| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||
Common Units | SMLP | New York Stock Exchange | ||||||
Accelerated filer Non-accelerated filer Smaller reporting company Emerging growth 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. $129,415,408. Common Units •our decision whether to pay, or our ability to grow, our cash distributions; •fluctuations in natural gas, NGLs and crude oil prices, including as a result of political or economic measures taken by various countries or OPEC; •the extent and success of our customers' drilling and completion efforts, as well as the quantity of natural gas, crude oil, fresh water deliveries, and produced water volumes produced within proximity of our assets; •the current and potential future impact of the COVID-19 pandemic on our business, results of operations, financial position or cash flows; •failure or delays by our customers in achieving expected production in their natural gas, crude oil and produced water projects; •competitive conditions in our industry and their impact on our ability to connect hydrocarbon supplies to our gathering and processing assets or systems; •actions or inactions taken or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers; •our ability to divest of certain of our assets to third parties on attractive terms, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets; •the ability to attract and retain key management personnel; •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; •our ability to comply with the terms of the agreements comprising the Global Settlement; •weather conditions and terrain in certain areas in which we operate; •physical and financial risks associated with climate change; •timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule; •our ability to finance our obligations related to capital expenditures, including through opportunistic asset divestitures or joint ventures and the impact any such divestitures or joint ventures could have on our results; •the effects of existing and future laws and governmental regulations, including environmental, safety and climate change requirements and federal, state and local restrictions or requirements applicable to oil and/or gas drilling, production or transportation; •changes in tax status; Risks Related to Our Operations •We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay distributions to holders of our preferred units and common units. •We depend on a relatively small number of customers for a significant portion of our revenues. •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. •Significant prolonged weakness in natural gas, NGL and crude oil prices could reduce throughput on our systems and materially adversely affect our revenues and ability to make cash distributions to our unitholders. •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. •Customers may not drill and complete wells on the acreage behind our systems, which could adversely impact the levels of throughput on our systems. •We may not be able to renew or replace expiring contracts at favorable rates or on a long term basis. •Our ability to operate our business effectively could be impaired if we fail to attract and retain key personnel. •Limited access to and/or availability of the commercial bank market, debt and equity capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements. •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. •We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful. •A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenues to decline or our operation and maintenance expenses to increase. •Increased regulation of hydraulic fracturing could result in reductions or delays in customer production, which could materially adversely impact our revenues. •We are subject to FERC jurisdiction, federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements and state and local regulation, and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced. •We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities. •Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the services we provide. • We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from various groups. •Our Partnership Agreement replaces our General Partner’s fiduciary duties to unitholders and those of our officers and directors with contractual standards governing their duties. • We may issue additional units without unitholder approval, which would dilute existing ownership interests. Summit Holdings' and Finance Corp.’s 5.75% senior unsecured notes due April 2025 Summit Holdings' and Finance Corp.’s 8.500% senior secured second lien notes due 2026 customers within the AMI be shipped on and/or processed by our gathering systems associated natural gas 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 ASC Accounting Standards Codification ASU Accounting Standards Update Bbl one barrel; used for crude oil and produced water and equivalent to 42 U.S. gallons Bcf one billion cubic feet Bcfe/d 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 Bison Midstream, LLC Board of Directors the board of directors of our General Partner CAA Clean Air Act CEA Commodity Exchange Act CERCLA Comprehensive Environmental Response, Compensation and Liability Act CFTC Commodity Futures Trading Commission cancellation of debt a natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions Conflicts Committee the conflicts committee of the Board of Directors, Summit Holdings and Finance Corp. DFW Midstream DFW Midstream Services LLC DJ Basin Denver-Julesburg Basin Dodd-Frank Act Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 DOT U.S. Department of Transportation Double E Double E Pipeline, LLC Double E commenced operations in November 2021 and provides transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Double E Project natural gas primarily composed of methane where heavy hydrocarbons and water either do not exist or have been removed through processing or treating one million British Thermal Units per day EPA Environmental Protection Agency Epping Epping Transmission Company, LLC an interstate crude oil pipeline in North Dakota, owned and operated by Epping Securities Exchange Act of 1934, as amended FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission Finance Corp. Summit Midstream Finance Corp. FTC Federal Trade Commission GAAP accounting principles generally accepted in the United States of America General Partner Summit Midstream GP, LLC GHG greenhouse gas(es) GP general partner Grand River Gathering, LLC Guarantor Subsidiaries 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, Mountaineer Midstream, Epping, Red Rock, Polar Midstream and hub geographic location of a storage facility and multiple pipeline interconnections ICA Interstate Commerce Act Intercreditor Agreement, dated as of November 2, 2021, by and among Bank of America, N.A., as first lien representative and collateral agent for the initial IRS Internal Revenue Service LIBOR London Interbank Offered Rate one thousand barrels per day Management's Discussion and Analysis of Financial Condition and Results of Operations MDTQ Meadowlark Midstream Company, LLC MMBtu one million British Thermal Units MMcf one million cubic feet MMcf/d one million cubic feet per day MMcfe/d Mountaineer Midstream Company, LLC MVC minimum volume commitment NAAQS national ambient air quality standard NEPA National Environmental Policy Act North Dakota Industrial Commission NGLs 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 NGPA Natural Gas Policy Act of 1978 Niobrara G&P Niobrara Gathering and Processing system Non-Guarantor Subsidiaries Permian Holdco and Summit Permian Transmission NYSE New York Stock Exchange the Co-Issuers and the Guarantor Subsidiaries OGC Ohio Gathering Company, L.L.C. Ohio Gathering Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C. OPA Oil Pollution Control Act OpCo Summit Midstream OpCo, LP play a proven geological formation that contains commercial amounts of hydrocarbons Permian Finance Summit Midstream Permian Finance, LLC Permian Holdco Summit Permian Transmission Holdco, LLC Permian Term Loan Facility the Polar and Divide system; collectively Polar Midstream and Epping Polar Midstream Polar Midstream, LLC produced water water from underground geologic formations that is a by-product of natural gas and crude oil production PSD Prevention of Significant Deterioration RCRA Resource Conservation and Recovery Act Red Rock Gathering Red Rock Gathering Company, LLC Revolving Credit Facility the senior secured revolving credit facility governed by the Fourth Amended and Restated Credit Agreement dated as of December 18,2020, as amended by the Third Amended and Restated Credit Agreement dated as of May 26, 2017, as amended by the First Amendment to Third Amended and Restated Credit Agreement dated as of September 22, 2017, the Second Amendment to Third Amended and Restated Credit Agreement dated as of June 26, 2019 and the Third Amendment to Third Amended and Restated Credit Agreement dated as of December 24, 2019 SEC Securities and Exchange Commission Securities Act Securities Act of 1933, as amended segment adjusted EBITDA total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) unit- based and noncash compensation, (vii) impairments and (viii) other noncash expenses or losses, less other noncash income or gains Series A Preferred Units Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units shortfall payment the payment received from a counterparty when its volume throughput does not meet its MVC for the applicable period SMLP Summit Midstream Partners, LP SMLP Holdings SMLP Holdings, LLC SMLP LTIP SMLP Long-Term Incentive Plan SMP Holdings Summit Midstream Partners Holdings, LLC, also known as SMPH Subsidiary Series A Preferred Units Series A Fixed Rate Cumulative Redeemable Preferred Units issued by Permian Holdco Summit Holdings Summit Midstream Holdings, LLC Summit Investments Summit Midstream Partners, LLC Summit Niobrara Summit Midstream Niobrara, LLC Summit Marketing Summit Midstream Marketing, LLC Summit Permian Summit Midstream Permian, LLC Summit Permian II Summit Midstream Permian II, LLC Summit Permian Transmission Summit Permian Transmission, LLC Summit Utica Summit Midstream Utica, LLC the Tax Cuts and Jobs Act of 2017 the Partnership Summit Midstream Partners, LP and its subsidiaries the Partnership 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 Tioga Midstream, LLC basin 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 VOC volatile organic compound(s) wellhead 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 •Capital structure optimization. We seek to maximize unitholder value. Our capital structure currently consists of common equity, preferred equity, and indebtedness that is comprised of debt securities and borrowings under our revolving credit facilities, a portion of which is secured by substantially all of the Partnership's assets. We intend to optimize our capital structure in the future by reducing our indebtedness with free cash flow, and when appropriate, we may pursue opportunistic capital markets transactions with the objective of increasing long-term unitholder value. •Portfolio management. We seek to maximize unitholder value by strategically managing our portfolio of midstream assets and allocating capital based on appropriate risk-informed cash flow assumptions. This may include opportunistic divestitures, re-allocation of capital to new or existing areas, and development of joint ventures involving our existing midstream assets or new investment opportunities. •Maintaining our focus on fee-based revenue with minimal direct commodity price exposure. We intend to maintain our focus on providing midstream services under primarily long-term and fee-based contracts. We believe that our focus on fee-based revenues with minimal direct commodity price exposure is essential to maintaining stable cash flows. Maintaining strong producer relationships to maximize utilization • •Simultaneously completed the strategic 2022 DJ Acquisitions for $305.0 million. In December 2022, we acquired Outrigger DJ for cash consideration of $165.0 million, subject to