Summit Midstream Partners
Annual Report 2019

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, 2019 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 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 28, 2019, was $309,575,112. 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 14, 2020 93,613,194 units DOCUMENTS INCORPORATED BY REFERENCE None TABLE OF CONTENTS Table of Contents Organizational Chart Commonly Used or Defined Terms PART I Item 1. Business. Item 1A. Risk Factors. Item 1B. Unresolved Staff Comments. Item 2. Item 3. Item 4. PART II Item 5. Item 6. Item 7. Properties. Legal Proceedings. Mine Safety Disclosures. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. Selected Financial Data. 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. Item 14. Part IV Item 15. Item 16. Signature Page 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. Principal Accounting Fees and Services. Exhibits, Financial Statement Schedules. Form 10-K Summary. 2 3 4 8 8 26 64 65 66 66 67 67 70 72 107 108 161 161 164 165 165 171 190 193 195 196 196 200 201 Table of Contents ORGANIZATIONAL CHART 3 Table of Contents 2014 SRS 2016 Drop Down 2016 SRS 2017 SRS 2020 SRS 5.5% Senior Notes 7.5% Senior Notes 5.75% Senior Notes AMI associated natural gas 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 COMMONLY USED OR DEFINED TERMS the Partnership's shelf registration statement initially filed with the SEC in July 2014 and amended in February 2017 which registered an indeterminate amount of common units, debt securities and guarantees (superseded by the 2017 SRS) 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 the Partnership's shelf registration statement declared effective in November 2016 which registered up to $1.5 billion of equity and debt securities in primary offerings and 36,701,230 common units beneficially owned by Summit Investments and affiliates of the Sponsor (superseded by the 2020 SRS) the Partnership's automatic shelf registration statement of well-known seasoned issuers filed with the SEC in July 2017 which registered an indeterminate amount of common units, preferred units, debt securities and guarantees and subsequently amended in November 2017 the Partnership's shelf registration statement filed in November 2019 and declared effective in January 2020, which registered an indeterminate amount of common units, preferred units, warrants, rights, debt securities and guarantees in primary offerings and 51,234,693 common units beneficially owned by SMP Holdings and SMLP Holdings Summit Holdings' and Finance Corp.’s 5.5% senior unsecured notes due August 2022 Summit Holdings' and Finance Corp.’s 7.5% senior unsecured notes redeemed in March 2017 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 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 BDO USA, L.L.P. 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 4 Table of Contents Dodd-Frank Act DOT Double E Double E Project dry gas Energy Capital Partners EPA Epping EPU Equity Restructuring 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 MQD MVC NAAQS NEPA NGA 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; also known as the Sponsor 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 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 quarterly distribution minimum volume commitment national ambient air quality standard National Environmental Policy Act Natural Gas Act 5 Table of Contents 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 produced water PSD RCRA Red Rock Gathering Remaining Consideration 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 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 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 consideration to be paid to SMP Holdings in 2022 in connection with the 2016 Drop Down, the present value of which is reflected on our balance sheets as the Deferred Purchase Price Obligation 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 and by the Second Amendment to Third Amended and Restated Credit Agreement dated as of June 26, 2019 and further amended 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) the change in the Deferred Purchase Price Obligation, (viii) impairments and (ix) 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 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 6 Table of Contents Summit Marketing Summit Permian Summit Permian II Summit Permian Transmission Summit Utica Tcfe the Company the Partnership throughput volume Tioga Midstream unconventional resource basin VOC wellhead 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, LLC and its subsidiaries 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 7 Table of Contents Item 1. Business. PART I SMLP is a Delaware limited partnership formed in May 2012. References to "we" or "our" refer collectively to SMLP and its subsidiaries. For additional information, see Note 1 to the consolidated financial statements. Item 1. Business is divided into the following sections: • • • • • • Overview Business Strategies Our Midstream Assets Regulation of the Natural Gas and Crude Oil Industries Environmental Matters Other Information 8 Table of Contents 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. 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: • • 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 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. We are the owner-operator of, or have significant ownership interests in, the following gathering and transportation systems, which comprise our Core Focus Areas: • • • • • • • Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio; Ohio Gathering, a natural gas gathering system and a condensate stabilization facility operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio; Polar and Divide, a crude oil and produced water gathering system and transmission pipeline operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; Bison Midstream, an associated natural gas gathering system operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; Niobrara G&P, an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara and Codell shale formations in northeastern Colorado and southeastern Wyoming; and Summit Permian, an associated natural gas gathering and processing system operating in the northern Delaware Basin, which includes the Wolfcamp and Bone Spring formations, in southeastern New Mexico. Double E, a 1.35 Bcf/d natural gas transmission pipeline that is under development and will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas. 9 Table of Contents We are the owner-operator of the following gathering systems, which comprise our Legacy Areas: • • • Grand River, a natural gas gathering and processing system operating in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado; DFW Midstream, a natural gas gathering system operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and Mountaineer Midstream, a natural gas gathering system operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia. 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. Key customers in our Core Focus Areas are as follows: • • Utica Shale – XTO Energy Inc. ("XTO") and Ascent Resources - Utica, LLC ("Ascent") are the key customers for Summit Utica. Ohio Gathering – Ascent and Gulfport Energy Corporation ("Gulfport") are the key customers for Ohio Gathering; • Williston Basin – Whiting Petroleum Corp. ("Whiting"), Zavanna, LLC (“Zavanna”) and Bruin Williston Holdings, LLC (“Bruin”) are the key customers for Polar and Divide. Oasis Petroleum, Inc. ("Oasis") and a large U.S. independent crude oil and natural gas company, are the key customers for Bison Midstream. • • DJ Basin – HighPoint Resources Corporation ("HighPoint") and a large U.S. independent crude oil and natural gas company are the key customers for Niobrara G&P. Permian Basin – XTO is the key customer for Summit Permian. 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. Key customers in our Legacy Areas are as follows: • • • Piceance Basin – Caerus Oil & Gas LLC ("Caerus") and Terra Energy Partners LLC ("Terra") are the key customers for Grand River. Barnett Shale – Total Gas & Power North America, Inc. ("Total") is the key customer for DFW Midstream. Marcellus Shale – Antero Resources Corp. ("Antero") is the key customer for Mountaineer Midstream. 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, have 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 or re- invest in our Core Focus Areas. 10 Table of Contents Our financial results are primarily driven by volume throughput across our gathering systems and by expense management. During 2019, aggregate natural gas volume throughput averaged 1,397 MMcf/d and crude oil and produced water volume throughput averaged 105.3 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. We also earn revenues from the following activities that directly expose us to fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers on the Bison Midstream, Grand River and Summit Permian systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. During the year ended December 31, 2019, these additional activities accounted for approximately 20% of total revenues including marketing transactions, and approximately 14% of total revenues excluding marketing transactions. 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 3.2 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, whether by collecting gathering or processing fees on actual throughput or from cash payments to cover any MVC shortfall. As of December 31, 2019, we had remaining MVCs totaling 1.8 Tcfe. Our MVCs have a weighted-average remaining life of 5.6 years (assuming contracted minimum volume commitments 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 the amount of cash distributions we pay to our unitholders. For additional information on our results of operations, see Item 6. Selected Financial Data and the "Results of Operations" section included in the Item 7. MD&A. Our Sponsor and Summit Investments. Energy Capital Partners, together with its affiliated funds, is a private equity firm with over $19.0 billion in capital commitments that is focused on investing in North America's energy infrastructure. Energy Capital Partners has significant energy and financial expertise to complement its investment in us, including investments in the power generation, midstream oil and gas, electric transmission, energy equipment and services, environmental infrastructure and other energy-related sectors. Summit Investments, which was formed in 2009 by current and former members of our management team and our Sponsor, is the ultimate owner of our General Partner. We are managed and operated by the Board of Directors and executive officers of our General Partner, which is managed and operated by Summit Investments. As a result, due to its ownership interest in Summit Investments and its representation on Summit Investments' board of managers, Energy Capital Partners controls our General Partner and its activities, thereby controlling SMLP. 11 Table of Contents Our key business strategies are as follows: Business Strategies • • • • Maintaining our focus on fee-based revenue with minimal direct commodity price exposure. We intend to maintain our focus on providing midstream energy 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. Allocating capital to maximize unitholder value. We will seek to maximize unitholder value by allocating our available capital and maintaining our commitment to risk-informed stable cash flows. This may include a re-allocation of capital into new areas, existing areas or to satisfy other obligations of the Partnership, including the Deferred Purchase Price Obligation. In some cases, production from our customers in our Core Focus Areas is expected to grow in excess of our existing throughput capacity over time, which will create opportunities for additional midstream infrastructure development. We will continue to evaluate opportunistic divestitures or joint ventures of certain or our assets as part of this strategy, which could include certain assets located in our Core Focus Areas or Legacy Areas. For example, in March 2019, we sold the Tioga Midstream gathering system which was included in the Williston Basin segment, to affiliates of Hess Infrastructure Partners LP for a combined purchase price of approximately $90 million (see Note 17 to the consolidated financial statements). 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 energy infrastructure in our Core Focus Areas. 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. Our Midstream Assets Our midstream assets, including assets in which we have a significant ownership interest, currently operate in the following unconventional resource plays: Core Focus Areas • • • • • the Utica Shale, which is served by Summit Utica; Ohio Gathering, which operates in the Appalachian Basin and includes our ownership interests in OGC and OCC; the Williston Basin, which is served by Polar and Divide and Bison Midstream; the DJ Basin, which is served by Niobrara G&P; and the Permian Basin, which is served by Summit Permian. Legacy Areas • • • 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. 12 Table of Contents 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 lease additional acreage within our AMIs in the future, 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, which could reduce our ownership interests in OGC and/or OCC. For example, in 2019, 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 38.5% and 40% to 38.9%, respectively, as of December 31, 2019. 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 contracted monthly or annual minimum revenue stream. As of December 31, 2019, we had remaining MVCs totaling 1.8 Tcfe. Our MVCs had a weighted-average remaining life of 5.6 years (assuming contracted minimum volume commitments 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 2 and 9 to the consolidated financial statements. 13 Table of Contents Utica Shale The following table provides operating information regarding our Utica Shale reportable segment as of December 31, 2019. Utica Shale Aggregate throughput capacity (MMcf/d) 720 Average daily MVCs through 2023 (MMcf/d) Remaining MVCs (Bcf) Weighted- average remaining contract life (Years) Weighted- average remaining MVC life (Years) n/a n/a 9.5 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 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 total 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, 2019, we owned a 38.5% ownership interest in Ohio Gathering. For additional information, see Note 8 to the consolidated financial statements. 14 Table of Contents Williston Basin The following table provides operating information regarding our Williston Basin reportable segment as of December 31, 2019. 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) 73 Remaining MVCs (Bcfe) (1) 107 Weighted- average remaining contract life (Years) (1)(2) 3.0 Weighted- average remaining MVC life (Years) (1)(2) 2.5 (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. DJ Basin The following table provides operating information regarding our DJ Basin reportable segment as of December 31, 2019. DJ Basin Aggregate throughput capacity (MMcf/d) 60 Average daily MVCs through 2023 (MMcf/d) 9 Remaining MVCs (Bcf) 13 Weighted- average remaining contract life (Years) (1) 7.0 Weighted- average remaining MVC life (Years) (1) 3.1 (1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate). 15 Table of Contents 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. Permian Basin The following table provides operating information regarding our Permian Basin reportable segment as of December 31, 2019. Permian Basin (1) Aggregate throughput capacity (MMcf/d) 60 Average daily MVCs through 2023 (MMcf/d) Remaining MVCs (Bcf) Weighted- average remaining contract life (Years) Weighted- average remaining MVC life (Years) n/a n/a 8.4 n/a (1) Contract terms related to MVCs are excluded for confidentiality purposes. 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. Piceance Basin The following table provides operating information regarding our Piceance Basin reportable segment as of December 31, 2019. Piceance Basin Aggregate throughput capacity (MMcf/d) 1,151 Average daily MVCs through 2023 (MMcf/d) 434 Remaining MVCs (Bcf) 837 Weighted- average remaining contract life (Years) (1) 9.9 Weighted- average remaining MVC life (Years) (1) 5.7 (1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate). 16 Table of Contents 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 gathering services pursuant to primarily long-term and fee-based agreements with multiple producers, including its key customers, Caerus and Terra. 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 that gathers natural gas produced from directional wells targeting the liquids-rich Mesaverde formation. 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 Northwest Pipeline system 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 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. Barnett Shale The following table provides operating information regarding our Barnett Shale reportable segment as of December 31, 2019. 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 6.3 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 retain a fixed percentage of the natural gas that we gather or pass through a portion of the power expense to our customers. 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. The DFW Midstream system currently provides midstream services for the Barnett Shale reportable segment. Marcellus Shale The following table provides operating information regarding our Marcellus Shale reportable segment as of December 31, 2019. 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) Remaining MVCs (Bcf) Weighted- average remaining contract life (Years) Weighted- average remaining MVC life (Years) n/a 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. Volume throughput on the Mountaineer Midstream system is underpinned by MVCs from Antero. 17 Table of Contents The Mountaineer Midstream system, which is underpinned by a minimum revenue commitment from Antero, 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. 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. 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, our Double E Project, which is currently under consideration by FERC in Docket No. CP19-495-000 under Section 7(c) of the NGA for a certificate of public convenience and necessity, and is anticipated to provide interstate natural gas transmission service from the Delaware Basin in southeastern New Mexico to the Waha Hub in Texas, will be subject to FERC jurisdiction if approved. 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. 18 Table of Contents 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 will commence its five-year review of its index adjustment in 2020 with the new adjustment to become effective starting July 1, 2021. 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, will be taken into account in FERC’s next five-year review of index rate adjustments in 2020. 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 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 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. 19 Table of Contents 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 $1,291,894 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 $1,231,690 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 $1,212,866 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. The Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 established mandatory inspections for certain U.S. oil and natural gas transmission pipelines in high consequence areas. The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (“2011 Act”) reauthorized funding for federal pipeline safety programs through 2015, increased penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. In 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act reauthorized pipeline safety programs through 2019 and provided limited new authority, including the ability to issue emergency orders, while increasing transparency into the status of remaining actions required by the 2011 Act. As of the end of 2019, the PHMSA had not yet been reauthorized for funding through 2023, but the PHMSA indicates that its pipeline safety functions can continue to function, subject to restrictions in an appropriations act. 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 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. 20 Table of Contents In October 2019, the PHMSA issued three new final rules. One rule 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 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 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. 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 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. 21 Table of Contents 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. 22 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 result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate, which 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 new 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 September 2019, the EPA published a rule proposing to reconsider certain aspects of both the 2012 and 2016 rules. This proposed rule would remove sources in the transmission and storage segments from the regulated source category and would rescind the application of the NSPS and methane-specific requirements to these sources. The 2012 and 2016 rules remain in effect pending reconsideration. While we do not expect this rule to significantly impact our existing operations, future modifications or new construction may be adversely affected by the revised rule. 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. The September 2018 rule was challenged in the U.S. District Court for the Northern District of California almost immediately after issuance. The challenge is still pending. While the rule 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. 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 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 (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. 23 Table of Contents 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 recently been circulated by interested groups for potential consideration in upcoming elections, although none have yet obtained the requisite number of signatures. Further, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of 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 Colorado Oil and Gas Conservation Commission, which regulates the oil and gas industry in Colorado. 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. The EPA announced in April 2017 that it would review these regulations and in September 2019, the EPA published a rule proposing to reconsider certain aspects of the regulations. However, the regulations currently remain in effect. 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 rescission rule is currently subject to a legal challenge. 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. 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. 24 Table of Contents 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 intends to withdraw from the agreement. The earliest possible effective withdrawal date from the agreement is November 2020. However, there are no guarantees that the agreement will not be re-implemented in the United States, or re-implemented in part by certain state or local governments. 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. 25 Table of Contents Other Information Employees. SMLP does not have any employees. All of the employees required to conduct and support its operations are employed by Summit Investments, but these individuals are sometimes referred to as our employees. The officers of our General Partner manage our operations and activities. As of December 31, 2019, Summit Investments employed 261 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. Item 1A. Risk Factors. Item 1A. Risk Factors is divided into the following sections: • • • Risks Related to our Business Risks Inherent in an Investment in Us Tax Risks Risks Related to Our Business We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements of expenses incurred on our behalf by our General Partner, to enable us to sustain the distributions to holders of our common units. We may not have sufficient available cash from operating surplus each quarter to sustain the distributions to holders of our common units. 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; 26 Table of Contents • • 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 will have available for distribution to our common unitholders will depend 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, including the Deferred Purchase Price Obligation; the amount of distributions on our preferred stock or the preferred stock of our subsidiaries; 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; adverse legal judgments, fines and settlements; distributions paid on our Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series A Preferred Units”); 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, and Whiting, a customer on our Williston Basin gathering system, each account 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 system and, therefore, materially adversely affect our revenues, cash flows and ability to make cash distributions to our unitholders. 27 Table of Contents 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’ business 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’ ability 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. Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations and cash flows and reduce our 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 than if we did not have such limited diversity on our financial condition, results of operations and cash flows. 28 Table of Contents 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. Fluctuations in energy prices can also greatly affect the development of new crude oil and natural gas reserves. Drilling and production activity generally decreases 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 the recent coronavirus, which may 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; 29 Table of Contents • • • • • • 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. 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. If our customers do not increase the volumes they provide to our gathering systems, our ability to sustain 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 sustain 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 sustain cash distributions to our unitholders. 30 Table of Contents 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. 31 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. 32 Table of Contents 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 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 location 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. 33 Table of Contents 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. 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 these risks. These risks 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 minimum volume commitments 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. Our insurance coverage is provided by policies that cover us and Summit Investments. Therefore, it is possible that a claim by Summit Investments could exhaust insurance coverage and leave SMLP and its subsidiaries exposed to risk of loss should they experience a loss during the same policy cycle. In addition, 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 and/or claims by Summit Investments may increase rates on all of the insured-asset group, including those owned by SMLP and its subsidiaries. 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. 34 Table of Contents 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 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. 35 Table of Contents Limited access 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 our 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) the impact of any secondary offering of common units by Summit Investments or the Sponsor, (vi) increasing disfavor among many investors towards investments in fossil fuel companies and (vii) 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, we do not have a contractual commitment from our Sponsor or Summit Investments to provide any direct or indirect financial assistance to us. 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 recently announced our second large reduction in our common unit distribution in a year, and this reduction may further reduce demand for our common units. 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 maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then- current distribution rate. 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. 36 Table of Contents 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, 2019, we had $1.48 billion of indebtedness outstanding and the unused portion of our $1.25 billion Revolving Credit Facility totaled $563.9 million. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of December 31, 2019 was approximately $100 million. See Note 10 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. 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. 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. 37 Table of Contents 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 SMLP’s revolving credit facility and total outstanding debt of $1.48 billion (inclusive of $800.0 million of senior unsecured notes), SMLP’s total leverage ratio and senior secured leverage ratio (as defined in the credit agreement) as of December 31, 2019, were 5.1 to 1.0 and 2.3 to 1.0, respectively, relative to maximum threshold limits of 5.5x and 3.75x. 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. 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. 38 Table of Contents 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 $188.7 million, $7.2 million and $60.5 million in 2017, 2018 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. Changes in the method of determining the London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt. Amounts drawn under our current debt agreements, including the Revolving Credit Facility, may bear interest at rates based on LIBOR. On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The Revolving Credit Facility does not provide for a mechanism to reflect the establishment of an alternative rate of interest upon the phase-out of LIBOR. Under the Revolving Credit Facility, if the agent is unable to determine LIBOR, all existing LIBOR loans will convert to base rate loans at the end of their respective interest periods, and we will only have access to these base rate loans. We have not yet pursued any technical amendment or other contractual alternative to address this matter and are currently evaluating the impact of the potential replacement of the LIBOR interest rate. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial market could have a material adverse effect on our financial condition, results of operations and cash flows. 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, 2019, we derived 20% 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 Bison Midstream, Grand River and Summit Permian systems, (ii) natural gas and crude oil marketing services in and around our gathering systems, (iii) the sale of natural gas we retain from certain DFW Midstream customers and (iv) the sale of condensate we retain from our gathering services at Grand River. 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 39 Table of Contents 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. 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 North Dakota Industrial Commission 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. In July 2018, 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. In November 2018, PHMSA also increased the maximum penalties for violating federal safety standards, which are subject to future increases to account for inflation. In October 2019, PHMSA issued three new final rules. One rule 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 PHMSA to issue an emergency order without advance notice or opportunity for a hearing. The other two rules 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 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. 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 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. 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. 40 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 recently been circulated by interested groups for potential consideration in upcoming elections, although none have yet obtained the requisite number of signatures. Further, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of 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. 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 (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 October 2018, the EPA published a proposed rule that would amend certain requirements of NSPS OOOOa. Among other things, the proposed rule would reduce monitoring frequencies for fugitive emissions and clarify and streamline certain other requirements. In September 2019, the EPA published another rule proposing amendments to the June 2016 rule that would remove sources in the transmission and storage segments from the regulated source category and would rescind the application of the NSPS and methane-specific requirements to these sources. However, the 2016 regulations currently remain in effect. 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 rescission rule is currently subject to a legal challenge. 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. 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. 41 Table of Contents 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, which is currently under consideration by FERC in Docket No. CP19-495-000, and 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 approved. 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 $1,291,894 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 $1,231,690 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 $1,212,866 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 complaints with state regulators in an effort to resolve access issues, rate grievances and other matters. Other state and municipal 42 Table of Contents 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 will also reflect the impact of the corporate income tax reduction enacted as part of the Tax Cuts and Jobs Act of 2017, will be used in FERC’s next five-year review and determination of the index rate adjustment, which will occur in 2020 and will become effective on July 1, 2021. 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 —Air Emissions" 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. 43 Table of Contents 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 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 2020 presidential and congressional elections may result in a change in administration and control of Congress with the potential consequence of 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. In October 2019, the PHMSA issued three new final rules. One rule 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 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 44 Table of Contents integrity management, and use certain safety features on in-line inspection equipment. 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. 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. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although 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 GHG emission reduction requirements. However, in October 2018, the EPA published a proposed rule that would amend certain requirements of NSPS OOOOa. Among other things, the proposed rule would reduce monitoring frequencies for fugitive emissions and clarify and streamline certain other requirements. In September 2019, the EPA published proposed amendments to the rule that would remove sources in the transmission and storage segments from the regulated source category and would rescind the application of the NSPS and methane-specific requirements to these sources. The 2016 regulation currently remains in effect. 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. 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. Although we cannot currently determine the effect of a potential regulatory framework developed by the ENMRD and the NMED or 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. 45 Table of Contents 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 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 intends to withdraw from the agreement. The earliest possible effective withdrawal date from the agreement is November 2020. However, if and to the extent the United States implements this agreement, it 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. 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. 46 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. 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. 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 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. 47 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. 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 certain an increasing number of financial institutions, funds, individual investors and other sources of capital restricting or eliminating their investment in fossil fuel-related activities. 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. 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; 48 Table of Contents • • 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. 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. 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. 49 Table of Contents Risks Inherent in an Investment in Us Summit Investments indirectly owns and controls our General Partner, which has sole responsibility for conducting our business and managing our operations and limited duties to us and our unitholders. Our General Partner and its affiliates have conflicts of interest with us and they may favor their own interests to the detriment of us and our unitholders. Summit Investments controls our General Partner and has authority to appoint all of the officers and directors of our General Partner, some of whom are officers, directors or principals of Energy Capital Partners, the entity that controls Summit Investments. Although our General Partner has a duty to manage us in a manner that is in our best interests, the directors and officers of our General Partner also have a duty to manage our General Partner in a manner that is in the best interests of its owner. Conflicts of interest will arise between Summit Investments and its owners and our General Partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our General Partner may favor its own interests and the interests of Summit Investments and its owners over our interests and the interests of our unitholders. These conflicts include the following situations, among others: • • • • • • • • • • • • Neither our Partnership Agreement nor any other agreement requires Summit Investments or its owners to pursue a business strategy that favors us, and the directors and officers of Summit Investments have a fiduciary duty to make these decisions in the best interests of the owners of Summit Investments, which may be contrary to our interests. Summit Investments may choose to shift the focus of their investment and growth to areas not served by our assets; Summit Investments is not limited in its ability to compete with us and in the future may offer business opportunities to third parties without first offering us the right to bid for them; Our General Partner is allowed to take into account the interests of parties other than us, such as Summit Investments and its owners, in resolving conflicts of interest; Our Partnership Agreement replaces the fiduciary duties that would otherwise be owed by our General Partner to us and our unitholders with contractual standards governing its duties to us and our unitholders. These contractual standards limit our General Partner's liabilities and the rights of our unitholders with respect to actions that, without the limitations, might constitute breaches of fiduciary duty; Except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval; Our General Partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership interests and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders; Our General Partner determines which costs incurred by it are reimbursable by us; Our Partnership Agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; Our General Partner intends to limit its liability regarding our contractual and other obligations; Our General Partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units; Our General Partner controls the enforcement of the obligations that it and its affiliates owe to us; and Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us. 50 Table of Contents Our general partner interest or the control of our General Partner may be transferred to a third party without unitholder consent. If Energy Capital Partners, the private equity firm that controls Summit Investments, consummates a transaction involving a sale or other disposition of its interests in Summit Investments, the transaction would result in a change of control of SMLP because Summit Investments indirectly owns and controls our General Partner. In addition, our General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our Partnership Agreement does not restrict the ability of Summit Investments to transfer all or a portion of its ownership interest in our General Partner to a third party. The owner of Summit Investments, or new members of our General Partner, as applicable, would then be in a position to replace the Board of Directors and officers of our General Partner with their own designees and thereby exert significant control over the decisions made by the Board of Directors and officers. This effectively permits a change of control without the vote or consent of the unitholders. The equity interests in our General Partner are pledged as collateral for SMP Holdings’ senior secured term loan facility; in the event SMP Holdings is unable to meet its obligations under that term loan facility, including as a result of a reduction in the amount, or elimination, of the distributions we pay to our unitholders, or is subject to certain bankruptcy or insolvency related events, SMP Holdings’ lenders may gain control of our general partner. On March 21, 2017, SMP Holdings entered into a term loan agreement, which we refer to as the SMP Holdings Term Loan Facility. SMP Holdings’ ownership interest in our general partner is subject to a lien under the SMP Holdings Term Loan Facility. In the event SMP Holdings is unable to satisfy its obligations under the SMP Holdings Term Loan Facility, including as a result of a reduction in the amount, or elimination, of the distributions we pay to our unitholders, including SMP Holdings, and the lenders foreclose on the collateral securing such obligations, the lenders will own our general partner, and effectively all of its assets, which include the general partner interest in us. In such event, SMP Holdings’ lenders would own the entity that controls our management and operation. Moreover, in the event SMP Holdings becomes insolvent or is declared bankrupt, our general partner also may be deemed insolvent or declared bankrupt. Under the terms of our partnership agreement, certain bankruptcy or insolvency related events of our general partner may cause a dissolution of our partnership. Our Sponsor is not limited in its ability to compete with us and is not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could materially adversely affect our results of operations and cash available for distribution to our unitholders. Although it controls Summit Investments, our Sponsor may compete with us for investment opportunities and may own interests in entities that compete with us. Our Sponsor is not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, our Sponsor and Summit Investments may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Pursuant to the terms of our Partnership Agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our General Partner, its officers and directors or any of its affiliates, including Summit Investments and our Sponsor and its respective executive officers, directors and principals. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our General Partner and result in less than favorable treatment of us and our unitholders. 51 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; 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 Sponsor may sell units in the public markets, which could reduce the market price of our outstanding common units. Of the 93,493,473 common units outstanding at December 31, 2019, Summit Investments beneficially owned 45,318,866 common units and a subsidiary of Energy Capital Partners directly owned 5,915,827 common units. If these entities were to dispose of a substantial portion of these units in the public market, whether in a single transaction or a series of transactions, it could reduce the market price of our common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future. Our Sponsor has rights to require underwritten offerings that could limit our ability to raise capital in the public equity market. Our Sponsor and any other unitholders that have registration rights may require us to conduct underwritten offerings of our common units. If we want to access the capital markets (debt and equity), those unitholders’ ability to sell a portion of their common units could satisfy investors’ demand for our common units, reduce the market price for our common units, or interfere with our financing plans, and thereby could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. 52 Table of Contents If we fail to develop or 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 develop and 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 implement and 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. Our Partnership Agreement replaces our General Partner's fiduciary duties to unitholders with contractual standards governing its duties. Our Partnership Agreement contains provisions that eliminate fiduciary duties to which our General Partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our Partnership Agreement permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner or otherwise, free of any duties to us and our unitholders, other than the implied contractual covenant of good faith and fair dealing. This entitles our General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our General Partner may make in its individual capacity include, among others: • • • • • • • how to allocate corporate opportunities among us and its affiliates; whether to exercise its limited call right; whether to seek approval of the resolution of a conflict of interest by the Conflicts Committee; how to exercise its voting rights with respect to the units it owns; whether to exercise its registration rights; whether to transfer any units it owns to a third party; and whether or not to consent to any merger or consolidation of the partnership or amendment to the Partnership Agreement. By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the Partnership Agreement, including the provisions discussed above. 53 Table of Contents Our Partnership Agreement limits the liabilities 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. 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; 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 General Partner intends to limit its liability regarding our obligations. Our General Partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our General Partner or its assets. Our General Partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our General Partner. Our Partnership Agreement provides that any action taken by our General Partner to limit its liability is not a breach of our General Partner's fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our General Partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders. 54 Table of Contents Reimbursements due to our General Partner and its affiliates for expenses incurred on our behalf will reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our General Partner. Prior to making any distribution on our common units, we will reimburse our General Partner and its affiliates, including Summit Investments, for expenses they incur and payments they make on our behalf. Under our Partnership Agreement, we will reimburse our General Partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our General Partner's employees and executive officers who provide services necessary to run our business. Our Partnership Agreement provides that our General Partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses to our General Partner and its affiliates will reduce the amount of available cash to pay cash distributions to our unitholders. The New York Stock Exchange does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements. We have listed our common units on the New York Stock Exchange. Because we are a publicly traded partnership, the New York Stock Exchange does not require us to have, and we do not have, a majority of independent directors on our General Partner's Board of Directors or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the New York Stock Exchange's shareholder approval rules. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the New York Stock Exchange corporate governance requirements. Holders of our common units have limited voting rights and are not entitled to elect our General Partner or its directors. Unlike the holders of common stock in a corporation, holders of our common units have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders have no right on an annual or ongoing basis to elect our General Partner or its Board of Directors. The Board of Directors has been chosen by Summit Investments. Furthermore, if our unitholders are dissatisfied with the performance of our General Partner, they have little ability to remove our General Partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our Partnership Agreement also contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management. Even if holders of our common units are dissatisfied, they may not be able to remove our General Partner without its consent. The vote of the holders of at least 66 2/3% of all outstanding limited partner units voting together as a single class is required to remove our General Partner. As of December 31, 2019, Summit Investments beneficially owned 45,318,866 common units out of 93,493,473 outstanding common units, representing a voting block sufficient to prevent the other limited partners from removing our General Partner. 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. 55 Table of Contents 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. 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. Summit Investments or our Sponsor may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units. As of December 31, 2019, Summit Investments beneficially owned 45,318,866 common units out of 93,493,473 outstanding common units and a subsidiary of Energy Capital Partners directly owned 5,915,827 common units. The sale of any of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop. 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. 56 Table of Contents As of December 31, 2019, Summit Investments beneficially owned 45,318,866 common units out of 93,493,473 outstanding common units and a subsidiary of Energy Capital Partners directly owned 5,915,827 common units. As such, our General Partner and its affiliates controlled a total of 51,234,693 common units, or 54.8% of our common units outstanding as of December 31, 2019. 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 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. 57 Table of Contents 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. Our 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, our Subsidiary Series A Preferred Units have priority over the common unitholders with respect to the cash flow from Permian Holdco. In addition, (i) prior to December 15, 2022, distributions on the Series A Preferred Units accrue 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%. The distribution rate of the Subsidiary Series A Preferred Units is 7.00% per annum of the $1,000 issue amount per outstanding Permian Holdco 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 or (B) declare or pay any distribution to common unitholders out of capital surplus. 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 the tax reform law known as the Tax Cuts and Jobs Act (the “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. 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. 60 Table of Contents 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,” (including, under proposed Treasury Regulations, our deduction for distributions on our Series A Preferred Units) 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. 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. 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 U.S. federal income 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 Department and the IRS suspended these rules for transfers of certain publicly traded partnership interests, including transfers of our common units, until regulations or other guidance has been issued. In May 2019, the IRS issued proposed Treasury Regulations that would require withholding on open market transactions, effective 60 days after the issuance of final Treasury Regulations, but in the case of a transfer made through a broker, would exclude a partner’s share of liabilities from the amount realized. In addition, the obligation to withhold would be imposed on the broker instead of the transferee. It is not clear if or when the proposed Treasury Regulations will be finalized and in what form, or if other guidance will be issued. Tax-exempt entities and non-U.S. persons should consult a tax advisor before investing in our units. 61 Table of Contents 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. 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. 62 Table of Contents Investment in the Series A Preferred Units by tax-exempt investors, such as employee benefit plans and individual retirement accounts, 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. 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. 63 Table of Contents If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, 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 for tax years beginning after 2017, 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. Item 1B. Unresolved Staff Comments. Not applicable. 64 Table of Contents Item 2. Properties. Our gathering systems, the unconventional resource basins in which they operate, and the reportable segments in which they are reported are as follows: • • • • • • • • • Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio, is included in the Utica Shale reportable segment; Polar and Divide, a crude oil and produced water gathering system and transmission pipeline operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota, is included in the Williston Basin reportable segment; Bison Midstream, an associated natural gas gathering system operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota, is included in the Williston Basin reportable segment; Niobrara G&P, an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara and Codell shale formations in northeastern Colorado and southeastern Wyoming, is included in the DJ Basin reportable segment; Summit Permian, an associated natural gas gathering and processing system operating in the northern Delaware Basin, which includes the Wolfcamp and Bone Spring formations, in southeastern New Mexico, is included in the Permian Basin reportable segment; Double E, a 1.35 Bcf/d natural gas transmission pipeline that is under development and will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas; Grand River, a natural gas gathering and processing system operating in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado, is included in the Piceance Basin reportable segment; DFW Midstream, a natural gas gathering system operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas, is included in the Barnett Shale reportable segment; and Mountaineer Midstream, a natural gas gathering system operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia, is included in the Marcellus Shale reportable segment. 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 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. On March 2, 2020, we relocated our corporate headquarters to Houston, Texas from the Woodlands, Texas. 65 Table of Contents 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. The U.S. Department of Justice has 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. 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 rupture. On March 3, 2016, the Partnership agreed to acquire, among other things, substantially all of the issued and outstanding membership interests of Meadowlark Midstream from an indirect, wholly owned subsidiary of Summit Investments in connection with the 2016 Drop Down. The Contribution Agreement executed in connection with the 2016 Drop Down contains customary representations and warranties, and Summit Investments has agreed to indemnify the Partnership with respect to certain losses, including losses associated with the above described incident. While we cannot predict the ultimate outcome of this matter with certainty, we believe at this time that it is not likely that the Partnership or our General Partner will be subject to any material liability as a result of any governmental proceeding related to the incident. On October 18, 2019, a petition was filed in the District Court of Tarrant County, Texas by Sage Natural Resources, LLC (the “plaintiff”) against us and certain of our affiliates. The plaintiff is a party to a gathering agreement and a gas marketing agreement with DFW Midstream. In its petition, the plaintiff alleges various claims relating to fees owed pursuant to the terms of these agreements, including breach of contract, fraud, fraudulent inducement, tortious interference, and negligent misrepresentation, as well as certain discriminatory rate claims under Texas law. The plaintiff is disputing its multi-year MVC shortfall payment in the amount of approximately $7.3 million that came due in the fourth quarter of 2019 and seeks a rescission of the gas marketing agreement and the gas gathering agreement, as well as actual and exemplary damages and attorney’s fees. While we cannot predict the ultimate outcome of this matter with certainty, we do not believe that it is likely that we or our affiliates will be subject to any material liability as a result of this matter and are defending ourselves vigorously against the plaintiff’s claims. In addition, we are actively pursuing collection of the multi-year MVC shortfall payment from both the plaintiff and its parent, which guaranteed Sage's performance. 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 February 14, 2020, there were approximately 10,744 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 for the quarterly period ended December 31, 2019. The 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. Our Cash Distribution Policy and Restrictions on Distributions General 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. 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. Pursuant to the Equity Restructuring Agreement, our general partner interest was converted into a non-economic general partner interest. For additional information, see Note 12 to the consolidated financial statements. 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. 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. 67 Table of Contents • • • 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 (including common units beneficially owned by Summit Investments). As of December 31, 2019, Summit Investments, which is the ultimate owner of our General Partner, beneficially owned 45,318,866 common units and a subsidiary of Energy Capital Partners 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. Preferred Unit Distributions Series A Preferred Units In November 2017, we issued 300,000 Series A Preferred Units representing limited partner interests in the Partnership at a price to the public of $1,000 per unit. We used the net proceeds of $293.2 million (after deducting underwriting discounts and offering expenses) to repay outstanding borrowings under our Revolving Credit Facility. 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 12 to the consolidated financial statements for additional details. Subsidiary Series A Preferred Units In December 2019, Permian Holdco issued 30,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit. Permian Holdco used the net proceeds of $27.4 million (after deducting offering expenses) to fund capital calls associated with the Double E Project. 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. 68 Table of Contents 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 12 to the consolidated financial statements for additional details. Stock Performance Table The following graph compares the cumulative total unitholder return on our common units to the cumulative total return of the S&P 500 Stock Index and the Alerian MLP Index for the five years ended December 31, 2019 by assuming $100 was invested in each investment option as of December 31, 2014. The Alerian MLP Index is the leading gauge of energy master limited partnerships, or MLPs, and is calculated using a float-adjusted, capitalization-weighted methodology. Issuer Purchases of Equity Securities We made no repurchases of our common units during the quarter or year ended December 31, 2019. Sponsor Purchases of Equity Securities Our Sponsor made no repurchases of our common units during the quarter or year ended December 31, 2019. 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 6. Selected Financial Data. The selected consolidated financial data presented as of and for the years ended December 31, 2019, 2018, 2017, 2016 and 2015 have been derived from the consolidated financial statements of SMLP. The following table presents selected balance sheet and other data as of the date indicated. 2019 2018 December 31, 2017 (In thousands, except per-unit amounts) 2016 2015 Balance sheet data: Total assets Total long-term debt Deferred Purchase Price Obligation Mezzanine capital Partners' capital Other data: Market price per common unit $ 2,573,451 $ 3,020,562 $ 2,894,793 $ 3,115,179 $ 3,164,672 1,267,270 — — 1,747,299 1,257,731 383,934 — 1,221,224 1,051,192 362,959 — 1,389,669 1,240,301 563,281 — 1,169,673 1,470,299 178,453 27,450 763,516 $ 3.01 $ 10.05 $ 20.50 $ 25.15 $ 18.73 The following table presents selected statements of operations and cash flows as well as other financial data for the annual periods indicated. Statements of operations data: Total revenues Total costs and expenses (1) Interest expense Early extinguishment of debt Deferred Purchase Price Obligation Loss from equity method investees (2) Net (loss) income (Loss) earnings per limited partner unit: Common unit - basic Common unit - diluted Subordinated unit - basic and diluted (3) Statements of cash flows data: Capital expenditures (other than acquisition capital expenditures) Contributions to equity method investees Investment in equity method investee Acquisition capital expenditures (4) Purchase of noncontrolling interest Other financial data: Distributions declared per unit (5) $ $ $ 2019 2018 Year ended December 31, 2017 (In thousands, except per-unit amounts) 2016 443,528 $ 402,340 74,429 — (1,982) (337,851) (369,833) 506,653 $ 371,702 60,535 — 20,975 (10,888) 42,351 488,741 $ 510,577 68,131 22,039 (200,322) (2,223) 86,050 402,362 $ 290,582 63,810 — 55,854 (30,344) (38,187) (4.84) $ (4.84) 0.06 $ 0.06 0.99 $ 0.98 (0.71) $ (0.71) 2015 400,557 557,735 59,092 — — (6,563) (222,228) (3.20) (3.20) (2.88) 182,291 $ — 18,316 — — 200,586 $ 4,924 — — 10,981 124,215 $ 25,513 — — 797 142,719 $ 31,582 — 866,858 — 272,225 86,200 — 288,618 — $ 1.438 $ 2.300 $ 2.300 $ 2.300 $ 2.270 (1) Includes (i) long-lived asset impairments of $60.5 million in 2019, (ii) a goodwill impairment of $16.2 million in 2019, (iii) long-lived asset impairments of $3.9 million in 2018, (iv) long-lived asset impairments of $101.9 million and contract intangible asset impairments of $85.2 million in 2017, and (v) goodwill impairments of $248.9 million and environmental remediation expenses of $21.8 million in 2015. See Notes 5, 6, 7 and 16 to the consolidated financial statements. (2) Includes (i) an impairment of our equity method investment in OGC of $329.7 million and an impairment in OCC of $6.3 million in 2019 and (ii) our 40% share, or $5.7 million and $1.4 million in asset impairments recognized by Ohio Gathering in December 2018 and 2017. In addition, 2018 includes our 40% share, or $2.0 million, of an estimated legal contingency. See Note 8 to the consolidated financial statements. 70 Table of Contents (3) The subordination period ended on February 16, 2016 and all 24,409,850 subordinated units converted to common units on a one-for-one basis. (4) Reflects cash and noncash consideration, including working capital and capital expenditure adjustments paid (received), for acquisitions and/or drop downs (see Notes 12 and 17 to the consolidated financial statements). (5) Represents distributions declared in a given period. For example, for the year ended December 31, 2019, represents the distributions paid in February 2019, in May 2019, in August 2019 and in November 2019. The preceding tables should be read in conjunction with MD&A and the consolidated financial statements and notes thereto. 71 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 SMLP and its subsidiaries. As a result, the following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in this report. Among other things, the consolidated financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in Forward-Looking Statements. Actual results may differ materially from those contained in any forward-looking statements. The discussion of our financial condition and results of operations for the year ended December 31, 2017 included in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2018 is incorporated by reference into this MD&A. This MD&A comprises the following sections: • • • • • • • Overview Trends and Outlook How We Evaluate Our Operations Results of Operations Liquidity and Capital Resources Critical Accounting Estimates Forward-Looking Statements Overview We are a value-driven limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in unconventional resource basins, primarily shale formations, in the continental United States. We classify our midstream energy infrastructure assets into two categories: • • Core Focus Areas – core producing areas of basins in which we expect our gathering systems to experience greater long-term growth, driven by our customers’ ability to generate more favorable returns and support sustained drilling and completion activity in varying commodity price environments. In the near-term, we expect to concentrate the majority of our capital expenditures in our Core Focus Areas. Our Utica Shale, Ohio Gathering, Williston Basin, DJ Basin and Permian Basin reportable segments (as described below) comprise our Core Focus Areas. Legacy Areas – production basins in which we expect volume throughput on our gathering systems to experience relatively lower long-term growth compared to our Core Focus Areas, given that our customers require relatively higher commodity prices to support drilling and completion activities in these basins. Upstream production served by our gathering systems in our Legacy Areas is generally more mature, as compared to our Core Focus Areas, and the decline rates for volume throughput on our gathering systems in the Legacy Areas are typically lower as a result. We expect to continue to reduce our near-term capital expenditures in these Legacy Areas. Our Piceance Basin, Barnett Shale and Marcellus Shale reportable segments (as described below) comprise our Legacy Areas. We are the owner-operator of or have significant ownership interests in the following gathering and transportation systems, which comprise our Core Focus Areas: • • Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio; Ohio Gathering, a natural gas gathering system and a condensate stabilization facility operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio; 72 Table of Contents • • • • • Polar and Divide, a crude oil and produced water gathering system and transmission pipeline operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; Bison Midstream, an associated natural gas gathering system operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; Niobrara G&P, an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara and Codell shale formations in northeastern Colorado and southeastern Wyoming; Summit Permian, an associated natural gas gathering and processing system operating in the northern Delaware Basin, which includes the Wolfcamp and Bone Spring formations, in southeastern New Mexico; and Double E, a 1.35 Bcf/d natural gas transmission pipeline that is under development and will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas. We are the owner-operator of the following gathering systems, which comprise our Legacy Areas: • • • Grand River, a natural gas gathering and processing system operating in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado; DFW Midstream, a natural gas gathering system operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and Mountaineer Midstream, a natural gas gathering system operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia. For additional information on our organization and systems, see Notes 1 and 4 to the consolidated financial statements. Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn revenues from the following activities that directly expose us to fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers on the Bison Midstream, Grand River and Summit Permian systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. During the year ended December 31, 2019, these additional activities accounted for approximately 20% of total revenues including marketing transactions, and approximately 14% of total revenues excluding marketing transactions. We also have indirect exposure to changes in commodity prices in that persistently low commodity prices may cause our customers to delay and/or cancel drilling and/or completion activities or temporarily shut-in production, which would reduce the volumes of natural gas and crude oil (and associated volumes of produced water) that we gather. If certain of our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, the associated MVCs, if any, ensure that we will earn a minimum amount of revenue. 73 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, 2019, 2018 and 2017" section herein. Net (loss) income 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) Contributions to equity method investees Investment in equity method investee Distributions to common unitholders Distributions to Series A Preferred unitholders Issuance of senior notes Tender and redemption of senior notes Net borrowings (repayments) under Revolving Credit Facility Proceeds from issuance of Series A preferred units, net of costs (2) Proceeds from ATM Program common unit issuances, net of costs $ $ $ $ 2019 Year ended December 31, 2018 (In thousands) 2017 (369,833) $ 42,351 $ 86,050 29,292 $ 39,126 69,437 18,668 (879) 98,765 43,043 20,051 182,337 $ 182,291 — 18,316 116,624 $ 28,500 — — 30,285 $ 39,969 76,701 7,558 (1,200) 111,042 43,268 24,267 227,929 $ 200,586 4,924 — 180,705 $ 28,500 — — 34,011 41,246 66,413 6,624 — 111,113 46,232 23,888 237,832 124,215 25,513 — 179,103 2,375 500,000 (300,000) 211,000 205,000 (387,000) 27,392 — — — 293,238 17,078 (1) See "Liquidity and Capital Resources" herein and Note 4 to the consolidated financial statements for additional information on capital expenditures. (2) Reflects proceeds from the issuance of Series A preferred units. Year ended December 31, 2019. The following items are reflected in our financial results: • • • In December 2019, we identified certain triggering events which indicated that our equity method investment in Ohio Gathering could be impaired. We completed an other-than-temporary impairment analysis to determine the potential equity method impairment charge to be recorded on our consolidated financial statements. As a result, an impairment charge of approximately $329.7 million was recorded in the loss from equity method investees caption on the consolidated statement of operations. In September 2019, in connection with our annual impairment evaluation, we determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value and we recognized a goodwill impairment charge of $16.2 million. In March 2019, certain events occurred which indicated that certain long-lived assets in the DJ Basin and Barnett Shale reporting segments could be impaired. Consequently, we performed a recoverability assessment of certain assets within these reporting segments. In the DJ Basin, we determined certain processing plant assets related to our 20 MMcf/d plant would no longer be operational due to our expansion plans for the Niobrara G&P system and we recorded an impairment charge of $34.7 million related to these assets. In the Barnett Shale, we determined certain compressor station assets would be shut down and de- commissioned and we recorded an impairment charge of $10.2 million related to these assets. 74 Table of Contents • • • • On November 7, 2019, we and SMP Holdings entered into a second amendment (the “Second Amendment”) to the Contribution Agreement between us and SMP Holdings dated February 25, 2016, as amended. On November 15, 2019, we made a cash payment of $51.75 million and issued 10,714,285 common units to SMP Holdings (the “November 2019 Prepayment”). In addition, the parties reduced the Remaining Consideration due to SMP Holdings by $19.25 million. Following the November 2019 Prepayment, the Remaining Consideration is $180.75 million. The parties also extended the final date by which we are obligated to deliver the Remaining Consideration to January 15, 2022. The Remaining Consideration remains payable to SMP Holdings in (i) cash, (ii) our common units or (iii) a combination of cash and our common units, and interest continues to accrue (and is payable quarterly in cash) at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020. The form(s) of Remaining Consideration to be delivered by us to SMP Holdings continue to be determinable by us in our sole discretion. The terms of the Second Amendment were approved by the Conflicts Committee, which consists entirely of independent directors. Previously, in February 2019, we and SMP Holdings signed a first amendment to the Contribution Agreement related to the 2016 Drop Down pursuant to which, in April 2019, the Partnership made a cash payment of $100 million to SMP Holdings in partial settlement of the Deferred Purchase Price Obligation. Following the payment, the Remaining Consideration was fixed at $303.5 million, with such amount being payable by the Partnership in one or more payments over the period from March 1, 2020 through December 31, 2020, in (i) cash, (ii) the Partnership’s common units or (iii) a combination of cash and the Partnership’s common units, at the discretion of the Partnership. At least 50% of the Remaining Consideration was required to be paid on or before June 30, 2020 and interest would accrue at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020. The first amendment was superseded by the second amendment. On March 22, 2019, pursuant to an equity restructuring agreement with the General Partner and SMP Holdings, we cancelled our IDRs and converted our 2% economic GP interest into a non-economic GP interest in exchange for 8,750,000 SMLP common units, which were issued to SMP Holdings in the Equity Restructuring. As a result of the Equity Restructuring, the general partner units and IDRs were eliminated, are no longer outstanding, and no longer participate in distributions of cash from SMLP. ECP continues to control the non-economic GP interest in SMLP. In December 2019, as part of our financing for the Double E Project, we formed Permian Holdco, a newly created, unrestricted subsidiary of SMLP that indirectly owns SMLP’s 70% interest in Double E. In connection with the formation of Permian Holdco, we entered into an agreement with TPG Energy Solutions Anthem, L.P. (“TPG”) on December 24, 2019 to fund up to $80 million of Permian Holdco’s future capital calls associated with the Double E Project. Simultaneously, on December 24, 2019, Permian Holdco issued 30,000 Subsidiary Series A Preferred Units to TPG for net proceeds of $27.4 million. In June 2019, we continued development of the Double E Project after securing firm 10-year commitments under binding precedent agreements for a substantial majority of the pipeline’s initial throughput capacity of 1.35 Bcf of gas per day and executing the JV Agreement with an affiliate of Double E’s foundation shipper. The Double E Project, which consists of an approximately 116-mile mainline and related facilities, will provide interstate natural gas transportation service from the Delaware Basin production area to the Waha Hub in Texas. Double E filed its application under Section 7(c) of the NGA with the FERC on July 31, 2019 to obtain a certificate of public convenience and necessity authorizing the construction and operation of the pipeline. In connection with the Double E Project, Summit Permian Transmission contributed total assets of approximately $23.6 million for a 70% ownership interest in Double E. Concurrent with this contribution, Double E distributed $7.3 million to the Partnership. We expect to own at least a 50% interest in the Double E Project, will lead the development, permitting and construction of the Double E Project and will operate the pipeline upon commissioning. At our current 70% interest, we estimate that our share of the capital expenditures required to develop the Double E Project will total approximately $350.0 million, and that more than 90% of those capital expenditures will be incurred in 2020 and 2021. Assuming timely receipt of the required regulatory approvals (including the FERC certificate) and no material delays in construction, we expect that the Double E Project will be placed into service in the third quarter of 2021. 