or loss before income taxes and income or loss from equity method investees to total of reportable segments' measures of profit or loss follows. Reconciliation of income (loss) before income taxes and income (loss) from equity method investees to total of reportable segments' measures of profit: Income (loss) before income taxes and income (loss) from equity method investees Add: Corporate and Other expense Interest expense Gain on early extinguishment of debt Depreciation and amortization(1) Proportional adjusted EBITDA for equity method investees Adjustments related to MVC shortfall payments Adjustments related to capital reimbursement activity Unit-based and noncash compensation Gain on asset sales, net Long-lived asset impairment Goodwill impairment Total of reportable segments' measures of profit Year ended December 31, 2020 2019 (In thousands) $ 177,661 $ (54,644) 59,585 78,894 (203,062) 119,070 31,056 — (1,395) 8,111 (307) 13,089 — $ 282,702 $ 44,808 91,966 — 111,574 39,126 3,476 (2,156) 8,171 (1,536) 60,507 16,211 317,503 (1) Includes the amortization expense associated with the Partnership’s favorable gas gathering contracts as reported in other revenues. For the years ended December 31, 2020 and 2019, adjustments related to MVC shortfall payments recognize the earnings from MVC shortfall payments ratably over the term of the associated MVC. Contributions in aid of construction are recognized over the remaining term of the respective contract. The Partnership includes adjustments related to capital reimbursement activity in its calculation of segment adjusted EBITDA to account for revenue recognized from contributions in aid of construction. 21. SUBSEQUENT EVENTS In January 2021, Double E received its Notice to Proceed with construction, as well as approval of its implementation plan, from FERC. With the receipt of the 7(c) certificate and the NTP, construction on the Double E pipeline commenced in February 2021, and the pipeline is expected to be in-service by the end of 2021. In February 2021, Summit Permian Transmission, LLC, received $175.0 million of commitments to finance the development of the Double E Project. The lenders have committed to provide senior secured credit facilities consisting of a $160.0 million delayed draw term loan facility and a $15.0 million working capital facility (the “Credit Facilities”). The Credit Facilities 132 Table of Contents are non-recourse to SMLP and mature seven years after the date of initial borrowing. SMLP expects to close and fund on the Credit Facilities shortly and will post a $15.0 million letter of credit under its corporate revolving credit facility to support back-end equity contributions, if needed, upon first funding. 133 Table of Contents Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. There have been no changes in, or disagreements with, accountants on accounting and financial disclosure matters during the years ended December 31, 2020 and 2019. Item 9A. Controls and Procedures. Disclosure Controls and Procedures We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to the management of our General Partner, including our General Partner’s principal executive and principal financial officers (whom we refer to as the Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. SMLP’s management, with the participation of the Chief Executive Officer and Chief Financial Officer of SMLP's General Partner, has evaluated the effectiveness of SMLP’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this annual report (the "Evaluation Date"). Based on such evaluation, the Chief Executive Officer and Chief Financial Officer of SMLP's General Partner have concluded that, as of the Evaluation Date, SMLP’s disclosure controls and procedures are effective. Changes in Internal Control Over Financial Reporting There have not been any changes in SMLP’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth fiscal quarter of 2020 that have materially affected, or are reasonably likely to materially affect, SMLP's internal control over financial reporting. 134 Table of Contents Management’s Annual Report on Internal Control Over Financial Reporting Our General Partner is responsible for establishing and maintaining adequate internal control over financial reporting for the Partnership. With our participation, an evaluation of the effectiveness of our internal control over financial reporting was conducted as of December 31, 2020, based on the framework and criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management has concluded that our internal control over financial reporting was effective as of December 31, 2020. Our independent registered public accounting firm has issued an audit report on our internal control over financial reporting, included below of this report. /s/ J. HEATH DENEKE J. Heath Deneke President and Chief Executive Officer, Summit Midstream GP, LLC (the General Partner of SMLP) /s/ MARC D. STRATTON Marc D. Stratton Executive Vice President and Chief Financial Officer, Summit Midstream GP, LLC (the General Partner of SMLP) 135 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors of Summit Midstream, GP, LLC and the unitholders of Summit Midstream Partners, LP Houston, Texas Opinion on Internal Control over Financial Reporting We have audited the internal control over financial reporting of Summit Midstream Partners, LP and subsidiaries (the “Partnership”) as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2020, of the Partnership and our report dated March 4, 2021, expressed an unqualified opinion on those financial statements based on our audit. Basis for Opinion The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. An entity’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ Deloitte & Touche LLP Houston, Texas March 4, 2021 136 Table of Contents Item 9B. Other Information. None. 137 Table of Contents PART III Item 10. Directors, Executive Officers and Corporate Governance. Management of Summit Midstream Partners, LP The Partnership is managed by the directors and executive officers of its General Partner, a wholly owned subsidiary of the Partnership as of December 31, 2020. The General Partner became a wholly owned subsidiary of the Partnership in May 2020 as a result of the GP Buy-In Transaction. Directors are appointed for a term of three years and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. In connection with the GP Buy-In Transaction, the Partnership amended its Partnership Agreement to, among other things, provide its common unitholders with voting rights in the election of the members of the Board on a staggered basis beginning in 2022. The Board is divided into three classes of directors. Two Class I directors will serve for an initial term that expires at the 2022 annual meeting, two Class II directors will serve for an initial term that expires at the 2023 annual meeting, and one Class III director will serve for an initial term that expires at the 2024 annual meeting. J. Heath Deneke, President and Chief Executive Offer of the general partner, serves as Chairman of the Board and will not be subject to public election. Committees of the Board of Directors The Board of Directors has an Audit Committee, a Compensation Committee, and a Corporate Governance and Nominating Committee, and may have such other committees as the Board of Directors shall determine from time to time. The table below shows the current membership of each standing board committee and indicates which directors are independent directors. Name James Cleary Heath Deneke(3) Lee Jacobe Robert McNally Jerry L. Peters Robert Wohleber(4) Marguerite Woung-Chapman Audit Committee Compensation Committee(1) Member Member Member Chair Member Chair Corporate Governance & Nominating Committee(2) Member Member Chair Independent Director Yes No Yes Yes Yes Yes Yes Class Class III Class I Class II Class I Class III Class II (1) In May 2020, the Conflicts Committee ceased to be a standing Committee of the Board. (2) The Corporate Governance and Nominating Committee of the Board was established in May 2020 (3) Mr. Deneke was appointed Chairman of Board effective May 28, 2020 (4) Mr. Wohleber was appointed as the Lead Director effective May 28, 2020 Each of the standing committees of the Board of Directors will have the composition and responsibilities described below. Audit Committee. Mr. Jacobe, Mr. McNally and Mr. Peters serve as the members of the Audit Committee. Mr. Peters serves as the chair of the Audit Committee. In this role, Mr. Peters satisfies the SEC and New York Stock Exchange rules regarding independence and qualifies as an Audit Committee financial expert. The Audit Committee assists the Board of Directors in its oversight of the integrity of the Partnership’s financial statements and its compliance with legal and regulatory requirements and corporate policies and controls. The Audit Committee has the sole authority to retain and terminate the Partnership’s independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by the Partnership’s independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of the Partnership’s independent registered public accounting firm. The Partnership’s independent registered public accounting firm has unrestricted access to the Audit Committee. 138 Table of Contents The Partnership’s Audit Committee has adopted an audit committee charter, which is publicly available on the Partnership’s website under the "Corporate Governance" subsection of the “Investors” section at www.summitmidstream.com. Compensation Committee. Mr. Cleary, Mr. Jacobe, and Mr. Wohleber serve as the members of the Compensation Committee, with Mr. Wohleber serving as chair of the committee. The Compensation Committee provides oversight, administers and makes decisions regarding the Partnership’s executive compensation policies and incentive plans. The Compensation Committee has adopted a Compensation Committee charter, which is publicly available on its website under the “Corporate Governance” subsection of the “Investors” section at www.summitmidstream.com. Corporate Governance and Nominating Committee. Mr. Cleary, Mr. Peters, and Ms. Woung-Chapman serve as the members of the Corporate Governance and Nominating Committee, with Ms. Woung-Chapman serving as the chair of the Corporate Governance and Nominating Committee, which was established by the Board of Directors on May 28,2020. The Corporate Governance and Nominating Committee identifies individuals qualified to become board members consistent with criteria approved by the Board of Directors, assists the Board of Directors in selection of directors nominees; oversees corporate governance principles, and oversees the evaluation of the Board of Directors and management. The Corporate Governance and Nominating Committee has adopted a Corporate Governance and Nominating Committee charter, which is publicly available on its website under the “Corporate Governance” subsection of the “Investors” section at www.summitmidstream.com. Directors and Executive Officers Directors of the General Partner are appointed for a term of three years and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. In connection with the GP Buy-In Transaction, the Partnership amended its Partnership Agreement to, among other things, provide its common unitholders with voting rights in the election of the members of the Board on a staggered basis beginning in 2022. Officers serve at the discretion of the Board of Directors. The following table shows information for the directors and executive officers of the General Partner as of February 25, 2021. Name Heath Deneke Marc D. Stratton James D. Johnston Position with Summit Midstream GP, LLC President and Chief Executive Officer, Director Executive Vice President and Chief Financial Officer Executive Vice President, General Counsel and Chief Age 47 43 51 Robert M. Wohleber Lee Jacobe Robert McNally Jerry Peters James Cleary Marguerite Woung-Chapman Compliance Officer 70 53 50 63 66 55 Lead Independent Director Director Director Director Director Director Heath Deneke has been President and Chief Executive Officer and a director of the General Partner since September 2019. Prior to joining the General Partner, Mr. Deneke served as Executive Vice President, Chief Operating Officer for Crestwood Equity Partners LP and Crestwood Midstream Partners LP from August 2017 through April 2019. Previously, Mr. Deneke was the President, Chief Operating Officer of Crestwood’s Pipeline Services Group from June 2015 to August 2017, where he was responsible for the commercial development and operations of Crestwood’s midstream businesses, including assets in the Marcellus, Bakken, PRB Niobrara, Delaware, Permian, Barnett, Granite Wash, Fayetteville and Haynesville shale plays. Prior to that, he served as President of Crestwood’s Natural Gas Business Unit from October 2013 to June 2015 and as Senior Vice President and Chief Commercial Officer of Crestwood’s legacy business from August 2012 until October 2013. Prior to joining Crestwood, Mr. Deneke served in various management positions at El Paso Corporation and its affiliates, including Vice President of Project Development and Engineering for the Pipeline Group, Director of Marketing and Asset Optimization for Tennessee Gas Pipeline Company, LLC and Manager of Business Development and Strategy for Southern Natural Gas Company, LLC. Mr. Deneke holds a bachelor’s degree in Mechanical Engineering from Auburn University. Marc D. Stratton has been the Executive Vice President and Chief Financial Officer of the General Partner since December 2018. Mr. Stratton joined Summit Investments as a founding member in 2009 and has held various senior management roles at the General Partner including, Senior Vice President of Finance, Treasurer and Head of Investor Relations. Prior to joining the General Partner, Mr. Stratton served as a midstream infrastructure investment analyst at ING Investment Management and, prior 139 Table of Contents to that, as Vice President of Project Finance at SunTrust Robinson Humphrey. Mr. Stratton has over 18 years of oil and gas industry experience in corporate finance and holds a bachelor’s degree in Economics from Denison University. James Johnston has been the Executive Vice President, General Counsel and Chief Compliance Officer of the General Partner since September 2020. Prior to joining the General Partner, Mr. Johnston worked in the corporate legal department for Crestwood Equity Partners as Senior Vice President and General Counsel, after serving as Vice President, Deputy General Counsel at Crestwood. Prior to joining Crestwood in 2013, Mr. Johnston served as Assistant General Counsel for Kinder Morgan and in various legal and commercial roles of increasing responsibility at Kinder Morgan, El Paso Corporation and Sonat, Inc. from 1997 to 2013. Mr. Johnston holds a bachelor's degree from Western University in Ontario, Canada and a Doctor of Jurisprudence from Samford University's Cumberland School of Law in Birmingham, Alabama. James J. Cleary has served as a director of the General Partner since June 2020. Mr. Cleary serves on the Compensation Committee and the Corporate Governance and Nominating Committee of the General Partner. Mr. Cleary has served as a Managing Director of Global Infrastructure Partners, a leading private equity infrastructure fund with over $60 billion under management and a focus on the energy, transport and water/waste industries since 2012. Prior to that, from 1999 until its acquisition by Kinder Morgan in 2012, Mr. Cleary served in various leadership roles for El Paso Corporation, a Fortune 500 energy company, including service as the President of Western Pipelines and President of the ANR Pipeline Company. From 1979 until 1999, Mr. Cleary served in various capacities of increasing responsibility with Sonat Inc., a Fortune 500 energy company, including service as the Executive Vice President & General Counsel of Southern Natural Gas Company, which was Sonat’s pipeline business. In addition to his experience as an executive, Mr. Cleary has had significant experience in the boardroom, having served on the board of the general partner of Access Midstream Partners, L.P., a large midstream master limited partnership, and he currently serves on the board of directors of Gibson Energy, Inc., a Canadian public company that transports, stores, processes and markets crude oil and refined products in Canada and the United States. He has a B.A. in Sociology from the College of William & Mary and a J.D. from Boston College Law School. Lee Jacobe has served as a director of the General Partner since April 2019. Additionally, Mr. Jacobe serves on the Audit Committee and the Compensation Committee of the General Partner. Mr. Jacobe currently serves as an advisor with respect to energy investments for Kelso & Company, a New York based private equity firm. From 2008 through 2018, Mr. Jacobe was involved in various capacities at Barclays Investment Banking – Energy Group, including head of the firm’s midstream coverage effort, co-head of its US Oil & Gas group, and Vice Chairman of the firm. From 1993 through 2008, Mr. Jacobe was an investment banker in the energy group at Lehman Brothers, including serving as a managing director from 2001–2008. Mr. Jacobe began his investment banking career at Wasserstein Perella & Co. in 1990. He has a B.B.A., with a major in Finance, from the University of Texas at Austin. Mr. Jacobe has valuable and extensive experience in the energy banking sector, including a vast array of experience in corporate finance, capital structure, and the evaluation of financial risks associated with publicly traded partnerships that invest in midstream infrastructure. Robert J. McNally has served as a director of the General Partner since May 2020. Additionally, Mr. McNally serves on the Audit Committee of the General Partner. Mr. McNally also serves as a director of Oasis Petroleum, where he sits on the Audit & Reserves Committee and the Compensation Committee. From 2018 through 2019, Mr. McNally served as President and Chief Executive Officer of EQT Corporation, an NYSE-listed independent natural gas producer with operations in Pennsylvania, West Virginia and Ohio. Prior to that, from 2016 to 2018, Mr. McNally served as Senior Vice President and Chief Financial Officer of EQT Corporation. From 2010 until 2016, Mr. McNally served as Executive Vice President and Chief Financial Officer of Precision Drilling Corporation, a TSE and NYSE-listed drilling contractor with operations primarily in the United States, Canada and the Middle East. From 2009 to 2010, and for a period in 2007, Mr. McNally served as an Investment Principal for Kenda Capital LLC. In 2008, Mr. McNally served as the Chief Executive Officer of Dalbo Holdings, Inc. In 2006, Mr. McNally served as Executive Vice President of Operations and Finance for Warrior Energy Services Corp. From 2000 to 2005, Mr. McNally worked in corporate finance with Simmons & Company International. Mr. McNally began his career as an engineer with Schlumberger Limited and served in various capacities of increasing responsibility during his tenure from 1994 until 2000. In addition to his experience as an executive, Mr. McNally has had extensive experience in the boardroom, where he has served, at various times, on the boards of Warrior Energy Services, Dalbo Holdings, EQT Midstream Partners, EQT GP Holdings, Rice Midstream Partners and EQT Corporation. He has a B.S. in Mechanical Engineering from University of Illinois, a B.A. in Mathematics from Knox College, and an M.B.A. from Tulane University Freeman School of Business. Mr. McNally brings a wealth of executive management, operational, and financial experience in the oil and gas industry to the Board of Directors. 140 Table of Contents Jerry L. Peters has served as a director of the General Partner since September 2012. Additionally, Mr. Peters served as the chair of the Conflicts Committee of the General Partner until November 2012 and serves as the chair and financial expert of the Audit Committee of the General Partner. Mr. Peters served as the Chief Financial Officer of Green Plains Inc., a publicly traded vertically integrated ethanol producer, from June 2007 until his retirement in September 2017. In 2015, Mr. Peters was appointed Chief Financial Officer and Director of the General Partner of Green Plains Partners LP, a publicly traded partnership engaged in fuel storage and transportation services. He retired from his role as Chief Financial Officer of the General Partner of Green Plains Partners LP in September 2017 but remains on the Board of Directors. Prior to joining Green Plains, Mr. Peters served as Senior Vice President—Chief Accounting Officer for ONEOK Partners, L.P. from May 2006 to April 2007, as Chief Financial Officer of ONEOK Partners, L.P. from July 1994 to May 2006, and in various senior management roles of ONEOK Partners, L.P. from 1985 to May 2006. Prior to joining ONEOK Partners, Mr. Peters was employed by KPMG LLP as a certified public accountant from 1980 to 1985. In October 2017, Mr. Peters joined the board of the general partner of USA Compression Partners LP and served as chair and financial expert of the audit committee thereof. Mr. Peters resigned from the board of the general partner of USA Compression Partners LP in March 2018. Mr. Peters received an MBA from Creighton University with an emphasis in finance and a B.S. in Business Administration from the University of Nebraska—Lincoln. Mr. Peters' extensive executive, financial and operational experience bring important and necessary skills to the Board of Directors. Robert M. Wohleber has served as a director of the General Partner since August 2013. Mr. Wohleber also serves as Chairperson of the Compensation committee of the General Partner. Mr. Wohleber served as Senior Vice President and Chief Financial Officer of Kerr-McGee Corporation, an oil and gas exploration and production company, from December 1999 to August 2006. From 1996 to 1998, he served as Senior Vice President and Chief Financial Officer of Freeport-McMoran, Inc., one of the largest phosphate fertilizer producers in the United States. He holds a B.B.A. from the University of Notre Dame and an M.B.A. from the University of Pittsburgh. Mr. Wohleber’s extensive executive and financial experience in the oil and gas industry bring important and necessary skills to the Board of Directors. Marguerite Woung-Chapman has served as a director of the General Partner since May 2020. Ms. Woung-Chapman also serves as the Chairperson of the Corporate Governance & Nominating Committee of the General Partner. In 2018, Ms. Woung-Chapman served as Senior Vice President, General Counsel and Corporate Secretary of Energy XXI Gulf Coast, Inc., a NASDAQ-listed independent exploration and production company that was engaged in the development, exploitation and acquisition of oil and natural gas properties in the U.S. Gulf Coast region. Prior to that, from 2012 to 2017, Ms. Woung- Chapman served in various capacities at EP Energy Corporation, a private company that subsequently became an NYSE-listed independent oil and gas exploration and production company, including, among others, Senior Vice President, Land Administration, General Counsel and Corporate Secretary. Ms. Woung-Chapman began her career as a corporate attorney with El Paso Corporation (including its predecessors) and served in various capacities of increasing responsibility during her tenure from 1991 until 2012, including, among others, Vice President, Legal Shared Services, Corporate Secretary and Chief Governance Officer. She has a B.S. in Linguistics from Georgetown University and a J.D. from the Georgetown University Law Center. Ms. Woung- Chapman also serves, since June 2020, as the Chair of the Board of Directors and President of the Girl Scouts of San Jacinto Council, which is the second largest Girl Scout council in the country. Ms. Woung-Chapman has valuable and extensive experience in all aspects of management and strategic direction of publicly-traded energy companies and brings a unique combination of corporate governance, regulatory, compliance, legal and business administration experience to the Board of Directors. Code of Business Conduct and Ethics The Board of Directors has adopted a Code of Business Conduct and Ethics which sets forth the Partnership’s policy with respect to business ethics and conflicts of interest. The Code of Business Conduct and Ethics is intended to ensure that the employees, officers and directors of the Partnership and its General Partner conduct business with the highest standards of integrity and in compliance with all applicable laws and regulations. It applies to the employees, officers and directors of the Partnership and its General Partner, including the principal executive officer, principal financial officer and principal accounting officer or controller, or persons performing similar functions (the “Senior Financial Officers”). The Code of Business Conduct and Ethics also incorporates expectations of the Senior Financial Officers that enable the Partnership to provide accurate and timely disclosure in its filings with the SEC and other public communications. The Code of Business Conduct and Ethics is publicly available on the Partnership’s website under the “Corporate Governance” subsection of the “Investors” section at www.summitmidstream.com and is also available free of charge on written request to the Secretary at the Houston office address given under the "Contact" section on the Partnership’s website. 141 Table of Contents Corporate Governance Guidelines The Partnership’s Corporate Governance Guidelines, which are available on its website under the “Corporate Governance” subsection of the “Investors” section at www.summitmidstream.com, provide guidelines for the governance of the Partnership. The Corporate Governance Guidelines specifically provide, among other things, that (i) the independent members of the Board will select an independent director to serve as “Lead Director” to preside over any executive sessions at which the Chairman of the Board is not present, and (ii) interested parties may communicate directly with the General Partner’s independent directors by submitting an envelope marked “Confidential” addressed to the “Independent Members of the Board” in care of the Secretary of the General Partner. Delinquent Section 16(a) Reports Section 16(a) of the Exchange Act requires SMLP’s directors and executive officers, and persons who own more than 10% of a registered class of the Partnership’s securities, to file with the SEC initial reports of ownership and reports of changes in ownership of SMLP's common units and other equity securities. Based on the Partnership’s records, it believes that all directors, executive officers and persons who own more than 10% of the Partnership’s common units have complied with the reporting requirements of Section 16(a) except for the following. On February 7, 2020, Energy Capital Partners II, LLC and Summit Midstream Partners, LLC filed delinquent Section 16(a) reports relating to the second amendment to that certain Contribution Agreement between SMP Holdings and the Partnership dated February 25, 2016, as amended, pursuant to which the Partnership issued 714,286 common units (as adjusted for the Reverse Unit Split) to SMP Holdings on November 15, 2019. 142 Table of Contents Item 11. Executive Compensation. This Compensation Discussion and Analysis (“CD&A”) provides information regarding the compensation of certain of our executive officers as reported in the Summary Compensation Table and other tables in this document. In this CD&A, we review the compensation decisions, and rationale for those decisions, relating to the person who served as our principal executive officer during the past fiscal year, the person who served as our principal financial officer during the past fiscal year, and the Partnership’s next most highly compensated executive officer. (1) The following describes the material components of the Partnership’s executive compensation program for the following individuals, who are referred to as the “Named Executive Officers” or “NEOs”: • • • • • Heath Deneke, President and Chief Executive Officer Marc D. Stratton, Executive Vice President and Chief Financial Officer James Johnston, Executive Vice President, General Counsel and Chief Compliance Officer(2) Leonard W. Mallett, Former Executive Vice President and Chief Operations Officer(3) Louise E. Matthews, Former Executive Vice President and Chief Administration Officer(4) (1) Mr. Deneke, Mr. Stratton, and Mr. Johnston are the only executive officers of the General Partner. (2) Mr. Johnston was appointed Executive Vice President, General Counsel and Chief Compliance Officer effective September 4, 2020. (3) Mr. Mallett’s employment terminated effective October 31, 2020. (4) Ms. Matthews’ employment terminated effective April 1, 2020. The NEOs are employees of Summit Operating Services Company, LLC (“Summit Operating”), a wholly owned subsidiary of the Partnership, and executive officers of the General Partner. Prior to the GP Buy-In Transaction, certain of the NEOs split their working time between SMLP's business and their responsibilities for its then affiliate relationships. See Note 1 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the GP Buy-In Transaction and the presentation of Partnership’s financial statements for periods prior to the GP Buy-In Transaction. All compensation amounts for the NEOs are reflected in the Partnership’s financial statements included in this Annual Report. The Compensation Committee provides oversight, administers and makes decisions regarding the Partnership’s compensation policies and plans. Compensation Philosophy and Objectives We seek to provide reasonable and competitive rewards to executives through compensation and benefit programs structured to: Attract and retain outstanding talent • • • • Drive achievement of short-term and long-term goals Reward successful execution of objectives Reinforce our culture and leadership competencies Align executives with the interests of the our unitholders We employ a pay-for-performance philosophy when designing executive compensation opportunities. Thus, a portion of an executive’s target compensation is performance based through linkage to the achievement of financial and other measures deemed to be drivers in the creation of unitholder value. While the Compensation Committee does not set a specific target allocation among the elements of total direct compensation, a portion of the compensation opportunity available to each of our NEOs is, by design, tied to the Partnership’s annual and long-term performance. Compensation of Named Executive Officers The Compensation Committee establishes the target total direct compensation of our executives and administers other benefit programs. The Compensation Committee engages an independent compensation consultant (the “Compensation Consultant”) who provides the Compensation Committee with data, analysis and advice on the structure and level of executive compensation. The Compensation Consultant participates in Compensation Committee meetings and executive sessions of the Compensation Committee meetings as requested. The Compensation Consultant may work with our management on various matters for which 143 Table of Contents the Compensation Committee is responsible. However, the Compensation Committee, not management, directs the activities of the Compensation Consultant. We consider the Compensation Consultant to be independent of the Partnership according to current NYSE listing requirements and SEC guidance. Willis Towers Watson serves as the Compensation Consultant. Partnership management, in consultation with the Compensation Committee chair and the Compensation Consultant, prepares materials for the Compensation Committee relevant to matters under consideration by the Compensation Committee, including market data provided by the Compensation Consultant and recommendations of our Chief Executive Officer (the "CEO") regarding compensation of the other executives. The Compensation Committee works directly with the Compensation Consultant to determine the compensation of our CEO, as required. Based on market data which the we use as a reference, we believe compensation for our NEOs is reasonably competitive with opportunities available to officers holding similar positions at comparable midstream companies. We seek to set compensation levels for each component of total direct compensation based on our assessment of market practices at or near the median. The Compensation Committee adjusts target compensation for each NEO above or below the median, taking into consideration experience, performance, internal equity and other relevant