post-closing adjustments, and Sterling DJ for cash consideration of $140.0 million, subject to post-closing adjustments. These acquisitions were a strategic step in our overall corporate strategy to establish a franchise position in the DJ Basin and expand our footprint for the benefit of our customers. The 2022 DJ Acquisitions significantly increased our gas processing capacity in the DJ Basin and diversified our customer base with a combination of long-term fixed fee and percentage-of-proceeds contracts. We funded these acquisitions through a combination of borrowings under the credit facility and the issuance of $85.0 million of Senior Secured Second Lien Notes due in 2026. •Portfolio optimization – Permian Midstream Divestiture. In June 2022, we completed the disposition of all the equity interests in Summit Permian, which owns the Lane Gathering and Processing System (“Lane G&P System”), and Permian Finance to Longwood Gathering and Disposal Systems, LP (“Longwood”), a wholly owned subsidiary of Matador ͏Resources Company (“Matador”), for cash consideration of $75.0 million. In connection with the transaction, we released, to a subsidiary of Matador, and Matador agreed to assume, take or-pay firm capacity on the Double E Pipeline. •Portfolio optimization – Bison Midstream Divestiture. In September 2022, we completed the sale of Bison Midstream, LLC (“Bison Midstream”) and its gas gathering system in Burke and Mountrail Counties, North Dakota to a subsidiary of Steel Reef Infrastructure Corp. (“Steel Reef”) for cash consideration of $40.0 million. •Issued inaugural Environmental, Social and Governance Report (“ESG Report”). In June 2022, we published our initial ESG Report. The report showcases our commitment to core principles that drive operational excellence, sustainability and value for our business. These principles include prioritizing safe and reliable operations, minimizing our environmental impact, protecting our employees’ health and wellbeing, and following responsible and ethical business practices. The ESG Report can be found at www.summitmidstream.com/esg but is not incorporated by reference and is not a part of this Annual Report on Form 10-K. We •Barnett – Includes our wholly owned midstream assets located in the Barnett Shale. Management's Discussion and Analysis of Financial Condition and Results of Operations. Gathering. our Segments Aggregate throughput capacity (MMcf/d) Average daily MVCs through 2023 (MMcf/d) Remaining MVCs (Bcf) Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years) Utica Shale 720 n/a n/a 12.2 n/a Utica, and the AMIs from our customers for this system cover approximately 115,000 surface acres in the aggregate. largest natural gas processing facilities in the United States. 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. Ohio Aggregate throughput capacity - liquids (Mbbl/d) Aggregate throughput capacity - natural gas (MMcf/d) Average daily MVCs through 2023 (MMcfe/d)(1) Remaining MVCs (Bcfe)(1) Weighted-average remaining contract life (Years)(1)(2) Weighted-average remaining MVC life (Years)(1)(2) Williston Basin 255 34 64 70 5.4 2.0 Aggregate throughput capacity (MMcf/d) Average daily MVCs through 2023 (MMcf/d) Remaining MVCs (Bcf) Weighted-average remaining contract life (Years)(1) Weighted-average remaining MVC life (Years)(1) DJ Basin 60 8 9 6.0 2.2 The Niobrara G&P system is located near Hereford, Colorado, in rural Weld, Morgan and Logan Counties, and in Cheyenne County of Nebraska. Weld County is the largest crude oil and natural gas producing county in Aggregate throughput capacity (MMcf/d) Average daily MVCs through 2023 (MMcf/d) Remaining MVCs (Bcf) Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years) Permian Basin(1) 60 n/a n/a 7.5 n/a Double E is a 135 mile, 1.35 Bcf/d, FERC-regulated interstate natural gas transmission pipeline that Aggregate throughput capacity (MMcf/d) Average daily MVCs through 2023 (MMcf/d) Remaining MVCs (Bcf) Weighted-average remaining contract life (Years)(1) Weighted-average remaining MVC life (Years)(1) Piceance Basin 1,151 369 603 9.1 4.9 Throughput capacity (MMcf/d) Average daily MVCs through 2023 (MMcf/d) Remaining MVCs (Bcf) Weighted-average remaining contract life (Years)(1) Weighted-average remaining MVC life (Years)(1) Barnett Shale 450 n/a n/a 6.1 n/a Total is the key customer for DFW Midstream. Our Customers 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. 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 •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 In addition, in August 2022, PHMSA issued a final rule that established new or additional requirements for natural gas transmission lines related to the management of change process, integrity management, corrosion control standards, and pipeline inspections and repairs. •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 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. increased compliance costs for us or our customers. settlement discussions. Several states filed lawsuits challenging the suspension, and on June 15, 2021, a judge in the U.S. District Court for the Western District of Louisiana issued a nationwide temporary injunction blocking the suspension. Although the injunction was subsequently overturned by the Court of Appeals for the Fifth Circuit, on remand the US District Court issued a permanent injunction as requested by the plaintiff states in August 2022. The Department of the Further, the Inflation Reduction Act, signed into law in August 2022, includes a Methane Emissions Reduction Program to incentivize methane emission reductions and impose a fee on GHG emissions from certain oil and gas facilities. •Talent development, compensation and retention – We strive to provide our employees with a rewarding work environment, including the opportunity for success and a platform for personal and professional development. We provide a competitive benefits package designed to attract and retain a skilled and diverse workforce. We offer our employees a comprehensive benefits package, which includes company funded health plan options, vision and dental coverage, healthcare savings account, paid time off, parental leave and flexible spending accounts. We also provide professional training and development opportunities as well as education reimbursement. We also offer employees immediate eligibility in our 401(k) plan with company matching program. Health and safety – Employee health and safety in the workplace is one of our core values. Some of the ways in which we support workforce. •the volumes we gather, transport, treat and process; •the level of production of natural gas and crude oil (and associated volumes of produced water) from wells connected to our gathering systems, which is dependent in part on the demand for, and the market prices of, crude oil, natural gas and NGLs; •damage to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters, accidents and acts of terrorism; •leaks or accidental releases of hazardous materials into the environment; •weather conditions and seasonal trends; •changes in the fees we charge for our services; •changes in contractual MVCs and our customer’s capacity to make MVC shortfall payments when due; •the level of competition from other midstream energy companies in our areas of operation; •changes in the level of our operating, maintenance and general and administrative expenses; •regulatory action affecting the supply of, or demand for, crude oil, natural gas and NGLs, the fees we can charge, how we contract for services, our existing contracts, our operating and maintenance costs or our operating flexibility; and •the level and timing of capital expenditures we make; •the level of our operating, maintenance and general and administrative expenses; •the cost of acquisitions, if any; •our ability to sell assets, if any, and the price that we may receive for such assets; •our debt service requirements and other liabilities; •fluctuations in our working capital needs; •our ability to borrow funds and access the debt and equity capital markets; •restrictions contained in our debt agreements; •the amount of cash reserves established by our General Partner; •not receiving anticipated shortfall payments from our customers; •adverse legal judgments, fines and settlements; In the latter half of 2022, the Henry Hub Natural Gas Spot Price declined from a monthly average of $8.81 per MMBtu in August 2022 to a monthly average of $5.53 per MMBtu in December 2022, closing the year at $3.52 per MMBtu on December 30, 2022. As of January 31, 2023, Henry Hub 12-month strip pricing closed at $3.41 per MMBtu. Cushing, Oklahoma West Texas Intermediate crude oil spot prices similarly trended down in the latter half of 2022, from a monthly average of $114.84 per barrel in June 2022 to a monthly average of $76.44 per barrel in December 2022, closing the year at $80.16 per barrel on December 30, 2022. As of January 31, 2023, West Texas Intermediate 12-month strip pricing closed at $78.03 per barrel. •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 •worldwide economic and geopolitical conditions; •global or national health concerns, including the outbreak of pandemic or contagious disease, such as COVID-19, 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; •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 level of existing and new competition to provide gathering and/or processing services in our areas of operation; •the macroeconomic factors affecting gathering, treating, transporting 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 continuous operations of our gathering, treating, transporting 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. •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 •damage to pipelines, processing plants, compression assets, related equipment and surrounding properties caused by tornadoes, floods, freezes, 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 to achieve our expected investment return, which could materially adversely affect our results of operations and financial condition. personnel, and 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. organization. The operation of gathering, treating, transporting and processing systems requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. •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. 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. These initiatives and similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. settlement discussion. case. However, if the FERC were to disallow the recovery of such costs from other customers, it could decrease the cash flow realized by our assets. complaints with state regulators in an effort to resolve access issues, rate grievances and other matters. Other state and municipal regulations do not directly apply to our business, but may nonetheless affect the availability of natural gas and crude oil for gathering, treating, transporting 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. necessary. 