75 Table of Contents • • • In December 2019, Red Rock Gathering and certain affiliates of SMLP (collectively, “the Red Rock Parties”) entered into a Purchase and Sale Agreement (the “Red Rock PSA”) pursuant to which the Red Rock Parties agreed to sell certain Red Rock Gathering system assets for a cash purchase price of $12.0 million (the “Red Rock Sale”). Prior to closing, we recorded an impairment charge of $14.2 million based on the expected consideration and the carrying value for the Red Rock Gathering system assets. On December 2, 2019, we closed the Red Rock Sale. The impairment is included in the Long-lived asset impairment caption on the consolidated statement of operations. The financial contribution of these assets (a component of the Piceance Basin reportable segment) are included in our consolidated financial statements and footnotes for the period from January 1, 2019 through December 1, 2019. Until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system in the Williston Basin. On March 22, 2019, we sold the Tioga Midstream system to affiliates of Hess Infrastructure Partners LP for a combined cash purchase price of approximately $90 million and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the carrying value for Tioga Midstream at closing. The gain is included in the Gain on asset sales, net caption on the consolidated statement of operations. The financial results of Tioga Midstream (a component of the Williston Basin reportable segment) are included in our consolidated financial statements and footnotes for the historical periods through March 22, 2019. Refer to Note 17 to the consolidated financial statements for details on the sale of Tioga Midstream. In the third quarter of 2019, we began an internal initiative to evaluate and transform our cost structure, enhance margins and improve our competitive position in response to a weakening commodity price backdrop. For the year ended December 31, 2019, we incurred approximately $5.0 million in restructuring costs relating to this initiative (included in general and administrative expense). Year ended December 31, 2018. The following items are reflected in our financial results: • • • • • In 2018, the present value of the Deferred Purchase Price Obligation increased by $21.0 million. The change was primarily due to the passage of time and an associated decrease in the discount rate, partially offset by the continued slowing and deferral of drilling and completion activities to periods outside of the DPPO measurement period (see Note 17 to the consolidated financial statements). Increased natural gas, NGLs and condensate sales and cost of natural gas and NGLs associated with increased marketing related activities. In November 2018, a subsidiary of SMLP purchased the remaining 1% ownership interest in OpCo held by a subsidiary of Summit Investments for approximately $10.9 million. During the year ended December 31, 2018, we recognized $6.0 million in gathering services and related fees from MVC shortfall adjustments. Under Topic 606, we recognize customer obligations under their MVCs as revenue and contract assets when (i) we consider it remote that the customer will utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods; (ii) the customer incurs a shortfall in a contract with no banking mechanism or claw back provision; (iii) the customer’s banking mechanism has expired; or (iv) it is remote that the customer will use its unexercised right. In December 2018, in connection with certain strategic initiatives, we performed a recoverability assessment of certain assets within the Williston Basin reporting segment. Based on the results, we concluded that the carrying value of certain long-lived assets related to the Tioga Midstream system in the Williston Basin were not fully recoverable and we recorded an impairment charge of $3.9 million. Year ended December 31, 2017. The following items are reflected in our financial results: • In February 2017, we completed a public offering of $500.0 million principal amount of 5.75% Senior Notes. Concurrent with and following the offering, we initiated a tender offer for the outstanding 7.5% Senior Notes. All remaining 7.5% Senior Notes were redeemed on March 18, 2017, with payment made on March 20, 2017. We used the proceeds from the issuance of the 5.75% Senior Notes to (i) fund the repurchase of the outstanding $300.0 million principal amount of 7.5% Senior Notes, (ii) pay redemption and call premiums on the 7.5% Senior Notes totaling $17.9 million and (iii) pay $172.0 million of the balance outstanding under our Revolving Credit Facility. 76 Table of Contents • • • • In March 2017, we recognized $37.7 million of gathering services and related fees revenue that had been previously deferred, and recorded on our consolidated balance sheet as deferred revenue, in connection with an MVC arrangement with a certain Williston Basin customer, for which we determined we had no further performance obligations. We include the effect of adjustments related to MVC shortfall payments in our definition of segment adjusted EBITDA. As such, the Williston Basin segment adjusted EBITDA was not impacted because the revenue recognition was offset by the associated adjustments related to MVC shortfall payments for this customer. In November 2017, we issued 300,000 Series A Preferred Units representing limited partner interests in the Partnership at a price of $1,000 per unit. We used the net proceeds of $293.2 million to repay outstanding borrowings under our Revolving Credit Facility. In 2017, we updated the Deferred Purchase Price Obligation based on management’s estimate of forecasted Business Adjusted EBITDA and capital expenditures for the 2016 Drop Down Assets. The decrease was primarily attributable to lower expected Business Adjusted EBITDA in 2018 and 2019 associated with the 2016 Drop Down Assets partially offset by lower estimated capital expenditures. The revision in estimated Business Adjusted EBITDA and estimated capital expenditures reflects a slower expected pace of drilling and completion activities from our customers, particularly in the Utica Shale in 2018 and 2019. The revised estimates had a favorable impact on our consolidated statements of operations for the year ended December 31, 2017. In December 2017, in connection with certain strategic initiatives, we performed a financial review of certain assets within the Williston Basin reporting segment. This resulted in a triggering event that required us to perform a recoverability test. Based on the results of the test, we concluded that the carrying value of certain intangible and long-lived assets related to the Bison Midstream system in the Williston Basin were not fully recoverable and we recorded an impairment charge of $187.1 million. Our business has been, and we expect our future business to continue to be, affected by the following key trends: Trends and Outlook • • • • Natural gas, NGL and crude oil supply and demand dynamics; Production from U.S. shale plays; Capital markets availability and cost of capital; and Shifts in operating costs and inflation. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. Natural gas, NGL and crude oil supply and demand dynamics. Natural gas continues to be a critical component of energy supply and demand in the United States. The average spot price of natural gas decreased by approximately 19% from 2018 to 2019, primarily due to natural gas supply exceeding demand. The average daily Henry Hub Natural Gas Spot Price was $2.56 per MMBtu during 2019, compared with $3.15 per MMBtu during 2018. Henry Hub closed at $2.09 per MMBtu on December 31, 2019 and as of February 10, 2020, closed at $1.85 per MMBtu. Natural gas prices continue to trade at lower-than-average historical prices due in part to increased natural gas production and an elevated level of natural gas in storage in the continental United States. The average amount of working natural gas in underground storage in the continental U.S. was 2.47 Tcf in 2019, which was 9.5% higher than in 2018. In the near term, we believe that until the supply of natural gas in storage has been reduced, natural gas prices are likely to remain constrained. Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven primarily by global population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation. However, we note that over the last several years there has been an increasing societal opposition to the production of hydrocarbons generally, which may be reflected in legislation, executive orders or regulations that may significantly restrict the domestic production of fossil fuels, including natural gas. 77 Table of Contents In addition, certain of our gathering systems are directly affected by crude oil supply and demand dynamics. Crude oil prices decreased in 2019, with the average daily Cushing, Oklahoma West Texas Intermediate ("WTI") crude oil spot price decreasing from an average $65.23 per barrel during 2018 to an average of $56.98 per barrel during 2019, representing a 12.6% decrease, reflecting broader market concerns for global oil supply and demand dynamics. In response to the general decrease in crude oil prices, the number of active crude oil drilling rigs in the continental United States decreased from 885 in December 2018 to 677 in December 2019, according to Baker Hughes. Over the next several years, we expect that crude oil prices will support continued drilling activity and increasing production in the Williston Basin, Permian Basin and, given the current regulatory environment in Colorado, in rural parts of the DJ Basin. Growth in production from U.S. shale plays. Over the past several years, natural gas production from unconventional shale resources has increased significantly due to advances in technology that allow producers to extract significant volumes of natural gas from unconventional shale plays on favorable economic terms relative to most conventional plays. In recent years, a number of producers and their joint venture partners, including large international operators, industrial manufacturers and private equity sponsors, have committed significant capital to the development of these unconventional resources, including the Piceance, Barnett, Bakken, Marcellus, Utica and Permian Basin shale plays in which we operate, and we believe that these long-term capital investments will support drilling activity in unconventional shale plays over the long term. Rate of growth in production from U.S. shale plays. Some of our producer customers have adjusted their drilling and completion activities and schedules to manage drilling and completion costs at levels that are achievable using internally generated cash flow from their underlying operations. Historically, as part of a strategy to accelerate production growth, these producers would raise external capital to fund drilling and completion costs in excess of the cash flows generated from their underlying assets. In general, we expect our producer customers to reduce completion and production activities across many of our systems relative to our previous expectations as a result of a weakening commodity price environment and a continuation of the general trend of producers constraining drilling and completion activity to levels that can be satisfied with internally generated cash flow. Capital markets availability and cost of capital. Credit markets were volatile throughout 2019, as borrowing costs increased and investors assessed the impact of rising rates on broader economic activity. Capital markets conditions, including but not limited to availability and higher borrowing costs, could affect our ability to access the debt capital markets to the extent necessary, to fund our future growth. Furthermore, market demand for equity issued by master limited partnerships has been significantly lower in recent years than it has been historically, which may make it more challenging for us to finance our capital expenditures with the issuance of additional equity. We recently announced a reduction in our common unit distribution to $0.125 per quarter, beginning with the distribution paid in respect of the fourth quarter of 2019, and this reduction may further reduce demand for our common units. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Shifts in operating costs and inflation. Throughout most of the last five years, high levels of crude oil and natural gas exploration, development and production activities across the United States resulted in increased competition for personnel and equipment as well as higher prices for labor, supplies, equipment and other services. Beginning in 2015, this dynamic began to shift as prices for crude oil and natural gas-related services decreased in line with overall decline in demand for these goods and services. While we expect lower service- related costs in the near term, we expect that over the longer term, these costs will continue to have a high correlation to changes in the prevailing price of crude oil and natural gas. 78 Table of Contents We conduct and report our operations in the midstream energy industry through eight reportable segments: How We Evaluate Our Operations • • • • • • • • the Utica Shale, which is served by Summit Utica; Ohio Gathering, which includes our ownership interest in OGC and OCC; the Williston Basin, which is served by Polar and Divide and Bison Midstream; the DJ Basin, which is served by Niobrara G&P; the Permian Basin, which is served by Summit Permian; the Piceance Basin, which is served by Grand River; the Barnett Shale, which is served by DFW Midstream; and the Marcellus Shale, which is served by Mountaineer Midstream. Additionally, until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Refer to Note 17 to the consolidated financial statements for details on the sale of Tioga Midstream. Each of our reportable segments provides midstream services in a specific geographic area. Our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations (see Note 4 to the consolidated financial statements). Our management uses a variety of financial and operational metrics to analyze our consolidated and segment performance. We view these metrics as important factors in evaluating our profitability and determining the amounts of cash distributions to pay to our unitholders. These metrics include: • • • • throughput volume; revenues; operation and maintenance expenses; and segment adjusted EBITDA. Throughput Volume The volume of (i) natural gas that we gather, compress, treat and/or process and (ii) crude oil and produced water that we gather depends on the level of production from natural gas or crude oil wells connected to our gathering systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity. Furthermore, because the production rate of natural gas and crude oil wells decline over time, production can only be maintained or increased by new drilling or other activity. As a result, we must continually obtain new supplies of production to maintain or increase the throughput volume on our systems. Our ability to maintain or increase throughput volumes from existing customers and obtain new supplies of throughput is impacted by: • • • • • successful drilling activity within our AMIs; the level of work-overs and recompletions of wells on existing pad sites to which our gathering systems are connected; the number of new pad sites in our AMIs awaiting connections; our ability to compete for volumes from successful new wells in the areas in which we operate outside of our existing AMIs; and our ability to gather, treat and/or process production that has been released from commitments with our competitors. 79 Table of Contents We report volumes gathered for natural gas in cubic feet per day. We aggregate crude oil and produced water gathering and report volumes gathered in barrels per day. Revenues Our revenues are primarily attributable to the volumes that we gather, compress, treat and/or process and the rates we charge for those services. A majority of our gathering and processing agreements are fee-based, which limits our direct exposure to fluctuations in commodity prices. We also have percent-of-proceeds arrangements with certain customers under which the gathering and processing revenues that we earn correlate directly with the fluctuating price of natural gas, condensate and NGLs. Certain of our gathering and processing agreements contain MVCs pursuant to which our customers agree to ship or process a minimum volume of production on our gathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. These MVCs help us generate stable revenues and serve to mitigate the financial impact associated with declining volumes. Operation and Maintenance Expenses We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating our assets. Direct labor costs, compression costs, ad valorem taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are largely independent of volumes delivered through our gathering systems but may fluctuate depending on the activities performed during a specific period. Segment Adjusted EBITDA Segment adjusted EBITDA is a supplemental financial measure used by management and by external users of our financial statements such as investors, commercial banks, research analysts and others. Segment adjusted EBITDA is used to assess: • • • • • the ability of our assets to generate cash sufficient to make cash distributions and support our indebtedness; the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities; and the financial performance of our assets without regard to (i) income or loss from equity method investees, (ii) the impact of the timing of minimum volume commitment shortfall payments under our gathering agreements or (iii) the timing of impairments or other noncash income or expense items. Additional Information. For additional information, see the "Results of Operations" section herein and the notes to the consolidated financial statements. For information on pending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 to the consolidated financial statements. 80 Table of Contents Our financial results are recognized as follows: Results of Operations Gathering services and related fees. Revenue earned from the gathering, compression, treating and processing services that we provide to our customers. Natural gas, NGLs and condensate sales. Revenue earned from (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds arrangements with certain of our customers on the Bison Midstream, Grand River and Summit Permian systems, (ii) natural gas and crude oil marketing services in and around our gathering systems, (iii) the sale of natural gas we retain from certain DFW Midstream customers and (iv) the sale of condensate we retain from our gathering services at Grand River. Other revenues. Revenue earned primarily from (i) certain costs for which certain of our customers have agreed to reimburse us and (ii) connection fees for customers of the Polar and Divide system. Cost of natural gas and NGLs. The cost of natural gas and NGLs represents (i) the purchase of natural gas and NGLs associated with marketing activity surrounding certain of our natural gas and crude oil-related operations and (ii) the costs associated with the percent-of- proceeds arrangements under which we sell natural gas and NGLs purchased from certain of our customers on the Bison Midstream and Grand River systems. Operation and maintenance. Operation and maintenance primarily comprises direct labor costs, compression costs, ad valorem taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services. These items represent the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are largely independent of variations in throughput volumes but may fluctuate depending on the activities performed during a specific period. General and administrative. Expenses associated with our operations that are not specifically associated with the operation and maintenance of a particular system or another cost and expense line item. These expenses largely reflect salaries, benefits and incentive compensation, professional fees, insurance and rent. Depreciation and amortization. The depreciation of our property, plant and equipment and the amortization of our contract and right-of-way intangible assets. Transaction costs. Financial and legal advisory costs associated with completed acquisitions and divestitures and restructuring activities. Other income or expense. Generally represents other items of gain or loss but may also include interest income. Interest expense. Interest expense associated with our Revolving Credit Facility and our Senior Notes as well as amortization expense associated with debt issuance costs. Deferred Purchase Price Obligation. Represents the change in fair value associated with the Deferred Purchase Price Obligation. Income tax expense or benefit. Represents the expense or benefit associated with the Texas Margin Tax. Income or loss from equity method investees. Represents the income or loss and other-than-temporary impairment associated with our ownership interest in Ohio Gathering. 81 Table of Contents Consolidated Overview for the Years Ended December 31, 2019, 2018 and 2017 The following table presents certain consolidated data and volume throughput for the years ended December 31. 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) loss on asset sales, net Long-lived asset impairment Goodwill impairment Total costs and expenses Other income (expense) Interest expense Early extinguishment of debt Deferred Purchase Price Obligation (Loss) income before income taxes and loss from equity method investees Income tax expense Loss from equity method investees Net (loss) income Volume throughput (1): Aggregate average daily throughput - natural gas (MMcf/d) Aggregate average daily throughput - liquids (Mbbl/d) 2019 Year ended December 31, 2018 (In thousands) 2017 2019 v. 2018 2018 v. 2017 Percentage Change $ 326,747 $ 86,994 29,787 443,528 344,616 $ 134,834 27,203 506,653 63,438 97,587 54,139 110,206 1,788 (1,536) 60,507 16,211 402,340 451 (74,429) — 1,982 107,661 96,878 52,877 107,100 — — 7,186 — 371,702 (169) (60,535) — (20,975) (30,808) (1,174) (337,851) (369,833) $ 53,272 (33) (10,888) 42,351 $ $ 394,427 68,459 25,855 488,741 57,237 93,882 54,681 115,475 73 527 188,702 — 510,577 298 (68,131) (22,039) 200,322 88,614 (341) (2,223) 86,050 (5%) (35%) 9% (12%) (41%) 1% 2% 3% * * * * 8% * 23% * * * * * * 1,397 1,673 1,748 (16%) 105.3 94.9 75.2 11% (13%) 97% 5% 4% 88% 3% (3%) (7%) * * (96%) * (27%) * (11%) * * * * 390% * (4%) 26% * Not considered meaningful (1) Exclusive of volume throughput for Ohio Gathering. For additional information, see the "Ohio Gathering" section herein. 82 Table of Contents Volumes – Gas. Natural gas throughput volumes decreased 276 MMcf/d for the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily reflecting: • • • • • a volume throughput decrease of 111 MMcf/d for the Marcellus Shale segment. a volume throughput decrease of 99 MMcf/d for the Piceance Basin segment. a volume throughput decrease of 86 MMcf/d for the Utica Shale segment. a volume throughput increase of 18 MMcf/d for the Permian Basin segment. a volume throughput increase of 10 MMcf/d for the DJ Basin segment. Natural gas throughput volumes decreased 75 MMcf/d for the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily reflected: • • • • • a volume throughput decrease of 31 MMcf/d for the Piceance Basin segment. a volume throughput decrease of 28 MMcf/d for the Marcellus Shale segment. a volume throughput decrease of 14 MMcf/d for the Barnett Shale segment. a volume throughput decrease of 6 MMcf/d for the Utica Shale segment. a volume throughput increase of 4 MMcf/d for the DJ Basin segment. Volumes – Liquids. Crude oil and produced water throughput volumes at the Williston segment increased 10.4 Mbbl/d for the year ended December 31, 2019 compared to the year ended December 31, 2018. Crude oil and produced water throughput volumes at the Williston segment increased 19.7 Mbbl/d for the year ended December 31, 2018 compared to the year ended December 31, 2017. For additional information on volumes, see the "Segment Overview for the Years Ended December 31, 2019, 2018 and 2017" section herein. Revenues. Total revenues decreased $63.1 million during the year ended December 31, 2019 compared to the prior year primarily comprised of a $47.8 million decrease in natural gas, NGLs and condensate sales and a $17.9 million decrease in gathering services and related fees. Gathering Services and Related Fees. Gathering services and related fees decreased $17.9 million compared to the year ended December 31, 2018, primarily reflecting: • • • • a $11.2 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting $5.1 million in lower MVC shortfall revenue attributable to the timing of revenue recognition and an unfavorable gathering rate mix on certain gathering services and related fees. Also impacting 2019 revenues was the presentation of $4.5 million of gathering services as a reduction to cost of natural gas and NGLs due to the assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream operations. a $14.5 million decrease in gathering services and related fees in the Piceance Basin relating to lower volume throughput due to a lack of drilling and completion activity and natural production declines. a $5.1 million decrease in gathering services and related fees in the Marcellus Shale relating to lower volume throughput due to natural production declines partially offset by additional drilling and completion activities. a $3.3 million decrease in gathering services and related fees in the Utica Shale due to a combination of natural production declines on existing wells together with increased temporary production curtailments associated with infill drilling, completion activity and other operational downtime partially offset by the completion of new wells at the end of the fourth quarter of 2018 and throughout 2019 and a more favorable volume and gathering rate mix from customers. 83 Table of Contents • • • a $2.0 million decrease in gathering services and related fees in the Williston Basin primarily reflecting a $9.8 million decrease in gathering services and related fees attributable to the sale of the Tioga Midstream system on March 22, 2019, whose 2019 financial results are included for the period from January 1, 2019 through March 22, 2019. This was partially offset by higher liquids volume throughput due to increased drilling and completion activity. a $10.7 million increase in gathering services and related fees in the DJ Basin relating to higher volume throughput due to increased drilling activity and a more favorable volume and gathering rate mix from customers, partially offset by natural production declines. a $3.5 million increase in gathering services and related fees in the Permian Basin (commissioned in the fourth quarter of 2018). Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales decreased $47.8 million compared to the year ended December 31, 2018, primarily reflecting lower natural gas, NGL and crude oil marketing services. The majority of the decrease in revenue is offset by a $44.2 million decrease in natural gas, NGL and condensate purchases. Total revenues for the year ended December 31, 2018 increased $17.9 million compared to the year ended December 31, 2017 primarily comprised of a $66.4 million increase in natural gas, NGLs and condensate sales and a $49.8 million decrease in gathering services and related fees. Gathering Services and Related Fees. Gathering services and related fees decreased $49.8 million compared to the year ended December 31, 2017, as compared to the prior year, primarily reflecting: • • • • the impact of the 2017 recognition of $37.7 million of previously deferred revenue related to a certain Williston Basin customer. a $13.3 million decrease in gathering services and related fees for the Williston Basin segment due to the reclassification of amounts under certain percent-of-proceeds arrangements currently recognized on a net basis in cost of natural gas and NGLs under Topic 606. a $3.6 million decrease in gathering services and related fees for the Barnett Shale segment largely as a result of the expiration of an MVC during 2017. a $6.0 million increase from the recognition of MVC shortfall adjustments for the Barnett Shale segment under Topic 606 (see Note 3 in the consolidated financial statements). Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales increased $66.4 million compared to the year ended December 31, 2017, primarily reflecting the addition of natural gas, NGL and crude oil marketing services provided for the Piceance Basin, DJ Basin, Barnett Shale and Williston Basin segments. Costs and Expenses. Total costs and expenses increased $30.6 million during the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily reflecting: • • • • • • the recognition of $34.9 million of certain long-lived asset impairments in the DJ Basin. a goodwill impairment charge of $16.2 million relating to the Mountaineer Midstream system in the Marcellus Shale. the recognition of $14.2 million of long-lived asset impairments relating to the sale of certain Red Rock Gathering system assets in the Piceance Basin. the recognition of $10.2 million of certain long-lived asset impairments in the Barnett Shale. the recognition of $1.3 million of certain long-lived asset impairments in the Permian Basin. a $44.2 million decrease in natural gas, NGLs and condensate purchases primarily driven by lower natural gas, NGL and crude oil marketing activity. 84 Table of Contents Total costs and expenses decreased $138.9 million during the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily reflecting: • • • • • the impact of the 2017 recognition of $187.1 million of certain intangible and long-lived asset impairments relating to the Bison Midstream system in the Williston Basin segment. a $63.7 million increase in natural gas, NGLs and condensate purchases primarily driven by increased natural gas, NGL and crude oil marketing activity for the Piceance Basin, DJ Basin, Barnett Shale and Williston Basin segments. a $3.0 million increase in operation and maintenance expense primarily due to planned compressor overhaul maintenance. a $13.3 million decrease in the cost of natural gas and NGLs for the Williston Basin segment due to the reclassification of amounts under certain percent-of-proceeds arrangements under Topic 606 that were previously recognized in gathering services and related fees. a $8.4 million decrease in depreciation and amortization primarily due to the impairment of certain intangible and long-lived assets relating to the Bison Midstream system in the Williston Basin segment recognized in the fourth quarter of 2017. Cost of Natural Gas and NGLs. Cost of natural gas and NGLs decreased $44.2 million during the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily driven by lower natural gas, NGL and crude oil marketing activity. Cost of natural gas and NGLs increased $50.4 million during the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily reflecting: • • a $63.7 million increase in natural gas, NGLs, crude oil and condensate purchases driven by increased natural gas, NGL and crude oil marketing activity for the Piceance Basin, DJ Basin, Barnett Shale and Williston Basin segments. the reclassification of $13.3 million in cost of natural gas and NGLs for the Williston Basin segment under certain percent-of- proceeds arrangements previously recognized in gathering services and related fees, which is presented net in cost of natural gas and NGLs under Topic 606. Operation and Maintenance. Operation and maintenance expense increased $0.7 million for the year ended December 31, 2019 compared to the year ended December 31, 2018. Operation and maintenance expense increased $3.0 million for the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily due to an increase in planned compressor overhaul maintenance. General and Administrative. General and administrative expense increased $1.3 million for the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily due to a $7.3 million increase in severance and restructuring expenses partially offset by lower headcount associated with our cost cutting initiatives and lower performance-based compensation. General and administrative expense decreased $1.8 million for the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily reflecting a decrease in information technology expense of $1.3 million and an increase in capitalized labor of $0.7 million associated with the continued development of Summit Permian and the DJ Basin. For additional information, see the "Corporate and Other Overview of the Years Ended December 31, 2019, 2018 and 2017" sections herein. Depreciation and Amortization. The increase in depreciation and amortization expense during 2019 compared to the year ended December 31, 2018 was primarily due to the assets placed into service in the Permian Basin. The decrease in depreciation and amortization expense during 2018 compared to the year ended December 31, 2017 was primarily due to the impairment of certain intangible and long-lived assets on the Bison Midstream system in the Williston Basin segment recognized in the fourth quarter of 2017. 85 Table of Contents Transaction Costs. Transaction costs recognized during the year ended December 31, 2019 primarily relate to $0.9 million in financial advisory costs associated with the Equity Restructuring and $0.5 million in financial advisory costs associated with the DPPO restructuring. Interest Expense. The increase in interest expense in the year ended December 31, 2019 compared to the year ended December 31, 2018, was primarily due to a higher average outstanding balance on the Revolving Credit Facility. The decrease in interest expense in 2018 compared to the year ended December 31, 2017, was as a result of (i) the tender and redemption of the $300.0 million principal 7.5% Senior Notes, (ii) the issuance of 300,000 Series A Preferred Units in November 2017 whereby the net proceeds were used to repay outstanding borrowings under our Revolving Credit Facility and (iii) a lower average outstanding balance on the Revolving Credit Facility. The decrease was partially offset by the interest associated with issuance of the $500.0 million principal 5.75% Senior Notes and an increase in the interest rate on the Revolving Credit Facility. Early Extinguishment of Debt. The early extinguishment of debt recognized during the year ended December 31, 2017 was driven by the tender and redemption of the $300.0 million principal 7.5% Senior Notes. Deferred Purchase Price Obligation. Deferred Purchase Price Obligation recognized during the year ended December 31, 2019 represents the change in present value to Remaining Consideration in connection with the 2016 Drop Down (see Note 17 to the consolidated financial statements). Deferred Purchase Price Obligation recognized during the year ended December 31, 2018 represents the change in present value of the estimated Remaining Consideration to be paid in connection with the 2016 Drop Down. The change was primarily due to the passage of time and an associated decrease in the discount rate, partially offset by the continued slowing and deferral of drilling and completion activities to periods outside of the DPPO measurement period. For additional information, see the "Segment Overview for the Years Ended December 31, 2019, 2018 and 2017" and "Corporate and Other Overview for the Years Ended December 31, 2019, 2018 and 2017" sections herein and “Business – Recent Developments.” Segment Overview for the Years Ended December 31, 2019, 2018 and 2017 Utica Shale. The Utica Shale reportable segment includes the Summit Utica system. Volume throughput for our Summit Utica system follows. Average daily throughput (MMcf/d) 2019 Year ended December 31, 2018 2017 273 359 365 Percentage Change 2019 v. 2018 (24%) 2018 v. 2017 (2%) Utica Shale Volume throughput declined compared to the year ended December 31, 2018 due to natural production declines from existing wells on pad sites connected to the Summit Utica, partially offset by the completion of new wells at the end of the fourth quarter of 2018 and throughout 2019. In addition, volume throughput was impacted by an increase in temporary production curtailments associated with infill drilling, completion activity and other operational downtime associated with customers on existing pad sites. Volume throughput decreased during 2018 due to natural declines from existing wells on pad sites connected to the Summit Utica system together with temporary production curtailments associated with infill drilling and completion activity from customers on existing pad sites, partially offset by the completion of new wells during 2017 and in 2018. In addition, the TPL-7 connector project was commissioned in the first quarter of 2017 which partially offset volume declines in 2018 due to a full year of operations. 86 Table of Contents 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 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 2019 Year ended December 31, 2018 (Dollars in thousands) $ 31,926 $ 2,065 33,991 35,233 $ — 35,233 4,151 530 7,659 — — 12,340 4,556 374 7,672 5 1,440 14,047 Utica Shale 2017 2019 v. 2018 2018 v. 2017 Percentage Change 38,907 — 38,907 4,487 409 7,009 542 878 13,325 (9%) * (4%) (9%) 42% (0%) * * (12%) (9%) * (9%) 2% (9%) 9% * * 5% 7,659 7,672 7,009 (18) — — 29,292 $ (18) 5 1,440 30,285 $ $ — 542 878 34,011 (3%) (11%) Year ended December 31, 2019. Segment adjusted EBITDA decreased $1.0 million compared to the year ended December 31, 2018, primarily reflecting: • • a $3.3 million decrease in gathering services and related fees due to the volume throughput declines discussed above partially offset by a more favorable volume and gathering rate mix from customers. a $2.1 million increase in other revenues due to the release of an acreage dedication to one of our customers. Year ended December 31, 2018. Segment adjusted EBITDA decreased $3.7 million compared to the year ended December 31, 2017, primarily reflecting: • a $3.7 million decrease in gathering services and related fees from a lower gathering rate mix associated with increasing volumes from the TPL-7 connector project, which was commissioned in the first quarter of 2017, along with a decrease in volume throughput from wells that we gather from pad sites on the Summit Utica system and temporary production curtailments. The decrease was partially offset by an increase in volume throughput associated with new wells completed in 2017 and 2018. Ohio Gathering. The Ohio Gathering reportable segment includes OGC and OCC. We account for our investment in Ohio Gathering using the equity method. We recognize our proportionate share of earnings or loss in net income on a one-month lag based on the financial information available to us during the reporting period. Gross volume throughput for Ohio Gathering, based on a one-month lag follows. Average daily throughput (MMcf/d) * Not considered meaningful Ohio Gathering 2019 Year ended December 31, 2018 2017 732 769 766 Percentage Change 2019 v. 2018 (5%) 2018 v. 2017 * Volume throughput for the Ohio Gathering system in 2019 decreased compared to the year ended December 31, 2018 as a result of natural production declines on existing wells on the system, partially offset by the completion of new wells. 87 Table of Contents Volume throughput for the Ohio Gathering system in 2018 increased slightly compared to the year ended December 31, 2017 as a result of increased drilling activity from our customers during the second half of 2017 and in 2018, partially offset by natural production declines on existing wells on the system. Financial data for our Ohio Gathering reportable segment, based on a one-month lag follows. Proportional adjusted EBITDA for equity method investees Segment adjusted EBITDA 2019 Year ended December 31, 2018 2017 (Dollars in thousands) Percentage Change 2019 v. 2018 2018 v. 2017 Ohio Gathering $ $ 39,126 $ 39,126 $ 39,969 $ 39,969 $ 41,246 41,246 (2%) (2%) (3%) (3%) Year ended December 31, 2019. Segment adjusted EBITDA for equity method investees decreased $0.8 million compared to the year ended December 31, 2018. Other items to note: • In the fourth quarter of 2019, we impaired our equity method investment in Ohio Gathering (see Note 8 to the consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2019. Year ended December 31, 2018. Segment adjusted EBITDA for equity method investees decreased $1.3 million compared to the year ended December 31, 2017, primarily as a result of higher expenses, partially offset by higher volumes at OGC and OCC. Williston Basin. The Polar and Divide, Tioga Midstream (through March 22, 2019; refer to Note 17 to the consolidated financial statements for details on the sale of Tioga Midstream) and Bison Midstream systems provide our midstream services for the Williston Basin reportable segment. Volume throughput for our Williston Basin reportable segment follows. Aggregate average daily throughput - natural gas (MMcf/d) Aggregate average daily throughput - liquids (Mbbl/d) Williston Basin 2019 12 Year ended December 31, 2018 18 2017 19 Percentage Change 2019 v. 2018 2018 v. 2017 (33%) (5%) 105.3 94.9 75.2 11% 26% Natural gas. Natural gas volume throughput in 2019 decreased compared to the year ended December 31, 2018, primarily reflecting natural production declines, the sale of Tioga Midstream and operational downtime on the Bison Midstream system. Natural gas volume throughput in 2018 decreased compared to the year ended December 31, 2017, primarily reflecting natural production declines. Liquids. The increase in liquids volume throughput in 2019 compared to the year ended December 31, 2018, primarily reflected well drilling and completion activity by existing customers on our Polar and Divide system in 2018 and in 2019 as well as the addition of a new customer, partially offset by the sale of Tioga Midstream and natural production declines. The increase in liquids volume throughput in 2018 compared to the year ended December 31, 2017 primarily reflected well completion activity by existing customers on our Polar and Divide system in the second half of 2017 and in 2018 as well as the addition of new customers. 88 Table of Contents 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) 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 Year ended December 31, Percentage Change 2019 2018 2017 2019 v. 2018 2018 v. 2017 Williston Basin (Dollars in thousands) $ 77,626 $ 16,461 11,564 105,651 79,606 $ 31,840 12,204 123,650 5,821 27,172 1,493 19,829 (1,177) 10 53,148 18,284 25,300 2,089 22,642 63 3,972 72,350 120,717 29,724 11,062 161,503 30,004 25,058 2,335 33,772 (22) 187,127 278,274 (2%) (48%) (5%) (15%) (68%) 7% (29%) (12%) * * (27%) (34%) 7% 10% (23%) (39%) 1% (11%) (33%) * * * 19,829 22,642 33,772 — — (37,693) (1,728) (1,177) 10 69,437 $ (1,276) 63 3,972 76,701 $ — (22) 187,127 66,413 $ (9%) 15% Year ended December 31, 2019. Segment adjusted EBITDA decreased $7.3 million compared to the year ended December 31, 2018 primarily reflecting: • a decrease of $7.6 million of segment adjusted EBITDA contributed by the Tioga Midstream system compared to the year ended December 31, 2018 due to the sale of Tioga Midstream on March 22, 2019. We also experienced lower natural gas volume throughput primarily reflecting natural production declines and operational downtime on the Bison Midstream system. The operational downtime began with third party maintenance on infrastructure located downstream of the Bison Midstream system, which created an operational disruption on the Bison Midstream system for approximately 15 days during the second quarter and continued to impact throughput capacity through August 2019. This was partially offset by higher liquids volume throughput on our Polar and Divide system due to increased drilling and completion activity in 2018 and throughout 2019. • a $1.9 million increase in operation and maintenance expense primarily related to an increase in environmental remediation costs. Other items to note: • On March 22, 2019, we sold the Tioga Midstream system and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the then carrying value for Tioga Midstream at closing. The financial results of Tioga Midstream are included in our consolidated financial statements for the period from January 1, 2019 through March 22, 2019. 89 Table of Contents Year ended December 31, 2018. Segment adjusted EBITDA increased $10.3 million compared to the year ended December 31, 2017, primarily reflecting an increase in liquids volume throughput on our Polar and Divide system and $1.6 million in fees attributable to our Dakota Access Pipeline interconnect which was commissioned in the second quarter of 2017. Other items to note: • • • The decrease in the cost of natural gas and NGLs includes a $13.3 million reduction in expense due to the reclassification of amounts under certain percent-of-proceeds arrangements previously recognized in gathering services and related fees under Topic 606 (see Note 3 in the consolidated financial statements). In the fourth quarter of 2018, we impaired certain long-lived assets relating to the Tioga Midstream system in the Williston Basin (see Note 5 to the consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2018. Depreciation and amortization decreased during 2018 largely as a result of the long-lived asset impairment recognized in 2017. DJ Basin. The Niobrara G&P system provides midstream services for the DJ Basin reportable segment. Volume throughput for our DJ Basin reportable segment follows. Average daily throughput (MMcf/d) 2019 Year ended December 31, 2018 2017 2019 v. 2018 2018 v. 2017 Percentage Change DJ Basin 27 17 13 59% 31% Volume throughput in 2019 increased compared to the year ended December 31, 2018, primarily as a result of ongoing drilling and completion activity across our service area partially offset by natural production declines. Volume throughput in 2018 increased compared to the year ended December 31, 2017, primarily as a result of ongoing drilling and completion activity across our service area. Financial data for our DJ Basin reportable segment follows. 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 Long-lived asset impairment Total costs and expenses Add: Depreciation and amortization Adjustments related to capital reimbursement activity Loss on asset sales Long-lived asset impairment Segment adjusted EBITDA Year ended December 31, Percentage Change 2019 2018 2017 2019 v. 2018 2018 v. 2017 DJ Basin (Dollars in thousands) 21,940 $ 389 3,721 26,050 34 7,616 315 3,732 — 34,913 46,610 11,251 $ 371 3,672 15,294 45 6,482 647 3,133 — 9 10,316 8,918 398 2,544 11,860 17 5,001 218 2,636 3 — 7,875 3,732 3,133 2,636 95% 5% 1% 70% (24%) 17% (51%) 19% * * 352% 26% (7%) 44% 29% 165% 30% 197% 19% * * 31% $ 583 — 34,913 18,668 $ 90 (562) — 9 7,558 $ — 3 — 6,624 147% 14% Table of Contents * Not considered meaningful Year ended December 31, 2019. Segment adjusted EBITDA increased $11.1 million compared to the year ended December 31, 2018, primarily reflecting: • • a $10.7 million increase in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity, a more favorable volume and gathering rate mix from customers, and the commissioning of our new natural gas processing plant in June 2019. This was partially offset by natural production declines. a $1.1 million increase in operation and maintenance expense primarily due to higher costs to support volume growth. Other items to note: • During the quarter ended March 31, 2019, we impaired certain long-lived assets in the DJ Basin (see Note 5 to the consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2019. Year ended December 31, 2018. Segment adjusted EBITDA increased $0.9 million compared to the year ended December 31, 2017, primarily reflecting: • • an increase in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity. a $1.5 million increase in operation and maintenance expense primarily due to $1.1 million of higher electricity expenses we pass through to certain customers (which is also included in the increase in Other revenues in the table above) in addition to higher operation and maintenance costs to support volume growth. Permian Basin. The Summit Permian system provides our midstream services for the Permian Basin reportable segment. Volume throughput for our Permian Basin reportable segment follows. Average daily throughput (MMcf/d) 91 Permian Basin Year ended December 31, 2019 2018 19 Percentage Change 2019 v. 2018 * 1 Table of Contents 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, Percentage Change 2019 2018 2019 v. 2018 (In thousands) $ 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) $ 115 843 — 958 1,569 428 161 243 — 761 3,162 243 — 761 (1,200) * * * * * * * * * * * * Year ended December 31, 2019. Segment adjusted EBITDA totaled ($0.9) million primarily reflecting fixed operating costs associated with commissioning and operating the Lane processing plant and certain inefficiencies and higher fuel costs associated with lower plant utilization and initial production volumes. Other items to note: In December 2019, we impaired certain long-lived assets in the Permian Basin (see Notes 5 and 6 to the consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2019. Year ended December 31, 2018. Segment adjusted EBITDA totaled ($1.2) million primarily reflecting less than one month’s volume throughput of the Summit Permian natural gas gathering and processing system commissioned in December 2018 as well as operational and general and administrative expenses incurred during the year. Piceance Basin. The Grand River system provides midstream services for the Piceance Basin reportable segment. Volume throughput for our Piceance Basin reportable segment follows. Aggregate average daily throughput (MMcf/d) 2019 Year ended December 31, 2018 2017 2019 v. 2018 2018 v. 2017 Percentage Change Piceance Basin 452 551 582 (18%) (5%) 92 Table of Contents Volume throughput decreased compared to the year ended December 31, 2018, as a result of natural production declines. Volume throughput decreased compared to the year ended December 31, 2017, as a result of natural production declines, partially offset by drilling and completion activity that occurred across our service area during the second half of 2017 and through the third quarter of 2018. Financial data for our Piceance Basin reportable segment follows. 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 MVC shortfall payments Adjustments related to capital reimbursement activity Loss on asset sales, net Long-lived asset impairment Segment adjusted EBITDA * Not considered meaningful Piceance Basin Year ended December 31, Percentage Change 2019 2018 2017 2019 v. 2018 2018 v. 2017 (Dollars in thousands) $ 121,357 $ 135,810 $ 136,834 (11%) 7,954 4,327 133,638 14,800 4,909 155,519 13,452 4,607 154,893 5,612 27,306 1,009 47,018 104 14,162 95,211 9,591 33,947 1,168 46,919 — 1,004 92,629 7,952 30,143 2,617 46,289 — 697 87,698 47,018 46,919 46,289 (103) 10 (3,068) (46%) (12%) (14%) (41%) (20%) (14%) * * * 3% (1%) 10% 7% 0% 21% 13% (55%) 1% * * 6% (843) 104 14,162 98,765 $ 219 — 1,004 111,042 $ — — 697 111,113 $ (11%) (0%) Year ended December 31, 2019. Segment adjusted EBITDA decreased $12.3 million compared to the year ended December 31, 2018, primarily reflecting: • • • a $14.5 million decrease in gathering services and related fees as a result of natural production declines. a $2.9 million decrease in natural gas, NGLs and condensate activity (sales and purchases) as a result of lower volume throughput and lower commodity prices associated with the sale of NGLs and condensate. a $6.6 million decrease in operation and maintenance expense primarily due to a $3.3 million reduction in planned compressor overhaul maintenance costs and $2.2 million in lower compensation expense. Other items to note: • In December 2019, we sold certain assets from our Red Rock Gathering system and recorded an impairment charge of $14.2 million based on the difference between the consideration received and the then carrying value of the assets at closing. The noncash impairment expense had no impact on segment adjusted EBITDA for the year ended December 31, 2019. 93 Table of Contents Year ended December 31, 2018. Segment adjusted EBITDA decreased $0.1 million compared to the year ended December 31, 2017, primarily reflecting: • • • a $3.8 million increase in operation and maintenance expense primarily due to planned compressor overhaul maintenance costs during the period. a $1.5 million decrease in general and administrative expenses. a $2.3 million increase, after taking into account the adjustments related to MVC shortfall payments and adjustments related to capital reimbursement activity, in gathering services and related fees primarily as a result of the drilling and completion activity that occurred across our service area by other customers during the second half of 2017 and through the third quarter of 2018, and a $1.0 million MVC shortfall payment received from a customer in 2018 that did not occur in 2017, partially offset by natural production declines. Barnett Shale. The DFW Midstream system provides our midstream services for the Barnett Shale reportable segment. Volume throughput for our Barnett Shale reportable segment follows. Average daily throughput (MMcf/d) 2019 Year ended December 31, 2018 2017 251 253 267 Percentage Change 2019 v. 2018 (1%) 2018 v. 2017 (5%) Barnett Shale Volume throughput decreased slightly compared to the year ended December 31, 2018 reflecting natural production declines partially offset by new volumes from well completion activity throughout 2019. Volume throughput declined compared to the year ended December 31, 2017 reflecting natural production declines, partially offset by new volumes from completion activity during the fourth quarter of 2017, first quarter of 2018 and the fourth quarter of 2018. 94 Table of Contents 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) 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 Year ended December 31, Percentage Change 2019 2018 2017 2019 v. 2018 2018 v. 2017 Barnett Shale $ (Dollars in thousands) 47,862 $ 17,147 6,793 71,802 10,751 21,729 968 15,354 (325) 10,095 58,572 59,030 $ 2,523 6,712 68,265 — 21,358 971 15,658 (68) — 37,919 61,622 1,946 8,099 71,667 — 23,074 1,146 15,604 4 — 39,828 16,575 15,325 15,001 3,579 (3,642) (612) (19%) 580% 1% 5% * 2% (0%) (2%) * * 54% (4%) 30% (17%) (5%) * (7%) (15%) 0% * * (5%) (111) (325) 10,095 43,043 $ 1,307 (68) — 43,268 $ — 4 — 46,232 $ (1%) (6%) *Not considered meaningful (1) Includes the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues. Year ended December 31, 2019. Segment adjusted EBITDA decreased $0.2 million compared to the year ended December 31, 2018. Other items to note: • • Impacting 2019 revenues was the presentation of $4.5 million of gathering services as a reduction to cost of natural gas and NGLs due to the assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream operations. In March 2019, we impaired certain long-lived assets in the Barnett Shale (see Note 5 to the consolidated financial statements). The noncash impairment expense had no impact on segment adjusted EBITDA for the year ended December 31, 2019. Year ended December 31, 2018. Segment adjusted EBITDA decreased $3.0 million compared to the year ended December 31, 2017, primarily reflecting: • • a $4.3 million decrease, after taking into account the adjustments related to MVC shortfall payments and adjustments related to capital reimbursement activity, in gathering services and related fees associated with the expiration of MVCs during 2017 of $3.6 million in addition to lower volume throughput. a $1.7 million decrease in operation and maintenance expense primarily from $1.3 million of lower electricity expenses associated with lower volume throughput and a decrease in tax expenses. Marcellus Shale. The Mountaineer Midstream system provides our midstream services for the Marcellus Shale reportable segment. 95 Table of Contents Volume throughput for the Marcellus Shale reportable segment follows. Average daily throughput (MMcf/d) Marcellus Shale Year ended December 31, 2019 2018 2017 363 474 502 Percentage Change 2019 v. 2018 (23%) 2018 v. 2017 (6%) Volume throughput decreased compared to the year ended December 31, 2018, primarily due to natural production declines partially offset by additional drilling and completion activities. Volume throughput decreased compared to the year ended December 31, 2017, primarily due to natural production declines. These declines were partially offset by volumes generated by the completion, in the second half of 2017 and first quarter of 2018, of a number of drilled but uncompleted (“DUC”) wells. 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 Goodwill impairment Total costs and expenses Add: Depreciation and amortization Goodwill impairment Adjustments related to capital reimbursement activity Segment adjusted EBITDA *Not considered meaningful Marcellus Shale Year ended December 31, Percentage Change 2019 2018 2017 2019 v. 2018 2018 v. 2017 (Dollars in thousands) $ 24,471 $ 24,471 29,573 $ 29,573 30,394 30,394 3,861 521 9,141 16,211 29,734 9,141 16,211 4,813 397 9,090 — 14,300 6,057 449 9,047 — 15,553 9,090 — 9,047 — (17%) (17%) (20%) 31% 1% * 108% (3%) (3%) (21%) (12%) 0% * (8%) (38) 20,051 $ (96) 24,267 $ — 23,888 $ (17%) 2% Year ended December 31, 2019. Segment adjusted EBITDA decreased $4.2 million compared to the year ended December 31, 2018, primarily reflecting: • • a $5.1 million decrease in gathering services and related fees as a result of volume declines partially offset by additional drilling and completion activities. a $1.0 million decrease in operation and maintenance expense primarily due to a decrease in various operating expenses. Other items to note: • In September 2019, we recorded a goodwill impairment charge of $16.2 million relating to the Mountaineer Midstream system in the Marcellus Shale (see Note 7 to the consolidated financial statements). This noncash impairment expense had no impact on segment adjusted EBITDA for the year ended December 31, 2019. 96 Table of Contents Year ended December 31, 2018. Segment adjusted EBITDA increased $0.4 million compared to the year ended December 31, 2017, primarily reflecting: • • a $0.8 million decrease in gathering services and related fees as a result of volume declines. a $1.2 million decrease in operation and maintenance expense primarily due to declines in expenses for repairs to right-of-way of $0.9 million and lower property taxes of $0.7 million during the period. Corporate and Other Overview for the Years Ended December 31, 2019, 2018 and 2017 Corporate and Other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, natural gas and crude oil marketing services, transaction costs, interest expense, early extinguishment of debt and a change in the Deferred Purchase Price Obligation fair value. Revenues: Total revenues Costs and expenses: Cost of natural gas and NGLs General and administrative Transaction costs Interest expense Early extinguishment of debt (1) Deferred Purchase Price Obligation Corporate and Other 2019 Year ended December 31, 2018 (Dollars in thousands) 2017 2019 v. 2018 2018 v. 2017 Percentage Change $ 27,622 $ 78,161 $ 19,517 26,107 48,989 1,788 74,429 — (1,982) 78,172 47,070 — 60,535 — 20,975 19,264 47,507 73 68,131 22,039 (200,322) * * 4% 23% * * * * (1%) (11%) * * * Not considered meaningful (1) Early extinguishment of debt includes $17.9 million paid for redemption and call premiums, as well as $4.1 million of unamortized debt issuance costs which were written off in connection with the repurchase of the outstanding $300.0 million 7.5% Senior Notes in the first quarter of 2017. Total Revenues. Total revenues attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services (primarily natural gas sales). The decrease of $50.5 million compared to the year ended December 31, 2018 was attributable to lower natural gas, NGL and crude oil marketing activity. The increase of $58.6 million compared to the year ended December 31, 2017 was attributable to higher natural gas, NGL and crude oil marketing activity. Cost of Natural Gas and NGLs. Cost of natural gas and NGLs attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services. The decrease of $52.1 million compared to the year ended December 31, 2018 was attributable to lower marketing activity. The increase of $58.9 million compared to the year ended December 31, 2017 was attributable to higher marketing activity. General and Administrative. General and administrative expense increased $1.9 million compared to the year ended December 31, 2018, primarily due to a $7.3 million increase in severance and restructuring expenses partially offset by lower headcount associated with our cost cutting initiatives and lower performance-based compensation. General and administrative expense decreased compared to the year ended December 31, 2017, primarily reflecting reductions in information technology costs. Transaction costs. Transaction costs recognized during the year ended December 31, 2019 primarily relate to $0.9 million in financial advisory costs associated with the Equity Restructuring and $0.5 million in financial advisory costs associated with the DPPO restructuring. 97 Table of Contents Interest Expense. Interest expense increased $13.9 million compared to the year ended December 31, 2018 primarily as a result of a higher average outstanding balance on the Revolving Credit Facility. Interest expense decreased $7.6 million compared to the year ended December 31, 2017 as a result of (i) the tender and redemption of the $300.0 million principal 7.5% Senior Notes, (ii) the issuance of 300,000 Series A Preferred Units in November 2017 whereby the net proceeds were used to repay outstanding borrowings under our Revolving Credit Facility and (iii) a lower average outstanding balance on the Revolving Credit Facility. The decrease was partially offset by the interest associated with issuance of the $500.0 million principal 5.75% Senior Notes and an increase in the interest rate on the Revolving Credit Facility. Early Extinguishment of Debt. The early extinguishment of debt recognized during the year ended December 31, 2017 was driven by the tender and redemption of the $300.0 million principal amount of 7.5% Senior Notes. Deferred Purchase Price Obligation. Deferred Purchase Price Obligation recognized during the year ended December 31, 2019 represents the change in present value of the estimated Remaining Consideration to be paid in connection with the 2016 Drop Down (see Note 17 to the consolidated financial statements). Deferred Purchase Price Obligation recognized during the year ended December 31, 2018 represents the change in present value of the estimated Remaining Consideration to be paid in connection with the 2016 Drop Down. The change was primarily due to the passage of time and an associated decrease in the discount rate, partially offset by the continued slowing and deferral of drilling and completion activities to periods outside of the DPPO measurement period. Liquidity and Capital Resources Based on the terms of our Partnership Agreement, we expect that we will make distributions to our unitholders with cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flows generated from our operations, borrowings under our Revolving Credit Facility, future issuances of debt, preferred equity and equity securities and proceeds from potential asset divestitures. Capital Markets Activity January 2020 Shelf Registration Statement. In November 2019, we filed the 2020 SRS which registered an indeterminate amount of common units, preferred units, warrants, rights, debt securities and guarantees. In January 2020, the SEC declared the 2020 SRS effective. There have been no transactions executed on the 2020 SRS. July 2017 Shelf Registration Statement. In July 2017, we filed the 2017 SRS with the SEC to issue an indeterminate amount of debt, equity securities and guarantees. In November 2017, we filed a post-effective amendment to the 2017 SRS with the SEC to register, in addition to the classes of securities originally registered, an indeterminate amount of preferred units representing limited partner interests in the Partnership. The 2017 SRS expires in July 2020. However, we are no longer a well-known seasoned issuer and are therefore not able to use the 2017 SRS. The following transaction was executed pursuant thereto: • In November 2017, we issued 300,000 9.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership at a price to the public of $1,000 per unit. We used the net proceeds of $293.2 million (after deducting underwriting discounts and offering expenses) to repay outstanding borrowings under our Revolving Credit Facility. November 2016 Shelf Registration Statement. In October 2016, we filed the 2016 SRS and in November 2016, the SEC declared it effective. The following transactions have been executed pursuant thereto: • In February 2017, we completed a secondary public offering of 4,000,000 SMLP common units held by a subsidiary of Summit Investments in accordance with our obligations under our Partnership Agreement. We did not receive any proceeds from this secondary offering. 98 Table of Contents • In February 2017, we executed a new equity distribution agreement and filed a prospectus supplement with the SEC for the issuance and sale from time to time of SMLP common units having an aggregate offering price of up to $150.0 million (the “ATM Program”). Sales of our common units may be made in negotiated transactions or transactions that are deemed to be at-the-market offerings as defined by SEC rules. During the years ended December 31, 2019 and 2018, we did not issue any units under the ATM Program. During the year ended December 31, 2017, we issued 763,548 units under the ATM Program for aggregate gross proceeds of $17.7 million, and paid approximately $0.2 million as compensation to the sales agents pursuant to the terms of the equity distribution agreement. Our General Partner made capital contributions to maintain its approximate 2% General Partner interest in SMLP. The 2016 SRS expired in November 2019. Debt Revolving Credit Facility. We have a $1.25 billion senior secured Revolving Credit Facility. On May 26, 2017, Summit Holdings closed on the Third Amended and Restated Credit Agreement which extended the maturity from November 2018 to May 2022 (see Note 10 to the consolidated financial statements). As of December 31, 2019, the outstanding balance of the Revolving Credit Facility was $677.0 million and the unused portion totaled $563.9 million, after giving effect to the issuance thereunder of a $9.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of December 31, 2019 was approximately $100 million. There were no defaults or events of default during 2019, and as of December 31, 2019, we were in compliance with the financial covenants in the Revolving Credit Facility. See Notes 10 and 16 to the consolidated financial statements for more information on the Revolving Credit Facility and the issuance of the $9.1 million letter of credit, respectively. Senior Notes. In February 2017, the Co-Issuers co-issued $500.0 million of 5.75% Senior Notes. In July 2014, the Co-Issuers co-issued $300.0 million of 5.50% Senior Notes. There were no defaults or events of default as of and for the year ended December 31, 2019 on either series of senior notes. For additional information on our long-term debt, see Notes 10 and 18 to the consolidated financial statements. Deferred Purchase Price Obligation In March 2016, we entered into an agreement with a subsidiary of Summit Investments to fund a portion of the 2016 Drop Down whereby we have recognized the Deferred Purchase Price Obligation (see Note 17 to the consolidated financial statements and the “Contractual Obligations Update” section below). LIBOR Transition LIBOR is the basic rate of interest widely used as a reference for setting the interest rates on loans globally. In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, a steering committee comprised of large U.S. financial institutions, is considering replacing U.S. dollar LIBOR with a new index, the Secured Overnight Financing Rate (“SOFR”), calculated using short-term repurchase agreements backed by Treasury securities. We are evaluating the potential impact of the eventual replacement of the LIBOR benchmark interest rate, however, we are not able to predict whether LIBOR will cease to be available after 2021, whether SOFR will become a widely accepted benchmark in place of LIBOR, or what the impact of such a possible transition to SOFR may be on our business, financial condition and results of operations. 99 Table of Contents We will need to renegotiate our Revolving Credit Facility to determine the interest rate to replace LIBOR with the new standard that is established. The potential effect of any such event on interest expense cannot yet be determined. Cash Flows Net cash provided by operating activities Net cash used in investing activities Net cash used in financing activities Net change in cash, cash equivalents and restricted cash 2019 Year ended December 31, 2018 2017 $ $ (In thousands) 182,337 $ (90,870) (63,472) 27,995 $ 227,929 $ (216,279) (8,735) 2,915 $ 237,832 (148,683) (95,147) (5,998) The components of the net change in cash, cash equivalents and restricted cash were as follows: Operating activities. Cash flows from operating activities for the year ended December 31, 2019, primarily reflected: • • a $12.2 million increase in cash interest payments; and other changes in working capital. Cash flows from operating activities for the year ended December 31, 2018, primarily reflected: • • • a $6.8 million decrease in cash interest payments due to the extinguishment of the 7.5% Senior Notes in the first quarter of 2017; a decrease in distributions from equity method investees; and other changes in working capital. Investing activities. Details of cash flows from investing activities follow. Cash flows used in investing activities during the year ended December 31, 2019 primarily reflected: • • • • $182.3 million of capital expenditures primarily attributable to the ongoing development of the DJ Basin of $80.5 million, Summit Permian of $45.0 million, the Williston Basin of $30.9 million and Corporate and Other, which includes $17.7 million of capital expenditures relating to the Double E Project; $18.3 million for investments in the Double E joint venture relating to the Double E Project; $89.5 million of net proceeds from the Tioga Midstream sale and $12.0 million of proceeds from the Red Rock Gathering sale; and $7.3 million for a distribution from an equity method investment. Cash flows used in investing activities during the year ended December 31, 2018 primarily reflected: • • • $200.6 million of capital expenditures primarily attributable to the ongoing development of the Permian Basin of $83.8 million as well as the continued development in the DJ Basin of $64.9 million, and the Williston Basin of $25.2 million; a $10.9 million purchase of a noncontrolling interest; and $4.9 million of capital contributions to Ohio Gathering. Financing activities. Details of cash flows from financing activities follow. Cash flows used in financing activities during the year ended December 31, 2019 primarily reflected: • • • $145.1 million of distributions; $211.0 million of net borrowings under our Revolving Credit Facility; $151.8 million payment on the Deferred Purchase Price Obligation; and 100 Table of Contents • $27.4 of net proceeds from the issuance of Subsidiary Series A Preferred Units. Cash flows used in financing activities during the year ended December 31, 2018 primarily reflected: • • $209.2 million of distributions; and $205.0 million of net borrowings under our Revolving Credit Facility. Contractual Obligations Update The table below summarizes our contractual obligations as of December 31, 2019. Long-term debt and interest payments (1) Deferred Purchase Price Obligation (2) Purchase obligations (3) Finance leases (4) Operating leases (4) Total contractual obligations Total Less than 1 year 1-3 years 3-5 years More than 5 years $ 1,757,558 $ 180,750 132,622 1,991 4,803 $ 2,077,724 $ (In thousands) — 132,622 1,299 1,705 78,884 $ 1,106,799 $ 180,750 — 692 1,555 214,510 $ 1,289,796 $ 57,500 $ — — — 648 58,148 $ 514,375 — — — 895 515,270 (1) For the purpose of calculating future interest on the Revolving Credit Facility, assumes no change in balance or rate from December 31, 2019. Includes a 0.50% commitment fee on the unused portion of the Revolving Credit Facility and a 0.125% fronting fee on the outstanding but undrawn irrevocable standby letter of credit. See Note 10 to the consolidated financial statements. (2) See Note 17 to the consolidated financial statements. (3) Represents agreements to purchase goods or services that are enforceable and legally binding. (4) See Item 2. Properties and Note 16 to the consolidated financial statements. In March 2016, we recognized the Deferred Purchase Price Obligation in connection with the 2016 Drop Down. Pursuant to the Equity Restructuring, in April 2019, the Partnership made a cash payment of $100 million to SMP Holdings in partial settlement of the Deferred Purchase Price Obligation. On November 7, 2019, we and SMP Holdings entered into a second amendment (the “Second Amendment”) to the Contribution Agreement between us and SMP Holdings dated February 25, 2016, as amended. On November 15, 2019, we made a cash payment of $51.75 million and issued 10,714,285 common units to SMP Holdings (the “November 2019 Prepayment”). In addition, the parties reduced the Remaining Consideration due to SMP Holdings by $19.25 million. Following the November 2019 Prepayment, the Remaining Consideration is $180.75 million. The parties also extended the final date by which we are obligated to deliver the Remaining Consideration to January 15, 2022. The Remaining Consideration remains payable to SMP Holdings in (i) cash, (ii) our common units or (iii) a combination of cash and our common units, and interest continues to accrue (and is payable quarterly in cash) at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020. The form(s) of Remaining Consideration to be delivered by us to SMP Holdings continue to be determinable by us in our sole discretion. The present value of the Deferred Purchase Price Obligation is reflected as a liability on our balance sheet until paid. As of December 31, 2019, the Remaining Consideration, which reflects the net present value of the $180.75 million Deferred Purchase Price Obligation, was $178.5 million on the consolidated balance sheet using a discount rate of 5.25%. 101 Table of Contents Capital Requirements Our business is capital intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our Partnership Agreement requires that we categorize our capital expenditures as either: • • maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. For the year ended December 31, 2019, cash paid for capital expenditures totaled $182.3 million (see Note 4 to the consolidated financial statements) which included $14.2 million of maintenance capital expenditures. For the year ended December 31, 2019, there were no contributions to Ohio Gathering and we contributed $18.3 million to Double E (see Note 8 to the consolidated financial statements). For the year ended December 31, 2018, cash paid for capital expenditures totaled $200.6 million, compared with $124.2 million for the year ended December 31, 2017 (see Note 4 to the consolidated financial statements). Maintenance capital expenditures totaled $21.4 million for the year ended December 31, 2018 compared to $15.6 million for the year ended December 31, 2017. For the year ended December 31, 2018, contributions to equity method investees totaled $4.9 million, compared with $25.5 million for the year ended December 31, 2017 (see Note 8 to the consolidated financial statements). The year-over-year increase in cash paid for capital expenditures primarily reflected the expansion of our existing gathering and processing complex in the DJ Basin with the addition of a new 60 MMcf/d cryogenic processing plant in addition to the development of our new associated natural gas gathering and processing system in the Permian Basin. We rely primarily on internally generated cash flow as well as external financing sources, including commercial bank borrowings and the issuance of debt, equity and preferred equity securities, and proceeds from potential asset divestitures to fund our capital expenditures. We believe that our Revolving Credit Facility, together with internally generated cash flow and access to debt or equity capital markets, will be adequate to finance our business for the foreseeable future without adversely impacting our liquidity. With the completion of our 60 MMcf/d DJ Basin processing plant and compression expansions in the Permian Basin, capital expenditures began to decline in the third and fourth quarter of 2019. We will remain disciplined with respect to future capital expenditures, which will be primarily concentrated on the Double E Project and accretive expansions of our existing systems in our Core Focus Areas. We continue to advance our financing plans for our equity interest in Double E, which we intend to be credit neutral to Summit. We are currently targeting a financing structure that limits cash payments by us during 2020, and which shifts a substantial majority of our Double E capital commitments to third parties. On December 24, 2019, we entered into an agreement with TPG Energy Solutions Anthem, L.P. (“TPG”) to fund up to $80 million of Permian Holdco’s future capital calls associated with the Double E Project. Simultaneously, on December 24, 2019, Permian Holdco issued 30,000 Subsidiary Series A Preferred Units to TPG for net proceeds of $27.3 million. We estimate that our 2020 capital program will range from $50 million to $70 million, including approximately $10 million related to our equity method investment in Double E. There are a number of risks and uncertainties that could cause our current expectations to change, including, but not limited to, (i) the ability to reach agreement with third parties; (ii) prevailing conditions and outlook in the natural gas, crude oil and natural gas liquids industries and markets and (iii) our ability to obtain financing from commercial banks, the capital markets, or other financing sources. 102 Table of Contents Credit and Counterparty Concentration Risks We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. Certain of our customers may be temporarily unable to meet their current obligations. While this may cause disruption to cash flows, we believe that we are properly positioned to deal with the potential disruption because the vast majority of our gathering assets are strategically positioned at the beginning of the midstream value chain. The majority of our infrastructure is connected directly to our customers’ wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customers’ commodities flow and, in many cases, the only way for our customers to get their production to market. We have exposure due to nonperformance under our MVC contracts whereby a customer, who was not meeting its MVCs, does not have the wherewithal to make its MVC shortfall payments when they become due. We typically receive payment for all prior-year MVC shortfall billings in the quarter immediately following billing. Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period. For additional information, see Notes 4, 9 and 11 to the consolidated financial statements. Off-Balance Sheet Arrangements We had no off-balance sheet arrangements as of or during the year ended December 31, 2019. Critical Accounting Estimates We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. Our significant accounting policies are described in Note 2 to the consolidated financial statements. The estimates that we deem to be most critical to an understanding of our financial position and results of operations are those related to determination of fair value. The preparation and evaluation of these critical accounting estimates involve the use of various assumptions developed from management's analyses and judgments. Subsequent experience or use of other methods, estimates or assumptions could produce significantly different results. Our critical accounting estimates are as follows: Recognition and Impairment of Long-Lived Assets Our long-lived assets include property, plant and equipment and amortizing intangible assets. Property, Plant and Equipment and Amortizing Intangible Assets. As of December 31, 2019, we had net property, plant and equipment with a carrying value of approximately $1.9 billion and net amortizing intangible assets with a carrying value of approximately $232.3 million. When evidence exists that we will not be able to recover a long-lived asset's carrying value through future cash flows, we write down the carrying value of the asset to its estimated fair value. We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable as well as in connection with any goodwill impairment evaluations. 103 Table of Contents With respect to property, plant and equipment and our amortizing intangible assets, the carrying value of a long-lived asset is not recoverable if the carrying value exceeds the sum of the undiscounted cash flows expected to result from the asset's use and eventual disposal. In this situation, we recognize an impairment loss equal to the amount by which the carrying value exceeds the asset's fair value. We determine fair value using an income-based and market-based approach in which we discount the asset's expected future cash flows to reflect the risk associated with achieving the underlying cash flows. Any impairment determinations involve significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these estimates are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment. 2019 Impairments. In the DJ Basin, we determined that certain processing plant assets related to our existing 20 MMcf/d plant would no longer be utilized due to our expansion plans for the Niobrara G&P system. Based on the results of the recoverability assessment and the conclusion that the carrying value was not fully recoverable, we recorded an impairment charge of $34.7 million related to these assets in the first quarter of 2019. In the Piceance Basin, we sold certain Red Rock Gathering system assets for a cash purchase price of $12.0 million. Prior to closing, we recorded an impairment charge of $14.2 million in the fourth quarter of 2019 based on the expected consideration and the carrying value for the Red Rock Gathering system assets. In the Barnett Shale, we determined that certain compressor station assets would be shut down and decommissioned. As a result, we recorded an impairment charge of $9.7 million related to these assets in the first quarter of 2019. Also in connection with this evaluation, we evaluated the related intangible assets associated therewith for impairment consisting of rights-of-way intangible assets. We concluded the rights-of-way intangible assets were also impaired and, as a result, we recorded an impairment charge of $0.5 million in the first quarter of 2019. In the Permian Basin, in connection with the cancellation of a project, we determined certain processing plant assets and the related rights- of-way intangible assets would no longer be utilized. As a result, we recorded an impairment charge of $0.7 million and $0.6 million related to the processing plant assets and rights-of-way intangible assets, respectively, in the fourth quarter of 2019. See Notes 5 and 6 for additional details. 2018 Impairments. In December 2018, in connection with certain strategic initiatives, we performed a recoverability assessment of certain assets within the Williston Basin reporting segment. Based on the results, we concluded that the carrying value of certain long-lived assets related to the Tioga Midstream system within the Williston Basin were not fully recoverable. We recorded an impairment charge of $3.9 million related to these assets after comparing the fair value of the long-lived assets to their carrying values. In addition, we reviewed other assets that had been identified as potentially impaired and recognized long-lived asset impairments as detailed in Note 5 to the consolidated financial statements. 2017 Impairments. In December 2017, in connection with certain strategic initiatives, we performed a financial review of certain assets within the Williston Basin reporting segment. This resulted in a triggering event that required us to perform a recoverability test. Based on the results of the test, we concluded that the carrying value of certain long-lived assets and the related intangible assets related to the Bison Midstream system in the Williston Basin were not fully recoverable. As a result, we recorded an impairment charge of $101.9 million related to the long-lived assets and $85.2 million related to contract intangibles assets. For additional information, see Notes 2, 5 and 6 to the consolidated financial statements. Goodwill. We evaluate goodwill for impairment annually on September 30 and whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value, including goodwill. 104 Table of Contents 2019 Impairment Evaluation. We performed our annual goodwill impairment testing for the Mountaineer Midstream reporting unit as of September 30, 2019 using a combination of the income and market approaches. We determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value, including goodwill. As a result, we recognized a goodwill impairment charge of $16.2 million for the year ended December 31, 2019. 2018 and 2017 Impairment Evaluations. We performed our 2018 and 2017 annual goodwill impairment analysis as of September 30 and concluded that none of our goodwill had been impaired. See Notes 2 and 7 for additional information. Minimum Volume Commitments Adjustments for MVC Shortfall Payments. We estimate the impact of expected MVC shortfall payments for inclusion in our calculation of segment adjusted EBITDA. Adjustments related to MVC shortfall payments account for: • • the net increases or decreases in deferred revenue for MVC shortfall payments and our inclusion of expected annual MVC shortfall payments. We also included a proportional amount of any historical and expected MVC shortfall payments in each quarter prior to the quarter in which we actually recognized the shortfall payment. We estimate expected MVC shortfall payments based on assumptions including, but not limited to, contract terms, historical volume throughput data and expectations regarding future investment, drilling and production. For additional information, see Notes 2, 4 and 9 to the consolidated financial statements and the "Results of Operations" and "Liquidity and Capital Resources—Credit and Counterparty Concentration Risks" sections herein. Forward-Looking Statements Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officers and employees during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us, our subsidiaries, Summit Investments or our Sponsor, are also forward-looking statements. These forward-looking statements involve various risks and uncertainties, including, but not limited to, those described in Item 1A. Risk Factors included in this report. Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this paragraph. These risks and uncertainties include, among others: • • • • • our ability to sustain our current rate of cash distributions; fluctuations in natural gas, NGLs and crude oil prices; the extent and success of our customers' drilling efforts, as well as the quantity of natural gas, crude oil and produced water volumes produced within proximity of our assets; failure or delays by our customers in achieving expected production in their natural gas, crude oil and produced water projects; competitive conditions in our industry and their impact on our ability to connect hydrocarbon supplies to our gathering and processing assets or systems; 105 Table of Contents • • • • • • • • • • • • • • • • • • • 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 or the Deferred Purchase Price Obligation, including through opportunistic asset divestitures or joint ventures and the impact any such divestitures or joint ventures could have on our results; the effects of existing and future laws and governmental regulations, including environmental, safety and climate change requirements and federal, state and local restrictions or requirements applicable to oil and/or gas drilling, production or transportation; the ability of SMP Holdings to meet its obligations under its senior secured term loan facility; changes in tax status; the effects of litigation; changes in general economic conditions; and certain factors discussed elsewhere in this report. 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. 106 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 debt portfolio. As of December 31, 2019, we had $800.0 million principal of fixed-rate Senior Notes and $677.0 million outstanding under our variable rate Revolving Credit Facility (see Note 10 to the consolidated financial statements). 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, 2019, a hypothetical 1% increase (decrease) in interest rates would have increased (decreased) our interest expense by approximately $5.7 million assuming no changes in amounts drawn or other variables under our Revolving Credit Facility or Senior Notes. Commodity Price Risk We currently 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 on the Bison Midstream, Grand River and Summit Permian systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. Our gathering agreements with certain DFW Midstream 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. Our gathering agreements with our Grand River customers permit us to retain condensate volumes from the Grand River system gathering lines. 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. 107 Table of Contents Item 8. Financial Statements and Supplementary Data. Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets as of December 31, 2019 and 2018 Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017 Consolidated Statements of Partners' Capital for the years ended December 31, 2019, 2018 and 2017 Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017 Notes to Consolidated Financial Statements 1. Organization, Business Operations and Presentation and Consolidation 2. Summary of Significant Accounting Policies 3. Revenue 4. Segment Information 5. Property, Plant and Equipment, Net 6. Amortizing Intangible Assets 7. Goodwill 8. Equity Method Investments 9. Deferred Revenue 10. Debt 11. Financial Instruments 12. Partners' Capital and Mezzanine Capital 13. Earnings Per Unit 14. Unit-Based and Noncash Compensation 15. Related-Party Transactions 16. Leases, Commitments and Contingencies 17. Dispositions, Drop Down Transactions and Restructuring 18. Condensed Consolidated Financial Information 19. Unaudited Quarterly Financial Data 20. Subsequent Events 108 109 110 111 112 113 115 115 116 122 124 128 130 131 131 133 135 138 139 143 143 145 145 149 151 160 160 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, 2019 and 2018, the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2019, 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 Partnership 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. We did not audit the financial statements of Ohio Gathering Company, L.L.C. (“Ohio Gathering”) as of and for the years ended December 31, 2019, 2018, and 2017, 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 and $642,036,000 as of December 31, 2019 and 2018, respectively, and its loss from equity method investee in Ohio Gathering of $329,736,000, $11,085,000, and $1,823,000 for the years ended December 31, 2019, 2018 and 2017, respectively. 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 prior to the impairment loss discussed in Note 8, 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, 2019, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 9, 2020 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 the other auditors provide a reasonable basis for our opinion. /s/ Deloitte & Touche LLP Atlanta, Georgia March 9, 2020 We have served as the Partnership's auditor since 2009. 109 Table of Contents SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS Assets Current assets: Cash and cash equivalents Restricted cash Accounts receivable Other current assets Total current assets Property, plant and equipment, net Intangible assets, net Goodwill Investment in equity method investees Other noncurrent assets Total assets Liabilities and Capital Current liabilities: Trade accounts payable Accrued expenses Due to affiliate Deferred revenue Ad valorem taxes payable Accrued interest Accrued environmental remediation Other current liabilities Total current liabilities Long-term debt Noncurrent Deferred Purchase Price Obligation Noncurrent deferred revenue Noncurrent accrued environmental remediation Other noncurrent liabilities Total liabilities Commitments and contingencies (Note 16) $ $ $ December 31, 2019 December 31, 2018 (In thousands, except unit amounts) 4,948 $ 27,392 102,118 5,018 139,476 1,882,251 232,278 — 309,728 9,718 2,573,451 $ 24,415 $ 11,482 311 13,493 8,477 12,311 1,725 11,933 84,147 1,470,299 178,453 38,709 2,926 7,951 1,782,485 4,345 — 97,936 3,971 106,252 1,963,713 273,416 16,211 649,250 11,720 3,020,562 38,414 21,963 240 11,467 10,550 12,286 2,487 12,645 110,052 1,257,731 383,934 39,504 3,149 4,968 1,799,338 Mezzanine Capital Subsidiary Series A Preferred Units (30,058 units issued and outstanding at December 31, 2019) Partners' Capital Series A Preferred Units (300,000 units issued and outstanding at December 31, 2019 and December 31, 2018) Common limited partner capital (93,493,473 units issued and outstanding at December 31, 2019 and 73,390,853 units issued and outstanding at December 31, 2018) General Partner interests (zero units issued and outstanding at December 31, 2019 and 1,490,999 units issued and outstanding at December 31, 2018) Total partners' capital Total liabilities, mezzanine capital and partners' capital The accompanying notes are an integral part of these consolidated financial statements. 27,450 — 293,616 293,616 469,900 902,358 — 763,516 2,573,451 $ 25,250 1,221,224 3,020,562 $ 110 Table of Contents SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS 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) loss on asset sales, net Long-lived asset impairment Goodwill impairment Total costs and expenses Other income (expense) Interest expense Early extinguishment of debt Deferred Purchase Price Obligation (Loss) income before income taxes and loss from equity method investees Income tax expense Loss from equity method investees Net (loss) income Less: Net income attributable to noncontrolling interest Net (loss) income attributable to SMLP Net income attributable to General Partner, including IDRs Net (loss) income attributable to limited partners Net income attributable to Series A Preferred Units Net income attributable to Subsidiary Series A Preferred Units Net (loss) income attributable to common limited partners (Loss) income per limited partner unit: Common unit – basic Common unit – diluted $ $ $ $ $ Weighted-average limited partner units outstanding: Common units – basic Common units – diluted The accompanying notes are an integral part of these consolidated financial statements. 111 2019 Year ended December 31, 2018 (In thousands, except per-unit amounts) 2017 326,747 $ 86,994 29,787 443,528 63,438 97,587 54,139 110,206 1,788 (1,536) 60,507 16,211 402,340 451 (74,429) — 1,982 (30,808) (1,174) (337,851) (369,833) $ — (369,833) 12 (369,845) 28,500 58 (398,403) $ 344,616 $ 134,834 27,203 506,653 107,661 96,878 52,877 107,100 — — 7,186 — 371,702 (169) (60,535) — (20,975) 53,272 (33) (10,888) 42,351 $ 168 42,183 9,384 32,799 28,500 — 4,299 $ 394,427 68,459 25,855 488,741 57,237 93,882 54,681 115,475 73 527 188,702 — 510,577 298 (68,131) (22,039) 200,322 88,614 (341) (2,223) 86,050 363 85,687 10,202 75,485 3,563 — 71,922 (4.84) $ (4.84) $ 0.06 $ 0.06 $ 0.99 0.98 82,365 82,365 73,304 73,615 72,705 73,047 Table of Contents SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL Partners' capital Limited partners Series A Preferred Units Common General Partner (In thousands) Noncontrolling interest $ $ — (2,236) 294,426 $ — $ 3,563 (2,375) — — 17,078 — — (202) 1,129,132 $ 71,922 (167,062) 7,878 293,238 — — — — Partners' capital, January 1, 2017 Net income Distributions to unitholders Unit-based compensation Tax withholdings on vested SMLP LTIP awards Issuance of Series A Preferred Units, net of offering costs ATM Program issuances, net of costs Contribution from General Partner Purchase of noncontrolling interest Other Partners' capital, December 31, 2017, as reported January 1, 2018 impact of Topic 606 day 1 adoption Partners' capital, January 1, 2018 Net income Distributions to unitholders Unit-based compensation Tax withholdings on vested SMLP LTIP awards Purchase of noncontrolling interest Other Partners' capital, December 31, 2018 Net income (loss) Conversion of General Partner economic interests Distributions to unitholders Unit-based compensation Tax withholdings on vested SMLP LTIP awards DPPO partial settlement Partners' capital, December 31, 2019 The accompanying notes are an integral part of these consolidated financial statements. 4,130 1,060,640 4,299 (168,567) 8,088 (1,974) — (128) 902,358 $ (398,403) — — (810) 293,616 $ 28,500 — 294,426 28,500 (28,500) — (2,614) 51,750 469,900 $ — — 293,616 $ 22,222 (113,584) 8,171 — (28,500) — 1,056,510 $ $ $ 112 29,294 $ 10,202 (12,041) — 11,247 $ 363 — — Total 1,169,673 86,050 (181,478) 7,878 — — — 465 — — — (2,236) — — — (797) — 293,238 17,078 465 (797) (202) 27,920 $ 10,813 $ 1,389,669 84 28,004 9,384 (12,138) — — — — 25,250 $ 12 (22,222) (3,040) — — — — $ — 10,813 168 — — — (10,981) — — $ — — — — — — — $ 4,214 1,393,883 42,351 (209,205) 8,088 (1,974) (10,981) (938) 1,221,224 (369,891) — (145,124) 8,171 (2,614) 51,750 763,516 Table of Contents SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Cash flows from operating activities: Net (loss) income Adjustments to reconcile net (loss) income to net cash provided by operating activities: Depreciation and amortization Noncash lease expense Amortization of debt issuance costs Deferred Purchase Price Obligation Unit-based and noncash compensation Loss from equity method investees Distributions from equity method investees (Gain) loss on asset sales, net Long-lived asset impairment Goodwill impairment Early extinguishment of debt Write-off of debt issuance costs Changes in operating assets and liabilities: Accounts receivable Trade accounts payable Accrued expenses Due from (to) affiliate 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) Contributions to equity method investees Distributions from equity method investment Investment in equity method investee Purchase of noncontrolling interest Other, net Net cash used in investing activities 2019 Year ended December 31, 2018 (In thousands) 2017 $ (369,833) $ 42,351 $ 86,050 111,426 3,086 4,411 (1,982) 8,171 337,851 37,300 (1,536) 60,507 16,211 — — (4,334) (95) (10,327) 71 1,683 (1,525) 25 (2,284) (6,489) 182,337 106,767 — 4,285 20,975 8,328 10,888 35,271 — 7,186 — — — (21,535) 81 9,464 (848) 5,355 2,221 (24) (3,808) 972 227,929 114,872 — 4,158 (200,322) 7,951 2,223 40,220 527 188,702 — 22,039 302 25,063 (3,246) 1,110 830 (40,758) (2,259) (5,173) (4,109) (348) 237,832 (182,291) (200,586) (124,215) 102,111 — 7,313 (18,316) — 313 (90,870) 496 (4,924) — — (10,981) (284) (216,279) 2,300 (25,513) — — (797) (458) (148,683) 113 Table of Contents SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) Cash flows from financing activities: Distributions to unitholders Distributions to Series A Preferred unitholders Borrowings under Revolving Credit Facility Repayments under Revolving Credit Facility Repayment of Deferred Purchase Price Obligation Debt issuance costs Payment of redemption and call premiums on senior notes Proceeds from ATM Program common unit issuances, net of costs Proceeds from issuance of Series A preferred units, net of costs Contribution from General Partner Issuance of senior notes Tender and redemption of senior notes 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 (1) Supplemental cash flow disclosures: 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) DPPO partial settlement Asset contribution to an equity method investment Capital expenditures relating to contributions in aid of construction for Topic 606 day 1 adoption Right-of-use assets relating to Topic 842 Year ended December 31, 2019 2018 2017 (In thousands) (116,624) (28,500) 369,000 (158,000) (151,750) (499) — — 27,392 — — — (4,491) (63,472) 27,995 4,345 32,340 $ (180,705) (28,500) 289,000 (84,000) — (344) — — — — — — (4,186) (8,735) 2,915 1,430 4,345 $ (179,103) (2,375) 247,500 (634,500) — (16,390) (17,932) 17,078 293,238 465 500,000 (300,000) (3,128) (95,147) (5,998) 7,428 1,430 76,883 $ 6,974 69,909 $ 64,678 $ 8,497 56,181 $ 71,488 2,579 68,909 150 $ 175 $ — 19,846 $ 51,750 23,643 — 5,448 33,750 $ — — 33,123 — 11,792 — — — — $ $ $ $ $ (1) A reconciliation of cash, cash equivalents and restricted cash to the consolidated balance sheets follow: Cash and cash equivalents Restricted cash Total cash, cash equivalents and restricted cash 2019 Year ended December 31, 2018 (In thousands) 2017 $ $ 4,948 $ 27,392 32,340 $ 4,345 $ — 4,345 $ 1,430 — 1,430 The accompanying notes are an integral part of these consolidated financial statements. 114 Table of Contents SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION Organization. SMLP, a Delaware limited partnership, was formed in May 2012 and began operations in October 2012. SMLP is a growth- 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. Our business activities are conducted through various operating subsidiaries, each of which is owned or controlled by our wholly owned subsidiary holding company, Summit Holdings, a Delaware limited liability company. References to the "Partnership," "we," or "our" refer collectively to SMLP and its subsidiaries. The General Partner, a Delaware limited liability company, manages our operations and activities. Summit Investments, a Delaware limited liability company, is the ultimate owner of our General Partner and has the right to appoint the entire Board of Directors. Summit Investments is controlled by Energy Capital Partners. Summit Investments owned an approximate 2% general partner interest in SMLP (including the IDRs) until March 22, 2019. On March 22, 2019, we executed an equity restructuring agreement with the General Partner and SMP Holdings pursuant to which the IDRs and the 2% general partner interest were converted into a non-economic general partner interest in exchange for 8,750,000 common units which were issued to SMP Holdings (the “Equity Restructuring”). As of December 31, 2019, SMP Holdings, a wholly owned subsidiary of Summit Investments, beneficially owned 45,318,866 SMLP common units and a subsidiary of Energy Capital Partners directly owned 5,915,827 SMLP common units. Neither SMLP nor its subsidiaries have any employees. All of the personnel that conduct our business are employed by Summit Investments, but these individuals are sometimes referred to as our employees. Business Operations. We provide 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 our customers. Our results are primarily driven by the volumes of natural gas that we gather, compress, treat and/or process as well as by the volumes of crude oil and produced water that we gather. We are the owner-operator of, or have significant ownership interests in, the following gathering and transportation systems: • • • • • • • • Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio; Ohio Gathering, a natural gas gathering system and a condensate stabilization facility operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio; Polar and Divide, a crude oil and produced water gathering system and transmission pipeline operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; Bison Midstream, an associated natural gas gathering system operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; Niobrara G&P, an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara and Codell shale formations in northeastern Colorado and southeastern Wyoming; Summit Permian, an associated natural gas gathering and processing system operating in the northern Delaware Basin, which includes the Wolfcamp and Bone Spring formations, in southeastern New Mexico; Double E, a 1.35 Bcf/d natural gas transmission pipeline that is under development and will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas; Grand River, a natural gas gathering and processing system operating in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado; 115 Table of Contents • • DFW Midstream, a natural gas gathering system operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and Mountaineer Midstream, a natural gas gathering system operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia. Until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Refer to Note 17 for details on the sale of Tioga Midstream. In June 2019, in conjunction with the Double E Project, Summit Permian Transmission entered into a definitive joint venture agreement (the “Agreement”) with an affiliate of Double E’s foundation shipper (the “JV Partner”) to fund the capital expenditures associated with the Double E Project. Refer to Note 8 for additional details. Other than our investments in Double E and Ohio Gathering, all of our business activities are conducted through wholly owned operating subsidiaries. Presentation and Consolidation. We prepare our consolidated financial statements in accordance with GAAP as established by the FASB. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, including fair value measurements, the reported amounts of revenues and expenses and the 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. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cash, Cash Equivalents and Restricted Cash. We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Cash that is held by a major bank and has restrictions on its availability to us is classified as restricted cash. See Note 12 for additional information. Accounts Receivable. Accounts receivable relate to gathering and other services provided to our customers and other counterparties. We evaluate the collectability of accounts receivable and the need for an allowance for doubtful accounts based on customer-specific facts and circumstances. To the extent we doubt the collectability of a specific customer or counterparty receivable, we recognize 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. We record property, plant and equipment at historical cost of construction or fair value of the assets at acquisition. We capitalize 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, we recognize expenditures as an expense as incurred. We capitalize project costs incurred during construction, including interest on funds borrowed to finance the construction of facilities, as construction in progress. We record depreciation on a straight-line basis over an asset’s estimated useful life. We base our 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. 116 Table of Contents We base an asset’s carrying value on estimates, assumptions and judgments for useful life and salvage value. Upon sale, retirement or other disposal, we remove the carrying value of an asset and its accumulated depreciation from our balance sheet and recognize the related gain or loss, if any. Accrued capital expenditures are reflected in trade accounts payable. Asset Retirement Obligations. We record 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, we then evaluate whether the expected date and related costs of retirement can be estimated. We have concluded that our gathering and processing assets have an indeterminate life because they are owned and will operate for an indeterminate period when properly maintained. Because we did not have sufficient information to reasonably estimate the amount or timing of such obligations and we have no current plan to discontinue use of any significant assets, we did not provide for any asset retirement obligations as of December 31, 2019 or 2018. Amortizing Intangibles. Upon the acquisition of DFW Midstream, certain of its gas gathering contracts were deemed to have above-market pricing structures. We have recognized the above-market contracts as favorable gas gathering contracts. We amortize the favorable contracts using a straight-line method over the contract’s estimated useful life. We define useful life as the period over which the contract is expected to contribute to our future cash flows. These contracts have original terms ranging from 10 years to 20 years. We recognize the amortization expense associated with these contracts in Other revenues. We amortize 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. We recognize the amortization expense associated with these contracts in Depreciation and amortization expense. We have rights-of-way associated with city easements and easements granted within existing rights-of-way. We amortize 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. We recognize the amortization expense associated with rights-of-way assets in Depreciation and amortization expense. Goodwill. Goodwill represents consideration paid in excess of the fair value of the net identifiable assets acquired in a business combination. We evaluate goodwill for impairment annually on September 30. 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. As of December 31, 2019, we did not have a goodwill balance on our consolidated balance sheet. Equity Method Investments. We account for investments in which we exercise significant influence using the equity method so long as we (i) do not control the investee and (ii) are not the primary beneficiary. We recognize these investments in investment in equity method investees in the accompanying consolidated balance sheets. We recognized (i) our proportionate share of earnings or loss in net income for Ohio Gathering, on a one-month lag, and (ii) an other-than-temporary impairment for Ohio Gathering, based on the financial information available to us during the reporting period. We recognize 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 would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or 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. We evaluate our equity method investments whenever a triggering event exists that would indicate a need to assess the investment for potential impairment. 117 Table of Contents Other Noncurrent Assets. Other noncurrent assets primarily consist of external costs incurred in connection with the closing of our Revolving Credit Facility and related amendments. We capitalize and then amortize these debt issuance costs on a straight-line basis, which approximates the effect of the effective interest rate method, over the life of the respective debt instrument. We recognize the amortization of the Revolving Credit Facility debt issuance costs in interest expense. Debt Issuance Costs. Debt issuance costs, other than those associated with our Revolving Credit Facility, are reflected in the carrying value of the Senior Notes as an adjustment to the principal amount and amortized on a straight-line basis, which approximates the effect of the effective interest rate method, over the life of the respective debt instrument. We recognize the amortization of the Senior Notes debt issuance costs in interest expense. Deferred Purchase Price Obligation. We recognize a liability for the Deferred Purchase Price Obligation to reflect the present value of the estimated Remaining Consideration for the acquisition of the 2016 Drop Down Assets. In March 2016, we recognized the Deferred Purchase Price Obligation in connection with the 2016 Drop Down. On November 7, 2019, we and SMP Holdings entered into a second amendment (the “Second Amendment”) to the Contribution Agreement between us and SMP Holdings dated February 25, 2016, as amended. On November 15, 2019, we made a cash payment of $51.75 million and issued 10,714,285 common units to SMP Holdings (the “November 2019 Prepayment”). In addition, the parties reduced the Remaining Consideration due to SMP Holdings by $19.25 million. Following the November 2019 Prepayment, the Remaining Consideration is $180.75 million. The parties also extended the final date by which we are obligated to deliver the Remaining Consideration to January 15, 2022. The Remaining Consideration remains payable to SMP Holdings in (i) cash, (ii) our common units or (iii) a combination of cash and our common units, and interest will accrue (and will be payable quarterly in cash) at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020 (see Note 17 for additional information). Impairment of Long-Lived Assets. We test assets for impairment when events or circumstances indicate that 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 we conclude that an asset's carrying value will not be recovered through future cash flows, we recognize an impairment loss on the long-lived asset equal to the amount by which the carrying value exceeds its fair value. We determine fair value using either a market-based approach, an income-based approach or a combination of the two approaches. Derivative Contracts. We have commodity price exposure related to our sale of the physical natural gas we retain from certain DFW Midstream customers and our procurement of electricity to operate the DFW Midstream system's electric-drive compression assets. Our gas gathering agreements with certain DFW Midstream customers permit us to retain a certain quantity of natural gas that we gather to offset the power costs we incur to operate these electric-drive compression assets. We manage this 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 based 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. Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. We have designated these contracts as normal under the normal purchase and sale exception under the accounting standards for derivatives. We do not enter into risk management contracts for speculative purposes. 118 Table of Contents Restructuring Costs. Our restructuring costs are comprised primarily of employee termination costs related to headcount reductions. A liability for costs associated with an exit or disposal activity is recognized and measured initially at fair value only when the liability is incurred. Our restructuring charges also include relocation expenses and advisory costs. We reassess the liability periodically based on market conditions. Refer to Note 17 for additional details. Fair Value of Financial Instruments. The fair-value-measurement standard under GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which the inputs are observable. The three levels of the fair value hierarchy are as follows: • • • Level 1. Inputs represent quoted prices in active markets for identical assets or liabilities; Level 2. Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs); and Level 3. Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an internally developed present value of future cash flows model that underlies management's fair value measurement). Commitments and Contingencies. We record accruals for loss contingencies when we determine that it is probable that a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. We recognize gain contingencies when their realization is assured beyond a reasonable doubt. Noncontrolling Interest. Noncontrolling interest represented the ownership interests of third-party entities in the net assets of our consolidated subsidiaries. Revenue Recognition. The majority of our revenue is derived from long-term, fee-based contracts with original terms of up to 25 years. We account for revenue in accordance with Topic 606, which we adopted on January 1, 2018, using the modified retrospective method. See below for further discussion of the adoption. We recognize revenue earned from fee-based gathering, compression, treating and processing services in gathering services and related fees. We also earn revenue in the Williston Basin and Permian Basin reporting segments from the sale of physical natural gas purchased from our customers under certain percent-of-proceeds arrangements. Under ASC Topic 606, these gathering contracts are presented net within cost of natural gas and NGLs. We sell natural gas that we retain from certain customers in the Barnett Shale reporting segment to offset the power expenses of the electric-driven compression on the DFW Midstream system. We also sell condensate and NGLs retained from certain of our 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 us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis, with the revenue component recognized in Other revenues. We provide gathering and/or processing services principally under contracts that contain one or more of the following arrangements: • Fee-based arrangements. Under fee-based arrangements, we receive 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. 119 Table of Contents • Percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat the natural gas, process the natural gas and/or sell the natural gas to a third party for processing. We then remit to our 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 we are able to sell the residue natural gas and NGLs. Certain of our gathering and/or processing agreements provide for monthly or annual MVCs. Under these MVCs, our customers agree to ship and/or process a minimum volume of production on our 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 us 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. We recognize customer obligations under their MVCs as revenue and contract assets when (i) we consider it remote that the customer will utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods; (ii) the customer incurs a shortfall in a contract with no banking mechanism or claw back provision; (iii) the customer’s banking mechanism has expired; or (iv) it is remote that the customer will use its unexercised right. In making this determination, we consider 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. Unit-Based Compensation. For awards of unit-based compensation, we determine a grant date fair value and recognize the related compensation expense in the statements of operations over the vesting period of the respective awards. Income Taxes. As a partnership, we are generally not subject to federal and state income taxes, except as noted below. However, our unitholders are individually responsible for paying federal and state income taxes on their share of our taxable income. Net income or loss for GAAP purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and the GAAP basis of assets and liabilities and the taxable income allocation requirements under our Partnership Agreement. 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. Our financial statements reflect provisions for these tax obligations. Earnings or Loss Per Unit. We determine basic EPU by dividing the net income or loss that is attributed, in accordance with the net income and loss allocation provisions of our Partnership Agreement, to common limited partners under the two-class method, after deducting (i) any payment of IDRs, by the weighted-average number of limited partner units outstanding (for periods presented through the Equity Restructuring), (ii) the General Partner's approximate 2% interest in net income or loss (for periods presented up through the Equity Restructuring), and (iii) net income attributable to Series A Preferred Units and Subsidiary Series A Preferred Units. Diluted EPU reflects the potential dilution that could occur if securities or other agreements to issue common units, such as unit-based compensation, were exercised, settled or converted into common units and included in the weighted-average number of units outstanding. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted EPU calculation, the impact is reflected by applying the treasury stock method. 120 Table of Contents Environmental Matters. We are subject to various federal, state and local laws and regulations relating to the protection of the environment. Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. We accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Such accruals are adjusted as further information develops or circumstances change. Recoveries of environmental remediation costs from other parties or insurers are recorded as assets when their realization is assured beyond a reasonable doubt. Recent Accounting Pronouncements. Accounting standard setters frequently issue new or revised accounting rules. We review new pronouncements to determine the impact, if any, on our financial statements. Accounting standards that have or could possibly have a material effect on our financial statements are discussed below. Recently Adopted Accounting Pronouncements. We have recently adopted the following accounting pronouncement: • ASU No. 2016-02 Leases (“Topic 842"). We adopted Topic 842 with a date of initial application of January 1, 2019. We applied Topic 842 by recognizing (i) a $5.4 million right-of-use (“ROU”) asset which represents the right to use, or to control the use of, specified assets for a lease term. The ROU asset is included in the Property, plant and equipment, net caption on the consolidated balance sheet; and (ii) a $5.4 million lease liability for the obligation to make lease payments arising from the leases. The lease liability is included in the Other current liabilities and Other noncurrent liabilities captions on the consolidated balance sheet. The comparative information has not been adjusted and is reported under the accounting standards in effect for those periods. Refer to Note 16 for additional information. Accounting Pronouncements Pending Adoption. We have not yet adopted the following accounting pronouncements as of December 31, 2019: • • 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 our consolidated financial statement 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 our consolidated financial statements or disclosures. 121 Table of Contents 3. REVENUE The majority of our revenue is derived from long-term, fee-based contracts with our customers, which include original terms of up to 25 years. We recognize revenue earned from fee-based gathering, compression, treating and processing services in gathering services and related fees. We also earn revenue in the Williston Basin and Permian Basin reporting segments from the sale of physical natural gas purchased from our customers under certain percent-of-proceeds arrangements. Under ASC Topic 606, these gathering contracts are presented net within cost of natural gas and NGLs. We sell natural gas that we retain from certain customers in the Barnett Shale reporting segment to offset the power expenses of the electric-driven compression on the DFW Midstream system. We also sell condensate and NGLs retained from certain of our 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 us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis, with the revenue component recognized in Other revenues. The transaction price in our contracts is primarily based on the volume of natural gas, crude oil or produced water transferred by our 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, we do 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, we measure the transaction price at the point of sale when the volume, mix and market price of the commodities are known. We have contracts with MVCs that are variable and constrained. Contracts with greater 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 our 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. We also have 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, we allocate the contract’s transaction price to each performance obligation using our best estimate of the standalone selling price of each service in the contract. Performance obligations for gathering services are generally satisfied over time. We utilize 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 our gathering and/or processing agreements provide for monthly or annual MVCs. Under these MVCs, our customers agree to ship and/or process a minimum volume of production on our 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 us 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. 122 Table of Contents We recognize customer obligations under their MVCs as revenue and contract assets when (i) we consider it remote that the customer will utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods; (ii) the customer incurs a shortfall in a contract with no banking mechanism or claw back provision; (iii) the customer’s banking mechanism has expired; or (iv) it is remote that the customer will use its unexercised right. Our services are typically billed on a monthly basis and we do not offer extended payment terms. We do not have contracts with financing components. 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. We applied the practical expedient in paragraph 606-10-50-14 of Topic 606 for certain arrangements that we consider 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 $ 122,055 $ 102,127 $ 84,736 $ 66,693 $ 50,608 $ 59,602 2020 2021 2022 2023 2024 Thereafter (In thousands) Revenue by Category. In the following table, revenue is disaggregated by geographic area and major products and services. Ohio Gathering is excluded from the tables below due to equity method accounting. For more detailed information about reportable segments, see Note 4. Reportable Segments Year ended December 31, 2019 Utica Shale Williston Permian Piceance Basin DJ Basin Basin Basin Barnett Shale Marcellus Shale (In thousands) Total reportable segments All other segments Total Major products / services lines Gathering services and related fees Natural gas, NGLs and condensate sales Other revenues Total Major products / services lines Gathering services and related fees Natural gas, NGLs and condensate sales Other revenues Total $ 31,926 $ 77,626 $ 21,940 $ 3,610 $ 121,357 $ 47,862 $ 24,471 $ 328,792 $ (2,045) $ 326,747 — 16,461 2,065 11,564 28,660 86,994 1,007 29,787 $ 33,991 $ 105,651 $ 26,050 $ 20,303 $ 133,638 $ 71,802 $ 24,471 $ 415,906 $ 27,622 $ 443,528 7,954 17,147 6,793 4,327 389 16,383 310 58,334 28,780 — — 3,721 Reportable Segments Year ended December 31, 2018 Utica Shale Williston DJ Permian Piceance Basin Basin Basin Basin Barnett Shale Marcellus Shale (In thousands) Total reportable segments All other segments Total $ 35,233 $ 79,606 $ 11,251 $ 115 $ 135,810 $ 59,030 $ 29,573 $ 350,618 $ (6,002) $ 344,616 — — $ 35,233 31,840 12,204 $ 123,650 371 3,672 $ 15,294 $ 843 14,800 4,909 $ 155,519 — 958 2,523 6,712 $ 68,265 — — $ 29,573 50,377 27,497 $ 428,492 123 84,457 134,834 (294) 27,203 $ 506,653 $ 78,161 Table of Contents Contract balances. Contract assets relate to our rights to consideration for work completed but not billed at the reporting date and consist of the estimated MVC shortfall payments expected from our 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, beginning of period Additions Transfers out Contract assets, end of period December 31, 2019 December 31, 2018 $ $ (In thousands) 8,755 $ 18,077 (22,930) 3,902 $ — 26,403 (17,648) 8,755 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. As of December 31, 2018, receivables with customers totaled $82.9 million and contract assets totaled $8.8 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. We recognize contract liabilities under these arrangements in revenue over the contract period. For the years ended December 31, 2019 and 2018, we recognized $10.1 million and $10.8 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 9 for additional details. 4. SEGMENT INFORMATION As of December 31, 2019, our reportable segments are: • • • • • • • • the Utica Shale, which is served by Summit Utica; Ohio Gathering, which includes our ownership interest in OGC and OCC; the Williston Basin, which is served by Polar and Divide and Bison Midstream; the DJ Basin, which is served by Niobrara G&P; the Permian Basin, which is served by Summit Permian; the Piceance Basin, which is served by Grand River; the Barnett Shale, which is served by DFW Midstream; and the Marcellus Shale, which is served by Mountaineer Midstream. Until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Until December 1, 2019, we owned certain assets in the Red Rock Gathering system operating in the Piceance Basin. Refer to Note 17 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 our reportable segments provides midstream services in a specific geographic area. Our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations. The Ohio Gathering reportable segment includes our 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 8). For the year ended December 31, 2019, other than the investment activity described in Note 8, 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 third quarter of 2021. 124 Table of Contents Corporate and Other represents those results that are: (i) not specifically attributable to a reportable segment; (ii) not individually reportable (such as Double E); or (iii) that have not been allocated to our 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 Eliminations Total assets 2019 December 31, 2018 (In thousands) $ $ 206,368 $ 275,000 452,152 205,308 185,708 631,140 350,638 184,631 2,490,945 82,506 — 2,573,451 $ 207,357 $ 649,250 526,819 166,580 145,702 699,638 376,564 208,790 2,980,700 44,181 (4,319) 3,020,562 $ 2017 212,311 690,485 512,860 79,438 57,590 719,284 383,306 217,362 2,872,636 22,406 (249) 2,894,793 (1) At December 31, 2019, Corporate and Other included $34.7 million relating to our investment in Double E (included in the Investment in equity method investees caption of the consolidated balance sheet). At December 31, 2018, Corporate and Other included $9.6 million of capital expenditures relating to the Double E Project. Revenues by reportable segment follow. Revenues (1): Utica Shale Williston Basin DJ Basin Permian Basin Piceance Basin Barnett Shale Marcellus Shale Total reportable segments revenue Corporate and Other Eliminations Total revenues (1) Excludes revenues earned by Ohio Gathering due to equity method accounting. Counterparties accounting for more than 10% of total revenues were as follows: Percentage of total revenues (1): Counterparty A - Piceance Basin Counterparty B - Williston Basin Counterparty C - Piceance Shale Counterparty D - Barnett Shale (1) Excludes revenues earned by Ohio Gathering due to equity method accounting. * Less than 10% 125 2019 Year ended December 31, 2018 (In thousands) 2017 $ $ 33,991 $ 105,651 26,050 20,303 133,638 71,802 24,471 415,906 30,552 (2,930) 443,528 $ 35,233 $ 123,650 15,294 958 155,519 68,265 29,573 428,492 88,286 (10,125) 506,653 $ 38,907 161,503 11,860 — 154,893 71,667 30,394 469,224 26,446 (6,929) 488,741 Year ended December 31, 2019 2018 2017 11% 10% * * * * 10% * * 13% * * Table of Contents Depreciation and amortization, including the amortization expense associated with our favorable and unfavorable (for 2018) gas gathering contracts as reported in other revenues, by reportable segment follows. Depreciation and amortization (1): Utica Shale Williston Basin DJ Basin Permian Basin Piceance Basin Barnett Shale (2) Marcellus Shale Total reportable segment depreciation and amortization Corporate and Other Total depreciation and amortization 2019 Year ended December 31, 2018 (In thousands) 2017 $ $ 7,659 $ 19,829 3,732 4,868 47,018 16,575 9,141 108,822 2,604 111,426 $ 7,672 $ 22,642 3,133 243 46,919 15,325 9,090 105,024 1,743 106,767 $ 7,009 33,772 2,636 — 46,289 15,001 9,047 113,754 1,118 114,872 (1) Excludes depreciation and amortization recognized by Ohio Gathering due to equity method accounting. (2) Includes the amortization expense associated with our favorable and unfavorable (for 2018) gas gathering contracts as reported in Other revenues. Cash paid for capital expenditures by reportable segment follow. Cash paid for capital expenditures (1): Utica Shale Williston Basin DJ Basin Permian Basin Piceance Basin Barnett Shale (2) Marcellus Shale Total reportable segment capital expenditures Corporate and Other Total cash paid for capital expenditures 2019 Year ended December 31, 2018 (In thousands) 2017 $ $ 3,902 30,861 80,487 44,955 1,946 184 693 163,028 19,263 182,291 $ $ 5,719 25,202 64,920 83,823 7,887 1,370 1,030 189,951 10,635 200,586 $ $ 22,921 17,309 7,150 56,020 16,564 569 641 121,174 3,041 124,215 (1) Excludes cash paid for capital expenditures by Ohio Gathering due to equity method accounting. (2) For the year ended December 31, 2019, the amount includes sales tax reimbursements of $1.1 million. For the years ended December 31, 2019 and 2018, Corporate and Other includes cash paid of $1.6 million and $3.3 million, respectively, for corporate purposes; the remainder represents capital expenditures relating to the Double E Project. We assess the performance of our reportable segments based on segment adjusted EBITDA. We define segment adjusted EBITDA as total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) 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) change in the Deferred Purchase Price Obligation fair value, (viii) impairments (ix) other noncash expenses or losses, less other noncash income or gains and (x) restructuring expenses. We define proportional adjusted EBITDA for our equity method investees 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) our ownership interest in Ohio Gathering during the respective period. 126 Table of Contents For the purpose of evaluating segment performance, we exclude 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, change in the Deferred Purchase Price Obligation fair value and income tax expense or benefit from segment adjusted EBITDA. 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 2019 Year ended December 31, 2018 (In thousands) 2017 $ $ 29,292 $ 39,126 69,437 18,668 (879) 98,765 43,043 20,051 317,503 $ 30,285 $ 39,969 76,701 7,558 (1,200) 111,042 43,268 24,267 331,890 $ 34,011 41,246 66,413 6,624 — 111,113 46,232 23,888 329,527 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 (loss) income before income taxes and loss from equity method investees to total of reportable segments' measures of profit: (Loss) income before income taxes and loss from equity method investees Add: Corporate and Other expense Interest expense Early extinguishment of debt Deferred Purchase Price Obligation Depreciation and amortization 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) loss on asset sales, net Long-lived asset impairment Goodwill impairment Total of reportable segments' measures of profit 2019 Year ended December 31, 2018 (In thousands) 2017 $ (30,808) $ 53,272 $ 88,614 40,639 74,429 — (1,982) 111,426 39,126 3,476 (2,156) 8,171 (1,536) 60,507 16,211 317,503 $ 38,917 60,535 — 20,975 106,767 39,969 (3,632) (427) 8,328 — 7,186 — 331,890 $ 39,140 68,131 22,039 (200,322) 114,872 41,246 (41,373) — 7,951 527 188,702 — 329,527 $ For the years ended December 31, 2019 and 2018, adjustments related to MVC shortfall payments recognize the earnings from MVC shortfall payments ratably over the term of the associated MVC (see Note 3). Contributions in aid of construction are recognized over the remaining term of the respective contract. We include adjustments related to capital reimbursement activity in our calculation of segment adjusted EBITDA to account for revenue recognized from contributions in aid of construction. 127 Table of Contents For the year ended December 31, 2017, we included adjustments related to MVC shortfall payments in our calculation of segment adjusted EBITDA to account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. With respect to the impact of a net change in deferred revenue for MVC shortfall payments, we treated increases in deferred revenue balances as a favorable adjustment to segment adjusted EBITDA, while decreases in deferred revenue balances were treated as an unfavorable adjustment to segment adjusted EBITDA. We also included a proportional amount of any historical and expected MVC shortfall payments in each quarter prior to the quarter in which we actually recognize the shortfall payment. Adjustments related to MVC shortfall payments by reportable segment follow. Adjustments related to expected MVC shortfall payments: $ — $ (In thousands) (103) $ 3,579 $ 3,476 Year ended December 31, 2019 Williston Basin Piceance Basin Barnett Shale Total Adjustments related to expected MVC shortfall payments: $ — $ (In thousands) 10 $ (3,642) $ (3,632) Year ended December 31, 2018 Williston Basin Piceance Basin Barnett Shale Total Adjustments related to MVC shortfall payments: Net change in deferred revenue for MVC shortfall payments Expected MVC shortfall adjustments Total adjustments related to MVC shortfall payments 5. PROPERTY, PLANT AND EQUIPMENT, NET Details on 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 Year Ended December 31, 2017 Williston Basin Piceance Basin Barnett Shale Total (In thousands) $ $ (37,693) $ — (37,693) $ (3,065) $ (3) (3,068) $ — $ (612) (612) $ (40,758) (615) (41,373) December 31, 2019 December 31, 2018 $ $ (In thousands) 2,182,950 78,716 10,137 53,129 2,324,932 442,681 1,882,251 $ $ 2,155,325 137,920 11,748 45,853 2,350,846 387,133 1,963,713 During 2019, 2018 and 2017, we identified certain events, facts and circumstances which indicated that certain of our property, plant and equipment could be impaired. As such, we reviewed the assets that had been identified as potentially impaired and estimated the fair value of the identified property, plant and equipment using a market-based approach. In December 2019, we sold certain Red Rock Gathering system assets for a cash purchase price of $12.0 million. Prior to closing, we recorded an impairment charge of $14.2 million based on the expected consideration and the carrying value for the Red Rock Gathering system assets. See Note 17 for additional details. 128 Table of Contents In December 2019, in connection with the cancellation of a project, we determined certain processing plant assets in the Permian Basin would no longer be utilized. As a result, we recorded an impairment charge of $0.7 million related to these assets in the fourth quarter of 2019. See Note 6 for additional details. In March 2019, certain events occurred which indicated that certain long-lived assets in the DJ Basin and Barnett Shale reporting segments could be impaired. Consequently, in the first quarter of 2019, we performed a recoverability assessment of certain assets within these reporting segments. In the DJ Basin, we determined that certain processing plant assets related to our existing 20 MMcf/d plant would no longer be utilized due to our expansion plans for the Niobrara G&P system. Based on the results of the recoverability assessment and the conclusion that the carrying value was not fully recoverable, we recorded an impairment charge of $34.7 million related to these assets in the first quarter of 2019. In the Barnett Shale, we determined, in the first quarter of 2019, that certain compressor station assets would be shut down and decommissioned. As a result, we recorded an impairment charge of $9.7 million related to these assets in the first quarter of 2019. See Note 6 for additional details. In December 2018, in connection with certain strategic initiatives, we performed a recoverability assessment of certain assets within the Williston Basin reporting segment. Based on the results, we concluded that the carrying value of certain long-lived assets related to the Tioga Midstream system within the Williston Basin were not fully recoverable. We recorded an impairment charge of $3.9 million related to these assets after comparing the fair value of the long-lived assets to their carrying values. In addition, we reviewed the other assets that had been identified as potentially impaired and recognized the long-lived asset impairments in the table below. In December 2017, in connection with certain strategic initiatives, we performed a financial review of certain assets within the Williston Basin reporting segment. This resulted in a triggering event that required us to perform a recoverability test. Based on the results of the test, we concluded that the carrying value of certain long-lived assets related to the Bison Midstream system within the Williston Basin were not fully recoverable. We recorded an impairment charge of $101.9 million related to these assets after comparing the fair value of the long-lived assets to their carrying values. See Note 6 for additional details. During 2019, 2018 and 2017, we recognized the following long-lived asset impairments, by segment. Long-lived asset impairment: Williston Basin Piceance Basin DJ Basin Barnett Shale Utica Shale Permian Basin 2019 Year ended December 31, 2018 (In thousands) 2017 $ $ 10 14,162 34,913 9,629 — 726 3,972 $ 1,004 9 — 1,440 761 101,961 697 — — 878 — Our impairment determinations, in the context of these reviews, involved 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. Depreciation expense and capitalized interest follow. Depreciation expense Capitalized interest 2019 Year ended December 31, 2018 2017 (In thousands) $ 78,341 $ 6,974 74,511 $ 8,497 75,120 2,579 129 Table of Contents 6. AMORTIZING INTANGIBLE ASSETS Details regarding our intangible assets, all of which are subject to amortization, follow. 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, 2019 Accumulated amortization (In thousands) 24,195 $ 278,448 157,175 459,818 $ (15,125) $ (169,549) (42,866) (227,540) $ Gross carrying amount December 31, 2018 Accumulated amortization (In thousands) 24,195 $ 278,448 166,209 468,852 $ (13,905) $ (143,962) (37,569) (195,436) $ $ $ $ $ Net 9,070 108,899 114,309 232,278 Net 10,290 134,486 128,640 273,416 In December 2019, in connection with the cancellation of a project, we determined certain rights-of-way intangible assets in the Permian Basin would no longer be utilized (see Note 5). As a result, we recorded an impairment charge of $0.6 million in the fourth quarter of 2019. Also in early 2019, certain events occurred which indicated that certain long-lived assets relating to the Barnett Shale reporting segment could be impaired (see Note 5). In connection with this evaluation, we evaluated the related intangible assets associated therewith for impairment consisting of rights-of-way intangible assets. We concluded the rights-of-way intangible assets were also impaired and, as a result, we recorded an impairment charge of $0.5 million in the first quarter of 2019. In December 2017, in connection with certain strategic initiatives, we evaluated certain long-lived assets relating to the Bison Midstream system within the Williston Basin reporting segment (see Note 5). In connection with this evaluation, we evaluated the related intangible assets associated therewith for impairment consisting of contract intangible assets and rights-of-way intangible assets. We concluded the contract intangible assets were also impaired and, as a result, we recorded an impairment charge of $85.2 million. We recognized amortization expense in Other revenues as follows: Amortization expense – favorable gas gathering contracts $ (1,220) $ (1,555) $ (1,555) We recognized amortization expense in costs and expenses as follows: 2019 Year ended December 31, 2018 2017 (In thousands) Amortization expense – contract intangibles Amortization expense – rights-of-way 130 2019 Year ended December 31, 2018 2017 (In thousands) $ 25,587 $ 6,278 26,141 $ 6,448 34,202 6,153 Table of Contents The estimated aggregate annual amortization expected to be recognized for as of December 31, 2019 for each of the five succeeding fiscal years follows. 2020 2021 2022 2023 2024 7. GOODWILL Intangible assets (In thousands) $ 31,901 28,209 25,142 25,088 14,917 Goodwill for the year ended December 31, 2018 of $16.2 million was related to the acquisition of the Mountaineer Midstream system in 2013. Accumulated goodwill impairments by reportable segment for those reporting units that have previously recognized goodwill follow. Accumulated goodwill impairment: Piceance Basin Williston Basin Marcellus Shale Total accumulated goodwill impairment 2019 Year ended December 31, 2018 (In thousands) 2017 $ $ 45,478 $ 257,572 16,211 319,261 $ 45,478 $ 257,572 — 303,050 $ 45,478 257,572 — 303,050 We evaluate 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, we conclude that the goodwill of the reporting unit has not been impaired and no further work is performed. If we determine that the reporting unit’s carrying value, including goodwill, exceeds its fair value, we recognize the excess of the carrying value over the fair value as a goodwill impairment loss. We performed our annual goodwill impairment testing for the Mountaineer Midstream reporting unit as of September 30, 2019 using a combination of the income and market approaches. We determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value, including goodwill. As a result, we recognized a goodwill impairment charge of $16.2 million for the year ended December 31, 2019. We had no impairments of goodwill for the years ended December 31, 2018 and 2017. Fair Value Measurement. Our impairment determinations, in the context of (i) our annual impairment evaluations and (ii) our 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. 8. EQUITY METHOD INVESTMENTS Double E In June 2019, we formed Double E in connection with the Double E Project. Effective June 26, 2019, Summit Permian Transmission, a wholly owned and consolidated subsidiary of the Partnership, and our JV Partner executed the Agreement whereby Double E will provide natural gas transportation services from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas. In connection with the 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 our 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 Agreement, Double E 131 Table of Contents distributed $7.3 million to the Partnership. Subsequent to the formation of Double E, we also made additional cash investments of $18.3 million through December 2019. Double E is deemed to be a variable interest entity as defined in GAAP. As of the date of the Agreement, Summit Permian Transmission was not deemed to be the primary beneficiary due to the JV Partner’s voting rights on significant matters. We account for our ownership interest in Double E as an equity method investment because we have significant influence over Double E. Our portion of Double E’s net assets, which was $34.7 million at December 31, 2019, is reported under the caption Investment in equity method investees on the consolidated balance sheet. For the year ended December 31, 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 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. Our initial investment in Ohio Gathering in 2014 included a $190.0 million payment to acquire a 1% interest from a third party, which included an option to increase our ownership to 40%, as well as a series of contributions directly to Ohio Gathering in 2014, which increased our ownership to 40%. Concurrent with and subsequent to the exercise of the option, the non-affiliated owners have retained their respective 60% ownership interest in Ohio Gathering (the "Non-affiliated Owners"). We account for our ownership interests in Ohio Gathering as an equity method investment because we have joint control with the Non- affiliated Owners, which gives us significant influence. We recognized the $190.0 million paid for the initial 1% interest as an investment in Ohio Gathering at inception. In addition, Ohio Gathering assigned a value of $7.5 million to the exercise option, which it ultimately attributed to our capital account. Neither of the aforementioned transactions involved a flow of funds to or from Ohio Gathering. As such, they created a basis difference between our recorded investment in equity method investees and the amount attributed to us by Ohio Gathering within its financial statements. In December 2019, we identified certain triggering events which indicated that our equity method investment in Ohio Gathering could be impaired. In accordance with ASC Topic 323, we completed an equity method impairment analysis to determine the equity method impairment charge to be recorded on our consolidated financial statements resulting from an other-than-temporary impairment. As a result of our analysis, an impairment charge of approximately $329.7 million was recorded in 2019 in Loss from equity method investments on the accompanying consolidated statements of operations. The fair value of our 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 percent. 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 we recognize activity for Ohio Gathering on a one-month lag, we recorded an impairment loss of $6.3 million in Loss from equity method investees in the consolidated statements of operations because the information was available to us. In December 2018, Ohio Gathering was involved in legal proceedings relating to a dispute regarding pipeline right of way rights and associated trespass claims that took place prior to December 31, 2018. Ohio Gathering received a judgment on those proceedings in January 2019 and recorded an estimate of the legal exposure as of December 31, 2018. Although we recognize activity for Ohio Gathering on a one-month lag, we recorded the asset impairments and legal contingency in our results of operations for the year ending December 31, 2018 because the information was available to us. We recorded our then 40% share of the asset impairments and legal contingency amounting to $7.7 million in 2018 in Loss from equity method investees in the consolidated statements of operations. As a result of our joint venture partner funding a disproportionate amount of the capital calls during the year ended December 31, 2019, our ownership interest in Ohio Gathering decreased from 40.0% at December 31, 2018, to 38.5% at December 31, 2019. 132 Table of Contents A reconciliation of our 38.5% and 40% ownership interest in Ohio Gathering to our investment per Ohio Gathering's books and records follows for the years ending December 31, 2019 and 2018, respectively (in thousands). Investment in Ohio Gathering, December 31 $ December cash distributions Impairment loss (1) Loss contingency Basis difference 2019 2018 (In thousands) 275,000 $ 2,700 232,521 — — 649,250 2,736 5,652 2,040 (116,832) Investment in Ohio Gathering, net of basis difference, November 30 542,846 (1) Amount is comprised of (i) a $329.7 million impairment of our equity method investment in Ohio Gathering; (ii) the write-off of our basis 510,221 $ $ difference of ($103.5) million in Ohio Gathering as a result of the impairment in our 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). Current assets Noncurrent assets Total assets Current liabilities Noncurrent liabilities Total liabilities November 30, 2019 OGC OCC November 30, 2018 OGC OCC $ 41,972 $ 1,281,171 $ 1,323,143 $ (In thousands) 2,187 28,323 30,510 $ 37,403 $ 1,262,253 $ 1,299,656 $ $ $ 21,798 $ 4,113 25,911 $ 4,016 6,683 10,699 $ $ 19,903 $ 3,688 23,591 $ 3,716 27,203 30,919 3,912 8,807 12,719 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) 9. DEFERRED REVENUE Twelve months ended November 30, 2019 OCC OGC Twelve months ended November 30, 2018 OCC OGC (In thousands) Twelve months ended November 30, 2017 OGC OCC $ 142,138 $ 108,234 33,897 8,601 38,815 (30,214) $ 142,398 $ 136,722 5,670 10,177 9,053 498 $ 140,679 $ 111,897 28,785 8,607 8,298 (907) Certain of our 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. Many of our gas gathering agreements contain provisions that can reduce or delay the cash flows that we expect to receive from our 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, we 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). 133 Table of Contents • • 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 our MVCs apply will be less than the weighted- average of the original stated contract terms of our MVCs. To the extent that certain of our 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, 2018 Additions Less revenue recognized Current deferred revenue, December 31, 2018 Additions Less revenue recognized Current deferred revenue, December 31, 2019 Utica Shale Williston Basin DJ Basin Piceance Basin Barnett Shale Marcellus Shale Total current (In thousands) $ 18 $ 18 18 1,017 $ 1,744 1,347 358 $ 943 562 7,038 $ 21,955 21,377 1,619 $ 1,651 1,628 38 $ 96 96 10,088 26,407 25,028 18 18 18 1,414 2,262 1,743 739 5,165 3,044 7,616 16,211 16,813 1,642 1,632 1,644 38 38 38 11,467 25,326 23,300 $ 18 $ 1,933 $ 2,860 $ 7,014 $ 1,630 $ 38 $ 13,493 A rollforward of noncurrent deferred revenue follows. Noncurrent deferred, revenue, January 1, 2018 Additions Less reclassification to current deferred revenue Noncurrent deferred revenue, December 31, 2018 Additions Less reclassification to current deferred revenue Noncurrent deferred revenue, December 31, 2019 Utica Shale Williston Basin DJ Basin Piceance Basin Barnett Shale Marcellus Shale Total noncurrent (In thousands) $ 39 $ — 4,215 $ 1,851 4,505 $ 3,720 18,219 $ 7,869 8,217 $ 3,062 333 $ — 35,528 16,502 18 1,673 941 8,146 1,651 97 12,526 21 — 4,393 1,940 7,284 5,470 17,942 6,104 9,628 1,579 236 — 39,504 15,093 18 2,699 5,165 6,336 1,632 38 15,888 $ 3 $ 3,634 $ 7,589 $ 17,710 $ 9,575 $ 198 $ 38,709 134 Table of Contents 10. DEBT Debt consisted of the following: December 31, 2019 December 31, 2018 (In thousands) Summit Holdings' variable rate senior secured Revolving Credit Facility (4.55% at December 31, 2019 and 5.03% at December 31, 2018) due May 2022 Summit Holdings' 5.5% senior unsecured notes due August 2022 Less unamortized debt issuance costs (1) Summit Holdings' 5.75% senior unsecured notes due April 2025 Less unamortized debt issuance costs (1) Total long-term debt (1) Issuance costs are being amortized over the life of the notes. $ $ 677,000 300,000 (1,686) 500,000 (5,015) 1,470,299 $ $ The aggregate amount of debt maturing during each of the years after December 31, 2019 are as follows (in thousands): 2020 2021 2022 2023 2024 Thereafter Total long-term debt $ $ 466,000 300,000 (2,362) 500,000 (5,907) 1,257,731 — — 977,000 — — 500,000 1,477,000 Revolving Credit Facility. Summit Holdings has a senior secured revolving credit facility which allows for revolving loans, letters of credit and swingline loans. The Revolving Credit Facility has a $1.25 billion borrowing capacity, matures in May 2022, and includes a $250.0 million accordion feature. As of December 31, 2019, 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. 135 Table of Contents In May 2017, Summit Holdings amended and restated its Revolving Credit Facility with a third amended and restated credit agreement which: (i) maintained the Revolving Credit Facility commitments of $1.25 billion, (ii) extended the maturity from November 2018 to May 2022, (iii) included a $250.0 million accordion feature, (iv) maintained the same leverage-based pricing and commitment fee grid, (v) increased the maximum permitted total leverage ratio, as defined in the credit agreement, from 5.00 to 1.00 to 5.50 to 1.00 and (vi) included a maximum permitted senior secured leverage ratio, as defined in the credit agreement, of 3.75 to 1.00. In June 2019, we executed the second amendment to the third amended and restated credit agreement that, among other things, made accommodations for the transactions contemplated by the Agreement and designated Double E as an unrestricted subsidiary under the Revolving Credit Facility. In December 2019, we executed the third amendment to the third amended and restated credit agreement that, among other things, designated the Non- Guarantor Subsidiaries as unrestricted subsidiaries under the Revolving Credit Facility. 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 1.75% or the adjusted Eurodollar rate (as defined in the credit agreement) plus an applicable margin ranging from 1.75% to 2.75%, with the commitment fee ranging from 0.30% to 0.50% in each case based on our relative leverage at the time of determination. At December 31, 2019, the applicable margin under LIBOR borrowings was 2.75%, the interest rate was 4.55% and the unused portion of the Revolving Credit Facility totaled $563.9 million, subject to a commitment fee of 0.50%, after giving effect to the issuance thereunder of a $9.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of December 31, 2019 was approximately $100 million. See Note 16 for additional information on our letter of credit. 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 5.50 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, 2019, we had $6.2 million of debt issuance costs attributable to our Revolving Credit Facility and related amendments which are included in Other noncurrent assets on the consolidated balance sheet. As of December 31, 2019, we were in compliance with the Revolving Credit Facility's financial covenants. There were no defaults or events of default during the year ended December 31, 2019. 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 "5.5% Senior Notes" and, together with the 5.75% Senior Notes (defined below), the “Senior Notes”). In 2018, we executed supplemental indentures to include OpCo, Summit Utica, Meadowlark Midstream and Tioga Midstream (through March 22, 2019) as guarantors concurrent with the purchase of a 1% noncontrolling interest held by a subsidiary of Summit Investments (see Note 12 to the consolidated financial statements for additional details). In 2019, we executed a partial release agreement that designated the Non- Guarantor Subsidiaries as unrestricted subsidiaries under the Senior Notes. 136 Table of Contents The Guarantor Subsidiaries are 100% owned by a subsidiary of SMLP. The Guarantor Subsidiaries and SMLP fully and unconditionally and jointly and severally guarantee the Senior Notes. There are no significant restrictions on the ability of SMLP or Summit Holdings to obtain funds from its subsidiaries by dividend or loan. Finance Corp. has had no assets or operations since inception in 2013. We have no other independent assets or operations. At no time have the Senior Notes been guaranteed by the Co-Issuers. 