circumstances. During the Compensation Committee’s annual review of executive compensation, the Compensation Consultant provided the Compensation Committee with an analysis of positions comparable to the NEOs at peer companies. To develop these exhibits, information from peer company public filings was compiled, including public company proxy statements and annual reports on Form 10-K. The peer group used for 2020 executive compensation consisted of publicly traded midstream companies with whom we compete for executive talent. The peer group comprised the following companies: Altus Midstream Company Archrock, Inc. Crestwood Equity Partners, LP DCP Midstream, LP Enable Midstream Partners, LP EnLink Midstream, LLC Equitrans Midstream Corporation Genesis Energy, LP Magellen Midstream Partners, L.P. NGL Energy Partners LP NuStar Energy, LP Targa Resources Corp Tidewater Midstream and Infrastructure Ltd. USA Compression Partners, LP USD Partners LP The compensation analysis encompassed the primary components of total direct compensation, including annual base salary, annual short-term incentive and long-term incentive awards for the NEOs of these peer group companies. The Compensation Committee considered the information provided to ascertain whether the compensation of our NEOs is aligned with the its compensation philosophy and competitive with the compensation for executive officers of the peer group companies. The Compensation Committee reviewed the compensation analysis to confirm our compensation programs were supporting a competitive total compensation approach that emphasizes incentive-based compensation and appropriately rewards achievement of our objectives. For 2020, the target total direct compensation for the NEOs as set by the Compensation Committee is summarized below. Each element is further discussed in this CD&A. Components of Executive Compensation Name and Principal Position Heath Deneke President and Chief Executive Officer Marc D. Stratton Executive Vice President and Chief Financial Officer James Johnston (1) 2020 Target Annual Bonus: Percent of Base Salary (%) Base Salary ($) 2020 Target Annual Bonus Value ($) 2020 Target LTIP Award: Percent of Base Salary (%) 2020 LTIP Target Award Value ($) 2020 Target Total Direct Compensation ($) 600,000 150% 900,000 275% 1,650,000 3,150,000 350,000 100% 350,000 165% 577,500 1,277,500 144 Table of Contents Executive Vice President, General Counsel and Chief Compliance Officer Leonard W. Mallett (2) Former Executive Vice President and Chief Operations Officer Louise E. Matthews (3) Former Executive Vice President and Chief Administration Officer 350,000 100% 350,000 165% 577,500 1,277,500 400,000 100% 400,000 165% 660,000 1,460,000 300,000 100% 300,000 150% 450,000 1,050,000 (1) James Johnston was appointed Executive Vice President, General Counsel and Chief Compliance Officer effective September 4, 2020; his target total direct compensation was approved by the Compensation Committee. Although Mr. Johnston's target annual bonus set forth in his employment agreement is 100% of his base salary, his employment agreement further provides that his 2020 bonus shall be prorated for the period of time he actually served as Executive Vice President, General Counsel and Chief Compliance Officer. (2) Mr. Mallett’s employment terminated effective October 31, 2020. (3) Ms. Matthews’ employment terminated effective April 1, 2020. The primary elements of compensation for the NEOs are base salary, annual incentive compensation and long-term equity-based compensation awards. The NEOs also receive certain retirement, health and welfare and additional benefits. Base Salary. The base salaries for our NEOs are reviewed annually by the Compensation Committee. Base salaries our NEOs have generally been set at levels deemed necessary to attract and retain individuals with superior talent. The base salaries of our NEOs are set forth in the following table: Name and Principal Position Heath Deneke President and Chief Executive Officer Marc D. Stratton Executive Vice President and Chief Financial Officer James Johnston (1) Executive Vice President, General Counsel and Chief Compliance Officer Leonard W. Mallett (2) Former Executive Vice President and Chief Operations Officer Louise E. Matthews (3) Former Executive Vice President and Chief Administration Officer 2020 Base Salary ($) 600,000 350,000 350,000 400,000 300,000 (1) James Johnston was appointed Executive Vice President, General Counsel and Chief Compliance Officer effective September 4, 2020. (2) Mr. Mallett’s employment terminated effective October 31, 2020. (3) Ms. Matthews’ employment terminated effective April 1, 2020. Annual Incentive Compensation. We provide an annual incentive bonus (“annual bonus”) to drive the achievement of key business results and to recognize NEOs based on their contributions to those results. The annual bonus plan is a cash-based incentive plan. Incentive amounts are intended to provide total cash compensation near the market range for executive officers in comparable positions when target performance is achieved. Annual bonus compensation levels are set above or below the market range to reflect actual performance results as appropriate when performance is greater or less than expectations. Annual bonus payouts may range from 0% to 200% of the target opportunity and may be adjusted at the discretion of the Compensation Committee. In March 2020, the Compensation Committee established the 2020 annual bonus plan target opportunities as a percentage of base salary for our NEOs other than Mr. Johnston. The 2020 target for Mr. Deneke was 150%. For Messrs. Stratton and Mallett and for Ms. Matthews it was 100% of their base salaries. In August 2020, the Compensation Committee approved Mr. Johnston’s annual bonus plan target opportunity as 100% of his base salary. Although Mr. Johnston's target annual bonus set forth in his employment agreement is 100% of his base salary, his employment agreement further provides that his 2020 bonus shall be prorated for the period of time he actually served as Executive Vice President, General Counsel and Chief Compliance Officer. 145 Table of Contents Name and Principal Position Heath Deneke President and Chief Executive Officer Marc D. Stratton Executive Vice President and Chief Financial Officer James Johnston (1) Executive Vice President, General Counsel and Chief Compliance Officer Leonard W. Mallett (2) Former Executive Vice President and Chief Operations Officer Louise E. Matthews (3) Former Executive Vice President and Chief Administration Officer 2020 Target Annual Bonus: Percent of Base Salary (%) 150 100 100 100 100 2020 Target Annual Bonus Value ($) 900,000 350,000 350,000 400,000 300,000 (1) (2) (3) James Johnston was appointed Executive Vice President, General Counsel and Chief Compliance Officer effective September 4, 2020. Mr. Mallett’s employment terminated effective October 31, 2020. Ms. Matthews’ employment terminated effective April 1, 2020. In 2020, quantitative factors, as reflected in the corporate scorecard applicable to the senior leadership team (the "SLT Scorecard") set the baseline for the annual bonuses for our NEOs, which were subject to further adjustments as explained below. The SLT Scorecard contained four factors, which are considered by the Board of Directors and management as key indicators of the successful execution of our business plan. Those factors were (i) adjusted EBITDA, (ii) distributable cash flow per unit, (iii) controllable expense metric and (iv) health, safety, environmental and regulatory goals. The annual bonuses paid to Messrs. Deneke, Stratton and Johnston were approved by the Board and determined in accordance with their employment agreements, as further described below. In February 2021, the Compensation Committee and the Board of Directors reviewed the SLT Scorecards for 2020 and determined the level of achievement of each key factor. We exceeded our health, safety, environmental and regulatory goals and met our (i) controllable expense metric and (ii) distributable cash flow per unit targets. We did not meet our adjusted EBITDA target. These results yielded a calculated SLT Scorecard result of 52% of target. In addition to corporate results, additional considerations are applied at the discretion of the CEO, the Compensation Committee and the Board of Directors that may affect the actual annual bonus earned. Those considerations include judgments regarding overall company performance and business events, performance of each NEO’s respective business unit, industry climate and performance, the market for executive talent, demonstrated leadership capabilities and progress on strategic initiatives. Each NEO’s bonus amount, as reflected below, is adjusted up or down in recognition of these additional considerations. Mr. Deneke’s annual bonus payout reflects his demonstrated leadership capabilities. Mr. Deneke was awarded 75% of his target annual bonus in 2020, or $675,000. Mr. Stratton’s annual bonus payout reflects consideration for the combined performance of the finance and accounting business units. Mr. Stratton was awarded 75% of his target annual bonus in 2020, or $262,500. Mr. Johnston’s annual bonus payout reflects consideration for the combined performance of the legal, human resources and health, safety, environmental and regulatory units. Mr. Johnston was awarded 75% of his target annual bonus in 2020, or $87,500, prorated for the period of time he served as Executive Vice President, General Counsel and Chief Compliance Officer. In connection with their terminations, Mr. Mallett and Ms. Matthews received prorated annual bonuses for 2020 pursuant to the terms of their employment agreements. Mr. Mallett received a prorated annual bonus of $158,333 and Ms. Matthews received a prorated annual bonus equal to $74,795. 146 Table of Contents Based on the foregoing discussion, the annual bonus awards to be paid in March 2021 to our NEOs for 2020 performance are as follows: Name and Principal Position Heath Deneke President and Chief Executive Officer Marc D. Stratton Executive Vice President and Chief Financial Officer James Johnston Executive Vice President, General Counsel and Chief Compliance Officer Leonard W. Mallett (1) Former Executive Vice President and Chief Operations Officer Louise E. Matthews (1) Former Executive Vice President and Chief Administration Officer 2020 Annual Bonus Payout ($) 675,000 262,500 87,500 158,333 74,795 (1) The amounts reflected are prorated annual bonuses paid to Mr. Mallett and Ms. Matthews upon their terminations in accordance with their employment agreements. Mr. Mallett employment terminated on October 31, 2020. Ms. Matthews employment terminated on April 1, 2020. Long-Term Equity-Based Compensation Awards. The General Partner approved the SMLP LTIP pursuant to which eligible officers (including the NEOs), employees, consultants and directors of the General Partner and its affiliates are eligible to receive awards with respect to our equity interests, thereby linking the recipients’ compensation directly to the value of our common units and enhancing our ability to attract and retain superior talent. The SMLP LTIP provides for the grant, from time to time at the discretion of the Board of Directors or Compensation Committee, of a dollar-denominated award, unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The SMLP LTIP is designed to promote our interests, as well as the interests of our unitholders, by aligning the interests of our eligible employees (including the NEOs) and directors with those of common unitholders, as well as by strengthening our ability to attract, retain and motivate qualified individuals to serve as directors and employees. SMLP LTIP award guidelines for NEOs are designed to attract, retain and motivate the NEOs and were determined using the Compensation Consultant's analysis for individuals in comparable positions and an analysis of the scope of their roles and duties. These guidelines set an annual equity award target in the amount of 275% of salary for Mr. Deneke; 165% for Messrs. Stratton, Johnston and Mallett; 150% of base salary for Ms. Matthews. Although LTIP is usually granted once per fiscal year (during the quarterly period ended March 31st), in 2020 there were two separate equity grants, described below: March 2020 Equity Grants. Effective March 20, 2020, based on the recommendation of the Compensation Committee, the Board of Directors approved a grant of phantom units and cash award to Messrs. Deneke, Stratton, and Mallet. The underlying phantom units and cash award vest ratably over a three- year period. Holders of phantom units are entitled to distribution equivalent rights for each phantom unit, if applicable, providing for a lump sum payment equal to any accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. The Compensation Committee selected equity awards that vest contingent on continued service to foster increased unit ownership by the NEOs and as a retention incentive for continued employment with the Partnership. September 11, 2020 Equity Grant to Mr. Johnston. As an inducement to accept the position of Executive Vice President, General Counsel and Chief Compliance Officer of the General Partner, on September 11, 2020, Mr. Johnston received a one-time grant of phantom units and cash award valued at approximately $1,155,000, pursuant to a standalone phantom unit award agreement (the "Award Agreement"). Subject to the terms and conditions of the Award Agreement, the underlying phantom units will vest ratably over a two-year period, and are entitled to distribution equivalent rights for each phantom unit, if applicable, providing for a lump sum payment equal to any accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. 147 Table of Contents All SMLP LTIP grants to our NEOs are subject to accelerated vesting on the occurrence of any of the following events: (i) a termination of the NEO's employment other than for cause, (ii) a termination of the NEO's employment by the NEO for good reason (as defined in the NEO's employment agreement), (iii) a termination of the NEO's employment by reason of the NEO's death or disability or (iv) a Change in Control (as defined in the applicable award agreement). To calculate the number of phantom units granted to each eligible NEO in March 2020, the Compensation Committee determined the dollar amount of the long-term incentive compensation award, and then granted the number of phantom units that had a fair market value equal to that amount as of market close on the date of the grant. The same calculation was performed with respect to the September 4, 2020 grant to Mr. Johnston. Phantom unit and Cash awards granted in 2020 were as follows: Name and Principal Position Heath Deneke President and Chief Executive Officer Marc D. Stratton Executive Vice President and Chief Financial Officer James Johnston (1) Executive Vice President, General Counsel and Chief Compliance Officer Leonard W. Mallett Former Executive Vice President and Chief Operations Officer Louise E. Matthews (2) Former Executive Vice President and Chief Administration Officer (1) and cash award was approved by the Compensation Committee. 2020 Target LTIP Award: Percent of Base Salary (%) 2020 Phantom Units Awarded (#) 2020 Cash Awarded ($) 2020 SMLP LTIP Award Value ($) 275 165 165 165 150 108,882 758,257 1,650,000 25,406 369,427 577,500 33,333 800,000 1,155,000 29,035 422,202 660,000 — — — Although Mr. Johnston’s employment agreement provides for a target LTIP award valued at 165% of his base salary, in 2020 the value of his initial one-time grant of phantom units (2) Ms. Matthews employment terminated effective April 1, 2020. Ms. Mathews received no grants of phantom unit awards in 2020. Retirement, Health and Welfare and Additional Benefits. The NEOs are eligible to participate in such employee benefit plans and programs we offer to our employees, subject to the terms and eligibility requirements of those plans. 401(k) Plan. The NEOs are eligible to participate in a tax qualified 401(k) defined contribution plan to the same extent as all of our other employees. In 2020, we made a fully vested matching contribution on behalf of each of the 401(k) plan's participants up to 5% of such participant's eligible salary for the year. Health Savings Account ("HSA") Program. The NEOs are eligible to participate in a tax qualified health savings account (“HSA”) if they are enrolled in the available high-deductible health plan. The HSA is a tax-free savings account owned by an individual and can be used to pay for current or future qualified medical expenses. Participants determine how much to contribute, when and how to spend the money on eligible medical expenses, and how to invest the balance. The balance remains in the account and is not subject to forfeiture. The Partnership makes annual contributions to all HSA-eligible employees who enroll in and contribute to an HSA. In 2020, we made tax-free HSA contributions of $600 to Mr. Deneke, $600 to Mr. Stratton and $185 to Ms. Matthews. Deferred Compensation Plan. Effective May 28, 2020, the Deferred Compensation Plan was terminated. As a result, payment of all remaining amounts deferred thereunder was tendered to participants or their designated beneficiaries, as applicable, in a single lump sum payment. Additional Benefits. Pursuant to the terms of their employment agreements: • • All NEOs are entitled to reimbursement for tax preparation and advisory services expenses of up to $12,000 per year. Mr. Deneke is entitled to be reimbursed up to $15,000 per year for annual international or local chapter dues associated with his membership in the Young Presidents Organization (“YPO”). 148 Table of Contents Expenditures for these benefits are included as “All Other Compensation” in the Summary Compensation Table and further described in the table entitled “All Other Compensation” below. Employment and Severance Arrangements. Employment Agreements. Our NEOs each have employment agreements with Summit Operating. Elements of the NEOs’ total direct compensation are subject to periodic review and may be adjusted accordingly by the Compensation Committee. Mr. Deneke’s employment agreement, which has an effective date of September 1, 2020, has an initial term that expires on September 1, 2022, and is then automatically extended for successive one-year periods, unless either party gives notice of non-extension to the other no later than 30 days prior to the expiration of the then-applicable term. Mr. Deneke’s employment agreement provides for an annual base salary of $600,000, and a performance-based bonus ranging from 0% to 300% of base salary, with a target of 150% of base salary. Mr. Deneke is entitled to receive a prorated annual bonus (based on target) if his employment is terminated by Mr. Deneke with good reason, or by us without cause or as a result of a non-extension of the term, or due to death or disability. In addition, Mr. Deneke’s employment agreement also provides for reimbursement of certain business expenses incurred in connection with his employment, including company-paid tax preparation and advisory services of up to $12,000 per year and YPO membership dues of up to $15,000 per year. Mr. Deneke’s employment agreement provides for a cash severance payment upon a termination resulting from a non-extension of the term by us, or a termination by us without cause or by Mr. Deneke for good reason, which is defined generally as the officer's termination of employment within two years after the occurrence of (i) a material diminution in Mr. Deneke’s authority, duties or responsibilities, (ii) a material diminution in the aggregated total of Mr. Deneke’s base salary, target bonus (as a percentage of base salary) or Annual LTIP Target (as that term is defined in the agreement), (iii) a material change in the geographic location at which Mr. Deneke must perform his services under the agreement, (iv) a change in Mr. Deneke’s reporting relationship resulting in Mr. Deneke no longer reporting directly to the Board of Directors, or (v) any other action or inaction that constitutes a material breach of the employment agreement by us (each a "Qualifying Termination"). In the event of a Qualifying Termination, Mr. Deneke’s severance payment will be equal to two and one-half times the sum of his annual base salary and the higher of his target annual bonus payable in respect of the immediately preceding year and the annual bonus actually paid to him in respect of that year. Following any termination of employment other than one resulting from non-extension of the term, his employment agreement provides that Mr. Deneke will be subject to a post-termination non-competition covenant through the severance period, and, following any termination of employment, Mr. Deneke will be subject to a one-year post-termination non-solicitation covenant. If Mr. Deneke’s employment terminates as a result of a non-extension of the term, we may choose to subject him to a non-competition covenant for up to one year post-termination. If we exercise this “noncompete option” following a non- extension of term by Mr. Deneke, then Mr. Deneke would be entitled to a severance payment in an amount equal to two and one-half times the sum of his annual base salary and the higher of his target annual bonus payable in respect of the immediately preceding year and the annual bonus actually paid to him in respect of that year, multiplied by a fraction, the numerator of which is equal to the number of days from the date of termination through the expiration of the restricted period (as elected by us) and the denominator of which is 365. In this case, the severance payment will be payable in equal installments over the restricted period. Following any termination of employment, we have agreed to pay the out-of-pocket premium cost to continue Mr. Deneke’s medical and dental coverage for a period not to exceed 18 months, with such coverage terminating if any new employer provides benefits coverage. Mr. Deneke’s employment agreement also provides that all equity awards granted to him under the SMLP LTIP and held by him as of immediately prior to a change in control of the Partnership or the General Partner will become fully vested immediately prior to the change in control. Additionally, as an inducement to accept the position as our President and Chief Executive Officer of the General Partner, at the beginning of his employment term, Mr. Deneke received a one-time grant of phantom units valued at $4,000,000, pursuant to standalone phantom unit award agreement (“Deneke Award Agreement”). Subject to the terms and conditions of the Deneke Award Agreement, the underlying phantom units will vest ratably over a three-year period, and are entitled to distribution equivalent rights for each phantom unit, providing for a lump sum payment equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. Furthermore, the phantom units will be subject to accelerated vesting on the occurrence of any of the following events: (i) a termination of Mr. Deneke’s employment other than for cause, (ii) 149 Table of Contents a termination of employment by Mr. Deneke for good reason (as that term is defined in Mr. Deneke’s employment agreement), (iii) a termination of Mr. Deneke’s employment by reason of death or disability or (iv) a Change in Control (as defined in the Award Agreement). The remaining NEOs’ employment agreements are substantially the same as Mr. Deneke’s, except for the following: • • • • • • Each of the other NEOs is entitled to a severance payment in the event of a Qualifying Termination equal to one and one-half times the sum of his or her annual base salary and his or her annual bonus payable in respect of the immediately preceding year. Each of the other NEOs is entitled to a severance payment in the event the we exercise the “noncompete option” following a non-extension of the term by the NEO equal to the sum of 1.5 times his annual base salary and the higher of his target annual bonus and the annual bonus paid to him in respect of the immediately preceding year. Each of the other NEOs is entitled to a performance-based bonus ranging from 0% to 200% of base salary, with a target of 100% of base salary. The other NEOs are not entitled to be reimbursed for membership dues. Mr. Stratton’s base salary is $350,000, and the initial term of his employment agreement ends on September 1, 2022. Mr. Johnston’s base salary is $350,000, and the initial term of his employment agreement ends on September 4, 2022. Retention Bonus Agreements. Effective June 7, 2019, and prior to the GP Buy-In Transaction, Summit Investments, the General Partner, and SMLP jointly entered into retention bonus agreements with certain NEOs for the amounts indicated below: Mr. Mallett: Mr. Stratton: Ms. Matthews: $420,000 $365,000 $365,000 The agreements provided for a cash payment “Retention Bonus” upon the earlier of a termination without cause or a change in control (as those terms are defined in the executive’s employment agreement). The agreements terminated if the executive officer continued to be employed and a change in control had not occurred on or prior to December 31, 2020. Mr. Mallett’s employment terminated effective October 31, 2020. According to the terms of his retention bonus agreement, Mr. Mallett received payment of $420,000 upon his termination. Ms. Matthews’ employment terminated effective April 1, 2020. According to the terms of her retention bonus agreement, Ms. Matthews’ received payment of $365,000 upon her termination. Risk Assessment Relative to Compensation Programs. The Compensation Committee manages risk as it relates to our compensation plans, programs, and structure (collectively, our “Compensation Practices”). The Compensation Committee meets with management to review whether any aspect of our Compensation Practices creates incentives for our employees to take inappropriate risks that could materially adversely affect the Partnership. Accordingly, we believe that the compensation practices for our NEOs and other employees are appropriately structured and do not pose a material risk to the Partnership. We believe these compensation practices are designed and implemented in a manner that does not promote excessive risk-taking that could damage the value of the Partnership or provide compensatory rewards for inappropriate decisions or behavior. Compensation Committee Report. The Compensation Committee has reviewed and discussed this CD&A with the our management and, based on such review and discussion, has recommended to the Board of Directors that the CD&A be included in the Annual Report. 150 Table of Contents Summary Compensation Table for 2020, 2019 and 2018 The following table sets forth certain information with respect to the compensation paid to our NEOs for the years ended December 31, 2020, 2019 and 2018. Name and Principal Position Heath Deneke President and Chief Executive Officer Marc D. Stratton Executive Vice President and Chief Financial Officer James Johnston (5) Executive Vice President, General Counsel, Chief Compliance Officer and Secretary Leonard W. Mallett (6) Former Executive Vice President and Chief Operations Officer Louise E. Matthews (7) Former Executive Vice President and Chief Administration Officer Year 2020 2019 2020 2019 2018 2020 Salary ($) (1) 600,000 161,538 350,000 262,500 231,782 102,308 Bonus ($) (1) 758,257 369,427 — — 800,000 2020 2019 2018 2020 2019 346,154 350,000 364,800 84,231 285,000 842,202 87,500 — 365,000 — Equity Awards ($) (2) 891,743 4,000,000 208,073 768,500 225,000 355,000 237,798 843,500 625,000 — 693,500 Non-Equity Incentive Plan Compensation ($) (3) All Other Compensation ($) (4) Total ($) 675,000 300,000 262,500 170,625 254,625 87,500 158,333 227,500 364,800 74,795 185,250 52,671 28,822 34,171 28,800 31,700 10,262 2,977,671 4,490,360 1,224,171 1,230,425 743,107 1,355,070 150,700 12,895 13,773 932,506 35,197 1,735,187 1,521,395 1,368,373 1,456,532 1,198,947 (1) (2) (3) (4) Amounts shown represent the portion of the NEO’s base salary and bonus allocated to the Partnership. Prior to closing the GP Buy-In Transaction in May 2020, compensation amounts for the NEO were allocated between the General Partner and SMLP. As a result of the GP Buy-In Transaction, the Partnership now pays for 100% of the NEO’s compensation. For a discussion of the cost allocation methodology, please refer to “Agreements with Affiliates—Reimbursement of Expenses from General Partner” in Item 13. Certain Relationships and Related Transactions, and Director Independence. Amounts shown reflect the grant date fair value of the phantom unit awards granted to the NEOs in 2020, 2019 and 2018, respectively, in accordance with FASB Accounting Standards Codification Topic 718, Compensation—Stock Compensation ("FASB ASC Topic 718"). For the assumptions made in valuing these awards, see Note 16 to the consolidated financial statements. For additional information, please refer to "Components of Executive Compensation—Long-Term Equity-Based Compensation Awards" above. Amounts shown represent the incentive bonus earned under the Partnership’s annual incentive bonus program in the fiscal year indicated but paid in the following fiscal year. The amounts shown represent that portion of the NEO's annual bonus that has been allocated to SMLP. Prior to closing the GP Buy-In Transaction in May 2020, compensation amounts for the NEO were allocated between the General Partner and SMLP. As a result of the GP Buy-In Transaction, the Partnership now pays for 100% of the NEO’s compensation. For a discussion of the cost allocation methodology, please refer to “Agreements with Affiliates—Reimbursement of Expenses from General Partner” in Item 13. Certain Relationships and Related Transactions, and Director Independence The table below presents the components of "All Other Compensation" allocated to SMLP for each NEO for the fiscal year ended December 31, 2020. For additional information, please see "Components of Executive Compensation—Retirement, Health and Welfare and Additional Benefits" above. Prior to closing the GP Buy-In Transaction in May 2020, compensation amounts for the NEO were allocated between the General Partner and SMLP. As a result of the GP Buy-In Transaction, the Partnership now pays for 100% of the NEO’s compensation. For a discussion of the cost allocation methodology, please refer to “Agreements with Affiliates—Reimbursement of Expenses from General Partner” in Item 13. Certain Relationships and Related Transactions, and Director Independence (5) Mr. Johnston began his employment with the Partnership effective September 4, 2020. (6) Mr. Mallett’s employment terminated on October 31, 2020. The portion of the severance payment made to Mr. Mallett in 2020 is included in the “All Other Compensation” column. (7) Ms. Matthews’ employment terminated on April 1, 2020. The severance payment made to Ms. Mathews in 2020 is included in the “All Other Compensation” column. Pay Ratio Disclosure The following is a reasonable estimate, prepared under applicable SEC rules, of the ratio of the annual total compensation of our CEO to the median of the annual total compensation of our other employees. Although we previously identified our median employee on December 31, 2019, due to a change in our employee population that we reasonably believe will result in a significant change to our pay ratio disclosure, we identified a new median employee in 2020. For 2020, we determined or median employee by ranking our employees (other than the CEO) employed as of December 31, 2020 (the “determination date”) by the sum of each employee’s annualized base salary, his or her actual cash bonus received in 2020 for 2019 performance, and his or her actual overtime pay received in 2020. In annualizing each employee’s base salary, we used each employee’s base salary rate as of the determination date. We made no full-time equivalent adjustment for any employee, we had no temporary or seasonal workers as of the determination date, and we made no cost-of-living adjustments. The annual total compensation our median 151 Table of Contents employee (other than the CEO) for 2020 was $120,592. To determine the annual total compensation of our CEO for purposes of this disclosure, we chose the person who was serving as CEO as of the determination date and used the total compensation he received in 2020 as set forth in the Summary Compensation Table above. Accordingly, for purposes of this disclosure, we determined that the CEO’s annual total compensation for 2020 was $2,510,333. Based on the foregoing, we estimate of the ratio of the annual total compensation of our CEO to the median of the annual total compensation of all other employees was 20.8 to 1. Given the different methodologies that various public companies will use to determine an estimated pay ratio, our estimated pay ratio should not be used as a basis for comparison with ratios disclosed by other companies. All Other Compensation. The following table sets forth information concerning all other compensation paid to our NEOs in 2020. Medical Insurance Premium ($) 18,071 18,071 6,224 6,700 18,071 Individual Tax Preparation ($) 12,000 1,250 — — — Health Savings Account (HSA) Employer Contributions ($) 401(k) Plan Employer Contributions ($) Membership Dues ($) Severance Paid in 2020 ($) 600 600 — — 185 14,250 14,250 4,038 — 14,250 7,750 — — — — — — — 144,000 900,000 Total ($)(1) 52,671 34,171 10,262 150,700 932,506 Name Heath Deneke Marc D. Stratton James Johnston Leonard W. Mallett Louise E. Matthews (1) allocated between the General Partner and SMLP. As a result of the GP Buy-In Transaction, the Partnership now pays for 100% of the NEO’s compensation. For a discussion of the cost allocation methodology, please refer to “Agreements with Affiliates—Reimbursement of Expenses from General Partner” in Item 13. Certain Relationships and Related Transactions, and Director Independence. Amounts shown represent the portion of the NEO’s base salary and bonus allocated to the Partnership. Prior to closing the GP Buy-In Transaction in May 2020, compensation amounts for the NEO were Grants of Plan-Based Awards in 2020. The following table sets forth information concerning annual incentive awards and phantom unit awards granted to the Partnership’s NEOs in fiscal year 2020. Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) Target ($) 900,000 Maximum ($) 1,800,000 Threshold ($) — Grant Date 3/23/2020 All Other Stock Awards: Number of Shares of Stocks or Units (2) Grant Date Fair Value of Stock and Option Awards (3) Cash Awards (4) (#) 108,882 ($) 891,743 ($) 758,257 3/23/2020 — 350,000 700,000 25,406 208,073 369,427 9/11/2020 — 350,000 700,000 33,333 355,000 800,000 Name Heath Deneke Marc D. Stratton James Johnston Leonard W. Mallett 3/23/2020 — 400,000 800,000 29,038 237,798 422,202 Louise E. Matthews (5) — 300,000 600,000 — — — (1) (2) Represents annual incentive opportunities that may be awarded pursuant to the Partnership’s annual incentive program for the year ended December 31, 2020 with payment based upon the Partnership’s achievement of pre-established performance goals and other factors. For additional information, please see "Components of Executive Compensation— Annual Incentive Compensation" above. Represents grants of phantom units with distribution equivalent rights under the SMLP LTIP. For additional information, please see "Components of Executive Compensation— Long-Term Equity-Based Compensation Awards" above. 152 Table of Contents (3) Amounts shown represent the fair value of the award on the date of the grant, in accordance with FASB ASC Topic 718. For the assumptions made in valuing these awards, see Note 13 to the consolidated financial statements. (4) Amount shown represent the dollar-denominated cash amount of the LTIP grant award. (5) Ms. Matthews’ employment terminated on April 1, 2020. Ms. Mathews received no grants of phantom unit awards in 2020. Narrative Disclosure to the Summary Compensation Table and Grants of the Plan-Based Awards Table. A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, non-equity incentive plan compensation and all other compensation can be found in the CD&A that precedes these tables. Outstanding Equity Awards at December 31, 2020. The following table presents information regarding the outstanding equity awards held by the Partnership’s NEOs at December 31, 2020. Name (1) Heath Deneke Marc D. Stratton (5) James Johnston (6) Unit Awards Cash Awards Number of Unearned Phantom Units That Have Not Vested (#) (2) Market Value of Unearned Phantom Units That Have Not Vested ($) (3) Unearned Cash Awards That Have Not Vested (4) ($) 108,882 34,320 25,406 3,333 2,613 328 33,333 1,359,935 428,657 317,321 41,629 32,636 4,097 416,333 758,257 — 369,427 — — — 800,000 Grant Date 3/23/2020 9/16/2019 3/23/2020 11/15/2019 3/15/2019 3/15/2018 9/11/2020 (1) Ms. Mathews is omitted from this table because her outstanding equity awards vested upon her termination effective April 1, 2020. Mr. Mallet is omitted from this table because his outstanding equity awards vested upon his termination effective October 31, 2020. (2) (3) (4) (5) (6) Except in the case of Mr. Johnston, as noted below, phantom units granted to the NEOs vest ratably over a three-year period with the first tranche scheduled to vest on the first anniversary of the grant date, subject to continued employment, and accelerated vesting as provided in the applicable award agreement. The NEOs also receive distribution equivalent rights for each phantom unit, if applicable, providing for a lump sum payment equal to any accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. Amounts were calculated using the closing price of SMLP's publicly traded common units on December 31, 2020. Amounts shown represent the dollar-denominated cash amount of the SMLP LTIP grant award. Phantom units granted on November 15, 2019, vest in their entirety on the third anniversary of the grant date. One half of the phantom units and cash awards granted on September 11, 2020 vest on March 31, 2021 and the other half vests on March 31, 2022 Phantom Units and Cash Awards Vested. The following table represents information regarding the vesting of phantom units during the year ended December 31, 2020 with respect to the Partnership’s NEOs. Name Heath Deneke (1) Marc D. Stratton (2) James Johnston Leonard W. Mallett (3) Louise E. Matthews (4) Phantom Unit Cash Award Number of Phantom Units Vested (#) (1) Value Realized on Vesting ($) (1) Vesting ($) 17,160 1,842 — 39,312 7,566 184,041 37,020 — 439,618 87,258 — — — 422,202 — (1) Mr. Deneke’s amounts represent the number and value of the phantom units that vested on September 16, 2020, plus the distribution equivalent rights earned in tandem. The value of the phantom units that vested was calculated using the closing price of SMLP’s publicly traded common units as of September 15, 2020, the trading day immediately prior to vesting. (2) Mr. Stratton amounts represent the number and value of the phantom units that vested on March 16, 2020, plus the distribution equivalent rights earned in tandem. The value of the phantom units that vested was calculated using the closing price of SMLP’s publicly traded common units as of March 13, 2020, the trading day prior to vesting. (3) Mr. Mallett’s amounts represent the number and value of the phantom units that vested on March 16, 2020 plus the distribution equivalent rights earned in tandem. The value of the phantom units that vested on March 16, 2020 was calculated using the closing price of SMLP’s publicly traded common units as of March 13, 2020, the trading day prior to vesting. In addition, the amount includes amounts for the phantom units and cash awards 153 Table of Contents that vested upon his termination effective October 31, 2020, plus the distribution equivalent rights earned in tandem. The value of Mr. Mallett’s phantom units that vested on October 31, 2020 was calculated using the closing price of SMLP’s units as of October 30, 2020, the trading day immediately prior to vesting. (4) Ms. Mathews' amounts represent the number and value of the phantom units that vested on March 16, 2020 and upon her termination effective April 1, 2020, plus the distribution equivalent rights earned in tandem. The value of the phantom units that vested on March 16, 2020 was calculated using the closing price of SMLP's publicly traded common units as of March 13, 2020, the trading day prior to vesting. The value of Ms. Matthews' phantom units that vested on April 1, 2020 was calculated using the closing price of SMLP’s units as of March 31, 2020, the trading day immediately prior to vesting. Pension Benefits. Currently, the Partnership does not sponsor or maintain a pension or defined benefit program for its NEOs. This policy may change in the future. Nonqualified Deferred Compensation Table for 2020. Effective May 28, 2020, the Deferred Compensation was terminated resulting in payment of all remaining amounts deferred thereunder to participants or their designated beneficiaries, as applicable, in a single lump sum payment. Potential Payments upon Termination or Change in Control. The following table sets forth information concerning potential amounts payable to the NEOs upon termination of employment under various circumstances, and upon a change in control, if such event took place on December 31, 2020. 154 Table of Contents Name and Principal Position Heath Deneke President and Chief Executive Officer (3) Marc D. Stratton Executive Vice President and Chief Financial Officer (5) James Johnston Executive Vice President, General Counsel and Chief Compliance Officer (5) Triggering Event Salary ($) Bonus ($) (1) Pro-Rata Bonus ($) Health Benefits ($) Acceleration of Unvested Equity ($) (2) Total ($) Termination by Reason of Death or Disability Termination Without Cause Resignation for Good Reason Nonextension of Term by Partnership Nonextension of Term by Executive, Partnership Exercises Noncompete Change in Control (4) Termination by Reason of Death or Disability Termination Without Cause Resignation for Good Reason Nonextension of Term by Partnership Change in Control (4) Nonextension of Term by Executive, Partnership Exercises Noncompete Termination by Reason of Death or Disability Termination Without Cause Resignation for Good Reason Nonextension of Term by Partnership Change in Control (4) Nonextension of Term by Executive, Partnership Exercises Noncompete — — 900,000 1,500,000 1,500,000 2,250,000 2,250,000 900,000 900,000 1,500,000 2,250,000 900,000 1,500,000 2,250,000 — — — — 525,000 525,000 525,000 525,000 — — 350,000 350,000 350,000 525,000 525,000 350,000 — 350,000 — 350,000 — — — — 116,667 525,000 525,000 525,000 525,000 116,667 116,667 525,000 525,000 116,667 — 350,000 — 525,000 — — 19,341 19,341 19,341 19,341 19,341 2,546,849 3,466,190 2,546,849 2,546,849 7,216,190 7,216,190 2,546,849 7,216,190 — 3,769,341 — 2,546,849 2,546,849 19,341 19,341 19,341 19,341 — 19,341 19,941 19,941 19,941 19,941 — 19,941 765,110 1,134,451 765,110 765,110 2,184,451 2,184,451 765,110 2,184,451 765,110 — 765,110 719,341 1,216,333 1,352,941 1,216,333 1,216,333 2,402,941 2,402,941 1,216,333 2,402,941 1,216,333 — 1,216,333 894,941 Leonard W. Mallett Former Executive Vice President and Chief Operations Officer (5) (6) Termination Without Cause 600,000 996,000 400,000 15,285 710,625 2,721,910 Louise E. Matthews Former Executive Vice President and Chief Administration Officer (5) (6) Termination Without Cause 450,000 815,000 74,795 19,341 54,156 1,413,292 (1) Where applicable, the amount includes the “Retention Bonus” payable to Mr. Mallett and Ms. Matthews upon a termination without cause or change in control. For more information see “Employment and Severance Arrangements; Retention Bonus Agreements” above. (2) Amounts represent the value of the phantom units that vest upon the occurrence of a triggering event plus the earned distribution equivalent rights that vest in tandem. The value of the phantom units was calculated using the closing price of SMLP's publicly traded common units on December 31, 2020. (3) Mr. Deneke’s employment agreement provides that upon termination of employment resulting from a non-extension of the term, termination without cause, or by Mr. Deneke’s resignation for good reason (each a "Qualifying Termination"), Mr. Deneke’s severance payment will be equal to two and one-half times the sum of his annual base salary and the higher of his target annual bonus payable in respect of the immediately preceding year and the annual bonus actually paid to him in respect of that year. Mr. Deneke is also entitled to receive a prorated annual bonus (based on target) if his employment is terminated by reason of death or disability or as a result of a Qualifying Termination. If the Partnership exercises the “noncompete option” after Mr. Deneke elects not to extend the term, then Mr. Deneke is entitled to a severance payment in an amount equal to the two and one-half times the sum of his annual base salary and the higher of the target annual bonus payable or the bonus actually paid in respect of the preceding year, multiplied by a fraction, the numerator of which is equal to the number of days from the date of termination through the expiration of the restricted period (as elected by the Partnership) and the denominator of which is 365. Any unvested equity awards granted to Mr. Deneke will immediately vest upon a Qualifying Termination, termination by reason of death or disability, or a change in control. If any portion of the payments or benefits provided to Mr. Deneke in connection with a change in control become subject to the excise tax under Section 4999 of the Internal Revenue Code, then the payments and benefits will be reduced to the extent such reduction would result in a greater after-tax benefit to Mr. Deneke. Following any termination 155 Table of Contents of employment, the Partnership has agreed to pay the out-of-pocket premium cost to continue Mr. Deneke’s medical and dental coverage for a period not to exceed 18 months, with such coverage terminating if any new employer provides benefits coverage. (4) Single-trigger event without a qualifying termination of employment. (5) Mr. Stratton’s, Mr. Johnston’s, Mr. Mallett’s, and Ms. Matthews’ employment agreements are substantially identical to Mr. Deneke’s with respect to potential payments upon termination or a change in control, except that (i) in the event of a Qualifying Termination, each of these NEOs is entitled to receive a severance payment equal to one and one-half times the sum of his or her annual base salary and his or her annual bonus payable in respect of the immediately preceding year; and (ii) in the event the Partnership exercises the “noncompete option” after any such NEO elects not to extend the term, then the NEO is entitled to a severance payment equal to the sum of his or her annual base salary and the bonus actually paid in respect of the preceding year, multiplied by a fraction, the numerator of which is equal to the number of days from the date of termination through the expiration of the restricted period (as elected by the Partnership) and the denominator of which is 365. (6) Both Mr. Mallett and Ms. Matthews were terminated without cause in 2020. Accordingly, disclosure is limited to the triggering event that occurred. The amounts reflect actual amounts. Compensation Committee Report The Compensation Committee provides oversight, administers and makes decisions regarding the Partnership’s compensation policies and plans. Additionally, the Compensation Committee generally reviews and discusses the Compensation Discussion and Analysis with senior management of the Partnership as a part of the Partnership’s governance practices. Based on this review and discussion, the Compensation Committee has recommended to the Board of Directors of the General Partner that the Compensation Discussion and Analysis be included in this report for filing with the SEC. Robert M. Wohleber (Chair) Members of the Compensation Committee of Summit Midstream GP, LLC James J. Cleary James Lee Jacobe Director Compensation In 2020, under the director compensation plan, the independent directors, which include Messrs. Peters, Wohleber, Jacobe, McNally, Cleary and Ms. Woung-Chapman each received the following: • • • an annual cash retainer of $80,000; and an annual award of common units with a grant date fair value of approximately $100,000. In addition, under the director compensation plan, the independent directors receive the following for their respective service on the committees of our Board of Directors: o o o o o the chairman of the Audit Committee receives an additional annual retainer of $15,000; each independent member of the Audit Committee received an additional annual retainer of $7,000; the chairman of the Conflicts Committee, which was dissolved in May 2020, received an additional annual retainer of $15,000; the chairman of the Corporate Governance and Nominating Committee received an additional annual retainer of $10,000; the chairman of the Compensation Committee receives an additional annual retainer of $12,000; and each independent member of any committee (other than the chairman) receives an additional annual retainer of $5,000. Messrs. Peters, Jacobe and Wohleber were paid their compensation in March 2020, whereas Messrs. McNally, Cleary and Ms. Woung-Chapman were paid upon the commencement of their service on the Board in June 2020. In addition to their regular compensation described above, the independent directors received the following additional fees for the increased time and effort they expended as chairperson and members, respectively, of the Conflicts Committee, in connection with the review of the GP Buy-In transaction for fairness to the Partnership and its unitholders: • $25,000 to Mr. Wohleber and $20,000 to Mr. Peters and Mr. Jacobe for their work related to the GP Buy-In Transaction. Board members are reconsidered for appointment on the one-year anniversary of their most recent appointment. 156 Table of Contents The Partnership reimburses all directors for travel and other related expenses in connection with attending board and committee meetings and board-related activities. The following table shows the compensation paid, including amounts deferred, under the Partnership’s director compensation plan in 2020. Name Heath Deneke Robert M. Wohleber Jerry L. Peters Lee Jacobe Robert J. McNally Marguerite Woung-Chapman James J. Cleary Fees earned or paid in cash ($) — 152,000 125,000 117,000 87,000 90,000 90,000 Other fees ($) — — — — — — — Unit awards ($) (1) — 100,000 100,000 100,000 100,000 100,000 100,000 Compensation deferred ($) (2) — — — — — — — Total ($) — 252,000 225,000 217,000 187,000 190,000 190,000 (1) (2) Amount shown represents the grant date fair value of the unit awards as determined in accordance with GAAP. These unit awards were fully vested on the grant date. In 2020, no director elected to defer any portion of his compensation related to Board committee service. Compensation Committee Interlocks and Insider Participation The Partnership’s Compensation Committee consists of Mr. Jacobe, Mr. Cleary and Mr. Wohleber. Although the Partnership’s common units are listed on the NYSE, the Partnership has taken advantage of the “Limited Partnership” exemption to the NYSE rule that would otherwise require listed companies to have an independent compensation committee with a written charter. During 2020, no member of the Compensation Committee was an executive officer of another entity on whose compensation committee or board of directors any executive officer of the Partnership served. During 2019, no director was an executive officer of another entity on whose compensation committee any executive officer of Summit Investments (and in connection therewith, SMLP) served. The Partnership’s CEO participated in his capacity as a director in the deliberations of the Board of Directors concerning named executive officer compensation and made recommendations to the Compensation Committee regarding named executive officer compensation but abstained from any decisions regarding his compensation. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. The following table sets forth certain information regarding the beneficial ownership of the Partnership’s common units of: • • • • each person who is known to us to beneficially own 5% or more of such units to be outstanding (based solely on Schedules 13D and 13G filed with the SEC prior to February 17, 2021); the General Partner; each of the directors and NEOs of the General Partner; and all of the directors and executive officers of the General Partner as a group. All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be. The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a beneficial owner of a security if that person has or shares voting power, which includes the power to vote or to direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units that a person has the right to acquire upon the vesting of phantom units where the units are issuable within 60 days of February 17, 2021, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. The percentage of units beneficially owned is based on a total of 6,110,092 common limited partner units outstanding as of February 17, 2021. All common unit amounts reflect the Reverse Unit Split. 157 Table of Contents Except as indicated by footnote, the persons named in the following table have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. Name of Beneficial Owner Ares Management LLC(1) Invesco Ltd. (2) J. Heath Deneke (3) (4) James Johnston (3) (4) Leonard W. Mallett (3) (5) Louise Matthews (3) (5) Marc D. Stratton (3) (4) Robert J. McNally(3) Marguerite Woung-Chapman (3) James J. Cleary (3) Jerry L. Peters (3) Robert M. Wohleber (3) James Lee Jacobe (3) All directors and executive officers as a group (consisting of 11 persons) * An asterisk indicates that the person or entity owns less than one percent. Common Units Beneficially Owned Percentage of Common Units Beneficially Owned 312,143 914,071 53,454 16,666 29,035 3,361 7,695 4,166 4,166 4,166 14,197 14,030 12,848 163,784 5.1% 15.0% * * * * * * * * * * * * (1) Ares Management LLC (“Ares”) controls, directly or indirectly, each Ares Lender of Record, as defined in the Form 13G filed by Ares Management LLC on November 27, 2020. The number of common units beneficially owned by Ares represents the collective number of common units beneficially owned by each Ares Lender of Record, as set forth in the Form 13G filed by Ares. The address for this entity is 2000 Avenue of the Stars, 12th Floor, Los Angeles, CA 90067. (2) The address for this entity is 1555 Peachtree Street NE, Suite 1800, Atlanta, GA 30309. (3) The address for this person is 910 Louisiana Street, Suite 4200, Houston, TX 77002. (4) Includes common units which the individuals have the right to acquire upon vesting of phantom units, where the units are issuable as of February 17, 2021 or within 60 days thereafter. Such units are deemed to be outstanding in calculating the percentage ownership of such individual (and all directors and officers as a group) but are not deemed to be outstanding as to any other person. (5) This individual’s employment was terminated in 2020, and the common units beneficially owned by this individual are based on the last Form 4 filed by or on behalf of such individual. Securities Authorized for Issuance Under Equity Compensation Plans The following table provides information as of December 31, 2020 with respect to the Partnership's common units that may be issued under the SMLP LTIP, as amended. Plan category Equity compensation plans approved by security holders Equity compensation plans not approved by security holders Total 158 Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) (1) Weighted-average exercise price of outstanding options, warrants and rights (b) 291,691 n/a 291,691 n/a n/a — Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) 440,030 n/a 440,030 Table of Contents (1) Amount shown represents phantom unit awards outstanding under the SMLP LTIP at December 31, 2020. The awards are expected to be settled in common units upon the applicable vesting date and are not subject to an exercise price. 2012 SMLP Long-Term Incentive Plan. In connection with the IPO, the Partnership’s General Partner approved the SMLP LTIP, as amended and restated on March 19, 2020, pursuant to which eligible officers, employees, consultants and directors of the Partnership’s General Partner and its affiliates are eligible to receive awards with respect to the Partnership’s equity interests. The SMLP LTIP is designed to promote the Partnership’s interests, as well as the interests of the Partnership’s unitholders, by rewarding eligible officers, employees, consultants and directors for delivering desired performance results, as well as by strengthening the Partnership’s ability to attract, retain and motivate qualified individuals to serve as directors, consultants and employees. A total of 15,000,000 common units was reserved for issuance, pursuant to and in accordance with the SMLP LTIP. Following the Reverse Unit Split, a total of 1,000,000 common units were reserved for issuance under the SMLP LTIP. The SMLP LTIP is administered by Compensation Committee of the General Partner’s the Board of Directors. The SMLP LTIP provides for the grant, from time to time at the discretion of the Board of Directors, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Units that are canceled or forfeited are available for delivery pursuant to other awards. Common units to be delivered with respect to awards may be newly issued units, common units acquired by the Partnership or the Partnership’s General Partner in the open market, common units already owned by the Partnership or the Partnership’s General Partner, common units acquired by the Partnership’s General Partner directly from the Partnership or any other person or any combination of the foregoing. The General Partner's Board of Directors, at its discretion, may terminate the SMLP LTIP at any time with respect to the common units for which a grant has not previously been made. The SMLP LTIP will automatically terminate on the 10th anniversary of the amendment effective date, presently set at March 19, 2030. The General Partner's Board of Directors also has the right to alter or amend the SMLP LTIP or any part of it from time to time or to amend any outstanding award made under the SMLP LTIP, provided that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant. Item 13. Certain Relationships and Related Transactions, and Director Independence. In May 2020, the Partnership completed the GP Buy-In Transaction, whereby the Partnership acquired from its then private equity sponsor, ECP, (i) Summit Investments, which owned the Partnership’s General Partner, (ii) through its indirect ownership of SMP Holdings, 3,415,646 of its common units and (iii) the Deferred Purchase Price obligation receivable owed by the Partnership. Consideration paid to ECP included a $35.0 million cash payment and the issuance of warrants to purchase up to 666,667 common units. In connection with the closing of the GP Buy-In Transaction, ECP’s management resigned from the Board of Directors and ECP fully exited its investment in the Partnership (other than retaining the aforementioned warrants). As a result of the GP Buy-In Transaction, the Partnership indirectly owns its General Partner, and the General Partner’s Board of Directors is comprised of a majority of independent directors. The Partnership Agreement provides the Partnership’s common unitholders with voting rights in the election of the members of the Board of Directions on a staggered basis beginning in 2022. Distributions and Payments to the Partnership’s General Partner and its Affiliates. The following summarizes the distributions and payments made by us to the General Partner and its affiliates in connection with the Partnership’s ongoing operations and its liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations. • • Operational Stage: See "Agreements with Affiliates—Reimbursement of Expenses from General Partner" below. Liquidation Stage: Upon the Partnership’s liquidation, the Partnership’s partners, including the General Partner, will be entitled to receive liquidating distributions according to their particular capital account balances. Agreements with Affiliates. The Partnership has various agreements with certain of its affiliates, as described below. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm's-length negotiations. • Reimbursement of Expenses from General Partner: Prior to the GP Buy-In Transaction, under the then effective Partnership Agreement, SMLP reimbursed its General Partner and its affiliates for certain expenses incurred on SMLP’s behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to SMLP’s General 159 Table of Contents Partner's employees and executive officers who perform services necessary to run SMLP. The then effective Partnership Agreement provided that SMLP’s General Partner will determine in good faith the expenses that are allocable to us. Operation and maintenance expenses incurred by the General Partner and reimbursed by SMLP under then then effective Partnership Agreement were $28.6 million in 2019 and $9.0 million for the period from January 1, 2020 to May 28, 2020. General and administrative expenses incurred by the General Partner and reimbursed by SMLP under the then effective Partnership Agreement were $32.2 million in 2019 and $11.9 million for the period from January 1, 2020 to May 28, 2020. As a result of the GP Buy-In Transaction, the Partnership indirectly owns its General Partner and is no longer required to reimburses an affiliate for its expenses. • Expense Allocations: Prior to the completion of the GP Buy-In Transaction in May 2020, certain of Summit Investments’ current and former employees received Class B membership interests, classified as net profits interests, in Summit Investments (the “Net Profits Interests”). The Net Profits Interests participated in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested Net Profits Interests. The Net Profits Interests were accounted for as compensatory awards. Concurrent with closing the GP Buy-In Transaction, the Net Profits Interests were settled and are no longer outstanding. Review, Approval and Ratification of Related-Person Transactions. The Board of Directors has a policy for the identification, review and approval of certain related person transactions. The policy provides for the review and (as appropriate) approval by the Conflicts Committee of transactions between SMLP and its subsidiaries, on the one hand, and related persons (as that term is defined in SEC rules), on the other hand. Pursuant to the policy, the General Counsel of SMLP's General Partner is charged with primary responsibility for determining whether, based on the facts and circumstances, a proposed transaction is a related person transaction. For purposes of the policy, a "related person" is any director or executive officer of SMLP's General Partner, any nominee for director, any unitholder known to SMLP to be the beneficial owner of more than 5% of any class of the SMLP's common units, and any immediate family member, affiliate or controlled subsidiary of any such person. A "related person transaction" is generally a transaction in which SMLP is, or SMLP's General Partner or any of SMLP's subsidiaries is, a participant, where the amount involved exceeds the lesser of (i) $120,000 or (ii) 1% of the average of our total assets at year-end for the last two completed fiscal years, and a related person has a direct or indirect material interest. Transactions resolved under the conflicts provision of the Partnership Agreement are not required to be reviewed or approved under the policy. If, after weighing all of the facts and circumstances, the general counsel of SMLP's General Partner determines that a proposed transaction is a related person transaction that requires review or approval and the transaction meets certain monetary thresholds or involves certain related persons, management must present the proposed transaction to the Conflicts Committee for advance approval. If the transaction does not meet the designated monetary threshold or involve certain related persons, management presents the transaction(s) to the Committee for their review on a quarterly basis. The policy described above was adopted by the Board of Directors on March 7, 2013, and as a result, certain of the transactions described in "Agreements with Affiliates" above were not reviewed under such policy. Director Independence. Each of the current members of the Audit, Compensation and Corporate Governance & Nominating Committees have been determined to be independent under the applicable NYSE listing standards and rules of the SEC and the Corporate Governance Guidelines. 