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. operations •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 increase” section of Item 1A. Risk Factors. facilities. Double E Pipeline. countries, including the United States, ratified or otherwise consented to be bound by the agreement. In November 2019, the United States submitted formal notification to the United Nations that it intended to withdraw from the agreement. However, on January 20, 2021, President Biden signed an “Acceptance on Behalf of the United States of America” that, reversed the prior withdrawal, and the United States officially rejoined the Paris Agreement on February 19, 2021. •our quarterly distributions, if any; •our quarterly or annual earnings or those of other companies in our industry; •the loss of a large customer; •announcements by our customers or others regarding our customers or changes in our customers’ credit ratings, liquidity position, leverage profile and/or other financial or credit-related metrics; •announcements by our competitors of significant contracts or acquisitions; •changes in accounting standards, policies, guidance, interpretations or principles; •general economic and geopolitical conditions; •the failure of securities analysts to cover our common units or changes in financial estimates by analysts; and •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 those determinations and actions 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; 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. units. •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 The Partnership Agreement does not require our General Partner to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our Partnership Agreement that prevents our General Partner from causing us to issue additional common units and then exercising its call right. If our General Partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. •we were conducting business in a state but had not complied with that particular state's partnership statute; or 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. The Partnership elected to pay distributions in-kind during 2022, 2021 and 2020, except for the periods ended September 30, 2022 and December 31, 2022 in which it made cash distributions. partnerships, including proposals that would eliminate our ability to quality for partnership tax treatment. 2023. Current and prospective non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units. 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. A cyber-incident involving our IT or OT systems, •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 a communications network or power grid could cause operational disruption, resulting in loss of revenues; •a deliberate corruption of our financial or operational data could result in events of non-compliance, which could lead to regulatory fines or penalties; and exception of certain ordinary course encumbrances and permits with governmental entities that have been applied for, but not yet issued. 2021 and portions of 2022, and paid distributions on our Subsidiary Series A Preferred Units totaling $3.3 million in 2022 and accrued an additional $1.6 million in 2022 which was subsequently paid in 2023. Units in the foreseeable future. •Our cash distribution policy is subject to restrictions on distributions under our ABL Facility and the 2026 Secured Notes Indenture and the indenture governing the 2025 Senior Notes. These agreements contain financial tests, excess cash flow sweep mechanisms, 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. 31,2022 and $21.5 million of accrued and unpaid distributions. 31, 2021, we completed an offer to exchange our Series A Preferred Units for newly issued common units (the “2021 Preferred Exchange Offer”), whereby we issued 538,715 SMLP common units, net of units withheld for withholding taxes, in exchange for 18,662 Series A Preferred Units. Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn a portion of our revenues from the following activities that directly expose us to fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers in the Year ended December 31, 2020 2019 (In thousands) Net income (loss) $ 189,078 $ (393,726 ) Reportable segment adjusted EBITDA Utica Shale $ 32,783 $ 29,292 Ohio Gathering 31,056 39,126 Williston Basin 52,060 69,437 DJ Basin 19,449 18,668 Permian Basin 4,426 (879 ) Piceance Basin 88,820 98,765 Barnett Shale 32,093 43,043 Marcellus Shale 22,015 20,051 Net cash provided by operating activities $ 198,589 $ 161,741 Capital expenditures(1) 43,128 182,291 Investment in Double E equity method investee 99,927 18,316 Net cash distributions to noncontrolling interest SMLP unitholders $ 6,037 $ 68,874 Series A Preferred Unit distributions — 28,500 Net borrowings under Revolving Credit Facility 180,000 211,000 Repayments on SMPH term loan (6,300 ) (65,250 ) Open Market Repurchases of 2022 and 2025 Senior Notes (Note 9) (145,567 ) — Tender Offers of 2022 and 2025 Senior Notes (Note 9) (47,530 ) — TL Restructuring (Note 9) (26,500 ) — Proceeds from issuance of Subsidiary Series A preferred units, net of issuance costs 48,710 27,392 Preferred Tender (Note 9) (25,000 ) — Purchase of common units in GP Buy-In Transaction (41,778 ) — (1)See "Liquidity and Capital Resources" herein and Note •Strategic DJ Acquisitions. On December 1, 2022, we completed the acquisition of 100% of the membership interests in Outrigger DJ from Outrigger Energy II LLC for cash consideration of $165 million, subject to post-closing adjustments, and 100% of the membership interests in each of Sterling Energy Investments LLC, Grasslands Energy Marketing LLC and Centennial Water Pipelines LLC from Sterling Investment Holdings LLC for cash consideration of $140 million, subject to post-closing adjustments, respectively, pursuant to definitive agreements, each dated October 14, 2022. •Sale of Non-Core Assets. On September 19, 2022, we completed the sale of Bison Midstream, LLC (“Bison Midstream”) and its gas gathering system in Burke and Mountrail Counties, North Dakota to a subsidiary of Steel Reef Infrastructure Corp., an integrated owner and operator of associated gas capture, gathering and processing assets in North Dakota and Saskatchewan. Additionally, on June 30, 2022, we completed the sale of Summit Permian, which owns the Lane Gathering and Processing System (“Lane G&P System”), to Longwood Gathering and Disposal Systems, LP (“Longwood”), a wholly owned subsidiary of Matador ͏Resources Company (“Matador”). •January 2022 Series A Preferred Unit Exchange. In January 2022, we completed the 2022 Preferred Exchange Offer, whereby we issued 2,853,875 SMLP common units, net of units withheld for withholding taxes, in exchange for 77,939 Series A Preferred Units. Upon the settlement of the 2022 Preferred Exchange Offer, we eliminated $92.6 million of the Series A Preferred Unit liquidation preference amount, inclusive of accrued distributions due as of the settlement date. See Note 12 – Partners' Capital and Mezzanine Capital for additional information. Key Matters for the Year ended December 31, •Refinancing debt obligations with near-term maturities. On November 2, 2021, the Co-Issuers issued $700.0 million of the 2026 Secured Notes. We used the net proceeds from the offering of the 2026 Secured Notes, together with cash on hand and borrowings under the ABL Facility, to repay in full all of Summit Holdings’ obligations under the Revolving Credit Facility. Additionally, the Co-Issuers redeemed all of the outstanding 2022 Senior Notes at a redemption price equal to 100.0% of the principal amount plus accrued and unpaid interest. •Global Settlement. We were the subject of multiple investigations stemming from the 2015 Blacktail Release. On August 4, 2021, we entered into a Global Settlement to resolve these legal matters that includes the payment of penalties and fines of $36.3 million over six years. As a result of the settlement, we recognized an additional loss for this matter during 2021 and had $33.2 million accrued for this matter as of December 31, 2021. See Note 10 - Commitments and Contingencies to the consolidated financial statements and Item 3. Legal Proceedings for additional information. •April 2021 Series A Preferred Unit Exchange. In April 2021, the Partnership completed the 2021 Preferred Exchange Offer, whereby it issued 538,715 common units, net of units withheld for withholding taxes, in exchange for 18,662 Series A Preferred Units. Upon settlement of the 2021 Preferred Exchange Offer, the Partnership eliminated $20.7 million of the Series A Preferred Unit liquidation preference amount, inclusive of $2.5 million of accrued distributions due as of the settlement date. See Note 12 – Partners' Capital and Mezzanine Capital for additional information. •Double E Project. In November 2021, the Partnership placed the Double E Pipeline in service. As a result, our investment in Double E recognized positive equity in earnings from Double E beginning in the quarter ended December 31, 2021. Capital contributions to Double E in 2021 totaled $148.7 million and were funded primarily from our Permian Transmission Credit Facility and cash on hand. Trends and Outlook •Ongoing impact of the COVID-19 pandemic and fluctuations in demand for oil and natural gas; •Ongoing impact of the current Russia-Ukraine conflict and the international sanctions against Russia on commodity prices; •Natural gas, NGL and crude oil supply and demand dynamics; •Production from U.S. shale plays; On December 1, 2022, we completed the 2022 DJ Acquisitions for total cash consideration of $305.0 million, subject to post-closing adjustments. As a result of the 2022 DJ Acquisitions, we acquired natural gas gathering and processing systems, a crude oil gathering system, freshwater rights, and a subsurface freshwater delivery system in the DJ Basin. The acquired assets of Outrigger DJ and Sterling DJ are located in Weld, Morgan, and Logan Counties, Colorado and Cheyenne County, Nebraska. In 2023, we will spend time and resources integrating the 2022 DJ Acquisitions into our existing DJ Basin assets and expect to attain capital and operating synergies in the future. In response to the COVID-19 pandemic, we •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 •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 Additional Information. For additional information, see the 2021 Year ended December 31, 2020 2019 Percentage change (In thousands) Revenues: Gathering services and related fees $ 302,792 $ 326,747 (7%) Natural gas, NGLs and condensate sales 49,319 86,994 (43%) Other revenues 31,362 29,787 5% Total revenues 383,473 443,528 (14%) Costs and expenses: Cost of natural gas and NGLs 36,653 63,438 (42%) Operation and maintenance 86,030 98,719 (13%) General and administrative 73,438 55,947 31% Depreciation and amortization 118,132 110,354 7% Transaction costs 2,993 3,017 (1%) Gain on asset sales, net (307 ) (1,536 ) (80%) Long-lived asset impairment 13,089 60,507 (78%) Goodwill impairment — 16,211 * Total costs and expenses 330,028 406,657 (19%) Other income 48 451 (89%) Interest expense (78,894 ) (91,966 ) Gain on early extinguishment of debt 203,062 — * Income (loss) before income taxes and equity method investment income (loss) 177,661 (54,644 ) * Income tax benefit (expense) 146 (1,231 ) * Income (loss) from equity method investees 11,271 (337,851 ) * Net income (loss) $ 189,078 $ (393,726 ) * Volume throughput (1): Aggregate average daily throughput - natural gas (MMcf/d) 1,375 1,397 (2%) Aggregate average daily throughput - liquids (Mbbl/d) 79 105 (25%) *Not considered meaningful Northeast and Permian sections herein under the caption “Segment Overview for the Years Ended December 31, 2022 and 2021”. •a volume throughput decrease of 1 MMcf/d for the Barnett segment. Volumes – Liquids. Crude oil and produced water volume throughput ECP Loan Repayment Open Market Repurchases Tender Offers TL Restructuring Total 2022 2025 2022 2025 Senior Notes Senior Notes Senior Notes Senior Notes (in thousands) Gain on Repurchases of Senior Notes and TL Restructuring $ — $ 11,554 $ 76,789 $ 9,223 $ 15,479 $ 99,175 $ 212,220 Debt issue costs (361 ) (143 ) (1,541 ) (125 ) (351 ) (2,724 ) (5,245 ) Transaction cost (249 ) (105 ) (105 ) (467 ) (467 ) (2,520 ) (3,913 ) Gain (loss) on debt extinguishment $ (610 ) $ 11,306 $ 75,143 $ 8,631 $ 14,661 $ 93,931 $ 203,062 Utica Shale Year ended December 31, 2020 2019 Percentage Change Average daily throughput (MMcf/d) 358 273 31% Utica Shale Year ended December 31, 2020 2019 Percentage Change (Dollars in thousands) Revenues: Gathering services and related fees $ 36,509 $ 31,926 14% Other revenues — $ 2,065 Total revenues 36,509 33,991 7% Costs and expenses: Operation and maintenance 3,396 4,151 (18%) General and administrative 301 530 (43%) Depreciation and amortization 7,696 7,659 0% Gain on asset sales, net (35 ) — * Total costs and expenses 11,358 12,340 (8%) Add: Depreciation and amortization 7,696 7,659 Adjustments related to capital reimbursement activity (29 ) (18 ) Gain on asset sales, net (35 ) — Segment adjusted EBITDA $ 32,783 $ 29,292 12% Ohio Gathering Year ended December 31, 2020 2019 Percentage Change Average daily throughput (MMcf/d) 571 732 (22%) Ohio Gathering Year ended December 31, 2020 2019 Percentage Change (Dollars in thousands) Proportional adjusted EBITDA for equity method investees $ 31,056 $ 39,126 (21%) Segment adjusted EBITDA $ 31,056 $ 39,126 (21%) Williston Basin Year ended December 31, 2020 2019 Percentage Change Aggregate average daily throughput - natural gas (MMcf/d) 14 12 17% Aggregate average daily throughput - liquids (Mbbl/d) 79 105 (25%) June 30, 2022. Williston Basin Year ended December 31, 2020 2019 Percentage Change (Dollars in thousands) Revenues: Gathering services and related fees $ 59,239 $ 77,626 (24%) Natural gas, NGLs and condensate sales 20,018 16,461 22% Other revenues 13,438 11,564 16% Total revenues 92,695 105,651 (12%) Costs and expenses: Cost of natural gas and NGLs 12,741 5,821 119% Operation and maintenance 23,793 27,172 (12%) General and administrative 1,738 1,493 16% Depreciation and amortization 25,911 19,829 31% Gain on asset sales, net (50 ) (1,177 ) (96%) Long-lived asset impairment 2,421 10 * Total costs and expenses 66,554 53,148 25% Add: Depreciation and amortization 25,911 19,829 Adjustments related to capital reimbursement activity (2,363 ) (1,728 ) Gain on asset sales, net (50 ) (1,177 ) Long-lived asset impairment 2,421 10 Segment adjusted EBITDA $ 52,060 $ 69,437 (25%) DJ Basin Year ended December 31, 2020 2019 Percentage Change Average daily throughput (MMcf/d) 26 27 (4%) connections in 2022. DJ Basin Year ended December 31, 2020 2019 Percentage Change (Dollars in thousands) Revenues: Gathering services and related fees $ 23,868 $ 21,940 9% Natural gas, NGLs and condensate sales 245 389 (37%) Other revenues 3,957 3,721 6% Total revenues 28,070 26,050 8% Costs and expenses: Cost of natural gas and NGLs 67 34 97% Operation and maintenance 9,579 7,616 26% General and administrative 1,088 315 245% Depreciation and amortization 6,146 3,732 65% Loss on asset sales, net 20 — * Long-lived asset impairment 3,692 34,913 (89%) Total costs and expenses 20,592 46,610 (56%) Add: Depreciation and amortization 6,146 3,732 Adjustments related to capital reimbursement activity 2,113 583 Loss on asset sales, net 20 — Long-lived asset impairment 3,692 34,913 Segment adjusted EBITDA $ 19,449 $ 18,668 4% Permian Basin Year ended December 31, 2020 2019 Percentage Change Average daily throughput (MMcf/d) 33 19 74% Permian Basin Year ended December 31, 2020 2019 Percentage Change (Dollars in thousands) Revenues: Gathering services and related fees $ 10,091 $ 3,610 180% Natural gas, NGLs and condensate sales 18,857 16,383 15% Other revenues 585 310 89% Total revenues 29,533 20,303 45% Costs and expenses: Cost of natural gas and NGLs 18,785 15,113 24% Operation and maintenance 6,038 5,755 5% General and administrative 284 314 (10%) Depreciation and amortization 5,455 4,868 12% Gain on asset sales, net — (148 ) * Long-lived asset impairment 324 1,327 (76%) Total costs and expenses 30,886 27,229 13% Add: Depreciation and amortization 5,455 4,868 Gain on asset sales, net — (148 ) Long-lived asset impairment 324 1,327 Segment adjusted EBITDA $ 4,426 $ (879 ) * Piceance Basin Year ended December 31, 2020 2019 Percentage Change Aggregate average daily throughput (MMcf/d) 364 452 (19%) There were no new well connections in 2022. Piceance Basin Year ended December 31, 2020 2019 Percentage Change (Dollars in thousands) Revenues: Gathering services and related fees $ 106,657 $ 121,357 (12%) Natural gas, NGLs and condensate sales 2,612 7,954 (67%) Other revenues 4,621 4,327 7% Total revenues 113,890 133,638 (15%) Costs and expenses: Cost of natural gas and NGLs 1,717 5,612 (69%) Operation and maintenance 21,064 27,306 (23%) General and administrative 1,053 1,009 4% Depreciation and amortization 45,203 47,018 (4%) (Gain) loss on asset sales, net (190 ) 104 * Long-lived asset impairment 7 14,162 * Total costs and expenses 68,854 95,211 (28%) Add: Depreciation and amortization 45,203 47,018 Adjustments related to MVC shortfall payments — (103 ) Adjustments related to capital reimbursement activity (1,236 ) (843 ) (Gain) loss on asset sales, net (190 ) 104 Long-lived asset impairment 7 14,162 Segment adjusted EBITDA $ 88,820 $ 98,765 (10%) volume throughput as a result of natural production declines. Barnett Shale Year ended December 31, 2020 2019 Percentage Change Average daily throughput (MMcf/d) 212 251 (16%) declines. Barnett Shale Year ended December 31, 2020 2019 Percentage Change (Dollars in thousands) Revenues: Gathering services and related fees $ 40,687 $ 47,862 (15%) Natural gas, NGLs and condensate sales 7,587 17,147 (56%) Other revenues (1) 6,185 6,793 (9%) Total revenues 54,459 71,802 (24%) Costs and expenses: Cost of natural gas and NGLs 3,341 10,751 (69%) Operation and maintenance 18,814 21,729 (13%) General and administrative 1,306 968 35% Depreciation and amortization 15,174 15,354 (1%) Gain on asset sales, net (19 ) (325 ) (94%) Long-lived asset impairment 4,902 10,095 (51%) Total costs and expenses 43,518 58,572 (26%) Add: Depreciation and amortization 16,112 16,575 Adjustments related to MVC shortfall payments — 3,579 Adjustments related to capital reimbursement activity 157 (111 ) Gain on asset sales, net (19 ) (325 ) Long-lived asset impairment 4,902 10,095 Segment adjusted EBITDA $ 32,093 $ 43,043 (25%) nonrecurrence of commercial settlements that benefited the segment’s financial results in 2021. Marcellus Shale Year ended December 31, 2020 2019 Percentage Change Average daily throughput (MMcf/d) 368 363 1% Marcellus Shale Year ended December 31, 2020 2019 Percentage Change (Dollars in thousands) Revenues: Gathering services and related fees $ 25,741 $ 24,471 5% Total revenues 25,741 24,471 5% Costs and expenses: Operation and maintenance 3,343 3,861 (13%) General and administrative 345 521 (34%) Depreciation and amortization 9,195 9,141 1% Gain on asset sales, net (8 ) — * Goodwill impairment — 16,211 * Total costs and expenses 12,875 29,734 (57%) Add: Depreciation and amortization 9,195 9,141 Goodwill impairment — 16,211 Adjustments related to capital reimbursement activity (38 ) (38 ) Gain on asset sales, net (8 ) — Segment adjusted EBITDA $ 22,015 $ 20,051 10% Corporate and Other Overview for the Years Ended December 31, 2021 Corporate and Other Year ended December 31, 2020 2019 Percentage Change (Dollars in thousands) Revenues: Total revenues $ 2,575 $ 27,622 (91%) Costs and expenses: Cost of natural gas and NGLs — 26,107 * General and administrative 67,324 50,797 33% Transaction costs 2,993 3,017 (1%) Interest expense 78,894 91,966 (14%) Gain on asset sales or disposals (21 ) — * Long-lived asset impairment 1,740 — * Gain on early extinguishment of debt (203,062 ) — * outstanding but undrawn irrevocable standby The Co-Issuers may redeem all or part of the 2025 Senior Notes at a redemption price of do so. Year ended December 31, 2020 2019 (In thousands) Net cash provided by operating activities $ 198,589 $ 161,741 Net cash used in investing activities (140,569 ) (90,870 ) Net cash provided by (used in) financing activities (79,398 ) (50,122 ) Net change in cash, cash equivalents and restricted cash $ (21,378 ) $ 20,749 •net loss of $123.5 million plus adjustments of $235.7 million for non-cash items; and •$5.9 million increase in working capital accounts. Investing activities. Details of cash flows from investing activities follow. •$166.6 million of cash consideration paid for the acquisition of Outrigger DJ, net of cash acquired in the transaction; •$148.7 million of capital contributions and costs for our equity method investment in Double E; and •$25.0 million of capital expenditures primarily attributable to the ongoing development of our Rockies, Northeast and Permian segments. Financing activities. Details of cash flows from financing activities follow. •$160.0 million of borrowings from the Permian Transmission Credit Facility to fund our capital contributions to our equity method investment in Double E. Contractual Obligations Update Total 2021 2022 2023 2024 2025 Revolving Credit Facility, due May 2022 (2) $ 892,208 $ 24,853 $ 867,355 $ — $ — $ — 2022 Senior Notes, due August 2022 (2) 255,502 12,873 242,629 — — — 2025 Senior Notes, due April 2025 (2) 309,193 14,919 14,919 14,919 14,919 264,436 Capital contributions to Double E equity method investment(1) 172,410 147,710 24,700 — — — Lease obligations 5,772 2,405 1,434 896 573 464 Total $ 1,635,085 $ 202,760 $ 1,151,037 $ 15,815 $ 15,492 $ 264,900 Year ended December 31, 2019 SMLP Obligor Group (In thousands) Total revenues $ — $ 443,528 Total costs and expenses 4,401 397,939 Loss before income taxes and income from equity method investees (1,968 ) (28,840 ) Income from equity method investees — (336,950 ) Net loss $ (3,142 ) $ (365,790 ) revenues and expenses and related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis, based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following describes significant judgments and estimates used in the preparation of our consolidated financial statements. Permian Transmission Term Loan. industry peers. •We tested the effectiveness of controls over the purchase price allocation, including management's controls over the assumptions used in the valuation of the property, plant and equipment and intangible assets, including estimating the preliminary appraisal and fair value of the acquired property, plant and equipment and intangible assets, determination of the weighted average cost of capital, and reviewing the work of third-party specialists. carrying value exceeds its fair value. degree of auditor judgment and the extent of specialized knowledge needed. •We tested the effectiveness of internal controls over financial reporting related to management’s identification of possible impairment indicators for long-lived assets that may indicate the carrying amount of long-lived assets may not be recoverable. •We evaluated management’s analysis of impairment indicators by: December 31, December 31, 2020 2019 (In thousands, except unit amounts) ASSETS Cash and cash equivalents $ 15,544 $ 9,530 Restricted cash — 27,392 Accounts receivable 61,932 97,418 Other current assets 4,623 5,521 Total current assets 82,099 139,861 Property, plant and equipment, net 1,817,546 1,882,489 Intangible assets, net 199,566 232,278 Investment in equity method investees 392,740 309,728 Other noncurrent assets 7,866 9,742 TOTAL ASSETS $ 2,499,817 $ 2,574,098 LIABILITIES AND CAPITAL Trade accounts payable $ 11,878 $ 24,415 Accrued expenses 13,036 11,339 Deferred revenue 9,988 13,493 Ad valorem taxes payable 9,086 8,477 Accrued compensation and employee benefits 9,658 8,719 Accrued interest 8,007 12,346 Accrued environmental remediation 1,392 1,725 Other current liabilities 5,363 3,487 Current portion of SMPH term loan — 5,546 Total current liabilities 68,408 89,547 Long-term debt 1,347,326 1,622,279 Noncurrent deferred revenue 48,250 38,709 Noncurrent accrued environmental remediation 1,537 2,926 Other noncurrent liabilities 21,747 7,951 Total liabilities 1,487,268 1,761,412 Commitments and contingencies (Note 11) Mezzanine Capital Subsidiary Series A Preferred Units (55,251 and 30,058 units issued and outstanding at December 31, 2020 and December 31, 2019, respectively) 89,658 27,450 Partners' Capital Series A Preferred Units (162,109 and 300,000 units issued and outstanding at December 31, 2020 and December 31, 2019, respectively) 174,425 293,616 Common limited partner capital (6,110,092 and 3,021,258 units issued and outstanding at December 31, 2020 and December 31, 2019, respectively) 748,466 305,550 Noncontrolling interest — 186,070 Total partners' capital 922,891 785,236 TOTAL LIABILITIES AND CAPITAL $ 2,499,817 $ 2,574,098 Year ended December 31, 2020 2019 (In thousands, except per-unit amount) Revenues: Gathering services and related fees $ 302,792 $ 326,747 Natural gas, NGLs and condensate sales 49,319 86,994 Other revenues 31,362 29,787 Total revenues 383,473 443,528 Costs and expenses: Cost of natural gas and NGLs 36,653 63,438 Operation and maintenance 86,030 98,719 General and administrative 73,438 55,947 Depreciation and amortization 118,132 110,354 Transaction costs 2,993 3,017 Gain on asset sales, net (307 ) (1,536 ) Long-lived asset impairment 13,089 60,507 Goodwill impairment 0 