5.75% Senior Notes. In February 2017, the Co-Issuers completed a public offering of $500.0 million of 5.75% senior unsecured notes maturing April 15, 2025. We pay interest on the 5.75% Senior Notes semi-annually in cash in arrears on April 15 and October 15 of each year. The 5.75% Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 5.75% Senior Notes are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness. We used the proceeds from the issuance of the 5.75% Senior Notes to (i) fund the repurchase of the outstanding $300.0 million principal 7.5% Senior Notes, (ii) pay redemption and call premiums on the 7.5% Senior Notes totaling $17.9 million and (iii) pay $172.0 million of the balance outstanding under our Revolving Credit Facility. At any time prior to April 15, 2020, the Co-Issuers may redeem up to 35% of the aggregate principal amount of the 5.75% Senior Notes at a redemption price of 105.750% of the principal amount of the 5.75% Senior Notes, plus accrued and unpaid interest, if any, but not including, the redemption date, with an amount not greater than the net cash proceeds of certain equity offerings. On and after April 15, 2020, the Co- Issuers may redeem all or part of the 5.75% Senior Notes at a redemption price of 104.313% (with the redemption premium declining ratably each year to 100.000% on and after 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 5.75% Senior Notes. The 5.75% Senior Notes' indenture restricts SMLP’s and the Co-Issuers’ ability and the ability of certain of their subsidiaries to: (i) incur additional debt or issue preferred stock; (ii) make distributions, repurchase equity or redeem subordinated debt; (iii) make payments on subordinated indebtedness; (iv) create liens or other encumbrances; (v) make investments, loans or other guarantees; (vi) sell or otherwise dispose of a portion of their assets; (vii) engage in transactions with affiliates; and (viii) make acquisitions or merge or consolidate with another entity. These covenants are subject to a number of important exceptions and qualifications. At any time when the senior notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default or event of default under the indenture has occurred and is continuing, many of these covenants will terminate. The 5.75% Senior Notes' indenture provides that each of the following is an event of default: (i) default for 30 days in the payment when due of interest on the 5.75% Senior Notes; (ii) default in the payment when due of the principal of, or premium, if any, on the 5.75% Senior Notes; (iii) failure by the Co-Issuers or SMLP to comply with certain covenants relating to mergers and consolidations, change of control or asset sales; (iv) failure by SMLP for 180 days after notice to comply with certain covenants relating to the filing of reports with the SEC; (v) failure by the Co-Issuers or SMLP for 30 days after notice to comply with any of the other agreements in the indenture; (vi) specified defaults under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by SMLP or any of its restricted subsidiaries (or the payment of which is guaranteed by SMLP or any of its restricted subsidiaries); (vii) failure by SMLP or any of its restricted subsidiaries to pay certain final judgments aggregating in excess of $75.0 million; (viii) except as permitted by the indenture, any guarantee of the senior notes shall cease for any reason to be in full force and effect or any guarantor, or any person acting on behalf of any guarantor, shall deny or disaffirm its obligations under its guarantee of the senior notes; and (ix) certain events of bankruptcy, insolvency or reorganization described in the indenture. In the case of an event of default as described in the foregoing clause (ix), all outstanding 5.75% Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 5.75% Senior Notes may declare all the 5.75% Senior Notes to be due and payable immediately. 137 Table of Contents 5.5% Senior Notes. We pay interest on the 5.5% Senior Notes semi-annually in cash in arrears on February 15 and August 15 of each year. The 5.5% Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 5.5% Senior Notes are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness. We used the proceeds from the issuance of the 5.5% Senior Notes to repay a portion of the balance outstanding under our Revolving Credit Facility. At any time prior to August 15, 2020, the Co-Issuers may redeem all or part of the 5.5% Senior Notes at a redemption price of 101.375% (with the redemption premium declining to 100.000% on and after August 15, 2020), plus accrued and unpaid interest, if any. Debt issuance costs of $5.1 million are being amortized over the life of the 5.5% Senior Notes. The 5.5% Senior Notes' indenture restricts SMLP’s and the Co-Issuers’ ability and the ability of certain of their subsidiaries to: (i) incur additional debt or issue preferred stock; (ii) make distributions, repurchase equity or redeem subordinated debt; (iii) make payments on subordinated indebtedness; (iv) create liens or other encumbrances; (v) make investments, loans or other guarantees; (vi) sell or otherwise dispose of a portion of their assets; (vii) engage in transactions with affiliates; and (viii) make acquisitions or merge or consolidate with another entity. These covenants are subject to a number of important exceptions and qualifications. At any time when the senior notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default or event of default under the indenture has occurred and is continuing, many of these covenants will terminate. The 5.5% Senior Notes' indenture provides that each of the following is an event of default: (i) default for 30 days in the payment when due of interest on the 5.5% Senior Notes; (ii) default in the payment when due of the principal of, or premium, if any, on the 5.5% Senior Notes; (iii) failure by the Co-Issuers or SMLP to comply with certain covenants relating to mergers and consolidations, change of control or asset sales; (iv) failure by SMLP for 180 days after notice to comply with certain covenants relating to the filing of reports with the SEC; (v) failure by the Co-Issuers or SMLP for 30 days after notice to comply with any of the other agreements in the indenture; (vi) specified defaults under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by SMLP or any of its restricted subsidiaries (or the payment of which is guaranteed by SMLP or any of its restricted subsidiaries); (vii) failure by SMLP or any of its restricted subsidiaries to pay certain final judgments aggregating in excess of $20.0 million; (viii) except as permitted by the indenture, any guarantee of the senior notes shall cease for any reason to be in full force and effect or any guarantor, or any person acting on behalf of any guarantor, shall deny or disaffirm its obligations under its guarantee of the senior notes; and (ix) certain events of bankruptcy, insolvency or reorganization described in the indenture. In the case of an event of default as described in the foregoing clause (ix), all outstanding 5.5% Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 5.5% Senior Notes may declare all the 5.5% Senior Notes to be due and payable immediately. As of and during the December 31, 2019, we were in compliance with the financial covenants governing our Senior Notes. There were no defaults or events of default during the year ended December 31, 2019. 11. FINANCIAL INSTRUMENTS Concentrations of Credit Risk. Financial instruments that potentially subject us to concentrations of credit risk consist of cash and cash equivalents, restricted cash and accounts receivable. We maintain our cash and cash equivalents and restricted cash in bank deposit accounts that frequently exceed federally insured limits. We have not experienced any losses in such accounts and do not believe we are exposed to any significant risk. Accounts receivable primarily comprise amounts due for the gathering, compression, treating and processing services we provide to our customers and also the sale of natural gas liquids resulting from our processing services. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of our counterparties and can require letters of credit 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. Our top five customers or counterparties accounted for 46% of total accounts receivable at December 31, 2019, compared to 39% as of December 31, 2018. 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. 138 Table of Contents The Deferred Purchase Price Obligation's carrying value is its fair value because carrying value represents the present value of the payment which can be made at any time prior to January 15, 2022. In November 2019, we and SMP Holdings entered into a second amendment (the “Second Amendment”) to the Contribution Agreement between us and SMP Holdings dated February 25, 2016, as amended. On November 15, 2019, we made a cash payment of $51.75 million and issued 10,714,285 common units to SMP Holdings (the “November 2019 Prepayment”). In addition, the parties reduced the Remaining Consideration due to SMP Holdings by $19.25 million. Following the November 2019 Prepayment, the Remaining Consideration is $180.75 million. The parties also extended the final date by which we are obligated to deliver the Remaining Consideration to January 15, 2022. The Remaining Consideration remains payable to SMP Holdings in (i) cash, (ii) our common units or (iii) a combination of cash and our common units, and interest continues to accrue (and is payable quarterly in cash) at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020. The form(s) of Remaining Consideration to be delivered by us to SMP Holdings continue to be determinable by us in our sole discretion (see Note 17 for additional information). A summary of the estimated fair value of our debt financial instruments follows. Summit Holdings 5.5% Senior Notes ($300.0 million principal) Summit Holdings 5.75% Senior Notes ($500.0 million principal) December 31, 2019 December 31, 2018 Carrying value Estimated fair value (Level 2) Carrying value Estimated fair value (Level 2) (In thousands) $ 298,314 $ 266,750 $ 297,638 $ 286,625 494,985 382,708 494,093 455,208 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, 2019 and 2018. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the Senior Notes. 12. PARTNERS' CAPITAL AND MEZZANINE CAPITAL A rollforward of the number of common limited partner, preferred limited partner and General Partner units follows. Units, January 1, 2017 Units issued in connection with the November 2017 Equity Offering Net units issued under the SMLP LTIP Units issued under ATM program General Partner 2% contribution Units, December 31, 2017 Net units issued under the SMLP LTIP Units, December 31, 2018 Conversion of General Partner economic interests Net units issued under the SMLP LTIP DPPO partial settlement Units, December 31, 2019 Limited partners Series A Preferred Units — 300,000 — — — 300,000 — 300,000 — — — 300,000 Common 72,111,121 General Partner 1,471,187 — 211,327 763,548 — 73,085,996 304,857 73,390,853 8,750,000 638,335 10,714,285 93,493,473 — — — 19,812 1,490,999 — 1,490,999 (1,490,999) — — — 139 Table of Contents GP/IDR Exchange. On March 22, 2019, we cancelled our IDRs and converted our 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 in the Equity Restructuring. These units had a fair value of $84.5 million as of the transaction date (March 22, 2019). As a result of the Equity Restructuring, the general partner units and IDRs were eliminated, are no longer outstanding, and no longer participate in distributions of cash from SMLP. Energy Capital Partners continues to control the non-economic GP interest in SMLP. Immediately following the Equity Restructuring, SMP Holdings directly owned a 41.8% limited partner interest in SMLP and an affiliate of Energy Capital Partners II, LLC directly owned a 7.2% limited partner interest in SMLP. Our General Partner held IDRs (through the Equity Restructuring). Our payment of IDRs as reported in distributions to unitholders – General Partner in the statements of partners' capital during the years ended December 31 follow. IDR payments 2019 Year ended December 31, 2018 2017 (In thousands) $ 2,139 $ 8,535 $ 8,460 For the purposes of calculating net income attributable to General Partner in the statements of operations and partners' capital, the financial impact of IDRs was recognized in respect of the quarter for which the distributions were declared. For the purposes of calculating distributions to unitholders in the statements of partners' capital and cash flows, IDR payments are recognized in the quarter in which they are paid. Unit Offerings. In February 2017, we completed a secondary underwritten public offering of 4,000,000 SMLP common units held by a subsidiary of Summit Investments pursuant to the 2016 SRS. We did not receive any proceeds from this offering. At-the-market Program. In February 2017, we executed a new equity distribution agreement and filed a prospectus with the SEC for the issuance and sale from time to time of SMLP common units having an aggregate offering price of up to $150.0 million (the "ATM Program"). During the years ended December 31, 2019 and 2018, there were no transactions under the ATM Program. During the year ended December 31, 2017, we sold 763,548 units under the ATM Program for aggregate gross proceeds of $17.7 million, and paid approximately $0.2 million as compensation to the sales agents pursuant to the terms of the equity distribution agreement. Series A Preferred Units. In November 2017, we 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. We used the net proceeds of $293.2 million (after deducting underwriting discounts and offering expenses) to repay outstanding borrowings under our Revolving Credit Facility. 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 for the respective reporting period. 140 Table of Contents 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%. Subsidiary Series A Preferred Units. In December 2019, we issued 30,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit. We used the net proceeds of $27.4 million (after deducting underwriting discounts and offering expenses) to fund capital expenses associated with the Double E Project. On January 16, 2020, we issued 10,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit. We used the net proceeds of $9.7 million (after deducting underwriting discounts and offering expenses) to fund capital expenses associated with the Double E Project. The proceeds associated with the issuance of Subsidiary Series A Preferred Units is 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. Accounting for the Subsidiary Series A Preferred Units These preferred units are considered redeemable securities under GAAP due to the existence of certain redemption provisions that are outside of our control. Therefore, the securities are classified as temporary equity in the mezzanine section of the consolidated balance sheet. Initial and Subsequent Measurement We initially recognized these preferred units at the time of issuance in the amount of $27.4 million, their issuance date fair value, net of issuance costs. We will not be required to adjust the carrying amount of these preferred units unless it becomes probable that the units would become redeemable. If events or circumstances indicate that redemption is probable, we would accrete these preferred units to the redemption value over a period of time comprising the date redemption first became probable and the date the units can first be redeemed. The Subsidiary Series A Preferred Units rank 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 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. 141 Table of Contents 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. Noncontrolling Interest. At December 31, 2017, we recorded Summit Investments' indirect retained ownership interest in OpCo and its subsidiaries as a noncontrolling interest in the consolidated financial statements. In November 2018, a subsidiary of SMLP purchased the remaining 1% ownership interest in OpCo held by a subsidiary of Summit Investments for approximately $10.9 million. As a result of this transaction, other than our investment in Ohio Gathering, our investment in Double E and the Subsidiary Series A Preferred Units at Permian Holdco, our business activities are conducted through wholly owned operating subsidiaries. Cash Distribution Policy Our Partnership Agreement requires that we distribute all of our available cash, subject to reserves established by our 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 our policy is subject to fluctuations based on the amount of cash we generate from our business and the decision to make any distribution is determined by our General Partner, taking into consideration the terms of our Partnership Agreement. General Partner Interest. On March 22, 2019, we cancelled our IDRs and converted our 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 in the Equity Restructuring. Cash Distributions Paid and Declared. We paid the following per-unit distributions during the years ended December 31: Per-unit distributions to unitholders 2019 Year ended December 31, 2018 2017 $ 1.4375 $ 2.300 $ 2.300 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. With respect to our Subsidiary Series A Preferred Units relating to the fourth quarter of 2019, we declared a payment-in-kind ("PIK") of the quarterly distribution, which resulted in the pro-rated issuance of 47 Subsidiary Series A Preferred Units. This PIK amount equates to a pro- rated distribution of $1.5556 per Subsidiary Series A Preferred Unit for the fourth quarter in 2019, or $70 on a full year annualized basis. 142 Table of Contents 13. EARNINGS PER UNIT The following table details the components of EPU. Numerator for basic and diluted EPU: Allocation of net (loss) income among limited partner interests: Net (loss) income attributable to limited partners Less net income attributable to Series A Preferred Units Less net income attributable to Subsidiary Series A Preferred Units Net (loss) income attributable to common limited partners Denominator for basic and diluted EPU: Weighted-average common units outstanding – basic Effect of nonvested phantom units Weighted-average common units outstanding – diluted (Loss) earnings per limited partner unit: Common unit – basic Common unit – diluted Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU 14. UNIT-BASED AND NONCASH COMPENSATION 2019 Year ended December 31, 2018 (In thousands, except per-unit amounts) 2017 $ $ (369,845) 28,500 58 (398,403) $ $ 32,799 28,500 — 4,299 $ $ 82,365 — 82,365 73,304 311 73,615 75,485 3,563 — 71,922 72,705 342 73,047 $ $ (4.84) $ (4.84) $ 0.06 $ 0.06 $ 0.99 0.98 175 2 42 SMLP Long-Term Incentive Plan. The SMLP LTIP provides for equity awards to eligible officers, employees, consultants and directors of our General Partner and its affiliates, thereby linking the recipients' compensation directly to SMLP’s performance. The SMLP LTIP is administered by our General Partner's Board of Directors, though such administration function may be delegated to a committee appointed by the board. A total of 5.0 million common units was reserved for issuance pursuant to and in accordance with the SMLP LTIP. As of December 31, 2019, approximately 1.3 million common units remained available for future issuance. The SMLP LTIP provides for the granting, from time to time, of unit-based awards, including common 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 of our General Partner. The administrator of the SMLP LTIP may make grants under the SMLP LTIP that contain such terms, consistent with the SMLP LTIP, as the administrator may determine are appropriate, including vesting conditions. The administrator of the SMLP LTIP may, in its discretion, base vesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the SMLP LTIP) or as otherwise described in an award agreement. Termination of employment prior to vesting will result in forfeiture of the awards, except in limited circumstances as described in the plan documents. Units that are canceled or forfeited will be available for delivery pursuant to other awards. 143 Table of Contents The following table presents phantom unit activity: Nonvested phantom units, January 1, 2017 Phantom units granted Phantom units vested Phantom units forfeited Nonvested phantom units, December 31, 2017 Phantom units granted Phantom units vested Phantom units forfeited Nonvested phantom units, December 31, 2018 Phantom units granted Phantom units vested Phantom units forfeited Nonvested phantom units, December 31, 2019 Units 691,955 $ 371,972 (293,222) (21,431) 749,274 515,358 (359,016) (41,492) 864,124 1,913,099 (602,617) (68,611) 2,105,995 $ Weighted-average grant date fair value 19.59 22.50 24.76 20.07 20.07 15.25 22.39 17.27 17.11 6.48 16.78 12.87 7.69 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 our 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 our 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 $ 5,940 $ 5,393 $ 6,657 As of December 31, 2019, the unrecognized unit-based compensation related to the SMLP LTIP was $8.5 million. Incremental unit-based compensation will be recorded over the remaining weighted-average vesting period of approximately 1.6 years. Unit-based compensation recognized in general and administrative expense related to awards under the SMLP LTIP follows. 2019 Year ended December 31, 2018 2017 (In thousands) SMLP LTIP unit-based compensation $ 8,171 $ 8,328 $ 7,951 2019 Year ended December 31, 2018 2017 (In thousands) 144 Table of Contents 15. RELATED-PARTY TRANSACTIONS Acquisitions. See Notes 1 and 17. Reimbursement of Expenses from General Partner. Our General Partner and its affiliates do not receive a management fee or other compensation in connection with the management of our business, but will be reimbursed for expenses incurred on our behalf. Under our Partnership Agreement, we reimburse our General Partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our General Partner's employees and executive officers who perform services necessary to run our business. Our Partnership Agreement provides that our General Partner will determine in good faith the expenses that are allocable to us. The "Due to affiliate" line item on the consolidated balance sheet represents the payables to our General Partner for expenses incurred by it and paid on our behalf. Expenses incurred by the General Partner and reimbursed by us under our Partnership Agreement were as follows: Operation and maintenance expense General and administrative expense 2019 Year ended December 31, 2018 2017 (In thousands) $ 28,643 $ 32,222 29,061 $ 30,119 27,450 30,899 In February 2017, SMP Holdings sold 4,000,000 common units representing limited partner interests in SMLP at a price to the public of $24.00 per common unit. Consistent with our obligations under the Partnership Agreement, we paid all costs and expenses of the secondary offering (other than underwriting discounts and fees and expenses of counsel and advisors to SMP Holdings in the sale). We did not receive any of the proceeds from the secondary offering. 16. LEASES, COMMITMENTS AND CONTINGENCIES Leases. We account for leases in accordance with Topic 842, which we adopted on January 1, 2019, using the modified retrospective method. Under the modified retrospective method, the comparative information is not adjusted and is reported under the accounting standards in effect for those periods. See Note 2 for further discussion of the adoption. We and Summit Investments lease certain office space and equipment under operating leases. We lease office space for our corporate headquarters as well as for corporate offices in Dallas, Denver and Atlanta and offices in and around our gathering systems for terms of between 3 and 10 years. We lease the office space to limit exposure to risks related to ownership, such as fluctuations in real estate prices. In addition, we lease equipment primarily to support our operations in response to the needs of our gathering systems for terms of between 3 and 4 years. We and Summit Investments also lease vehicles under finance leases to support our operations in response to the needs of our gathering systems for a term of 3 years. We only lease from reputable companies and our leased assets are not specialized in our industry. Some of our 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. We have options to extend the lease term of certain office space in Texas, Colorado and West Virginia. The beginning of the noncancelable lease period for these leases ranged from 2014 to 2018 and the lease period ends between 2020 and 2028. These lease agreements contain between one and three options to renew the lease for a period of between two and five years. As of December 31, 2019, the exercise of the renewal options for these leases are not reasonably certain and, as a result, the payments associated with these renewals are not included in the measurement of the lease liability and ROU asset. 145 Table of Contents We also have options to extend the lease term of certain compression equipment used at the Summit Utica gathering system. The beginning of the noncancelable lease period for these leases was 2017 and the lease period ends in 2020. Upon expiration of the noncancelable lease period, we have the option to renew the leases on a month-to-month basis; we therefore have not included any amounts attributable to renewals in the measurement. Our leases do not contain residual value guarantees. In accordance with the provisions in our Revolving Credit Facility, our aggregate finance lease obligations cannot exceed $50 million in any period of twelve consecutive calendar months during the life of such leases. In November 2019, we entered into a sublease agreement with a third party to sublease corporate office space in Houston, Texas. The noncancelable sublease period begins in 2020 and the sublease period ends in 2025. The sublease agreement contains one option to renew the lease for five years. We moved our corporate headquarters to the Houston office on March 2, 2020. Our future minimum sublease payments are approximately $1.2 million. In March 2019, we entered into an agreement with a third party vendor to construct a transmission line to deliver electric power to the new 60 MMcf/d processing plant in the DJ Basin. The project is expected to cost approximately $7.8 million and we made an up-front payment of $3.0 million, which is included in the Property, plant and equipment, net caption on the consolidated balance sheet. During the second quarter of 2019, we exercised an option to increase the capacity of the transmission line for an additional cost of $4.3 million and we issued an irrevocable standby letter of credit payable to the vendor with an initial term of one year totaling $9.1 million, which reflects the expected remaining cost of the project. The letter of credit will automatically renew for successive twelve month periods following the initial term, subject to certain adjustments. Once construction is complete, the letter of credit will be adjusted to reflect the final construction cost. We determined the contract contained a lease based on the right to use the constructed transmission line to power the processing plant in the DJ Basin. The project is expected to be completed and the commencement date of the ROU asset will be on or before January 2021. Our significant assumptions or judgments include the determination of whether a contract contains a lease and the discount rate used in our lease liabilities. The rate implicit in our lease contracts is not readily determinable. In determining the discount rate used in our lease liabilities, we analyzed certain factors in our incremental borrowing rate, including collateral assumptions and the term used. Our incremental borrowing rate on the Revolving Credit Facility was 4.55% at December 31, 2019, which reflects the fixed rate at which we could borrow a similar amount, for a similar term and with similar collateral as in the lease contracts at the commencement date. We adopted the following practical expedients in Topic 842 for all asset classes, which included (i) not being required to reassess whether any expired or existing contracts are or contain leases; (ii) not being required to reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840 will be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will be classified as finance leases); (iii) not being required to reassess initial direct costs for any existing leases; (iv) not recognizing ROU assets and lease liabilities that arise from short-term leases of twelve months or less for any class of underlying asset; (v) not allocating consideration in a contract between lease and nonlease (e.g., maintenance services) components for our leased office space and equipment; and (vi) not evaluating existing or expired land easements that were not previously accounted for as leases under Topic 840. 146 Table of Contents ROU assets (included in the Property, plant and equipment, net caption on our consolidated balance sheet) and lease liabilities (included in the Other current liabilities and Other noncurrent liabilities captions on our consolidated balance sheet) follow: 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) 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 $ $ $ $ $ $ $ $ $ December 31, 2019 (In thousands) 3,580 3,159 6,739 1,221 1,246 2,467 2,513 676 3,189 Year ended December 31, 2019 (In thousands) Twelve months ended December 31, 2019 (In thousands) 1,559 102 3,159 4,820 3,396 102 1,873 1,218 1,350 5.8 2.0 5% 4% We recognize total lease expense incurred or allocated to us in general and administrative expenses. Lease expense related to operating leases, including lease expense incurred on our behalf and allocated to us, was as follows: Lease expense 2019 Year ended December 31, 2018 2017 (In thousands) $ 3,851 $ 3,928 $ 3,772 147 Table of Contents Future minimum lease payments due under noncancelable leases at December 31, 2019, were as follows 2020 2021 2022 2023 2024 2025 Thereafter Total future minimum lease payments December 31, 2019 (In thousands) Operating Finance $ $ 1,705 $ 1,004 551 408 240 153 742 4,803 $ 1,299 616 76 — — — — 1,991 Future minimum lease payments due under noncancelable operating leases (under ASC 840) at December 31, 2018, were as follows: 2019 2020 2021 2022 2023 Thereafter Total future minimum lease payments Future payments due under finance leases (under ASC 840) at December 31, 2018, were as follows: 2019 2020 2021 Total finance lease obligations Less: Amounts representing interest Net present value of finance lease obligations Less: Amount representing current portion (included in Other current liabilities) Finance lease obligations, less current portion (included in Other noncurrent liabilities) December 31, 2018 (In thousands) 3,133 1,018 550 506 373 621 6,201 December 31, 2018 (In thousands) 1,473 902 174 2,549 (104) 2,445 (1,406) 1,039 $ $ $ $ Environmental Matters. Although we believe that we are in material compliance with applicable environmental regulations, the risk of environmental remediation costs and liabilities are inherent in pipeline ownership and operation. Furthermore, we can provide no assurances that significant environmental remediation costs and liabilities will not be incurred by the Partnership in the future. We are currently not aware of any material contingent liabilities that exist with respect to environmental matters, except as noted below. 148 Table of Contents In 2015, Summit Investments learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream system near Williston, North Dakota. The incident, 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. Summit Investments exhausted the $25.0 million pollution liability policy in 2015. We submitted property and business interruption claim requests to the insurers and reached a settlement in January 2017. In connection therewith, we recognized $2.6 million of business interruption recoveries and $0.4 million of property recoveries. A rollforward of the aggregate accrued environmental remediation liabilities follows. Accrued environmental remediation, January 1, 2018 Payments made Additional accruals Accrued environmental remediation, December 31, 2018 Payments made Additional accruals Accrued environmental remediation, December 31, 2019 Total (In thousands) 5,344 (3,808) 4,100 5,636 (2,284) 1,299 4,651 $ $ $ As of December 31, 2019, we have 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 and fines expected to be incurred subsequent to December 31, 2020. Each of these amounts represent our best estimate for costs expected to be incurred. Neither of these amounts has been discounted to its present value. While we cannot predict the ultimate outcome of this matter with certainty for Summit Investments or Meadowlark Midstream, especially as it relates to any material liability as a result of any governmental proceeding related to the incident, we believe at this time that it is unlikely that SMLP or its General Partner will be subject to any material liability as a result of any governmental proceeding related to the rupture. 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. 17. DISPOSITIONS, DROP DOWN TRANSACTIONS AND RESTRUCTURING Red Rock Gathering Asset Disposition. 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, subject to adjustments as provided in the Red Rock PSA (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 Disposition. In February 2019, Tioga Midstream, LLC, a subsidiary of SMLP, and certain affiliates of SMLP (collectively, “the Tioga Parties”) entered into two Purchase and Sale Agreements (the “Tioga PSAs”) with Hess Infrastructure Partners LP and Hess North Dakota Pipelines LLC (collectively, “Hess Infrastructure”), pursuant to which the Tioga Parties agreed to sell the Tioga Midstream system to Hess Infrastructure for a combined cash purchase price of $90 million, subject to adjustments as provided in the Tioga PSAs (the “Tioga Midstream Sale”). On March 22, 2019, the Tioga Parties closed the Tioga Midstream Sale 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 through March 22, 2019. 149 Table of Contents 2016 Drop Down. In 2016, SMLP acquired a controlling interest in OpCo, the entity which owns the 2016 Drop Down Assets. These assets include certain natural gas, crude oil and produced water gathering systems located in the Utica Shale, the Williston Basin and the DJ Basin, as well as ownership interests in Ohio Gathering. The net consideration paid and recognized in connection with the 2016 Drop Down (i) consisted of a cash payment to SMP Holdings of $360.0 million funded with borrowings under our Revolving Credit Facility and a $0.6 million working capital adjustment received in June 2016 (the “Initial Payment”) and (ii) includes the Deferred Purchase Price Obligation payment due in 2020. In March 2019, the Partnership amended the Contribution Agreement related to the 2016 Drop Down and fixed the Remaining Consideration at $303.5 million, with such amount to be paid by the Partnership in one or more payments over the period from March 1, 2020 through December 31, 2020, in (i) cash, (ii) the Partnership’s common units or (iii) a combination of cash and the Partnership’s common units, at the discretion of the Partnership. At least 50% of the Remaining Consideration must be paid on or before June 30, 2020 and interest will accrue at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020. On November 7, 2019, we and SMP Holdings entered into a second amendment (the “Second Amendment”) to the Contribution Agreement between us and SMP Holdings dated February 25, 2016, as amended. On November 15, 2019, we made a cash payment of $51.75 million and issued 10,714,285 common units to SMP Holdings (the “November 2019 Prepayment”). In addition, the parties reduced the Remaining Consideration due to SMP Holdings by $19.25 million. Following the November 2019 Prepayment, the Remaining Consideration is $180.75 million. The parties also extended the final date by which we are obligated to deliver the Remaining Consideration to January 15, 2022. The Remaining Consideration remains payable to SMP Holdings in (i) cash, (ii) our common units or (iii) a combination of cash and our common units, and interest continues to accrue (and is payable quarterly in cash) at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020. The form(s) of Remaining Consideration to be delivered by us to SMP Holdings continue to be determinable by us in our sole discretion. The present value of the Deferred Purchase Price Obligation is reflected as a liability on our balance sheet until paid. As of December 31, 2019, the Remaining Consideration, which reflects the net present value of the $180.75 million Deferred Purchase Price Obligation, was $178.5 million on the consolidated balance sheet using a discount rate of 5.25%. Restructuring Activities. In 2019, our management approved and initiated a plan to restructure our operations resulting in certain management, facility and organizational changes. During the year ended December 31, 2019, we expensed costs of approximately $5.0 million associated with 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. As of December 31, 2019, the components of our restructuring plan are as follows: • Employee-related costs — we reorganized our workforce and eliminated redundant or unneeded positions. In connection with the workforce restructuring, we expect to incur severance, benefits and other employee related costs of approximately $6.0 million to be incurred over the twelve months following December 31, 2019. During the fiscal year ended December 31, 2019, we expensed approximately $3.8 million primarily related to severance, redundant salaries, certain bonuses and other employee benefits in connection with our plan. As of December 31, 2019, we had approximately $2.7 million included in current liabilities for these costs. 150 Table of Contents • Consultants — we engaged third-party consulting firms to assist in the evaluation of the Company’s cost structure, to help formulate the plan to implement the project, and to provide project management services for certain project initiatives. During the fiscal year ended December 31, 2019, we expensed approximately $1.2 million related to these services. As of December 31, 2019, we had approximately $0.6 million included in current liabilities for these costs. We expect to incur an additional $0.2 million related to consulting costs to be incurred over the next twelve months following December 31, 2019. 18. CONDENSED CONSOLIDATING FINANCIAL INFORMATION The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by SMLP and the Guarantor Subsidiaries (see Note 10). 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 December 2019, we executed the third amendment to the third amended and restated credit agreement that, among other things, designated Permian Holdco and Summit Permian Transmission as unrestricted subsidiaries under the Revolving Credit Facility. Prior to this amendment, Summit Permian Transmission did not have any assets or operations. In December 2019, we executed a partial release agreement that designated the Non-Guarantor Subsidiaries as unrestricted subsidiaries under the Senior Notes. As a result of these transactions, all prior periods presented have been recast to reflect this change. The following supplemental condensed consolidating financial information reflects SMLP's separate accounts, the combined accounts of the Co-Issuers, the combined accounts of the Guarantor Subsidiaries, the combined accounts of the Non-Guarantor Subsidiaries and the consolidating adjustments for the dates and periods indicated. For purposes of the following consolidating information each of SMLP and the Co-Issuers account for their subsidiary investments, if any, under the equity method of accounting. 151 Table of Contents Condensed Consolidating Balance Sheet. Balance sheets as of December 31, 2019 and 2018 follow. SMLP Co-Issuers December 31, 2019 Guarantor Subsidiaries Non- Guarantor Subsidiaries (In thousands) Consolidating adjustments Total Assets Cash and cash equivalents Restricted cash Accounts receivable Other current assets Due from affiliate Total current assets Property, plant and equipment, net Intangible assets, net Investment in equity method investees Other noncurrent assets Investment in subsidiaries Total assets Liabilities and Capital Trade accounts payable Accrued expenses Due to affiliate Deferred revenue Ad valorem taxes payable Accrued interest Accrued environmental remediation Other current liabilities Total current liabilities Long-term debt Noncurrent Deferred Purchase Price Obligation Noncurrent deferred revenue Noncurrent accrued environmental remediation Other noncurrent liabilities Total liabilities $ 118 $ — 69 2,124 — 2,311 6,420 — 611 $ — — — 36,300 36,911 4,110 $ — 102,049 2,894 776,552 885,605 — 1,875,558 232,278 — 109 $ 27,392 — — — 27,501 — — — $ — — — (812,852) (812,852) 4,948 27,392 102,118 5,018 — 139,476 273 1,882,251 232,278 — — 3,152 275,000 — 29 6,167 1,758,547 3,198,079 — $ 1,770,430 $ 3,241,157 $ 3,268,470 $ 35,002 370 (274) — — (4,956,626) 309,728 9,718 — 62,873 $ (5,769,479) $ 2,573,451 $ 657 $ 1,649 777,077 — 14 — — 7,342 786,739 — $ — — — — 12,311 — — 12,311 — 1,470,299 23,758 $ 9,536 — 13,493 8,463 — 1,725 4,591 61,566 — 178,453 — — — — 38,709 — $ 297 — — — — 297 — — — — $ — (776,766) — — — — — (776,766) 24,415 11,482 311 13,493 8,477 12,311 1,725 11,933 84,147 — 1,470,299 — — 178,453 38,709 — 5,635 — — 970,827 1,482,610 2,926 2,316 105,517 — — 297 — — 2,926 7,951 (776,766) 1,782,485 Total mezzanine capital — — — 27,450 — 27,450 Total partners' capital Total liabilities, mezzanine capital and partners' capital 799,603 1,758,547 3,162,953 35,126 (4,992,713) 763,516 $ 1,770,430 $ 3,241,157 $ 3,268,470 $ 62,873 $ (5,769,479) $ 2,573,451 152 Table of Contents Assets Cash and cash equivalents Accounts receivable Other current assets Due from affiliate Total current assets Property, plant and equipment, net Intangible assets, net Goodwill Investment in equity method investees Other noncurrent assets Investment in subsidiaries Total assets Liabilities and Partners' Capital Trade accounts payable Accrued expenses Due to affiliate Deferred revenue Ad valorem taxes payable Accrued interest Accrued environmental remediation Other current liabilities Total current liabilities Long-term debt Noncurrent Deferred Purchase Price Obligation Noncurrent deferred revenue Noncurrent accrued environmental remediation Other noncurrent liabilities Total liabilities SMLP Co-Issuers December 31, 2018 Guarantor Subsidiaries Non- Guarantor Subsidiaries (In thousands) Consolidating adjustments Total $ 185 $ 321 1,179 — 1,685 5,813 — — 230 $ — — — 230 3,930 $ 97,615 2,792 593,384 697,721 — 1,948,280 273,416 — 16,211 — — $ — — — — 9,620 — — — $ — — (593,384) (593,384) 4,345 97,936 3,971 — 106,252 — 1,963,713 273,416 — 16,211 — — 3,183 649,250 — 26 8,511 2,096,717 3,461,921 — $ 2,107,398 $ 3,470,662 $ 3,584,904 $ — — — — — (5,558,638) 649,250 11,720 — 9,620 $ (6,152,022) $ 3,020,562 $ 275 $ 1,106 482,384 — 14 — — 7,306 491,085 — $ — 103,928 — — 12,286 — — 116,214 — 1,257,731 35,831 $ 20,857 — 11,467 10,536 — 2,487 5,339 86,517 — 2,308 $ — — — — — — — 2,308 — — $ — (586,072) — — — — — (586,072) 38,414 21,963 240 11,467 10,550 12,286 2,487 12,645 110,052 — 1,257,731 383,934 — — — — 39,504 — — — — 383,934 39,504 — 3,843 — — 878,862 1,373,945 3,149 1,125 130,295 — — 2,308 — — 3,149 4,968 (586,072) 1,799,338 Total partners' capital Total liabilities partners' capital 1,228,536 2,096,717 3,454,609 $ 2,107,398 $ 3,470,662 $ 3,584,904 $ 7,312 (5,565,950) 1,221,224 9,620 $ (6,152,022) $ 3,020,562 Condensed Consolidating Statement of Operations. For the purposes of the following condensed consolidating statements of operations, we allocate general and administrative expenses recognized at the SMLP parent to the Guarantor Subsidiaries and Non-Guarantor Subsidiaries to reflect what those entities' results would have been had they operated on a stand-alone basis. Statements of operation for the years ended December 31, 2019, 2018 and 2017 follow. 153 Table of Contents 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 Loss (gain) on asset sales, net Long-lived asset impairment Goodwill impairment Total costs and expenses Other income Interest expense Deferred Purchase Price Obligation (Loss) income before income taxes and loss from equity method investees Income tax expense Loss from equity method investees Equity in earnings of consolidated subsidiaries Net (loss) income SMLP Co-Issuers Year ended December 31, 2019 Guarantor Subsidiaries Non- Guarantor Subsidiaries (In thousands) Consolidating adjustments Total $ — $ — $ 326,747 $ — $ 326,747 — — — — — — 2,604 1,788 9 — — 4,401 451 — 1,982 — — — 86,994 29,787 443,528 — — — — — — — — — — (74,327) — 63,438 97,587 54,139 107,602 — (1,545) 60,507 16,211 397,939 — (102) — (1,968) (1,174) (74,327) — 45,487 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 86,994 29,787 443,528 63,438 97,587 54,139 110,206 1,788 (1,536) 60,507 16,211 402,340 451 (74,429) 1,982 — — (30,808) (1,174) — — (336,950) (901) — (337,851) (366,691) (369,833) $ (292,364) (366,691) $ — (291,463) $ $ — (901) $ 659,055 659,055 $ — (369,833) 154 Table of Contents 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 Long-lived asset impairment Total costs and expenses Other income Interest expense Deferred Purchase Price Obligation Income (loss) before income taxes and loss from equity method investees Income tax expense Loss from equity method investees Equity in earnings of consolidated subsidiaries Net income SMLP Co-Issuers Year ended December 31, 2018 Guarantor Subsidiaries Non- Guarantor Subsidiaries (In thousands) Consolidating adjustments Total $ — $ — $ 344,616 $ — $ — $ 344,616 — — — — — — 134,834 27,203 506,653 — — — 1,743 — 1,743 (169) — (20,975) — — — — — — — (60,442) — 107,661 96,878 52,877 105,357 7,186 369,959 — (93) — (22,887) (33) (60,442) — 136,601 — — — (10,888) — — — — — — — — — — — — — — — — — — — — — — — — — — — 134,834 27,203 506,653 107,661 96,878 52,877 107,100 7,186 371,702 (169) (60,535) (20,975) — — 53,272 (33) — (10,888) 65,271 42,351 $ 125,713 65,271 $ — 125,713 $ $ — — $ (190,984) (190,984) $ — 42,351 155 Table of Contents 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 Total costs and expenses Other income Interest expense Early extinguishment of debt Deferred Purchase Price Obligation Loss before income taxes and loss from equity method investees Income tax expense Loss from equity method investees Equity in loss of consolidated subsidiaries Net loss SMLP Co-Issuers Year ended December 31, 2017 Guarantor Subsidiaries Non- Guarantor Subsidiaries (In thousands) Consolidating adjustments Total $ — $ — $ 394,427 $ — $ — $ 394,427 — — — — — — 68,459 25,855 488,741 — — — 1,101 73 — — 1,174 298 — — 200,322 — — — — — — — — — (68,080) (22,039) — 57,237 93,882 54,681 114,374 — 527 188,702 509,403 — (51) — — 199,446 (341) (90,119) — (20,713) — — — (2,223) — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 68,459 25,855 488,741 57,237 93,882 54,681 115,475 73 527 188,702 510,577 298 (68,131) (22,039) 200,322 — — 88,614 (341) — (2,223) (113,055) 86,050 $ (22,936) (113,055) $ — (22,936) $ $ — — $ 135,991 135,991 $ — 86,050 156 Table of Contents Condensed Consolidating Statement of Cash Flows. Statement of cash flows for the years ended December 31, 2019, 2018 and 2017 follow. Cash flows from operating activities: Net cash provided by (used in) operating activities Cash flows from investing activities: Capital expenditures Proceeds from asset sales Distributions from equity method investment Investment in equity method investee Other, net Advances to affiliates Net cash (used in) provided by investing activities Cash flows from financing activities: Distributions to unitholders Distributions to Series A Preferred unitholders Borrowings under Revolving Credit Facility Repayments under Revolving Credit Facility Repayment of Deferred Purchase Price Obligation Debt issuance costs Proceeds from the issuance of Series A preferred units, net of costs Other, net Advances from affiliates Net cash (used in) provided by 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 SMLP Co-Issuers Year ended December 31, 2019 Guarantor Subsidiaries Non- Guarantor Subsidiaries (In thousands) Consolidating adjustments Total $ 5,811 $ (69,891) $ 246,492 $ (75) $ — $ 182,337 (1,323) — — — 314 (28,776) — — — — — (140,229) (163,379) 102,111 (17,589) — — 7,313 — — — — (1) (183,170) (18,316) — — — — 352,175 (182,291) 102,111 7,313 (18,316) 313 — (29,785) (140,229) (244,439) (28,592) 352,175 (90,870) (116,624) (28,500) — — — — 369,000 (158,000) (151,750) — — (499) — — — — — — — (2,618) 323,399 — — — — (1,873) — — — — — — — 27,392 — — — — — — — — 28,776 (352,175) (116,624) (28,500) 369,000 (158,000) (151,750) (499) 27,392 (4,491) — 23,907 210,501 (1,873) 56,168 (352,175) (63,472) (67) 381 180 27,501 185 230 3,930 — — — 27,995 4,345 $ 118 $ 611 $ 4,110 $ 27,501 $ — $ 32,340 157 Table of Contents Cash flows from operating activities: Net cash provided by (used in) operating activities Cash flows from investing activities: Capital expenditures Proceeds from asset sales Contributions to equity method investees Purchase of noncontrolling interest Other, net Advances to affiliates Net cash provided by (used in) investing activities Cash flows from financing activities: Distributions to unitholders Distributions to Series A Preferred unitholders Borrowings under Revolving Credit Facility Repayments under Revolving Credit Facility Debt issuance costs Other, net Advances from affiliates Net cash (used in) provided by financing activities Net change in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period SMLP Co-Issuers Year ended December 31, 2018 Guarantor Subsidiaries Non- Guarantor Subsidiaries (In thousands) Consolidating adjustments Total $ 7,470 $ (56,181) $ 276,640 $ — $ — $ 227,929 (3,323) — — (10,981) (284) (7,312) — — — — — (189,951) 496 (7,312) — — — (200,586) 496 (4,924) — — — — — — — — — 233,919 (4,924) (10,981) (284) — (148,320) (78,287) (21,900) (148,320) (272,666) (7,312) 233,919 (216,279) (180,705) (28,500) — — — 289,000 — — — — — (2,913) 226,607 (84,000) (344) — — — — (1,273) — — — — — — — 7,312 — — — — — — (233,919) (180,705) (28,500) 289,000 (84,000) (344) (4,186) — 14,489 204,656 (1,273) 7,312 (233,919) (8,735) 59 126 155 75 2,701 1,229 — — — — 2,915 1,430 $ 185 $ 230 $ 3,930 $ — $ — $ 4,345 158 Table of Contents Cash flows from operating activities: Net cash provided by (used in) operating activities Cash flows from investing activities: Capital expenditures Proceeds from asset sales Contributions to equity method investees Purchase of noncontrolling interest Other, net Advances to affiliates Net cash used in investing activities Cash flows from financing activities: Distributions to unitholders Distributions to Series A Preferred unitholders Borrowings under Revolving Credit Facility Repayments under Revolving Credit Facility Debt issuance costs Payment of redemption and call premiums on senior notes Proceeds from ATM Program issuances, net of costs Proceeds from issuance of Series A preferred units, net of costs Contribution from General Partner Issuance of senior notes Tender and redemption of senior notes Other, net Advances from affiliates Net cash provided by (used in) financing activities Net change in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period SMLP Co-Issuers Year ended December 31, 2017 Guarantor Subsidiaries Non- Guarantor Subsidiaries (In thousands) Consolidating adjustments Total $ 7,122 $ (68,915) $ 299,625 $ — $ — $ 237,832 (3,041) — — (797) (458) (278,493) (282,789) (179,103) (2,375) — — — — — — — — — — — — — 247,500 (634,500) (16,390) (17,932) 17,078 — 293,238 465 — — — 500,000 (121,174) 2,300 (25,513) — — (148,229) (292,616) — — — — — — — — — — — (2,437) 148,229 (300,000) — 290,261 — (691) (11,768) 275,095 68,939 (12,459) (572) 698 24 51 (5,450) 6,679 — — — — — — — — — — — — — — — — — — — — — — — — — — — — 426,722 426,722 — — — — — — — — — — — — (426,722) (124,215) 2,300 (25,513) (797) (458) — (148,683) (179,103) (2,375) 247,500 (634,500) (16,390) (17,932) 17,078 293,238 465 500,000 (300,000) (3,128) — (426,722) (95,147) — — (5,998) 7,428 $ 126 $ 75 $ 1,229 $ — $ — $ 1,430 159 Table of Contents 19. UNAUDITED QUARTERLY FINANCIAL DATA Summarized information on the consolidated results of operations for each of the quarters during the two-year period ended December 31, 2019, follows. Total revenues Net (loss) income attributable to SMLP Less net income and IDRs attributable to General Partner Less net income attributable to Series A Preferred Units Less net income attributable to Subsidiary Series A Preferred Units Net loss attributable to common limited partners Loss per limited partner unit: Common unit - basic Common unit - diluted Total revenues Net income (loss) attributable to SMLP Less net income and IDRs attributable to General Partner Less net income attributable to Series A Preferred Units Net income (loss) attributable to common limited partners Earnings (loss) per limited partner unit: Common unit - basic Common unit - diluted 20. SUBSEQUENT EVENTS December 31, 2019 September 30, 2019 June 30, 2019 March 31, 2019 112,247 $ 100,187 $ 99,686 $ 131,408 (In thousands, except per-unit amounts) Quarter ended (327,083) $ (10,645) $ 4,809 $ (36,914) — — — 7,125 7,125 7,125 12 7,125 58 — — — (334,266) $ (17,770) $ (2,316) $ (44,051) (3.79) $ (3.79) $ (0.21) $ (0.21) $ Quarter ended (0.03) $ (0.03) $ (0.58) (0.58) December 31, 2018 September 30, 2018 June 30, 2018 March 31, 2018 133,671 $ 127,479 $ 128,183 $ 117,320 (In thousands, except per-unit amounts) 38,654 $ 57,430 $ (49,971) $ 2,907 7,125 3,279 7,125 1,140 7,125 (3,930) 2,058 7,125 28,622 $ 47,026 $ (58,236) $ (13,113) 0.39 $ 0.39 $ 0.64 $ 0.64 $ (0.79) $ (0.79) $ (0.18) (0.18) $ $ $ $ $ $ $ $ $ $ We have evaluated subsequent events for recognition or disclosure in the consolidated financial statements and no events have occurred that require adjustment to or disclosure in the consolidated financial statements. 160 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, 2019 and 2018. 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 2019 that have materially affected, or are reasonably likely to materially affect, SMLP's internal control over financial reporting. 161 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, 2019, 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, 2019. Our independent registered public accounting firm has issued an audit report on our internal control over financial reporting, included below of this report. /s/ Heath Deneke 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) 162 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, 2019, 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, 2019, 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, 2019, of the Partnership and our report dated March 9, 2020 expressed an unqualified opinion on those financial statements based on our audit and the report of other auditors. 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 An entity’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 Atlanta, Georgia March 9, 2020 163 Table of Contents Item 9B. Other Information. None. 164 Table of Contents Item 10. Directors, Executive Officers and Corporate Governance. Management of Summit Midstream Partners, LP PART III We are managed by the directors and executive officers of our General Partner, Summit Midstream GP, LLC. Our General Partner is not elected by our unitholders and will not be subject to re-election in the future. Summit Investments, which is controlled by Energy Capital Partners, owns and controls SMP Holdings, the sole owner of our General Partner. SMP Holdings has the right to appoint the entire Board of Directors, including our independent directors. All decisions of the Board of Directors will require the affirmative vote of a majority of all of the directors constituting the board, provided that such majority includes at least a majority of the directors designated as an "Energy Capital Partner Designated Director" by Energy Capital Partners. The Energy Capital Partner Designated Directors are Matthew F. Delaney, Peter Labbat, Thomas K. Lane, Scott A. Rogan and Jeffrey R. Spinner. Our unitholders are not entitled to directly or indirectly participate in our management or operations. Our General Partner is liable, as General Partner, for all of our debts (to the extent not paid from our assets), except for indebtedness (including the outstanding indebtedness under our Revolving Credit Facility) or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our General Partner. Our General Partner's limited liability company agreement provides that the Board of Directors must obtain the approval of members representing a majority interest in our General Partner for certain actions affecting us. These include actions related to: • • • • • • transactions with affiliates; entering into any hedging transactions that are not in compliance with GAAP; the voluntary liquidation, wind-up or dissolution of us or any of our subsidiaries; making any election that would result in us being classified as other than a partnership or a disregarded entity for U.S. federal income tax purposes; filing or consenting to the filing of any bankruptcy, insolvency or reorganization petition for relief from debtors or protection from creditors naming us or any of our subsidiaries; and effecting a material amendment to our General Partner's limited liability company agreement. Currently, SMP Holdings is the sole member of our General Partner. Committees of the Board of Directors The Board of Directors has an Audit Committee, a Conflicts Committee and a Compensation 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 Matthew F. Delaney Heath Deneke Lee Jacobe Peter Labbat Thomas K. Lane Jerry L. Peters Scott A. Rogan Jeffrey R. Spinner Robert M. Wohleber Audit Committee Conflicts Committee Compensation Committee Member Member Chair Member Member Chair Chair Member Member Independent Director No No Yes No No Yes No No Yes 165 Table of Contents Each of the standing committees of the Board of Directors will have the composition and responsibilities described below. Audit Committee. Mr. Jacobe, Mr. Peters and Mr. Wohleber serve as the members of the Audit Committee. Mr. Peters serves as the chair of our 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 our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The Audit Committee has the sole authority to retain and terminate our 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 our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to the Audit Committee. Our Audit Committee has adopted an audit committee charter, which is publicly available on our website under the "Corporate Governance" subsection of the “Investors” section at www.summitmidstream.com. Conflicts Committee. At the direction of our General Partner, our Conflicts Committee will review specific matters that may involve conflicts of interest in accordance with the terms of our Partnership Agreement. The Conflicts Committee will determine the resolution of the conflict of interest that is in the best interests of the Partnership. There is no requirement that our General Partner seek the approval of the Conflicts Committee for the resolution of any conflict. The members of the Conflicts Committee may not be officers or employees of our General Partner or directors, officers, or employees of any of its affiliates. They may not hold any ownership interest in our General Partner or us and our subsidiaries other than common units and other awards that are granted under our incentive plans in place from time to time. Furthermore, the members of the Conflicts Committee must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. Mr. Jacobe, Mr. Peters and Mr. Wohleber currently serve as the members of our Conflicts Committee, with Mr. Wohleber serving as chair of the committee. Any matters approved by the Conflicts Committee in good faith will be conclusively deemed to be approved by all of our partners and not a breach by our General Partner of any duties it may owe us or our unitholders. Any unitholder challenging any matter approved by the Conflicts Committee will have the burden of proving that the members of the Conflicts Committee did not subjectively believe that the matter was in the best interests of the Partnership. Moreover, any acts taken or omitted to be taken in reliance upon the advice or opinions of experts such as legal counsel, accountants, appraisers, management consultants and investment bankers, where our General Partner (or any members of the Board of Directors including any member of the Conflicts Committee) reasonably believes the advice or opinion to be within such person's professional or expert competence, shall be conclusively presumed to have been taken or omitted in good faith. Compensation Committee. Mr. Lane, Mr. Spinner and Mr. Wohleber serve as the members of the Compensation Committee, with Mr. Lane serving as chair of the committee. The Compensation Committee provides oversight, administers and makes decisions regarding our executive compensation policies and incentive plans. Although our common units are listed on the NYSE, we qualify for the “Limited Partnership” exemption to the NYSE rule that would otherwise require listed companies to have an independent compensation committee with a written charter. Directors and Executive Officers Directors of our General Partner are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the Board of Directors. 166 Table of Contents The following table shows information for the directors and executive officers of our General Partner as of February 27, 2020. Name Heath Deneke Leonard W. Mallett Marc D. Stratton Brock M. Degeyter Louise E. Matthews Matthew F. Delaney Lee Jacobe Peter Labbat Thomas K. Lane Jerry L. Peters Scott A. Rogan Jeffrey R. Spinner Robert M. Wohleber Position with Summit Midstream GP, LLC Age 46 President and Chief Executive Officer, Director 63 Executive Vice President and Chief Operations Officer 42 Executive Vice President and Chief Financial Officer 43 Executive Vice President, General Counsel and Chief Compliance Officer 50 Executive Vice President and Chief Administration Officer 33 Director 52 Director 54 Director 63 Director 62 Director 49 Director 38 Director 69 Director Heath Deneke has been President and Chief Executive Officer and a director of our General Partner since his appointment effective September 16, 2019. Prior to joining our 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. Leonard W. Mallett has been Executive Vice President and Chief Operating Officer of our General Partner since December 2015, and also served as President and Chief Executive Officer and director of our General Partner on an interim basis from February 21, 2019 until Mr. Deneke’s appointment effective September 16, 2019. Prior to joining our General Partner, Mr. Mallett served as Senior Vice President of Engineering for Enterprise, where he was responsible for the engineering, project management, sourcing and technical support functions supporting all of Enterprise’s pipeline and related plants. Mr. Mallett began his career with TEPPCO as a Project Engineer and spent the next three decades working with TEPPCO and successor entities in various engineering, transportation, and operations roles. At the end of 2006, Enterprise bought TEPPCO’s General Partner from Duke Energy Field Services, at which time Mr. Mallett was serving as SVP of Operations for TEPPCO. Post-merger, Mr. Mallett was named SVP-Environmental, Health and Safety. Mr. Mallett holds a Bachelor of Science in Mechanical Engineering from Prairie View A&M University and a Master of Business Administration from Houston Baptist University. Marc D. Stratton has been the Executive Vice President and Chief Financial Officer of our 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 Company including, Senior Vice President of Finance, Treasurer and Head of Investor Relations. Prior to joining the Company, Mr. Stratton served as a midstream infrastructure investment analyst at ING Investment Management and, prior to that, as Vice President of Project Finance at SunTrust Robinson Humphrey. Mr. Stratton has over 17 years of oil and gas industry experience in corporate finance and holds a bachelor’s degree in Economics from Denison University. 167 Table of Contents Brock M. Degeyter has been the Executive Vice President, General Counsel and Chief Compliance Officer of our General Partner since March 2015. Previously, he served as Senior Vice President and General Counsel from January 2012 until March 2015. Mr. Degeyter has been the Chief Compliance Officer of our General Partner since January 2014. Mr. Degeyter also served as Secretary of our General Partner from May 2012 until February 21, 2019. Prior to joining Summit Investments, Mr. Degeyter worked in the corporate legal department for Energy Future Holdings (formerly TXU Corp.) from January 2007 through December 2011 where he served as Director of Corporate Governance and Senior Counsel. Prior to joining Energy Future Holdings, Mr. Degeyter was engaged in private practice with the firm of Correro Fishman Haygood Phelps Walmsley & Casteix LLP from May 2002 through December 2006. Mr. Degeyter is licensed to practice law in the states of Texas and Louisiana. Mr. Degeyter received a B.A. in Political Science from Louisiana State University and a J.D. from Loyola University College of Law in New Orleans. Louise E. Matthews has been Executive Vice President and Chief Administration Officer since February 21, 2019. Previously, she served as Senior Vice President, Human Resources and Corporate Communications from March 2016 to February 2019, and Vice President, Human Resources from May 2013 to March 2016. Prior to joining our General Partner, Ms. Matthews served as Senior Vice President at SunTrust Bank (“SunTrust”) from November 2010 to May 2013, leading the Human Resources organization supporting Enterprise Technology and Operations for all segments, including Wholesale, Investment Banking, Retail and Corporate Functions. While with SunTrust, Ms. Matthews also served as a certified executive coach. Prior to her time at SunTrust, Ms. Matthews served as Vice President of Human Resources with ING Investment Management. Ms. Matthews has also served as HR Director for Sprint, Integrated Health Services and Jekyll Island Authority. Ms. Matthews earned her Master of Business Administration and Bachelor of Business Administration from Georgia Southern University. Ms. Matthews intends to resign from her position as an executive officer of the General Partner and terminate her employment with the Company effective April 30, 2020. Matthew F. Delaney has served as a director of our General Partner since May 2016 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls Summit Investments, the sole owner of SMP Holdings, the entity that owns and controls our General Partner. Mr. Delaney has been an investment professional at Energy Capital Partners since 2011. Prior to joining Energy Capital Partners, Mr. Delaney worked in the Investment Banking Division at Morgan Stanley focusing on energy mergers and acquisitions. Mr. Delaney received a B.A. in Economics from Amherst College. Mr. Delaney was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry, and his financial and business expertise. Lee Jacobe has served as a director of our General Partner since April 2019. 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. 168 Table of Contents Peter Labbat has served as a director of our General Partner since August 2016 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls Summit Investments, the sole owner of SMP Holdings, the entity that owns and controls our General Partner. Mr. Labbat is Managing Partner of Energy Capital Partners and has been an investment professional at Energy Capital Partners since 2006. Prior to joining Energy Capital Partners, Mr. Labbat spent 13 years in Goldman Sachs’ Investment Banking Division. He currently serves on the boards of Triton Power Holdings Limited, Sendero Midstream Partners, LP, Next Wave Energy Partners, LP and NCSG Crane & Heavy Haul Corp. Mr. Labbat received a B.A. in Economics from Georgetown University and an M.B.A. from the Wharton School at the University of Pennsylvania. Mr. Labbat was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise. Thomas K. Lane has served as director of our General Partner since May 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls Summit Investments, the sole owner of SMP Holdings, the entity that owns and controls our General Partner. Additionally, Mr. Lane serves as the chair of the Compensation Committee. Mr. Lane has served on the board of WEC Energy Group since January 2020 and is Vice Chairman of Energy Capital Partners. He was previously a partner of Energy Capital Partners from 2005 to 2016. Prior to joining Energy Capital Partners, Mr. Lane worked for 17 years in the Investment Banking Division at Goldman Sachs. As a Managing Director at Goldman Sachs, Mr. Lane had senior-level coverage responsibility for electric and gas utilities, independent power companies and merchant energy companies throughout the United States. Mr. Lane received a B.A. in economics from Wheaton College and an MBA from the University of Chicago. Mr. Lane was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise. Jerry L. Peters has served as a director of our General Partner since September 2012. Additionally, Mr. Peters served as the chair of the Conflicts Committee of our General Partner until November 2012 and serves as the chair and financial expert of the Audit Committee of our 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. Scott A. Rogan has served as a director of our General Partner since February 2014 and was appointed to the board in connection with his affiliation with Energy Capital Partners. Mr. Rogan joined Energy Capital Partners as a principal in February 2014. For five years prior to joining Energy Capital Partners, Mr. Rogan was employed by Barclays Capital ("Barclays") as a Managing Director working in the investment banking division of the natural resources group. Prior to its merger with Barclays in 2008, Mr. Rogan worked for over 10 years in investment banking for Lehman Brothers. Mr. Rogan received a bachelor’s degree in business administration and a master’s degree in professional accounting from the University of Texas at Austin as well as a master’s degree in business administration from the University of Chicago. Mr. Rogan was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise. 169 Table of Contents Jeffrey R. Spinner has served as a director of our General Partner since November 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners. Mr. Spinner has been an investment professional at Energy Capital Partners since 2006. Prior to joining Energy Capital Partners, Mr. Spinner worked in the Natural Resources Investment Banking Group at Banc of America Securities. Mr. Spinner received a B.S. in Economics from Duke University. Mr. Spinner was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise. Robert M. Wohleber has served as a director of our General Partner since August 2013. 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. Code of Business Conduct and Ethics The Board of Directors has adopted a Code of Business Conduct and Ethics which sets forth SMLP’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 SMLP 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 SMLP 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 us to provide accurate and timely disclosure in our filings with the SEC and other public communications. The Code of Business Conduct and Ethics is publicly available on our 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 Woodlands office address given under the "Contact" section on our website. Corporate Governance Guidelines Our Corporate Governance Guidelines, which are available on our website under the “Corporate Governance” subsection of the “Investors” section at www.summitmidstream.com, provide guidelines for the governance of the Company. The Corporate Governance Guidelines specifically provide, among other things, that (i) Jerry L. Peters, as the chairman of our Audit Committee, shall preside over any executive sessions, and (ii) interested parties may communicate directly with our independent directors by submitting a specially marked envelope to the Secretary of our 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 our 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 our records, we believe that all directors, executive officers and persons who own more than 10% of our 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 10,714,285 common units to SMP Holdings on November 15, 2019. 170 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 three persons 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 our next three most highly compensated executive officers. The following describes the material components of our 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 (1) Steven J. Newby, former President and Chief Executive Officer (2) Leonard W. Mallett, Executive Vice President and Chief Operations Officer (3) Marc D. Stratton, Executive Vice President and Chief Financial Officer Brock M. Degeyter, Executive Vice President, General Counsel and Chief Compliance Officer Brad N. Graves, Executive Vice President and Chief Commercial Officer (4) Louise E. Matthews, Executive Vice President and Chief Administration Officer (1) Mr. Deneke was appointed President and Chief Executive Officer effective September 16, 2019. (2) Mr. Newby served as our President and Chief Executive Officer until his resignation effective February 21, 2019. Mr. Newby’s employment terminated effective February 28, 2019. (3) Mr. Mallett served as our President and Chief Executive Officer on an interim basis from February 21, 2019, the date of Mr. Newby’s resignation, until the appointment of Mr. Deneke effective September 16, 2019. (4) Mr. Graves’ employment terminated effective December 31, 2019. The NEOs are employees of Summit Investments and executive officers of our General Partner. Certain of the NEOs split their working time between SMLP's business and their responsibilities for Summit Investments and its affiliates other than us. Under the terms of our Partnership Agreement, our General Partner determines the portion of the NEOs' compensation that is allocated to us. The percentage of total compensation allocated to us in 2019 for each NEO is as follows: 100% for Mr. Deneke; 55% for Mr. Newby; 87.5% for Mr. Mallett; 75% for Mr. Stratton; 70% for Mr. Degeyter; 80% for Mr. Graves; and 95% for Ms. Matthews. The Compensation Committee provides oversight, administers and makes decisions regarding our 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 company culture and leadership competencies Align executives with the interests of our unitholders 171 Table of Contents 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 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. BDO USA L.L.P. served as Compensation Consultant until September 2019 when it was replaced by Willis Towers Watson. 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 on our CEO’s compensation as required. Based on market data which we use as a reference, we believe compensation of 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 2019 executive compensation consisted of publicly traded midstream companies with whom we compete for executive talent. The peer group comprised the following companies: Crestwood Equity Partners, LP DCP Midstream, LP Enable Midstream Partners, LP EQM Midstream Partners, LP Genesis Energy, LP Hess Midstream Partners, LP Noble Midstream Partners, LP NuStar Energy, LP Phillips 66 Partners LP SemGroup Corporation Tallgrass Energy, LP Targa Resources Corp. 172 Table of Contents 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 our compensation philosophy and competitive with the compensation for executive officers of the peer group companies. The Compensation Committee reviewed the compensation analysis to confirm that our compensation programs were supporting a competitive total compensation approach that emphasizes incentive-based compensation and appropriately rewards achievement of our objectives. For 2019, 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 (1) Heath Deneke (2) (3) President and Chief Executive Officer Marc D. Stratton Executive Vice President and Chief Financial Officer Brock M. Degeyter Executive Vice President, General Counsel and Chief Compliance Officer Brad N. Graves (4) Executive Vice President and Chief Commercial Officer Leonard W. Mallett (5) Executive Vice President and Chief Operations Officer Louise E. Matthews Executive Vice President and Chief Administration Officer Base Salary ($) 2019 Target Annual Bonus: Percent of Base Salary (%) 2019 Target LTIP Award: Percent of Base Salary (%) 2019 LTIP Target Award Value ($) 2019 Target Total Direct Compensation ($) 600,000 350,000 380,000 400,000 400,000 300,000 150 100 100 100 100 100 275 1,650,000 3,150,000 150 525,000 1,225,000 150 570,000 1,330,000 150 600,000 1,400,000 150 600,000 1,400,000 150 450,000 1,050,000 (1) Mr. Newby is omitted from this table because he resigned from his position as President and Chief Executive Officer effective February 21, 2019, before the Compensation Committee’s annual review and setting of the NEOs’ target total direct compensation. (2) Mr. Deneke was appointed President and Chief Executive Officer effective September 16, 2019. Because Mr. Deneke was hired after the Compensation Committee’s annual review of executive compensation, the Compensation Committee played no role in the determination of Mr. Deneke’s target total direct compensation in 2019. Instead, Mr. Deneke’s target total direct compensation was determined by the General Partner and is reflected in his employment agreement. (3) Although Mr. Deneke’s target annual bonus set forth in his employment agreement is 150% of his base salary, his employment agreement further provides that his 2019 bonus shall be prorated for the period of time he actually served as President and Chief Executive Officer in 2019. (4) Mr. Graves’ employment terminated effective December 31, 2019. (5) Mr. Mallett served as our President and Chief Executive Officer on an interim basis from February 21, 2019, the date of Mr. Newby’s resignation, until the appointment of Mr. Deneke effective September 16, 2019. 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, welfare and additional benefits. Base Salary. The base salaries for our NEOs are reviewed annually by the Compensation Committee. Base salaries for our NEOs have generally been set at levels deemed necessary to attract and retain individuals with superior talent. 173 Table of Contents The base salaries of our NEOs, a portion of which are allocated to and reimbursed by Summit Investments and its affiliates other than us, are set forth in the following table: Name and Principal Position Heath Deneke (1) President and Chief Executive Officer Steven J. Newby (2) President and Chief Executive Officer (former) Marc D. Stratton Executive Vice President and Chief Financial Officer Brock M. Degeyter Executive Vice President, General Counsel and Chief Compliance Officer Brad N. Graves (3) Executive Vice President and Chief Commercial Officer Leonard W. Mallett (4) Executive Vice President and Chief Operations Officer Louise E. Matthews Executive Vice President and Chief Administration Officer 2019 Base Salary ($) 600,000 612,000 350,000 380,000 400,000 400,000 300,000 (1) Mr. Deneke was appointed President and Chief Executive Officer effective September 16, 2019. (2) Mr. Newby served as our President and Chief Executive Officer until his resignation effective February 21, 2019. (3) Mr. Graves’ employment terminated effective December 31, 2019. (4) Mr. Mallett served as our President and Chief Executive Officer on an interim basis from February 21, 2019, the date of Mr. Newby’s resignation, until the appointment of Mr. Deneke effective September 16, 2019. 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 2019, the Compensation Committee established the 2019 annual bonus plan target opportunities as a percentage of base salary for our NEOs other than Mr. Deneke and Mr. Newby. The 2019 targets for Messrs. Stratton, Degeyter, Graves and Mallett and for Ms. Matthews were 100% of their base salaries. The Compensation Committee played no role in the determination of the 2019 annual bonus plan target opportunities for Mr. Deneke, who did not become an employee until September 16, 2019, or for Mr. Newby, who resigned as President and Chief Executive Officer prior to the Compensation Committee’s annual review and setting of the NEOs’ annual bonus plan target opportunities. 