160 Table of Contents Item 14. Principal Accounting Fees and Services. The Partnership’s Audit Committee has ratified Deloitte & Touche LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of SMLP for the year ended December 31, 2020. Audit Fees. The fees billed by Deloitte & Touche LLP, as principal accountant, for the audit of the Partnership’s consolidated financial statements and other services rendered for the years ended December 31, 2020 and 2019 follow. Audit fees(1) Audit-related fees(2) Tax fees(3) All other fees Total Year ended December 31, 2020 2019 $ $ 1,522,293 100,000 588,156 — 2,210,449 $ $ 1,654,404 20,000 469,276 — 2,143,680 (1) Audit fees are fees billed by Deloitte & Touche LLP for professional services for the audit and quarterly reviews of the Partnership’s consolidated financial statements, review of other SEC filings, including registration statements, and issuance of comfort letters and consents. (2) Represents fees related to the Partnership’s At-the-market Program. (3) Tax fees are billed by Deloitte Tax LLP for tax compliance services, including the preparation of state, federal and Schedule K-1 tax filings and other tax planning and advisory services. Pre-approval Policy. Pursuant to its charter, the Audit Committee is responsible for the appointment, compensation, retention and oversight of SMLP's independent auditor (including resolution of disagreements between management and the independent auditor regarding financial reporting). The Audit Committee shall have sole authority to pre-approve all audit, audit-related and permitted non-audit engagements with the independent auditor, including the fees and other terms of such engagements. The independent auditor shall report directly to the Audit Committee. The Audit Committee may consult with management but may not delegate these responsibilities to management. 161 Table of Contents PART IV Item 15. Exhibits, Financial Statement Schedules. (a)(1) Financial Statements Our Consolidated Financial Statements and accompanying footnotes are included in Part II, Item 8, of this report. (2) Financial Statement Schedules All schedules are omitted because the required information is inapplicable or the information is presented in the financial statements or the notes thereto. (3) Exhibit Index The exhibits listed on the accompanying Exhibit Index are filed as part of, or incorporated by reference into, this Annual Report. Exhibit number 2.1 3.1 3.2 3.3 3.4 4.1 4.2 10.1 10.2 10.3 Description Purchase Agreement, dated May 3, 2020, by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-C (SMLP IP), LP, Energy Capital Partners II-C (Summit IP), LP, Energy Capital Partners II (Summit Co-Invest), LP and Summit Midstream Management, LLC, as contributors, SMP TopCo, LLC and SMLP Holdings, LLC, as sellers, Summit Midstream Partners, LP, as the acquiror, and, solely for certain purposes set forth therein, Summit Midstream Partners GP, LLC (Incorporated herein by reference to Exhibit 2.1 to SMLP's Current Report on Form 8-K dated May 5, 2020 (Commission File No. 001-35666)) Fourth Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated May 28, 2020 (Incorporated herein by reference to Exhibit 3.1 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666)) Second Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated May 28, 2020 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K filed June 2, 2020 (Commission File No. 001- 35666)) Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466)) Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466)) *** Description of Common Units Investor Rights Agreement, dated as of October 3, 2012, by and among EFS-S, LLC, Summit Midstream GP, LLC and Summit Midstream Partners, LLC (Incorporated herein by reference to Exhibit 4.1 to SMLP's Current Report on Form 8-K dated October 4, 2012 (Commission File No. 001-35666)) Strict Foreclosure Agreement, dated November 17, 2020, by and among Summit Midstream Partners Holdings, LLC, Summit Midstream Partners, LLC and Credit Suisse AG, Cayman Islands Branch (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated November 17, 2020 (Commission File No. 001-35666)) General Assignment and Bill of Sale, dated November 17, 2020, by Summit Midstream Partners Holdings, LLC and Summit Midstream Partners, LLC (Incorporated herein by reference to Exhibit 10.2 to SMLP’s Current Report on Form 8-K dated November 17, 2020 (Commission File No. 001-35666)) Mutual Release Agreement, dated November 17, 2020, by and among Summit Midstream Partners Holdings, LLC, Summit Midstream Partners, LLC, the lenders party thereto, and Credit Suisse AG, Cayman Islands Branch (Incorporated herein by reference to Exhibit 10.3 to SMLP’s Current Report on Form 8-K dated November 17, 2020 (Commission File No. 001-35666)). 162 Table of Contents 10.4 10.5 10.6 10.7 10.8 10.9 Term Loan Credit Agreement, dated May 28, 2020, by and among Summit Midstream Holdings, LLC, as borrower, SMP TopCo, LLC, as lender and administrative agent and Mizuho Bank (USA), as collateral agent (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666)) Term Loan Credit Agreement, dated May 28, 2020, by and among Summit Midstream Holdings, LLC, as borrower, SMLP Holdings, LLC, as lender, SMP TopCo, LLC, as administrative agent and Mizuho Bank (USA), as collateral agent (Incorporated herein by reference to Exhibit 10.2 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666)) Guarantee and Collateral Agreement, dated May 28, 2020, by and among Summit Midstream Holdings, LLC, Summit Midstream Partners, LP, the subsidiaries listed therein and Mizuho Bank (USA), as collateral agent, relating to the ECP NewCo Term Loan Credit Agreement (Incorporated herein by reference to Exhibit 10.3 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666)) Guarantee and Collateral Agreement, dated May 28, 2020, by and among Summit Midstream Holdings, LLC, Summit Midstream Partners, LP, the subsidiaries listed therein and Mizuho Bank (USA), as collateral agent, relating to the ECP Holdings Term Loan Credit Agreement (Incorporated herein by reference to Exhibit 10.4 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666)) Pari Passu Intercreditor Agreement, dated as of May 28, 2020, among Wells Fargo Bank, National Association, as Revolving Credit Facility Collateral Agent, Mizuho Bank (USA), as NewCo Term Loan Collateral Agent and SMLP Holdings Term Loan Collateral Agent, Summit Midstream Holdings, LLC and other grantors from time to time party thereto (Incorporated herein by reference to Exhibit 10.5 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666)) Warrant to Purchase Common Units, dated May 28, 2020, from Summit Midstream Partners, LP to SMP TopCo, LLC (Incorporated herein by reference to Exhibit 10.6 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666)) 10.10 Warrant to Purchase Common Units, dated May 28, 2020, from Summit Midstream Partners, LP to SMLP Holdings, LLC (Incorporated herein by reference to Exhibit 10.7 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666)) 10.11 10.12 10.13 10.14 10.15 10.16 10.17 Operation and Management Services Agreement, dated May 28, 2020, by and among Summit Midstream Partners, LP and Summit Operating Services Company, LLC (Incorporated herein by reference to Exhibit 10.8 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666)) Term Loan Agreement, dated as of March 21, 2017, among Summit Midstream Partners Holdings, LLC, as borrower, the lenders party thereto and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent and Collateral Agent (Incorporated herein by reference to Exhibit 10.9 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666)) Guarantee and Collateral Agreement, dated as of March 21, 2017, by and among Summit Midstream Partners Holdings, LLC, as grantor, Summit Midstream Partners, LLC, as pledgor and grantor and Credit Suisse AG, Cayman Islands Branch, as collateral agent (Incorporated herein by reference to Exhibit 10.10 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666)) Amendment to Warrants to Purchase Common Units, dated August 7, 2020, by and among Summit Midstream Partners, LP, SMP TopCo, LLC and SMLP Holdings, LLC (Incorporated herein by reference to Exhibit 10.11 to SMLP’s Quarterly Report on Form 10-Q for the period ended September 30, 2020 (Commission File No. 001-35666)) Transaction Support Agreement, dated September 29, 2020, by and among Summit Midstream Partners Holdings, LLC, Summit Midstream Partners, LLC, Summit Midstream Partners, LP and the Initial Directing Lenders listed therein (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated September 30, 2020 (Commission File No. 001-34666)) Purchase Agreement, dated as of June 12, 2013, by and among Summit Midstream Holdings, LLC, Summit Midstream Finance Corp., Summit Midstream GP, LLC, the Guarantors named therein and the Initial Purchasers named therein (Incorporated herein by reference to Exhibit 1.1 to SMLP's Current Report on Form 8-K dated June 17, 2013 (Commission File No. 001-35666)) Purchase and Sale Agreement between Meadowlark Midstream Company, LLC, Tioga Midstream, LLC and Hess North Dakota Pipelines LLC dated as of February 22, 2019 (Incorporated herein by reference to Exhibit 10.1 to SMLP's Current Report on Form 8-K dated February 26, 2019 (Commission File No. 001-35666)) 163 Table of Contents 10.18 10.19 Purchase and Sale Agreement between Meadowlark Midstream Company, LLC, Tioga Midstream, LLC and Hess Infrastructure Partners LP dated as of February 22, 2019 (Incorporated herein by reference to Exhibit 10.2 to SMLP's Current Report on Form 8-K dated February 26, 2019 (Commission File No. 001-35666)) Indenture, dated as of June 17, 2013, by and among Summit Midstream Holdings, LLC, Summit Midstream Finance Corp., the Guarantors party thereto and U.S. Bank National Association (including form of the 7½% senior notes due 2021) (Incorporated herein by reference to Exhibit 4.1 to SMLP's Current Report on Form 8-K dated June 17, 2013 (Commission File No. 001-35666)) 10.20 Registration Rights Agreement, dated as of June 17, 2013, by and among Summit Midstream Holdings, LLC, Summit Midstream Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (Incorporated herein by reference to Exhibit 4.2 to SMLP's Current Report on Form 8-K dated June 17, 2013 (Commission File No. 001-35666)) 10.21 Joinder Agreement, dated as of June 4, 2013, by and among Summit Midstream Holdings, LLC, The Royal Bank of Scotland plc, as Administrative Agent, and the lenders party thereto (Incorporated herein by reference to Exhibit 10.2 to SMLP's Current Report on Form 8-K dated June 5, 2013 (Commission File No. 001-35666)) 10.22 Third Amended and Restated Credit Agreement dated as of May 26, 2017 (Incorporated herein by reference to Exhibit 10.1 to SMLP's Current Report on Form 8-K dated May 30, 2017 (Commission File No. 001-35666)) 10.23 First Amendment to the Third Amended and Restated Credit Agreement dated as of September 22, 2017 (Incorporated herein by reference to Exhibit 10.7 to SMLP’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017 (Commission File No. 001-35666)) 10.24 Second Amendment to Third Amended and Restated Credit Agreement dated as of June 26, 2019 (Incorporated herein by reference to Exhibit 10.2 to SMLP's Quarterly Report on Form 10-Q dated August 9, 2019 (Commission File No. 001-35666)) 10.25 Third Amendment to Third Amended and Restated Credit Agreement and Second Amendment to Second Amended and Restated Guarantee and Collateral Agreement dated as of December 24, 2019 (Incorporated by reference to Exhibit 10.11 to SMLP’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019 (Commission File No. 001-35666)) 10.26 Fourth Amendment to Third Amended and Restated Credit Agreement and Third Amendment to Second Amended and Restated Guarantee and Collateral Agreement, dated as of December 18, 2020, by and among Summit Midstream Holdings, LLC, each of the other Loan Parties party thereto, Wells Fargo Bank, National Association, as administrative and collateral agent and the Lenders party thereto (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current.Report on Form 8-K dated December 18, 2020 (Commission File No. 01-35666)) 10.27 Amended and Restated Limited Liability Company Agreement of Summit Permian Transmission Holdco, LLC, dated as of December 24, 2019 (Incorporated by reference to Exhibit 10.12 to SMLP’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019 (Commission File No. 001-35666)) 10.28 Amended and Restated Guarantee and Collateral Agreement dated as of November 1, 2013 (Incorporated herein by reference to Exhibit 10.7 to SMLP's 2013 Annual Report on Form 10-K for the fiscal year ended December 31, 2013 (Commission File No. 001- 35666)) 10.29 Base Indenture, dated as of July 15, 2014, by and among Summit Midstream Holdings, LLC, Summit Midstream Finance Corp. and U.S. Bank National Association (Incorporated herein by reference to Exhibit 4.1 to SMLP's Current Report on Form 8-K dated July 9, 2014 (Commission File No. 001-35666)) 10.30 First Supplemental Indenture, dated as of July 15, 2014, by and among Summit Midstream Holdings, LLC, Summit Midstream Finance Corp., the Guarantors party thereto and U.S. Bank National Association (including form of the 5½% senior notes due 2022) (Incorporated herein by reference to Exhibit 4.2 to SMLP's Current Report on Form 8-K dated July 9, 2014 (Commission File No. 001- 35666)) 10.31 10.32 Second Supplemental Indenture, dated as of February 15, 2017, by and among Summit Midstream Holdings, LLC, Summit Midstream Finance Corp., the Guarantors party thereto and U.S. Bank National Association (including form of the 5.75% senior notes due 2025) (Incorporated herein by reference to Exhibit 4.2 to SMLP’s Current Report on Form 8-K dated February 17, 2017 (Commission File No. 001-35666)) Equity Distribution Agreement, dated June 12, 2015, among the Partnership, the General Partner, the Operating Company, Citigroup Global Markets Inc., Deutsche Bank Securities Inc. and RBC Capital Markets, LLC. (Incorporated herein by reference to Exhibit 1.1 to SMLP's Current Report on Form 8-K dated June 12, 2015 (Commission File No. 001-35666)) 164 Table of Contents 10.33 10.34 10.35 10.36 10.37 10.38 10.39 Contribution Agreement between Summit Midstream Partners Holdings, LLC and Summit Midstream Partners, LP dated as of February 25, 2016 (Incorporated herein by reference to Exhibit 10.1 to SMLP's Form 8-K filed March 1, 2016 (Commission File No. 001-35666)) Amendment to Contribution Agreement between Summit Midstream Partners Holdings, LLC and Summit Midstream Partners, LP dated February 25, 2019 (Incorporated herein by reference to Exhibit 10.3 to SMLP's Current Report on Form 8-K dated February 26, 2019 (Commission File No. 001-35666)) Amendment No. 2 to Contribution Agreement between Summit Midstream Partners Holdings, LLC and Summit Midstream Partners, LP dated November 7, 2019 (Incorporated herein by reference to Exhibit 10.1 to SMLP's Current Report on Form 8-K dated November 8, 2019 (Commission File No. 001-35666)) Amendment No. 3 to Contribution Agreement, dated November 17, 2020, by and between Summit Midstream Partners Holdings, LLC and Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 10.4 to SMLP’s Current Report on Form 8-K dated November 17, 2020 (Commission File No. 001-35666)) Equity Restructuring Agreement by and among Summit Midstream Partners, LP, Summit Midstream GP, LLC and Summit Midstream Partners Holdings, LLC dated as of February 25, 2019 (Incorporated herein by reference to Exhibit 10.4 to SMLP's Current Report on Form 8-K dated February 26, 2019 (Commission File No. 001-35666)) * Amendment No. 1 to Employment Agreement, dated December 1, 2015, effective August 4, 2017, by and between Summit Midstream Partners, LLC and Leonard Mallett (Incorporated herein by reference to Exhibit 10.2 to SMLP's Current Report on Form 8-K dated August 8, 2017 (Commission File No. 001-35666)) * Second Amended and Restated Employment Agreement, effective March 1, 2017, by and between Summit Midstream Partners, LLC and Brad N. Graves (Incorporated herein by reference to Exhibit 10.24 to SMLP’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (Commission File No. 001-35666)) 10.40 * Separation and General Release Agreement, effective as of August 7, 2020, by and between Summit Midstream Partners, LP and Brock Degeyter (Incorporated herein by reference to Exhibit 10.3 to SMLP’s Form 10-Q dated November 6, 2020 (Commission File No. 001-35666)) 10.41 *** Amended and Restated Employment Agreement, effective September 1, 2020, by and between Summit Midstream Partners, LLC and Marc D. Stratton 10.42 * Employment Agreement effective March 1, 2019, by and between Summit Midstream Partners, LLC and Louise E. Matthews (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated February 6, 2019 (Commission File Number 001-35666)) 10.43 * Form of Retention Bonus Agreement (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated June 11, 2019 (Commission File Number 001-35666)) 10.44 * Employment Agreement effective September 16, 2019, by and between Summit Midstream Partners, LLC and Heath Deneke (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated August 9, 2019 (Commission File Number 001-35666)) 10.45 * Employment Agreement, effective as of September 4, 2020, by and between Summit Midstream Partners, LP and James Johnston (Incorporated herein by reference to Exhibit 10.4 to SMLP’s Form 10-Q dated November 6, 2020 (Commission File No. 001-35666)) 10.46 * Summit Midstream Partners, LP 2012 Long-Term Incentive Plan, as amended and restated (incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated March 20, 2020 (Commission File No. 001-35666)) 10.47 * Award Agreement by and between Summit Midstream GP, LLC, Summit Midstream Partners, LP and Leonard Mallett (Incorporated herein by reference to Exhibit 10.2 to SMLP's Current Report on Form 8-K filed November 17, 2015 (Commission File No. 001- 35666)) 10.48 * Summit Midstream Partners, LP 2012 Long-Term Incentive Plan Phantom Unit Agreement (Incorporated herein by reference to Exhibit 10.1 to SMLP's Current Report on Form 8-K filed March 17, 2014 (Commission File No. 001-35666)) 10.49 * Form of Director Unit Award Agreement (Incorporated herein by reference to Exhibit 10.3 to SMLP's Current Report on Form 8-K filed October 4, 2012 (Commission File No. 001-35666)) 10.50 * Summit Midstream Partners, LLC Deferred Compensation Plan effective as of July 1, 2013 (Incorporated herein by reference to Exhibit 4.3 to SMLP's Form S-8 Registration Statement dated June 28, 2013 (Commission File No. 333-189684)) 165 Table of Contents 21.1 List of Subsidiaries (Incorporated herein by reference to Exhibit 21.1 to SMLP’s Form 8-K filed August 10, 2020 (Commission File No. 001-35666)) 22.1 Summit Midstream Partners, LP Subsidiary Issuers and Guarantors of Registered Securities (Incorporated herein by reference to Exhibit 22.1 to SMLP's Report on Form 10-Q filed May 8, 2020 (Commission File No. 001-35666)). 23.1 23.2 31.1 31.2 32.1 *** Consent of Deloitte & Touche LLP - Summit Midstream Partners, LP *** Consent of PricewaterhouseCoopers LLP - Ohio Gathering Company, L.L.C. *** Rule 13a-14(a)/15d-14(a) Certification, executed by Heath Deneke, President, Chief Executive Officer and Director *** Rule 13a-14(a)/15d-14(a) Certification, executed by Marc D. Stratton, Executive Vice President and Chief Financial Officer *** Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Heath Deneke, President, Chief Executive Officer and Director, and Marc D. Stratton, Executive Vice President and Chief Financial Officer 99.1 *** Ohio Gathering Company, L.L.C. Financial Statements as of December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017 101.INS ** XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document 101.SCH ** Inline XBRL Taxonomy Extension Schema 101.CAL ** Inline XBRL Taxonomy Extension Calculation Linkbase 101.DEF ** Inline XBRL Taxonomy Extension Definition Linkbase 101.LAB ** Inline XBRL Taxonomy Extension Label Linkbase 101.PRE ** Inline XBRL Taxonomy Extension Presentation Linkbase 104 Cover Page Interactive Data File (embedded within the Inline XBRL document). * Management contract or compensatory plan or arrangement required to be filed as an exhibit pursuant to Item 15(b) of this report † Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the SEC. ** Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections. The financial information contained in the XBRL (eXtensible Business Reporting Language)-related documents is unaudited and unreviewed. *** Filed herewith (c) Financial Statement Schedules Not applicable. Item 16. Form 10-K Summary. Not applicable. 166 Table of Contents Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. SIGNATURES Summit Midstream Partners, LP (Registrant) By: Summit Midstream GP, LLC (its General Partner) March 4, 2021 /s/ MARC D. STRATTON Marc D. Stratton, Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature Title /s/ J. HEATH DENEKE J. Heath Deneke /s/ MARC D. STRATTON Marc D. Stratton /s/ JAMES J. CLEARY James J. Cleary /s/ LEE JACOBE Lee Jacobe /s/ ROBERT J. MCNALLY Robert J. McNally /s/ JERRY L. PETERS Jerry L. Peters Director, President and Chief Executive Officer (Principal Executive Officer) Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) Director Director Director Director /s/ ROBERT M. WOHLEBER Director Robert M. Wohleber /s/ MARGUERITE WOUNG-CHAPMAN Director Marguerite Woung-Chapman 167 Date March 4, 2021 March 4, 2021 March 4, 2021 March 4, 2021 March 4, 2021 March 4, 2021 March 4, 2021 March 4, 2021 EXHIBIT 4.1 Description of Our Common Units The following description of the common units representing limited partner interests (“common units”) in Summit Midstream Partners, LP, a Delaware limited partnership (the “partnership” or, as the context requires, “we,” “us” or “our”), is a summary and is subject to, and qualified in its entirety by, reference to the provisions of our Third Amended and Restated Agreement of Limited Partnership, dated as of March 22, 2019 (referred to herein as our “partnership agreement”), which has been filed as Exhibit 3.1 to our Annual Report on Form 10-K for the year ended December 31, 2019, of which this Exhibit 4.1 is a part. General The common units represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. Our outstanding common units are listed on the New York Stock Exchange (the “NYSE”) under the symbol “SMLP,” and any additional common units we issue will also be listed on the NYSE. Series A Preferred Units On November 14, 2017, we issued 300,000 Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in us (the “Series A preferred units”) at a price to the public of $1,000 per unit. The Series A preferred units currently rank senior to our common units with respect to distribution rights and rights upon liquidation. The following description of the Series A preferred units is included because various terms of the Series A preferred units could impact our common units. Please also read “—Voting Rights—Voting Rights of Series A Preferred Units.” The Series A preferred units represent perpetual equity interests in us, and they have no stated maturity or mandatory redemption date. Holders of the Series A preferred units generally have no voting rights, except for limited voting rights in certain circumstances. The holders of our Series A preferred units are entitled to receive, when, as and if declared by our general partner out of legally available funds for such purpose, cumulative and compounding semi-annual distributions or quarterly cash distributions, as applicable. Distributions on the Series A preferred units are cumulative and compounding from November 14, 2017, the date of original issue, and are payable semi-annually in arrears on the 15th days of June and December of each year to, but not including, December 15, 2022 and, thereafter, quarterly in arrears on the 15th days of March, June, September and December of each year. The initial distribution rate for the Series A preferred units from and including November 14, 2017 to, but not including, December 15, 2022 is 9.50% per year of the liquidation preference per unit (equal to $95 per unit per year). On and after December 15, 2022, distributions on the Series A preferred units will accumulate for each distribution period at a percentage of the liquidation preference equal to the three-month LIBOR, or, if no such rate is so published, a substitute or successor rate determined by the calculation agent, plus a spread of 7.43%. The Series A preferred units have a liquidation preference of $1,000 per unit. Upon the occurrence of certain rating agency events, we may redeem the Series A preferred units, in whole but not in part, at a price of $1,020 (102% of the liquidation preference) per Series A preferred unit plus an amount equal to all accumulated and unpaid distributions thereon to, but not including, the date fixed for redemption, whether or not declared. In addition, at any time on or after December 15, 2022, we may, at our option, redeem the Series A preferred units, in whole or in part, at a redemption price of (i) $1,040 for the year 2022, $1,020 for the year 2023 or $1000 for the years 2024 and thereafter (104%, 102% and 100% of the liquidation preference, respectively), per Series A preferred unit plus an amount equal to all accumulated and unpaid distributions thereon to, but not including, the date of redemption, whether or not declared (assuming such Series A preferred units are redeemed during the 12-month period beginning on the years indicated). If certain change of control triggering events occur, each holder of the Series A preferred units may require us to repurchase all or a portion of such holders Series A preferred units at a purchase price equal to $1,010 per Series A preferred unit (101% of the liquidation preference) plus an amount equal to all accumulated and unpaid distributions thereon to, but not including, the date of settlement. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness. Distributions of Available Cash Our Cash Distribution Policy. Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to common unitholders of record on the applicable record date. Please read “—Definition of Available Cash” below. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax. We pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about seven days prior to such distribution date. We make the distribution on the business day immediately preceding the indicated distribution date if the distribution date falls on a holiday or non-business day. Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy. There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay any distribution on our common units except to the extent we have available cash as defined in our partnership agreement and discussed in further detail below. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following: Our cash distribution policy is subject to restrictions under our Third Amended and Restated Credit Agreement dated as of May 26, 2017, as amended by the First Amendment to Third Amended and Restated Credit Agreement dated as of September 22, 2017 and by the Second Amendment to Third Amended and Restated Credit Agreement dated as of June 26, 2019 (the “Revolving Credit Facility”) and our Material Senior Indebtedness (as defined below). Our Revolving Credit Facility and Material Senior Indebtedness contain financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions notwithstanding our stated cash distribution policy. In any quarter, the Series A preferred units and any Parity Securities (as defined below) must receive the distribution to which they are entitled for that quarter, plus any accrued and unpaid distributions from prior quarters, and the general partner must expect to have sufficient funds to pay the next distribution on the Series A preferred units and any Parity Securities, before any distributions can be paid on the common units. We cannot pay distributions on any junior securities, including any of the common units, prior to paying the distributions payable on the Series A preferred units. In addition, our Series A preferred units contain covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions on our common units notwithstanding our stated cash distribution policy. Our general partner has the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those cash reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders. Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to distribute all of our available cash, may be amended. We • • • • 2 can amend our partnership agreement with the consent of our general partner and the approval of a majority of the outstanding common units (including common units beneficially owned by Summit Midstream Partners, LLC). As of February 18, 2020, Summit Midstream Partners Holdings, LLC, which is the parent of our general partner, beneficially owned 45,318,866 and SMLP Holdings, LLC beneficially owned 5,915,827 common units. Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Under Delaware law, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly distribution rate to service or repay our debt or fund expansion capital expenditures. • • • • Definition of Available Cash. Our partnership agreement generally defines “available cash” for any quarter as: • the sum of: o o all of our and our subsidiaries’ cash and cash equivalents on hand at the end of that quarter; as determined by our general partner, all of our and our subsidiaries’ cash or cash equivalents on hand on the date of determination of available cash for that quarter resulting from working capital borrowings (as described below) made after the end of that quarter; less • the amount of cash reserves established by our general partner to: o o o o provide for the proper conduct of our business (including reserves for future capital expenditures and for future credit needs); comply with applicable law or any debt instrument or other agreement or obligation to which we or our subsidiaries are a party or to which our or our subsidiaries’ assets are subject; provide funds for distributions on the Series A preferred units; or provide funds for distributions to our common unitholders for any one or more of the next four quarters; provided, however, that if our general partner so determines, disbursements made by us or our subsidiaries or cash reserves established, increased or reduced after the end of such quarter but on or before the date of determination of available cash with respect to such quarter shall deemed to have been made, established, increased or reduced, for purposes of determining available cash within such quarter. 3 Working capital borrowings are generally borrowings incurred under a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to unitholders, and with the intent of the borrower to repay such borrowings within 12 months with funds other than from additional working capital borrowings. Method of Distributions. Subject to the distribution preferences of the Series A Preferred Units, we intend to distribute available cash to our common unitholders, pro rata. Our partnership agreement permits, but does not require, us to borrow to pay distributions. Accordingly, there is no guarantee that we will pay any distribution on the common units in any quarter. The Series A preferred units receive the distribution preference described below under “—Series A Preferred Units.” Common Units. As of January 2, 2020, we had 93,493,473 common units outstanding. Subject to the distribution preferences of the Series A preferred units, each common unit is entitled to receive cash distributions to the extent we distribute available cash. Common units do not accrue arrearages. Subject to the voting rights of the Series A preferred units, our partnership agreement allows us to issue an unlimited number of additional equity interests of equal or senior rank. Please read “The Partnership Agreement—Issuances of Additional Partnership Interests” and “The Partnership Agreement—Voting Rights.” Series A Preferred Units. As of January 2, 2020, we had 300,000 Series A preferred units outstanding. Until the redemption of the Series A preferred units, holders of the Series A preferred units are entitled to receive cumulative compounding distributions semi-annually, until December 15, 2022 and quarterly thereafter. We cannot pay any distributions on any junior securities, including any of the common units, prior to paying the distribution payable to the Series A preferred units. Please read “Description of Our Preferred Units—Series A Preferred Units.” Voting Rights The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that require the approval of a “unit majority” require the approval of a majority of the outstanding common units. In voting their common units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or our unitholders, including any duty to act in the best interests of us or our unitholders, other than the implied contractual covenant of good faith and fair dealing. Issuance of additional units 4 No approval right by common unitholders; certain issuances require approval by 66 2/3% of the holders of our Series A preferred units. Please read “— Voting Rights of Series A Preferred Units.” Amendment of our partnership agreement Certain amendments may be made by our general partner without the approval of the unitholders, and certain other amendments that would materially adversely affect any of the preferences, rights, powers, duties or obligations of the Series A preferred units require the approval of holders of 66 2/3% of the Series A preferred units. Other amendments generally require the approval of a unit majority. Please read “— Amendment of Our Partnership Agreement” and “—Voting Rights of Series A Preferred Units.” Merger of our partnership or the sale of all or substantially all of our assets Unit majority in certain circumstances, and if such merger or sale would materially adversely affect any of the rights, preference and privileges of the Series A Preferred Units, the affirmative vote of 66 2/3% of the Series A preferred units. Please read “—Merger, Sale or Other Disposition of Assets.” Dissolution of our partnership Unit majority. Please read “—Termination and Dissolution.” Continuation of our business upon dissolution Unit majority. Please read “—Termination and Dissolution.” Withdrawal of our general partner Removal of our general partner Transfer of our general partner interest Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to December 31, 2022 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.” Not less than 66 2/3% of the outstanding common units, voting as a single class, including units held by our general partner and its affiliates. Please read “—Withdrawal or Removal of Our General Partner.” Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2022. Please read “—Transfer of General Partner Interest.” Transfer of ownership interests in our general partner No approval required at any time. Please read “—Transfer of Ownership Interests in Our General Partner.” Voting Rights of Series A Preferred Units. The affirmative vote of 66 2/3% of the outstanding Series A preferred units, voting as a separate class, is required for us to amend our partnership in a way that would have a material adverse effect on the existing preferences, rights, powers, duties or obligations of the Series A preferred units. 5 The affirmative vote of 66 2/3% of the outstanding Series A preferred units, voting as a class together with holders of any other Parity Securities established after the Series A preferred units and upon which like voting rights have been conferred and are exercisable, is required for us to: • • • • • create or issue any Parity Securities if the cumulative distributions payable on then outstanding Series A preferred units are in arrears; create or issue any Parity Securities in excess of the Parity Basket (as defined below) if the cumulative distributions payable on then outstanding Series A preferred units are not in arrears; create or issue any Senior Securities (as defined below); declare of pay any distributions to our common unitholders out of capital surplus (as defined in our partnership agreement); or take any action that would result, without regard to any notice requirement or applicable cure period, in an Event of Default (as defined in our Material Senior Indebtedness, as defined below) for failure to comply with any covenant in the Material Senior Indebtedness related to: o o o o o o o o o restricted payments, incurrence of indebtedness and issuance of preferred stock, incurrence of liens, dividends and other payments affecting subsidiaries, merger, consolidation or sale of assets, transactions with affiliates, designation of restricted and unrestricted subsidiaries, additional subsidiary guarantors, or sale and leaseback transactions. “Material Senior Indebtedness” means (a) the indebtedness issued under that certain First Supplemental Indenture, dated as of July 15, 2014, by and among us, Summit Midstream Finance Corp., the guarantors party thereto and U.S. Bank National Association, (b) the indebtedness issued under that certain Second Supplemental Indenture, dated as of February 15, 2017, by and among us, Summit Midstream Finance Corp., the guarantors party thereto and U.S. Bank National Association and (c) any future indebtedness of us or Summit Midstream Finance Corp. in an amount greater than $200,000,000 issued under a note indenture (and not under any loan or other credit agreement with commercial banking institutions). “Parity Basket” means: (1) if there is at least $100 million of outstanding Series A preferred units, the greater of (a) an aggregate $150 million of non- convertible Parity Securities and (b) so long as the market capitalization of our common units is at least $1.5 billion, an aggregate amount of Series A preferred units or other non-convertible Parity Securities such that, at the time of issuance, the aggregate amount of outstanding Series A preferred units and other Parity Securities does not exceed 15% of the value of all outstanding common units; or 6 (2) if there is less than $100 million of outstanding Series A preferred units, an amount of Parity Securities as our general partner may determine. “Parity Securities” means any class or series of partnership interests or other equity securities established after the original issue date of the Series A preferred units that is not expressly made senior or subordinated to the Series A preferred units as to the payment of distributions and amounts payable on a liquidation event. “Senior Securities” means any class or series of partnership interests or other equity securities established after the original issue date of the Series A preferred units that is expressly made senior to the Series A preferred units as to the payment of distributions and amounts payable on a liquidation event. Distributions of Cash Upon Liquidation If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation; provided, that any accumulated and unpaid distributions and the applicable liquidation preference on our Series A preferred units shall be distributed with respect to our Series A preferred units (up to the positive balance in the associated capital accounts), prior to any distributions with respect to our common units or other junior securities. Limited Liability Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right of, or exercise of the right by, the limited partners as a group: • • • to remove or replace our general partner; to approve some amendments to our partnership agreement; or to take other action under our partnership agreement; constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for such a claim in Delaware case law. Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited is included in the assets of the limited partnership only to the extent that the fair value of that property exceeds that liability. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a 7 substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to it at the time it became a limited partner and that could not be ascertained from the partnership agreement. Our subsidiaries conduct business in nine states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of our primary operating subsidiary, Summit Holdings, which we refer to as our “operating company,” may require compliance with legal requirements in the jurisdictions in which the operating company conducts business, including qualifying our subsidiaries to do business there. Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners. Issuance of Additional Partnership Interests Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of our limited partners, other than current holders of Series A preferred units in certain circumstances. Please read “—Voting Rights—Voting Rights of Series A Preferred Units.” It is possible that we will fund acquisitions through the issuance of additional common units, preferred units, warrants, rights or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units, preferred units, warrants, rights or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets. In accordance with Delaware law and the provisions of our partnership agreement, subject to the voting rights of the Series A preferred units, we may also issue additional partnership interests (such as preferred units, warrants or rights) that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, subject to the voting rights of the Series A preferred units, our partnership agreement does not prohibit our subsidiaries from issuing equity securities, which may effectively rank senior to the common units. Our general partner has the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units, that existed immediately prior to each issuance. The holders of our units do not have preemptive rights under our partnership agreement to acquire additional units or other partnership interests. Amendment of Our Partnership Agreement General. Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner has no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or our unitholders, including any duty to act in the best interests of our partnership or our 8 unitholders, other than the implied contractual covenants of good faith and fair dealing. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority. In addition, any amendment that materially adversely affects any of the preferences, rights, powers, duties or obligations of the Series A preferred units requires the approval of holders of 66 2/3% of the Series A preferred units, voting as a separate class. Prohibited Amendments. No amendment may be made that would: • • enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion. The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). As of December 31, 2019, our general partner and its affiliates beneficially owned approximately 54.8% of the outstanding common units. No Unitholder Approval. Subject to the voting rights of the Series A preferred units, our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect: a change in our name, the location of our principal place of business, our registered agent or our registered office; the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement; a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we, our operating company nor its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes; a change in our fiscal year or taxable year and related changes; an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor; an amendment that our general partner determines to be necessary or appropriate in connection with the authorization or issuance of additional partnership interests or rights to acquire partnership interests; any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone; • • • • • • • 9 • • • • an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement; any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, as otherwise permitted by our partnership agreement; mergers with, conveyances to or conversions into another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger, conveyance or conversion other than those it receives by way of the merger, conveyance or conversion; or any other amendments substantially similar to any of the matters described above. In addition, subject to the voting rights of the Series A preferred units, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments: • • • • • do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests; are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute; are necessary or appropriate to facilitate the trading of units or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the units are or will be listed for trading; are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or are required to effect the intent expressed in a prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement. The affirmative vote of 66 2/3% of the Series A preferred units, voting separately as a class, is necessary on any manner (including a merger, consolidation or business combination) that would materially adversely affect any of the existing preferences, rights, powers, duties or obligations of the Series A preferred units. Opinion of Counsel and Limited Partner Approval. Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described above under “—No Unitholder Approval.” No other amendments to our partnership agreement will become effective without the approval of holders of at least 90.0% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners. In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced. Any amendment that would increase the percentage of units required to remove our general partner must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than 90.0% of outstanding units. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the affirmative vote of unitholders whose aggregate outstanding units constitute at least a majority of the outstanding units. 10 Merger, Sale or Other Disposition of Assets A merger or consolidation of us requires the prior consent of our general partner. However, our general partner has no duty or obligation to consent to any merger or consolidation and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of our partnership or our unitholders, other than the implied contractual covenant of good faith and fair dealing. In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our and our subsidiaries’ assets in a single transaction or a series of related transactions, including by way of merger, consolidation, other combination or sale of ownership interests of our subsidiaries. Further, the affirmative vote of 66 2/3% of the Series A preferred units, voting separately as a class, is necessary on any matter (including a merger, consolidation or business combination) that would materially adversely affect any of the existing preferences, rights, powers, duties or obligations of the Series A preferred units. Please read “—Voting Rights—Voting Rights of Series A Preferred Units.” Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our and our subsidiaries’ assets without that approval. Our general partner may also sell all or substantially all of our and our subsidiaries’ assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of the limited partners), each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued do not exceed 20.0% of our outstanding partnership interests immediately prior to the transaction. If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed limited liability entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event. Transfer of Common Units By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee: • • • automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; represents and warrants that the transferee has the right, power, authority and capacity to enter into our partnership agreement; and gives the consents, waivers and approvals contained in our partnership agreement. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly. We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder. 11 Common units are securities and any transfers are subject to the laws governing the transfer of securities. Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations. Termination and Dissolution We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon: • • • • the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor; the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority; the entry of a decree of judicial dissolution of our partnership; or there being no limited partners, unless we are continued without dissolution in accordance with the Delaware Act. Upon a dissolution under the first clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement and appoint as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that: • • the action would not result in the loss of limited liability of any limited partner; and neither we nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed). Liquidation and Distribution of Proceeds Upon our dissolution, unless we are continued as a limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “— Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time if it determines that an immediate sale or distribution would be impractical or would cause undue loss to our partners. The liquidator may distribute our assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the partners. Withdrawal or Removal of Our General Partner Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2022 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2022, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving at least 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50.0% of the outstanding units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or 12 otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Interest.” Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “—Termination and Dissolution.” Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of all outstanding common units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units. The ownership of more than 33 1/3% of the outstanding common units by our general partner and its affiliates gives them the ability to prevent our general partner’s removal. Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist or withdrawal of our general partner where that withdrawal does not violate our partnership agreement our general partner will have the right to convert its general partner interest into common units or receive cash in exchange for those interests based on the fair market value of those interests as of the effective date of its removal. In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner for its fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value. If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph. In addition, we will be required to reimburse the departing general partner for all amounts due to it, including, without limitation, all employee- related liabilities, including severance liabilities, incurred in connection with the termination of any employees employed by the departing general partner or its affiliates for our benefit. Transfer of General Partner Interest Except for transfer by our general partner of all, but not less than all, of its general partner interest to: • • an affiliate of our general partner (other than an individual); or another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to such entity, our general partner may not transfer all or any of its general partner interest to another person prior to December 31, 2022 without the approval of the holders of at least a majority of the outstanding common units, excluding common 13 units held by our general partner and its affiliates. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters. Our general partner and its affiliates may, at any time, transfer common units to one or more persons, without unitholder approval. Transfer of Ownership Interests in Our General Partner At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or a third party without the approval of our unitholders. Change of Management Provisions Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change our management. Please read “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20.0% or more of any class of units, including our Series A preferred units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units directly from our general partner or its affiliates or any transferee of that person or group that is approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner, or to any holder of Series A preferred units in connection with any vote, consent or approval of the holders of Series A preferred units. Limited Call Right If at any time our general partner and its affiliates own more than 80.0% of the then-issued and outstanding limited partner interests of any class (other than the Series A preferred units), our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10, but not more than 60, days’ notice. The purchase price in the event of this purchase is the greater of: • • the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and the average of the daily closing prices of the partnership interests of such class for the 20 consecutive trading days immediately preceding the date three days before the date the notice is mailed. As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Redemption of Ineligible Holders In order to avoid any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that may be subject to rate regulation by the Federal Energy Regulatory Commission or an analogous regulatory body in the future, each transferee of partnership interests, upon becoming the record holder of such partnership interests, will automatically certify, and the general partner at any time can request such holder to re-certify: • that the transferee or unitholder is an individual or an entity subject to United States federal income taxation on the income generated by us; or 14 • that, if the transferee unitholder is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity’s owners are subject to United States federal income taxation on the income generated by us. Furthermore, in order to avoid a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest as the result of any federal, state or local law or regulation concerning the nationality, citizenship or other related status of any unitholder, our general partner may at any time request unitholders to certify as to, or provide other information with respect to, their nationality, citizenship or other related status. The certifications as to taxpayer status and nationality, citizenship or other related status can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose. If a unitholder fails to furnish the certification or other requested information with 30 days or if our general partner determines, with the advice of counsel, upon review of such certification or other information that a unitholder does not meet the status set forth in the certification, we will have the right to redeem all of the units held by such unitholder at the average of the daily closing prices per limited partner interest of such class for the 20 consecutive trading days immediately prior to the date fixed for redemption. The purchase price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5.0% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date. Further, the units will not be entitled to any allocations of income or loss, distributions or voting rights while held by such unitholder. Transfer Agent and Registrar Duties. American Stock Transfer and Trust Company (“AST”) serves as the transfer agent, cash distribution paying agent and registrar for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders: • • • surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges in connection therewith; special charges for services requested by a common unitholder; and other similar fees or charges. There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify AST, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity. Resignation or Removal. The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent, cash distribution paying agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed. 15 Amended and Restated Employment Agreement This Amended and Restated Employment Agreement (the “Agreement”), effective September 1, 2020 (the “Effective Date”), is made by and between M arc Stratton (the “Executive”) and Summit Operating Services Company, LLC (together with any of its subsidiaries and affiliates as may employ the Executive from time to time, and any successor(s) thereto, the “C ompany”). EXHIBIT 10.41 RECITALS 1. The Company and the Executive are parties to an employment agreement, dated January 1, 2019 (the “Original Employment Agreement”). 2. The Company and the Executive desire to amend and restate the Original Employment Agreement in the form hereof. 3. The Company desires to assure itself of the services of the Executive by engaging the Executive to perform services under the terms hereof. 4. The Executive desires to provide services to the Company on the terms herein provided. NOW, THEREFORE, in consideration of the foregoing and of the respective covenants and agreements set forth AGREEMENT below the parties hereto agree as follows: 1. C ertain Definitions. (a) (b) (c) (d) (e) (f) (g) “AAA” shall have the meaning set forth in Section 18. “Affiliate” shall mean, with respect to any Person, any other Person directly or indirectly controlling, controlled by, or under common control with, such Person where “control” shall have the meaning given such term under Rule 405 of the Securities Act of 1933, as amended from time to time. “Agreement” shall have the meaning set forth in the preamble hereto. “Annual Base Salary” shall have the meaning set forth in Section 3(a). “Annual Bonus” shall have the meaning set forth in Section 3(b). “Annual LTIP Target” means the annual grant-date LTIP target award value, which value may vary in the Board’s discretion based on Executive’s or the Company’s performance prior to each annual LTIP grant. “Board” shall mean the Board of Managers of the General Partner, or any successor governing body of the Partnership. (h) (i) (j) (k) The Company shall have “Cause” to terminate the Executive’s employment hereunder upon: (i) the Executive’s willful failure to substantially perform the duties set forth herein (other than any such failure resulting from the Executive’s Disability); (ii) the Executive’s willful failure to carry out, or comply with, in any material respect any lawful directive of the Board; (iii) the Executive’s commission at any time of any act or omission that results in, or may reasonably be expected to result in, a conviction, plea of no contest, plea of nolo contendere, or imposition of unadjudicated probation for any felony or crime involving moral turpitude; (iv) the Executive’s unlawful use (including being under the influence) or possession of illegal drugs on the Company’s premises or while performing the Executive’s duties and responsibilities hereunder; (v) the Executive’s commission at any time of any act of fraud, embezzlement, misappropriation, material misconduct, conversion of assets of the Company, or breach of fiduciary duty against the Company (or any predecessor thereto or successor thereof); or (vi) the Executive’s material breach of this Agreement, or other agreements with the Company (including, without limitation, any breach of the restrictive covenants of any such agreement). “Change in Control” shall mean: (i) any “person” or “group” within the meaning of Sections 13(d) and 14(d)(2) of the Exchange Act shall become the beneficial owners, by way of merger, acquisition, consolidation, recapitalization, reorganization or otherwise, of fifty percent (50%) or more of the combined voting power of the equity interests in the General Partner or the Partnership; (ii) the limited partners of the Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership, (iii) the sale or other disposition by the General Partner or the Partnership of all or substantially all of the Partnership’s assets in one or more transactions to any Person other than the Company, the General Partner, or the Partnership; or (iv) a transaction resulting in a Person other than the Company, the General Partner, or any of their respective Affiliates (as determined immediately prior to the consummation of any such transaction) being the sole general partner of the Partnership. Notwithstanding any of the foregoing, or anything to the contrary expressed or implied by any other provision of this Agreement, in no event shall a “Change in Control” result from a mutually agreed transaction or out-of-court settlement between the parties, or a voluntary or involuntary foreclosure, reorganization, bankruptcy or similar judicial proceeding, the result of which is that certain equity interests in the General Partner or the Partnership that are pledged to the lenders as collateral to secure Summit Midstream Partners Holdings, LLC’s obligations under the Term Loan (as defined below) are transferred to one or more of such lenders in full and final satisfaction of the term loan obligations. “Code” shall mean the Internal Revenue Code of 1986, as amended. “Company” shall, except as otherwise provided in Section 7(i), have the meaning set forth in the preamble hereto. 2 (l) (m) (n) (o) (p) (q) (r) (s) (t) (u) (v) “Compensation Committee” shall mean the Compensation Committee of the Board, or if no such committee exists, the Board. “Date of Termination” shall mean (i) if the Executive’s employment is terminated due to the Executive’s death, the date of the Executive’s death; (ii) if the Executive’s employment is terminated due to the Executive’s Disability, the date determined pursuant to Section 4(a)(ii); (iii) if the Executive’s employment is terminated pursuant to Section 4(a)(iii)-(vi) or Section 4(a)(ix), either the date indicated in the Notice of Termination or the date specified by the Company pursuant to Section 4(b), whichever is earlier; or (iv) if the Executive’s employment is terminated pursuant to Section 4(a)(vii)-(viii), the date immediately following the expiration of the then-current Term. “Disability” shall mean the Executive’s inability, with or without reasonable accommodation, to perform the essential functions of his position by reason of any medically determinable physical or mental impairment that can be expected to result in death or that can be expected to last for a continuous period of not less than twelve (12) months as determined by a physician jointly selected by the Company and the Executive. “Effective Date” shall have the meaning set forth in the preamble hereto. “Exchange Act” shall mean the Securities Exchange Act of 1934, as amended. “Excise Tax” shall have the meaning set forth in Section 6(b). “Executive” shall have the meaning set forth in the preamble hereto. “Extension Term” shall have the meaning set forth in Section 2(b). “First Payment Date” shall have the meaning set forth in Section 5(b)(ii). “General Partner” means Summit Midstream GP, LLC, a Delaware limited liability company. “Good Reason” will mean the occurrence of one or more of the following conditions: (i) a material diminution in the Executive’s authority, duties, or responsibilities, as described herein; (ii) a material diminution in the aggregated total of the Executive’s (A) Annual Base Salary, (B) target Annual Bonus (as a percentage of Annual Base Salary) and (C) Annual LTIP Target, in each case as described herein; provided, however that any diminution of the Annual LTIP Target in accordance with the proviso of the definition thereof shall be disregarded for purposes of this definition; (iii) a material change in the geographic location at which the Executive must perform the Executive’s services hereunder that requires the Executive to relocate his or her residence to a location more than fifty (50) miles from Houston, Texas; provided that the foregoing shall only constitute Good Reason under this Agreement if (1) as of the Effective Date, Executive’s residence is located within fifty (50) miles of Houston, Texas or (2) at 3 the request of the Company, Executive relocates his or her residence to within fifty (50) miles of Houston, Texas during the Term; (iv) and any other action or inaction that constitutes a material breach of this Agreement by the Company. For the avoidance of doubt, the following will not constitute "Good Reason": (x) the notification and placement of Executive on administrative leave with compensation and benefit continuation pending a potential determination by the Board that Executive may be terminated for Cause and (y) non-extension of the Term by the Executive. (w) (x) (y) “I nitial Term” shall have the meaning set forth in Section 2(b). “I nstallment Payments” shall have the meaning set forth in Section 5(b)(ii). “LTIP” shall mean the Summit Midstream Partners, LP 2012 Long-Term Incentive Plan adopted by the Partnership in connection with Registration Statement 333-184214, filed by the Partnership with the Securities and Exchange Commission on October 1, 2012, and any additional long-term incentive plan adopted in the future and identified by the Company or the Partnership, in the adopting resolution or otherwise, as an “LTIP” pursuant hereto. (z) “Notice of Termination” shall have the meaning set forth in Section 4(b). (aa) “Original Employment Agreement” shall have the meaning set forth in the recitals hereto. (bb) “Partnership” means Summit Midstream Partners LP, a Delaware limited partnership. (cc) “Performance Targets” shall have the meaning set forth in Section 3(b). (dd) “Person” shall mean any individual, natural person, corporation (including any non-profit corporation), general partnership, limited partnership, limited liability partnership, joint venture, estate, trust, company (including any company limited by shares, limited liability company or joint stock company), incorporated or unincorporated association, governmental authority, firm, society or other enterprise, organization or other entity of any nature. (ee) “Proprietary Information” shall have the meaning set forth in Section 7(c). (ff) “Prorated Termination Bonus” shall have the meaning set forth in Section 3(b) (gg) “Release” shall have the meaning set forth in Section 5(b)(ii). (hh) “Restricted Business” shall mean any business (i) relating to midstream assets (including, without limitation, the gathering, processing and transportation of natural gas and crude oil), which competes with the business of the Company, its parent, Affiliates, related entities, or any of their direct or indirect subsidiaries, or (ii) which the Company, its parent, Affiliates, related entities, or any of their 4 direct or indirect subsidiaries have taken active steps to engage in or acquire, but only if the Executive directly or indirectly engaged in, had any equity interest in, or managed or operated, such business or activity (whether as director, officer, employee, agent, representative, partner, security holder, consultant or otherwise) at any time during the twelve (12)-month period immediately prior to the Date of Termination. (ii) “Restricted Period” shall mean the period from the Date of Termination through the first (1st) anniversary of the Date of Termination. (jj) “Restricted Territory” shall mean (i) those counties set forth on Exhibit A to this Agreement, (ii) those counties in which the Company, its parent, Affiliates, related entities, or any of their direct or indirect subsidiaries engaged in operations or owned or operated assets at any time during the twelve (12)-month period immediately prior to the Date of Termination, and (iii) those counties in which the Company, its parent, Affiliates, related entities, or any of their direct or indirect subsidiaries took active steps to engage in operations or acquire or operate assets, but only if the Executive directly or indirectly engaged in, had any equity interest in, or managed or operated, such business or activity (whether as director, officer, employee, agent, representative, partner, security holder, consultant or otherwise) at any time during the twelve (12)- month period immediately prior to the Date of Termination. (kk) “Section 409A” shall mean Section 409A of the Code and the Department of Treasury regulations and other interpretive guidance issued thereunder, including without limitation any such regulations or other guidance that may be issued after the Effective Date. (ll) “Severance Payment” shall have the meaning set forth in Section 5(b)(i). (mm) “Severance Period” shall mean the period beginning on the Date of Termination and ending on the first (1st) anniversary of the Date of Termination, unless earlier terminated pursuant to the last sentence of Section 7(a). (nn) “Term” shall have the meaning set forth in Section 2(b) (oo) “Term Loan” shall mean the Term Loan Agreement dated as of March 21, 2017 by and between Summit Midstream Partners Holdings, LLC, as Borrower, the several Lenders party thereto, and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent and Collateral Agent (as amended). (pp) “Total Payments” shall have the meaning set forth in Section 6(b). 