16,211 Total costs and expenses 330,028 406,657 Other income 48 451 Interest expense (78,894 ) (91,966 ) Gain on early extinguishment of debt 203,062 0 Income (loss) before income taxes and equity method investment income (loss) 177,661 (54,644 ) Income tax benefit (expense) 146 (1,231 ) Income (loss) from equity method investees 11,271 (337,851 ) Net income (loss) $ 189,078 $ (393,726 ) Less: Net income (loss) attributable to noncontrolling interest (3,274 ) (209,275 ) Net income (loss) attributable to limited partners 192,352 (184,451 ) Net income attributable to Series A Preferred Units 26,529 28,500 Net income attributable to Subsidiary Series A Preferred Units 13,498 58 Add: Deemed contribution from preferred unit exchange and purchase 110,669 0 Net income (loss) attributable to common limited partners $ 262,994 $ (213,009 ) Net income (Loss) per limited partner unit: Common unit – basic $ 73.22 $ (70.50 ) Common unit – diluted $ 71.19 $ (70.50 ) Weighted-average limited partner units outstanding: Common units – basic 3,592 3,021 Common units – diluted 3,694 3,021 Noncontrolling Interest Partners' Capital Series A Preferred Units Common Noncontrolling Interests (1) Series A Preferred Units Partners' Capital Total (In thousands) Partners' capital, December 31, 2018 $ 293,616 $ 554,472 $ — $ 543,479 $ 1,391,567 Net income (loss) 28,500 (209,275 ) — (213,009 ) (393,784 ) Net cash distributions SMLP unitholders (28,500 ) (68,874 ) — — (97,374 ) Net cash distributions to Energy Capital Partners — — — (120,730 ) (120,730 ) Unit-based compensation — 8,171 — — 8,171 Effect of common unit issuances under SMLP LTIP — 2,664 — (2,664 ) — Tax withholdings and associated payments on vested SMLP LTIP awards — (2,614 ) — — (2,614 ) Conversion of noncontrolling interest related to cancellation of subsidiary incentive distribution rights — (48,203 ) — 48,203 — Conversion of noncontrolling interest related to partial cancellation of subsidiary of payable — (50,271 ) — 50,271 — Partners' capital, December 31, 2019 293,616 186,070 — 305,550 785,236 Net income 11,875 (3,274 ) 14,654 152,325 175,580 Unit-based compensation — 4,054 — 4,057 8,111 Tax withholdings and associated payments on vested SMLP LTIP awards — (1,018 ) — (438 ) (1,456 ) Tax withholdings on Series A Preferred Unit Exchange — — — (237 ) (237 ) Net cash distribution to SMLP unitholders — (6,037 ) — — (6,037 ) Effect of common issuances under SMLP LTIP — 2,322 — (2,322 ) — GP-Buy-In Transaction assumption of noncontrolling interest in SMLP (305,491 ) (182,117 ) 305,491 182,117 — Repurchase of common units under GP Buy-In Transaction — — — (44,078 ) (44,078 ) Common unit issuance due to TL Restructuring — — — 30,521 30,521 Effect of Exchange Offer and Preferred Tender(2) — — (145,720 ) 120,720 (25,000 ) Other — — — 251 251 Partners' capital December 31, 2020 $ — $ — $ 174,425 $ 748,466 $ 922,891 Year ended December 31, 2020 2019 (In thousands) Cash flows from operating activities: Net income (loss) $ 189,078 $ (393,726 ) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation and amortization 119,070 111,574 Noncash lease expense 3,242 3,086 Amortization of debt issuance costs 6,608 6,313 Unit-based and noncash compensation 8,111 8,171 (Income) loss from equity method investees (11,271 ) 337,851 Distributions from equity method investees 28,185 37,300 Gain on asset sales, net (307 ) (1,536 ) Gain on early extinguishment of debt (206,975 ) 0 Gain on fair value of warrants (393 ) 0 Settlement of interest rate derivative 134 0 Long-lived asset impairment 13,089 60,507 Goodwill impairment 0 16,211 Changes in operating assets and liabilities: Accounts receivable 35,352 (5,466 ) Trade accounts payable (4,063 ) (96 ) Accrued expenses 2,841 (10,572 ) Deferred revenue, net 6,036 1,683 Ad valorem taxes payable 609 (1,525 ) Accrued interest (3,343 ) 7 Accrued environmental remediation, net (1,996 ) (1,152 ) Other, net 14,582 (6,889 ) Net cash provided by operating activities 198,589 161,741 Cash flows from investing activities: Capital expenditures (43,128 ) (182,291 ) Proceeds from asset sale (net of cash of $1,475 for the year ended December 31, 2019) 0 102,111 Distribution from equity method investment 0 7,313 Investment in Double E equity method investee (99,927 ) (18,316 ) Other, net 2,486 313 Net cash used in investing activities (140,569 ) (90,870 ) Cash flows from financing activities: Net cash distributions to noncontrolling interest SMLP unitholders (6,037 ) (68,874 ) Series A Preferred Unit distributions 0 (28,500 ) Net cash distributions to Energy Capital Partners 0 (120,730 ) Borrowings under Revolving Credit Facility 249,300 369,000 Repayments on Revolving Credit Facility (69,300 ) (158,000 ) Transaction costs (4,221 ) 0 Repayments on SMPH Term Loan before TL Restructuring (6,300 ) (65,250 ) Open Market Repurchases of 2022 and 2025 Senior Notes (145,567 ) 0 Tender Offers of 2022 and 2025 Senior Notes (47,530 ) 0 TL Restructuring (26,500 ) 0 Proceeds from issuance of Subsidiary Series A preferred units, net of issuance costs 48,710 27,392 Preferred Tender (25,000 ) 0 Borrowings under ECP Loans 35,000 0 Repayment of ECP Loans (35,000 ) 0 Purchase of common units in GP Buy-In Transaction (41,778 ) 0 Debt issuance costs (2,558 ) (673 ) Proceeds from asset sale 288 0 Other, net (2,905 ) (4,487 ) Net cash used in financing activities (79,398 ) (50,122 ) Net change in cash, cash equivalents and restricted cash (21,378 ) 20,749 Cash, cash equivalents and restricted cash, beginning of period 36,922 16,173 Cash, cash equivalents and restricted cash, end of period $ 15,544 $ 36,922 Business Operations. The Partnership provides natural gas gathering, compression, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term, fee-based agreements with its customers. In addition to these services, the Partnership also provides freshwater delivery services pursuant to short-term agreements with customers.The Partnership’s results are primarily driven by the volumes of natural gas that it gathers, compresses, treats and/or processes as well as by the volumes of crude oil and produced water that it gathers. Other than the Partnership’s investments in Double E and Ohio Gathering, all of its business activities are conducted through wholly owned operating disclosure of commitments and contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates. AND RECENTLY ISSUED ACCOUNTING STANDARDS APPLICABLE TO THE PARTNERSHIP Gathering and processing systems and related equipment 12-30 Other 4-15 whether the expected retirement date and related costs of retirement can be estimated. The Partnership has concluded that its gathering and processing assets have an indeterminate life because they are owned and will operate for an indeterminate period when properly maintained. Because the Partnership does not have sufficient information to reasonably estimate the amount or timing of such obligations and does not have any current plan to discontinue use of any significant assets, the Partnership did Amortizing Intangibles. The Partnership has certain acquired gas gathering contracts that had above-market pricing structures at the acquisition date and the Partnership amortizes these favorable contracts using a straight-line method over the contract’s estimated useful life. The Partnership defines useful life as the period over which the contract is expected to contribute to the Partnership’s future cash flows. These favorable contracts have original terms ranging from 10 years to 20 years and the Partnership recognizes the amortization expense associated with these contracts in Other revenues. component of equity unless the noncontrolling interest is considered redeemable, in which case the noncontrolling interest is recorded between liabilities and equity (mezzanine or temporary equity) in the Partnership’s consolidated balance sheet. •Fee-based arrangements. Under fee-based arrangements, the Partnership receives a fee or fees for one or more of the following services (i) natural gas gathering, treating, transporting, compressing and/or processing and (ii) crude oil and/or produced water gathering and (iii) fresh water delivery services. Percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, the Partnership generally purchases natural gas from producers at the wellhead, or other receipt points, gathers the wellhead natural gas through its gathering system, treats and compresses the natural gas, processes the natural gas and/or sells the natural gas to a third party for processing. The Partnership then remits to its producers an agreed-upon percentage of the actual proceeds received from sales of the residue natural gas and NGLs. Certain of these arrangements may also result in returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. The margins earned are directly related to☐o Yes ☒x NoSecurities Act. ☐o Yes ☒x No☒x Yes Yes☐o No☒x Yes Yes☐o NoLarge accelerated filer ☐☐☒☒☐☐o☒o☐x Yes ☒No2020,2022 was $45,998,000.ClassClass As of February 26, 202124, 20236,110,092 unitsNone•our decision whether to pay, or our ability to grow, our cash distributions;fluctuations in natural gas, NGLs and crude oil prices, including as a result of political or economic measures taken by various countries or OPEC;the extent and success of our customers' drilling efforts, as well as the quantity of natural gas, crude oil and produced water volumes produced within proximity of our assets;the current and potential future impact of the COVID-19 pandemic on our business, results of operations, financial position or cash flows;failure or delays by our customers in achieving expected production in their natural gas, crude oil and produced water projects;competitive conditions in our industry and their impact on our ability to connect hydrocarbon supplies to our gathering and processing assets or systems;actions or inactions taken or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers;our ability to divest of certain of our assets to third parties on attractive terms, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets;the ability to attract and retain key management personnel;commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets;•changes in the availability and cost of capital and the results of our financing efforts, including availability of funds•commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets;restrictions placed on us by the agreements governing our debt and preferred equity instruments;the availability, terms and cost of downstream transportation and processing services;natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control;operational risks and hazards inherent in the gathering, compression, treating and/or processing of natural gas, crude oil and produced water;weather conditions and terrain in certain areas in which we operate;any other issues that can result in deficiencies in the design, installation or operation of our gathering, compression, treating and processing facilities;timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule;our ability to finance our obligations related to capital expenditures, including through opportunistic asset divestitures or joint ventures and the impact any such divestitures or joint ventures could have on our results;•the effects of existing and future laws and governmental regulations, including environmental, safety and climate change requirements and federal, state and local restrictions or requirements applicable to oil and/or gas drilling, production or transportation;changes in tax status;the effects of litigation;changes in general economic conditions; andcertain factors discussed elsewhere in this report.Risks Related to COVID-19•The COVID-19 pandemic, coupled with other current pressures on oil and gas prices resulting from the OPEC price war, has had, and is expected to continue to have, an adverse impact on our business, results of operations, financial position and cash flows.•We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay distributions to holders of our common units.We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of our customers could materially adversely affect our revenues, cash flows and ability to make cash distributions to our unitholders.We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties and any material nonpayment or nonperformance by one or more of these parties could materially adversely affect our financial and operating results.Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders.•Significant prolonged weakness in natural gas, NGL and crude oil prices could reduce throughput on our systems and materially adversely affect our revenues•Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders.Any significant decrease in the demand for natural gas and crude oil could reduce the volumes of natural gas and crude oil that we gather and process, which could adversely affect our business and operating results.Our industry is highly competitive, and increased competitive pressure could materially adversely affect our business and operating results.We may not be able to renew or replace expiring contracts at favorable rates or on a long term basis.Interruptions in operations at any of our facilities may adversely affect our operations and cash flows and our ability to make cash distributions to our unitholders.Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could materially adversely affect our operational and financial results.•We do not own all•A transition from hydrocarbon energy sources to alternative energy sources could lead to changes in demand, technology and public sentiment which could have material adverse effects on our business and results of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.Financing