174 Table of Contents Name and Principal Position (1) Heath Deneke (2) (3) President and Chief Executive Officer Marc D. Stratton Executive Vice President and Chief Financial Officer Brock M. Degeyter Executive Vice President, General Counsel and Chief Compliance Officer Brad N. Graves (4) Executive Vice President and Chief Commercial Officer Leonard W. Mallett (5) Executive Vice President and Chief Operations Officer Louise E. Matthews Executive Vice President and Chief Administration Officer 2019 Target Annual Bonus: Percent of Base Salary (%) 2019 Target Bonus: Dollar Value ($) 150 100 100 100 100 100 900,000 350,000 380,000 400,000 400,000 300,000 (1) Mr. Newby is omitted from this table because he resigned from his position as President and Chief Executive Officer effective February 21, 2019, before the Compensation Committee’s annual review and setting of the NEOs’ target total direct compensation. (2) Mr. Deneke was appointed President and Chief Executive Officer effective September 16, 2019. Because Mr. Deneke was hired after the Compensation Committee’s annual review of executive compensation, the Compensation Committee had no role in the determination of Mr. Deneke’s target annual bonus in 2019. Instead, Mr. Deneke’s target annual bonus in 2019 was set by the terms of his employment agreement. (3) Mr. Deneke’s employment agreement provides that his 2019 bonus shall be prorated for the period of time he actually served as President and Chief Executive Officer in 2019. (4) Mr. Graves’ employment terminated effective December 31, 2019. (5) Mr. Mallett served as our President and Chief Executive Officer on an interim basis from February 21, 2019, the date of Mr. Newby’s resignation, until the appointment of Mr. Deneke effective September 16, 2019. 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 Messrs. Deneke, Stratton, Degeyter and Mallett and for Ms. Matthews, 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. Newby and Graves were approved by the Board and determined in accordance with their employment agreements, as further described below. In February 2020, the Compensation Committee and the Board of Directors reviewed the SLT Scorecards for 2019 and determined the level of achievement of each key factor. We exceeded two of our targets: our controllable expense metric and our health, safety, environmental and regulatory goals. We did not meet our adjusted EBITDA target or our distributable cash flow per unit target. These results yielded a calculated SLT Scorecard result of 54% 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. 175 Table of Contents The Board approved an annual bonus for Mr. Deneke equal to the target bonus set forth in his employment agreement, prorated for the period of time he served as CEO in 2019, or $300,000. Mr. Deneke’s annual bonus payout reflects his demonstrated leadership capabilities for the period of time he was employed by us in 2019, and the fact that he did not serve as Chief Executive Officer for the full year. Mr. Stratton’s annual bonus payout reflects consideration for the combined performance of the finance and accounting business units. Mr. Stratton was awarded 65% of his target annual bonus in 2019, or $227,500. Mr. Degeyter’s annual bonus payout reflects consideration for the performance of the legal business unit. Mr. Degeyter was awarded 65% of his target annual bonus in 2019, or $247,000. Mr. Mallett's annual bonus payout reflects consideration for the combined performance of the engineering, operations and health, safety, environmental and regulatory business units. Mr. Mallett was awarded 65% of his target annual bonus in 2019, or $260,000. Ms. Matthews’ annual bonus payout reflects consideration for the performance of the administration business unit, including human resources and information technology. Ms. Matthews was awarded 65% of her target annual bonus in 2019, or $195,000. In connection with their terminations, Messrs. Newby and Graves received prorated annual bonuses for 2019 pursuant to the terms of their employment agreements. Mr. Newby received a prorated annual bonus of $148,389 and Mr. Graves received a prorated annual bonus equal to $400,000. Only a portion of the annual bonus amounts are allocated to and reimbursed by the Partnership. For a discussion of the cost allocation methodology, please refer to "Reimbursement of Expenses from General Partner" in Item 13. Certain Relationships and Related Transactions, and Director Independence. Based on the foregoing discussion, the annual bonus awards to be paid in March 2020 to our NEOs for 2019 performance are as follows: Name and Principal Position Heath Deneke President and Chief Executive Officer Steven J. Newby (1) Former President and Chief Executive Officer Marc D. Stratton Executive Vice President and Chief Financial Officer Brock M. Degeyter Executive Vice President, General Counsel and Chief Compliance Officer Brad N. Graves (1) Executive Vice President and Chief Commercial Officer Leonard W. Mallett (2) Executive Vice President and Chief Operations Officer Louise E. Matthews Executive Vice President and Chief Administration Officer 2019 Annual Bonus Payout ($) 300,000 148,389 227,500 247,000 400,000 260,000 195,000 (1) The amounts reflected are prorated annual bonuses paid to Messrs. Newby and Graves upon their terminations in accordance with their employment agreements. Mr. Newby resigned from his position as President and Chief Executive Officer effective February 21, 2019 and his employment terminated on February 28, 2019. Mr. Graves’ employment terminated on December 31, 2019. In addition to his annual bonus reflected in the table above, in March 2019 Mr. Mallett received a one-time bonus of $100,000 for his service as President and Chief Executive Officer on an interim basis between the resignation of Mr. Newby and the appointment of Mr. Deneke. (2) 176 Table of Contents Long-Term Equity-Based Compensation Awards. Our General Partner approved the SMLP LTIP pursuant to which eligible officers (including the NEOs), employees, consultants and directors of our 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 SMLP's 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 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 150% of base salary for Messrs. Stratton, Degeyter, Graves and Mallett, and for Ms. Matthews. Pursuant to his employment agreement, Mr. Deneke’s target equity award for 2019 was 275% of his base salary. Mr. Newby was not granted an LTIP award in 2019. Although LTIP is usually granted once per fiscal year, on or about March 15th, in 2019 there were three separate equity grants, described below: March 2019 Equity Grants. Effective March 15, 2019, based on the recommendation of the Compensation Committee, the Board of Directors approved a grant of phantom units to Messrs. Stratton, Degeyter, Graves and Mallet and to Ms. Matthews. The underlying phantom units vest ratably over a three-year period. Holders of phantom units 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. 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 16, 2019 Equity Grant to Mr. Deneke. As an inducement to accept the position of President and Chief Executive Officer of the Company, on September 16, 2019 Mr. Deneke received a one-time grant of phantom units valued at $4,000,000, 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 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. November 15, 2019 “Off-Cycle” Equity Grants to Certain NEOs. On November 15, 2019, as a retention incentive for continued employment with the Partnership, Messrs. Degeyter, Stratton, and Mallett, and Ms. Matthews received an additional grant of 50,000 phantom units with a fair market value of $193,500. The phantom units will “cliff vest” on November 15, 2022, subject to continued employment and accelerated vesting as provided in the applicable award agreement. All SMLP LTIP grants to our NEOs are subject to accelerated vesting on the occurrence of any of the following events: (i) a termination of the NEO's employment other than for cause, (ii) a termination of the NEO's employment by the officer for good reason (as defined in the NEO's employment agreement), (iii) a termination of the NEO's employment by reason of the NEO's death or disability or (iv) a Change in Control (as defined in the applicable award agreement). 177 Table of Contents To calculate the number of phantom units granted to each eligible NEO in March 2019, the Compensation Committee determined the dollar amount of the long-term incentive compensation award, and then granted the number of phantom units that had a fair market value equal to that amount as of market close on the date of the grant. The same calculation was performed with respect to the September 16, 2019 grant to Mr. Deneke except the dollar amount was determined by Partnership management. With respect to the November 15, 2019 grant to certain NEOs, Partnership management determined the number of phantom units to be granted. Phantom unit awards granted in 2019 were as follows: 2019 Target LTIP Award: Percent of Base Salary (%) 2019 Phantom Units Awarded (#) (2) 2019 SMLP LTIP Award Value ($) Name and Principal Position Heath Deneke (1) President and Chief Executive Officer Marc D. Stratton Executive Vice President and Chief Financial Officer Brock M. Degeyter Executive Vice President, General Counsel and Chief Compliance Officer Brad N. Graves Executive Vice President and Chief Commercial Officer Leonard W. Mallett Executive Vice President and Chief Operations Officer Louise E. Matthews Executive Vice President and Chief Administration Officer ___________ (1) Although Mr. Deneke’s employment agreement provides for a target LTIP award valued at 275% of his base salary, in 2019 the value of his initial one- time grant of phantom units was determined by the General Partner. 693,500 600,000 818,500 768,500 843,500 101,124 772,200 113,905 116,462 108,793 61,349 150 275 150 150 150 150 4,000,000 (2) Amount includes units granted on March 15, 2019 and, as discussed above in this section, September 16, 2019 and November 15, 2019 with respect to certain NEOs. Retirement, Health and Welfare and Additional Benefits. The NEOs are eligible to participate in such employee benefit plans and programs as 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 2019, 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 2019, Summit Investments made tax-free HSA contributions of $1,680 to Mr. Graves, $1,575 to Mr. Stratton and $1,995 to Ms. Matthews. Deferred Compensation Plan. Effective July 1, 2013, the Board approved a Deferred Compensation Plan (the “DCP”), which is a defined contribution supplemental executive retirement plan established to attract and retain key employees and directors by providing participants with an opportunity to defer receipt of a portion of their salary, bonus and other specified compensation. The DCP is an unfunded, nonqualified plan that provides each participant in the plan with benefits based on the participant’s notional account balance at the time of retirement or termination. Each participant allocates deferrals among designated mutual fund investments to serve as indices for the purpose of determining notional investment gains and losses to each participant’s account. 178 Table of Contents Deferrals of SMLP LTIP grants and other equity-based awards are allocated to the Summit Midstream Partners, LP Unit Fund (the “Unit Fund”). The Unit Fund consists of notional common units in SMLP, with each unit approximating the value of one common unit of SMLP. The distribution equivalent rights associated with any SMLP LTIP grant may be allocated to any available investment option, other than the Unit Fund. The DCP is filed as Exhibit 4.3 to the Partnership’s Form S-8 Registration Statement dated June 28, 2013. 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 YPO. 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 Investments (the “Company”). 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 16, 2019, has an initial term that expires on September 16, 2021, 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 the Company 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 the Company, by the Company 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 of the Company or the General Partner, or (v) any other action or inaction that constitutes a material breach of the employment agreement by the Company (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. 179 Table of Contents 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, the Company may choose to subject him to a non-competition covenant for up to one year post- termination. If the Company exercises 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 the Company) 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, the Company 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. Mr. Deneke’s employment agreement also provides that all equity awards granted to him under the LTIP and held by him as of immediately prior to a change in control of the Company will become fully vested immediately prior to the change in control. Mr. Deneke’s employment agreement provides that, if any portion of the payments or benefits provided to Mr. Deneke would be subject to the excise tax imposed under Section 4999 of the Internal Revenue Code, then the payments and benefits will be reduced if such reduction would result in a greater after-tax payment to Mr. Deneke. Additionally, as an inducement to accept the position of President and Chief Executive Officer of the Company, at the beginning of his employment term, Mr. Deneke received a one-time grant of phantom units valued at $4,000,000, pursuant to the Award Agreement. Subject to the terms and conditions of the 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) 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 (other than Mr. Newby’s) 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 Company exercises the “noncompete option” following a non-extension of the term by the NEO equal to 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 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 or the cost of an annual executive physical. Mr. Stratton’s base salary is $350,000, and the initial term of his employment agreement ends on March 31, 2021. Mr. Degeyter’s base salary is $380,000, and the initial term of his employment agreement ends on March 1, 2020. Mr. Graves’ base salary is $400,000, and the initial term of his employment agreement ended on March 1, 2019. 180 Table of Contents • • • Mr. Mallett’s base salary is $400,000, and the initial term of his employment agreement ends on March 1, 2020. Ms. Matthews’ base salary is $300,000 and the initial term of her employment agreement ends on March 31, 2021. Additionally, as an inducement to accept the position of Chief Operations Officer of the Company, on December 1, 2015, Mr. Mallett received a one-time grant of phantom units valued at $1,600,000, pursuant to a standalone phantom unit award agreement. The phantom units vested ratably over a three-year period, which concluded on December 1, 2018. Mr. Newby’s employment agreement is substantially similar to Mr. Deneke’s except for the following: • • It provides for a severance payment in the event the Company exercises the “noncompete option” following a non-extension of the term by Mr. Newby equal to the sum of his annual base salary and his or her annual bonus payable in respect of the immediately preceding year. It did not provide for a one-time grant of phantom units as an inducement to accept the position of President and Chief Executive Officer. Pursuant to his employment agreement, Mr. Newby was paid a cash severance payment upon his termination effective February 28, 2019, which was a “Qualifying Termination” under his employment agreement. In addition, Mr. Newby’s outstanding equity awards vested upon his termination. Retention Bonus Agreements. Effective June 7, 2019, Summit Investments, the General Partner, and SMLP jointly entered into retention bonus agreements with certain NEOs for the amounts indicated below: Mr. Mallett: $420,000 Mr. Degeyter: $400,000 Mr. Graves: $400,000 Mr. Stratton: $365,000 Ms. Matthews: $365,000 The agreements provide 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 terminate if the executive officer continues to be employed and a change in control has not occurred on or prior to December 31, 2020, provided that the termination date may be extended to December 31, 2021. 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 our management and, based on such review and discussion, has recommended to the Board that the CD&A be included in the Annual Report on Form 10-K. 181 Table of Contents Summary Compensation Table for 2019, 2018 and 2017 The following table sets forth certain information with respect to the compensation paid to our NEOs for the years ended December 31, 2019, 2018 and 2017 and allocated to us by our General Partner. Under the terms of our Partnership Agreement, our General Partner determines the portion of the NEOs' compensation that is allocated to us. 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. Name and Principal Position Heath Deneke (5) President and Chief Executive Officer Steven J. Newby (6) President and Chief Executive Officer (former) Marc D. Stratton (7) Executive Vice President and Chief Financial Officer Brock M. Degeyter Executive Vice President, General Counsel and Chief Compliance Officer Brad N. Graves Executive Vice President and Chief Commercial Officer Salary ($) (1) Year 2019 161,538 2019 89,328 2018 459,000 2017 540,000 2019 262,500 2018 231,782 2019 266,000 2018 335,700 2017 346,750 2019 320,000 2018 368,150 Bonus ($) — — — — — — — — — — — 2017 390,000 Leonard W. Mallett (8) 2019 350,000 Executive Vice President and Chief Operations Officer 2018 364,800 2017 375,000 2019 285,000 Louise E. Matthews (9) Executive Vice President and Chief Administration Officer — 87,500 — — — (1) Amounts shown represent the portion of the NEO's base salary allocated to SMLP. Equity Awards ($) (2) 4,000,000 — 1,550,000 1,950,000 768,500 225,000 818,500 625,000 700,000 600,000 625,000 700,000 843,500 625,000 700,000 693,500 Non-Equity Incentive Plan Compensation ($) (3) All Other Compensation ($) (4) 300,000 28,822 Total ($) 4,490,360 81,614 688,500 769,500 170,625 254,625 172,900 352,800 342,000 320,000 368,150 375,000 227,500 364,800 375,000 185,250 1,713,791 34,487 36,918 28,800 31,700 26,938 1,884,733 2,731,987 3,296,418 1,230,425 743,107 1,284,338 33,980 1,347,480 34,983 32,100 1,423,733 1,272,100 38,114 1,399,414 39,438 12,895 13,773 14,624 35,197 1,504,438 1,521,395 1,368,373 1,464,624 1,198,947 (2) Amounts shown reflect the grant date fair value of the phantom unit awards granted to the NEOs in 2019, 2018 and 2017, 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 14 to the consolidated financial statements. For additional information, please refer to "Components of Executive Compensation—Long-Term Equity-Based Compensation Awards" above. (3) Amounts shown represent the incentive bonus earned under our 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. (4) The table below presents the components of "All Other Compensation" allocated to SMLP for each NEO for the fiscal year ended December 31, 2019. For additional information, please see "Components of Executive Compensation—Retirement, Health and Welfare and Additional Benefits" above. (5) Mr. Deneke began his employment with the Company effective September 16, 2019. (6) Mr. Newby resigned from his position as our President and Chief Executive Officer effective February 21, 2019 and his employment terminated on February 28, 2019. The portion of the severance payment made to Mr. Newby in 2019 is included in the “All Other Compensation” column. (7) Mr. Stratton was appointed Executive Vice President and Chief Financial Officer effective December 7, 2018. Mr. Stratton was not an NEO prior to his appointment. 182 Table of Contents (8) In addition to his equity and non-equity incentive plan awards, Mr. Mallett received a one-time cash bonus of $100,000 relating to his service as our President and Chief Executive Officer during the period between the resignation of Mr. Newby and the appointment of Mr. Deneke. A portion of this bonus has been allocated to us and is included in the “Bonus” column. (9) Ms. Matthews was not an NEO before 2019. 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 29, 2017, due to a change in our employee population that we reasonably believe would result in a significant change to our pay ratio disclosure, we identified a new median employee in 2019. For 2019, we determined our median employee by ranking our employees (other than the CEO) employed as of December 31, 2019 (the “determination date”) by the sum of each employee’s annualized base salary, his or her actual cash bonus received in 2019 for 2018 performance, and his or her actual overtime pay received in 2019. 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 of our median employee (other than the CEO) for 2019 was $91,403. 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 2019 as set forth in the Summary Compensation Table above except that we annualized his compensation. Accordingly, for purposes of this disclosure, we determined that the CEO’s annual total compensation for 2019 that was allocated to us by our General Partner was $5,235,055. Based on the foregoing, our estimate of the ratio of the annual total compensation of our CEO to the median of the annual total compensation of all other employees was 57.3 to 1. Given the different methodologies that various public companies will use to determine an estimated pay ratio, our estimated pay ratio should not be used as a basis for comparison with ratios disclosed by other companies. All Other Compensation. The following table sets forth information concerning all other compensation paid to our NEOs in fiscal 2019 and allocated to us by our General Partner. Name Heath Deneke Steven J. Newby Marc D. Stratton Brock M. Degeyter Brad N. Graves Leonard W. Mallett Louise E. Matthews Medical Insurance Premium ($) 5,640 11,706 15,712 14,618 16,760 12,895 19,902 Individual Tax Preparation ($) 3,025 — 1,013 2,520 2,460 — — Health Savings Account (HSA) Employer Contributions ($) — — 1,575 — 1,680 — 1,995 183 401(k) Plan Employer Contributions ($) Membership Dues ($) Severance Paid in 2019 ($) 8,077 7,700 10,500 9,800 11,200 — 13,300 12,080 — — — — — — — 1,694,385 — — — — — Total ($) 28,822 1,713,791 28,800 26,938 32,100 12,895 35,197 Table of Contents Grants of Plan-Based Awards in 2019. The following table sets forth information concerning annual incentive awards and phantom unit awards granted to our NEOs in fiscal 2019. Name (1) Heath Deneke Marc D. Stratton Brock M. Degeyter Brad N. Graves Leonard W. Mallett Louise E. Matthews Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (2) Target Threshold ($) ($) 900,000 N/A Maximum ($) 1,800,000 N/A 350,000 700,000 N/A 380,000 760,000 N/A N/A 400,000 800,000 400,000 800,000 N/A 300,000 600,000 Grant Date N/A 9/16/2019 N/A 3/15/2019 11/15/2019 N/A 3/15/2019 11/15/2019 N/A 3/15/2019 N/A 3/15/2019 11/15/2019 N/A 3/15/2019 11/15/2019 All Other Stock Awards: Number of Shares of Stocks or Units (3) Grant Date Fair Value of Stock and Options Awards (4) (#) ($) 772,200 4,000,000 58,793 50,000 63,905 50,000 575,000 193,500 625,000 193,500 61,349 600,000 66,462 50,000 51,124 50,000 650,000 193,500 500,000 193,500 (1) Mr. Newby is omitted from this table. Due to his termination on February 28, 2019, Mr. Newby received no grants of phantom unit awards and did not participate in the non-equity incentive program in 2019. (2) Represents annual incentive opportunities that may be awarded pursuant to our annual incentive program for the year ended December 31, 2019 with payment based upon our achievement of pre-established performance goals and other factors. For additional information, please see "Components of Executive Compensation—Annual Incentive Compensation" above. (3) 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. (4) 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 14 to the consolidated financial statements. 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. 184 Table of Contents Outstanding Equity Awards at December 31, 2019. The following table presents information regarding the outstanding equity awards held by our NEOs at December 31, 2019. Name (1) Heath Deneke Marc D. Stratton Brock M. Degeyter Brad N. Graves Leonard W. Mallett Louise E. Matthews Unit Awards Number of Unearned Phantom Units That Have Not Vested (#) (2) Market Value of Unearned Phantom Units That Have Not Vested ($) (3) 772,200 50,000 58,793 9,836 3,111 50,000 63,905 27,322 10,370 61,349 27,322 10,370 50,000 66,462 27,322 10,370 50,000 51,124 9,398 2,962 2,555,982 165,500 194,605 32,557 10,297 165,500 211,526 90,436 34,325 203,065 90,436 34,325 165,500 219,989 90,436 34,325 165,500 169,220 31,107 9,804 Grant Date 9/16/2019 11/15/2019 3/15/2019 3/15/2018 3/15/2017 11/15/2019 3/15/2019 3/15/2018 3/15/2017 3/15/2019 3/15/2018 3/15/2017 11/15/2019 3/15/2019 3/15/2018 3/15/2017 11/15/2019 3/15/2019 3/15/2018 3/15/2017 (1) Mr. Newby is omitted from this table because his outstanding equity awards vested upon his termination without cause effective February 28, 2019. (2) Except for phantom units granted to certain NEOs on November 15, 2019, which vest in their entirety on the third anniversary of the grant date, phantom units granted to the NEOs vest ratably over a three-year period with the first tranche scheduled to vest on the first anniversary of the grant date, subject to continued employment, and accelerated vesting as provided in the applicable award agreement. The NEOs also receive distribution equivalent rights for each phantom unit, providing for a lump sum payment equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. (3) Amounts were calculated using the closing price of SMLP's publicly traded common units on December 31, 2019. Phantom Units Vested. The following table represents information regarding the vesting of phantom units during the year ended December 31, 2019 with respect to our NEOs. Name Heath Deneke Steven J. Newby Marc D. Stratton Brock M. Degeyter Brad N. Graves Leonard W. Mallett Louise E. Matthews ___________ Phantom Unit Awards Number of Phantom Units Vested (#) (1) — 198,777 12,302 38,650 38,650 37,526 11,599 Value Realized on Vesting ($) (1) — 2,858,293 175,419 557,990 557,990 539,242 165,036 (1) For NEOs other than Mr. Newby, the amounts represent the number and value of the phantom units that vested on March 15, 2019, plus the distribution equivalent rights earned in tandem. The value of the phantom units that vested on March 15, 2019 was calculated using the closing price of SMLP's publicly traded common units as of March 14, 2019, the trading day immediately prior to vesting. Mr. Newby’s amounts represent the number and value of the phantom units that vested upon his termination effective 185 Table of Contents February 28, 2019, plus the distribution equivalent rights earned in tandem. The value of Mr. Newby’s phantom units that vested on February 28, 2019 was calculated using the closing price of SMLP’s units as of February 27, 2019. Pension Benefits. Currently, our General Partner does not sponsor or maintain a pension or defined benefit program for our NEOs. This policy may change in the future. Nonqualified Deferred Compensation Table for 2019. The following table represents information regarding the nonqualified deferred compensation of our NEOs for the year ended December 31, 2019. Name Steven J. Newby Marc D. Stratton Brad N. Graves Executive Contributions in Last Fiscal Year ($) (1) Registrant Contributions in Last Fiscal Year ($) 124,422 — 3,898 — — — Aggregate Earnings in Last Fiscal Year ($) (440,052) 8,009 17,139 Aggregate Withdrawals / Distributions ($) (522,332) — — Aggregate Balance at Last Fiscal Year-End ($) 918,054 41,551 214,594 (1) Messrs. Newby and Graves’ executive contributions are comprised of quarterly distributions on previously deferred LTIP units. For additional information, see "Components of Executive Compensation—Retirement, Health and Welfare and Additional Benefits" above. 186 Table of Contents Potential Payments upon Termination or Change in Control. The following table sets forth information concerning potential amounts payable to the NEOs upon termination of employment under various circumstances, and upon a change in control, if such event took place on December 31, 2019. Name and Principal Position Heath Deneke President and Chief Executive Officer (3) Marc D. Stratton Executive Vice President and Chief Financial Officer (5) Brock M. Degeyter Executive Vice President, General Counsel and Chief Compliance Officer (5) Leonard W. Mallett Executive Vice President and Chief Operations Officer (5) Triggering Event Salary ($) 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 Company Nonextension of Term by Executive, Company Exercises Noncompete Change in Control (4) Termination by Reason of Death or Disability Termination Without Cause Resignation for Good Reason Nonextension of Term by Company Change in Control (4) Nonextension of Term by Executive, Company Exercises Noncompete Termination by Reason of Death or Disability Termination Without Cause Resignation for Good Reason Nonextension of Term by Company Change in Control (4) Nonextension of Term by Executive, Company Exercises Noncompete Termination by Reason of Death or Disability Termination Without Cause Resignation for Good Reason Nonextension of Term by Company Change in Control (4) — — 263,836 22,407 2,777,990 3,064,233 1,500,000 1,500,000 1,500,000 1,500,000 — 2,250,000 263,836 22,407 2,777,990 6,814,233 2,250,000 263,836 22,407 2,777,990 6,814,233 2,250,000 263,836 22,407 2,777,990 6,814,233 2,250,000 — — — 22,407 — — 2,777,990 3,772,407 2,777,990 — — 350,000 22,407 501,769 874,176 525,000 801,500 350,000 22,407 501,769 2,200,676 525,000 436,500 350,000 22,407 501,769 1,835,676 525,000 — 436,500 365,000 350,000 — 22,407 — 501,769 501,769 1,835,676 866,769 350,000 291,000 — 22,407 — 663,407 — — 380,000 22,341 699,956 1,102,297 570,000 988,000 380,000 22,341 699,956 2,660,297 570,000 588,000 380,000 22,341 699,956 2,260,297 570,000 — 588,000 400,000 380,000 — 22,341 — 699,956 699,956 2,260,297 1,099,956 380,000 392,000 — 22,341 — 794,341 — — 400,000 15,285 710,625 1,125,910 600,000 996,000 400,000 15,285 710,625 2,721,910 600,000 576,000 400,000 15,285 710,625 2,301,910 600,000 — 576,000 420,000 400,000 — 15,285 — 710,625 710,625 2,301,910 1,130,625 187 Table of Contents Louise E. Matthews Executive Vice President and Chief Administration Officer (5) Nonextension of Term by Executive, Company Exercises Noncompete Termination by Reason of Death or Disability Termination Without Cause Resignation for Good Reason Nonextension of Term by Company Change in Control (4) Nonextension of Term by Executive, Company Exercises Noncompete Termination Without Cause 400,000 384,000 — 15,285 — 799,285 — — 300,000 22,407 465,628 788,035 450,000 747,500 300,000 22,407 465,628 1,985,535 450,000 382,500 300,000 22,407 465,628 1,620,535 450,000 — 382,500 365,000 300,000 — 22,407 — 465,628 465,628 1,620,535 830,628 300,000 255,000 — 22,407 — 577,407 Steven J. Newby Former President and Chief Executive Officer (6) (7) Brad N. Graves Executive Vice President and Chief Commercial Officer (5) (7) ___________ (1) Where applicable, the amount includes the “Retention Bonus” payable to Messrs. Mallett, Degeyter, Graves, and Stratton upon a termination without Termination Without Cause 2,858,293 1,066,389 2,137,500 1,530,000 400,000 997,000 600,000 494,079 22,713 22,407 2,513,486 7,614,895 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, 2019. (3) Mr. Deneke’s employment agreement provides that upon termination of employment resulting from a non-extension of the term by Summit Investments, termination by Summit Investments 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 Summit Investments 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 Summit Investments) 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 of employment, Summit Investments 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. Degeyter’s, Mr. Mallett’s, Mr. Graves’ 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 Summit Investments 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 188 Table of Contents of termination through the expiration of the restricted period (as elected by Summit Investments) and the denominator of which is 365. (6) Mr. Newby’s employment agreement is substantially identical to Mr. Deneke’s with respect to potential payments upon termination or a change in control, except that in the event Summit Investments exercises the “noncompete option” after Mr. Newby elects not to extend the term, then he is entitled to a severance payment equal to the sum of his 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 Summit Investments) and the denominator of which is 365. (7) Both Mr. Newby and Graves were terminated without cause in 2019. Accordingly, disclosure is limited to the triggering event that actually occurred. In Mr. Newby’s case, the amounts reflect actual amounts. Compensation Committee Report The Compensation Committee provides oversight, administers and makes decisions regarding our compensation policies and plans. Additionally, the Compensation Committee generally reviews and discusses the Compensation Discussion and Analysis with senior management of our General Partner as a part of our governance practices. Based on this review and discussion, the Compensation Committee has recommended to the Board of Directors of our General Partner that the Compensation Discussion and Analysis be included in this report for filing with the SEC. . Thomas K. Lane Jeffrey R. Spinner Robert M. Wohleber Members of the Compensation Committee of Summit Midstream GP, LLC Director Compensation In 2019, under the director compensation plan, the independent directors, which include Messrs. Peters, Wohleber, and Jacobe, 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 $80,000. In addition, under the director compensation plan, the independent directors receive the following for their respective service on our Board's committees: • • • the chairman of the Audit Committee receives an additional annual retainer of $15,000; the chairman of the Conflicts Committee receives an additional annual retainer of $10,000; and each independent member of any committee (other than the chairman) received an additional annual retainer of $5,000. Messrs. Peters and Wohleber were paid their compensation in March 2019, whereas Mr. Jacobe was paid upon the commencement of his service on the Board in April 2019. 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 certain major transactions in 2019: • • • $25,000 to Mr. Wohleber and $20,000 to Mr. Peters for their work on the Equity Restructuring; $20,000 to Mr. Wohleber and $15,000 to Messrs. Peters and Jacobe for their work on the DPPO partial prepayment transaction; and $15,000 to Messrs. Wohleber and Peters for their work relating to certain additional contemplated transactions. Board members are reconsidered for appointment on the one-year anniversary of their most recent appointment. 189 Table of Contents We reimburse all directors, except for employees of Energy Capital Partners for travel and other related expenses in connection with attending board and committee meetings and board-related activities. We do not compensate employees of the Partnership or Energy Capital Partners for their services as directors. The following table shows the compensation paid, including amounts deferred, under our director compensation plan in 2019. Name Matthew F. Delaney Lee Jacobe Peter Labbat Thomas K. Lane Heath Deneke Jerry L. Peters Jeffrey R. Spinner Robert M. Wohleber Fees earned or paid in cash ($) Other fees ($) Unit awards ($) (1) Compensation deferred ($) (2) Total ($) — 105,000 — — — 150,000 — 160,000 — — — — — — — — — 80,000 — — — 80,000 — 80,000 — — — — — — — — — 185,000 — — — 230,000 — 240,000 (1) 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. (2) In 2019, no director elected to defer any portion of his compensation related to Board committee service. Compensation Committee Interlocks and Insider Participation Our Compensation Committee consists of Mr. Lane, Mr. Spinner and Mr. Wohleber. Although our common units are listed on the NYSE, we have 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 2019, 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 Summit Investments (and in connection therewith, SMLP) 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. Our 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. Also, Mr. Lane and Mr. Spinner were selected to serve on the Compensation Committee due to their affiliations with Energy Capital Partners, which controls our General Partner. 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 our 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 18, 2020); our General Partner; each of the directors and NEOs of our General Partner; and all of the directors and executive officers of our General Partner as a group. 190 Table of Contents 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 18, 2020, 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 93,613,194 common limited partner units outstanding as of February 18, 2020. 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 Summit Investments (1) (2) (3) SMP Holdings (2) (3) (4) Energy Capital Partners II, LLC (1) (3) (5) (6) SMLP Holdings, LLC (5) (6) Invesco Ltd. (7) Steven J. Newby (2) (9) J. Heath Deneke (2) (8) Brock M. Degeyter (2) (8) Brad N. Graves (2) (8) (9) Leonard W. Mallett (2) (8) Louise Matthews (2) Marc D. Stratton (2) (8) Matthew F. Delaney (5) Peter Labbat (5) Thomas K. Lane (5) (10) Jerry L. Peters (2) (9) Scott A. Rogan (11) Jeffrey R. Spinner (11) Robert M. Wohleber (2) James Lee Jacobe (2) All directors and executive officers as a group (consisting of 15 persons) Common Units Beneficially Owned 45,318,866 45,318,866 51,234,693 5,915,827 13,906,836 285,879 — 135,327 173,916 194,319 50,416 60,174 — 20,000 40,000 15,612 — — 27,310 9,580 1,012,533 Percentage of Common Units Beneficially Owned 48.4% 48.4% 54.7% 6.3% 14.9% * * * * * * * * * * * * * * An asterisk indicates that the person or entity owns less than one percent. (1) Summit Investments owns 100% of SMP Holdings, the entity that owns 100% of our General Partner. Energy Capital Partners II, LLC ("ECP II") and its parallel and co-investment funds (the "ECP Funds" and together with ECP II, "ECP") hold in the aggregate, 100% of the Class A membership interests in Summit Investments, the sole owner of SMP Holdings. ECP II is the General Partner of the General Partner of each of the ECP Funds that holds membership interests in Summit Investments and has voting and investment control over the securities held thereby. Accordingly, ECP may be deemed to indirectly beneficially own all of the common units held by Summit Investments and SMP Holdings as of February 18, 2020. (2) The address for this person or entity is 910 Louisiana Street, Suite 4200, Houston, TX. (3) Because of its ownership interest in Summit Investments, ECP is entitled to elect five directors of Summit Investments. In addition, Mr. Delaney (who is a principal of Energy Capital Partners), Mr. Labbat (who is a partner of Energy Capital Partners), Mr. Lane (who is Vice Chairman of Energy Capital Partners), Mr. Rogan (who is a principal of Energy Capital Partners) and Mr. Spinner (who is a principal of Energy Capital Partners) are each directors of our General Partner. Neither Mr. Delaney, Mr. Labbat, Mr. Lane, Mr. Rogan nor Mr. Spinner are deemed to beneficially own, and they disclaim beneficial ownership of, any common units held by our General Partner, Summit Investments or SMP Holdings. 191 Table of Contents (4) SMP Holdings owns 100% of our General Partner and 48.4% of our outstanding common units. Given its ownership interest in Summit Investments, ECP may be deemed to indirectly beneficially own all of the common units held by SMP Holdings as of February 18, 2020. (5) The address for this person or entity is 51 John F. Kennedy Parkway, Suite 1250, Short Hills, NJ 07078. (6) Energy Capital Partners II, LP and certain of its parallel funds (collectively, the "SMLP Holdings Owners") collectively hold all of the membership interests in SMLP Holdings, LLC ("SMLP Holdings"). ECP II indirectly controls the SMLP Holdings Owners. Accordingly, ECP II and the SMLP Holdings Owners may be deemed to indirectly beneficially own all of the common units held by SMLP Holdings. (7) The address for this person or entity is 1555 Peachtree Street NE, Suite 1800, Atlanta, GA 30309. (8) Includes common units which the individuals have the right to acquire upon vesting of phantom units, where the units are issuable as of February 18, 2020 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. (9) Excludes vested units for which receipt has been deferred into our Deferred Compensation Plan. (10) Includes 20,000 common units held by Lane Ventures LLC ("Lane Ventures"). Two of Mr. Lane's estate planning trusts collectively own a majority of the membership interests in Lane Ventures and as a result, Mr. Lane may be deemed to indirectly beneficially own the common units held by Lane Ventures. (11) The address for this person or entity is 1000 Louisiana, Suite 5200, Houston, Texas 77002. Securities Authorized for Issuance Under Equity Compensation Plans The following table provides information as of December 31, 2019 with respect to the Partnership's common units that may be issued under the 2012 Long-Term Incentive Plan. Plan category Equity compensation plans approved by security holders Equity compensation plans not approved by security holders Total Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) Weighted-average exercise price of outstanding options, warrants and rights (b) n/a n/a — 1,277,309 n/a 1,277,309 Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) (1) 2,105,995 n/a 2,105,995 (1) Amount shown represents phantom unit awards outstanding under the SMLP LTIP at December 31, 2019. 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, our General Partner approved the SMLP LTIP, pursuant to which eligible officers, employees, consultants and directors of our General Partner and its affiliates are eligible to receive awards with respect to our equity interests. The SMLP LTIP is designed to promote our interests, as well as the interests of our unitholders, by rewarding eligible officers, employees, consultants and directors for delivering desired performance results, as well as by strengthening our ability to attract, retain and motivate qualified individuals to serve as directors, consultants and employees. A total of 5,000,000 common units was reserved for issuance, pursuant to and in accordance with the SMLP LTIP. The SMLP LTIP is administered by 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. 192 Table of Contents Common units to be delivered with respect to awards may be newly issued units, common units acquired by us or our General Partner in the open market, common units already owned by our General Partner or us, common units acquired by our General Partner directly from us 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 date it was initially adopted by our General Partner. 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. Of the 93,493,473 common units outstanding at December 31, 2019, Summit Investments beneficially owned 45,318,866 common units and a subsidiary of Energy Capital Partners directly owned 5,915,827 common units. In addition, SMP Holdings owns and controls our General Partner. Distributions and Payments to our General Partner and its Affiliates The following summarizes the distributions and payments to be made by us to our General Partner and its affiliates in connection with our ongoing operations and our 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 Payments to our General Partner and its affiliates. See "Agreements with Affiliates—Reimbursement of Expenses from General Partner" below. Liquidation Stage Upon our liquidation, our partners, including our General Partner, will be entitled to receive liquidating distributions according to their particular capital account balances. Agreements with Affiliates We have various agreements with certain of our 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. Under our Partnership Agreement, we reimburse our General Partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our General Partner's employees and executive officers who perform services necessary to run our business. Our Partnership Agreement provides that our General Partner will determine in good faith the expenses that are allocable to us. Operation and maintenance expenses incurred by the General Partner and reimbursed by us under our Partnership Agreement were $28.6 million in 2019. General and administrative expenses incurred by the General Partner and reimbursed by us under our Partnership Agreement were $32.2 million in 2019. As of December 31, 2019, we had a payable of $0.3 million to the General Partner for expenses that were paid on our behalf. Expense Allocations. 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 participate 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. 193 Table of Contents 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 $120,000, 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 Although most companies listed on the New York Stock Exchange are required to have a majority of independent directors serving on the board of directors of the listed company, the New York Stock Exchange does not require a listed limited partnership like us to have, and we do not intend to have, a majority of independent directors on the Board of Directors. 194 Table of Contents Item 14. Principal Accounting Fees and Services. Our 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, 2019. Audit Fees. The fees billed by Deloitte & Touche LLP, as principal accountant, for the audit of our consolidated financial statements and other services rendered for the years ended December 31, 2019 and 2018 follow. Audit fees (1) Audit-related fees (2) Tax fees (3) All other fees Total Year ended December 31, 2019 2018 $ $ 1,654,404 20,000 469,276 — 2,143,680 $ $ 1,747,000 75,500 473,130 — 2,295,630 (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 our At-the-market Program (see Note 12 to the consolidated financial statements). (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. 195 Table of Contents PART IV Item 15. Exhibits, Financial Statement Schedules. (a)(1) Financial Statements Included in Part II, Item 8, of this report: Summit Midstream Partners, LP and Subsidiaries: Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets as of December 31, 2019 and 2018 Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017 Consolidated Statements of Partners' Capital for the years ended December 31, 2019, 2018 and 2017 Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017 Notes to Consolidated Financial Statements (2) Financial Statement Schedules 109 110 111 112 113 115 All schedules are omitted because the required information is inapplicable or the information is presented in the financial statements or the notes thereto. SEC Rule 3-09 of Regulation S-X ("Rule 3-09") requires that we include or incorporate by reference financial statements for OGC in this Form 10-K if our investment was considered to be significant for the year ended December 31, 2019. We have concluded that OGC is significant. As such, the following documents are incorporated herein by reference: • The audited balance sheets of OGC as of December 31, 2019 and 2018 and the related statements of operations, members' equity and cash flows for the years ended December 31, 2019, 2018 and 2017 and the related notes to the financial statements, are filed as Exhibit 99.1 to this Report. (3) Exhibit Index An “Exhibit Index” has been filed as part of this Report included below and is incorporated herein by this reference. Schedules other than those listed above are omitted because they are not required, are not material, are not applicable, or the required information is shown in the financial statements or notes thereto. In reviewing the agreements included as exhibits to this annual report, please remember they are included to provide information regarding their terms and are not intended to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and: • • • • should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate; have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement; may apply standards of materiality in a way that is different from what may be viewed as material by others; and were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. 196 Table of Contents Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. (b) Exhibit Index Exhibit number 3.1 Description Third Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated as of March 22, 2019 (Incorporated herein by reference to Exhibit 3.1 to SMLP's Current Report on Form 8-K dated March 22, 2019 (Commission File No. 001-35666)) Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated as of October 3, 2012 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K dated October 4, 2012 (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)) 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)) 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)) 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)) 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)) 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)) First Amendment to the Third Amended and Restated Credit Agreement dated as of September 22, 2017 197 3.2 3.3 3.4 4.1 4.2 10.2 10.3 10.4 10.5 10.6 10.7 10.8 10.9 Table of Contents 10.10 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 Current Report on Form 10-Q dated August 9, 2019 (Commission File No. 001-35666)) 10.11 *** 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 10.12 *** Amended and Restated Limited Liability Company Agreement of Summit Permian Transmission Holdco, LLC, dated as of December 24, 2019 10.13 10.14 10.15 10.16 10.17 10.18 10.19 10.20 10.21 10.22 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)) 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)) 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)) 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)) 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)) 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)) 10.23 * 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)) 198 Table of Contents 10.24 * Amendment No. 1 to Amended and Restated Employment Agreement by and between Summit Midstream Partners LLC and Brock M. Degeyter, effective January 23, 2018 (Incorporated herein by reference to Exhibit 10.1 to SMLP's Form 8-K filed February 24, 2016 (Commission File No. 001-35666)) 10.25 * Employment Agreement, effective January 1, 2019, by and between Summit Midstream Partners, LLC and Marc D. Stratton (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Form 8-K dated January 2, 2019 (Commission File No. 001-35666)) 10.26 * 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)) 10.27 * 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)) 10.28 * 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)) 10.29 * Summit Midstream Partners, LP 2012 Long-Term Incentive Plan (Incorporated herein by reference to Exhibit 10.2 to SMLP's Current Report on Form 8-K filed October 4, 2012 (Commission File No. 001-35666)) 10.30 * 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)) 10.31 * 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)) 10.32 * 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)) 10.33 * 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 (File No. 333-189684)) 21.1 23.1 23.2 31.1 31.2 32.1 List of Subsidiaries 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 104 ** Inline XBRL Taxonomy Extension Presentation Linkbase 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 199 Table of Contents † 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. 200 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 9, 2020 /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 Director, President and Chief Executive Officer (Principal Executive Officer) Date March 9, 2020 /s/ Heath Deneke Heath Deneke /s/ Marc D. Stratton Marc D. Stratton /s/ Matthew F. Delaney Matthew F. Delaney /s/ Lee Jacobe Lee Jacobe /s/ Peter Labbat Peter Labbat /s/ Thomas K. Lane Thomas K. Lane /s/ Jerry L. Peters Jerry L. Peters /s/ Scott A. Rogan Scott A. Rogan /s/ Jeffrey R. Spinner Jeffrey R. Spinner /s/ Robert M. Wohleber Robert M. Wohleber Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) March 9, 2020 Director Director Director Director Director Director Director Director 201 March 9, 2020 March 9, 2020 March 9, 2020 March 9, 2020 March 9, 2020 March 9, 2020 March 9, 2020 March 9, 2020 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 THIRD AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT AND SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GUARANTEE AND COLLATERAL AGREEMENT EXHIBIT 10.11 Execution Version THIS THIRD AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT AND SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GUARANTEE AND COLLATERAL AGREEMENT (this “Amendment”), dated as of December 24, 2019, is made by and among SUMMIT MIDSTREAM HOLDINGS, LLC, a limited liability company organized under the laws of Delaware (the “Borrower”), each of the other Loan Parties party hereto, WELLS FARGO BANK, NATIONAL ASSOCIATION, as administrative agent (in such capacity, together with its successors in such capacity, the “Administrative Agent”) and collateral agent (in such capacity, together with its successors in such capacity, the “Collateral Agent”) under the hereinafter-defined Credit Agreement, and the Lenders party hereto. W I T N E S S E T H: WHEREAS, the Borrower, the Administrative Agent, the Collateral Agent, the lenders from time to time party thereto (the “Lenders”) and the other parties from time to time party thereto have entered into that certain Third Amended and Restated Credit Agreement, dated as of May 26, 2017 (as amended by that certain First Amendment to Third Amended and Restated Credit Agreement, dated as of September 22, 2017, that certain Second Amendment to Third Amended and Restated Credit Agreement and First Amendment to Second Amended and Restated Guarantee and Collateral Agreement, dated as of June 26, 2019, and as further amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”); WHEREAS, the Borrower, the other Loan Parties party thereto from time to time and the Collateral Agent have entered into that certain Second Amended and Restated Guarantee and Collateral Agreement, dated as of May 26, 2017 (as amended by that certain Second Amendment to Third Amended and Restated Credit Agreement and First Amendment to Second Amended and Restated Guarantee and Collateral Agreement, dated as of June 26, 2019 and as further amended, restated, amended and restated, supplemented or otherwise modified from time to time, the “Collateral Agreement”); WHEREAS, the Borrower has requested that the Lenders agree to make certain amendments to the Credit Agreement and the Collateral Agreement; and WHEREAS, the Lenders party hereto have agreed to such amendments on the terms and conditions set forth herein. NOW, THEREFORE, in consideration of the premises and the mutual agreements, representations and warranties herein set forth, and for other good and valuable consideration, the receipt and sufficiency of which are acknowledged, the Borrower, the other Loan Parties party hereto, the Collateral Agent, the Administrative Agent and the undersigned Required Lenders do hereby agree as follows: 1. (a) Amendments to Credit Agreement. Section 1.01 of the Credit Agreement is hereby amended as follows: (i) Each of the following definitions are amended and restated in their entirety as follows: “Double E Joint Venture Conditions” shall mean, (a) the Opt-In Time has occurred, (b) at all times in the relevant calculation period (for clauses (i), (ii) and (iii), other than prior to the Opt-In Time), (i) the Double E Joint Venture does not at any time incur or have, (x) in the aggregate, greater than U.S.$20.0 million of indebtedness for borrowed money or (y) material Liens other than Liens permitted by the limited liability company agreement of the Double E Joint Venture in existence on the Second Amendment Effective Date; provided that from and after the Opt-In Time no Loan Party, in its role as member or manager of the Double E Joint Venture, shall vote to approve any Lien on any assets of the Double E Joint Venture if the imposition or existence of such Lien would result in Liens approved pursuant to this proviso in excess of U.S.$20.0 million at any time on assets of the Double E Joint Venture in the aggregate, (ii) the Equity Interests of the Double E Joint Venture that are not owned by the Borrower or a Restricted Subsidiary have no preferential rights to dividends or other distributions over the Equity Interests owned by the Borrower or a Restricted Subsidiary (other than any preferential rights to dividends or other distributions set forth in the Double E LLC Agreement as in effect on the Second Amendment Effective Date), (iii) the Borrower’s and each applicable Restricted Subsidiary’s Equity Interests in the Double E Joint Venture are pledged in accordance with the Collateral and Guarantee Requirement and (iv) the Borrower or a Restricted Subsidiary shall own Equity Interests in the Double E Joint Venture sufficient to retain negative control with respect to matters requiring Required Approval (as defined in the Double E LLC Agreement as in effect on the Second Amendment Effective Date) (but in no event to be less than a 20% Percentage Interest (as defined in the Double E LLC Agreement as in effect on the Second Amendment Effective Date)) and (c) none of the Borrower or any Restricted Subsidiary has taken any action that would result in a breach of Section 6.09(f) on or after the Opt-In Time. “Non-Recourse Debt” shall mean Indebtedness (a) as to which neither the Borrower nor any of its Restricted Subsidiaries 2 (ii) (i) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (ii) is directly or indirectly liable as a guarantor or otherwise or (iii) constitutes the lender; (b) no default with respect to which (including any rights that the holders of such Indebtedness may have to take enforcement action against an Unrestricted Subsidiary) would permit, upon notice, lapse of time or both, any holder of any other Indebtedness of the Borrower or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment of the Indebtedness to be accelerated or payable prior to its stated maturity; and (c) as to which the lenders of such Indebtedness have been notified in writing that they will not have any recourse to the Equity Interests or other Property of the Borrower or its Restricted Subsidiaries; provided, that the Borrower or any Restricted Subsidiary may pledge the Equity Interests it owns in any Subsidiary that is not (x) a Restricted Subsidiary, (y) an Included Entity or (z) from and after the Opt-In Time, the Double E Joint Venture, in order to secure such Indebtedness. By adding the following defined terms in appropriate alphabetical order: “Opt-In Conditions” means, as of the date of determination, that (i) the Double E Joint Venture does not have, (x) in the aggregate, greater than U.S.$20.0 million of indebtedness for borrowed money or (y) Liens other than Liens permitted by the limited liability company agreement of the Double E Joint Venture in existence on the Second Amendment Effective Date not in excess of U.S.$20.0 million in the aggregate, (ii) the Equity Interests of the Double E Joint Venture that are not owned by the Borrower or a Restricted Subsidiary have no preferential rights to dividends or other distributions over the Equity Interests owned by the Borrower or a Restricted Subsidiary (other than any preferential rights to dividends or other distributions set forth in the Double E LLC Agreement as in effect on the Second Amendment Effective Date), (iii) the Borrower’s and each applicable Restricted Subsidiary’s Equity Interests in the Double E Joint Venture are pledged in accordance with the Collateral and Guarantee Requirement, (iv) the Borrower or a Restricted Subsidiary shall own Equity Interests in the Double E Joint Venture sufficient to retain negative control with respect to matters requiring Required Approval (as defined in the Double E LLC Agreement as in effect on the Second Amendment Effective Date) (but in no event to be less than a 20% Percentage Interest (as defined in the Double E LLC Agreement as in effect on the Second Amendment Effective Date)), (v) the Double E Joint Venture’s relevant constitutional documents on such date, when compared against such documents as in effect on the Second Amendment Effective Date, do not contain any material amendments or 3 modifications adverse to the Lenders to (1) the Double E Joint Venture’s distribution policies, (2) the ability of the Double E Joint Venture to incur Indebtedness and Liens (other than to the extent permitted under the definition of “Double E Joint Venture Conditions”), (3) the ability of the Borrower or a Restricted Subsidiary to pledge the Equity Interests in the Double E Joint Venture as Collateral securing the Obligations, (4) the voting provisions in the Double E Joint Venture’s relevant constitutional documents (other than any amendment or modification thereto so long as the Borrower or a Restricted Subsidiary owns Equity Interests in the Double E Joint Venture sufficient to retain negative control with respect to matters requiring Required Approval (as defined in the Double E LLC Agreement as in effect on the Second Amendment Effective Date)) or (5) the change of control provisions in the Double E Joint Venture’s relevant constitutional documents, and (vi) each Subsidiary directly or indirectly owning Equity Interests in the Double E Joint Venture shall (1) be a Restricted Subsidiary and (2) become a Subsidiary Loan Party by joining the Collateral Agreement and otherwise causing the Collateral and Guarantee Requirement to be satisfied with respect to it. “Opt-In Time” means the time when a Responsible Officer of the Borrower certifies in writing to the Administrative Agent that the Opt-In Conditions are satisfied as of such time, which certificate shall be accompanied by reasonably detailed information demonstrating the satisfaction of the Opt-In Conditions. “Third Amendment” shall mean that certain 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, by and among the Borrower, the Subsidiary Loan Parties, the MLP Entity, the Administrative Agent, the Collateral Agent and the Lenders party thereto. amending and restating sub-clauses (c) and (d) thereof in its entirety as follows: (iii) The definition of “Collateral and Guarantee Requirement” in the Credit Agreement is amended by “(c) in the case of any Person that is required to become a Subsidiary Loan Party after the Restatement Date pursuant to Section 5.10(e) or the definition of “Opt-In Conditions”, the Collateral Agent shall have received a supplement to the Collateral Agreement, in the form specified therein, duly executed and delivered on behalf of such Person, on or before the date required in Section 5.10(e) or the Opt-In Time, as applicable;” 4 “(d) all Equity Interests of (i) each Loan Party (other than the MLP Entity), (ii) each Included Entity and (iii) each Ohio Joint Venture and, from and after the Opt-In Time, the Double E Joint Venture (in the case of this clause (iii), to the extent directly owned by any Loan Party) shall have been pledged (or shall be pledged concurrently with the actions making such Equity Interests subject to this provision) in accordance with the Collateral Agreement, except, in each case, to the extent that a pledge of such Equity Interests is not permitted under Section 9.21, and the Collateral Agent shall have received (or shall receive concurrently with the actions making such Equity Interests subject to this provision) all certificates or other instruments (if any) representing such Equity Interests, together with stock powers or other instruments of transfer with respect thereto endorsed in blank, or shall have otherwise received a security interest over such Equity Interests satisfactory to the Collateral Agent;” and restating clause (e)(iii) in its entirety as follows: (iv) The definition of “Consolidated Net Income” in the Credit Agreement is amended by amending “(iii) the Double E Joint Venture (such amount for such period is hereinafter referred to as the “Double E Joint Venture Distribution Amount”); provided, that (A) the inclusion of this clause (e) (iii) for such calculation period is subject to the final sentence in the definition of “EBITDA”, (B) the Double E Joint Venture Distribution Amount for any quarter shall include cash dividends, cash distributions and other payments paid in cash to (or converted into cash by) the Borrower or a Restricted Subsidiary pursuant to this clause (e)(iii) in respect of such period whether such amount was actually received during the period or thereafter, but only to the extent received prior to the date of calculation, and (C) (1) prior to the Opt-In Time, clause (b)(iv) of the definition of “Double E Joint Venture Conditions” shall be satisfied for such calculation period and (2) after the Opt-In Time, the Double E Joint Venture Conditions shall be satisfied for such calculation period; provided further, that in no event shall any distribution by the Double E Joint Venture of the Exxon Equity Option Price (as defined in the Double E LLC Agreement on the Second Amendment Effective Date) to the Borrower or any Restricted Subsidiary be included in Consolidated Net Income for any calculation period” restating clause (d) thereof in its entirety as follows: (v) The definition of “Unrestricted Subsidiary” in the Credit Agreement is amended by amending and “(d) that after giving effect to such designation, as to which (i) neither the Borrower nor any Restricted Subsidiary has or would have any direct or indirect obligation for any obligation or liability of such Unrestricted Subsidiary, and (ii) neither the Borrower nor any Restricted Subsidiary is required to maintain or preserve such Unrestricted Subsidiary’s financial condition or to cause such Person to achieve any specified levels of operating results, other 5 than, in the case of clauses (i) and (ii), Guarantees that are permitted under Section 6.01 and Section 6.04 by the Borrower or any Restricted Subsidiary of obligations of any Unrestricted Subsidiary and other than (except in the case of any Included Entity or, from and after the Opt-In Time, the Double E Joint Venture) the pledge by the Borrower or any Restricted Subsidiary of its Equity Interests in such Unrestricted Subsidiary to support Non-Recourse Debt of such Unrestricted Subsidiary.” (b) Section 5.10(g) of the Credit Agreement is hereby amended and restated in its entirety as follow: (g) In the case of any Loan Party, furnish to the Collateral Agent (A) prompt written notice of any change in such Loan Party’s corporate or organization name or organizational identification number or other change that may have an effect on the “know your customer”, U.S.A. PATRIOT ACT or Beneficial Ownership Regulation disclosures delivered in connection with this Agreement or any other Loan Document; (B) prior written notice of any change in such Loan Party’s identity or organizational structure; provided, that no Loan Party shall effect or permit any such change unless all filings have been made, or will have been made within any statutory period, under the UCC or otherwise that are required in order for the Collateral Agent to continue at all times following such change to have a valid, legal and perfected security interest in all the Collateral for the benefit of the Secured Parties; (C) promptly upon the request thereof, any change, to the Borrower’s knowledge, in the information provided in the Beneficial Ownership Certification delivered to the Administrative Agent or any Lender that would result in a change to the list of beneficial owners identified in such certification (or, if applicable, the Borrower ceasing to fall within an express exclusion to the definition of “legal entity customer” under the Beneficial Ownership Regulation), as from time to time reasonably requested by the Administrative Agent or any Lender; and (D) promptly upon reasonable request thereof, any information or documentation requested for purposes of complying with the Beneficial Ownership Regulation. (c) Section 6.09(f) of the Credit Agreement is hereby amended and restated as follows: “(f) From and after the Opt-In Time, to the extent adverse to the Lenders, consent to or vote in favor of material amendments or modifications to (i) the Double E Joint Venture’s distribution policies, (ii) the ability of the Double E Joint Venture to incur Indebtedness and Liens (other than to the extent permitted under the definition of “Double E Joint Venture Conditions”), (iii) the ability of the Borrower or a Restricted Subsidiary to pledge the Equity Interests in the Double E Joint Venture as Collateral securing the Obligations, (iv) the voting provisions in the Double E Joint Venture’s relevant constitutional documents (other than any amendment or modification thereto so long as the Borrower or a Restricted Subsidiary owns Equity Interests in the Double E Joint Venture sufficient to retain negative control with respect to matters requiring Required Approval (as defined in the Double E LLC Agreement as in effect on the Second Amendment Effective Date)) or (v) the change of control provisions in the Double E Joint Venture’s relevant constitutional documents.” 6 (d) Section 9.18(a) of the Credit Agreement is hereby amended and restated in its entirety as follows: “Section 9.18 Release of Liens and Guarantees. (a) In the event that (i) the Borrower or any Subsidiary Loan Party conveys, sells, leases, assigns, transfers or otherwise disposes of all or any portion of its assets (including the Equity Interests of any of its Subsidiaries) to a Person that is not (and is not required to become) a Loan Party in a transaction not prohibited by the Loan Documents (other than any sale or conveyance of any assets to Eddy County in connection with the IRB Transactions) or (ii) any Restricted Subsidiary becomes an Unrestricted Subsidiary (other than any Included Entity, any Ohio Joint Venture or, from and after the Opt-In Time, the Double E Joint Venture), then, in any of such cases, the Administrative Agent and the Collateral Agent shall promptly (and the Lenders hereby authorize the Administrative Agent and the Collateral Agent to) take such action and execute any such documents as may be reasonably requested by the Borrower and at the Borrower’s sole cost and expense to release any Liens created by any Loan Document in respect of such Equity Interests, Subsidiary Loan Party or assets that are the subject of such disposition, release any Liens created by any Loan Document in respect of Equity Interests of any Restricted Subsidiary that becomes an Unrestricted Subsidiary (other than any Included Entity, any Ohio Joint Venture or, from and after the Opt-In Time, the Double E Joint Venture) and release any Guarantees of the Obligations and release any Liens granted to secure the Obligations, in each case by a Person that ceases to be a Subsidiary of the Borrower or ceases to be a Subsidiary Loan Party as a result of a transaction described above. Any representation, warranty or covenant contained in any Loan Document relating to any such Equity Interests or assets shall no longer be deemed to be made once such Equity Interests or assets are so conveyed, sold, leased, assigned, transferred or disposed of. Any sale or conveyance of any assets to Eddy County in connection with the IRB Transactions shall be subject to all Liens thereon created under the Loan Documents, and such Liens created under the Loan Documents shall continue in effect after such sale or conveyance.” 2. Amendment to Collateral Agreement. Section 3.01 of the Collateral Agreement is amended by amending and restating clause (a)(ii) thereof in its entirety as follows: “(ii) any other Equity Interests owned in the future by such Pledgor and issued by the Borrower, a Subsidiary Loan Party, an Included Entity, an Ohio Joint Venture or, from and after the Opt-In Time, the Double E Joint Venture;” 3. Designation of Unrestricted Subsidiary. The Borrower hereby designates Summit Permian Transmission, LLC, a Delaware limited liability company, and Summit Permian Transmission Holdco, LLC, a Delaware limited liability company (“Transmission Holdco” and together, the “Permian Transmission Entities”), as Unrestricted Subsidiaries under the Credit Agreement (as hereby amended). Such designation complies with all requirements set forth in the definition of “Unrestricted Subsidiary” in the Credit Agreement, including that: (a) both before and after giving effect to such designation, no Default or Event of Default shall have occurred and be continuing; 7 (b) at the time of such designation, the Borrower or any of its Restricted Subsidiaries are permitted to make Investments pursuant to the terms of Section 6.04(a)(i) and 6.04(i) of the Credit Agreement (taken together) in an amount equal to the Investments previously made in the Permian Transmission Entities and that have not been repaid by the Permian Transmission Entities as dividends or distributions to any Loan Party; (c) the amount of such Investments previously made by the Borrower or any of its Restricted Subsidiaries in the Permian Transmission Entities during the period from the Restatement Date to the date hereof, and that have not been repaid via dividend or distribution to the Borrower or a Restricted Subsidiary, shall be included in the calculation of the aggregate amount of Investments permitted under Section 6.04(a)(i) and 6.04(i) of the Credit Agreement; (d) after giving effect to such designation, the Permian Transmission Entities will have no Indebtedness other than Non-Recourse Debt and Indebtedness that is guaranteed pursuant to Section 6.01(p) of the Credit Agreement; (e) except as not prohibited by Section 6.07 of the Credit Agreement, after giving effect to such designation neither Permian Transmission Entity is party to any transaction with the Borrower or any Restricted Subsidiary; and (f) after giving effect to such designation, (i) neither the Borrower nor any Restricted Subsidiary has or would have any direct or indirect obligation for any obligation or liability of the Permian Transmission Entities and (ii) neither the Borrower nor any Restricted Subsidiary is required to maintain or preserve the Permian Transmission Entities’ financial condition or to cause the Permian Transmission Entities to achieve any specified levels of operating results, other than, in the case of clauses (i) and (ii), Guarantees that are permitted under Sections 6.01 and 6.04 of the Credit Agreement by the Borrower or any Restricted Subsidiary of obligations of the Permian Transmission Entities. 4. Conditions Precedent. This Amendment shall become effective as of the date (the “Third Amendment Effective Date”) that each of the following conditions is satisfied (or waived by (a) Required Lenders and (b) each other Person required to consent to such waiver pursuant to and in accordance with Section 9.08 of the Credit Agreement): (a) The Administrative Agent (or its counsel) shall have received from the Borrower, the other Loan Parties party hereto and the Required Lenders either (x) an original counterpart of this Amendment signed on behalf of such party or (y) evidence satisfactory to the Administrative Agent (which may include a facsimile copy or PDF copy of each signed signature page) that such party has signed a counterpart of this Amendment. (b) The Administrative Agent shall have received, to the extent invoiced, all amounts due and payable pursuant to the Credit Agreement and Loan Documents on or prior to the Third Amendment Effective Date, including, to the extent invoiced, reimbursement or payment of all reasonable out-of-pocket expenses (including reasonable fees and expenses of Sidley Austin LLP, counsel to the Administrative Agent) that are required to be reimbursed or paid by the Borrower under the Credit Agreement, hereunder or under any Loan Document. 8 (c) The representations and warranties in Section 5 shall be true and correct in all material respects as of the date hereof. (d) The Administrative Agent shall have received evidence satisfactory to it that Transmission Holdco shall have closed, substantially concurrently herewith, the initial funding in a private placement transaction pursuant to which Transmission Holdco will create a new series of preferred units representing limited liability company interests in Transmission Holdco (the “Series A Preferred Units”) and, subject to certain terms and conditions to be set forth in the definitive documentation with respect to such contemplated transaction, issue and sell up to 140,000 Series A Preferred Units at a price of $1,000 per Series A Preferred Unit to a certain third party financial buyer. The Administrative Agent shall notify the Borrower and the Lenders of the Third Amendment Effective Date, and such notice shall be conclusive and binding absent manifest error. 5. Representations and Warranties. Each Loan Party represents and warrants to the Administrative Agent and each of the Lenders that: (a) all of the representations and warranties contained in the Credit Agreement and the other Loan Documents are true and correct in all material respects (except for any representation and warranty that is qualified by materiality or Material Adverse Effect, which such representation and warranty shall be true and correct in all respects) on and as of the date hereof except to the extent that such representations and warranties expressly relate solely to an earlier date in which case they shall have been true and correct in all material respects (except for any representation and warranty that is qualified by materiality or Material Adverse Effect, which such representation and warranty shall be true and correct in all respects) as of such earlier date, except that the representations and warranties contained in Section 3.05 of the Credit Agreement shall be deemed to refer to the most recent financial statements furnished pursuant to Sections 5.04(a) and (b) of the Credit Agreement, respectively; (b) any Loan Document; no Default or Event of Default has occurred and is continuing as of the date hereof under (c) this Amendment is within such Loan Party’s organizational powers and has been duly authorized by all necessary organizational action on the part of such Loan Party; (d) this Amendment has been duly executed and delivered by each Loan Party and constitutes a legal, valid and binding obligation of each Loan Party, enforceable against such Loan Party in accordance with its terms, subject to applicable laws affecting creditors’ rights generally and subject to (i) the effects of bankruptcy, insolvency, moratorium, reorganization, fraudulent conveyance or other laws affecting creditors’ rights generally, (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law) and (iii) implied covenants of good faith and fair dealing; and 9 (e) this Amendment will not violate any applicable law in any material respect, will not violate or result in a default or require any consent or approval under any indenture, agreement or other instrument binding upon any Loan Party or its property, or give rise to a right thereunder to require any payment to be made by any Loan Party, except for violations, defaults or the creation of such rights that could not reasonably be expected to result in a Material Adverse Effect. 