2. E mployment. (a) I n General. The Company shall employ the Executive and the Executive shall enter the employ of the Company, for the period set forth in Section 2(b), in the position set forth in Section 2(c), and upon the other terms and conditions herein provided. 5 (b) T erm of Employment. The initial term of employment under this Agreement (the “I nitial Term”) shall be for the period beginning on the Effective Date and ending on the second (2nd) anniversary of the Effective Date, unless earlier terminated as provided in Section 4. The Initial Term shall automatically be extended for successive one (1) year periods (each, an “Extension Term” and, collectively with the Initial Term, the “Term”), unless either party hereto gives notice of non-extension to the other no later than thirty (30) days prior to the expiration of the then- applicable Term. (c) P osition and Duties. During the Term, the Executive: (i) shall serve as Executive Vice President and Chief Financial Officer of the Company, with responsibilities, duties and authority customary for such position, subject to direction by the Board; (ii) shall report to the P resident and CEO; (iii) shall devote substantially all the Executive’s working time and efforts to the business and affairs of the Partnership and its subsidiaries, provided that the Executive may (1) serve on corporate, civic, charitable, industry or professional association boards or committees, subject to the Board’s prior written consent in the case of any such board or committee that relates directly or indirectly to the business of the Company or its subsidiaries (which consent shall not unreasonably be withheld), (2) deliver lectures, fulfill speaking engagements or teach at educational institutions and (3) manage his personal investments, so long as none of such activities meaningfully interferes with the performance of the Executive’s duties and responsibilities hereunder, or involves a conflict of interest with the Executive’s duties or responsibilities hereunder or a breach of the covenants contained in Section 7; and (iv) agrees to observe and comply with the Company’s rules and policies as adopted by the Company from time to time, which have been made available to the Executive. 3. C ompensation and Related Matters. (a) A nnual Base Salary. During the Term, the Executive shall receive a base salary at a rate of $ 350,000 per annum, which shall be paid in accordance with the customary payroll practices of the Company, subject to review and upward, but not downward without Executive’s written consent, adjustment by the Board in its sole discretion (the “Annual Base Salary”). (b) A nnual Bonus. With respect to each calendar year that ends during the Term, the Executive shall be eligible to receive an annual cash bonus (the “Annual Bonus”), prorated for the first calendar year of the Term, ranging from zero to t wo hundred percent (200%) of the Annual Base Salary, with a target Annual Bonus equal to o ne hundred percent (100%) of the Annual Base Salary, based upon annual performance targets (the “Performance Targets”) established by the Board in its sole discretion. The amount of the Annual Bonus shall be based upon attainment of the Performance Targets, as determined by the Board (or any authorized committee of the Board) in its sole discretion. Each such Annual Bonus shall be payable on such date as is determined by the Board, but in any event on or prior to March 15 of the calendar year immediately following the calendar year with respect to which such Annual Bonus relates. Notwithstanding the foregoing, no bonus shall be payable with respect to any calendar year unless the Executive remains continuously employed with the Company during the period beginning on the Effective Date and ending on December 31 of such year; provided that if the Executive’s employment is terminated pursuant to Section 4(a)(i), (ii), (iv), (v) or (vii), the Company shall pay to the Executive a prorated Annual Bonus with respect to the calendar year in which the Date of Termination occurs equal to the target Annual Bonus for such calendar year 6 multiplied by a fraction, the numerator of which is the number of calendar days during such calendar year that the Executive was continuously employed by the Company and the denominator of which is 365 (the “Prorated Termination Bonus”); provided further that, in the case of a termination pursuant to Section 4(a)(ii), (iv), (v) or (vii), no portion of the Prorated Termination Bonus shall be paid unless the Executive timely executes the Release and does not revoke the Release within the time periods set forth in Section 5(b)(ii). (c) L TIP Award. During the Term, the Executive shall be eligible to receive annual equity award grants pursuant to the LTIP, as determined by the Board or a committee thereof. For calendar year 2 020 and beyond, the Annual LTIP Target will be equal to 1 65% of the Annual Base Salary. Any awards issued to the Executive under the LTIP are governed by and subject to the terms of the LTIP and the underlying award agreements. (d) B enefits. The Executive shall be eligible to participate in benefit plans, programs and arrangements of the Company, as in effect from time to time (including, without limitation, medical and dental insurance and a 401(k) plan). (e) V acation; Holidays. During the Term, the Executive shall be entitled to paid time off (“PTO”) each full calendar year as provided by the Company’s PTO policies for similarly situated employees. The PTO shall be used for vacation and sick days. Any vacation shall be taken at the reasonable and mutual convenience of the Company and the Executive. Any PTO that the Executive is entitled to in any calendar year that is not used by the end of such calendar year shall be forfeited, except for up to five days of PTO each year that may be carried forward to the following year. Holidays shall be provided in accordance with Company policy, as in effect from time to time. (f) B usiness Expenses.During the Term, the Company shall reimburse the Executive for all reasonable travel and other business expenses incurred by the Executive in the performance of the Executive’s duties to the Company in accordance with the Company’s applicable expense reimbursement policies and procedures. In addition to the foregoing, the Company shall reimburse the Executive for annual tax preparation services and ongoing tax advice of up to $ 12,000 per year, beginning with such expenses incurred in 2020. In addition, the Company shall reimburse the Executive for an annual executive physical at a medical facility of the Executive’s choice. 4. T ermination. The Executive’s employment hereunder may be terminated by the Company or the Executive, as applicable, without any breach of this Agreement only under the following circumstances: (a) C ircumstances (i) D eath. The Executive’s employment hereunder shall terminate upon the Executive’s death. (ii) D isability. If the Executive incurs a Disability, the Company may give the Executive written notice of its intention to terminate the Executive’s employment. In that 7 event, the Executive’s employment with the Company shall terminate, effective on the later of the thirtieth (30th) day after receipt of such notice by the Executive or the date specified in such notice; provided that Executive’s Disability continues beyond such thirty (30) day notice period. (iii) T ermination for Cause.The Company may terminate the Executive’s employment for Cause. Executive’s termination will not be deemed to be for Cause unless the Company has provided a written Notice of Termination (defined in Section 4(b) below) to Executive specifying the event or condition claimed to constitute Cause and, in the case of a termination pursuant to Section 1(h)(i), (ii), or (vi), Executive has failed to cure Executive’s failure or breach within thirty (30) days following the Executive’s receipt of the Company’s Notice of Termination (to the extent that, in the reasonable judgment of the Board, such failure or breach can be cured by the Executive). (iv) T ermination without Cause. The Company may terminate the Executive’s employment without Cause. (v) R esignation for Good Reason.The Executive may resign from employment for Good Reason. Executive’s resignation will not be deemed to be for Good Reason if Executive has consented to the condition claimed to constitute Good Reason, nor will Executive’s resignation be deemed to be for Good Reason, unless Executive has provided a written Notice of Termination (defined in Section 4(b) below) to the Company specifying the event or condition claimed to constitute Good Reason within ninety (90) days following the initial existence of such event or condition, and the Company has, after receipt of such notice of Good Reason from Executive, failed to cure or correct such condition or event within thirty (30) days following the Company’s receipt of Executive’s Notice of Termination evidencing intent to resign for Good Reason. (vi) R esignation without Good Reason. The Executive may resign from the Executive’s employment without Good Reason. (vii) N on-Extension of Term by the Company. The Company may give notice of non-extension to the Executive pursuant to Section 2(b). For the avoidance of doubt, non-extension of the Term by the Company shall not constitute termination by the Company without Cause. (viii) N on-Extension of Term by the Executive. The Executive may give notice of non-extension to the Company pursuant to Section 2(b). (ix) R esignation following a Change in Control. The Executive may resign from the Executive’s employment within sixty (60) days following a Change in Control. (b) N otice of Termination. Any termination of the Executive’s employment by the Company or by the Executive under this Section 4 (other than a termination pursuant to Section 4(a)(i) above) shall be communicated by a written notice to the other party hereto: (i) indicating the specific termination provision in this Agreement relied upon, (ii) except with respect to a termination pursuant to Section 4(a)(iv), (vi), (vii), (viii), or (ix), setting forth in reasonable detail 8 the facts and circumstances claimed to provide a basis for termination of the Executive’s employment under the provision so indicated, and (iii) specifying a Date of Termination which, if submitted by the Executive (or, in the case of a termination described in Section 4(a)(ii), by the Company), shall be at least thirty (30) days following the date of such notice (a “Notice of Termination); p rovided, however, that a Notice of Termination delivered by the Company pursuant to Section 4(a)(ii) shall not be required to specify a Date of Termination, in which case the Date of Termination shall be determined pursuant to Section 4(a)(ii); and provided, further, that in the event that the Executive delivers a Notice of Termination (other than a notice of non- extension under Section 4(a)(viii) above) to the Company, the Company may, in its sole discretion, accelerate the Date of Termination to any date that occurs following the date of Company’s receipt of such Notice of Termination (even if such date is prior to the date specified in such Notice of Termination). A Notice of Termination submitted by the Company may provide for a Date of Termination on the date the Executive receives the Notice of Termination, or any date thereafter elected by the Company in its sole discretion. The failure by the Company or the Executive to set forth in the Notice of Termination any fact or circumstance which contributes to a showing of Cause or Good Reason shall not waive any right of the Company or the Executive hereunder or preclude the Company or the Executive from asserting such fact or circumstance in enforcing the Company’s or the Executive’s rights hereunder. (c) P ost-Termination Assistance. Executive agrees to make reasonable efforts to assist the Company after the termination of Executive’s employment, including but not limited to, transitioning of Executive’s job duties as well as assisting with any legal proceeding, lawsuit, or claim involving matters occurring during Executive’s employment with the Company. The Company shall reimburse Executive for reasonable expenses incurred in connection with such cooperation. (d) D eemed Resignations. Unless otherwise agreed to in writing by the Company and the Executive prior to the termination of the Executive's employment, any termination of the Executive's employment shall, without changing the basis for termination of employment or the impact of such termination on the Executive's rights, if any, under this Agreement, constitute (i) an automatic resignation of the Executive from any position held as an officer of the Company and any of its Affiliates and (ii) an automatic resignation of the Executive from the Board of Managers of the General Partner (if applicable), from the board of directors or similar governing body of any Affiliate of the Company and from the board of directors or similar governing body of any corporation, limited liability entity or other entity in which the Company or any Affiliate holds an equity interest and with respect to which board or similar governing body the Executive serves as the Company's or such Affiliate's designee or other representative. 5. C ompany Obligations Upon Termination of Employment. (a) I n General. Upon a termination of the Executive’s employment for any reason, the Executive (or the Executive’s estate) shall be entitled to receive: (i) any portion of the Executive’s Annual Base Salary through the Date of Termination not theretofore paid, (ii) any expenses owed to the Executive under Section 3(e), (iii) any accrued but unused PTO pursuant to Section 3(d), and (iv) any amount arising from the Executive’s participation in, or benefits under, any employee benefit plans, programs or arrangements under Section 3(c), which amounts shall be payable in accordance with the terms and conditions of such employee benefit plans, 9 programs or arrangements. Any Annual Bonus earned for any calendar year completed prior to the Date of Termination, but unpaid prior to such date, and any Prorated Termination Bonus owed pursuant to the last sentence of Section 3(b), shall be paid within sixty (60) days after the Date of Termination (but in any event on or prior to March 15 of the calendar year immediately following such completed calendar year with respect to which such Annual Bonus or Prorated Termination Bonus was earned). Except as otherwise set forth in Section 5(b) below, the payments and benefits described in this Section 5(a) shall be the only payments and benefits payable in the event of the Executive’s termination of employment for any reason. (b) S everance Payment (i) In addition to the payments and benefits described in Section 5(a) above, if the Executive’s employment shall be terminated by the Company without Cause pursuant to Section 4(a)(iv), by the Executive’s resignation for Good Reason pursuant to Section 4(a)(v), or due to non-extension of the Initial Term or any Extension Term by the Company pursuant to Section 4(a)(vii), the Company shall pay to Executive severance in the total gross amount equal to o ne and one-half (1.5) times the sum of (1) the Annual Base Salary for the year in which the Date of Termination occurs, and (2) the higher of the target Annual Bonus or the Annual Bonus paid to the Executive in respect of the calendar year immediately preceding the year in which the Date of Termination occurs (the “Severance Payment”). (ii) The Severance Payment shall be in lieu of notice or any other severance benefits to which the Executive might otherwise be entitled. Notwithstanding anything herein to the contrary, (A) no portion of the Severance Payment shall be paid unless, on or prior to the sixtieth (60th) day following the Date of Termination, the Executive timely executes a general waiver and release of claims agreement, in a form substantially similar to that attached to this Agreement as Exhibit B (the “Release”), which Release shall not have been revoked by the Executive prior to the expiration of the period (if any) during which any portion of such Release is revocable under applicable law, and (B) as of the first date on which the Executive violates any covenant contained in Section 7, any remaining unpaid portion of the Severance Payment shall thereupon be forfeited. Subject to the provisions of Section 9, the Severance Payment shall be paid in equal installments during the Severance Period, at the same time and in the same manner as the Annual Base Salary would have been paid had the Executive remained in active employment during the Severance Period, in accordance with the Company’s normal payroll practices in effect on the Date of Termination; provided that any installment that would otherwise have been paid prior to the first normal payroll payment date occurring on or after the sixtieth (60th) day following the Date of Termination (such payroll date, the “First P ayment Date”) shall instead be paid on the First Payment Date. For purposes of Section 409A (including, without limitation, for purposes of Section 1.409A-2(b)(2)(iii) of the Department of Treasury Regulations), the Executive’s right to receive the Severance Payment in the form of installment payments (the “Installment Payments”) shall be treated as a right to receive a series of separate payments and, accordingly, each Installment Payment shall at all times be considered a separate and distinct payment. 10 (c) During the lesser of the period during which Executive or a qualifying beneficiary (as defined in Section 607 of ERISA) has in effect an election for post-termination continuation coverage for medical and dental benefits under applicable law, including Section 4980 of the Code (“COBRA”), or the period ending on the 18-month anniversary of the Date of Termination, Executive (or, if applicable, the qualifying beneficiary) shall be entitled to such coverage at an out- of-pocket premium cost that does not exceed the out-of-pocket premium cost applicable to similarly situated active employees (and their eligible dependents). (d) The provisions of this Section 5 shall supersede in their entirety any severance payment provisions in any severance plan, policy, program or other arrangement maintained by the Company. (e) R echaracterization of Termination. Notwithstanding any other provision of this Agreement, if following the termination of employment the Company discovers that grounds existed as of the Date of Termination for a termination for Cause, then such termination shall be deemed to be a termination for Cause and Executive shall only be entitled to the payments and benefits provided in Section 5(a). In the event Executive’s termination is reclassified as a termination for Cause pursuant to this Section 5(e), Executive’s termination shall be so treated and classified for all purposes under this Agreement and any other agreements between Executive and the Company, and Executive shall repay to the Company any monies or benefits received by Executive following termination to which Executive would not have been entitled upon being terminated for Cause. 6. C hange in Control. (a) E quity Awards. Notwithstanding anything to the contrary in this Agreement or any other agreement, including the LTIP and any award agreement thereunder, all equity awards granted to the Executive under the LTIP and held by the Executive as of immediately prior to a Change in Control, to the extent unvested, shall become fully vested immediately prior to the Change in Control. (b) G olden Parachute Excise Tax Protection. Notwithstanding any provision of this Agreement, if any portion of the payments or benefits provided to the Executive hereunder, or under any other agreement with the Executive or any plan, policy or arrangement of the Company or any of its Affiliates (in the aggregate, “Total Payments”), would constitute an “excess parachute payment” and would, but for this Section 6(b), result in the imposition on the Executive of an excise tax under Section 4999 of the Code (the “Excise Tax”), then the Total Payments to be made to the Executive shall either be (i) delivered in full, or (ii) reduced by such amount such that no portion of the Total Payments would be subject to the Excise Tax, whichever of the foregoing results in the receipt by the Executive of the greatest benefit on an after-tax basis (taking into account the applicable federal, state and local income taxes and the Excise Tax). The determination of whether a reduction in Total Payments is necessary and the amount of any such reduction shall be made by the Company in its reasonable discretion and in reliance on its tax advisors. If the Company so determines that a reduction in Total Payments is required, such reduction shall apply first pro rata to (A) cash payments subject to Section 409A of the Code as “deferred compensation” and (B) cash payments not subject to Section 409A of the Code (in each case with the cash payments otherwise scheduled to be paid latest in time 11 reduced first), and then pro rata to (C) equity-based compensation subject to Section 409A of the Code as “deferred compensation” and (D) equity-based compensation not subject to Section 409A of the Code. 7. R estrictive Covenants. (a) The Executive shall not, at any time during the Term or, in the event of a termination of Executive’s employment pursuant to Section 4(a)(iv), (v), or (vii), during the Restricted Period, directly or indirectly, (i) engage in the Restricted Business within the Restricted Territory, or (ii) have any equity interest in or manage, participate in, assist, or operate any Person (whether as director, officer, employee, agent, representative, partner, security holder, consultant or otherwise) that engages in the Restricted Business within the Restricted Territory. Notwithstanding the foregoing, the Executive shall be permitted to acquire a passive stock or equity interest in such a business; provided that such stock or other equity interest is publicly traded and the amount acquired by Executive is not more than five percent (5%) of the outstanding interest in such business. Notwithstanding the foregoing, at any time during the Restricted Period, Executive may, at Executive’s option, serve on the Company a written notice waiving the right to any and all future installments of the Severance Payment pursuant to Section 5(b) (a “S everance Waiver Notice”), and upon delivery of the Severance Waiver Notice, Executive shall no longer be bound by the restrictions set forth in this Section 7(a) for the period on and after the date on which the Severance Waiver Notice is delivered to the Company; provided, however, that notwithstanding the delivery of a Severance Waiver Notice, Executive will continue to be bound by the remaining obligations set forth in this Agreement, including but not limited to those covenants of Executive set forth in Sections 7(b)-(g) hereof. (b) The Executive shall not, at any time during the Term or during the Restricted Period, directly or indirectly, either for himself or on behalf of any other Person, (i) recruit or otherwise solicit or induce any employee of the Company to terminate his, her or its employment or arrangement with the Company, or otherwise change his, her or its relationship with the Company, (ii) hire, or cause to be hired, any person who was employed by the Company and served in a capacity of “vice president” (or any person serving in a capacity senior to vice president) at any time during the twelve (12)- month period immediately prior to the Date of Termination, or (iii) influence, induce, or encourage any customer, subscriber, or supplier of the Company to discontinue, reduce, or materially change its relationship or business with the Company. (c) Except as the Executive reasonably and in good faith determines to be required in the faithful performance of the Executive’s duties hereunder or in accordance with Section 7(e), the Executive shall, during the Term and after the Date of Termination, maintain in confidence and shall not directly or indirectly, use, disseminate, disclose or publish, or use for the Executive’s benefit or the benefit of any Person, any confidential or proprietary information or trade secrets of or relating to the Company, including, without limitation, information with respect to the Company’s operations, processes, protocols, products, inventions, business practices, finances, principals, vendors, suppliers, customers, potential customers, marketing methods, costs, prices, contractual relationships, regulatory status, compensation paid to employees or other terms of employment (“Proprietary Information”), or deliver to any Person, any document, record, notebook, computer program or similar repository of or containing any 12 such Proprietary Information. The Executive’s obligation to maintain and not use, disseminate, disclose or publish, or use for the Executive’s benefit or the benefit of any Person, any Proprietary Information after the Date of Termination will continue so long as such Proprietary Information is not, or has not by legitimate means become, generally known and in the public domain (other than by means of the Executive’s direct or indirect disclosure of such Proprietary Information) and continues to be maintained as Proprietary Information by the Company. The parties hereby stipulate and agree that as between them, the Proprietary Information identified herein is important, material and affects the successful conduct of the businesses of the Company (and any successor or assignee of the Company). (d) Upon termination of the Executive’s employment with the Company for any reason, the Executive will promptly deliver to the Company all correspondence, drawings, manuals, letters, notes, notebooks, reports, programs, plans, proposals, financial documents, or any other documents concerning the Company’s customers, business plans, marketing strategies, products or processes. (e) The Executive may respond to a lawful and valid subpoena or other legal process but shall give the Company (if lawfully permitted to do so) the earliest possible notice thereof, and shall, as much in advance of the return date as possible, make available to the Company and its counsel the documents and other information sought, and shall assist such counsel in resisting or otherwise responding to such process. Upon notification from Executive of such subpoena or other legal process, the Company shall, at its reasonable expense, retain mutually acceptable legal counsel to represent Executive in connection with Executive’s response to any such subpoena or other legal process. The Executive may also disclose Proprietary Information if: (i) in the reasonable written opinion of counsel for the Executive furnished to the Company, such information is required to be disclosed for the Executive not to be in violation of any applicable law or regulation or (ii) the Executive is required to disclose such information in connection with the enforcement of any rights under this Agreement or any other agreements between the Executive and the Company. (f) Executive shall refrain from publishing any oral or written statements about the Company or any of its Affiliates, or any of their respective officers, employees, shareholders, investors, directors, agents or representatives that are malicious, obscene, threatening, harassing, intimidating or discriminatory and which are designed to harm any of the foregoing, at any time; p rovided that the Executive may confer in confidence with the Executive’s legal representatives, make truthful statements to any government agency in sworn testimony, or make truthful statements as otherwise required by law. The Company agrees that, upon the termination of the Executive’s employment hereunder, it shall advise its directors and executive officers to refrain from publishing any oral or written statements about Executive that are malicious, obscene, threatening, harassing, intimidating or discriminatory and which are designed to harm Executive, at any time; provided that they may confer in confidence with the Company’s and their legal representatives and make truthful statements as required by law. (g) Prior to accepting other employment or any other service relationship during the Restricted Period, the Executive shall provide a copy of this Section 7 to any recruiter who assists the Executive in obtaining other employment or any other service relationship and to any 13 employer or Person with which the Executive discusses potential employment or any other service relationship. (h) Executive agrees and hereby acknowledges that: (i) the provisions of this Section 7 do not impose a greater restraint than is necessary to protect the goodwill, trade secrets, or other business interests of the Company; (ii) such provisions contain reasonable limitations as to time, scope of activity, and geographical area to be restrained; (iii) the provisions of this Section 7 are necessary and essential to protect the Proprietary Information, trade secrets, and goodwill of the Company, as well as due to Executive’s position as an executive and/or management employee of the Company, and (iv) the consideration provided hereunder, including without limitation, the Proprietary Information provided to Executive, is sufficient to compensate Executive for the restrictions contained in this Section 7. In consideration of the foregoing and in light of Executive’s education, skills, and abilities, Executive agrees that Executive will not assert that, and it should not be considered that, any provisions of Section 7 otherwise are void, voidable, or unenforceable or should be voided or held unenforceable. In the event the terms of this Section 7 shall be determined by any court of competent jurisdiction to be unenforceable by reason of its extending for too great a period of time or over too great a geographical area or by reason of its being too extensive in any other respect, it will be interpreted to extend only over the maximum period of time for which it may be enforceable, over the maximum geographical area as to which it may be enforceable, or to the maximum extent in all other respects as to which it may be enforceable, all as determined by such court in such action. (i) As used in this Section 7, the term “Company” shall include the Company, its parent, Affiliates, related entities, and any of its direct or indirect subsidiaries. 