Finances•Limited access to and/or availability of the commercial bank market, debt and equity capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements.We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects, and may limit our flexibility to obtain financing.We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful.A portion of our revenues are directly exposed to changes in crude oil, natural gas and NGL prices, and our exposure may increase in the future.•We are under investigation by federal and state regulatory agencies over a pipeline rupture and release of produced water by one of our subsidiaries. The resolution of this matter could have a material adverse effect on our results of operations or cash flows.We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. As a result, we may be required to expend significant funds for legal defense or to settle claims. Any such loss, if incurred, could be material.A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenues to decline or our operation and maintenance expenses to increase.Increased regulation of hydraulic fracturing could result in reductions or delays in customer production, which could materially adversely impact our revenues.We are subject to FERC jurisdiction, federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements and state and local regulation, and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced.We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.•Because our common units are yield-oriented securities, increases in interest rates could materially adversely impact our unit price, our ability to issue equity or incur debt and our ability to make cash distributions to our unitholders.The market price of our common units may fluctuate significantly and, due to limited daily trading volumes, an investor could lose all or part of its investment in us.Tax Risks•Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.•The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations of applicable law, possibly on a retroactive basis.•We have engaged in recent transactions that generated substantial cancellation of debt (“COD”) income on a per unit basis relative to the trading price of our common units. We may engage in other transactions that result in substantial COD income or other gains in the future, and such events may cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to the unitholder.52020:
6
2016 Drop Downthe 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 Gathering2022 Senior NotesSummit Holdings' and Finance Corp.’s 5.5% senior unsecured notes due August 20222022 DJ Acquisitions 2025 Senior Notes AMI2026 Secured Notes Indenture Indenture, dated as of November 2, 2021, by and among Summit Holdings, Finance Corp., the guarantors party thereto and Regions Bank, as trustee ABL Facility the asset-based lending credit facility governed by the ABL Agreement ABL Agreement Additional 2026 Secured Notes the additional $85.0 million of 2026 Secured Notes issued in November 2022 in connection with the 2022 DJ Acquisitions AMI area of mutual interest; AMIs require that any production from wells drilled by our Audit Committeethe audit committee of the Board of DirectorsCompensation CommitteeCollateral Agreement Collateral Agreement, dated as of November 2, 2021, by and among SMLP, as a pledgor, Summit Holdings and Finance Corp., as pledgors and grantors, the subsidiary guarantors party therein, and Regions Bank, as collateral agent Compensation Committee the compensation committee of the Board of Directors Compensation ConsultantWillis Towers WatsoncondensateCWACWA Clean Water Act Deferred Purchase Price Obligationthe deferred payment liability recognized in connection with the 2016 Drop Down, as subsequently amended; also referred to as DPPOProjectthe development and construction of long-haul1.35 Bcf per day, FERC-regulated interstate natural gas transmission pipeline with an initial throughput capacity of 1.35 billion cubic feet per day that will provideHubhub in Texasthe development and construction of the Double E Pipeline dry gas Energy Capital PartnersECP Energy Capital Partners II, LLC and its parallel and co-investment funds EPUEPU earnings or loss per unit Equity Restructuringa 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 Holdings7Exchange Act GP interest2.0% general partner interest of GP in the Partnership prior to the Equity Restructuring and a non-economic general partner interest after the Equity RestructuringGrand River Mountaineer MidstreamIDRsincentive distribution rightsIPOpublic offeringMbblone thousand barrelsMbbl/dMcfone thousand cubic feetMD&Amaximum daily transportation quantity Meadowlark Midstream Mountaineer Midstream NGANGA Natural Gas Act OCCOCC Ohio Condensate Company, L.L.C. PHMSAPHMSA Pipeline and Hazardous Materials Safety Administration Permian Transmission Credit Facility the credit facility governed by the Credit Agreement, dated as of March 8, 2021, among Summit Permian Transmission, LLC, as borrower, MUFG Bank Ltd., as administrative agent, Mizuho Bank (USA), as collateral agent, ING Capital LLC, Mizuho Bank, Ltd. and MUFG Union Bank, N.A., as L/C issuers, coordinating lead arrangers and joint bookrunners, and the lenders from time-to-time party thereto Polar and Divide 8Senior NotesThe 5.5% Senior Notes and the 5.75% Senior Notes, collectivelySPCCSPCC Spill Prevention Control and Countermeasure SponsorEnergy Capital Partners II, LLC and its parallel and co-investment funds; also known as Energy Capital PartnersTcfeTcfe the equivalent of one trillion cubic feet
Agreement
Partnership dated May 28, 2020, as amended by Amendment No. 1 to the Fourth Amended and Restated Agreement of Limited Partnership, dated February 23, 2023throughput volume unconventional resource 9Under GAAP, the GP Buy-In Transaction (as defined below) whereby the Partnership acquired Summit Investments, the parent company of the General Partner, and the General Partner became a wholly-owned subsidiary of the Partnership, the GP Buy-In Transaction was deemed a transaction between entities under common control with a change in reporting entity. As a result, the Partnership recast its financial statements for the periods preceding the GP Buy-In Transaction, during which the entities were under the common control of Summit Investments, to retrospectively reflect the GP Buy-In Transaction. Although the Partnership is the surviving entity for legal purposes, Summit Investments is the surviving entity for accounting purposes; therefore, the historical financial results of the Partnership prior to the GP Buy-In Transaction are those of Summit Investments. Prior to the GP Buy-In Transaction, Summit Investments controlled the Partnership and the Partnership’s financial statements were consolidated into Summit Investments.The financial data included in this Annual Report includes periods prior to the GP Buy-In Transaction. Consequently, the Partnership’s consolidated financial statements have been retrospectively recast for all periods presented in order to present the financial results of the surviving entity, Summit Investments, for accounting purposes."SMLP"“SMLP”, or “the Partnership”), is a value-driven limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in unconventional resource basins, primarily shale formations, in the continental United States. Our common units are listed and traded on the NYSE under the ticker symbol “SMLP.”As a result of the GP Buy-In Transaction (as described below), the Partnership indirectly owns its General Partner, and the General Partner’s Board of Directors is comprised of a majority of independent directors. The Partnership’s Fourth Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”) provides the Partnership’s common unitholders with voting rights in the election of the members of the Board of Directors on a staggered basis beginning in 2022.premier production basins and core demand centers, including the Williston Basin, DJ Basin, Utica Shale, Marcellus Shale, Barnett Shale, Piceance Basin and Permian Basin. Our primary business objective is to maximize cash flow and provide cash flow stability for our stakeholders while growing prudently and profitably. We intend to accomplish this objective by executing the following strategies:•Liability management. We seek to maximize unitholder value by reducing and extending, where appropriate, the Partnership’s indebtedness and other fixed capital obligations through a combination of opportunistic liability management transactions, operating cash flow, and other corporate transactions.Portfolio management. We seek to maximize unitholder value by strategically managing our portfolio of midstream assets and allocating capital based on appropriate risk-informed cash flow assumptions. This may include opportunistic divestitures, re-allocation of capital to new or existing areas, and development of joint ventures involving our existing midstream assets or new investment opportunities.Maintaining our focus on fee-based revenue with minimal direct commodity price exposure. We intend to maintain our focus on providing midstream services under primarily long-term and fee-based contracts. We believe that our focus on fee-based revenues with minimal direct commodity price exposure is essential to maintaining stable cash flows. of all of our midstream assets. We have cultivated strong producer relationships by focusing on customer service, reliable project execution and by operating our assets safely and reliably over time. We believe that our strong producer relationships will create future opportunities to optimize the utilization of the gathering systems in our Legacy Areas and develop new midstream infrastructure in our Core Focus Areas.10Table of Contentsall of our midstream assetsContinuing to prioritize safe and reliable operations. 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.sinceand highlights for the year ended December 31, 2019.2022. Additional information regarding these items may be found elsewhere in this Annual Report.