6. Ratification. Except as expressly amended hereby, the Loan Documents shall remain in full force and effect. The Credit Agreement, as hereby amended, and all rights and powers created thereby or thereunder and under the other Loan Documents are in all respects ratified and confirmed and remain in full force and effect. The Collateral Agreement, as hereby amended, and all rights and powers created thereby or thereunder are in all respects ratified and confirmed and remain in full force and effect. 7. Reaffirmation of Collateral Documents. In connection with this Amendment, each Loan Party party hereto, as debtor, grantor, pledgor, guarantor, or another similar capacity in which such Loan Party grants Liens or security interests or otherwise acts as a guarantor, joint or several obligor or other accommodation party, as the case may be, in each case under the Collateral Documents heretofore executed and delivered in connection with or pursuant to the Credit Agreement (as such Collateral Documents may have been heretofore, or are hereby, amended, restated, supplemented or otherwise modified), hereby (a) ratifies and reaffirms all of its payment and performance obligations, contingent or otherwise, under such Collateral Documents to which it is a party, (b) to the extent such Loan Party granted Liens on or security interests in any of its properties pursuant to such Collateral Documents, hereby ratifies and reaffirms such grant of security and confirms that such Liens and security interests continue to secure the Secured Obligations (as defined in the Collateral Agreement) thereunder and (c) to the extent such Loan Party guaranteed, was joint or severally liable, or provided other accommodations with respect to, the Obligations or any portion thereof, hereby ratifies and reaffirms such guaranties, liabilities and other accommodations. 8. Definitions and References. Any term used in this Amendment that is defined in the Credit Agreement shall have the meaning therein ascribed to it. The terms “Agreement” ,“Credit Agreement” and “Collateral Agreement” as used in the Loan Documents or any other instrument, document or writing furnished to the Administrative Agent, the Collateral Agent or the Lenders by the Borrower and referring to the Credit Agreement or the Collateral Agreement, as applicable, shall mean the Credit Agreement as hereby amended or the Collateral Agreement as hereby amended, as applicable. 9. Miscellaneous. This Amendment (a) shall be binding upon and inure to the benefit of the Borrower, the Guarantors, the Administrative Agent, the Collateral Agent and the Lenders and their respective successors and assigns (provided, however, no party may assign its rights hereunder except in accordance with the Credit Agreement); (b) may be modified or amended only in accordance with the Credit Agreement; (c) may be executed in several counterparts, and by the parties hereto on separate counterparts, and each counterpart, when so executed and delivered, shall constitute an original agreement, and all such separate counterparts shall constitute but one and the same agreement; and (d) TOGETHER WITH THE OTHER LOAN DOCUMENTS, EMBODIES THE ENTIRE AGREEMENT AND UNDERSTANDING AMONG THE 10 PARTIES WITH RESPECT TO THE SUBJECT MATTER HEREOF AND SUPERSEDES ALL PRIOR AGREEMENTS, CONSENTS AND UNDERSTANDINGS RELATING TO SUCH SUBJECT MATTER. Delivery of an executed counterpart of a signature page to this Amendment by telecopy or as an attachment to an email shall be effective as delivery of a manually executed counterpart of this Amendment. 10. Loan Document. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of any Lender, the Administrative Agent or the Collateral Agent under any of the Loan Documents, nor constitute a waiver of any provision of any of the Loan Documents. On and after the effectiveness of this Amendment, this Amendment shall for all purposes constitute a Loan Document. 11. Governing Law. This Amendment shall be governed by, and construed in accordance with, the law of the State of New York. 11 [Signature Pages Follow] The parties hereto have caused this Amendment to be duly executed as of the day and year first above written. BORROWER: SUMMIT MIDSTREAM HOLDINGS, LLC /s/ Marc Stratton By: Name: Marc Stratton Title: Executive Vice President and Chief Financial Officer OTHER LOAN PARTIES: SUMMIT MIDSTREAM PARTNERS, LP By: By: SUMMIT MIDSTREAM GP, LLC, its general partner /s/ Marc Stratton Name:Marc Stratton Title:Executive Vice President and Chief Financial Officer DFW MIDSTREAM SERVICES LLC SUMMIT MIDSTREAM FINANCE CORP. GRAND RIVER GATHERING, LLC RED ROCK GATHERING COMPANY, LLC MOUNTAINEER MIDSTREAM COMPANY, LLC BISON MIDSTREAM, LLC POLAR MIDSTREAM, LLC EPPING TRANSMISSION COMPANY, LLC SUMMIT MIDSTREAM MARKETING, LLC SUMMIT MIDSTREAM PERMIAN, LLC MEADOWLARK MIDSTREAM COMPANY, LLC SUMMIT MIDSTREAM UTICA, LLC SUMMIT MIDSTREAM PERMIAN FINANCE CORP. SUMMIT MIDSTREAM NIOBRARA, LLC SUMMIT MIDSTREAM PERMIAN II, LLC Signature Pages – SMLP Third Amendment By: By: By: Title: Executive Vice President and Chief Financial Office /s/ Marc Stratton Marc Stratton Name: SUMMIT MIDSTREAM OPCO, LP SUMMIT MIDSTREAM MARKETING, LLC, its general partner Title: Executive Vice President and Chief Financial Officer /s/ Marc Stratton Marc Stratton Name: WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, Collateral Agent and a Lender By:/s/ Brandon Kast Name: Brandon Kast Title: Director BMO HARRIS FINANCING, INC., as a Lender By:/s/ Gumaro Tijerina Name: Gumaro Tijerina Title: Managing Director ING CAPITAL LLC, as a Lender By: By: /s/ Sibha Pasumarti Name: Sibha Pasumarti Title: Managing Director /s/ Phoebe (T.P.) Nguyen Name: Phoebe (T.P.) Nguyen Title: Vice President Signature Pages – SMLP Third Amendment ROYAL BANK OF CANADA, as a Lender By: /s/ Michael Sharp Name: Michael Sharp Title: Authorized Signatory TORONTO-DOMINION BANK, NEW YORK BRANCH, as a Lender By: /s/ Brian MacFarlane Name: Brian MacFarlane Title: Authorized Signatory BANK OF AMERICA, N.A., as a Lender By: /s/ Victor F. Cruz Name: Victor F. Cruz Title: Vice President BBVA USA, as a Lender By: /s/ Mark H. Wolf Name: Mark H. Wolf Title: Senior Vice President REGIONS BANK, as a Lender By: /s/ David Valentine Name: David Valentine Title: Managing Director CAPITAL ONE, NATIONAL ASSOCIATION, as a Lender By: /s/ Scott Mackey Name: Scott Mackey Title: Director Signature Pages – SMLP Third Amendment CITIBANK, N.A., as a Lender By: /s/ Thomas Benavides Name: Thomas Benavides Title: Director ZIONS BANCORPORATION, N.A. DBA AMEGY BANK, as a Lender By: /s/ Jill McSorley Name: Jill McSorley Title: Senior Vice President - Amegy Bank Division BARCLAYS BANK PLC, as a Lender By: /s/ May Huang Name: May Huang Title: Assistant Vice President CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH, as a Lender By: By: /s/ Nupur Kumar Name: Nupur Kumar Title: Authorized Signatory /s/ Christopher Zybrick Name: Christopher Zybrick Title: Authorized Signatory GOLDMAN SACHS BANK USA, as a Lender By: /s/ Jamie Minieri Name: Jamie Minieri Title: Authorized Signatory Signature Pages – SMLP Third Amendment MORGAN STANLEY SENIOR FUNDING, INC., as a Lender By: /s/ John Kuhns Name: John Kuhns Title: Vice President MORGAN STANLEY BANK, N.A., as a Lender By: /s/ John Kuhns Name: John Kuhns Title: Authorized Signatory TRUIST BANK, formerly known as Branch Banking and Trust Company, as a Lender By: /s/ Greg Krablin Name: Greg Krablin Title: Senior Vice President CADENCE BANK, as a Lender By: /s/ David Anderson Name: David Anderson Title: Senior Vice President COMERICA BANK, as a Lender By: /s/ Mark Fuqua Name: Mark Fuqua Title: Executive Vice President CITIZENS BANK, N.A., as a Lender By: /s/ Scott Donaldson Name: Scott Donaldson Title: Senior Vice President Signature Pages – SMLP Third Amendment EXHIBIT 10.12 Execution Version AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF SUMMIT PERMIAN TRANSMISSION HOLDCO, LLC a Delaware Limited Liability Company Dated as of December 24, 2019 Limited liability company interests in Summit Permian Transmission Holdco, LLC, a Delaware limited liability company, have not been registered with or qualified by the Securities and Exchange Commission or any securities regulatory authority of any state. The interests are being sold in reliance upon exemptions from such registration or qualification requirements. The interests cannot be sold, transferred, assigned or otherwise disposed of except in compliance with the restrictions on transferability contained in this Amended and Restated Limited Liability Company Agreement of Summit Permian Transmission Holdco, LLC, as such may be amended or restated from time to time, and applicable federal and state securities laws. TABLE OF CONTENTS Page ARTICLE I DEFINITIONS1 Section 1.1 Section 1.2 Certain Definitions1 Construction23 ARTICLE II ORGANIZATION24 Section 2.1 Section 2.2 Section 2.3 Section 2.4 Section 2.5 Section 2.6 Section 2.7 Section 2.8 Continuation of the Company24 Name24 Registered Office; Registered Agent24 Principal Office24 Purpose; Powers24 Fiscal Year; Fiscal Quarter25 Foreign Qualification Governmental Filings25 Term25 ARTICLE III MEMBERS; DISPOSITIONS25 Section 3.1 Section 3.2 Section 3.3 Section 3.4 Section 3.5 Section 3.6 Section 3.7 Section 3.8 Members25 Restrictions on the Transfer of Units26 Issuance of Units; Additional Members27 Liability to Third Parties27 Rights and Obligations of Transferee27 Responsibilities of the Members27 Representations and Warranties of the Members28 Member Action29 ARTICLE IV INTERESTS; CAPITAL CONTRIBUTIONS30 Section 4.1 Section 4.2 Section 4.3 Section 4.4 Section 4.5 Section 4.6 Section 4.7 Section 4.8 Section 4.9 Section 4.10 Interests30 Effective Date Transactions; Subsequent Closing30 Additional Capital Contributions by Series A Preferred Members30 Failure to Contribute31 Accordion Feature32 Capital Accounts33 Withdrawal or Return of Capital33 Redemption34 Remedial Sale35 Undrawn Commitment Amount37 ARTICLE V DISTRIBUTIONS AND ALLOCATIONS37 Section 5.1 Section 5.2 Section 5.3 Section 5.4 Distributions37 Tax Distributions39 Allocations40 Withholding45 i ARTICLE VI MANAGEMENT45 Section 6.1 Section 6.2 Section 6.3 Section 6.4 Section 6.5 Section 6.6 Section 6.7 Section 6.8 Section 6.9 Management45 Board46 Officers48 Waiver of Fiduciary Duties; Indemnification; Limitation of Liability49 Company as Indemnitor of First Resort51 Other Activities52 No Recourse Against Nonparty Affiliates53 Preferred Approvals53 Financial Covenant58 ARTICLE VII RIGHTS OF MEMBERS; CONFIDENTIALITY59 Section 7.1 Section 7.2 Section 7.3 Access to Information; Inspection Rights59 Financial Reports; Information59 Confidentiality60 ARTICLE VIII TAXES60 Section 8.1 Section 8.2 Section 8.3 Tax Returns60 Tax Elections61 Company Representative61 ARTICLE IX BOOKS, RECORDS, REPORTS, AND BANK ACCOUNTS62 Section 9.1 Section 9.2 Section 9.3 Maintenance of Books and Records62 Reports62 Bank Accounts62 ARTICLE X DISSOLUTION, LIQUIDATION, TERMINATION AND CONVERSION63 Section 10.1 Section 10.2 Section 10.3 Section 10.4 Dissolution63 Liquidation and Termination63 Cancellation of Filing64 Survival64 ARTICLE XI GENERAL PROVISIONS64 Section 11.1 Section 11.2 Section 11.3 Section 11.4 Section 11.5 Section 11.6 Section 11.7 Section 11.8 Section 11.9 Section 11.10 Section 11.11 Section 11.12 Offset64 Notices64 Entire Agreement; Supersedure65 Effect of Waiver or Consent65 Amendment or Modification65 Survivability of Terms66 Binding Effect66 Governing Law; Severability66 Consent to Jurisdiction; Waiver of Jury Trial66 Specific Performance67 Further Assurances67 Waiver of Certain Rights67 ii Section 11.13 Section 11.14 Section 11.15 Section 11.16 Section 11.17 Title to Company Property67 Counterparts67 Electronic Transmissions67 Legal Counsel68 Special Purpose Entity68 iii AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF SUMMIT PERMIAN TRANSMISSION HOLDCO, LLC This AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT (the “Agreement”) of SUMMIT PERMIAN TRANSMISSION HOLDCO, LLC, a Delaware limited liability company (the “Company”), is made and entered into effective as of December 24, 2019 (the “Effective Date”) by and among the Common Unit Member (as defined below), the Series A Preferred Members (as defined below) that are designated as such on the signature pages of this Agreement and, solely for purposes of Sections 3.6(a), 4.9 and 11.17, Summit Parent (as defined below). Capitalized terms used in this Agreement without definition have the meanings ascribed to such terms in Section 1.1. The Company and the Members are sometimes collectively referred to herein as the “Parties” and each is sometimes referred to herein as a “Party.” RECITALS WHEREAS, the Company was formed under the Laws of the State of Delaware by filing a Certificate of Formation (the “Certificate”) with the Secretary of State of the State of Delaware on December 17, 2019; WHEREAS, Summit Member, as the sole member of the Company, entered into the Limited Liability Company Agreement of the Company dated as of December 17, 2019 (the “Initial Agreement”); WHEREAS, on the Effective Date, the Company entered into a Preferred Unit Purchase Agreement with the Series A Preferred Members (the “Preferred Purchase Agreement”) to issue the Series A Preferred Units to the Series A Preferred Members; and WHEREAS, in connection with the transactions contemplated by the Preferred Purchase Agreement, on the Effective Date, Summit Member and the Series A Preferred Members desire to effect the amendment and restatement of the Company’s Initial Agreement in its entirety to (a) provide for the Series A Preferred Units as a new class of preferred securities, (b) provide for the admission of new Members, (c) establish and set forth the Members’ agreement with respect to certain rights and obligations associated with the ownership of Units and (d) provide for such other changes as the Members have determined are necessary and appropriate in connection with the foregoing. NOW, THEREFORE, in consideration of the mutual covenants and agreements contained in this Agreement and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Members agree as follows: ARTICLE I DEFINITIONS Section 1.1 Certain Definitions . As used in this Agreement, the following terms have the following meanings: “Accordion Amount” means $60,000,000. “Accordion Capital Call” has the meaning set forth in Section 4.5(a). “Accordion Units” has the meaning set forth in Section 4.5(a). “Act” means the Delaware Limited Liability Company Act and any successor statute. “Additional Funding Request” has the meaning given to it in the Preferred Purchase Agreement. “Adjusted Capital Account” means, with respect to any Holder, the balance, if any, in such Holder’s Capital Account as of the end of the relevant Tax Year or other period, after giving effect to the following adjustments: add to such Capital Account any amounts which such Holder is obligated to restore in accordance with this Agreement or is deemed to be obligated to restore to the Company in accordance with Treasury Regulations Sections 1.704-1(b)(2)(ii)(c), 1.704-2(g)(1) and 1.704-2(i)(5); and (a) Regulations Sections 1.704-1(b)(2)(ii)(d)(4), (5) and (6). (b) subtract from such Capital Account such Holder’s share of the items described in Treasury The foregoing definition is intended to comply with the provisions of Treasury Regulations Sections 1.704-1(b)(2)(ii) (d) and 1.704-2 and shall be interpreted consistently therewith. “Adoption Agreement” means the Adoption Agreement substantially in the form of Exhibit D. “Affiliate” means, with respect to a specified Person, any other Person, that, directly or indirectly Controls, is Controlled by or under common Control with, such Person. Notwithstanding anything to the contrary in this Agreement, for purposes of this Agreement, with respect to any Person holding Series A Preferred Units that is an investment fund, investment account or investment company, any other investment fund, investment account or investment company that is managed, advised or sub-advised by the same investment advisor as such Person or by an Affiliate of such investment advisor, shall be considered Controlled by, and an Affiliate of, such first Person. “Agreement” has the meaning set forth in the introductory paragraph. “Available Cash” means, with respect to any fiscal quarter of the Company ending prior to the occurrence of a Dissolution Event or a Trigger Event, (a) all cash and cash equivalents of the Company on hand at the end of such fiscal quarter (excluding any Specified Exxon Proceeds or any proceeds resulting from any Permitted Summit Operating Sell-Down, in each case, that have been distributed to or otherwise received by the Company), less (b) the amount of any cash reserves established by the Board in Good Faith to (i) provide for the proper conduct of the business of the Company and its Subsidiaries (including reserves for general and administrative expenses, capital expenditures, capital calls, taxes, investments and debt service costs), (ii) comply with applicable 2 Law or any loan agreement, security agreement, mortgage, debt instrument, or other agreement or obligation to which the Company or any of its Subsidiaries is a party or by which it is bound or its assets are subject and (iii) provide funds necessary to make Series A Preferred Distributions in accordance with Section 5.1(c); provided that such cash reserves shall not equal less than the forthcoming three months of anticipated capital calls that are expected to be made by Permian Transmission to fund its capital commitment obligations to Double E (excluding any capital commitment obligations to fund “Expansion Opportunities” (as such term is defined in the Double E LLC Agreement (as in effect on the Effective Date, without any amendments, modifications, supplements, waivers or other changes thereto)) (including “Expansion Opportunities” that are “Special Construction Projects” (as such term is defined in the Double E LLC Agreement) solely to the extent that Permian Transmission is the “Participating Member” (as such term is defined in the Double E LLC Agreement) in accordance with the terms of the Double E LLC Agreement (as in effect on the Effective Date, without any amendments, modifications, supplements, waivers or other changes thereto)) that are able to be satisfied through cash reserves then available at Double E or through debt or equity financing that is permitted pursuant to this Agreement and the Double E LLC Agreement (as in effect on the Effective Date, without any amendments, modifications, supplements, waivers or other changes thereto) and is, as of the relevant time of determination, available pursuant to binding contractual commitments that are enforceable by Double E) without Preferred Approval. Notwithstanding the foregoing, “Available Cash” shall equal zero with respect to the fiscal quarter (and all fiscal quarters thereafter) in which a Dissolution Event or a Trigger Event occurs (unless and until the applicable Trigger Event is cured, if applicable, or as otherwise determined by the Series A Preferred Members with Preferred Approval). “Baker Botts” has the meaning set forth in Section 11.16(b). “Bankruptcy Event” means, with respect to any Person: (a) such Person (i) admits in writing its inability to pay its debts as they become due, (ii) files, consents or acquiesces by answer or otherwise to the filing against it of a petition for relief, reorganization, rearrangement, readjustment or similar relief or any other petition in bankruptcy, for liquidation or to take advantage of any bankruptcy, insolvency, dissolution, reorganization, moratorium or other similar Law of any jurisdiction, (iii) makes an assignment for the benefit of its creditors, (iv) consents to the appointment of a custodian, receiver, trustee or other officer with similar powers with respect to it or with respect to any substantial part of its property, (v) is adjudicated as bankrupt or as insolvent or to be liquidated, (vi) gives notice to any Governmental Entity of insolvency or pending insolvency or (vii) takes corporate action for the purpose of any of the foregoing; (b) (i) a court or other Governmental Entity of competent jurisdiction enters an order (A) appointing, without consent by such Person, a custodian, receiver, trustee or other officer with similar powers with respect to it or with respect to any substantial part of its property, (B) constituting an order for relief or approving a petition for relief, reorganization or any other petition in bankruptcy or for liquidation or to take advantage of any bankruptcy or insolvency Law of any jurisdiction or (C) ordering the dissolution, winding-up or liquidation of such Person or (ii) a petition or involuntary case with respect to any of the foregoing is filed or commenced against such Person; 3 creditors to restructure, reorganize or market itself or its assets through a bankruptcy process; (c) such Person enters into a definitive restructuring support agreement or other agreement with (d) such Person is in any (i) default with respect to the timely payment of principal or interest or any “event of default” or analogous concept with respect to such Person’s indebtedness for borrowed money (or other Funded Indebtedness) or (ii) other material, continuing breach or default of any covenant or other term or condition of such Person’s indebtedness for borrowed money (or other Funded Indebtedness), provided, in the case of clause (ii), that such breach or default has not been cured (if such breach or default is capable of cure or remedy) within any applicable cure period under the terms of such indebtedness and has not matured into an “event of default” or analogous concept with respect to such indebtedness; or such Person’s indebtedness for borrowed money (or other Funded Indebtedness). (e) such Person enters into a forbearance agreement with the applicable creditors with respect to any of “Base Return” means, with respect to each issued and outstanding Series A Preferred Unit as of the applicable date of determination, an amount equal to the greater of: (a) an amount sufficient to cause the ROI of such Series A Preferred Unit to be ____; and (b) an amount sufficient to cause the IRR of such Series A Preferred Unit to be ____%; plus, in the case of each of foregoing clauses (a) and (b), to the extent any Series A Preferred Distributions arrearages are owed in respect of such Series A Preferred Units of such date of determination, the portion of such arrearages attributable to the Step-Up Rate. Notwithstanding anything to the contrary in this Agreement, in no event shall any calculation of the Base Return (or the calculations of ROI and IRR used therein) take into account (y) any expenses of the Series A Preferred Members reimbursed by the Company or paid as an indemnity or as damages pursuant to the Preferred Purchase Agreement or any of the Other Transaction Documents or (z) any Undrawn Commitment Amount (or corresponding Undrawn Commitment Units), Transaction Amount or Structuring Amount. “Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only upon the occurrence of a subsequent condition. The terms “Beneficially Owns” and “Beneficially Owned” have correlative meanings. “Board” has the meaning set forth in Section 6.1. “Board Observer” has the meaning set forth in Section 6.2(o). “Business” has the meaning set forth in Section 2.5. “Business Day” means any day other than a Saturday, Sunday or legal holiday on which banks in New York, New York, are authorized or obligated by Law to close. 4 “C&M Agreement” means the Construction Management Agreement, by and between Summit Member and Double E, dated as of June 26, 2019. “Capital Account” means the Capital Account maintained for each Holder on the Company’s books and records in accordance with the following provisions: (a) To each Holder’s Capital Account there will be added (i) the amount of cash and the Gross Asset Value of any other asset contributed by such Holder to the Company pursuant to any provision of this Agreement, (ii) such Holder’s allocable share of Profits and any items in the nature of income or gain that are specially allocated to such Holder pursuant to Section 5.3(a) and Section 5.3(b) or other provisions of this Agreement and (iii) any other increases allowed or required by Treasury Regulations Section 1.704-1(b)(2)(iv). (b) From each Holder’s Capital Account there will be subtracted (i) the amount of cash and the Gross Asset Value of any other Company assets distributed to such Holder pursuant to any provision of this Agreement, (ii) such Holder’s allocable share of Losses and any other items in the nature of expenses or losses that are specially allocated to such Holder pursuant to Section 5.3(a) and Section 5.3(b) or other provisions of this Agreement, (iii) liabilities of such Holder assumed by the Company or which are secured by any property contributed by such Holder to the Company and (iv) any other decreases allowed or required by Treasury Regulations Section 1.704-1(b)(2)(iv). (c) In the event any Unit is Transferred (other than by pledge of, or grant of a security interest in, such Interest) in accordance with the terms of this Agreement, the transferee will succeed to the Capital Account of the transferor to the extent it relates to the Unit that is Transferred in accordance with the provisions of Treasury Regulations Section 1.704-1(b) (2)(iv)(l). take into account Code Section 752(c) and any other applicable provisions of the Code and Treasury Regulations. (d) Determination of the amount of any liability for purposes of subparagraphs (a) and (b) above will The foregoing provisions and the other provisions of this Agreement relating to the maintenance of Capital Accounts are intended to comply with Treasury Regulations Sections 1.704-1(b) and 1.704-2 and will be interpreted and applied in a manner consistent with such Treasury Regulations while giving as much effect to the provisions of this Agreement as possible. “Capital Contribution” means, with respect to any Member, as of any time of determination, (a) the amount of money contributed or, to the extent provided in this Agreement, deemed contributed to the Company and (b) the Fair Market Value of any Property (other than money) contributed to the Company, in each case by such Member as of the time in question. “Capital Stock” means (a) in the case of a corporation, corporate stock; (b) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock; (c) in the case of a partnership or limited liability company, partnership interests (whether general or limited) or membership interests; and (d) any other interest or participation that confers on a Person the right to receive a share of the 5 profits and losses of, or distributions of assets of, the issuing Person (excluding debt securities convertible into or exchangeable for Capital Stock, prior to such conversion). “Certificate” has the meaning set forth in the recitals. “Change of Control” means the occurrence of one or more of the following events: the direct or indirect sale, lease, transfer, conveyance or other disposition, in one or a series of related transactions, of all or substantially all of the properties or assets of the Company, Permian Transmission or Double E, taken as a whole, to any Person or Persons; (a) Transmission or Double E; (b) the adoption of a plan relating to the liquidation or dissolution of the Company, Permian (c) the consummation of any sale, transfer, conveyance or other transaction (including any merger, consolidation or other business combination) the result of which is that any “person” or “group” (as such terms are used in Section 13(d) and Section 14(d) of the Exchange Act) that was not previously the Beneficial Owner of Capital Stock of the Company representing more than 50% of the aggregate ordinary voting power and more than 50% of the rights to distributions upon the liquidation, dissolution or winding up of the Company to which holders of Units (other than Series A Preferred Units) would be entitled if the assets of the Company had been sold for their Fair Market Value and the resulting proceeds distributed (after satisfying all debts and other liabilities and obligations of the Company) in a complete liquidation of the Company becomes the Beneficial Owner, directly or indirectly, of Capital Stock of the Company representing more than 50% of the aggregate ordinary voting power or more than 50% of the rights to distributions upon the liquidation, dissolution or winding up of the Company to which holders of Units (other than Series A Preferred Units) would be entitled if the assets of the Company had been sold for their Fair Market Value and the resulting proceeds distributed (after satisfying all debts and other liabilities and obligations of the Company) in a complete liquidation of the Company; provided, that for purposes of this clause (c), a “person” or “group” shall include, in connection with a direct merger or other business combination of any Entity with a class of securities traded on a national or regional securities exchange with the Company, the shareholders of such publicly traded Entity with whom the Company merges or that become equityholders of the Company in connection with such transaction; the consummation of any tender offer, merger, recapitalization, consolidation or business combination, or reorganization or other transaction, or series of such transactions, involving the Company, Permian Transmission or Double E and any other Person or group of Persons; or (d) (e) the consummation of any transaction, or series of related transactions, involving the Company, Permian Transmission or Double E and any other Person or group of Persons whereby the Company directly or indirectly Transfers beneficial ownership of any Capital Stock in Double E to any Person other than the Company or a wholly-owned Subsidiary of the Company. 6 to occur as a result of (i) a Permitted Summit Operating Sell-Down or (ii) a Permitted Summit HoldCo Sell-Down. (f) Notwithstanding the foregoing clauses (a) through (e), a “Change of Control” shall not be deemed “Code” means the Internal Revenue Code of 1986 and any successor statute, as amended from time to time. “Commitment” means, with respect to each Series A Preferred Member, the amount set forth next to such Series A Preferred Member’s name on Exhibit A. “Common Unit” means a limited liability company interest in the Company referred to in this Agreement as a “Common Unit”. “Common Unit Member” means any Member owning Common Units and identified as a Common Unit Member on Exhibit A, as such may be amended from time to time by the Board pursuant to this Agreement. “Common Unit Sharing Percentage” means, as to any Holder of Common Units, as of the time of determination, the percentage obtained by dividing the number of Common Units held by such Holder by the total number of issued and outstanding Common Units held by all of the Holders at the time in question. “Company” has the meaning specified therefor in the introductory paragraph. “Company Minimum Gain” has the meaning set forth in Treasury Regulations Sections 1.704-2(b)(2) and 1.704-2(d) (1) for the phrase “partnership minimum gain.” “Company Representative” has the meaning assigned to the term “partnership representative” in Code Section 6223 and any Treasury Regulations (and any analogous provision of state or local Law). “Competitor” means (a) any Entity that has substantial experience in the natural gas gathering, processing or transmission business in the United States and (b) any private equity fund that has any equity position in, or Controls, any Person that owns or operates FERC-regulated interstate natural gas pipeline transportation assets located in the Permian or Delaware Basins. “Contracting Parties” has the meaning set forth in Section 6.7. “Control” (including the terms “Controlling” and “Controlled”) means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise. “Covered Persons” has the meaning set forth in Section 6.6. “Cumulative Assumed Tax Liability” means, with respect to any Member as of any Fiscal Year, the product of (a) the U.S. federal taxable income (other than taxable income incurred in connection with the receipt of a guaranteed payment for services by such Member, but expressly including a guaranteed payment for the use of capital) allocated by the Company to such Member, 7 and taxable income allocated to any Member pursuant to Section 5.3, in such Fiscal Year and all prior Fiscal Years less the U.S. federal taxable loss allocated by the Company to such Member in such Fiscal Year and all prior Fiscal Years (but assuming that the allocated taxable loss from prior Fiscal Years taken into account for purposes of this calculation shall not exceed 80% of taxable income allocated by the Company to such Member in such Fiscal Year or such other limitation as set forth in Section 172(a)(2) of the Code or any similar successor provision), multiplied by (b) the highest applicable U.S. federal, state and local income tax rate (including the tax rate imposed on “net investment income” by Code Section 1411 to the extent applicable to the taxable income allocated to such Member) applicable to an individual (or, if higher, a corporation) resident in San Francisco, California (for the avoidance of doubt, regardless of the actual rate applicable to such Member) taking into account (i) the character of U.S. federal taxable income or loss allocated by the Company to such Member (e.g., capital gains or losses, dividends, ordinary income, etc.) during each applicable Fiscal Year and (ii) any adjustment to such Member’s taxable income attributable to its direct or indirect ownership of the Company and its Subsidiaries as a result of any tax examination, audit or adjustment with respect to any period or portion thereof. For the avoidance of doubt, the term “Cumulative Assumed Tax Liability” shall not take into account any impact of (i) Code Section 199A or (ii) the deductibility of state and local taxes for U.S. federal income tax purposes for so long as such deductions are limited under Code Section 164. When the Cumulative Assumed Tax Liability must be calculated in advance of a Tax Distribution Date, it shall be calculated as of the last day of the most recent fiscal quarter as if such day constituted the end of a taxable year. “D&O Insurance” has the meaning set forth in Section 6.4(j). “Default Amount” has the meaning set forth in Section 4.4(a). “Defaulting Preferred Member” has the meaning set forth in Section 4.4(a). “Depreciation” means, for each Tax Year or other period, an amount equal to the depreciation, amortization or other cost recovery deduction allowable for federal income tax purposes with respect to an asset for such Tax Year or other period, except that (a) with respect to any property the Gross Asset Value of which differs from its adjusted tax basis for federal income tax purposes and which difference is being eliminated by use of the “remedial method” pursuant to Treasury Regulations Section 1.704-3(d), Depreciation for such Tax Year or other period will be the amount of book basis recovered for such Tax Year or other period under the rules prescribed by Treasury Regulations Section 1.704-3(d)(2) and (b) with respect to any other property the Gross Asset Value of which differs from its adjusted basis for federal income tax purposes at the beginning of such Tax Year or other period, Depreciation for such Tax Year or other period will be an amount that bears the same ratio to such beginning Gross Asset Value as the federal income tax depreciation, amortization or other cost recovery deduction for such Tax Year or other period bears to such beginning adjusted tax basis. Notwithstanding the foregoing, if the federal income tax depreciation, amortization or other cost recovery deduction for such Tax Year or other period is zero, then for the purposes of clause (a) of the preceding sentence Depreciation will be determined with reference to such beginning Gross Asset Value using any reasonable method selected by the Board. “Development Budget” has the meaning set forth in the C&M Agreement. 8 “Director” has the meaning set forth in Section 6.1. “Dissolution Event” has the meaning set forth in Section 10.1. “Double E” means Double E Pipeline, LLC, a Delaware limited liability company. “Double E LLC Agreement” means the Amended and Restated Limited Liability Company Agreement of Double E, dated as of June 26, 2019. “Double E Pipeline” means the pipeline and any laterals, interconnections, meter stations, and any related pipeline assets contemplated by the Project Execution Plan (as defined in the C&M Agreement) originating in the northern Delaware Basin in Eddy County, New Mexico and terminating at Waha, Reeves and Pecos Counties, Texas; provided, that “Double E Pipeline” shall also include any Construction Opportunities (as defined in the Double E LLC Agreement) and Special Construction Projects (as defined in the Double E LLC Agreement) placed in-service. “ECP” means Energy Capital Partners III, LP and Energy Capital Partners IV, LP and each of their affiliated funds and investment vehicles that are Controlled by ECP ControlCo, LLC or the investment committee of Energy Capital Partners III, LP or Energy Capital Partners IV, LP. “ECP Commitment Letter” means an equity commitment letter, in form and substance acceptable to TES Member, (a) issued by a private equity fund or similar investment fund Controlled by ECP ControlCo, LLC or the investment committee of Energy Capital Partners III, LP or Energy Capital Partners IV, LP that has reserved (solely for the purposes of guaranteeing the Company’s obligations under Section 4.8(a)) ECP Creditworthy LP Commitments from limited partners in such fund in an amount necessary to guarantee all obligations of the Company from time to time owing pursuant to Section 4.8(a) and (b) which TES Member is entitled enforce directly against the issuer as a party thereto. “ECP Creditworthy LP Commitments” means uncalled capital commitments from limited partners in a private equity fund or similar investment fund to the extent such commitments would reasonably be expected to be given credit by a Major Commercial Bank in the determination of the fund’s borrowing base under a customary subscription-secured credit facility provided to such fund by a Major Commercial Bank (i.e., if a limited partner has made a $__ commitment, but a Major Commercial Bank would only provide $__ of borrowing base capacity in respect of such commitment, then such commitment would constitute $__ of ECP Creditworthy LP Commitments). “Effective Date” has the meaning set forth in the introductory paragraph. “Enforceability Exceptions” means (a) any applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium or other similar Laws relating to or affecting the enforcement of creditors’ rights generally and (b) any legal principles of general applicability governing the availability of equitable remedies, including principles of commercial reasonableness, good faith and fair dealing (whether considered in a proceeding in equity or at Law or under applicable legal codes). 9 “Entity” means any corporation, limited liability company, general partnership, limited partnership, venture, trust, business trust, unincorporated association, estate or other entity. “Exchange Act” means the Securities Exchange Act of 1934, as amended. “Exxon” has the meaning ascribed to the term “Exxon Member” in the Double E LLC Agreement (as in effect on the Effective Date, without any amendments, modifications, supplements, waivers or other changes thereto). “Exxon Consent” has the meaning set forth in the Preferred Purchase Agreement. “Fair Market Value” means, with respect to Property (other than cash), the fair market value of such Property as determined in Good Faith by the Board, with Preferred Approval (not to be unreasonably withheld, conditioned or delayed) unless otherwise specified in this Agreement or in one of the Other Transaction Documents, as applicable. “FERC” means the Federal Energy Regulatory Commission. “FERC Approval” means FERC’s issuance of a certificate under Section 7(c) of the Natural Gas Act of 1938 in respect of the Application of Double E Pipeline, LLC for Certificate of Public Convenience and Necessity and Related Authorizations, FERC Docket No. CP19-495-000, dated July 31, 2019. “Fiscal Year” has the meaning set forth in Section 2.6. “Funded Indebtedness” means, as to any Person, without duplication, all indebtedness of such Person for borrowed money, all obligations of such Person evidenced by bonds (other than performance, surety or similar bonds), debentures, notes or similar debt instruments, all obligations in respect of letters of credit of such Person, and all guarantees by such Person of Funded Indebtedness of other Persons, in each case determined in accordance with GAAP, provided that for the avoidance of doubt, lease obligations and other similar arrangements of Double E conveying the right to use (whether in effect as of the date of this Agreement or thereafter incurred) that are required to be classified under GAAP as a liability (including pursuant to Accounting Standards Update, Leases (Topic 842)) will be excluded from Funded Indebtedness. “Funding Termination Date” means the earlier of (a) December 31, 2021 and (b) the date on which Remaining Accordion Amount equals $0.00. “GAAP” means generally accepted accounting principles as in effect in the United States from time to time. “Good Faith” means the Director or Directors making a determination or taking or declining to take an action have the subjective belief that the determination or other action or inaction is in the best interests of the Company and its Subsidiaries. “Governmental Entity” means any (a) national, state, county, tribal, municipal or local government (whether domestic or foreign) and any political subdivision thereof, (b) court or administrative tribunal, (c) other governmental, quasi-governmental, judicial, public or statutory 10 instrumentality, authority, body, agency, bureau or entity of competent jurisdiction (including any zoning authority or state public utility commission, or any comparable authority) and (d) non-governmental agency, tribunal or entity that is properly vested by a governmental authority with applicable jurisdiction. “Gross Asset Value” means, with respect to any asset, the asset’s adjusted basis for federal income tax purposes, except as follows: Holder to the Company is the Fair Market Value of such asset. (a) the initial Gross Asset Value of any asset (other than cash) contributed by a the Gross Asset Value of all Company assets immediately prior to the occurrence of any event described in subparagraphs (i) through (v) below may be adjusted to equal their respective Fair Market Values, as of the following times: (b) the acquisition of an additional Interest in the Company by a new or existing Holder in exchange for more than a de minimis Capital Contribution, if the Board reasonably determines that such adjustment is necessary or appropriate to reflect the relative interests of the Holders in the Company; (i) the distribution by the Company to a Holder of more than a de minimis amount of Company assets as consideration for an Interest in the Company, if the Board reasonably determines that such adjustment is necessary or appropriate to reflect the relative interests of the Holders in the Company; (ii) Section 1.704-1(b)(2)(ii)(g); (iii) the liquidation or dissolution of the Company within the meaning of Treasury Regulations (iv) the grant of an Interest in the Company (other than a de minimis Interest) as consideration for the provision of services to or for the benefit of the Company by an existing Holder acting in his capacity as a Holder, or by a new Holder acting in his capacity as a Holder or in anticipation of becoming a Member of the Company, if the Board reasonably determines that such adjustment is necessary or appropriate to reflect the relative interests of the Members in the Company; and order to comply with Treasury Regulations Sections 1.704-1(b) and 1.704-2. (v) at such other times as the Board may reasonably determine to be necessary or advisable in of such asset (taking Code Section 7701(g) into account) on the date of distribution. (c) the Gross Asset Value of any Company asset distributed to a Holder shall be the Fair Market Value (d) the Gross Asset Values of Company assets will be increased (or decreased) to reflect any adjustments to the adjusted basis of such assets pursuant to Code Section 734(b) or Code Section 743(b), but only to the extent that such adjustments are taken into account in determining Capital Accounts pursuant to Treasury Regulations Section 1.704- 1(b)(2)(iv)(m), except that Gross Asset Values will not be adjusted pursuant to this subparagraph (d) to the extent 11 that an adjustment pursuant to subparagraph (b) above is made in connection with a transaction that would otherwise result in an adjustment pursuant to this subparagraph (d). “Holder” or “Holder of Units” means a Person holding Units at any given time. “In Effect” means, with respect to the Summit Parent Guarantee, that the Termination Date (as defined in the Summit Parent Guarantee) has not yet occurred or the Termination Date has occurred but the Gap Period (as defined in the Summit Parent Guarantee) is continuing and has not yet expired by its terms. “In-Service Date” means the date that the Double E Pipeline and related facilities are completed and ready for firm transportation service. “Indemnified Losses” has the meaning set forth in Section 6.4(e). “Indemnitee” has the meaning set forth in Section 6.4(e). “Initial Agreement” has the meaning set forth in the recitals. “Initial Contribution Amount” means, with respect to each Series A Preferred Member, the amount set forth next to such Series A Preferred Member’s name on Exhibit A. “Initial Public Offering” means the initial firm commitment underwritten offering of equity securities of the Company, any successor entity to or any Subsidiary of the Company or any parent of the Company created for the purpose of conducting an Initial Public Offering, in each case to the public pursuant to an effective registration statement under the Securities Act. “Initiating Member” has the meaning set forth in Section 4.9(a). “Interest” means the limited liability company interest of a Holder at any particular time. “Interest Rate” means a rate per annum equal to the lesser of (a) a varying rate per annum that is equal to the interest rate publicly quoted by JPMorgan Chase Bank (or its successor) from time to time as its prime commercial or similar reference interest rate, with adjustments in that varying rate to be made on the same date as any change in that rate and (b) the maximum rate permitted by applicable Law. “IRR” means with respect to any issued and outstanding Series A Preferred Unit, as of any time of determination, the actual internal annual pre-tax rate of return, compounded quarterly, on the Series A Preferred Issue Amount, only as a result of cash distributions paid on such Series A Preferred Unit pursuant to this Agreement; provided, for the avoidance of doubt, that the return on any portion of the PIK Units shall be calculated from the first day of the fiscal quarter immediately following the fiscal quarter in respect of which such portion of the PIK Units were issued. IRR shall be calculated using the XIRR function in the most recent version of Microsoft Excel (or if such program is no longer available, such other software program for calculating IRR determined by the Board with the consent of the Series A Preferred Members, such consent not to be unreasonably withheld, conditioned or delayed). Notwithstanding anything to the contrary in this Agreement, in no event shall any calculation of IRR take into account (y) any expenses of the 12 Series A Preferred Members reimbursed by the Company or paid as an indemnity or as damages pursuant to the Preferred Purchase Agreement or any of the Other Transaction Documents or (z) any Undrawn Commitment Amount (or corresponding Undrawn Commitment Units), Transaction Amount or Structuring Amount. “Kirkland” has the meaning set forth in Section 11.16(a). “Law” means any statute, law (including common law), rule, ordinance, or regulation or any judgment, order, writ, injunction, or decree of any Governmental Entity. “Leverage Ratio” means, as of any time of determination, an amount equal to the quotient of (a)(i) the then-outstanding aggregate amount of Funded Indebtedness (including principal and interest accrued thereon) of the Company and its Subsidiaries plus (ii) an amount equal to the aggregate Base Return for all issued and outstanding Series A Preferred Units, divided by (b) LTM EBITDA. “Lien” means any lien, mortgage, security interest, pledge, charge, encumbrance, hypothecation or deposit arrangement or other arrangement having the practical effect of any of the foregoing. “LTM EBITDA” means, for the most recent trailing 12 calendar months ended on or before the applicable measurement date, with respect to Double E, the product of (a) the aggregate percentage of the total issued and outstanding Capital Stock of Double E held by Permian Transmission and (b) the sum of (i) consolidated net income (or loss) during such period (excluding extraordinary gains and losses) determined in accordance with GAAP, plus (ii) all interest paid or accrued (including amortization of original issue discount and the interest component of any deferred payment obligations and capital lease obligations) that was deducted in determining such consolidated net income, plus (iii) all income taxes that were deducted in determining such consolidated net income, plus (iv) all depreciation, amortization (including amortization of goodwill and debt issue costs), impairment and abandonment expenses and other non-cash charges (including any provision for the reduction in the carrying value of assets recorded in accordance with GAAP) that were deducted in determining such consolidated net income, minus (v) all non-cash items of income that were included in determining such consolidated net income. Notwithstanding the foregoing, LTM EBITDA shall be annualized until there is available information for 12 trailing calendar months to calculate LTM EBITDA in accordance with the foregoing. “Major Commercial Bank” means a major U.S. commercial bank or a U.S. branch of a major foreign commercial bank, in either case, with a credit rating for senior unsecured long term indebtedness (not supported by third-party enhancement) of A- or higher from S&P Global Ratings or Fitch, Inc. or A3 or higher from Moody’s Investors Service, Inc. and that is not an Affiliate of Summit Parent or ECP. “Market-Based Financing” means the entrance by the Company or a Subsidiary of the Company into a first lien, senior secured credit facility with one or more commercial banks and pursuant to terms and conditions that would reasonably be considered to be a “market-based” financing; provided that the proceeds of such financing shall be designed, consistent with market- 13 based terms for such financing, to satisfy the obligations of the Company or such applicable Subsidiary of the Company to fund its capital commitment obligations to Double E; and provided further that the terms of such financing shall not expressly prohibit the payment of distributions to which the Series A Preferred Members are entitled under this Agreement or otherwise contain any non-market-based terms that would have the effect of materially and adversely affecting the rights of the Series A Preferred Units. “Material Contract” has the meaning set forth in the Preferred Purchase Agreement. “Maximum Quarterly AC Distribution Amount” means $________; provided, however, after Double E places into operational service any “Expansion Opportunity” (as such term is defined in the Double E LLC Agreement (as in effect on the Effective Date, without any amendments, modifications, supplements, waivers or other changes thereto)) that increases the volume capacity of the Double E Pipeline to be at least 1.85 billion cubic feet of natural gas per day, the Maximum Quarterly AC Distribution Amount shall be $___________. “Member” means any Person executing this Agreement as a Member, but does not include any Person who has ceased to hold any Units of the Company or a direct or indirect transferee of Units from a Member unless and until admitted as a Member in accordance with the provisions of this Agreement. “Member Minimum Gain” means an amount, with respect to each Member Nonrecourse Debt, equal to the Company Minimum Gain that would result if such Member Nonrecourse Debt were treated as a Nonrecourse Liability, determined in accordance with Treasury Regulations Section 1.704-2(i) with respect to “partner minimum gain.” “Member Nonrecourse Debt” has the meaning set forth in Treasury Regulations Section 1.704-2(b)(4) for the phrase “partner nonrecourse debt.” “Member Nonrecourse Deductions” has the meaning set forth in Treasury Regulations Section 1.704-2(i) for the phrase “partner nonrecourse deductions.” “Minimum Optional Redemption Amount” has the meaning set forth in Section 4.8(b)(iii). “New Intermediate Holdco” means a direct Subsidiary of the Company formed in order to effectuate a Permitted Summit Operating Sell-Down to which all of the Company’s Capital Stock in Permian Transmission is transferred and which is Controlled by the Company following such Permitted Summit Operating Sell-Down. “Nonparty Affiliates” has the meaning set forth in Section 6.7. “Nonrecourse Deductions” has the meaning set forth in Treasury Regulations Sections 1.704-2(b)(1) and 1.704-2(c). “Nonrecourse Liability” has the meaning set forth in Treasury Regulations Sections 1.704-2(b)(3) and 1.752-1(a)(2). 14 “O&M Agreement” means the Operations and Maintenance Agreement dated as of June 26, 2019, by and between Double E and Summit Member. “Officer” means any Person designated as an officer of the Company pursuant to Section 6.2(a). “Other Indemnitor” has the meaning set forth in Section 6.5(a). “Other Transaction Documents” means this Agreement, the Preferred Purchase Agreement, the Summit Parent Guarantee and any and all other agreements or instruments executed and delivered by the parties or their respective Affiliates, as applicable, in connection with the transactions contemplated by this Agreement and the Preferred Purchase Agreement. “Partnership Tax Audit Rules” means Sections 6221 through 6241 of the Code together with any final or temporary Treasury Regulations, Revenue Rulings, and case Law interpreting Sections 6221 through 6241 of the Code (and any analogous provision of state or local tax Law). “Party” has the meaning specified therefor in the introductory paragraph. “Permian Transmission” means Summit Permian Transmission, LLC, a Delaware limited liability company. “Permitted Summit HoldCo Sell-Down” means: (a) (b) ECP) if: any Transfer of less than 50% of the Common Units of the Company; or any Transfer of 50% or more of the Common Units of the Company: (i) by Summit Parent of its Units to a transferee (other than ECP or an Entity Controlled by (A) the transferee of Summit Parent’s Units: (1) (x) has a credit rating for senior unsecured long term indebtedness (not supported by a third party enhancement) of BB- or higher from either S&P Global Ratings or Fitch, Inc. or Ba3 or higher from Moody’s Investors Service, Inc. and (y) if the Summit Parent Guarantee remains In Effect at the time of such Transfer, irrevocably assumes in full all of Summit Parent’s obligations under the Summit Parent Guarantee; or (2) (x) has substantial experience in the natural gas gathering, processing or transmission business in the United States and (y) if the Summit Parent Guarantee remained In Effect at the time of such Transfer, provides to the TES Member a replacement guarantee to the Summit Parent Guarantee in substantially the same form as the Summit Parent Guarantee, or another form of credit support (including an irrevocable letter of credit) that is sufficient to 15 Approval if: provide to the TES Member the same or better level of credit support with respect to all obligations that were covered under the Summit Parent Guarantee as the credit support that was provided under the Summit Parent Guarantee and that is reasonably acceptable to TES Member in its sole discretion; and (B) Exxon either (1) consents in writing to such Transfer in accordance with Section 6.16 of the Double E LLC Agreement (as in effect on the Effective Date, without any amendments, modifications, supplements, waivers or other changes thereto) or (2) assumes control as “operator” of the Double E Pipeline in accordance with the Double E LLC Agreement and the O&M Agreement (in each case, as in effect on the Effective Date, without any amendments, modifications, supplements, waivers or other changes thereto); or (ii) by Summit Parent of its Units to ECP or an Entity Controlled by ECP following FERC (A) the transferee of Summit Parent’s Units (x) has substantial experience in the natural gas gathering, processing or transmission business in the United States and (y) if the Summit Parent Guarantee remains In Effect immediately prior to the time of such Transfer, provides an ECP Commitment Letter to the TES Member; and (B) Exxon either (1) consents in writing to such Transfer in accordance with Section 6.16 of the Double E LLC Agreement (as in effect on the Effective Date, without any amendments, modifications, supplements, waivers or other changes thereto) or (2) assumes control as “operator” of the Double E Pipeline in accordance with the Double E LLC Agreement and the O&M Agreement (in each case, as in effect on the Effective Date, without any amendments, modifications, supplements, waivers or other changes thereto). “Permitted Summit Operating Sell-Down” means any Transfer of less than 50% of the Capital Stock in Double E held by Permian Transmission as of the Effective Date; provided that such Transfer is (a) consummated after the Remaining Commitment has been reduced to $0.00, (b) entirely for cash consideration that is immediately payable at the consummation of such transaction, (c) on an arms’ length basis for fair market value (as determined in Good Faith by the Board), (d) structured as (i) a direct transfer of common equity interests in Permian Transmission or Double E that the Company was the Beneficial Owner of immediately prior to such transfer or (ii) an issuance of new common equity interests in Permian Transmission, Double E or a New Intermediate Holdco, in each case where such new common equity interests being issued are identical to the common equity interests that the Company is the Beneficial Owner of (resulting in proportionate dilution of the common equity interests that the Company is the Beneficial Owner of), and (e) to a Person that is not a Qualifying Owner, Summit Member, Summit Parent, ECP or any of their respective Affiliates. Notwithstanding the foregoing, Exxon’s exercise of the Equity 16 Option (as defined in the Double E LLC Agreement) under Section 3.21 of the Double E LLC Agreement shall be deemed a Permitted Summit Operating Sell-Down. “Person” means any individual or Entity. “PIK Period” means the period of time beginning on the Effective Date and ending on the earlier to occur of (a) June 30, 2022 and (b) the last day of the calendar quarter following the calendar quarter in which the In-Service Date occurs. “PIK Units” has the meaning set forth in Section 5.1(c)(ii). “Preferred Approval” means the affirmative vote or consent of the Holders of at least a majority of the outstanding Series A Preferred Units, unless otherwise expressly subject to another standard set forth in this Agreement, such affirmative vote or consent to be given or withheld in the sole and absolute judgment of such Holders. “Preferred Payment Default” has the meaning set forth in Section 4.4(a). “Preferred Purchase Agreement” has the meaning set forth in the recitals. “Profits” and “Losses” means, for each Tax Year or other period, an amount equal to the Company’s taxable income or loss for such year or period determined in accordance with Code Section 703(a) (for this purpose, all items of income, gain, loss, deduction or credit required to be stated separately pursuant to Code Section 703(a)(1) will be included in taxable income or loss), with the following adjustments: any income of the Company that is exempt from federal income tax and not otherwise taken into account in computing Profits or Losses pursuant to this definition of Profits and Losses will increase the amount of such income and/or decrease the amount of such loss; (a) (b) any expenditure of the Company described in Code Section 705(a)(2)(B) or treated as a Code Section 705(a)(2)(B) expenditure pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv)(i), and not otherwise taken into account in computing Profits or Losses pursuant to this definition of Profits and Losses, will decrease the amount of such income and/or increase the amount of such loss; gain or loss resulting from any disposition of Company assets where such gain or loss is recognized for federal income tax purposes will be computed by reference to the Gross Asset Value of the Company assets disposed of, notwithstanding that the adjusted tax basis of such Company assets differs from its Gross Asset Value; (c) computing such income or loss, Depreciation will be taken into account for such Fiscal Year or other period; (d) in lieu of the depreciation, amortization and other cost recovery deductions taken into account in to the extent an adjustment to the adjusted tax basis of any asset included in Company assets pursuant to Code Section 734(b) or Code Section 743(b) is required pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv) (m) to be taken into account in determining Capital (e) 17 Accounts as a result of a distribution other than in liquidation of a Holder’s Interest, the amount of such adjustment will be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases the basis of the asset) from the disposition of the asset and will be taken into account for the purposes of computing Profits and Losses; (f) if the Gross Asset Value of any Company asset is adjusted in accordance with subparagraph (b) or subparagraph (c) of the definition of “Gross Asset Value” above, the amount of such adjustment will be taken into account in the taxable year of such adjustment as gain or loss from the disposition of such asset for purposes of computing Profits or Losses; and (g) notwithstanding any other provision of this definition of Profits and Losses, any items that are specially allocated pursuant to Section 5.3(a) will not be taken into account in computing Profits or Losses. The amounts of the items of Company income, gain, loss or deduction available to be specially allocated pursuant to Section 5.3(a) will be determined by applying rules analogous to those set forth in this definition of Profits and Losses. “Property” means an interest of any kind in any real or personal (or mixed) property, including cash, and any improvements thereto, and includes both tangible and intangible property. “Qualified Income Offset” has the meaning set forth in the Treasury Regulations Section 1.704-1(b)(2)(ii)(d). “Qualifying Owners” means the collective reference to (a) Energy Capital Partners II, LP, Energy Capital Partners II-A, L.P., Energy Capital Partners II-B IP, LP, Energy Capital Partners II-C (Summit IP), LP, Energy Capital Partners II (Summit Co- Invest), LP, SMLP Holdings, LLC and each of their affiliated funds and investment vehicles and any fund manager, general partner, managing member or principal of any of the foregoing; (b) the officers, directors and management employees of any Person described in clause (a) or of Summit Parent, Summit Holdings LLC or any of the Subsidiaries of Summit Parent; and (c) any Person Controlled by any of the Persons described in any of the clauses (a) or (b). “Quarterly AC Distribution Date” has the meaning set forth in Section 5.1(b)(i). “Remaining Accordion Amount” means, at the time of determination, the Accordion Amount less all Capital Contributions made prior to such time by TES Member (or its assignee(s)) pursuant to Section 4.5. “Remaining Commitment” means, at the time of determination, with respect to each Series A Preferred Member, its Commitment, less all Capital Contributions made by such Series A Preferred Member (or its predecessor(s) in interest) prior to such time. “Remedial Sale” has the meaning set forth in Section 4.9(a). “Remedial Sale Notice” has the meaning set forth in Section 4.9(a). “Right to Compete” has the meaning set forth in Section 6.6. 18 “ROI” means with respect to each issued and outstanding Series A Preferred Unit, as of any time of determination, an amount equal to the quotient of (a) the actual pre-tax total return paid to the Holder thereof (or its predecessor(s) in interest) with respect to such Series A Preferred Unit, only as a result of cash distributions paid to such Holder thereof and such Holder’s predecessors in interest with respect to such Series A Preferred Unit pursuant to this Agreement, and (b) the Series A Preferred Issue Amount. Notwithstanding anything to the contrary in this Agreement, in no event shall any calculation of the Base Return (including in the calculations of ROI and IRR) take into account (y) any expenses of the Series A Preferred Members reimbursed by the Company or paid as an indemnity or as damages pursuant to the Preferred Purchase Agreement or any of the Other Transaction Documents or (z) any Undrawn Commitment Amount (or corresponding Undrawn Commitment Units), Transaction Amount or Structuring Amount. “Securities Act” means the Securities Act of 1933, as amended. “Series A Allocation Event” has the meaning set forth in Section 5.3(c)(iii). “Series A Non-Cash Distribution Election” has the meaning set forth in Section 5.1(c)(ii). “Series A Permitted Transferee” means, with respect to any Series A Preferred Member, any of the following: (a) (i) any Affiliate of TES Member (other than a “portfolio company” of TES Member or Affiliate of TES Member, or any Entity Controlled by such a “portfolio company”), (ii) any fund, account or Entity managed or advised by TES Member or any of its Affiliates (other than a “portfolio company” of TES Member or Affiliate of TES Member, or any Entity Controlled by such a “portfolio company”) or (iii) any limited partner, member or similar investor in any private equity fund or similar investment fund managed or advised by TES Member or any of its Affiliates and (b) other Holders of Series A Preferred Units or any Affiliate thereof (other than a “portfolio company” of such Holder or Affiliate of such Holder or any Entity Controlled by such a “portfolio company”). “Series A Preferred Director” has the meaning set forth in Section 6.2(a)(ii). “Series A Preferred Director Approval Event” means, with respect to the Company and its Subsidiaries, (a) liquidating or dissolving the Company or any of its Subsidiaries; (b) taking any action that would, or would be reasonably be expected to, result in a Bankruptcy Event of the Company or any of its Subsidiaries; (c) adopting a plan of liquidation of the Company or any of its Subsidiaries; (d) taking any action to commence any suit, case, proceeding or other action under any existing or future Law of any jurisdiction relating to bankruptcy, insolvency, reorganization or relief of debtors seeking to have an order for relief entered with respect to the Company or any of its Subsidiaries, or seeking to adjudicate the Company or any of its Subsidiaries as bankrupt or insolvent, or seeking reorganization, arrangement, adjustment, winding-up, liquidation, dissolution, composition or other relief with respect to the Company or any of its Subsidiaries; (e) appointing a receiver, trustee, custodian or other similar official for the Company or any of its Subsidiaries, or for all or any material portion of the assets of the Company or any of its Subsidiaries; or (f) making a general assignment for the benefit of the creditors of the Company or any of its Subsidiaries. “Series A Preferred Distributions” has the meaning set forth in Section 5.1(c)(i). 