8. I njunctive Relief.The Executive recognizes and acknowledges that a breach of the covenants contained in Section 7 will cause irreparable damage to the Company and its goodwill, the exact amount of which will be difficult or impossible to ascertain, and that the remedies at law for any such breach will be inadequate. Accordingly, the Executive agrees that in the event of a breach of any of the covenants contained in Section 7, in addition to any other remedy that may be available at law or in equity, the Company will be entitled to specific performance and injunctive relief. 9. S ection 409A. (a) G eneral. The parties hereto acknowledge and agree that, to the extent applicable, this Agreement shall be interpreted in accordance with, and incorporate the terms and conditions required by, Section 409A. Notwithstanding any provision of this Agreement to the contrary, in the event that the Company determines that any amounts payable hereunder will be immediately taxable to the Executive under Section 409A, the Company reserves the right to (without any obligation to do so or to indemnify the Executive for failure to do so) (i) adopt such amendments to this Agreement or adopt such other policies and procedures (including amendments, policies and procedures with retroactive effect) that it determines to be necessary or appropriate to preserve the intended tax treatment of the benefits provided by this Agreement, to preserve the economic benefits of this Agreement and to avoid less favorable accounting or tax consequences for the Company and/or (ii) take such other actions it determines to be necessary or appropriate to exempt the amounts payable hereunder from Section 409A or to comply with the requirements 14 of Section 409A and thereby avoid the application of penalty taxes thereunder. Notwithstanding anything herein to the contrary, no provision of this Agreement shall be interpreted or construed to transfer any liability for failure to comply with the requirements of Section 409A from the Executive or any other individual to the Company or any of its Affiliates, employees or agents. (b) S eparation from Service under Section 409A; Section 409A Compliance. Notwithstanding anything herein to the contrary: (i) no termination or other similar payments and benefits hereunder shall be payable unless the Executive’s termination of employment constitutes a “separation from service” within the meaning of Section 1.409A-1(h) of the Department of Treasury Regulations; (ii) if the Executive is deemed at the time of the Executive’s separation from service to be a “specified employee” for purposes of Section 409A(a)(2)(B)(i) of the Code, to the extent delayed commencement of any portion of any termination or other similar payments and benefits to which the Executive may be entitled hereunder (after taking into account all exclusions applicable to such payments or benefits under Section 409A) is required in order to avoid a prohibited distribution under Section 409A(a)(2)(B)(i) of the Code, such portion of such payments and benefits shall not be provided to the Executive prior to the earlier of (x) the expiration of the six (6)-month period measured from the date of the Executive’s “separation from service” with the Company (as such term is defined in the Department of Treasury Regulations issued under Section 409A) and (y) the date of the Executive’s death; p rovided that upon the earlier of such dates, all payments and benefits deferred pursuant to this Section 9(b)(ii) shall be paid in a lump sum to the Executive, and any remaining payments and benefits due hereunder shall be provided as otherwise specified herein; the determination of whether the Executive is a “specified employee” for purposes of Section 409A(a)(2)(B)(i) of the (iii) Code as of the time of the Executive’s separation from service shall be made by the Company in accordance with the terms of Section 409A (including, without limitation, Section 1.409A-1(i) of the Department of Treasury Regulations and any successor provision thereto); (iv) to the extent that any Installment Payments under this Agreement are deemed to constitute “nonqualified deferred compensation” within the meaning of Section 409A, for purposes of Section 409A (including, without limitation, for purposes of Section 1.409A- 2(b)(2)(iii) of the Department of Treasury Regulations), each such payment that the Executive may be eligible to receive under this Agreement shall be treated as a separate and distinct payment; (v) to the extent that any reimbursements or corresponding in-kind benefits provided to the Executive under this Agreement are deemed to constitute “deferred compensation” under Section 409A, such reimbursements or benefits shall be provided reasonably promptly, but in no event later than December 31 of the year following the year in which the expense was incurred, and in any event in accordance with Section 1.409A-3(i)(1)(iv) of the Department of Treasury Regulations; and (vi) the amount of any such payments or expense reimbursements in one calendar year shall not affect the expenses or in-kind benefits eligible for payment or reimbursement in any other calendar year, other than an arrangement providing for the reimbursement of medical expenses referred to in Section 105(b) of the Code, and the Executive’s right to such payments or reimbursement of any such expenses shall not be subject to liquidation or exchange for any other benefit. 10. A ssignment and Successors. The Company may, without Executive’s consent, assign its rights and obligations under this Agreement to any entity, including any successor to all or substantially all the assets of the Company, by merger or otherwise, and may assign or encumber this Agreement and its rights hereunder as security for indebtedness of the Company and its 15 Affiliates. The Executive may not assign the Executive’s rights or obligations under this Agreement to any individual or entity. This Agreement shall be binding upon and inure to the benefit of the Company, the Executive and their respective successors, assigns, personnel and legal representatives, executors, administrators, heirs, distributees, devisees, and legatees, as applicable. 11. G overning Law. This Agreement shall be governed, construed, interpreted and enforced in accordance with the substantive laws of the State of Delaware, without reference to the principles of conflicts of law of Delaware or any other jurisdiction, and where applicable, the laws of the United States. 12. N otices.Any notice, request, claim, demand, document and other communication hereunder to any party hereto shall be effective upon receipt (or refusal of receipt) and shall be in writing and delivered personally or sent by email or certified or registered mail, postage prepaid, to the following address (or at any other address as any party hereto shall have specified by notice in writing to the other party hereto): (a) If to the Company: Summit Midstream Partners, LLC Attn: General Counsel 910 Louisiana Street Suite 4200 Houston, Texas 77042 Facsimile: (832) 413-4780 with copies to: Summit Midstream Partners, LLC Attn: Heath Deneke, President & CEO 910 Louisiana Street Suite 4200 Houston, Texas 77042 Facsimile: (832) 413-4780 Heath.deneke@summitmidstream.com And Locke Lord LLP Attn: Jeffrey M. McPhaul, Partner 2800 JPMorgan Chase Tower 600 Travis St. Houston, TX 77002 T: 713-226-1269 F: 713-229-2537 jmcphaul@lockelord.com 16 If to the Executive, at the address set forth on the signature page hereto. 13. C ounterparts. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same Agreement. 14. E ntire Agreement.This Agreement (together with any other agreements and instruments contemplated hereby or referred to herein) is intended by the parties hereto to be the final expression of their agreement with respect to the employment of the Executive by the Company and may not be contradicted by evidence of any prior or contemporaneous agreement (including, without limitation, any term sheet or offer letter). The parties hereto further intend that this Agreement shall constitute the complete and exclusive statement of its terms and that no extrinsic evidence whatsoever may be introduced in any judicial, administrative, or other legal proceeding to vary the terms of this Agreement. This Agreement expressly supersedes the Original Employment Agreement. 15. A mendments; Waivers. This Agreement may not be modified, amended, or terminated except by an instrument in writing, signed by the Executive and a duly authorized officer of the Company and approved by the Board, which expressly identifies the amended provision of this Agreement. By an instrument in writing similarly executed and approved by the Board, the Executive or a duly authorized officer of the Company may waive compliance by the other party or parties hereto with any provision of this Agreement that such other party was or is obligated to comply with or perform; provided, however, that such waiver shall not operate as a waiver of, or estoppel with respect to, any other or subsequent failure to comply or perform. No failure to exercise and no delay in exercising any right, remedy, or power hereunder shall preclude any other or further exercise of any other right, remedy, or power provided herein or by law or in equity. 16. N o Inconsistent Actions. The parties hereto shall not voluntarily undertake or fail to undertake any action or course of action inconsistent with the provisions or essential intent of this Agreement. Furthermore, it is the intent of the parties hereto to act in a fair and reasonable manner with respect to the interpretation and application of the provisions of this Agreement. 17. C onstruction. This Agreement shall be deemed drafted equally by both of the parties hereto. Its language shall be construed as a whole and according to its fair meaning. Any presumption or principle that the language is to be construed against any party hereto shall not apply. The headings in this Agreement are only for convenience and are not intended to affect construction or interpretation. Any references to paragraphs, subparagraphs, sections or subsections are to those parts of this Agreement, unless the context clearly indicates to the contrary. Also, unless the context clearly indicates to the contrary, (a) the plural includes the singular and the singular includes the plural; (b) “and” and “or” are each used both conjunctively and disjunctively; (c) “any,” “all,” “each,” or “every” means “any and all,” and “each and every”; (d) ”includes” and “including” are each “without limitation”; (e) “herein,” “hereof,” “hereunder” and other similar compounds of the word “here” refer to the entire Agreement and not to any particular paragraph, subparagraph, section or subsection; and (f) all pronouns and any 17 variations thereof shall be deemed to refer to the masculine, feminine, neuter, singular or plural as the identity of the entities or persons referred to may require. 18. A rbitration.Any dispute or controversy based on, arising under or relating to this Agreement shall be settled exclusively by final and binding arbitration, conducted before a single neutral arbitrator in Houston, Texas in accordance with the Employment Arbitration Rules and Mediation Procedures of the American Arbitration Association (the “AAA”) then in effect. Due to the interstate nature of the Company’s operations, the parties agree that the Federal Arbitration Act shall apply to this Agreement. Arbitration may be compelled, and judgment may be entered on the arbitration award in any court having jurisdiction; provided, however, that the Company shall be entitled to seek a restraining order or injunction in any court of competent jurisdiction to prevent any continuation of any violation of the provisions of Section 7, and the Executive hereby consents that such restraining order or injunction may be granted without requiring the Company to post a bond (or, if required by applicable law, a bond of $500). Only individuals who are (a) lawyers engaged full-time in the practice of law and (b) on the AAA roster of arbitrators shall be selected as an arbitrator. Within twenty (20) days of the conclusion of the arbitration hearing, the arbitrator shall prepare written findings of fact and conclusions of law. The arbitrator shall be entitled to award any relief available in a court of law. Each party shall bear its own costs and attorneys’ fees in connection with an arbitration; provided that the Company shall bear the cost of the arbitrator and the AAA’s administrative fees. 19. N otice of Immunity. The Executive acknowledges that the Company has provided the Executive with the following notice of immunity rights in compliance with the requirements of the Defend Trade Secrets Act of 2016: (i) the Executive shall not be held criminally or civilly liable under any U.S. federal or state trade secret law for the disclosure of Proprietary Information that is made in confidence to a U.S. federal, state or local government official or to an attorney solely for the purpose of reporting or investigating a suspected violation of law; (ii) the Executive shall not be held criminally or civilly liable under any U.S. federal or state trade secret law for the disclosure of Proprietary Information that is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is made under seal; and (iii) if the Executive files a lawsuit for retaliation by the Company for reporting a suspected violation of law, the Executive may disclose the Proprietary Information to the Executive’s attorney and use the Proprietary Information in the court proceeding, if the Executive files any document containing the Proprietary Information under seal, and does not disclose the Proprietary Information, except pursuant to court order. However, under no circumstance will the Executive be authorized to disclose any information covered by attorney-client privilege or attorney work product of the Company without prior written consent of the Company’s General Counsel or other officer designated by the Company. Notwithstanding anything to the contrary contained herein, no provision of this Agreement shall be interpreted so as to impede the Executive (or any other individual) from reporting possible violations of U.S. federal law or regulation to any governmental agency or entity, including but not limited to the U.S. Department of Justice, the U.S. Securities and Exchange Commission, the U.S. Congress, and any agency Inspector General of the U.S. government, or making other disclosures under the whistleblower provisions of U.S. federal law or regulation. The Executive does not need the prior authorization of the Company to make any such reports or disclosures and the Executive shall not be required to notify the Company that such reports or disclosures have been made. 18  20. E nforcement. The invalidity or unenforceability of any provision or provisions of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect. If any provision of this Agreement is held to be illegal, invalid or unenforceable under present or future laws effective during the term of this Agreement, such provision shall be fully severable; this Agreement shall be construed and enforced as if such illegal, invalid or unenforceable provision had never comprised a portion of this Agreement; and the remaining provisions of this Agreement shall remain in full force and effect and shall not be affected by the illegal, invalid or unenforceable provision or by its severance from this Agreement. Furthermore, in lieu of such illegal, invalid or unenforceable provision there shall be added automatically as part of this Agreement a provision as similar in terms to such illegal, invalid or unenforceable provision as may be possible and be legal, valid and enforceable. 21. W aiver of Breach. Failure of the Company to demand strict compliance with any of the terms, covenants or conditions hereof will not be deemed a waiver of the term, covenant or condition, nor will any waiver or relinquishment by the Company of any right or power under this Agreement at any one time or more times be deemed a waiver or relinquishment of the right or power at any other time or times. 22. W ithholding. The Company shall be entitled to withhold from any amounts payable under this Agreement, any federal, state, local or foreign withholding or other taxes or charges which the Company is required to withhold. The Company shall be entitled to rely on an opinion of counsel if any questions as to the amount or requirement of withholding shall arise. 23. A bsence of Conflicts; Executive Acknowledgement. The Executive hereby represents that from and after the Effective Date the performance of the Executive’s duties hereunder will not breach any other agreement to which the Executive is a party. The Executive acknowledges that the Executive has read and understands this Agreement, is fully aware of its legal effect, has not acted in reliance upon any representations or promises made by the Company other than those contained in writing herein, and has entered into this Agreement freely based on the Executive’s own judgment. 24. S urvival.The expiration or termination of the Term shall not impair the rights or obligations of any party hereto that shall have accrued prior to such expiration or termination. [Signature pages follow] 19 IN WITNESS WHEREOF, the parties hereto have executed this Agreement on the date and year first above written. COMPANY By: Heath Deneke President and Chief Executive Officer EXECUTIVE By: Marc Stratton 4875 Lansbury Dr. Atlanta, Georgia 30342 EXHIBIT A 1. Denver County, Colorado 2. Garfield County, Colorado 3. Mesa County, Colorado 4. Moffat County, Colorado 5. Rio Blanco County, Colorado 6. Weld County, Colorado 7. Cobb County, Georgia 8. Eddy County, New Mexico 9. Lea County, New Mexico 10. Laramie County, Wyoming 11. Burke County, North Dakota 12. Divide County, North Dakota 13. Mountrail County, North Dakota 14. Williams County, North Dakota 15. Dallas County, Texas 16. Harris County, Texas 17. Ellis County, Texas 18. Johnson County, Texas 19. Tarrant County, Texas 20. Belmont County, Ohio 21. Guernsey County, Ohio 22. Harrison County, Ohio 23. Monroe County, Ohio 24. Noble County, Ohio 25. Doddridge County, West Virginia 26. Harrison County, West Virginia EXHIBIT B RELEASE AGREEMENT This Release Agreement (“R elease Agreement”) is by and between M arc Stratton (the “Executive”) and Summit Operating Services Company, LLC (the “Company”). Executive and the Company may sometimes be referred to individually as a “Party” or collectively as the “Parties”. RECITALS WHEREAS, Executive and the Company previously entered into that certain Employment Agreement, dated as of S eptember 1, 2020 (the “Employment Agreement”); WHEREAS, Executive and the Company mutually agreed, pursuant to Section 3(b) and S ection 5(b) of the Employment Agreement, that as a condition to receiving any Prorated Termination Bonus or Severance Payment, Executive must timely execute, and not revoke, this Release Agreement; and WHEREAS, capitalized terms used herein and not otherwise defined shall have the meanings ascribed to them in the Employment Agreement. AGREEMENT NOW, THEREFORE, in consideration of the foregoing and the mutual covenants and agreements of the Parties set forth in this Release Agreement and the Employment Agreement, and for such other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereto agree as follows: 1. R elease of All Claims and Promise Not to Sue. In return for the Company’s promises in this Release Agreement and the Employment Agreement, including payment of the Prorated Termination Bonus and/or the Severance Payment, Executive voluntarily and knowingly hereby waives, releases, and discharges (A) the Company and any of its past or present parents, subsidiaries, owners, shareholders, members, or Affiliates (all collectively the “Company Parties”); (B) any past or present officer, director, manager or employee of the Company Parties, in their individual and official capacities; and (C) any predecessors, parent companies, subsidiaries, investors, owners, shareholders, stockholders, members, managers, operating units, Affiliates, divisions, agents, representatives, officers, directors, partners, members, employees, benefit plans, fiduciaries, insurers, attorneys, successors, and assigns of the entities and Persons named in (A)-(B) (all collectively, the “Released Parties”) from all claims, liabilities, demands, and causes of action, known or unknown, fixed or contingent, which Executive may have or claim to have against any of them as a result of Executive’s employment with the Company and/or separation from employment with the Company and/or as a result of any other matter arising through the date of Executive’s signature on this Release Agreement. Executive agrees not to file a lawsuit against any Released Party to assert any such released claims, and Executive agrees not to accept any monetary damages or other personal relief (including legal or equitable relief) in connection with any administrative agency report, disclosure, claim or lawsuit filed by any Person or governmental agency with the exception of the same in connection with a report or disclosure to the Securities and Exchange Commission (“SEC”). Executive represents Executive has not already made, transferred or assigned any rights to the claims released in this Release Agreement. This waiver, release, and discharge includes, but is not limited to: (a) (b) (c) (d) (e) (f) claims arising under federal, state, or local laws regarding employment or prohibiting employment discrimination such as, without limitation, Title VII of the Civil Rights Act of 1964, the Equal Pay Act, the Age Discrimination in Employment Act, the Older Workers’ Benefit Protection Act, the Genetic Information Nondiscrimination Act, the Occupational Safety and Health Act, the National Labor Relations Act, the Civil Rights Act of 1866 (42 U.S.C. § 1981), the Americans with Disabilities Act, the Fair Labor Standards Act, the Family and Medical Leave Act (FMLA), the Texas Commission on Human Rights Act; and Chapters 21, 61 and 451 of the Texas Labor Code, Comprehensive Omnibus Budget Reconciliation Act of 1985 (COBRA), the Worker Adjustment and Retraining Notification (WARN) Act; claims based on any express or implied contract, including, without limitation, under the Employment Agreement, or other agreement or representation relating to the terms and conditions of Executive’s employment, which may have been alleged to exist between Executive and the Company or any other Released Party, and claims that the Company violated its personnel policies, handbooks, or any covenant of good faith and fair dealing; claims for personal injury, harm, or other damages (whether intentional or unintentional and whether occurring on the job or not, including, without limitation, negligence, defamation, misrepresentation, fraud, intentional infliction of emotional distress, assault, battery, invasion of privacy, and other such tort or injury claims); claims growing out of any legal restrictions on the Released Parties’ right to terminate employment of their respective employees including any claims based on any violation of public policy or retaliation for taking a protected action; claims regarding any restrictions on the Released Parties’ right to enforce any of Executive’s post- termination obligations regarding non-disclosure, non- disparagement, non-competition, non-solicitation, and non-interference; and claims for equity or other ownership or profits interests, wages, back pay, overtime pay, severance pay, future pay, bonuses, commissions, and any other compensation, including, without limitation, pursuant to the Employment Agreement or the Award Letters. NOTHING IN THIS RELEASE AGREEMENT SHALL WAIVE OR MODIFY THE FOLLOWING RIGHTS IF EXECUTIVE OTHERWISE HAS SUCH RIGHTS: (g) (h) (i) (j) (k) (l) (m) (n) (o) 2. any right or claim provided under this Release Agreement; benefit claims under employee pension or welfare benefit plans in which the Executive is a participant by virtue of his employment with any of the Company Parties; any rights of indemnification the Executive may have under any written agreement between the Executive and the Company (or its Affiliates), the Company’s Certificate of Incorporation, the Partnership’s LP Agreement, the General Corporation Law of the State of Delaware, any applicable statute or common law, or pursuant to any applicable insurance policy, contractual rights to vested equity awards; any right to COBRA continuation coverage; any right to seek unemployment compensation benefits if Executive is otherwise qualified under applicable law; any rights regarding a pending workers’ compensation claim, however, Executive states that Executive has no unfiled workers’ compensation claim or unreported injury; any rights that may not be waived as a matter of law; or any claim based on facts occurring after this Release Agreement is signed. E xecutive’s Release of Age Discrimination Claims. In addition, Executive acknowledges the following: (a) (b) (c) (d) This Release Agreement is written in a manner calculated to be understood by Executive and that Executive in fact understands the terms, conditions and effect of this Release Agreement. This Release Agreement refers to rights or claims arising under the Age Discrimination in Employment Act and Older Workers’ Benefit Protection Act. Executive does not waive rights or claims that may arise after the date this Release Agreement is executed. Executive waives rights or claims only in exchange for consideration in addition to anything of value to which Executive is already entitled. (e) (f) (g) (h) (i) (j) Executive is advised in writing to consult with an attorney prior to executing the Release Agreement. Executive has [21/45] days in which to consider this Release Agreement before accepting, but need not take that long if Executive does not wish to, and any decision to sign this Release Agreement before the [21/45] days have expired was done so voluntarily and not because of any fraud or coercion or improper conduct by any of the Released Parties. This Release Agreement allows a period of seven (7) days following Executive’s signature on the agreement during which Executive may revoke this Release Agreement. This Release Agreement is not effective until after the revocation period has been exhausted without any revocation by Executive. No payments shall be made until after the Release Agreement becomes effective. Executive fully understands all of the terms of this waiver agreement and knowingly and voluntarily enters into this Release Agreement. Executive has been given this Release Agreement to consider on [●] (the “Consideration Date”). Any notice of acceptance or revocation should be made by Executive to the Company as specified in Section 12 of the Employment Agreement. Any changes made to the version of this Release Agreement provided to Executive on the Consideration Date are not material or were made at the Executive’s request and will not restart the required [21/45]-day consideration period. 3. E xecutive’s Representations. Executive is, and will continue to be, in full compliance with any non-disclosure, non-disparagement, non-competition, and non-solicitation obligations owed to the Company Parties under any agreement or applicable law. Executive further represents and warrants that Executive has returned all information and property as required by S ection 7(d) of the Employment Agreement. 4. R eporting to Government Agencies. Nothing in this Release Agreement or in any other agreement referenced in this Release Agreement shall prevent Executive from filing a charge or complaint or making a disclosure or report of possible unlawful activity, including a challenge to the validity of this Release Agreement, with any governmental agency, including but not limited to the Equal Employment Opportunity Commission (“EEOC”), the National Labor Relations Board (“NLRB”), or the SEC, or from participating in any investigation or proceeding conducted by the EEOC, NLRB, SEC, or any federal, state or local agency. This Release Agreement does not impose any condition precedent (such as prior disclosure to any Released Party), any penalty, or any other restriction or limitation adversely affecting Executive’s rights regarding any governmental agency disclosure, report, claim or investigation. Executive understands and recognizes, however, that even if a report or disclosure is made or a charge is filed by Executive or on Executive’s behalf with a governmental agency other than the SEC, Executive will not be entitled to any damages or payment of any money or other relief personal to Executive relating to any event which occurred prior to Executive’s execution of this Release Agreement. 5. E ntire Agreement. Executive has carefully read and fully understands all of the terms of this Release Agreement. Executive agrees that this Release Agreement, together with the Employment Agreement, constitutes the complete agreement of the Parties in respect of the subject matter hereof and shall supersede all prior agreements between the Parties in respect of the subject matter hereof except to the extent set forth herein. For the avoidance of doubt, however, nothing in this Release Agreement shall constitute a waiver of any of the Company Parties’ rights to enforce any obligations of the Executive under the Employment Agreement that survive the Employment Agreement’s termination, including without limitation, any obligations concerning arbitration, confidentiality, non-competition, non- solicitation, and post-employment cooperation. 6. N o Admission. Executive understands this Release Agreement is not and shall not be deemed or construed to be an admission by any of the Released Parties of any wrongdoing of any kind or of any breach of any contract, law, obligation, policy, or procedure of any kind or nature. 7. I njunctive Relief.Executive acknowledges that damages may be difficult to calculate and/or wholly inadequate for certain breaches of this Release Agreement. The Released Parties may seek immediate injunctive or other equitable relief to enforce the terms of this Release Agreement, in addition to any legal or other relief to which the Released Parties may be entitled, including damages and attorneys’ fees. 8. R epresentations; Modifications; Severability.Executive acknowledges that Executive has not relied upon any representations or statements, written or oral, not set forth in this Release Agreement. This Release Agreement cannot be modified except in writing and signed by all Parties. The foregoing notwithstanding, if any part of this Release Agreement is found to be unenforceable by a court of competent jurisdiction, then such unenforceable portion will be modified to be enforceable, or severed from this Release Agreement if it cannot be modified, and such modification or severance shall have no effect upon the remaining portions of the Release Agreement which shall remain in full force and effect. 9. A ssignment and Successors. The Company may, without Executive’s consent, assign its rights and obligations under this Agreement to any entity, including any successor to all or substantially all the assets of the Company, by merger or otherwise. The Executive may not assign the Executive’s rights or obligations under this Agreement to any individual or entity. This Agreement shall be binding upon and inure to the benefit of the Company, the Executive and their respective successors, assigns, personnel and legal representatives, executors, administrators, heirs, distributees, devisees, and legatees, as applicable. 10. G overning Law. This Agreement shall be governed, construed, interpreted and enforced in accordance with the substantive laws of the State of Delaware, without reference to the principles of conflicts of law of Delaware or any other jurisdiction, and where applicable, the laws of the United States 11. C ounterparts. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same Agreement. [Signature Page Follows] IN WITNESS WHEREOF, the Company has caused this Release Agreement to be signed by its duly authorized officer, and Executive has executed this Release Agreement on the day and year written below. COMPANY By: Name: Title: Date: EXECUTIVE Marc Stratton By: Date: CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in Registration Statement No. 333-234781 on form S-3 and Nos. 333-184214, 333-189684 and 333-237323 on Form S-8 of our reports dated March 4, 2021, relating to the consolidated financial statements of Summit Midstream Partners, LP and subsidiaries (the “Partnership”), and the effectiveness of the Partnership's internal control over financial reporting, appearing in this Annual Report on Form 10-K of Summit Midstream Partners, LP for the year ended December 31, 2020. EXHIBIT 23.1 DELOITTE & TOUCHE LLP Houston, Texas March 4, 2021 EX 23.1-1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM EXHIBIT 23.2 We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-234781) and the Registration Statements on Form S-8 (Nos. 333-184214, 333-189684, and 333-237323) of Summit Midstream Partners, LP of our report dated March 6, 2020 relating to the financial statements of Ohio Gathering Company, L.L.C., which appears in this Form 10-K. /s/ PricewaterhouseCoopers LLP Denver, Colorado March 3, 2021 EX 23.2-1 EXHIBIT 31.1 I, Heath Deneke, certify that: CERTIFICATIONS 1. I have reviewed this annual report on Form 10-K of Summit Midstream Partners, LP; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: March 4, 2021 /s/ Heath Deneke Heath Deneke President, Chief Executive Officer and Director of Summit Midstream GP, LLC (the general partner of Summit Midstream Partners, LP) EX 31.1-1 EXHIBIT 31.2 I, Marc D. Stratton, certify that: CERTIFICATIONS 1. I have reviewed this annual report on Form 10-K of Summit Midstream Partners, LP; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: March 4, 2021 /s/ Marc D. Stratton Marc D. Stratton Executive Vice President and Chief Financial Officer of Summit Midstream GP, LLC (the general partner of Summit Midstream Partners, LP) EX 31.2-1 EXHIBIT 32.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the annual report on Form 10-K of Summit Midstream Partners, LP (the “Registrant”) for the annual period ended December 31, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Heath Deneke, as President, Chief Executive Officer and Director of Summit Midstream GP, LLC, the general partner of the Registrant, and Marc D. Stratton, as Executive Vice President and Chief Financial Officer of Summit Midstream GP, LLC, the general partner of the Registrant, each hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge: (1) (2) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant. /s/ Heath Deneke Name: Title: Date: Heath Deneke President, Chief Executive Officer and Director of Summit Midstream GP, LLC (the general partner of Summit Midstream Partners, LP) March 4, 2021 /s/ Marc D. Stratton Name: Title: Date: Marc D. Stratton Executive Vice President and Chief Financial Officer of Summit Midstream GP, LLC (the general partner of Summit Midstream Partners, LP) March 4, 2021 EX 32.1-1 EXHIBIT 99.1 Ohio Gathering Company, L.L.C. December 31, 2019, 2018, and 2017 Financial Statements and Report of Independent Registered Public Accounting Firm Report of Independent Registered Public Accounting Firm Audited Financial Statements: Balance Sheets Statements of Operations Statements of Changes in Members' Equity Statements of Cash Flows Notes to Financial Statements INDEX 2 Page 3 4 5 6 7 8 Report of Independent Registered Public Accounting Firm To the Board of Managers of Ohio Gathering Company, L.L.C. Opinion on the Financial Statements We have audited the accompanying balance sheets of Ohio Gathering Company, L.L.C. (the “Company”) as of December 31, 2019 and 2018, and the related statements of operations, of changes in members’ equity, and of cash flows for each of the three years in the period ended December 31, 2019, including the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits of these financial statements in accordance with the auditing standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/PricewaterhouseCoopers LLP Denver, Colorado March 6, 2020 We have served as the Company's auditor since 2016. 3 Ohio Gathering Company, L.L.C. Balance Sheets ($ in thousands) December 31, 2019 2018 $ $ $ $ 12,628 $ 11,751 9,604 6,008 282 40,273 1,273,775 3,296 46 1,317,390 $ 8,540 $ 1,591 9,685 19,816 3,579 312 23,707 6,523 14,371 14,463 4,619 59 40,035 1,259,075 3,730 46 1,302,886 12,073 3,464 11,700 27,237 3,371 332 30,940 1,293,683 1,317,390 $ 1,271,946 1,302,886 Assets Current assets: Cash Trade receivables Affiliate receivables Inventories Other current assets Total current assets Property and equipment, net Deferred contract costs, net Other noncurrent assets Total assets Liabilities and Members’ Equity Current liabilities: Accounts payable Affiliate payables Accrued liabilities Total current liabilities Asset retirement obligations Other long-term liabilities Total liabilities Commitments and contingencies (see Note 7) Members’ equity Total liabilities and members’ equity The accompanying notes are an integral part of these financial statements. 4 Ohio Gathering Company, L.L.C. Statements of Operations ($ in thousands) Revenue Operating expenses: Facility expenses General and administrative expenses Depreciation and accretion Impairment expense Total operating expenses Income from operations Miscellaneous income Income before provision for income tax Provision for deferred income tax expense Net income 2019 Year Ended December 31, 2018 2017 $ 141,262 $ 142,030 $ 140,505 38,340 3,538 62,470 3,469 107,817 33,445 — 33,445 8 33,437 $ 48,390 3,974 59,154 30,443 141,961 69 3,564 3,633 6 3,627 $ 33,649 3,676 68,294 3,423 109,042 31,463 — 31,463 6 31,457 $ The accompanying notes are an integral part of these financial statements. 5 Ohio Gathering Company, L.L.C. Statements of Changes in Members’ Equity ($ in thousands) Balance at December 31, 2016 $ 794,029 $ 556,995 $ MarkWest Utica EMG, L.L.C. Summit Midstream Partners, LP Total Contributions from members Distributions to members Net income Balance at December 31, 2017 Contributions from members Distributions to members Net income Balance at December 31, 2018 Contributions from members Distributions to members Net income 37,355 (60,330) 18,874 789,928 7,386 (52,908) 2,176 746,582 83,610 (58,010) 20,377 24,903 (40,220) 12,583 554,261 4,924 (35,272) 1,451 525,364 — (37,300) 13,060 Balance at December 31, 2019 $ 792,559 $ 501,124 $ The accompanying notes are an integral part of these financial statements. 6 1,351,024 62,258 (100,550) 31,457 1,344,189 12,310 (88,180) 3,627 1,271,946 83,610 (95,310) 33,437 1,293,683 Ohio Gathering Company, L.L.C. Statements of Cash Flows ($ in thousands) Cash flows from operating activities: Net income Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and accretion Amortization of deferred contract costs Deferred revenue Impairment expense Gain on insurance settlement related to construction costs Provision for deferred income tax expense ARO settlement Changes in operating assets and liabilities: Trade receivables Affiliate receivables Inventories Other current assets Accounts payable Affiliate payables Accrued liabilities All other, net Net cash provided by operating activities Cash flows from investing activities: Capital expenditures Proceeds from sale of property and equipment Proceeds from insurance settlement related to construction costs Net cash used in investing activities Cash flows from financing activities: Contributions from members Distributions to members Other Net cash used in financing activities Net increase (decrease) in cash Cash at beginning of year Cash at end of year Non-cash investing activities: (Decrease) increase in accrued property and equipment (Decrease) increase in affiliate payables for purchases of property and equipment Decrease (increase) in affiliate receivables for sales of property and equipment 2019 Year Ended December 31, 2018 2017 $ 33,437 $ 3,627 $ 31,457 62,470 435 (29) 3,469 — 8 (254) 2,621 (584) (1,389) (224) (1,195) (731) 1,641 — 99,675 (92,496) 10,662 — (81,834) 83,610 (95,310) (36) (11,736) 6,105 6,523 12,628 $ 59,154 435 (55) 30,443 (3,465) 6 — (724) 2,690 (871) 386 1,347 147 5,006 19 98,145 (47,056) 15,573 3,465 (28,018) 12,310 (88,180) — (75,870) (5,743) 12,266 6,523 $ 68,294 435 (1,181) 3,423 — 6 — 210 (1,609) (697) 1,357 109 103 214 — 102,121 (83,845) 12,796 — (71,049) 62,258 (100,550) — (38,292) (7,220) 19,486 12,266 (6,042) $ 7,671 $ (10,117) (1,141) 5,443 1,757 2,238 (236) (7,291) $ $ The accompanying notes are an integral part of these financial statements. 7 Ohio Gathering Company, L.L.C. Notes to Financial Statements ($ in thousands, unless otherwise indicated) 1.Organization and Business Effective May 31, 2012, MarkWest Utica EMG, L.L.C. (“MarkWest Utica”) a wholly-owned subsidiary of MPLX LP, entered into the Limited Liability Company Agreement (the “Original LLC Agreement”) with Blackhawk Midstream LLC (“Blackhawk”), in order to form Ohio Gathering Company, L.L.C. (the “Company” or “Ohio Gathering”). The Company provides natural gas gathering and compression services in the Utica Shale region of Ohio. All operational and administrative services are provided through contractual arrangements with affiliates of MarkWest Utica Operating Company, L.L.C. (“MarkWest Utica Operating”). See Note 3 for more information regarding affiliate transactions. In January 2014, Blackhawk sold its less than 1% ownership interest and an option to acquire a 40% equity interest in Ohio Gathering (the “Ohio Gathering Option” - see Note 2, Deferred Contract Costs, for further discussion) to Summit Midstream Partners, LP (“SMLP”). Effective June 1, 2014, SMLP exercised the Ohio Gathering Option and increased its equity ownership from less than 1% to approximately 40% through a net cash investment of $341.4 million. In August 2014, MarkWest Utica and SMLP entered into the Third Amended and Restated Limited Liability Company Agreement of Ohio Gathering Company, L.L.C. (“the Third Amended LLC Agreement”). In accordance with the Third Amended LLC Agreement, SMLP has the right, but not the obligation, to make additional capital contributions subject to certain limitations. If SMLP elects to contribute capital in response to a particular capital call then the aggregate amount of capital that MarkWest Utica is required to contribute pursuant to such capital call will be decreased, dollar for dollar, by the amount of capital SMLP elects to contribute. If a member fails to contribute any capital to the Company that is committed to be contributed or fails to timely wire the True-Up Amount (as defined in the Third Amended LLC Agreement) such member will be considered in default but will remain fully obligated to contribute such capital to the Company. The Company will be entitled to pursue all remedies available at law against the defaulting member. Through December 31, 2018, SMLP had elected to contribute 40% of all capital calls. On February 28, 2019, SMLP gave a formal notice of its election not to fund its pro rata portion of capital calls which has resulted in a reduction of its percentage interest in the Company as of December 31, 2019 from 40% to 38%. As of December 31, 2019, MarkWest Utica has contributed $1.4 billion and SMLP has contributed $853 million to the Company. The business and affairs of the Company are overseen by a board of managers. The composition of the board of managers changes in accordance with changes in investment balances. The reduction in SMLP’s percentage interest resulted in the loss of a board seat effective January 31, 2019. Therefore, effective January 31, 2019, the board of managers consists of three managers designated by MarkWest Utica and one manager designated by SMLP. The board of managers has delegated to MarkWest Utica Operating the authority to manage the day-to-day operations of the Company, subject to certain approval rights retained by the board. Pursuant to a services agreement between the Company and MarkWest Utica Operating, an affiliate of MarkWest Utica Operating provides all employees and services necessary for the daily operations and management of the Company’s business. The Company is required to distribute all available cash, as defined in the Third Amended LLC Agreement, to the members within 45 days of the end of each calendar month. 2. Significant Accounting Policies Basis of Presentation The accompanying financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Use of Estimates The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates are subject to uncertainties due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change and affect items such as, valuing inventory; evaluating impairments of long-lived assets; establishing estimated useful lives for long-lived assets; estimating revenues, expense accruals and capital expenditures; valuing asset retirement obligations; establishing inputs when determining fair value of options; evaluating forecasts when determining income tax valuation allowances; and determining liabilities, if any, for environmental and legal contingencies. Actual results could differ materially from those estimates. 8 Cash Cash includes cash on hand and secured deposits. The Company maintains cash deposits with a major bank, which, from time- to-time, may exceed federally insured limits. The Company had no cash equivalents at December 31, 2019 and 2018. Trade Receivables Trade receivables primarily consist of customer accounts receivable, which are recorded at the invoiced amount and generally do not bear interest. Past-due balances over 90 days and other higher risk amounts are reviewed individually for collectability. Balances that remain outstanding after reasonable collection efforts have been unsuccessful are written off through a charge to the valuation allowance and a credit to accounts receivable. Management reviews the allowance quarterly. The Company did not record a valuation allowance at December 31, 2019 or 2018. Inventories Inventories consist primarily of materials and supplies to be used in operations and are stated at the lower of cost or net realizable value. Costs for materials and supplies are determined primarily using the weighted-average cost method. Property and Equipment Property and equipment consists primarily of natural gas gathering assets, other pipeline assets, compressors and related facilities that are recorded at cost. Expenditures that extend the useful lives of assets are capitalized. Repairs, maintenance and renewals that do not extend the useful lives of assets are expensed as incurred. Leasehold improvements are amortized over the shorter of the useful life or lease term. Such assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment assessment is performed and the excess of the book value over the fair value is recorded as an impairment loss. The Company recorded Impairment expense of $3.5 million, $30.4 million and $3.4 million for the years ended December 31, 2019, 2018, and 2017, respectively. See Note 5 for further details. Depreciation is provided principally on a straight-line method over a period of 20 to 30 years, with the exception of miscellaneous equipment and vehicles, which are depreciated over a period ranging from 3 to 20 years. When items of property and equipment are sold or otherwise disposed of, any gains or losses are reported in the statements of operations. Gains on the disposal of property and equipment are recognized when they occur, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale. Asset Retirement Obligations An asset retirement obligation (“ARO”) is a legal obligation associated with the retirement of tangible long-lived assets that generally result from the acquisition, construction, development or normal operation of the asset. AROs are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a credit adjusted risk-free interest rate and increases due to the passage of time based on the time value of money until the obligation is settled. The Company routinely reviews and reassesses its estimates to determine if adjustments to the value of AROs are required. The Company recognizes a liability of a conditional ARO as soon as the fair value of the liability can be reasonably estimated. A conditional ARO is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. AROs have not been recognized for certain assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate. Such obligations will be recognized in the period when sufficient information becomes available to estimate a range of potential settlement dates. In addition to the conditional AROs, the Company may have AROs related to certain gathering and compression assets as a result of environmental and other legal requirements. The Company is not required to perform such work until it permanently ceases operations of the respective assets. As the Company considers the operational life of these assets to be indeterminable, an associated ARO cannot be calculated and is not recorded. Deferred Contract Costs Deferred contract costs of $6.6 million represent the asset created by the fair value of the Ohio Gathering Option that was recorded as permanent equity. This cost is amortized over the term of the arrangement into Facility expenses on the accompanying Statements of Operations. As of December 31, 2019 and 2018, the Company had recorded accumulated amortization of $3,296 and $2,861, respectively. As of December 31, 2019, the amortization of deferred contract costs is $435 for each of the next five years and $1,123 thereafter. Revenue Recognition Revenue is measured based on consideration specified in a contract with a customer. The Company recognizes revenue when it satisfies performance obligations by transferring control over a product or providing services to a customer. Performance obligations are determined based on the specific terms of the arrangements and the services offered and whether they are distinct. 9 The Company provides services under fee-based arrangements. Under fee-based arrangements, the Company receives a fee or fees for gathering and compression services provided to its customers. The revenue that the Company earns from these arrangements is generally directly related to the volume of natural gas and natural gas liquids that flows through the Company’s gathering system and is not directly dependent on commodity prices. These fee-based arrangements are reported as Revenue on the Statements of Operations. Revenue is recognized over time when the performance obligation is satisfied as services are provided in a series. The Company has elected to use the output measure of progress to recognize revenue based on the units gathered. The transaction price is based on variable components which are primarily dependent on volumes. Variable consideration will generally not be estimated at contract inception as the transaction price is specifically allocable to the services provided each period end. In instances in which tiered pricing structures do not reflect our efforts to perform, the Company will estimate variable consideration at contract inception. Amounts billed to customers for electricity and other costs to perform services are included in Revenue on the Statements of Operations. Customers generally pay monthly based on the services performed that month. Revenue and Expense Accruals The Company routinely makes accruals based on estimates for both revenues and expenses due to the timing of compiling billing information, receiving certain third-party information and reconciling the Company’s records with those of third parties. The delayed information from third parties includes, among other things, actual volumes transported and other operating expenses. The Company makes accruals to reflect estimates for these items based on its internal records and information from third parties. Estimated accruals are adjusted when actual information is received from third parties and the Company’s internal records have been reconciled. Income Taxes The Company is treated as a partnership for tax purposes under the provisions of the Internal Revenue Code. Accordingly, the accompanying financial statements do not reflect a provision for federal income taxes since the Company’s results of operations and related credits and deductions will be passed through and taken into account by its members in computing their respective tax liabilities. The Company is, however, subject to an income tax at the Cadiz, Ohio jurisdictional level. The Company accounts for income taxes under the asset and liability method. Deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates applied to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized as tax expense (benefit) from continuing operations in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to reflect the deferred tax assets at net realizable value as determined by management. All deferred tax balances are classified as long-term in the accompanying Balance Sheets. Environmental Costs Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. The Company recognizes remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure. Fair Value of Financial Instruments Management believes the carrying amounts of financial instruments, including cash, trade receivables, affiliate receivables and payables, other current assets, accounts payable, and accrued liabilities approximate fair value because of the short-term maturity of these instruments. Accounting Standards Recently Adopted ASU 2016-02, Leases In February 2016, the Federal Accounting Standards Board ("FASB") issued an Accounting Standards Update ("ASU"), which created Accounting Standards Codification Topic 842 ("ASC 842"), Leases. The Company adopted ASC 842, as of January 1, 2019, electing the transition method which permits entities to adopt the provisions of the standard using the modified retrospective approach without adjusting comparative periods. The Company also elected the practical expedients permitted under the transition guidance within the new standard, which among other things allowed us to grandfather the historical accounting conclusions until a reassessment event is present. The Company also elected the practical expedient to not recognize short-term leases on the balance sheet, the practical expedient related to right of way permits and land easements which allows the Company to carry forward our accounting treatment for those existing agreements, and the practical expedient to combine lease and non-lease components for the majority of our underlying classes of assets 10 except for our third-party contractor service and equipment agreements in which the Company is the lessee. The Company did not elect the practical expedient to combine lease and non-lease components for arrangements which the Company is the lessor. In instances where the practical expedient was not elected, lease and non-lease consideration is allocated based on relative standalone selling price. Right of use ("ROU") assets represent our right to use an underlying assets in which the Company obtains substantially all of the economic benefits and the right to direct the use of the asset during the lease term while lease liabilities represent the Company's obligation to make lease payments arising from the lease. Operating ROU assets and lease liabilities are recognized at commencement date based on the present value of lease payments over the lease term. The Company recognizes ROU assets and lease liabilities on the balance sheet for leases with a lease term of greater than one year. Payments that are not fixed at the commencement of the lease are considered variable and are excluded from the ROU assets and lease liability calculations. In the measurement of the Company's ROU assets and liabilities, the fixed lease payments in the agreement are discounted using a secured incremental borrowing rate for a term similar to the duration of the lease, as the Company's leases do not provide implicit rates. Operating lease expense is recognized on a straight-line basis over the lease term. The standard did not materially impact the Company's balance sheets, statements of income, cash flows or equity as a result of adoption. Not Yet Adopted ASU 2016-13, Credit Losses - Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued an ASU related to the accounting for credit losses on certain financial instruments. The guidance requires that for most financial assets, losses be based on an expected loss approach which includes estimates of losses over the life of exposure that considers historical, current and forecasted information. Expanded disclosures related to the methods used to estimate the losses as well as a specific disaggregation of balances for financial assets are also required. The Company plans to early adopt the standard for the fiscal year ended December 31, 2020. The application of this ASU is not expected to have a material impact on the Company's financial statements. 3. Affiliate Transactions The Company has no employees. Operating, maintenance and general and administrative services, including capitalizable engineering and construction management services, are provided to the Company under certain agreements with MarkWest Utica Operating or its affiliates. In addition, the Company has a short-term office lease agreement with an affiliate. From time to time, the Company may also sell to or purchase from affiliates, assets and inventory at the lesser of average unit cost or net realizable value. The Company has incurred the following amounts with affiliates related to the various agreements: Facility expenses Labor and benefits, net Rent expense General and administrative expenses Inventories Inventories sold to affiliates Inventories purchased from affiliates Property and equipment, net Capitalized engineering and construction management fees Capitalized labor and benefits Property and equipment sold to affiliates Property and equipment purchased from affiliates Year Ended December 31, 2018 2017 2019 $ 12,377 $ 531 12,601 $ 478 2,587 2,426 1,029 110 1,833 980 4,844 1,194 433 131 833 782 13,700 1,685 11,331 429 2,510 306 126 1,535 774 17,386 3,880 4. Significant Customers and Concentration of Credit Risk Financial instruments that potentially expose the Company to concentration of credit risk consist primarily of trade receivables, which are generally unsecured. The Company had certain customers whose trade receivable balances individually represented 10% or 11 more of the Company’s total trade receivables, or whose revenue individually represented 10% or more of the Company’s total revenue, as follows: Trade Receivables As of December 31, 2019 2018 2019 48% 45% 28% 65% Revenue Year Ended December 31, 2018 49% 44% 29% 62% 2017 26% 63% Customer A Customer B 5. Property and Equipment Property and equipment with associated accumulated depreciation is shown below: Gas gathering and compression equipment Pipeline right of way Land Construction in progress Property and equipment Less: accumulated depreciation Property and equipment, net December 31, 2019 $ 1,430,969 $ 174,196 2,754 18,937 1,626,856 353,081 1,273,775 $ December 31, 2018 1,325,940 165,530 2,754 57,028 1,551,252 292,177 1,259,075 $ Depreciation expense of $62 million, $58.4 million, and $68.2 million is included in Depreciation and accretion on the Statements of Operations for the years ended December 31, 2019, 2018, and 2017, respectively. As part of the Company's ongoing review of long- lived assets, the Company recorded an impairment $30.4 million in 2018 related to several compressor units and other miscellaneous construction in process ("CIP") inventory that were determined to not have a future use. The Company compared the carrying value of the compressor units and CIP inventory items to the estimated net realizable value to determine the impairment expense that was recorded for the years ended December 31, 2018. The Company recorded impairments of $3.5 million during 2019 and $3.4 million during 2017 related to CIP inventory from canceled projects that were determined to not have a future use. The Company also identified several assets with curtailed useful lives in which accelerated depreciation was recorded related to certain compressor units, dehydration units and right of way assets. The impact of this change resulted in increased depreciation expense and a reduction of net income of $11.8 million for the year ended December 31, 2017. 6. Asset Retirement Obligations The Company’s assets subject to AROs are primarily gas gathering pipelines and compression equipment. The Company also has land leases that require the Company to return the land to its original condition upon termination of the lease. The Company reviews current laws and regulations governing obligations associated with asset retirements and leases. The following is a reconciliation of the changes in the ARO liability for the years ended: Beginning asset retirement obligations Liabilities incurred Accretion expense Settlement Ending asset retirement obligations December 31, 2019 December 31, 2018 $ $ 3,371 $ 207 255 (254) 3,579 $ 3,159 72 140 — 3,371 At December 31, 2019 and 2018, there were no assets legally restricted for purposes of settling AROs. 12  7. Commitments and Contingencies Environmental Matters The Company is subject to federal, state and local laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for non-compliance. In 2015, representatives from the United States Environmental Protection Agency (“EPA”) and the United States Department of Justice conducted a raid on a pipeline launcher/receiver site owned by an affiliate of MarkWest Utica, which site was utilized for pipeline maintenance operations. In 2018, the Company, together with other MarkWest affiliates, entered into a Consent Decree with the EPA and the Pennsylvania Department of Environmental Protection by which it agreed to pay penalties and undertake supplemental environmental projects including monitoring and emission reduction projects at certain facilities. The Company paid its portion of the penalty in 2018 which was approximately $240 and has accrued $500 as of December 31, 2019 and 2018, respectively, for costs related to supplemental environmental projects. Legal During 2018, the Company was named in a lawsuit filed by Oxford Mining Company ("Oxford") alleging that their coal mining rights are superior to the Company's pipeline right of way through Oxford's Shugert North mine in Belmont County, Ohio. Following discovery, the trial court granted Oxford's motion for summary judgment in part, finding that Oxford has priority over the Company's right of way, and finding that the Company's pipeline constituted a trespass. On the Company's motion, the trial court dismissed Oxford's willful trespass damage claim and held that the jury would only be permitted to consider Oxford's lost profits. In January 2019, the jury returned a verdict in the amount of $5.5 million. The Company intends to appeal this determination. The $5.5 million has been accrued for at December 31, 2019 and 2018, respectively. The Company is also subject to a variety of risks and disputes, and is a party to various legal proceedings in the normal course of its business. The Company maintains insurance policies with coverage and deductibles that it believes are reasonable and prudent. However, the Company cannot assure that the insurance companies will promptly honor their policy obligations, or that the coverage or levels of insurance will be adequate to protect the Company from all material expenses related to future claims for property loss or business interruption to the Company, or for party claims of personal injury and property damage, or that the coverage or levels of insurance it currently has will be available in the future at economical prices. While it is not possible to predict the outcome of the legal actions with certainty, management is of the opinion that appropriate provisions and accruals for potential losses associated with all legal actions have been made in the financial statements and that none of these actions, either individually or in the aggregate, will have a material adverse effect on the Company’s financial condition, liquidity or results of operations. Other Contractual Obligations The Company has contractual commitments to acquire property and equipment totaling $1.8 million at December 31, 2019, which is committed for the year ended December 31, 2020. 8. Subsequent Events The Company has evaluated subsequent events from the balance sheet date through March 6, 2020, the date the financial statements were issued, and has determined that there are no material subsequent events that required additional disclosure. 13 

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