•GP Buy-In Transaction. In May 2020, the Partnership completed a simplification transaction (the “GP Buy-In Transaction”) whereby the Partnership acquired from its then private equity sponsor, Energy Capital Partners (“ECP”), (i) Summit Midstream Partners, LLC (“Summit Investments”), which owned the Partnership’s General Partner, (ii) through its indirect ownership of Summit Midstream Partners Holdings, LLC (“SMP Holdings”), 3,415,646 of its common units and (iii) the Deferred Purchase Price obligation receivable owed by the Partnership. Consideration paid to ECP included a $35.0 million cash payment and the issuance of warrants to purchase up to 666,667 common units. In connection with the closing of the GP Buy-In Transaction, ECP’s management resigned from the Board of Directors and ECP fully exited its investment in the Partnership (other than retaining the aforementioned warrants).Suspension of common and preferred unit distributions.In May 2020, and in conjunction with the GP Buy-In Transaction, the Partnership suspended distributions to holders of its common units and its Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. The suspension of distributions enabled the Partnership to retain an incremental $76.0 million per annum of operating cash flow and reallocate this retained cash to indebtedness reduction, liability management transactions and other corporate initiatives. The unpaid cash distributions on the Series A Preferred Units continue to accrue semi-annually, until paid.•Liability Management - Open Market Repurchases. Throughout 2020, the Partnership completed multiple open market repurchases of the 2022 Senior Notes and 2025 Senior Notes that resulted in the extinguishment of $32.4 million of face value of the 2022 Senior Notes and $201.8 million of face value of the 2025 Senior Notes (the “Open Market Repurchases”). Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 Senior Notes and 2025 Senior Notes, plus accrued interest totaled $150.3 million and the Partnership recognized an $86.5 million gain on the extinguishment of debt related to these Open Market Repurchases during 2020. •Liability Management - Debt Tender Offers. In September 2020, Summit Holdings and Finance Corp. (together with Summit Holdings, the “Co-Issuers”) completed cash tender offers (the “Debt Tender Offers”) to purchase a portion of their 2022 Senior Notes and 2025 Senior Notes. Upon completion of the Debt Tender Offers, the Co-Issuers repurchased $33.5 million principal amount of the 2022 Senior Notes and $38.7 million principal amount of the 2025 Senior Notes. Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 and 2025 Senior Notes, plus accrued interest, totaled $48.7 million, and the Partnership recognized a $23.3 million gain on the extinguishment of debt related to the Debt Tender Offers during 2020.•Liability Management - SMPH Term Loan Restructuring. In November 2020, the Partnership completed a consensual debt discharge and restructuring (the “TL Restructuring”) of SMP Holdings’ $155.2 million term loan (“SMPH Term Loan”). All of the lenders under the SMPH Term Loan (the “Term Loan Lenders”) participated in the TL Restructuring. As part of the TL Restructuring, the Partnership paid SMP Holdings $26.5 million in cash as consideration to fully settle the deferred purchase price obligation, which SMP Holdings then paid to the Term Loan Lenders. In addition, the Term Loan Lenders executed a strict foreclosure (the “Strict Foreclosure”) on the 2,306,972 common units pledged as collateral under the SMPH Term Loan in full satisfaction of SMP Holdings’ outstanding obligations under the SMPH Term Loan.•Reverse Unit Split. On November 9, 2020, after the close of trading on the NYSE, the Partnership effected a 1-for-15 reverse unit split (the “Reverse Unit Split”) of its common units. The common units began trading on a split-adjusted basis on November 10, 2020. Pursuant to the Reverse Unit Split, common unitholders received one common unit for every 15 common units owned at the close of business on November 9, 2020. Immediately prior to the11Reverse Unit Split, there were 56,624,887 common units issued and outstanding and immediately after the Reverse Unit Split, the number of issued and outstanding common units decreased to 3,774,992. July 2020 Series A Preferred Unit Exchange. In July 2020, the Partnership completed an offer to exchange its Series A Preferred Units for newly issued common units (the “Preferred Exchange Offer”), whereby it issued 837,547 SMLP common units in exchange for 62,816 Series A Preferred Units. Upon closing the Preferred Exchange Offer, it eliminated $66.5 million of the Series A Preferred Unit liquidation preference amount due as of the settlement date.December 2020 Series A Preferred Unit Tender. In December 2020, the Partnership completed a cash tender offer for its Series A Preferred Units (the “Preferred Tender Offer”) whereby it accepted 75,075 Series A Preferred Units for a purchase price of $333.00 per Series A Preferred Unit and an aggregate purchase price of $25.0 million. Upon closing the Preferred Tender Offer, it eliminated $82.7 million of the Series A Preferred Unit liquidation preference amount due as of the settlement date.Double E Project FERC approval. In January 2021, Double E, a joint venture focused on the development of an interstate natural gas pipeline in which the Partnership indirectly owns a 70% equity interest and serves as the pipeline's operator and construction manager, received its Notice to Proceed (“NTP”) with construction, as well as approval of its implementation plan, from FERC. Prior to this, in October 2020, Double E received FERC approval of its application to construct and operate the Double E Project, pursuant to Section 7(c) of the Natural Gas Act. With the receipt of the 7(c) certificate and the NTP, construction on the Double E pipeline commenced in February 2021, and the pipeline is expected to be in-service by the end of 2021.systemsmidstream assets primarily gather natural gas produced 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 to 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 allmost of the services our systems provide as gathering services.classifyalso provide natural gas transmission services via Double E, a long-haul natural gas pipeline in which we indirectly own a 70% equity interest and serve as the pipeline’s operator. Double E provides natural gas transportation services from multiple receipt points in the Permian Basin to various delivery points in and around the Waha hub in Texas.energy infrastructure assets into two categories,in which we collect fixed fees for gathering or processing hydrocarbons, gathering produced water, or transporting residue natural gas.Core Focus Areaswholly owned midstream assets located in the Williston Basin and the DJ Basin.Legacy Areas. Further detailsequity method investment in Ohio Gathering that is focused on the Utica Shale.Focus Areas and Legacy Areas are summarized below.•wholly owned midstream assets located in the Piceance Basin.Core Focus Areas. Core producing areas of basins in which we expect our gathering systems to experience greater long-term growth, driven by our customers’ ability to generate more favorable returns and support sustained drilling and completion activity in varying commodity price environments. In the near-term, we expect to concentrate the majority of our capital expenditures in our Core Focus Areas. Our Utica Shale, Ohio Gathering, Williston Basin, DJ Basin and Permian Basin reportable segments comprise our Core Focus Areas.Legacy Areas. Production basins in which we expect volume throughput on our gathering systems to experience relatively lower long-term growth compared to our Core Focus Areas, given that our customers require relatively higher commodity prices to support drilling and completion activities in these basins. Upstream production served by our gathering systems in our Legacy Areas is generally more mature, as compared to our Core Focus Areas, and the decline rates for volume throughput on our gathering systems in the Legacy Areas are typically lower as a result. We expect to continue to decrease our near-term capital expenditures in these Legacy Areas. Our Piceance Basin, Barnett Shale and Marcellus Shale reportable segments comprise our Legacy Areas.12 Additionally, we could face incremental competition to the extent we make acquisitions.MD&A.2036.2039. The AMIs generally require that any production by our customers within the AMIs will be shipped ongathered and/or processed by our assets. In general, our customers have not leased acreage that cover our entire AMIs but, to the extent that they have leased acreage within our AMI, or lease additional acreage in the future, within our AMIs, any production from wells drilled by them within that AMI will be dedicated to our systems.fundpursue 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 gathering 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. ForGathering, our joint venture partner may elect to fund 100% of the capital calls, if we choose not to fund our proportionate share of a given capital call, which could reduce our ownership interests in OGC and/or OCC. For example, in 2020, we chose not to fund capital calls at OGC and OCC, and as a result, our ownership interest in those ventures was reduced from 40% to 38.2% and 40% to 38.2%, respectively, as of December 31, 2020.2020,2022, we had remaining MVCs totaling 1.4 Tcfe. Our0.7 Tcfe, our MVCs had a weighted-average remaining life of 4.94.1 years, (assuming contracted MVCs for the remainder of the term) and these MVC's average approximately 0.9 Bcfe/408 MMcfe/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. 2027.Notes 3Note 4 – Revenue and Note 8– Deferred Revenue to the consolidated financial statements.2020,2022, aggregate natural gas volume throughput averaged 1,3751,208 MMcf/d and crude oil and produced water volume throughput averaged 7962 Mbbl/d. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure, which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk or volatility. We also earn a portion of our revenues from the following activities that directly expose us to fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers in the Williston Basin,Rockies, Permian and Piceance Basin, and Permian Basin segments, (ii) the sale of natural gas we retain from certain Barnett Shale customers, and (iii) the sale of condensate we retain from our gathering services in the Rockies and Piceance Basin segment.segments and (iv) additional gathering fees that are tied to performance of certain commodity price indexes, which are then added to the fixed gathering rates. During the year ended December 31, 2020,2022, these additional activities accounted for approximately 13%18% of total revenues.13In addition, the vast majority of our gathering and/or processing agreements in both our Core Focus Areas and our Legacy Areas include AMIs. Our AMIs cover approximately 2.8 million surface acres in the aggregate, which includes more than 0.8 million surface acres associated with Ohio Gathering. Certain of our gathering and processing agreements also include MVCs. To the extent the customer does not meet its MVC, it is contractually obligated to make an MVC shortfall payment to cover the shortfall of required volume throughput not shipped or processed, either on a monthly or annual basis. We have designed our MVC provisions to ensure that we will generate a minimum amount of revenue from each customer over the lifeassociated gathering and/or processing agreement, by collecting gathering or processing fees on actual throughput or from cash paymentsjoint venture and have made all required capital contributions to cover any MVC shortfall.Double E. As of December 31, 2020, we had remaining MVCs totaling 1.4 Tcfe. Our MVCs have2022, the Partnership owns a weighted-average remaining life70% interest in Double E. A subsidiary of 4.9 years (assuming contracted MVCs for the remainder of the term) and average approximately 0.9 Bcfe/d through 2023.We use a variety of financial and operational metrics to analyzeExxonMobil Corporation is our performance, including among others, throughput volume, revenues, operation and maintenance expenses and segment adjusted EBITDA. We view each of these operational and/or GAAP metrics as important factors in evaluating our profitability and determining whether, and what amount of cash distributions, we pay to our unitholders. For additional information on our results of operations, see the “Results of Operations” section included in Item 7. MD&A.14Core Focus Areas and Legacy AreasUtica Shale (Core Focus Area).Utica ShaleNortheast reportable segment as of December 31, 2020.2022.