19 “Series A Preferred Distributions Payment Date” shall mean the date that is 21 days after the end of each fiscal quarter of the Company, unless the Board designates an earlier date. “Series A Preferred Distributions Rate” means 7.0% per annum of the Series A Preferred Issue Amount as in effect for the applicable period computed quarterly and on the basis of a 360-day year comprised of 12 equal 30-day months. “Series A Preferred Issue Amount” means $1,000. “Series A Preferred Member” means any Member owning Series A Preferred Units, which Member shall be identified as a Series A Preferred Member on Exhibit A, as such may be amended from time to time by the Board in accordance with this Agreement. “Series A Preferred Optional Redemption Date” has the meaning set forth in Section 4.8(b)(i). “Series A Preferred Optional Redemption Notice” has the meaning set forth in Section 4.8(b)(ii). “Series A Preferred Sharing Percentage” means, as to any Holder of Series A Preferred Units, as of any time of determination, the percentage obtained by dividing the number of Series A Preferred Units held by such Holder by the total number of issued and outstanding Series A Preferred Units held by all of the Holders at the time in question. “Series A Preferred Unit” means a limited liability company interest in the Company referred to in this Agreement as a “Series A Preferred Unit”, including, for the avoidance of doubt all PIK Units and Undrawn Commitment Units. “Specified Exxon Proceeds” means any proceeds as a result of (a) Exxon exercising the Equity Option (as defined in the Double E LLC Agreement) under Section 3.21 of the Double E LLC Agreement or (b) the Board of Directors of Double E electing to terminate and liquidate Double E following Exxon’s exercise of its put right under Section 3.22 of the Double E LLC Agreement. “Step-Up Rate” means an additional ___% per annum, cumulative to the Series A Preferred Distributions Rate as in effect for the applicable period, computed quarterly and on the basis of a 360-day year comprised of 12 equal 30-day months. “Structuring Amount” has the meaning given to it in the Preferred Purchase Agreement. “Subsequent Closing” has the meaning given to it in the Preferred Purchase Agreement. “Subsequent Closing Date” has the meaning given to it in the Preferred Purchase Agreement. “Subsidiary” means, with respect to any specified Entity, any corporation, association, partnership or other business entity (a) which is Controlled by such Entity and (b) the outstanding 20 Capital Stock of which is entitled to more than 50% of the distributions therefrom are held, directly or indirectly, by such Entity. “Summit Director” has the meaning set forth in Section 6.2(a)(i). “Summit Holdings LLC” means Summit Midstream Holdings, LLC, a Delaware limited liability company. “Summit Member” means Summit Midstream Permian II, LLC, a Delaware limited liability company and which is, for the avoidance of doubt, as of the Effective Date, the Common Unit Member. “Summit Parent” means Summit Midstream Partners, LP, a Delaware limited partnership, and its successors. “Summit Parent Guarantee” means the limited guarantee agreement executed by Summit Parent concurrently with the execution of this Agreement in the form attached to this Agreement as Exhibit E. “Tax Distribution Date” means any date that is two Business Days prior to the date on which U.S. federal income tax payments (including estimated income tax payments) are required to be made by calendar year individual taxpayers. “Tax Distribution Default” has the meaning set forth in Section 5.2. “Tax Year” has the meaning set forth in Section 2.6. “TES Member” means TPG Energy Solutions Anthem, L.P., a Delaware limited partnership (together with each of its assignee(s) pursuant to Section 4.5(c) and each of their respective transferees of Units in accordance with this Agreement). If, at any time, the TES Member includes more than one Person, any matter that is subject to the consent, vote, approval or other action or decision of or by the TES Member shall be determined by a majority of the outstanding Series A Preferred Units held by all Persons constituting the TES Member, unless otherwise expressly subject to another standard set forth in this Agreement. All consents, votes, approvals or other actions or decisions of the TES Member shall be in the sole and absolute judgement of such Person or Persons constituting the TES Member at the relevant time of determination. “Third Party Payor” has the meaning set forth in Section 6.5(b)(ii). “Third-Party Purchaser” has the meaning set forth in Section 4.4(b)(i). “Total Invested Capital” means, as of the time of determination, the sum of (a) the then-outstanding aggregate amount of Funded Indebtedness (including principal and interest accrued thereon) of the Company and its Subsidiaries plus (b) an amount equal to the aggregate Base Return for all issued and outstanding Series A Preferred Units plus (c) the aggregate amount of Capital Contributions made by Summit Member to the Company as of the time of determination, which, for the avoidance of doubt, shall (x) include the value of any Specified Exxon Proceeds 21 (other than those Specified Exxon Proceeds that have been distributed to or otherwise received by the Company) and (y) include any proceeds resulting from any Permitted Summit Operating Sell-Down (other than such proceeds that have been distributed to or otherwise received by the Company). “Total Invested Capital Ratio” means, as of any time of determination, the quotient (expressed as a percentage of 100%) of (a)(i) the then-outstanding aggregate amount of Funded Indebtedness (including principal and interest accrued thereon) of the Company and its Subsidiaries plus (ii) an amount equal to the aggregate Base Return for all issued and outstanding Series A Preferred Units minus (iii) Unrestricted Cash, divided by (b) Total Invested Capital. “Transaction Amount” has the meaning given to it in the Preferred Purchase Agreement. “Transfer,” “Transferred” or “Transferring” means with respect to a Person, a direct or indirect disposition, sale, assignment, transfer, gift, surrender for cancellation, exchange or pledge, or the direct or indirect grant or transfer of any economic interest, security interest, voting power or other encumbrance, or any other direct or indirect transfer of beneficial interest, whether voluntary or involuntary, by operation of Law or judicial decree and including the direct or indirect disposition, sale, assignment, transfer, gift, surrender for cancellation, exchange or pledge, or the direct or indirect grant or transfer of any economic interest, security interest, voting interest or other encumbrance or any other direct or indirect transfer of beneficial interest in such Person by a Controlling Person, including in each such case (a) as part of any liquidation of assets, (b) in connection with any merger, consolidation, exchange, recapitalization, reorganization, conversion, cancellation, redemption or repurchase transaction whether by plan, contract or right contained in a security, (c) in connection with a change of Control or (d) as a part of any reorganization pursuant to federal or state bankruptcy Laws or similar debtor relief Laws. “Treasury Regulations” means temporary and final Treasury Regulations promulgated under the Code. “Trigger Event” means the occurrence of one or more of the following events: that it intends to exercise) its put right set forth in Section 3.22 of the Double E LLC Agreement; (a) Exxon, in accordance with the terms of the Double E LLC Agreement exercises (or gives notice on such date; (b) (c) (d) the seventh anniversary of the Effective Date, if any Series A Preferred Units remain outstanding a Bankruptcy Event involving the Company or any of its Subsidiaries; prior to the In-Service Date, a Bankruptcy Event involving Summit Parent or any of its Controlled Subsidiaries (other than the Company and its Subsidiaries); (e) any material, continuing breach or default by Permian Transmission under the Double E LLC Agreement; provided, that such breach or default has not been cured (if such breach or default is susceptible of cure or remedy) within a period of 30 days beginning on the earlier of (i) the Company’s receipt of written notice of such breach or default from Exxon and (ii) 22 the date on which any Officer, Summit Director or officer or member of management of Summit Parent becomes aware of such breach or should have, in the exercise of reasonable diligence, become aware of such breach; or (f) the Company or any of its Subsidiaries takes or permits any action that requires Preferred Approval without obtaining Preferred Approval; provided, that such breach has not been cured (if such breach is susceptible of cure or remedy) within a period of 15 days beginning on the date the Company receives written notice of such breach from a Series A Preferred Member. “Undrawn Commitment Amount” has the meaning set forth in Section 4.10. “Undrawn Commitment Rate” means ___% per annum, compounded quarterly (computed on the basis of a 360-day year comprised of 12 equal 30-day months). “Undrawn Commitment Units” has the meaning set forth in Section 4.10. “Undrawn Portion” means, as of the end of each fiscal quarter of the Company, the applicable Series A Preferred Member’s then Remaining Commitment. “Units” means the units of the Company and includes the Common Units, Series A Preferred Units and any other class or series of units or other equity securities of the Company authorized and issued after the Effective Date in accordance with the terms of this Agreement. “Unrestricted Cash” means, as of the time of determination, Available Cash, other than cash proceeds received by the Company from (a) the incurrence of Funded Indebtedness and (b) the issuance of Series A Preferred Units. Section 1.2 Construction . (a) The definitions in Section 1.1 will apply equally to both the singular and plural forms of the terms defined. The rules of construction set forth in this Section 1.2 shall apply to the interpretation of this Agreement. All references in this Agreement to Exhibits, Schedules, Articles, Sections, subsections, and other subdivisions of or to this Agreement refer to the corresponding Exhibits, Schedules, Articles, Sections, subsections, and other subdivisions of or to this Agreement unless expressly provided otherwise. Titles appearing at the beginning of any Articles, Sections, subsections, and other subdivisions of or to this Agreement are for convenience only, do not constitute any part of this Agreement, and shall be disregarded in construing the language of this Agreement. The words “this Agreement,” “herein,” “hereby,” “hereunder,” and “hereof,” and words of similar import, refer to this Agreement as a whole and not to any particular Article, Section, subsection, or other subdivision of or to this Agreement unless expressly so limited. The words “this Article,” “this Section,” “this subsection,” and “this clause,” and words of similar import, refer only to the Article, Section, subsection or clause hereof in which such words occur. Wherever the words “including” and “excluding” (in their various forms) are used in this Agreement, they shall be deemed to be followed by the words “without limiting the foregoing in any respect.” Unless expressly provided to the contrary, if a word or phrase is defined, its other grammatical forms have a corresponding meaning. The words “shall” and “will” have the equal force and effect. The word “or” means and includes “and/or”. All references to “$” or 23 “Dollars” shall be deemed references to United States Dollars. Each accounting term not defined in this Agreement will have the meaning given to it under GAAP as in effect as of the Effective Date. Pronouns in masculine, feminine, or neuter genders shall be construed to state and include any other gender. Reference in this Agreement to any federal, state, local, or foreign Law shall be deemed to also refer to all rules and regulations promulgated thereunder, unless the context requires otherwise, and, unless expressly provided to the contrary, reference in this Agreement to any agreement, instrument, or Law means such agreement, instrument, or Law as from time to time amended, modified, or supplemented, including, in the case of agreements or instruments, by waiver or consent and, in the case of Laws, by succession of comparable successor Laws. If any period of days referred to in this Agreement shall end on a day that is not a Business Day, then the expiration of such period shall automatically be extended until the end of the first succeeding Business Day. References to a Person are also to its permitted successors and permitted assigns. (b) Each Member acknowledges that it and its attorneys and advisers have been given an equal opportunity to negotiate the terms and conditions of this Agreement and that any rule of construction to the effect that ambiguities are to be resolved against the drafting Party or any similar rule operating against the drafter of an agreement shall not be applicable to the construction or interpretation of this Agreement. Section 2.1 Continuation of the Company ARTICLE II ORGANIZATION . The Company was organized as a Delaware limited liability company by the filing of the Certificate in the office of the Secretary of State of the State of Delaware pursuant to the Act on December 17, 2019. The Members desire to continue the Company for the purposes and upon the terms and conditions of this Agreement. Except as provided in this Agreement, the rights, duties and liabilities of each Member shall be as provided in the Act. Section 2.2 Name . The name of the Company is SUMMIT PERMIAN TRANSMISSION HOLDCO, LLC. Section 2.3 Registered Office; Registered Agent . The registered office of the Company in the State of Delaware will be the initial registered office designated in the Certificate or such other office (which need not be a place of business of the Company) as the Board may designate from time to time in the manner provided by Law. The registered agent of the Company in the State of Delaware will be the initial registered agent designated in the Certificate, or such other Person or Persons as the Board may designate from time to time in the manner provided by Law. Section 2.4 Principal Office . The principal office of the Company will initially be at 1790 Hughes Landing, Suite 500, The Woodlands, Texas 77380, or such other location as the Board may designate from time to time, which need not be in the State of Delaware. The Company may have such other offices as Board may determine to be appropriate. Section 2.5 Purpose; Powers . The Company has been formed for the object and purpose of, and the nature of the business to be conducted and promoted by the Company is to, (a) 24 own, directly or indirectly, issued and outstanding Capital Stock of Permian Transmission and fund Permian Transmission’s capital commitment obligations to Double E (the “Business”) and (b) engage in such other activities incidental or ancillary thereto as the Board deems necessary or advisable, in each case upon the terms and conditions set forth in this Agreement. Section 2.6 Fiscal Year; Fiscal Quarter . The fiscal year of the Company (the “Fiscal Year”) for financial statement purposes will end on December 31st unless otherwise determined by the Board. The tax year of the Company (the “Tax Year”) for income tax purposes will end on December 31st unless otherwise determined by the Board or as required under the Code. The fiscal quarters of the Company shall be the three-month periods commencing on January 1, April 1, July 1 and October 1 of any Fiscal Year and ending on the next March 31, June 30, September 30 and December 31, respectively. For so long as any Series A Preferred Units remain outstanding, the Company shall not change the Tax Year or the fiscal quarters as provided in this Section 2.6 without first obtaining Preferred Approval. Section 2.7 Foreign Qualification Governmental Filings . Prior to the Company’s conducting business in any jurisdiction other than the State of Delaware, the Board will cause the Company to comply, to the extent procedures are available, with all requirements necessary to qualify the Company as a foreign limited liability company in such jurisdiction. Each Officer is authorized, on behalf of the Company, to execute, acknowledge, swear to and deliver all certificates and other instruments as may be necessary or appropriate in connection with such qualifications. Further, each Member will execute, acknowledge, swear to and deliver all certificates and other instruments that are necessary or appropriate to qualify, or, as appropriate, to continue or terminate such qualification of, the Company as a foreign limited liability company in all such jurisdictions in which the Company may conduct business. Section 2.8 Term . The Company commenced on the date the Certificate was filed with the Secretary of State of the State of Delaware, and will continue in existence until terminated in accordance with this Agreement. ARTICLE III MEMBERS; DISPOSITIONS Section 3.1 Members . As of the Effective Date, the Common Unit Members and Series A Preferred Members executing this Agreement are the sole Members of the Company. The names, addresses, number and class or series of Units held by the Members as of the Effective Date are set forth on Exhibit A attached hereto and incorporated in this Agreement. Notwithstanding anything to the contrary in this Agreement (including Section 6.8), the Board is hereby authorized to complete or amend Exhibit A from time to time to accurately reflect (a) the admission of additional Members, (b) the withdrawal of a Member, (c) the change of address of a Member, (d) the number and classes or series of Units held by a Member and (e) other information called for by Exhibit A, without the need for any approval by any Member. Such completion, correction or amendment shall be made from time to time as and when the information called for by Exhibit A requires completion, correction or amendment in accordance with the terms of this Agreement. The Members shall not have any right to act on behalf of or with respect to the Company except to the extent expressly authorized to do so by the provisions of this Agreement (including pursuant to Section 4.9) or by action of the Board. Any Person admitted to the Company 25 as a Member following the Transfer of Units from a Holder of Units shall succeed to all of the rights, duties and obligations of its transferor with respect to such Units under this Agreement. Section 3.2 Restrictions on the Transfer of Units . (a) General . The Company and the Members agree that any Transfer of Units by any Holder of Units is subject to the restrictions on Transfer set forth in this Article III. Any attempted Transfer of any Units by a Holder of Units other than in accordance with this Section 3.2 is void and will not be recognized by the Company and is subject to the provisions of Section 3.5. (b) Transfers of Common Units (i) . The Common Units may not be Transferred by any Holder thereof prior to the receipt of FERC Approval. Subject to this Section 3.2(b) and Section 3.2(d), on or after FERC Approval, Common Units may be Transferred only if such Transfer constitutes a Permitted Summit Holdco Sell-Down. Any such Transfer permitted by the foregoing sentence may be in any amount by the Holder thereof to any Person or Persons, subject further to any restrictions, or other terms and conditions, the Board deems necessary or appropriate to impose on the transferee of Common Units in its sole discretion. Notwithstanding the foregoing, in no event shall any Holder or Holders of Common Units be entitled to Transfer any Common Units if such Transfer would constitute a Change of Control unless such Transfer and the related Change of Control is conducted in strict compliance with Section 6.8(b)(xii) and Section 10.2(c). (c) Transfers of Series A Preferred Units . Subject to Section 3.2(d), a Transfer of Series A Preferred Units may be made by any Holder thereof: prior to the Funding Termination Date, (A) to any Series A Permitted Transferee or (B) with the prior written consent of the Board (not to be unreasonably withheld, conditioned or delayed), to any other Person; and (i) (ii) on or after the Funding Termination Date, to any Person if (A) such transferee is not (immediately prior to such Transfer) a Competitor and (B) such Transfer (1) involves Series A Preferred Units with an aggregate Series A Preferred Issue Amount of at least $5,000,000 or (2) constitutes all of the Series A Preferred Units which such Transferring Holder then holds. (d) Conditions to Transfer . Notwithstanding any other provision of this Agreement, no Transfer of Units may be effected by any Person unless: (i) such Transfer is in compliance with the Securities Act and all applicable state securities Laws and such Transfer is either exempt from the requirements of the Securities Act and the applicable securities Laws of any state or such registration requirements have been complied with, and (ii) such Transfer would not cause the Company to be treated as an association or “publicly traded partnership” taxable as a corporation and would not make the Company ineligible for “safe harbor” treatment under Code Section 7704 and the Treasury Regulations promulgated thereunder. The Board will determine in Good Faith whether the foregoing conditions have been satisfied and may determine to waive any such conditions to the extent permitted by applicable Law. 26 Section 3.3 Issuance of Units; Additional Members . (a) Subject to Section 6.8 and Section 11.5, upon the approval of the Board, Units may be authorized and issued to such Persons as determined by the Board on such terms and conditions as the Board may determine at the time of admission, which may include making a Capital Contribution, and such Persons, if not already Members, may be admitted to the Company as Members pursuant to this Section 3.3. Subject to Section 6.8, the Company may provide for the creation of different classes or series of Units having different rights, powers and duties. (b) A transferee of Units pursuant to Section 3.2 or a recipient of the issuance of new Units pursuant to Section 3.3(a) that is not already a Member shall be admitted as a Member if and when each of the following occur: (i) all of the applicable conditions set forth in this Article III to such Transfer or issuance have been met or waived by the Board and (ii) such transferee or recipient agrees to be bound by the terms of this Agreement by executing and delivering (together with such Person’s spouse, if applicable) an Adoption Agreement. (c) Subject to Section 3.2(b), if any Person acquires Units from a Holder of Units in a Transfer, notwithstanding such Person’s failure to execute an Adoption Agreement in accordance with Section 3.3(b), whether such Transfer resulted by operation of Law or otherwise, such Person and such Units shall be subject to this Agreement, including Section 3.5, in the same manner as when held by the transferor. Section 3.4 Liability to Third Parties . No Member, Director or Officer will have any personal liability for any obligations or liabilities of the Company, whether such liabilities arise in contract, tort or otherwise, except to the extent that any such liabilities or obligations are expressly assumed in writing by such Member, Director or Officer. Section 3.5 Rights and Obligations of Transferee . A transferee of Units shall not have any rights of a Member unless and until such transferee is admitted as a Member pursuant to Section 3.3, but shall be entitled to the right to receive allocations of income, gains, losses, deductions, credits, and similar items and distributions to which the transferor of such Units would otherwise be entitled to the extent such items are Transferred to such transferee, and shall be subject to the obligations of a Holder of the class of Units Transferred to such transferee and bound by the provisions of Section 3.2, Section 7.3, Section 11.1, Section 11.2, Section 11.3, Section 11.4, Section 11.7, Section 11.8, Section 11.9, Section 11.11, Section 11.12, Section 11.15 and Section 11.16 as though such transferee was a Holder of the class of Units Transferred to such transferee. Section 3.6 Responsibilities of the Members . (a) Without limiting the generality of Section 3.6(b), but subject to the second sentence of this Section 3.6(a), each Member (and its respective Affiliates and Subsidiaries) shall be permitted to engage, directly or indirectly, in any opportunity, transaction, venture or other arrangement related to oil and natural gas gathering and processing activities of any kind and in any geographic location, without any duty or obligation to account to any of the other Members or the Company in connection therewith. Neither Summit Member nor Summit Parent (nor any of their respective Subsidiaries other than the Company and its Subsidiaries) shall engage in any 27 opportunity, transaction, venture or other arrangement related to the development or construction of capital assets that would reasonably be expected to expand the pipeline system or capacity of the Double E Pipeline unless such opportunity, transaction, venture or other arrangement is pursued through the Company or Double E. (b) Except as set forth in the second sentence of Section 3.6(a), and without limiting Section 6.6, each Member and its Affiliates may engage, directly or indirectly, without the consent or approval of any other Members, the Board, the Company or any other Person, in the business conducted by such Member and its Affiliates as of the Effective Date and in any other business, business opportunities, transactions, ventures or other arrangements of any nature or description, independently or with others, including business of a nature that may be competitive with or the same as or similar to the business conducted by the Company, regardless of geographic location, all without any duty or obligation to account to the other Members or the Company in connection therewith. Nothing in this Agreement is intended to create a joint venture, agency or other relationship creating fiduciary or quasi-fiduciary duties or similar duties and obligations (except as otherwise expressly provided by this Agreement or by Law) or subject any Member to joint and several or vicarious liability or to impose any duty, obligation or liability that would arise therefrom with respect to either or both of the Members or the Company. Notwithstanding anything to the contrary in this Agreement, but subject to the second sentence of Section 3.6(a), (i) the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Member or its Affiliates, (ii) none of the Members that (directly or through an Affiliate) acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Company shall have any duty to communicate or offer such opportunity to the Company or the other Members, and such Member shall not be liable to the Company, to the other Members or any other Person for breach of any fiduciary or other duty by reason of the fact that such Member pursues or acquires such opportunity or information, and (iii) neither the Company nor any Member shall have any right, by virtue of this Agreement, to share or participate in such other businesses, investments or activities of a Member or to the income or proceeds derived therefrom. Section 3.7 Representations and Warranties of the Members . By executing and delivering this Agreement, each Member, as of the Effective Date, represents and warrants to the Company and each other Member that the following statements are true and correct as of the Effective Date and as of each date on which such Member makes a Capital Contribution (as applicable): to resale or distribution thereof other than in compliance with all applicable securities Laws and this Agreement. (a) Such Member’s Units are being held for its own account solely for investment and not with a view of its jurisdiction of organization. If such Member is a natural person, such Member has full legal capacity. (b) If such Member is an Entity, such Member is duly organized and validly existing under the Laws (c) None of the execution, delivery and performance of this Agreement by such Member or the consummation by such Member of the acquisition of Units (i) conflicts or will conflict with or constitutes or will constitute a violation of any of its organizational documents, (ii) conflicts or will conflict with or constitutes or will constitute a breach or violation of, or a 28 default (or an event which, with notice or lapse of time or both, would constitute such a default) with respect to any material obligations under any material agreement to which such Member is a party or (iii) violates or will violate any Law or any order, judgment, decree or injunction of any Governmental Entity applicable to Member except, solely in the case of clauses (ii) or (iii), for such conflicts, breaches, violations or defaults as would not prevent the acquisition by Member of the Units or materially impair such Member’s ability to perform its obligations under this Agreement or any of the Other Transaction Documents. This Agreement has been duly executed and delivered by such Member and constitutes a valid and binding agreement of such Member, enforceable against such Member in accordance with its terms, subject to the Enforceability Exceptions. (d) Such Member acknowledges that the offering and sale of the Units have not been, and will not be registered under the Securities Act, and are being made in reliance upon federal and state exemptions for transactions not involving a public offering. In furtherance thereof, such Member represents and warrants that it is an “Accredited Investor” (as defined in Regulation D promulgated under the Securities Act) and such Member has sufficient knowledge and experience in financial and business matters so as to be capable of evaluating the risks of its investment in the Units. Such Member understands and agrees that it will not take any action that could have an adverse effect on the availability of the exemption from registration provided by Regulation D promulgated under the Securities Act and other applicable securities Laws with respect to the offer and sale of the interests in the Company. In connection with the purchase of Units, such Member meets all applicable suitability standards imposed on it by applicable Law. (e) Such Member has been given the opportunity to (i) ask questions of, and receive answers from, the Company concerning the terms and conditions of the Units and other matters pertaining to an investment in the Company and (ii) obtain any additional information necessary to evaluate the merits and risks of an investment in the Company that the Company can acquire without unreasonable effort or expense. In considering its investment in the Units, such Member has evaluated for itself the risks and merits of such investment, and is able to bear the economic risk of such investment, including a complete loss of capital. Such Member has carefully considered and has, to the extent it believes necessary, discussed with legal, tax, accounting and financial advisors the suitability of an investment in the Company in light of its particular tax and financial situation, and has determined that the Units are a suitable investment for such Member. (f) No Person has acted directly or indirectly as a broker, finder or financial advisor for such Member in connection with the negotiations related to the offering and sale of Units, and no Person is entitled to any fee or commission or like payment for acting as a broker, finder or financial advisor based in any way on any agreement, arrangement or understanding made by or on behalf of such Party. Section 3.8 Member Action . Except as expressly otherwise provided in this Agreement, all actions and decisions of the Common Unit Members required hereunder in their capacity as such shall require approval of Common Unit Members holding more than 50% of the Common Units. If there is any matter that requires the approval of the Board, such approval will be sufficient to authorize the Company to take that action and no further vote or approval of the Members of the Company will be necessary or required under the terms of this Agreement, except as expressly set forth in this Agreement. Except as expressly otherwise provided in this 29 Agreement, all actions and decisions of the Series A Preferred Members required hereunder in their capacity as such shall require Preferred Approval. Any matter requiring the consent, vote, approval or other action or decision of or by any Member or Members pursuant to this Agreement (including any matter that requires Preferred Approval) may be taken without a meeting, without prior notice and without a vote, by a consent in writing, setting forth such consent, vote, approval or other action or decision, and signed by the Member or Members required to grant such consent, vote, approval or other action or decision. ARTICLE IV INTERESTS; CAPITAL CONTRIBUTIONS Section 4.1 Interests . Each Member’s Interest in the Company will be represented by its Capital Account and by Units issued by the Company to such Member. The two initial classes of Units are Common Units and Series A Preferred Units. The number of Common Units and Series A Preferred Units issued to the Members as of the Effective Date is set forth on Exhibit A. The Board may, subject to Article III, Section 6.8 and Section 11.5, create additional series or classes of Units through subdivision or by issuance of Units of such class or series. The obligations of each Member hereunder shall be several and not joint, and no Member shall be obligated to make any of the Capital Contributions of another Member. The provisions of this Agreement together fix the preferences, rights, powers and duties of the Holders of the Common Units and the Series A Preferred Units, as applicable. Notwithstanding anything in this Agreement to the contrary, the Company will not be entitled to sell or issue any Series A Preferred Units to any other Person except in accordance with this Article IV, Section 5.1(c) or Section 5.2. Section 4.2 Effective Date Transactions; Subsequent Closing . On the Effective Date, the Series A Preferred Members have made the Capital Contributions set forth on Exhibit A as their initial Capital Contribution to the Company pursuant to this Agreement and the Preferred Purchase Agreement. (a) opposite each such Common Unit Member’s name on Exhibit A. (b) On the Effective Date, the Common Unit Members own the number of Common Units set forth purchase 10,000 Series A Preferred Units pursuant to Section 2.1(c) and (d) of the Preferred Purchase Agreement. (c) On the Subsequent Closing Date at the Subsequent Closing, the Series A Preferred Members will Section 4.3 Additional Capital Contributions by Series A Preferred Members . (a) Subject to the terms and conditions of this Agreement and the Preferred Purchase Agreement, the Series A Preferred Members have subscribed for, and upon valid delivery by the Company of an Additional Funding Request, in compliance with this Agreement and the Preferred Purchase Agreement, to each Series A Preferred Member prior to the Funding Termination Date will fund, additional Capital Contributions to the Company up to the amount of each Series A Preferred Member’s Commitment in accordance with Article III of the Preferred Purchase Agreement. In no event shall any Series A Preferred Member be required to fund additional Capital Contributions after its Remaining Commitment has been reduced to $0.00. 30 (b) Each Additional Funding Request shall (A) state the purpose of the Additional Funding Request, (B) be in an amount not less than $10,000,000 and (C) be due and payable not less than 15 Business Days after the date of receipt by the Series A Preferred Members of notice of such Additional Funding Request. Without limiting the foregoing, TES Member will use good faith efforts to fund its payment obligation in respect of an Additional Funding Request within 10 Business Days after the date of receipt by the Series A Preferred Members of notice of such Additional Funding Request to the extent TES determines in its sole discretion that it has access to immediately available funds from its revolving line of credit. (c) Each Series A Preferred Member shall be permitted to assign (without the consent of the Company, the Board or any other Person) all or a portion of its rights and obligations with respect to each Additional Funding Request to one or more Persons who constitute Series A Permitted Transferees; provided, that (i) such assigning Series A Preferred Member shall give notice to the Company of such assignment, (ii) such transferee or recipient agrees to be bound by the terms of this Agreement by executing and delivering (together with such Person’s spouse, if applicable) an Adoption Agreement, and (iii) such Series A Preferred Member shall remain obligated in the event such transferee breaches any such assigned obligations with respect to any such Additional Funding Request. (d) Upon receipt by the Company of any additional Capital Contributions made by a Series A Preferred Member in accordance with Section 4.3(a) (or its assignee in accordance with Section 4.3(c)), such Series A Preferred Member or its assignee, as applicable, shall be issued a number of Series A Preferred Units equal to the quotient of (x) the amount of such additional Capital Contribution divided by (y) the Series A Preferred Issue Amount. After the Funding Termination Date, no Series A Preferred Member (or any assignee in accordance with Section 4.3(c)) shall have any obligation to purchase any Series A Preferred Units and the Company shall not issue any Additional Funding Requests. (e) (f) Notwithstanding anything to the contrary in this Agreement or any Other Transaction Document, in no event shall any Series A Preferred Member be obligated to make additional Capital Contributions to the Company at any time in which any Bankruptcy Event (i) has occurred and, at the time of such Additional Funding Request, is pending with respect to Summit Parent or any of its Controlled Affiliates (other than the Company or any of its Subsidiaries) or (ii) has occurred (regardless of whether such Bankruptcy Event is pending at the time of such Additional Funding Request) with respect to the Company or any of its Subsidiaries. Section 4.4 Failure to Contribute . (a) If any Series A Preferred Member fails to make an additional Capital Contribution in accordance with Section 4.3(a) in the full amount required by any Additional Funding Request (assuming there is no good faith dispute regarding whether the conditions set forth in Section 3.2(a) of the Preferred Purchase Agreement were satisfied or waived with respect to such Additional Funding Request) on the due date therefor, a “Preferred Payment Default” shall be deemed to have occurred in the amount of the Default Amount. 31 (b) In the event a Preferred Payment Default has occurred: (i) the Company shall have the right, but not the obligation, to sell additional Series A Preferred Units to a third party (a “Third-Party Purchaser”), at the Series A Preferred Issue Amount per Series A Preferred Unit and otherwise on the same terms as the Series A Preferred Units held by the defaulting Series A Preferred Member (such Member, a “Defaulting Preferred Member”), equal in number to the number of Series A Preferred Units that would have been issued to the Defaulting Preferred Member in exchange for receipt of the amount of such Capital Contribution not paid (the “Default Amount”); Commitment with respect to the Defaulting Preferred Member to be reduced to $0.00; and (ii) the Company shall have the right, but not the obligation, to cause the Remaining (iii) the Company may, at its option, pursue any other rights and remedies available to it at law or in equity against the Defaulting Preferred Member pursuant to the Preferred Purchase Agreement or this Agreement, including (x) the right to specific performance of such Defaulting Preferred Member’s obligation to make such additional Capital Contribution and (y) pursuing a claim for actual damages of the Company or the Summit Member resulting from such Preferred Payment Default. Section 4.5 Accordion Feature . (a) From time to time (x) after TES Member’s Remaining Commitment has been reduced to $0.00 and (y) prior to the Funding Termination Date, the Board shall have the right, but not the obligation, to deliver written notice (each, an “Accordion Capital Call”) to TES Member giving TES Member the option to fund an amount up to the Accordion Amount as additional Capital Contributions to the Company in exchange for additional Series A Preferred Units issued by the Company (such additional Series A Preferred Units issued, the “Accordion Units”); provided, that: (i) TES Member is not required to make any additional Capital Contributions pursuant to this Section 4.5 and any purchase by TES Member of any Accordion Units offered for purchase under an Accordion Capital Call shall be at TES Member’s sole option; and (ii) the aggregate amount of Accordion Units offered for purchase under this Section 4.5(a) shall not exceed the Accordion Amount without Preferred Approval. (b) Each notice of an Accordion Capital Call shall (i) state the purpose of the Accordion Capital Call, which purpose must be in furtherance of the Business, (ii) be in an amount not less than $20,000,000; provided, that such $20,000,000 limitation shall not apply if at such time the Accordion Amount less all Accordion Units purchased under this Section 4.5 is less than $20,000,000, in which case the amount of such Accordion Capital Call shall equal such lesser amount in its entirety and (iii) be due and payable not less than 15 Business Days after the date of receipt by TES Member of notice of such Accordion Capital Call. Notwithstanding anything to the contrary in this Agreement, TES Member shall be permitted to assign (in its sole discretion and without the consent of the Company, the Board or any other Person) all or a portion of its rights and obligations with respect to all or any (c) 32 portion of the Accordion Amount to one or more Persons who constitute Series A Permitted Transferees of TES Member; provided, that (i) TES Member shall give notice to the Company of such assignment; (ii) such transferee or recipient agrees to be bound by the terms of this Agreement by executing and delivering (together with such Person’s spouse, if applicable) an Adoption Agreement and (iii) TES Member shall remain obligated in the event such transferee breaches any such assigned obligations with respect to any portion of the Accordion Amount. (d) Upon receipt by the Company of any additional Capital Contributions made by TES Member in accordance with Section 4.5(a) (or its assignee in accordance with Section 4.5(c)), TES Member or its assignee, as applicable, shall be issued a number of Accordion Units equal to the quotient of (x) the amount of such additional Capital Contribution paid divided by (y) the Series A Preferred Issue Amount. (e) If TES Member declines to purchase any Accordion Units offered for purchase under an Accordion Capital Call in accordance with Section 4.5(a), the Company may, at the election of the Board, offer and sell the remaining Accordion Units contemplated by such Accordion Capital Call to any Third-Party Purchaser without the need for any consent or approval of any other Member under this Agreement (including under Section 6.8); provided, however, such issuance shall be on terms and conditions no more favorable to such Third-Party Purchaser than those terms and conditions set forth in the Accordion Capital Call or upon which TES Member acquired any other Series A Preferred Units in accordance with this Agreement and the Preferred Purchase Agreement. For the avoidance of doubt, TES Member’s election not to purchase Accordion Units offered under an Accordion Capital Call shall not constitute a waiver of TES Member’s right to purchase Accordion Units offered in a subsequent Accordion Capital Call and any Accordion Units offered in a subsequent Accordion Capital Call shall be first offered to TES Member in accordance with Section 4.5(a). (f) Notwithstanding anything to the contrary in this Agreement or any Other Transaction Document, in no event shall the Company be authorized to issue or sell any Accordion Units at any time in which any Bankruptcy Event (i) has occurred and, at the time of such Accordion Capital Call, is pending with respect to Summit Parent or any of its Controlled Affiliates (other than the Company or any of its Subsidiaries) or (ii) has occurred (regardless of whether such Bankruptcy Event is pending at the time of such Accordion Capital Call) with respect to the Company or any of its Subsidiaries. Section 4.6 Capital Accounts . The Company will maintain for each Member owning any Units a separate Capital Account. Section 4.7 Withdrawal or Return of Capital . Except as provided in this Agreement, no Member is entitled to the return of or has the right to withdraw any part of its Capital Contribution from the Company prior to its liquidation and termination pursuant to Article X. No Member is entitled to be paid interest in respect of either its Capital Account or its Capital Contributions. Any unrepaid Capital Contribution is not a liability of the Company or of the other Members. A Member is not required to contribute or to lend any cash or property to the Company to enable the Company to return any other Member’s Capital Contributions. 33 Section 4.8 Redemption . (a) Mandatory Redemption. At any time (i) after February 28, 2022 (but only if FERC Approval has not been obtained by such date), (ii) after the occurrence of a Trigger Event or (iii) if the Company fails to obtain the Exxon Consent on or prior to January 22, 2020 (or if Exxon affirmatively rejects in writing to provide the Exxon Consent), then each Holder of Series A Preferred Units may, at its sole election by delivering a written notice to the Company, require the Company to, and the Company shall, purchase and redeem all (but not less than all) of the Series A Preferred Units then held by such Holder in cash for an amount equal to (x) in the case of a redemption resulting from an event described in clause (i) or (ii) of this Section 4.8(a), the Base Return for each such Series A Preferred Unit on the date of redemption and (y) in the case of a redemption resulting from an event described in clause (iii) of this Section 4.8(a), the Series A Preferred Issue Amount for each Series A Preferred Unit on the date of redemption, which in each case shall occur on the date that is 10 Business Days following the delivery of such written notice from such Holder to the Company (or such earlier date as may be agreed to by such Holder and the Company). The Company shall use such capital legally available to it and in compliance with any applicable covenants in its Funded Indebtedness permitted under this Agreement, including Section 6.9, to fulfill the Company’s obligations set forth in this Section 4.8(a). As a guarantee of the Company’s obligations under this Section 4.8(a), Summit Parent has caused the Summit Parent Guarantee to be executed and delivered to the Company and the Series A Preferred Members concurrently with the execution of this Agreement. (b) Optional Redemption. (i) At any time, and from time to time, the Company may, subject to applicable Law and this Section 4.8(b), redeem the Series A Preferred Units in cash, in whole or in part, from any source of funds legally available for such purpose. Subject to Section 4.8(b)(ii), any such redemption shall occur on a date set by the Company in its sole discretion (such date, the “Series A Preferred Optional Redemption Date”). Subject to applicable Law, the Company shall effect any such redemption pursuant to this Section 4.8(b) by paying cash for each Series A Preferred Unit to be redeemed in an amount equal to the then applicable Base Return with respect to such Series A Preferred Unit. The Base Return shall be paid by the Company to the Holders of the Series A Preferred Units to be redeemed on the Series A Preferred Optional Redemption Date pursuant to wiring instructions to be provided by Holder of such Series A Preferred Units to the Company at least one Business Day prior to the Series A Preferred Optional Redemption Date. (ii) The Company shall give notice of its election to redeem Series A Preferred Units pursuant to this Section 4.8(b) not less than three Business Days before the scheduled Series A Preferred Optional Redemption Date, to the Holders of Series A Preferred Units as such Holders’ names appear on Exhibit A at the address of such Holders shown therein. Such notice (the “Series A Preferred Optional Redemption Notice”) shall state: (A) the Series A Preferred Optional Redemption Date, (B) the number of Series A Preferred Units to be redeemed from each such Holder and (C) the Base Return as to such Series A Preferred Units as of the Series A Preferred Optional Redemption Date. 34 (iii) If the Company elects to redeem less than all of the outstanding Series A Preferred Units, the number of Series A Preferred Units to be redeemed shall be determined by the Company, and such Series A Preferred Units shall be redeemed by the Company pro rata across all Holders of Series A Preferred Units (based on such Holders’ respective Series A Preferred Sharing Percentages), with such adjustments as are appropriate, in the Board’s discretion, in order to avoid redemption of fractional Series A Preferred Units; provided, that except for any redemptions made in accordance with Section 5.1(b), each such redemption by the Company shall be for an aggregate amount of Series A Preferred Units involving at least $10,000,000 based on the Base Return as to the Series A Preferred Units the Company desires to redeem (the “Minimum Optional Redemption Amount”) or, if the Base Return as to all of the outstanding Series A Preferred Units is less than the Minimum Optional Redemption Amount, then all outstanding Series A Preferred Units. The Series A Preferred Units not redeemed shall remain outstanding and entitled to all the rights and preferences provided in this Agreement. Section 4.9 Remedial Sale . (a) In addition to, and not in limitation of, the rights set forth in Section 4.8(a), and subject to Section 6.8(b)(xiv), following the occurrence of a Trigger Event, the Series A Preferred Members (acting by Preferred Approval) shall have the right to cause the Company to pursue and consummate a transaction that results in the Base Return with respect to each then outstanding Series A Preferred Unit being paid in cash to the Holder of such Series A Preferred Unit at the consummation of such transaction (a “Remedial Sale”) by delivering written notice thereof (a “Remedial Sale Notice”) to the Company (the Member or Members delivering such notice, collectively the “Initiating Member”). A Remedial Sale may involve a sale of any or all of the equity interests or assets of the Company or its Subsidiaries (other than any sale or other transaction, including a sale of assets of Double E, that (i) would be in violation of the express terms of the Double E LLC Agreement or (ii) would require the consent or approval of the other members of Double E under the Double E LLC Agreement and which is completed without first obtaining such consent or approval). (b) Following delivery of a Remedial Sale Notice, the Board shall identify, manage, control, negotiate, structure (following consultation with the Series A Preferred Members), approve and otherwise pursue such Remedial Sale, which Remedial Sale may be structured, accomplished and implemented as may be determined by the Board (following consultation with the Series A Preferred Members); provided, however, without limiting any rights of the Holders of Series A Preferred Units set forth in Section 6.8(b)(xiv), the Company shall not enter into any agreement with respect to a Remedial Sale without the prior written approval of the TES Member (which approval shall not be unreasonably withheld, conditioned or delayed). The Board (i) shall manage the business and affairs of the Company primarily with a view toward the consummation of such Remedial Sale as soon as reasonably practicable following the exercise of such right and (ii) shall, and shall cause the Company to, take such actions as reasonably necessary to consummate a Remedial Sale, including (A) engaging a nationally recognized independent investment banker who is reasonably acceptable to the Series A Preferred Members to advise on and conduct such Remedial Sale and (B) Summit Parent agrees to cooperate, and to cause employees of Summit Parent to cooperate, (including by participating in management 35 presentations, preparing marketing materials and making diligence materials available in an electronic data room) in any marketing process in connection with any proposed Remedial Sale. (c) If the Company does not consummate a Remedial Sale approved or deemed approved by the Series A Preferred Members within six months of the date of the Remedial Sale Notice, then instead of the Board, the Initiating Member shall (i) engage, on behalf of the Company, an independent investment bank to advise on and conduct the sale and (ii) identify, manage, control, negotiate, structure (following consultation with the Company and the other Series A Preferred Members) and otherwise pursue such Remedial Sale, which Remedial Sale may be structured, accomplished and implemented as may be determined by the Initiating Member (following consultation with the Company and the other Series A Preferred Members). The Series A Preferred Members shall keep the Board reasonably informed of the Remedial Sale process. The Board (A) shall manage the business and affairs of the Company primarily with a view toward the consummation of such Remedial Sale as soon as reasonably practicable following the exercise of such right and (B) shall, and shall cause the Company to, take such actions as the Initiating Member reasonably requests in connection with any proposed Remedial Sale. (d) If the Initiating Member delivers a Remedial Sale Notice in accordance with Section 4.9(a), each Member shall (i) take all actions reasonably necessary to cooperate with the Initiating Member, the other Series A Preferred Members, the Company and the Board in working toward the consummation of a Remedial Sale, (ii) raise no objections against any Remedial Sale that (x) in the case of Section 4.9(b) is approved by the Board and the TES Member or (y) in the case of Section 4.9(c) is approved by the Initiating Member and (iii) to the extent necessary or desirable to effect the consummation of such Remedial Sale, that (x) in the case of Section 4.9(b) is approved by the Board and the TES Member, vote for and consent to, such Remedial Sale or (y) in the case of Section 4.9(c) is approved by the Initiating Member, vote for and consent to, and cause its appointee(s) to the Board to vote for and consent to, such Remedial Sale; provided, however, if the Company receives more than one offer to consummate a Remedial Sale, the Holders of Series A Preferred Units shall be deemed to have approved the offer for a Remedial Sale that results in the highest enterprise value of the Company, subject to the satisfaction of the requirements set forth in this Section 4.9. If the Remedial Sale is structured as a (x) merger, consolidation or sale of assets, each Member shall waive any dissenters’ rights, appraisal rights or similar rights in connection with such merger, consolidation or sale of assets or (y) sale of Units, each Member shall agree to sell all of its Units or rights to acquire Units on the terms and conditions reasonably approved by the Initiating Member or in the case of Section 4.9(b), the Board and the TES Member, and that are customary for such transaction. Notwithstanding anything in this Section 4.9 to the contrary, in connection with any Remedial Sale, without the prior written consent of such Holder of Series A Preferred Units in no event shall any Holder of Series A Preferred Units be subject to any post-closing obligations, including indemnification obligations, or to any non-compete, no contact, non-solicit or other restrictive covenants (other than a confidentiality covenant on terms reasonably acceptable to each Holder of Series A Preferred Units), nor shall Summit Parent or its Subsidiaries (other than the Company and its Subsidiaries) be subject to any post-closing restriction on its ability to engage in the oil and natural gas gathering and processing business without the prior written consent of Summit Parent. 36 In any Remedial Sale, the consideration received by the Company shall be allocated and distributed to each Member in accordance with Section 10.2(b) after all the liabilities of the Company have been satisfied in full or provided for. (e) expenses are incurred for the benefit of all Holders and are not otherwise paid by the acquiring party. (f) The Company shall bear the costs and expenses of any Remedial Sale to the extent such costs and (g) For the avoidance of doubt, notwithstanding anything herein to the contrary, in no event shall TES Member be required to consent to the consummation of any Remedial Sale that does not result in the satisfaction of the Base Return in cash or that imposes obligations on TES Member after the closing of such Remedial Sale, nor shall the Company consummate any such Remedial Sale without the consent of TES Member. Section 4.10 Undrawn Commitment Amount . The Company shall pay to each Series A Preferred Member, within 21 days after the end of each fiscal quarter, an amount (the “Undrawn Commitment Amount”) equal to the Undrawn Commitment Rate of such Series A Preferred Member’s Undrawn Portion. The Undrawn Commitment Amount may, at the discretion of the Board, be paid to each Series A Preferred Member (a) in cash or (b) by issuing a number of additional Series A Preferred Units in an amount equal to the quotient of (i) the Undrawn Commitment Amount divided by (ii) the Series A Preferred Issue Amount to such Series A Preferred Member (the “Undrawn Commitment Units”); provided that if, with respect to any fiscal quarter, the Company elects to satisfy any Undrawn Commitment Amount using both the forms of consideration described in the preceding clauses (a) and (b), the Company shall pay each Series A Preferred Member pro rata portions of each such form of consideration (based on each such Series A Preferred Member’s Undrawn Commitment Amount in respect of the relevant fiscal quarter). ARTICLE V DISTRIBUTIONS AND ALLOCATIONS Section 5.1 Distributions . Generally. Subject to Section 5.1(b), Section 5.1(c), Section 5.2 and Article X, all Available Cash shall be retained by the Company unless otherwise agreed by the Board and consented to by Preferred Approval in accordance with Section 6.8(b)(iii). (a) (b) Distributions of Available Cash. (i) The Company shall not make any distributions among the Members except as provided in Section 5.1(c), Section 5.2, and Article X; provided that, (A) the Company may make distributions among the Members pursuant to this Section 5.1(b) following the date on which there are no Series A Preferred Units outstanding; and (B) commencing with the first full fiscal quarter following the fiscal quarter in which the In-Service Date occurs and so long as all distributions required to be paid by the Company in accordance with Section 5.1(c) have been timely paid in accordance with Section 5.1(c), the Board may elect to cause the Company to make distributions of Available Cash in 37 respect of any fiscal quarter of the Company on the Series A Preferred Distribution Payment Date for such fiscal quarter (the “Quarterly AC Distribution Date”) as follows: (A) if no Funded Indebtedness of the Company or its Subsidiaries is outstanding on the applicable Quarterly AC Distribution Date, then the Company may make distributions of Available Cash with respect to the relevant fiscal quarter (1) __% to redeem, on a pro rata basis, the Series A Preferred Units in accordance with Section 4.8(b) (except that the Minimum Optional Redemption Amount shall not apply) and (2) __% to the Holders of Common Units in accordance with Section 5.1(b)(iii); and (B) if (1) Funded Indebtedness of the Company or its Subsidiaries is outstanding on the applicable Quarterly AC Distribution Date and (2) the Leverage Ratio is ___ or below, then the Company may make distributions of Available Cash with respect to the relevant fiscal quarter (a) __% to redeem, on a pro rata basis, the Series A Preferred Units in accordance with Section 4.8(b) (except that the Minimum Optional Redemption Amount shall not apply) and (b) __% to the Holders of Common Units in accordance with Section 5.1(b)(iii). quarter exceed the Maximum Quarterly AC Distribution Amount without Preferred Approval. (ii) In no event shall distributions made in accordance with Section 5.1(b)(i) in any fiscal (iii) Subject to Section 5.1(b)(i), the Board shall, following the end of each fiscal quarter, determine the amount of Available Cash distributable to the Holders of Common Units in accordance with Section 5.1(b)(i), if any, and promptly, on or following the Series A Preferred Distributions Payment Date for such fiscal quarter, distribute any such Available Cash to the Holders of Common Units pro rata (based on the Common Unit Sharing Percentages of such Holders). (c) Distributions on Series A Preferred Units. (i) From and after the Effective Date, distributions at the Series A Preferred Distributions Rate (or the Series A Preferred Distributions Rate plus the Step-Up Rate pursuant to either (A) Section 5.1(c)(iii) or (B) the last sentence of Section 5.2) shall accrue on each Series A Preferred Unit (the “Series A Preferred Distributions”). Series A Preferred Distributions shall accrue and accumulate from day to day, whether or not declared, and shall be cumulative. When, as and if declared by the Board, subject to the Company’s right to make Series A Non- Cash Distribution Elections during the PIK Period as set forth in Section 5.1(c)(ii), Series A Preferred Distributions shall be payable in cash, in arrears on each Series A Preferred Distributions Payment Date for the fiscal quarter ending immediately prior to such Series A Preferred Distributions Payment Date (or with respect to the first applicable Series A Preferred Distributions Payment Date, for the period commencing on the Effective Date and ending on the last day of the fiscal quarter during which the Effective Date occurs) from the assets of the Company out of funds legally permitted to be distributed pursuant to the Act for payment. Except as provided in Section 38 5.1(b), this Section 5.1(c), Section 5.2 and Article X, the Company shall not declare, pay or set aside any distributions or dividends on any Units (other than Series A Preferred Units) or effect any repurchase or redemption of, any Units or other Interests of the Company (other than redemptions of Series A Preferred Units in accordance with Section 4.8), in either case, so long as any Series A Preferred Units remain issued and outstanding. (ii) Notwithstanding anything to the contrary in this Section 5.1(c), the Company may, at the sole election of the Board, with respect to any Series A Preferred Distribution accrued in respect of any fiscal quarter (or portion thereof for which a Series A Preferred Distribution is due) until the expiration of the PIK Period, elect (a “Series A Non-Cash Distribution Election”) to have up to 100% of the amount that would have been payable in cash if such distribution had been a cash distribution to instead be paid through the issuance to the Series A Preferred Member of a number of Series A Preferred Units (the “PIK Units”) equal to the quotient resulting from the division of the amount of the Series A Preferred Distribution for such quarter by the Series A Preferred Issue Amount, which issuance shall be effective as of the first day of the fiscal quarter immediately following the fiscal quarter in respect of which such payment is due in lieu of paying such portion of such accrued Series A Preferred Distribution in cash. Notwithstanding anything in this Agreement to the contrary, for any fiscal quarter with respect to which there is any unpaid amount of any Series A Preferred Distribution, such quarter shall be deemed a fiscal quarter with respect to which the Company made a Series A Non-Cash Distribution Election. (iii) If the Company fails to pay in cash in full all or any part of any Series A Preferred Distribution when due for any quarter following the PIK Period, then from and after the first day of the immediately following fiscal quarter and continuing until such failure is cured by payment in full in cash of all arrearages (for the avoidance of doubt, including arrearages attributable to the Step-Up Rate), (A) the Series A Preferred Distributions shall accrue at the Series A Preferred Distributions Rate plus the Step-Up Rate and (B) the amount of such accrued but unpaid cash distributions shall constitute arrearages that shall accrue and accumulate (and compound quarterly) at the Series A Preferred Distributions Rate plus the Step-Up Rate until paid. Notwithstanding anything to the contrary in this Agreement, the portion of such arrearages attributable to the Step-Up Rate shall not be deemed distributions paid by the Company to the Holders of Series A Preferred Units for purposes of the ROI and IRR calculations as used in the calculation of the Base Return, but instead shall be deemed liquidated damages (and not a penalty) paid by the Company to the Holders of Series A Preferred Units as a return of a separate portion of the Base Return. Payments of Cash Distributions. Payment of all cash distributions made by the Company to a Member shall be made by wire transfer of immediately available funds in accordance with such written instructions to the Company as may be provided by such Member from time to time. (d) Section 5.2 Tax Distributions . To the extent (a) the Board determines that the Company has Available Cash and (b) such distributions are permitted by any credit or financing agreements to which the Company or any of its Subsidiaries is a party, the Board shall cause the 39 Company to make distributions to each Holder in the amount, if positive, of (X) such Holder’s Cumulative Assumed Tax Liability as of each Tax Distribution Date minus (Y) the cumulative cash distributions made to such Holder pursuant to Section 5.1 and this Section 5.2. If, as of any Tax Distribution Date, the Company either (a) has insufficient Available Cash or (b) is not permitted under any credit or financing agreement to make distributions in an amount equal to the aggregate of the Cumulative Assumed Tax Liabilities of the Holders of Series A Preferred Units for such Tax Distribution Date (if the Company is not permitted to make tax distributions pursuant to clauses (a) or (b), a “Tax Distribution Default”), then the Company shall make distributions to the Holders of Series A Preferred Units pursuant to this Section 5.2 to the extent of such Available Cash or to the extent permitted under such agreement, as applicable. Notwithstanding anything in this Section 5.2 to the contrary, no Holder shall have any obligation to make any Capital Contribution to fund any distributions described in this Section 5.2. Any distribution made pursuant to this Section 5.2 shall be treated as an advance against the next distribution payable to such Holder pursuant to Section 5.1, as applicable and shall reduce such distributions. If the Company is in a Tax Distribution Default for any portion of any fiscal quarter during the PIK Period, the Series A Preferred Distributions Rate for such fiscal quarter shall be the Series A Preferred Distributions Rate plus the Step-Up Rate (and, notwithstanding anything to the contrary in this Agreement, such portion of distributions attributable to the Step-Up Rate shall not, to the extent distributed by the Company by issuing additional Series A Preferred Units, be deemed distributions paid by the Company to the Holders of Series A Preferred Units for purposes of the ROI and IRR calculations as used in the calculation of Base Return, but instead shall be deemed liquidated damages (and not a penalty) paid by the Company to the Holders of Series A Preferred Units). Section 5.3 Allocations . (a) Profits and Losses. Except as otherwise provided in this Agreement, Profit and Loss of the Company will be allocated among the Members in a manner such that, after giving effect to the special allocations set forth in Section 5.3(b) and Section 5.3(c), the Capital Account balance of each Member, immediately after making such allocation, is, as nearly as possible, equal (proportionately) to their Target Capital Account. “Target Capital Account” with respect to a Member or Series A Preferred Unit means (i) the distributions that would be made to such Member or in respect of such Series A Preferred Unit pursuant to Section 5.1 and Section 10.2 if the Company were dissolved, its affairs wound up and its assets sold for cash equal to their Fair Market Value, all Company liabilities were satisfied (limited with respect to each nonrecourse liability to the Fair Market Value of the assets securing such liability) and the net assets of the Company were distributed in accordance with Section 10.2 to the Members immediately after making such allocation (but determined without regard to clause (a) of the definition of “Base Return”), minus (ii) such Member’s or Unit’s share of Company Minimum Gain and Member Minimum Gain, computed immediately prior to the hypothetical sale of assets. The entitlement to distributions pursuant to this Agreement (including pursuant to a redemption or dissolution) of a Holder of Series A Preferred Units shall not be treated, for U.S. federal income tax purposes, as a guaranteed payment for the use of capital pursuant to Section 707(c) of the Code or as a capital shift for U.S. federal income tax purposes, except to the extent that a distribution is paid in cash to a Holder of Series A Preferred Units and the Company has insufficient Profit and items of gross income and gain to allocate to a Holder of Series A Preferred Units to cause such Member’s Capital Account to reflect the amount such Member actually receives, in which case such excess distribution shall 40 be treated for U.S. federal income tax purposes as a guaranteed payment for the use of capital pursuant to Code Section 707(c). special allocations will be made in the following order of priority: (b) Regulatory Allocations. Notwithstanding the foregoing provisions of Section 5.3(a), the following (i) Minimum Gain Chargeback. If there is a net decrease in Company Minimum Gain during a Company taxable year, then each Holder will be allocated items of Company income and gain for such taxable year (and, if necessary, for subsequent years) in an amount equal to such Holder’s share of the net decrease in Company Minimum Gain, determined in accordance with Treasury Regulations Section 1.704-2(g)(2). This Section 5.3(b)(i) is intended to comply with the minimum gain chargeback requirement of Treasury Regulations Section 1.704-2(f) and will be interpreted consistently therewith. (ii) Member Minimum Gain Chargeback. If there is a net decrease in Member Minimum Gain attributable to a Member Nonrecourse Debt during any Company taxable year, each Holder who has a share of the Member Minimum Gain attributable to such Member Nonrecourse Debt, determined in accordance with Treasury Regulations Section 1.704-2(i)(5) will be specially allocated items of Company income and gain for such taxable year (and, if necessary, subsequent years) in an amount equal to such Holder’s share of the net decrease in Member Minimum Gain attributable to such Member Nonrecourse Debt, determined in a manner consistent with the provisions of Treasury Regulations Sections 1.704-2(g)(2) and (j)(2)(ii). This Section 5.3(b)(ii) is intended to comply with the partner nonrecourse debt minimum gain chargeback requirement of Treasury Regulation Section 1.704-2(i)(4) and will be interpreted consistently therewith. (iii) Qualified Income Offset. If any Holder unexpectedly receives an adjustment, allocation, or distribution of the type contemplated by Treasury Regulations Sections 1.704-1(b)(2)(ii)(d)(4), (5) or (6), items of income and gain will be allocated to all such Holders (in proportion to the amounts of their respective deficit Adjusted Capital Accounts) in an amount and manner sufficient to eliminate the deficit balance in the Adjusted Capital Account of such Holder as quickly as possible; provided, that an allocation pursuant to this Section 5.3(b)(iii) shall be made if and only to the extent that such Holder would have an Adjusted Capital Account deficit after all other allocations provided for in this Article V have been tentatively made as if this Section 5.3(b)(iii) were not in this Agreement. It is intended that this Section 5.3(b)(iii) qualify and be construed as a “qualified income offset” within the meaning of Treasury Regulations Section 1.704-1(b)(2)(ii)(d). (iv) Limitation on Allocation of Net Loss. If the allocation of Losses to a Holder as provided in Section 5.3(a) would create or increase an Adjusted Capital Account deficit, there will be allocated to such Holder only that amount of Losses as will not create or increase an Adjusted Capital Account deficit. The Losses that would, absent the application of the preceding sentence, otherwise be allocated to such Holder will be allocated to the other Holders in accordance with their relative proportion of Units, subject to the limitations of this Section 5.3(b)(iv). 41 (v) Certain Additional Adjustments. To the extent that an adjustment to the adjusted tax basis of any Company asset pursuant to Code Section 734(b) or Code Section 743(b) is required, pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv)(m)(2) or Treasury Regulations Section 1.704-1(b)(2)(iv)(m)(4), to be taken into account in determining Capital Accounts as the result of a distribution to a Holder in complete liquidation of its Interest, the amount of such adjustment to the Capital Accounts will be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such gain or loss will be specially allocated to the Holders in accordance with their Interests in the Company in the event that Treasury Regulations Section 1.704-1(b)(2)(iv)(m)(2) applies, or to the Holders to whom such distribution was made in the event that Treasury Regulations Section 1.704-1(b)(2)(iv)(m)(4) applies. Company will be allocated to the Common Units in proportion to their Common Unit Sharing Percentages. (vi) Nonrecourse Deductions. The Nonrecourse Deductions for each taxable year of the Member Nonrecourse Deductions. The Member Nonrecourse Deductions will be allocated each year to the Holder that bears the economic risk of loss (within the meaning of Treasury Regulations Section 1.752-2) for the Member Nonrecourse Debt to which such Member Nonrecourse Deductions are attributable. (vii) (c) Allocations with Respect to Series A Preferred Units. Notwithstanding any other provision of this Section 5.3: (i) Items of Company gross income and gain for the taxable period shall be allocated to the Holders of Series A Preferred Units in proportion to, and to the extent of, an amount equal to the sum of (A) the Series A Preferred Distributions that are paid in cash with respect to the Series A Preferred Units for such period; (B) after taking into account clause (A), the excess, if any, of (X) the Series A Preferred Issue Amount with respect to such Holder’s Series A Preferred Units, over (Y) such Holder’s existing Capital Account balance in respect of such Series A Preferred Units, until the Capital Account balance of each such Holder in respect of its Series A Preferred Units is equal to the Series A Preferred Issue Amount with respect to such Holder’s Series A Preferred Units; and (C) to the extent such allocation would not create or increase a Loss, additional items of gross income and gain such that the Capital Account balance in respect of each Series A Preferred Unit, immediately after making such allocation, is, as nearly as possible, equal (proportionately) to its Target Capital Account. (ii) Without duplication of allocations under (c)(i) above, items of Company gross income shall be allocated to the Holders of Series A Preferred Units, pro rata, until the aggregate amount of gross income allocated to each Holder of Series A Preferred Units pursuant hereto for the current taxable period and all previous taxable periods is equal to the cumulative amount of all Losses allocated to such Member pursuant to Section 5.3(a) for all previous taxable years. 42 (iii) If (A) (1) a redemption pursuant to Section 4.8 occurs, (2) a Remedial Sale occurs, or (3) the Company liquidates or dissolves pursuant to Section 10.2 (each, a “Series A Allocation Event”), and (B) after having made all other allocations provided for in this Section 5.3 for the taxable period in which the Series A Allocation Event occurs, the per unit Capital Account of each Series A Preferred Unit does not equal the amount each Holder of Series A Preferred Units receives pursuant to such Series A Allocation Event, then items of gross income, gain, loss and deduction for such taxable period shall be allocated among the Members in a manner determined appropriate by the Board so as to cause, to the maximum extent possible, the per unit Capital Account of each Series A Preferred Unit to equal the amount received with respect to such Series A Preferred Units (and no other allocation pursuant to this Agreement shall reverse the effect of such allocations). Notwithstanding anything to the contrary in this Agreement, the reallocation of items set forth in the immediately preceding sentence provides that, to the extent necessary to achieve the balances described above, items of gross income and gain that would otherwise be included in Profit or Loss, as the case may be, for the taxable period in which the Series A Allocation Event occurs, may be reallocated from the Members holding Units other than Series A Preferred Units to Members holding Series A Preferred Units. If a Series A Allocation Event occurs on or before 60 days after the end of the taxable period in which such Series A Allocation Event occurs and the reallocation of items for such taxable period as set forth above in this Section 5.3(c) fails to achieve the per unit Capital Accounts described above, then items of gross income, gain, loss and deduction for such prior taxable period shall be reallocated among all Members in a manner that will, to the maximum extent possible and after taking into account all other allocations made pursuant to this Section 5.3(c), cause the per unit Capital Account for each Series A Preferred Unit to equal the amount received with respect to a Series A Preferred Unit at the time of a Series A Allocation Event. (iv) If, after taking into account all other provisions of this Section 5.3 other than this Section 5.3(c)(iv), (A) a Series A Allocation Event occurs on or before the date prescribed by Law for the filing of the Company’s federal income tax return for the taxable period immediately prior to the taxable period in which the Series A Allocation Event occurs and (B) the reallocation of items for the taxable period in which the Series A Allocation Event occurs as set forth in this Section 5.3(c) fails to achieve the per unit Capital Account described in this Section 5.3(c), then for US federal income tax purposes, any deficit in such per unit Capital Account described in this Section 5.3(c) will be treated as a guaranteed payment for the use of capital within the meaning of Code Section 707(c). (d) Tax Allocations. (i) Except as provided in Section 5.3(d)(ii), for income tax purposes under the Code and the Treasury Regulations, each Company item of income, gain, loss, deduction and credit will be allocated between the Members in the same manner as the correlative item of “book” income, gain, loss, deduction or credit is allocated pursuant to this Article V. contributed to the Company, consistent with Revenue Ruling 99-5, (ii) Tax items with respect to Company assets that are contributed to the Company (or deemed 43 1991 C.B. 434) with a Gross Asset Value that varies from its basis in the hands of the contributing Holder immediately preceding the date of contribution will be allocated between the Holders for federal income tax purposes pursuant to Treasury Regulations promulgated under Code Section 704(c) so as to take into account such variation. The Company will account for such variation using the “remedial method” under Treasury Regulation Section 1.704-3(d). If the Gross Asset Value of any Company asset is adjusted pursuant to the definition of “Gross Asset Value” in this Agreement, subsequent allocations of income, gain, loss, deduction and credit with respect to such Company asset will take account of any variation between the adjusted basis of such Company asset for federal income tax purposes and its Gross Asset Value in a manner consistent with Code Section 704(c) and the Treasury Regulations promulgated thereunder using the “remedial method” under Treasury Regulation Section 1.704-3(d). Allocations pursuant to this Section 5.3(d) are solely for purposes of federal, state and local taxes and will not affect, or in any way be taken into account in computing, any Holder’s Capital Account or share of Profits, Losses and any other items or distributions pursuant to any provision of this Agreement. (iii) (e) Other Provisions. (i) For any Tax Year or other period during which any part of any Interest in the Company is Transferred between the Holders or to another Person (other than by pledge of, or grant of a security interest in, such Interest), the portion of the Profits, Losses and other items of income, gain, loss, deduction and credit that are allocable with respect to such part of an Interest in the Company will be apportioned between the transferor and the transferee under any method allowed pursuant to Code Section 706 and the applicable Treasury Regulations as determined by the Board. (ii) For purposes of determining a Holder’s proportional share of the Company’s “excess nonrecourse liabilities” within the meaning of Treasury Regulations Section 1.752-3(a)(3), each Holder’s interest in Profits shall be in the same proportion as Nonrecourse Deductions are allocated to such Holder, as provided in Section 5.3(b)(vi). (iii) The allocations set forth in Section 5.3 are intended to comply with the Code and Treasury Regulations. If the Board determines that the allocations to a Member are not in compliance with the Code and Treasury Regulations, the Board is authorized to make any appropriate adjustments; provided that the Board shall make no adjustments without first notifying the Members, providing an explanation of the proposed adjustments and permitting the Members to discuss the proposed adjustments with the Board; provided, further that the Board may not make any adjustments that would have a disproportionate and adverse impact on the Series A Preferred Members without Preferred Approval. (f) Valuation; Revaluation. Except as otherwise specifically provided in this Agreement, valuations for purposes of allocation of tax items will be made by the Board or, in the discretion of the Board, by independent third parties appointed by the Board and deemed qualified by the Board to render an opinion as to the value of the Company’s assets, using customary and 44 industry accepted valuation techniques and taking into account such information relating to the investments, assets and liabilities of the Company as the Board or independent third party, as the case may be, as are customary and reasonable and each such valuation shall be determined without application of any minority, illiquidity, or other discount. Section 5.4 Withholding . The Company may withhold distributions or portions thereof if it is required to do so by any applicable rule, regulation, or Law, and each Holder hereby authorizes the Company to withhold from or pay on behalf of or with respect to such Holder any amount of federal, state, local or foreign taxes that the Board determines that the Company is required to withhold or pay with respect to any amount distributable or allocable to such Holder pursuant to this Agreement. If the Company determines that it is required to withhold any amount payable to a Holder, the Company shall use commercially reasonable efforts to provide such Holder at least three Business Days prior to the date the applicable payment is scheduled to be made with (a) written notice of the intent to deduct and withhold, which shall include a copy of the calculation of the amount to be deducted and withheld, and (b) a reasonable opportunity for such Holder to provide forms or other evidence that would exempt such amounts from withholding (or reduce such withholding). Any amounts withheld pursuant to this Section 5.4 will be treated as having been distributed to such Holder. To the extent that the cumulative amount of such withholding for any period exceeds the distributions to which such Holder is entitled for such period, the amount of such excess will be considered a loan from the Company to such Holder, with interest accruing at 2% plus the Interest Rate. Such loan may, at the option of the Board, be satisfied (a) out of distributions to which such Holder would otherwise be subsequently entitled, or (b) by the immediate payment in cash to the Company of such excess amount. Section 6.1 Management ARTICLE VI MANAGEMENT . Subject to Section 4.9, Section 6.8 and any other provisions of this Agreement expressly setting forth rights of any Member or Members to consent to the conduct of any of the business or affairs of the Company, the business and affairs of the Company shall be managed and controlled by a board of directors (the “Board,” and each member of the Board, a “Director”), and the Board shall have full and complete discretion to manage and conduct the business and affairs of the Company, to make all decisions affecting the business and affairs of the Company and to take all such actions as it deems necessary, advisable or appropriate to accomplish the purposes of the Company as set forth in Section 2.5. Notwithstanding the foregoing, but without limiting the rights of the Series A Preferred Director under Section 6.2(n) or otherwise, no Director in his or her individual capacity shall have the authority to manage the Company or approve matters relating to, or otherwise to bind the Company, such powers being reserved to the Directors through the Board and to such agents of the Company as designated by the Board. In addition to the powers that now or hereafter may be granted under the Act and to all other powers granted under any other provision of this Agreement, subject to Section 4.9, Section 6.8 and any other provisions of this Agreement expressly setting forth rights of any Member or Members to consent to the conduct of any of the business or affairs of the Company, the Board shall have full power and authority to do all things on such terms as the Board may deem necessary or appropriate to conduct, or cause to be conducted the business and affairs of the Company in accordance with the terms of this Agreement. 45 Section 6.2 Board . (a) Composition; Initial Directors. Subject to the remaining provisions of this Article VI, the Board shall initially consist of four Directors, designated as follows: (i) three designees appointed by Summit Member (each, a “Summit Director”); and one designee chosen by the Series A Preferred Members (acting with Preferred Approval) (such Director, the “Series A Preferred Director”), solely for the purposes set forth in, and subject to the terms and conditions of, Section 6.2(n). (ii) Each Director shall serve in such capacity until such Director’s successor has been elected and qualified or until such individual’s death, resignation or removal. The initial Board shall consist of the individuals listed on Exhibit B. The members of the Board shall be “directors” within the meaning of the Act. The number of Directors may not be increased or decreased except as provided in this Agreement. (b) Removal. Any Director may be removed with or without cause only by consent of the Member or Members entitled to designate such Director. The removal of a Director who is also a Member will not affect the Director’s rights as a Member and will not constitute the resignation of such Member. (c) Resignations. A Director may resign at any time. Such resignation shall be in writing and shall take effect at the time specified therein or, if no time is specified, at the time of its receipt by the Company. The acceptance of a resignation shall not be necessary to make it effective unless expressly so provided in the resignation. (d) Vacancies. In the event that a vacancy is created on the Board by the death, disability, retirement, resignation or removal of any Director, the vacancy shall be filled by (i) in the case of a Summit Director, Summit Member, or (ii) in the case of the Series A Preferred Director, the Series A Preferred Members (acting with Preferred Approval). (e) Attendance; Votes per Director; Quorum; Required Vote for Board Action. Subject to Section 6.2(n), only the Summit Directors will have the right to vote on matters before the Board and each Summit Director shall have one vote. Unless otherwise required by this Agreement, including Section 6.2(n), Summit Directors having a majority of the votes, either present (in person or by teleconference) or represented by proxy, shall constitute a quorum for the transaction of business at a meeting of the Board. Unless expressly provided otherwise in this Agreement, including Section 6.2(n), approval of a matter by the Board will require the affirmative vote of Summit Directors having a majority of the votes then entitled to be cast by the total number of Summit Directors then entitled to be appointed to the Board. (f) Notice of Meetings; Place of Meetings; Order of Business. Notice of any meeting of the Board shall be given to each Director (except as otherwise provided in this Section 6.2) by an Officer or one of the Summit Directors calling the meeting at least 48 hours in advance of any meeting of the Board (provided that shorter notice may be given as necessary or desirable to permit the Board to respond timely to an emergency). The Board may hold its meetings and may have an 46 office and keep the books of the Company, except as otherwise provided by Law, in such place or places, within or without the State of Delaware, as the Board may from time to time determine by resolution. At all meetings of the Board, business shall be transacted in such order as shall from time to time be determined by resolution of the Board. (g) Regular Meetings. Regular meetings of the Board may be held at such times and places as shall be designated by resolution of the Board; provided, however, during any period in which the Series A Preferred Members are entitled to appoint a Board Observer in accordance with Section 6.2(o), regular meetings of the Board shall be held quarterly at such times and places as shall be designated by resolution of the Board. At each such meeting, the Board shall discuss the business activities of the Company and its Subsidiaries that took place during such quarterly period and the operating and financial performance of the Company and its Subsidiaries for such quarterly period. Unless the purpose of the meeting includes the contemplation of a Series A Preferred Director Approval Event, the Series A Preferred Director shall not have the right to receive notice or attend regular meetings of the Board. (h) Special Meetings. Special meetings of the Board may be called at any time by a majority of the Summit Directors. Unless the purpose of a special meeting includes the contemplation of a Series A Preferred Director Approval Event, the Series A Preferred Director shall not have the right to receive notice or attend special meetings of the Board. (i) Compensation; Reimbursement. No Director shall receive any compensation for serving on the Board. All of the Directors shall be entitled to reimbursement for reasonable out-of-pocket expenses incurred in connection with carrying out such Directors’ duties as a member of the Board. (j) Action Without a Meeting. Other than any action with respect to a Series A Preferred Director Approval Event (which action must be taken in person or telephonically), any action required or permitted to be taken at any meeting of the Board may be taken without a meeting and without a vote if a consent or consents in writing, setting forth the action so taken, is signed by Summit Directors having not fewer than the minimum number of votes that would be necessary to take the action at a meeting of the Board at which all Summit Directors entitled to vote on the action were present (in person or by teleconference) or represented by proxy and voted. Notice of actions taken by written consent in lieu of a meeting of the Board shall be delivered to each Summit Director as promptly as reasonably practicable following the date the requisite consent is obtained. (k) Telephonic Conference Meeting. Subject to the requirement for notice of meetings, Directors may participate in a meeting of the Board by means of a conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other, and participation in such a meeting shall constitute presence in person at such meeting, except where a Director participates in the meeting for the express purpose of objecting to the transaction of any business on the ground that the meeting is not lawfully called or convened. (l) Waiver of Notice Through Attendance. Attendance of a Director at any meeting of the Board (including by telephone) shall constitute a waiver of notice of such meeting, except where such Director attends the meeting for the express purpose of objecting to the transaction of 47 any business on the ground that the meeting is not lawfully called or convened and notifies the other Directors at such meeting of such purpose. (m) Reliance on Books, Reports and Records. Each Director shall, in the performance of his or her duties, be fully protected in relying in good faith upon the books of account or reports made to the Company by any of its Officers or by an independent certified public accountant or by an appraiser selected with reasonable care by the Board, or in relying in good faith upon other records of the Company. (n) Series A Preferred Director Approval Event. Notwithstanding anything in this Agreement to the contrary, (i) if the Board desires to take any action that would cause or constitute a Series A Preferred Director Approval Event, the Board may only approve such Series A Preferred Director Approval Event with the approval of (A) a majority of the Directors and (B) the approval of the Series A Preferred Director, (ii) if the purpose of any regular or special meeting of the Board includes the contemplation of a Series A Preferred Director Approval Event, then the presence (in person or by teleconference) of the Series A Preferred Director shall be required to constitute a quorum for the transaction of business at such meeting of the Board and (iii) no action with respect to a Series A Preferred Director Approval Event may be taken by the Board except at a regular or special meeting of the Board duly called in accordance with the terms of this Agreement. (o) Board Observer. For any period during which the Step-Up Rate is in effect pursuant to Section 5.1(c)(iii), the Series A Preferred Members (acting with Preferred Approval) shall be entitled to appoint one Board observer (the “Board Observer”), who shall be entitled to attend any meetings of the Board and participate in any meeting of the Board to the extent any Director would participate; provided that, (i) this Board Observer right shall automatically terminate at such time as the Step- Up Rate ceases to be in effect pursuant to Section 5.1(c)(iii); (ii) the Board Observer shall not have any right to vote on any matters before the Board; and (iii) the Board Observer may be excluded from any meeting of the Board or portion thereof (x) to preserve attorney-client work product or similar privilege or (y) if the Board determines, based on advice of outside legal counsel, that there exists, with respect to the subject of a meeting or Board materials, an actual or conflict of interest between the Board Observer and the Company; provided, further that, the Series A Preferred Members right to appoint the Board Observer shall be reinstated at any time in which the Step-Up Rate is in effect pursuant to Section 5.1(c)(iii). The Company (or Officer or Director, as applicable) shall provide the Board Observer with all notices and information provided to the Board at the same time and in the same manner as provided to the Directors, including notice of all meetings of the Board or actions to be taken by written consent in lieu of a meeting. The Board Observer shall be entitled to reimbursement for reasonable out-of-pocket expenses incurred in order to attend meetings of the Board in the same manner as provided to the Directors. The Series A Preferred Members (acting with Preferred Approval) shall have the right to remove and/or replace the Board Observer at any time by delivering written notice of such removal and/or replacement to the Company or the Board (for the avoidance of doubt, removing the Board Observer will not prejudice or eliminate the Series A Preferred Members’ right to appoint a subsequent Board Observer in accordance with this Section 6.2(o)). Section 6.3 Officers . The Board may, from time to time, designate one or more Persons to be Officers of the Company, with such titles as the Board may assign to such Persons. No Officer need be a Member or a resident of the State of Delaware. Officers so designated will have such authority and perform such duties as the Board may, from time to time, delegate to them and, 48 unless otherwise specified by the Board, will have the authority and responsibilities generally held by officers of a Delaware corporation holding the same titles. Any number of offices may be held by the same Person. Each Officer shall have such fiduciary duties to the Company and its Members that an officer of a Delaware corporation having a corresponding title would have. The salaries or other compensation, if any, of the Officers and agents of the Company will be fixed from time to time by the Board. Any Officer may resign as such at any time. Such resignation will be made in writing and delivered to the Board and will take effect at the time specified therein, or if no time be specified, at the time of its receipt by the Board. Any Officer may be removed as such, either with or without cause, by the Board, in its discretion. Any vacancy occurring in any office of the Company may be filled by the Board. Section 6.4 Waiver of Fiduciary Duties; Indemnification; Limitation of Liability . (a) Other than any action or failure to act in breach of Section 6.8(b)(xxiv) (which such breach would, for the avoidance of doubt, constitute a breach of the fiduciary duty of the Members acting or failing to act in breach of Section 6.8(b)(xxiv)), no Member shall have any fiduciary or other duty to the Company, any other Member or any other Person that is a party to or is otherwise bound by this Agreement other than the implied contractual covenant of good faith and fair dealing, and no Member shall be liable in damages to the Company, any other Member or any other Person that is a party to or is otherwise bound by this Agreement by reason of, or arising from or relating to the operations, business or affairs of, or any action taken or failure to act on behalf of, the Company, except to the extent that it is determined by a final, non-appealable order of a court of competent jurisdiction that any of the foregoing was caused by a bad faith violation of the implied contractual covenant of good faith and fair dealing or actual (and not constructive) fraud or willful misconduct, or, with respect to any criminal action or proceeding, that such Member acted with knowledge that such Member’s conduct was unlawful. (b) Other than any action or failure to act in breach of Section 6.2(n) (which such breach would, for the avoidance of doubt, constitute a breach of the fiduciary duty of the Directors acting or failing to act in breach of Section 6.2(n)), no Director shall have any fiduciary or other duty to the Company, any Member or any other Person that is a party to or is otherwise bound by this Agreement other than the implied contractual covenant of good faith and fair dealing, and no Director shall be liable in damages to the Company, any Member or any other Person that is a party to or is otherwise bound by this Agreement by reason of, or arising from or relating to the operations, business or affairs of, or any action taken or failure to act on behalf of, the Company, except to the extent that it is determined by a final, non-appealable order of a court of competent jurisdiction that any of the foregoing was caused by a bad faith violation of the implied contractual covenant of good faith and fair dealing, or actual (and not constructive) fraud or willful misconduct, or, with respect to any criminal action or proceeding, that such Director acted with knowledge that its conduct was unlawful. (c) Notwithstanding any other provision of this Agreement, to the extent that any provision of this Agreement purports or is interpreted (i) to have the effect of replacing, restricting or eliminating the duties that might otherwise, as a result of Delaware or other applicable Law, be owed by any Director or Member to the Company, the Members, any other Person who acquires an interest in the Company or any other Person who is bound by this Agreement or (ii) to constitute a waiver of such duties by the Company, the Members, any other Person who acquires 49 an interest in the Company or any other Person who is bound by this Agreement or a consent by any of the foregoing to any such replacement, restriction or elimination, such provision shall be deemed to have been approved by the Company, all the Members, each other Person who acquires an interest in the Company and each other Person who is bound by this Agreement. (d) Each Director, in performing its obligations under this Agreement, shall be entitled to act or omit to act considering only such factors as such Director chooses to consider, and any action of such Director or failure to act, taken or omitted in good faith reliance on this Section 6.4 shall not constitute a breach of any duty (including any fiduciary duty, all of which are disclaimed to the extent provided in Section 6.4(b)) on the part of such Director to the Company or any other Member. Notwithstanding anything to the contrary in this Agreement, to the fullest extent permitted by applicable Law, and without limiting the foregoing, (i) subject to the provisions of this Agreement, each Director may grant or withhold approval, in such Director’s sole and absolute discretion, with respect to any action before such Director on which it is entitled to grant approval and (ii) with respect to any action before a Director on which such Director is entitled to vote or grant approval, to the fullest extent permitted by applicable Law, such Director shall be entitled to consider only such interest and factors as it desires, including its own interests or the interest of such Director or its Affiliates, and shall have no duty (including any fiduciary or quasi-fiduciary duty) or obligation to give any consideration to any interest of or factors affecting the Company, the Members or any of their respective Subsidiaries, Affiliates or any other Person. (e) To the maximum extent permitted by applicable Law, but subject to the provisions of this Section 6.4, the Directors, Officers, the Board Observer and the Company Representative (or Persons acting at the written request of the Company in a similar capacity, which request may be inferred from written consents by the Board) (each an “Indemnitee”) will not be liable for, and will be indemnified and held harmless by the Company against, any and all claims, actions, demands, losses, damages, liabilities, costs, or expenses, including attorney’s fees, court costs, and costs of investigation, actually and reasonably incurred by any such Indemnitee (collectively, “Indemnified Losses”) arising from any civil, criminal or administrative proceedings in which such Indemnitee may be involved, as a party or otherwise, by reason of its being a Director, Officer, Board Observer or Company Representative of the Company, or by reason of its involvement in the management of the affairs of the Company, whether or not it continues to be such at the time any such Indemnified Loss is paid or incurred, except to the extent that any of the foregoing is determined by a final, non-appealable order of a court of competent jurisdiction that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Agreement, the Indemnitee acted in bad faith or engaged in actual (and not constructive) fraud, willful misconduct, or, with respect to criminal matters, that an Indemnitee acted with knowledge that his conduct was unlawful. IT IS THE EXPRESS INTENT OF THE COMPANY THAT THE FOREGOING INDEMNITY SHALL BE APPLICABLE TO ANY LOSS THAT HAS RESULTED FROM OR IS ALLEGED TO HAVE RESULTED FROM THE ACTIVE OR PASSIVE OR THE SOLE, JOINT, OR CONCURRENT NEGLIGENCE OF THE INDEMNITEE. (f) To the maximum extent permitted by applicable Law, expenses incurred by an Indemnitee in defending any proceeding (except a proceeding by or in the right of the Company), will be paid by the Company in advance of the final disposition of the proceeding, upon receipt of a written undertaking by or on behalf of such Indemnitee to repay such amount if 50 such Indemnitee is adjudicated to be ineligible for indemnification as authorized pursuant to this Section 6.4. representatives of each Indemnitee. (g) The indemnification provided by this Section 6.4 will inure to the benefit of the heirs and personal (h) Any indemnification pursuant to this Section 6.4 will be made only out of the assets of the Company and will in no event cause any Member to incur any personal liability nor shall it result in any liability of the Members to any third party. The Company shall not be required to make a capital call to fund any indemnification obligation hereunder, nor shall any of the Members (including any of the Series A Preferred Members) be required to make any Capital Contribution to the Company to fund any indemnification obligation hereunder. Indemnitee may otherwise be entitled by contract (including advancement of expenses) or as a matter of Law. (i) The rights of indemnification provided in this Section 6.4 are in addition to any rights to which an (j) The Company will have the power to purchase and maintain insurance on behalf of any Indemnitee against any liability asserted against such Indemnitee and incurred by such Indemnitee in any such capacity, or arising out of such Person’s status as a Indemnitee, whether or not the Company would have the power to indemnify such Indemnitee against such liability under the provisions of this Section 6.4 or under applicable Law. The Company will obtain and fully pay a customary directors’ and officers’ insurance policy (“D&O Insurance”) covering the Directors and Officers of the Company (including the Series A Preferred Director and Board Observer). The Company will cause the D&O Insurance to remain in effect for all periods during with any Series A Preferred Units are outstanding and shall ensure that the Board Observer and Series A Preferred Director are named insureds and covered by customary “Side A” coverage under the D&O Insurance and, in each case, are entitled to terms, conditions, retentions and limits of liability thereunder that are at least as favorable as the those provided under the directors’ and officers’ insurance coverage provided to any Summit Director by the Company or by Summit Parent to its directors. (k) Notwithstanding anything in this Agreement to the contrary, nothing in this Section 6.4 or Section 6.7 shall (i) limit or waive any claims against, actions, rights to sue, other remedies or other recourse the Company, any Member or any other Person may have against the any Member, Director, Officer or other Covered Person for a breach of contract claim relating to any binding agreement to which such Covered Person is a party (including, where applicable, this Agreement or any of the Other Transaction Documents) or (ii) entitle any such Covered Person to be indemnified or advanced expenses with respect to such a breach. Section 6.5 Company as Indemnitor of First Resort . (a) The Company hereby agrees that it is the indemnitor of first resort under this Agreement or any other indemnification agreement, arrangement or undertaking with respect to any Indemnitee, and as a result the Company’s obligations to any such Indemnitee under this Agreement or any other agreement, arrangement or undertaking to provide advancement of expenses and indemnification to such Indemnitee are primary without regard to any rights such 51 Indemnitee may have to seek or obtain indemnification or advancement of expenses from any other Person or any of its Affiliates (“Other Indemnitor”) or from any insurance policy for the benefit of such Indemnitee, and any obligation of any Other Indemnitor to provide advancement or indemnification for all or any portion of the same expenses, liabilities, judgments, penalties, fines and amounts paid in settlement (including all interest, assessments and other charges paid or payable in connection with or in respect of such expenses, liabilities, judgments, penalties, fines and amounts paid in settlement) incurred by such Indemnitee and any rights of recovery of such Indemnitee under any insurance policy for the benefit of such Indemnitee are secondary; and (b) if any Indemnitee pays or causes to be paid, for any reason, any amounts otherwise payable or indemnifiable under Section 6.4(e), then such Indemnitee shall be indemnified therefor in accordance with Section 6.4(e); (i) (ii) if any other party pays or causes to be paid on behalf of an Indemnitee, for any reason, any amounts otherwise payable or indemnifiable hereunder or under any other indemnification agreement, arrangement or undertaking (whether pursuant to contract, organizational document or otherwise) with such Indemnitee (a “Third Party Payor”), then (x) such Third Party Payor shall be fully subrogated to all rights of an Indemnitee with respect to such payment and (y) the Company shall fully indemnify, reimburse and hold harmless such Third Party Payor for all such payments actually made by such Third Party Payor; and (iii) if any Indemnitee collects under any insurance policy for the benefit of such Indemnitee, any amounts otherwise payable or indemnifiable hereunder or under any other indemnification agreement, arrangement or undertaking (whether pursuant to contract, organizational document or otherwise) with such Indemnitee, then (x) such insurer shall be fully subrogated to all rights of such Indemnitee with respect to such payment and (y) the Company shall fully indemnify, reimburse and hold harmless such insurer for all such payments actually made by such insurer. Section 6.6 Other Activities . Except as set forth in the second sentence of Section 3.6(a), the Members and their respective Affiliates and their respective equity holders, partners, members, officers, directors, employees and managers and any Person appointed to serve as a Director of the Company or any of its Subsidiaries by any of the foregoing (collectively, the “Covered Persons”) may engage or invest in, and devote its and their time to, any other business venture or activity of any nature and description, whether or not such activities are considered competitive with the Company or its business (the “Right to Compete”), and neither the Company nor any other Member will have any right by virtue of this Agreement or the relationship created hereby in or to such other venture or activity (or to the income or proceeds derived therefrom), and the pursuit of such other venture or activity will not be deemed wrongful or improper. The Right to Compete of the Covered Persons does not require notice to, approval from, or other sharing with, any of the other Members or the Company. Subject to the second sentence of Section 3.6(a), (a) the legal doctrines of “corporate opportunity,” “business opportunity” and similar doctrines will not be applied to any such competitive venture or activity of any Covered Person and (b) no 52 Covered Person will have any obligation to the Company or its other Members with respect to any opportunity. Section 6.7 No Recourse Against Nonparty Affiliates . All claims, obligations, liabilities, or causes of action (whether in contract or in tort, in law or in equity, or granted by statute) that may be based upon, in respect of, arise under, out or by reason of, be connected with, or relate in any manner to this Agreement, or the negotiation, execution, or performance of this Agreement (including any representation or warranty made in, in connection with, or as an inducement to, this Agreement), may be made only against (and are those solely of) the entities that are expressly identified as parties in the preamble to this Agreement (together with each of TES Member’s or any Series A Preferred Member’s assignee(s) pursuant to Section 4.3 and Section 4.5 and each of their respective transferees of Units in accordance with this Agreement) (collectively, the “Contracting Parties”). No Person who is not a Contracting Party, including any director, officer, employee, incorporator, member, partner, manager, equityholder, affiliate, agent, attorney, or representative of, and any financial advisor or lender to, any Contracting Party, or any director, officer, employee, incorporator, member, partner, manager, stockholder, affiliate, agent, attorney, or representative of, and any financial advisor or lender to any, of the foregoing (“Nonparty Affiliates”), shall have any liability (whether in contract or in tort, in law or in equity, or granted by statute) for any claims, causes of action, obligations, or liabilities arising under, out of, in connection with, or related in any manner to this Agreement or based on, in respect of, or by reason of this Agreement or its negotiation, execution, performance, or breach, and, to the maximum extent permitted by Law, each Contracting Party hereby waives and releases all such liabilities, claims, causes of action, and obligations against any such Nonparty Affiliates. Without limiting the foregoing, to the maximum extent permitted by Law, (a) each Contracting Party hereby waives and releases any and all rights, claims, demands, or causes of action that may otherwise be available at law or in equity, or granted by statute, to avoid or disregard the entity form of a Contracting Party or otherwise impose liability of a Contracting Party on any Nonparty Affiliate, whether granted by statute or based on theories of equity, agency, control, instrumentality, alter ego, domination, sham, single business enterprise, piercing the veil, unfairness, undercapitalization, or otherwise; and (b) each Contracting Party disclaims any reliance upon any Nonparty Affiliates with respect to the performance of this Agreement or any representation or warranty made in, in connection with, or as an inducement to this Agreement. Notwithstanding the foregoing, in no event shall any provision of this Section 6.7 limit any obligation of Summit Parent under the Summit Parent Guarantee in any respect. Section 6.8 Preferred Approvals . Holders of Series A Preferred Units shall not have any voting, consent or approval rights except as set forth in this Section 6.8, as expressly set forth elsewhere in this Agreement or as otherwise from time to time specifically required by the Act or the Certificate. (a) Notwithstanding anything in this Agreement to the contrary, the Company shall be required to obtain Preferred Approval prior to the Company or any of its Affiliates effecting, or permitting to be effected, any of the following: (b) Permitted Summit Holdco Sell-Down, any amendment, alteration, (i) other than for the sole purpose of effecting, and to the extent necessary to effect, a 53 modification, waiver, repeal or similar change (including by way of merger, consolidation, conversion or other transaction) of any provision of this Agreement, the Certificate or any other organizational documents of the Company, which directly or indirectly modifies in any respect the rights, preferences, privileges or powers of the Series A Preferred Units or of any of the Holders thereof, or of the Series A Preferred Director (including for the avoidance of doubt, any amendment, alteration, modification, waiver, repeal or similar change to Section 6.2(n)) or that would otherwise be reasonably expected to be adverse to the Series A Preferred Units or any of the Holders thereof; (ii) except for issuances of Series A Preferred Units in accordance with Article IV, (A) any creation or issuance of Units (or any security or other obligation convertible into or exchangeable for Units) that would have, or reclassification of Units the effect of which is such reclassified Units would have, rights, preferences or privileges (including with respect to distributions or rights upon liquidation, winding up or dissolution) superior to or on parity in any respect with the Series A Preferred Units (including the issuance of any additional Series A Preferred Units) which, for the avoidance of doubt, includes any Units that require the Company to pay distributions that would have priority to or parity with distributions payable on the Series A Preferred Units or that would have rights to distributions that would reduce the ability of the Company to pay distributions in respect of the Series A Preferred Units or (B) any issuance of Capital Stock by any Subsidiary of the Company (other than (1) to the Company, (2) to any wholly-owned Subsidiary of the Company, (3) to Exxon in accordance with Section 3.21 of the Double E LLC Agreement (as in effect on the Effective Date, without any amendments, modifications, supplements, waivers or other changes thereto) or (4) in accordance with and subject to clause (d)(ii) of the definition of “Permitted Summit Operating Sell-Down” for the sole purpose of effecting a Permitted Summit Operating Sell-Down); (iii) any dividend or distribution on, or repurchase or redemption of, any Unit or any Capital Stock of any Subsidiary of the Company, excluding any distributions in accordance with Sections 4.10, 5.1(b), 5.1(c) and 5.2 or any repurchase or redemption of Series A Preferred Units in accordance with this Agreement (including Section 4.8); (iv) increase (A) a Series A Preferred Member’s Commitment or (B) the Accordion Amount; (v) reduce the Series A Preferred Distributions Rate, change the form of payment of distributions on the Series A Preferred Units, change the Series A Preferred Distributions Payment Date or change the seniority rights of the Series A Preferred Members as to the payment of distributions in relation to the Holders of any other class or series of Units; (vi) (A) reduce the amount payable or change the form of payment to the Holders of the Series A Preferred Units upon the voluntary or involuntary liquidation, dissolution or winding up, or upon a Change of Control, Remedial Sale, Initial Public Offering or any other event, or (B) change the seniority of the liquidation preferences of the Holders of the Series A Preferred Units in relation to the rights upon liquidation of the Holders of any other class or series of Units; 54 reduce in any manner the rights, powers, preferences or privileges, or increase in any manner the duties, liabilities or obligations, of any Series A Preferred Member or the Series A Preferred Units pursuant to this Agreement or the Certificate of Formation; (vii) receipt of FERC Approval; (viii) any incurrence of Funded Indebtedness by the Company or its Subsidiaries prior to compliance with Section 6.9; (ix) any incurrence of Funded Indebtedness by the Company or its Subsidiaries that is not in (x) any Lien upon any property or assets of the Company or any of its Subsidiaries, except for (A) any Lien that is customarily incurred or created in connection with the incurrence of Funded Indebtedness that is approved under Section 6.8(b)(viii) or Section 6.8(b)(ix) or Funded Indebtedness that is otherwise permitted under Section 6.9 and (ii) any Lien incurred by Double E in compliance with Section 6.12 of the Double E LLC Agreement (as in effect on the Effective Date, without any amendments, modifications, supplements, waivers or other changes thereto); provided, that, for the avoidance of doubt nothing in this Section 6.8 shall restrict Summit Member from pledging, or otherwise creating a Lien on, Units held by it pursuant to the terms of Funded Indebtedness of Summit Parent and its Subsidiaries (other than the Company and its Subsidiaries); any transaction which results (or would result) in the Company or any of its Subsidiaries becoming a “restricted subsidiary” or otherwise obligated under the terms of any Funded Indebtedness incurred by Summit Parent or any of its Subsidiaries (other than the Company or its Subsidiaries); (xi) any transaction which results (or would result) in a Change of Control with respect to which each Holder of Series A Preferred Units does not receive, upon the consummation of such transaction, an amount in cash equal to the Base Return with respect to each Series A Preferred Unit held by such Holder; (xii) any Initial Public Offering with respect to which each Holder of Series A Preferred Units does not receive, upon the consummation of such Initial Public Offering, an amount in cash equal to the Base Return with respect to each Series A Preferred Unit held by such Holder; (xiii) any Remedial Sale with respect to which each Holder of Series A Preferred Units does not receive, upon the consummation of such Remedial Sale, an amount in cash equal to the Base Return with respect to each Series A Preferred Unit held by such Holder; (xiv) (xv) (A) any sale or transfer of assets by the Company and its Subsidiaries (other than Double E) (including, for the avoidance of doubt, any Transfer by the Company of any interest in Permian Transmission or by Permian Transmission of any interest in Double E, other than any Permitted Summit Operating Sell-Down) on a consolidated basis with a sale price in excess of $__ in any 12-month period or $___ in the 55 aggregate, or (B) any sale or transfer of assets by Double E (other than (x) sales or other dispositions of obsolete assets in the ordinary course of business or (y) sales in compliance with Section 6.12 of the Double E LLC Agreement (as in effect on the Effective Date, without any amendments, modifications, supplements, waivers or other changes thereto) and that have a sale price less than $__); provided that, in the case of both clauses (A) and (B), such Transfer must be on an arms’ length basis for fair market value (which, in the case of the Company, shall be as determined in Good Faith by the Board); provided further that, without limiting the foregoing, in the case of both clauses (A) and (B), 100% of such sale proceeds actually received by the Company (whether directly as a result of such sale or as a distribution from a Subsidiary of the Company) shall be concurrently applied to optionally redeem the Series A Preferred Units in accordance with Section 4.8(b), and any other proceeds received by a Subsidiary of the Company shall be used: (i) to fund “Required Contributions” (as such term is defined in the Double E LLC Agreement), (ii) to repay Funded Indebtedness or (iii) to fund operations of Double E; (xvi) subject to Section 6.8(b)(xv), any Permitted Summit Operating Sell-Down with respect to which 100% of the proceeds are not (A) if actually received by the Company (whether directly as a result of such Transfer or as a distribution from a Subsidiary of the Company), concurrently applied to optionally redeem the Series A Preferred Units in accordance with Section 4.8(b) or (B) if not actually received by the Company, used (i) to fund “Required Contributions” (as such term is defined in the Double E LLC Agreement), (ii) to repay Funded Indebtedness or (iii) to fund operations of Double E; (xvii) any use by the Company or its Subsidiaries (other than Double E) of (A) Specified Exxon Proceeds for any purpose other than (A) if actually received by the Company, optionally redeeming the Series A Preferred Units in accordance with Section 4.8(b) or (B) if not actually received by the Company, used (i) to fund “Required Contributions” (as such term is defined in the Double E LLC Agreement), (ii) to repay Funded Indebtedness or (iii) to fund operations of Double E; except for “Required Contributions” as such term is defined in the Double E LLC Agreement, incur any capital expenditures by the Company or its Subsidiaries in excess of $____ more than the aggregate amount provided in the Development Budget on an 8/8ths basis; (xviii) (A) any change to the principal line of business of the Company and its Subsidiaries beyond engaging in the Business and activities that are related or incidental thereto or (B) using any Capital Contributions for any purposes other than in furtherance of the Business; (xix) (xx) except for “De Minimis Affiliate Contracts” as defined in the Double E LLC Agreement (as in effect on the Effective Date, without any amendments, modifications, supplements, waivers or other changes thereto), any agreement (or amendment or termination thereof) or transaction between the Company or any of its Subsidiaries, including any equity issuance or transfer or business combination of any nature, on the one hand, and any of its officers, employees, members of the Board, Holders 56 of Units or Affiliates, Summit Parent or its Controlled Subsidiaries or ECP or any Qualifying Owner, on the other hand, unless such transaction is (A) consummated in the ordinary course of business of the Company or such Subsidiary, (B) on terms no less favorable to the Company or such Subsidiary than would be obtained in a comparable arms-length transaction with a third party and (C) involving total consideration not in excess of $__; (xxi) any amendment, alteration, modification, waiver, repeal or similar change to (including by way of merger, consolidation, conversion or other transaction), or any termination of, a Material Contract (including, but not limited to, the C&M Agreement and the O&M Agreement) which (A) in the case of a Material Contract in which the Company is a party, adversely affects the rights, preferences, privileges or benefits of the Company or (B) in the case of any Material Contract, that would reasonably be expected to be adverse to the Series A Preferred Units or any of the Holders thereof; any amendment, alteration, modification, waiver, repeal or similar change to (including by way of merger, consolidation, conversion or other transaction), or any termination (other than by its terms) of, the Summit Parent Guarantee other than in accordance with a Permitted Summit HoldCo Sell-Down; (xxii) (xxiii) any conversion of the Company into a corporation or other type of entity; (xxiv) (A) liquidating or dissolving the Company or any of its Subsidiaries; (B) taking any action that results, or would reasonably be expected to result, in a Bankruptcy Event of the Company or any of its Subsidiaries; (C) adopting a plan of liquidation of the Company or any of its Subsidiaries; (D) taking any action to commence any suit, case, proceeding or other action under any existing or future Law of any jurisdiction relating to bankruptcy, insolvency, reorganization or relief of debtors seeking to have an order for relief entered with respect to the Company or any of its Subsidiaries, or seeking to adjudicate the Company or any of its Subsidiaries as bankrupt or insolvent, or seeking reorganization, arrangement, adjustment, winding-up, liquidation, dissolution, composition or other relief with respect to the Company or any of its Subsidiaries; (E) appointing a receiver, trustee, custodian or other similar official for the Company or any of its Subsidiaries, or for all or any material portion of the assets of the Company or any of its Subsidiaries; or (F) making a general assignment for the benefit of the creditors of the Company or any of its Subsidiaries; purposes of a Permitted Summit Operating Sell-Down; (xxv) forming any Subsidiary of the Company other than a New Intermediate Holdco for any election by the directors elected by Permian Transmission to the board of managers of Double E to continue development of the Double E Pipeline in accordance with Section 3.22(a)(ii) of the Double E LLC Agreement; (xxvi) (xxvii) any change to the tax classification of the Company or any of its Subsidiaries; 57 refraining from making a tax election under the Partnership Tax Audit Rules, which election would prevent the Company or any of its Subsidiaries from being liable for income tax adjustments in respect of its income; (xxviii) (xxix) (A) other than for the sole purpose of effecting, and to the extent necessary to effect, a Permitted Summit Operating Sell-Down, any amendment, alteration, modification, waiver, repeal or like change (including by way of merger, consolidation, conversion or other transaction or otherwise) to the governing documents of the Subsidiaries of the Company (other than the Double E LLC Agreement) or (B) solely with respect to the organizational documents of Double E, which would reasonably be expected to adversely affect Permian Transmission or that would reasonably be expected to be adverse to the Series A Preferred Units or any of the Holders thereof; and (xxx) agreeing or committing to take any of the preceding actions. (c) Notwithstanding anything in Section 6.8(b) to the contrary, in no event shall Preferred Approval be required in connection with any Capital Contribution by the Summit Member to the Company, by the Company to Permian Transmission or by Permian Transmission to Double E; provided that such Capital Contribution is made only in cash and is in exchange only for common equity interests of the issuing Entity. (d) Notwithstanding anything in this Agreement to the contrary, at any time Summit Parent (or any of its Affiliates, Qualifying Owners or Subsidiaries) or the Company (or any of its Subsidiaries) beneficially owns any of the Series A Preferred Units (and, in the case of the Company, to the extent such Series A Preferred Units have not been irrevocably cancelled by the Company), none of such Series A Preferred Units shall be considered outstanding Series A Preferred Units or otherwise counted or have any rights for purposes of Preferred Approval or any other approval, consent, vote, or similar right conferred to Holders of Series A Preferred Units or Series A Preferred Members in this Agreement or otherwise, including with respect to the calculation of Series A Preferred Sharing Percentage in connection with any of the foregoing. Section 6.9 Financial Covenant . Prior to FERC Approval, the Company and its Subsidiaries shall not incur, create, assume or guarantee any Funded Indebtedness. After FERC Approval and notwithstanding anything to the contrary in this Agreement, so long as any Series A Preferred Units remain outstanding, the Company and its Subsidiaries shall not incur, create, assume or guarantee any Funded Indebtedness, except with Preferred Approval, unless, (a) following such incurrence, creation, assumption or guarantee, the Total Invested Capital Ratio is less than ___% and (b) such Funded Indebtedness is a Market-Based Financing. Notwithstanding the foregoing and for the avoidance of doubt, so long as there is no Funded Indebtedness of the Company and its Subsidiaries (other than Double E) outstanding, the provisions of this Section 6.9 shall not limit the Company’s ability to draw the full amount of the Commitment pursuant to Section 4.3 and the Preferred Purchase Agreement. The Company and its Subsidiaries shall not agree to any terms in a Market-Based Financing that expressly limit the rights, preferences, privileges or powers of the Series A Preferred Units or of any of the Holders thereof under this Agreement relative to a Market-Based Financing. Prior to the Company and its Subsidiaries incurring (or agreeing or committing to incur) any Funded Indebtedness, the Company shall notify the Series A Preferred Members of its intention to incur Funded 58 Indebtedness, the contemplated terms of such Funded Indebtedness and whether any transactions involving the Company or any of its Subsidiaries are contemplated in connection therewith, and thereafter the Company shall reasonably and in good faith consult with TES Member regarding the terms of such Funded Indebtedness. ARTICLE VII RIGHTS OF MEMBERS; CONFIDENTIALITY Section 7.1 Access to Information; Inspection Rights . In addition to the other rights specifically set forth in this Agreement, the Members will have access to all information to which a Member is entitled to have access under the Act. The Company shall permit each Series A Preferred Member and each of its designated representatives, during normal business hours and upon reasonable advance notice to the Company, for any purpose reasonably related to such Series A Preferred Member’s Series A Preferred Units, to (a) inspect the books, records, contracts and agreements of the Company and its Subsidiaries, and, in each case, make copies thereof, (b) obtain any other information reasonably requested by such Series A Preferred Member relating to the Company and its Subsidiaries and (c) meet with senior management of the Company in respect of the items set forth in clauses (a) and (b). All costs incurred in such inspection will be borne by the requesting Series A Preferred Member; provided, that if it is determined that the Company or any of its Subsidiaries is in breach of this Agreement, then such costs will be borne by the Company. Section 7.2 Financial Reports; Information . The Company shall furnish the following financial reports and other information to the Members: not later than 30 days after the end of each calendar month, and in no event more than one day after such information is provided to Exxon, a copy of the “flash report” provided to Permian Transmission under Section 7.4(f) of the Double E Agreement; (a) within 45 days after the end of each quarter an unaudited consolidated balance sheet as of the end of such quarter and unaudited related income statement and statement of cash flows for such quarter including any footnotes thereto (if any) prepared in accordance with GAAP, consistently applied; (b) (c) within 90 days after the end of each Fiscal Year: an audited consolidated balance sheet as of the end of such Fiscal Year and the related consolidated income statement, statement of Members’ equity and statement of cash flows for such Fiscal Year prepared in accordance with GAAP and a signed audit letter from the Company’s auditors; and (i) Standards 114 and 115 for such Fiscal Year; (ii) a copy of the reports from the Company’s auditors pursuant to Statements of Auditing (d) within five days of receipt thereof, any reports delivered to (i) Permian Transmission or any of its Affiliates in such Person’s capacity as a member of Double E (including any “Capital Call Forecasts” (as defined in the Double E LLC Agreement)) and (ii) any Summit Director (as defined in the Double E LLC Agreement) in such Person’s capacity as a director of Double E; 59 (e) within 45 days after the end of the quarter ending March 31, 2020, and thereafter, within 45 days after the end of each quarter ending June 30 and December 31 of each year, a statement specifying, as to each Series A Preferred Member, such Series A Preferred Member’s number of Series A Preferred Units and the Base Return as to such Series A Preferred Units as of the last day of such quarter; and (f) solely to TES Member, such other information regarding the Company and its Subsidiaries reasonably requested by TES Member. Section 7.3 Confidentiality . (a) Each Member, on behalf of itself, its Affiliates and its advisors and designees, agrees that the provisions of this Agreement, all understandings, agreements and other arrangements between and among the Members, and all other non-public information received from or otherwise relating to the Company, its Subsidiaries and their respective businesses will be confidential, and will not be disclosed or otherwise released to any other Person (other than another Party), without the approval of the Board, unless such disclosure or release is otherwise permitted pursuant to the terms of a separate agreement between the Company (or one of its Subsidiaries), on the one hand, and such Member, on the other. The obligations of the Members hereunder will not apply to the extent that the disclosure of information otherwise determined to be confidential is required by applicable Law; provided, that prior to disclosing such confidential information, to the extent practicable a Member must notify the Company thereof, which notice will include the basis upon which such Member believes the information is required to be disclosed. Each Member agrees that it will not use any of such confidential information for any purpose other than in connection with its investment in the Company, including a potential sale or acquisition of its Units. (b) Notwithstanding anything in Section 7.3(a) to the contrary, any of the Series A Preferred Members may disclose confidential information regarding the nature and performance of its investment in the Company, including any reports furnished by the Company to the Series A Preferred Members in accordance with Article VII, (i) to investors or potential investors (whether such investors or potential investors, as applicable, are or would be direct or indirect investors) in such Series A Preferred Member, (ii) to such Series A Preferred Member’s Affiliates (other than any portfolio company Controlled by (A) such Series A Preferred Member or (B) any of such Series A Preferred Member’s Affiliates that Controls such Series A Preferred Member) and/or (iii) to transferees or potential transferees of Series A Preferred Units; provided, that such investors or potential investors, Affiliates or transferees or potential transferees are obligated (whether based on such Series A Preferred Member’s governing documents, policies, procedures or otherwise or a written agreement between such Person and a Series A Preferred Member) to provide a substantially similar degree of protection of such confidential information as in Section 7.3(a). Section 8.1 Tax Returns ARTICLE VIII TAXES . The Board will cause to be prepared, signed and filed all necessary federal, state and local income tax returns for the Company and the Board will select a 60 nationally recognized accounting firm to prepare the Company’s federal and state income tax returns. Unless modified by the Board due to a change of applicable Law or otherwise, any Officer duly appointed by the Board is authorized to sign any tax return for the Company. Each Member will furnish to the Board all pertinent information in its possession relating to Company operations that is necessary to enable the Company’s income tax returns to be prepared and filed. The Company shall furnish to each Member an estimated IRS Form K-1 with respect to such Member no later than February 28 following each Tax Year. The Company will furnish to each Member copies of all returns that are actually filed, promptly after their filing. The Company shall provide all assistance and information reasonably requested by a Member to support the preparation and filing of tax estimates and tax returns by the Member and the Member’s direct and indirect equity holders. Section 8.2 Tax Elections . manner: (a) Elections by the Company. The Company will make the following elections in the appropriate (i) (ii) (iii) to adopt the Tax Year of the Company set forth in Section 2.6; to adopt the accrual method of accounting; to elect to amortize the start-up expenses of the Company under Code Section 195 ratably over a period of 180 months as permitted by Code Section 195(b); ratably as permitted by Code Section 709(b); and (iv) to elect to amortize the organization expenses of the Company under Code Section 709 best interests of the Members. (v) subject to Section 8.2(b), any other election the Board may deem appropriate and in the (b) Characterization by the Company. It is the intent of the Members that the Company be treated as a partnership for federal income tax purposes and, to the extent permitted by applicable Law, for state and local franchise and income tax purposes. Neither the Company nor any Member may make an election for the Company to be excluded from the application of the provisions of subchapter K of chapter 1 of subtitle A of the Code or any similar provisions of applicable state or local Law or to be treated as a corporation, and no provision of this Agreement will be construed to sanction or approve such an election. Section 754 Election. At the request of any Holder of Series A Preferred Units, the Board shall cause the Company to elect, under Code Section 754, to adjust the basis of the Company’s assets as provided in Code Sections 734 and 743. (c) Section 8.3 Company Representative . The Board may appoint and replace a Company Representative and authorize the Company Representative to take any and all actions determined by the Board and permissible under the Partnership Tax Audit Rules. The Company authorizes the Company Representative to appoint a designated individual to act on behalf of the Company Representative. The Company Representative is authorized to take such actions and to execute and file all statements and forms on behalf of the Company that are approved by the Board 61 and are permitted or required by the applicable provisions of the Partnership Tax Audit Rules (including a “push-out” election under Section 6226 of the Internal Revenue Code or any analogous election under state or local tax Law). The Company Representative shall act in good faith to keep the Members informed as to the status of any audit of the Company’s tax affairs. Each Member shall cooperate with the Company Representative and to do or refrain from doing any or all things requested by the Company Representative (including paying any and all resulting taxes, additions to tax, penalties and interest in a timely fashion) in connection with any examination of the Company’s affairs by any federal, state or local tax authorities, including resulting administrative and judicial proceedings. No Member shall have any claim against the Company Representative, the Board or the Company for any actions taken (or any failures to take action) by such persons in good faith. Any reasonable, documented cost or expense incurred by the Company Representative in connection with its duties, including the preparation for or pursuance of administrative or judicial proceedings, shall be paid by the Company. Without first obtaining the written consent of a majority of the Board, the Company Representative shall not extend the statute of limitations, file a request for administrative adjustment, or file suit concerning any tax refund or deficiency relating to any Company administrative adjustment relating to any Company item of income, gain, loss, deduction or credit. The Company Representative shall not agree to a settlement relating to taxes without obtaining the written concurrence of each Holder of Series A Preferred Units who would be (or whose partners for U.S. federal income tax purposes would be) adversely economically affected by agreement to such settlement. ARTICLE IX BOOKS, RECORDS, REPORTS, AND BANK ACCOUNTS Section 9.1 Maintenance of Books and Records . The books of account for the Company and other records of the Company will be located at the principal office of the Company or such other place as the Board may deem appropriate, and will be maintained on an accrual basis in accordance with the terms of this Agreement, except that the Capital Accounts of the Members will be maintained in accordance with the definition of “Capital Account” in this Agreement. For financial reporting purposes, the books and records of the Company will be kept on the accrual method of accounting and in accordance with GAAP, in each case, applied in a consistent manner and such books and records will reflect all Company transactions. Section 9.2 Reports . The Company will cause to be prepared or delivered such reports as the Board may require. The Company will bear the costs of such reports. Section 9.3 Bank Accounts . The Board will cause the Company to establish and maintain one or more separate bank or investment accounts for Company funds in the Company name with such financial institutions and firms as the Board may select and with such signatories thereon as the Board may designate. Company funds shall only be held in such separate accounts and may not be comingled with funds belong to other Persons. 62 ARTICLE X DISSOLUTION, LIQUIDATION, TERMINATION AND CONVERSION Section 10.1 Dissolution . The Company will dissolve and its affairs will be wound up upon the first to occur of either of the following (each, a “Dissolution Event”): Board; or (a) subject to Section 6.2(n) and Section 6.8(b)(xxiv), an election to dissolve the Company by the (b) the occurrence of any other event causing dissolution of the Company under the Act; provided, however, that, upon dissolution in accordance with clause (b) of this Section 10.1, any or all of the remaining Members may elect to continue the Business of the Company within 90 days of the occurrence of the event causing such dissolution. The death, resignation, withdrawal, bankruptcy, insolvency or expulsion of any Member will not dissolve the Company. Section 10.2 Liquidation and Termination . (a) Upon the occurrence of a Dissolution Event, the Company’s business will be liquidated in an orderly manner. The Board shall appoint a liquidating trustee to wind up the affairs of the Company pursuant to this Agreement. In performing its duties, the liquidating trustee is authorized to sell, distribute, exchange or otherwise dispose of the assets of the Company in accordance with the Act and in any reasonable manner that the liquidating trustee determines to be in the best interest of the Members. priority: (b) The proceeds of the liquidation of the Company will be distributed in the following order and (i) First, to the creditors (including any Members or their respective Affiliates that are creditors, including as a result of the TES Member’s exercise of its rights under Section 4.8(a), in respect of which it should be a creditor of the Company) of the Company in satisfaction of all of the Company’s indebtedness (whether by payment or by making reasonable provision for payment thereof, including the setting up of any reserves which are, in the judgment of the liquidating trustee, reasonably necessary therefor); (ii) Second, 100% to the Holders of Series A Preferred Units until an amount of cash has been distributed in respect of each Series A Preferred Unit equal to the Base Return; provided that if the proceeds of liquidation of the Company are insufficient to pay in full all such amounts to the Holders of Series A Preferred Units, then all such proceeds of liquidation that are actually available shall be distributed to the Holders of Series A Preferred Units, equally and ratably, in proportion to the full distributable amounts which such Holders are entitled upon such liquidation; and practicable. (iii) Third, the remainder, if any, 100% to the Common Unit Members, as promptly as Notwithstanding anything to the contrary in this Agreement (and without limiting the rights set forth in Section 6.8), in any transaction which would result in a Change of Control or a deemed liquidation of the Company, the consideration received by the Company or (c) 63 its equityholders shall be allocated and distributed or paid, (i) first, 100% to the Holders of Series A Preferred Units until an amount of cash has been distributed in respect of each Series A Preferred Unit equal to the Base Return; provided that if the consideration received is insufficient to pay in full all such amounts to the Holders of Series A Preferred Units, then all such consideration actually available shall be distributed to the Holders of Series A Preferred Units, equally and ratably, in proportion to the full distributable amounts which such Holders are entitled, before any amounts are allocated, distributed or paid to any other Member and (ii) thereafter, 100% to the Common Unit Members. (d) In the event it becomes necessary in connection with the liquidation of the Company to make a distribution of Property in-kind, subject to the priority set forth in Section 10.2, the liquidating trustee will have the right to compel each Member (other than any Series A Preferred Member) to accept a distribution of any Property in-kind, with such distribution being based upon the amount of cash that would be distributed to such Members if such Property were sold for an amount of cash equal to the Fair Market Value of such Property, as determined by the liquidating trustee in good faith. Section 10.3 Cancellation of Filing . On completion of the distribution of Company assets as provided in this Agreement, the Company will be terminated, and the Board (or such other Person or Persons as may be required) will cause the cancellation of any other filings previously made on behalf of the Company and will take such other actions as may be necessary to terminate the Company. Section 10.4 Survival . Termination, dissolution, liquidation or winding up of the Company for any reason will not release any Party from any liability which at the time of such termination, dissolution, liquidation or winding up already had accrued to any other Party or which thereafter may accrue in respect to any act or omission prior to such termination, dissolution, liquidation or winding up. Section 11.1 Offset ARTICLE XI GENERAL PROVISIONS . Whenever the Company is to pay any sum to any Member, any amounts such Member owes the Company or its Affiliates may be deducted from that sum before payment. Section 11.2 Notices . All notices, requests or consents provided for or permitted to be given under this Agreement will be in writing (except as otherwise provided in Section 11.15) and will be given (a) by depositing such writing in the United States mail, addressed to the recipient, postage paid and certified with return receipt requested, (b) by depositing such writing with a reputable overnight courier for next day delivery, (c) by delivering such writing to the recipient in person, by courier or (d) e-mail transmission (with request for confirmation of receipt from the recipient); provided, however, that any notice to be delivered to any of the Series A Preferred Members (or Holders of Series A Preferred Units) under this Agreement that is given by email transmission shall also substantially concurrently be given by the means described in the foregoing clauses (a), (b) or (c). A notice, request or consent given under this Agreement will be effective on receipt by the Person to receive notices, requests and consents to be sent to a Member will be 64 sent to or made at the addresses given for that Member on the list attached hereto as Exhibit A or such other address as that Member may specify by notice to the other Members. Any notice, request or consent to the Company also will be given by the Company to the Board. The use of an electronic signature to conduct a transaction, indicate the execution of an agreement or provide notice or other form of communication is expressly authorized. Section 11.3 Entire Agreement; Supersedure . This Agreement, together with its Exhibits and the Other Transaction Documents, constitutes the entire agreement of the Members relating to the Company and supersede all prior contracts or agreements with respect to the Company, whether oral or written. Nothing in this Agreement, express or implied, is intended to confer upon any Person other than the parties to this Agreement and their respective successors and permitted assigns, any rights or remedies under or by reason of this Agreement; provided, however, that (a) the Officers and former Officers (but only with respect to the time during which they served as Officers) are intended to be third party beneficiaries of Section 6.4 and Section 6.5, with rights to enforce such provisions as though a Party; (b) Nonparty Affiliates are intended to be third party beneficiaries with rights to enforce the provisions of Section 6.7 of this Agreement as though a Party; and (c) Covered Persons are intended to be third party beneficiaries with rights to enforce the provisions of Section 6.6 of this Agreement as though a Party. Section 11.4 Effect of Waiver or Consent . A waiver or consent, express or implied, to or of any breach or default by any Person in the performance by that Person of its obligations with respect to the Company will not constitute a consent or waiver to or of any other breach or default in the performance by that Person of the same or any other obligations of that Person with respect to the Company. Failure on the part of a Person to complain of any act of any Person or to determine any Person to be in default with respect to the Company, irrespective of how long such failure continues, will not constitute a waiver by that Person of its rights with respect to that default until the applicable limitations period has expired. Section 11.5 Amendment or Modification . Subject to the Company’s receipt of all Preferred Approvals as required under Section 6.8 or other sections where expressly set forth elsewhere in this Agreement, this Agreement may be amended or modified from time to time by a written instrument that is adopted by the Board; provided, however, in no event shall this Agreement be amended, supplemented, or otherwise modified, by merger, consolidation, conversion or other transactions or otherwise, (a) to require any Member to make a Capital Contribution to the Company without that Member’s prior written consent, (b) in a manner that would adversely affect a Nonparty Affiliate’s rights or protections under Section 6.7; (c) in a manner that would adversely affect a Covered Person’s rights or protections under Section 6.7. Notwithstanding anything in this Agreement to the contrary, no Member approval is required for any amendment made by the Board (x) to Exhibit A in accordance with Section 3.1 or (y) if an action, event or transaction that is subject to Preferred Approval under Section 6.8 or where expressly set forth elsewhere in this Agreement and which does receive Preferred Approval, in connection with effecting such action, event or transaction, as long as the amendment, supplement or modification itself is reviewed by the Series A Preferred Members and receives Preferred Approval. Notwithstanding anything to the contrary in this Section 11.5, nothing in this Section 11.5 shall limit the requirements of Section 6.8. 65 Section 11.6 Survivability of Terms . The terms and provisions of the obligations or agreements of the Members under Section 3.4, Section 6.4, Section 6.5, Section 6.6, Section 6.7, Section 7.3, Section 11.3 and Article IX in this Agreement shall survive any termination of this Agreement and will be construed as agreements independent of any other provisions of this Agreement. Section 11.7 Binding Effect . Subject to the restrictions on Transfer set forth in this Agreement, this Agreement will be binding on and inure to the benefit of the Members and their respective heirs, legal representatives, trustees, successors, and assigns. Section 11.8 Governing Law; Severability . This Agreement is governed by and will be construed in accordance with the Laws of the State of Delaware, excluding any conflict-of-laws rule or principle (whether under the Laws of Delaware or any other jurisdiction) that might refer the governance or the construction of this Agreement to the Law of another jurisdiction. If any provision of this Agreement or its application to any Person or circumstance is held invalid or unenforceable to any extent, the remainder of this Agreement and the application of such provision to other Persons or circumstances will not be affected thereby, and such provision will be enforced to the greatest extent permitted by Law. Section 11.9 Consent to Jurisdiction; Waiver of Jury Trial . (a) EACH OF THE PARTIES IRREVOCABLY SUBMITS TO THE EXCLUSIVE JURISDICTION OF THE COURT OF CHANCERY OF THE STATE OF DELAWARE LOCATED IN WILMINGTON, DELAWARE FOR THE PURPOSES OF ANY SUIT, ACTION OR OTHER PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY TRANSACTION CONTEMPLATED HEREBY. EACH OF THE PARTIES IRREVOCABLY AND UNCONDITIONALLY WAIVES ANY OBJECTION TO THE LAYING OF VENUE OF ANY ACTION, SUIT OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY IN THE COURT OF CHANCERY OF THE STATE OF DELAWARE LOCATED IN WILMINGTON, DELAWARE AND WAIVES ANY CLAIM THAT SUCH SUIT OR PROCEEDING HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. EACH PARTY AGREES THAT LIABILITY OF THE PARTIES ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY TRANSACTION CONTEMPLATED HEREBY SHALL BE DETERMINED SOLELY BY A FINAL AND NON-APPEALABLE JUDGMENT IN ANY ACTION OR PROCEEDING (OR A SETTLEMENT TANTAMOUNT THERETO) AND ANY SUCH FINAL AND NON-APPEALABLE JUDGMENT SHALL BE CONCLUSIVE AND MAY BE ENFORCED BY SUIT ON THE JUDGMENT IN ANY JURISDICTION WITHIN OR OUTSIDE THE UNITED STATES OR IN ANY OTHER MANNER PROVIDED IN LAW OR IN EQUITY. (b) EACH PARTY ACKNOWLEDGES AND AGREES THAT ANY CONTROVERSY WHICH MAY ARISE UNDER THIS AGREEMENT IS LIKELY TO INVOLVE COMPLICATED AND DIFFICULT ISSUES AND, THEREFORE, EACH SUCH PARTY IRREVOCABLY AND UNCONDITIONALLY WAIVES ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LEGAL ACTION ARISING DIRECTLY OR INDIRECTLY OUT OF OR RELATING TO THIS AGREEMENT OR THE 66  EACH PARTY TO THIS AGREEMENT CERTIFIES AND TRANSACTIONS CONTEMPLATED HEREBY. ACKNOWLEDGES THAT (A) NO REPRESENTATIVE OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT SEEK TO ENFORCE THE FOREGOING WAIVER IN THE EVENT OF A LEGAL ACTION, (B) SUCH PARTY HAS CONSIDERED THE IMPLICATIONS OF THIS WAIVER, (C) SUCH PARTY MAKES THIS WAIVER VOLUNTARILY, AND (D) SUCH PARTY HAS BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION 11.9(b). Section 11.10 Specific Performance . The parties to this Agreement acknowledge that money damages may not be an adequate remedy for breaches or violations of this Agreement and that any Party, in addition to any other rights and remedies which the parties to this Agreement may have hereunder or at law or in equity, may, in its sole discretion, apply to a court of competent jurisdiction in accordance with Section 11.9 for specific performance or injunction or such other equitable relief as such court may deem just and proper in order to enforce this Agreement in the event of any breach of the provisions of this Agreement or prevent any violation hereof and, to the extent permitted by applicable Law, each Party hereby waives (a) any objection to the imposition of such relief and (b) any requirement for the posting of any bond or similar collateral in connection therewith. Section 11.11 Further Assurances . In connection with this Agreement and the transactions contemplated hereby, each Member will execute and deliver any additional documents and instruments and perform any additional acts that may be necessary or appropriate to effectuate and perform the provisions of this Agreement and such transactions. Section 11.12 Waiver of Certain Rights . To the maximum extent permitted by applicable Law, each Member irrevocably waives any right it might have to maintain any action for dissolution of the Company, or to maintain any action for partition of the property of the Company. Section 11.13 Title to Company Property . All assets shall be deemed to be owned by the Company as an entity, and no Member, individually, shall have any ownership of such property. Section 11.14 Counterparts . This Agreement may be executed in any number of counterparts with the same effect as if all signatories had signed the same document. All counterparts will be construed together and constitute the same instrument. Section 11.15 Electronic Transmissions . Each of the parties to this Agreement agrees that (a) any consent or signed document transmitted by electronic transmission shall be treated in all manner and respects as an original written document, (b) any such consent or document shall be considered to have the same binding and legal effect as an original document and (c) at the request of any Party, any such consent or document shall be re-delivered or re-executed, as appropriate, by the relevant Party or Parties in its original form. Each of the parties further agrees that they will not raise the transmission of a consent or document by electronic transmission as a defense in any proceeding or action in which the validity of such consent or document is at issue 67 and hereby forever waives such defense. For purposes of this Agreement, the term “electronic transmission” means any form of communication not directly involving the physical transmission of paper, that creates a record that may be retained, retrieved and reviewed by a recipient thereof, and that may be directly reproduced in paper form by such a recipient through an automated process. Section 11.16 Legal Counsel . (a) The Members acknowledge and agree that Kirkland & Ellis LLP (“Kirkland”) (i) has represented TES Member and certain of its Affiliates in connection with the negotiation, execution and delivery of this Agreement and all other agreements contemplated by this Agreement (including the Preferred Purchase Agreement), (ii) has not represented the Company or any Member other than TES Member and (iii) in no event shall an attorney-client relationship be deemed to exist between Kirkland, on the one hand, and the Members (other than TES Member) or any of its respective Affiliates, or the Company, on the other hand, in respect of Kirkland’s representation as described in clauses (i) and (ii) above. (b) The Members acknowledge and agree that Baker Botts L.L.P. (“Baker Botts”) (i) has represented Summit Member and certain of its Affiliates in connection with the negotiation, execution and delivery of this Agreement and all other agreements contemplated by this Agreement (including the Preferred Purchase Agreement), (ii) has not represented any Member other than Summit Member and (iii) in no event shall an attorney-client relationship be deemed to exist between Baker Botts, on the one hand, and the Members (other than Summit Member) or any of their respective Affiliates, on the other hand, in respect of Baker Botts’ representation as described in clauses (i) and (ii) above. Section 11.17 Special Purpose Entity . outstanding, the Company shall not (and Summit Parent shall cause the Company not to): (a) Notwithstanding anything in this Agreement to the contrary, for so long as any Units remain fail to observe all corporate formalities and other formalities required by this Agreement or its other organizational documents or the Laws of the State of Delaware, or fail to preserve its existence as an entity duly organized, validly existing and in good standing (if applicable) under the Act; (i) commingle its funds or assets with the funds or assets of any other Person; provided, however, that distributions made by the Company not in violation of this Agreement shall not be considered assets of the Company for purposes of this clause (ii); (ii) from those of any other Person (including any Affiliates); (iii) fail to maintain all of its books, records, financial statements and bank accounts separate or identify its individual assets from those of any other Person; (iv) maintain its assets in such a manner that it will be costly or difficult to segregate, ascertain 68 being available to satisfy the obligations of any other Person; (v) hold itself out to be responsible for the debts of any other Person or hold out its credit as (vi) fail to (A) hold itself out to the public and identify itself, in each case, as a legal entity separate and distinct from any other Person and not as a division or part of any other Person, (B) conduct its business solely in its own name, (C) hold its assets in its own name or (D) correct any known misunderstanding regarding its separate identity; stationery, invoices and checks; (vii) fail to allocate shared expenses (including shared office space) or fail to use separate (viii) (ix) fail to pay its own liabilities from its own funds; guarantee, or otherwise become a restricted subsidiary pursuant to any agreement governing, any indebtedness of Summit Member, the Series A Preferred Members or any of their respective Affiliates; (x) fail to be adequately capitalized to engage in its business separate and apart from Summit Member, the Series A Preferred Members or each of their respective Affiliates and to remain solvent; provided, that the foregoing shall not be construed as imposing an obligation on any Member to contribute or loan additional capital, property or services to the Company; or fail to ensure that all material transactions between the Company, on the one hand, and Summit Member, the Series A Preferred Members or their respective Affiliates, on the other hand, whether currently existing or hereafter entered into, will be only on an arm’s length basis. (xi) (b) The Company’s assets have not and will not be listed as assets on the financial statement of any other Person; provided, however, that the Company’s assets may be consolidated for financial reporting purposes with Summit Parent and its Subsidiaries; provided, further that (i) appropriate notation shall be made on such consolidated financial statements or notes thereto in accordance with GAAP to indicate the separateness of the Company and such Affiliates and to indicate that the Company’s assets and credit are not available to satisfy the debts and other obligations of such Affiliates or any other Person and (ii) such assets shall be listed on the Company’s own separate balance sheet. Such consolidation shall not affect the status of the Company as a separate legal entity with its separate assets and separate liabilities. The Company has maintained and will maintain its books, records, resolutions and agreements as official records. Failure by the Board or the Company to comply with any of the obligations set forth in this Section 11.17 shall not affect the status of the Company as a separate legal entity, with its separate assets and separate liabilities. Summit Parent and each of the Members acknowledge and agree that the Company is a special purpose, non-guarantor, unrestricted, indirect Subsidiary of Summit Parent and shall be bankruptcy remote from Summit Parent and each of Summit Parent’s Subsidiaries other than the Company. (c) [Signature Pages Follow] 69 IN WITNESS WHEREOF, the undersigned Members have executed this Agreement effective as of the Effective Date. SUMMIT MEMBER: SUMMIT MIDSTREAM PERMIAN II, LLC /s/ Marc Stratton By: Name: Marc Stratton Title: Executive Vice President and Chief Financial Officer SIGNATURE PAGE TO AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF SUMMIT PERMIAN TRANSMISSION HOLDCO, LLC SERIES A PREFERRED MEMBERS: TPG ENERGY SOLUTIONS ANTHEM, L.P. /s/ Adam Fliss By: Name: Adam Fliss Title: Vice President Solely for purposes of Sections 3.6(a) 4.9 and 11.17: SUMMIT PARENT: SUMMIT MIDSTREAM PARTNERS, LP By: SUMMIT MIDSTREAM GP, LLC, its general partner /s/ Marc Stratton By: Name: Marc Stratton Title: Executive Vice President and Chief Financial Officer Name Summit Midstream Holdings, LLC Grand River Gathering, LLC DFW Midstream Services LLC Bison Midstream, LLC Summit Midstream Finance Corp. Red Rock Gathering Company, LLC Polar Midstream, LLC Epping Transmission Company, LLC Summit Midstream Utica, LLC Meadowlark Midstream Company, LLC Mountaineer Midstream Company, LLC Summit Midstream OpCo, LP Summit Midstream Marketing, LLC Summit Midstream Niobrara, LLC Summit Midstream Permian, LLC Summit Midstream Permian Finance, LLC Summit Midstream Permian II, LLC Summit Permian Transmission, LLC Summit Permian Transmission Holdco, LLC SUMMIT MIDSTREAM PARTNERS, LP LIST OF SUBSIDIARIES State or other jurisdiction of incorporation or organization EXHIBIT 21.1 Delaware Delaware Delaware Delaware Delaware Delaware Delaware Delaware Delaware Delaware Delaware Delaware Delaware Delaware Delaware Delaware Delaware Delaware Delaware EX 21.1-1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in Registration Statement Nos. 333-234781, and 333-219196 on Form S-3 and Nos. 333- 184214 and 333-189684 on Form S-8 of our reports dated March 9, 2020, 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, 2019. EXHIBIT 23.1 /s/ DELOITTE & TOUCHE LLP Atlanta, Georgia March 9, 2020 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 Statements on Form S-3 (No. 333-234781) and the Registration Statements on Form S-8 (Nos. 333-184214 and 333-189684) 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 6, 2020 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 9, 2020 /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 9, 2020 /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, 2019, 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 9, 2020 /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 9, 2020 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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