______________________________________________Aggregate throughput capacity (MMcf/d) Average daily MVCs through 2027 (MMcf/d) Remaining MVCs (Bcf) Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years) 1,770 221 403 7.2 4.0 1,100 n/a n/a 9.1 n/a windowreserves 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 areResources is the key customerscustomer of Summit Utica.gatheringSummit Utica 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 new and previously connected pad sites.sites in our service area. Over time, we intend to expand our midstream service offeringofferings 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.Summit UticaMountaineer Midstream system, currently provideswithin the Marcellus shale, is located in Doddridge and Harrison counties in West Virginia where it gathers natural gas midstream servicesunder a long-term, fee-based contract with Antero Resources Corporation (“Antero”), which is targeting liquids-rich natural gas production from the Marcellus shale in the Appalachian Basin. Volume throughput on the Mountaineer Midstream system is underpinned by minimum revenue commitments from Antero.Utica Shale reportable segment. (Core Focus Area).andGathering is operated by our partner, MPLX LP (“MPLX”).MPLX. Substantially all gathering services on the Ohio Gathering system are provided pursuant to long-term, fee-based gathering agreements. Ascent Resources and Gulfport Energy Corporation are Ohio Gathering's key customers.customers and the AMIs from our customers for Ohio Gathering totalthis system cover approximately 825,000830,000 surface acres in the aggregate.2020,2022, we owned approximately a 38.2% ownership37.2% interest in Ohio Gathering, which includes our ownership in OGC and approximately a 38.2% interest in OCC. For additional information, see Note 7 - Equity Method Investments to the consolidated financial statements.15Williston BasinRockies reportable segment as of December 31, 2020.2022.Aggregate throughput capacity -
liquids (Mbbl/d)Aggregate throughput capacity -
natural gas (MMcf/d)Average daily MVCs through 2027 (MMcf/d) Remaining MVCs (Bcfe) Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years) Rockies - Williston 225 n/a n/a n/a 5.2 n/a 50 220 13 26 8.4 5.4 (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).Williston BasinRockies reportable segment total approximately 1.22.4 million surface acres in the aggregate.Divide.Divide system and the Niobrara G&P system.dedications.dedications and MVCs. Chord Energy Corporation (formerly Whiting Petroleum Corporation), Zavanna LLC, Crescent Point Energy Corp, Enerplus Corporation and BruinKraken Resources are the key customers of the Polar and Divide system.The Polar and Divide 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.16DJ Basin (Core Focus Area).The following table provides operating information regarding our DJ Basin reportable segment as of December 31, 2020.(1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).AMIs for the DJ Basin reportable segment total approximately 185,000 surface acres in the aggregate.the state.Colorado. Gathering and processing services on the Niobrara G&P system are provided pursuant to long-term, fee-based gatheringand percentage of proceeds agreements with producers that are primarily targeting crude oil production from the Niobrara and Codell shale formations. HighPoint andChevron Corporation, Civitas Resources, Inc., a large U.S. independent crude oil and natural gas company, Mallard Exploration (recently acquired by Bison Oil and Gas IV in January 2023), and Verdad Resources are the key customers of the Niobrara G&P system and have underpinned our volume throughput with acreage dedications and MVCs.a cryogenic natural gas processing plantplants with processing capacity of 60up to 220 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.and Trailblazer Pipeline and Southern Star and processed NGLs are delivered to the Overland Pass Pipeline.The Niobrara G&PPipeline and the P66 NGL System.currently provides midstream serviceshas discrete freshwater infrastructure that consists of 19 water wells and other infrastructure to provide its customers with up to approximately 55,000 barrels per day of fresh water for well completion activities, and the DJ Basin reportable segment.17Basin reportable segment as of December 31, 2020.2022.
______________________________________________Aggregate throughput capacity (MMcf/d) Average daily MVCs through 2027 (MMcf/d) Remaining MVCs (Bcf) Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years) 1,350 964 3,177 8.8 8.8 Contract terms related Presented on a gross basis. Existing MVC’s contractually increase to MVCs are excluded for confidentiality purposes.AMIs for the Permian Basin reportable segment total approximately 89,000 surface acres1.0 Bcf/d beginning in the aggregate.The Summit Permian system is an associated natural gas gathering and processing system operatingNovember 2024. As of December 31, 2022, we owned a 70% interest in the northern Delaware Basin in Eddy and Lea counties in New Mexico. Gathering and processing services on the Summit Permian system are provided pursuant to long-term, fee-based gathering agreements with producers that are primarily targeting crude oil production from the Bone Spring and Wolfcamp shale formations. XTO is the key customer of the Summit Permian system.The Summit Permian system operates a low-pressure natural gas gathering system and a 60 MMcf/d cryogenic processing plant. Residue natural gas is delivered to the Transwestern Pipeline and processed NGLs are delivered to the Lone Star NGL Pipeline. Summit Permian provides services for the Permian Basin reportable segment.18 (Core Focus Area).is under developmentcommenced operations in November 2021 and will provideprovides transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hubhub in Texas. Double E is underpinned by 1.0 Bcf/d of long-term take-or-pay contracts with ExxonMobil Corporation, Marathon Oil and Matador Resources Company (“Matador”). In 2021, we entered into negotiated rate agreements with an average term of 10 years from the in-service date of the pipeline, which occurred on November 18, 2021 and with total MDTQ’s that increase from 585,000 Dth/d during the first year of the agreement to 1,000,000 Dth/d in the fourth year, which equates to approximately 74% of its certificated capacity of 1,350,000 Dth/d. Volume throughput is received from multiple processing plants, including Matador’s Marlan plant, XTO’s Cowboy plant, Targa’s Roadrunner plant, San Mateo’s Black River plant and Crestwood’s Carlsbad plant. Double E is in the process of connecting EnLink’s Lobo plant and expects that connection to be operational in 2023. The Partnership owns 70% of Double E is leadingand operates the development, permitting and construction of the pipeline, and will operate Double E upon commissioning. In January 2021, Double E received its Notice to Proceed with construction, as well as approval of its implementation plan, from FERC and expects the pipeline will be in-service by the end of 2021. Due to Double E’s early development status, its assets and operations are not included in a reportable segment.pipeline.19Basin reportable segment as of December 31, 2020.2022.Aggregate throughput capacity (MMcf/d) Average daily MVCs through 2027 (MMcf/d) Remaining MVCs (Bcf) Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years) Piceance 1,151 175 319 9.7 3.4 (1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).Basin reportable segment totalcover approximately 654,000434,000 surface acres in the aggregate.The Grand River system currently provides midstream services for the Piceance Basin reportable segment.20Shale reportable segment as of December 31, 2020.2022.Throughput capacity (MMcf/d) Average daily MVCs through 2027 (MMcf/d) Remaining MVCs (Bcf) Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years) Barnett 450 n/a n/a 4 n/a (1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).Shale reportable segment totalcover approximately 124,000 surface acres.core of the Barnett Shale because of the quality of the geology and the high production profile of the wells drilled to date.date in our service area. The DFW Midstream system is underpinned by a long-term, fee-based gathering agreementagreements with Total Gas & Power North America, Inc. (“Total”) and additionalother customers.sixfive primary interconnections with third-party, primarily intrastate pipelines. These interconnections enable us to connect our customers, directly or indirectly, with the major natural gas market hubs in Texas and Louisiana. Total Gas & Power North America, Inc. ("Total") is the key customer for DFW Midstream.The DFW Midstream system currently provides midstream services for the Barnett Shale reportable segment.21Throughput capacity (MMcf/d)Average daily MVCs through 2023 (MMcf/d)Remaining MVCs (Bcf)Weighted-average remaining contract life (Years)Weighted-average remaining MVC life (Years)Marcellus Shale(1)1,050n/an/an/an/a(1) Contract terms related to MVCs are excluded for confidentiality purposes.The Mountaineer Midstream system is located in Doddridge and Harrison counties in West Virginia where it gathers natural gas under a long-term, fee-based contract with Antero, which is targeting liquids-rich natural gas production from the Marcellus Shale formation in the Appalachian Basin. Volume throughput on the Mountaineer Midstream system is underpinned by minimum revenue commitments from Antero.The Mountaineer Midstream system consists of a high-pressure natural gas gathering system and two compressor stations. This system gathers high-pressure natural gas received from upstream pipeline interconnections with Antero Midstream Corporation and Crestwood Equity Partners LP. Mountaineer Midstream serves as a critical inlet to the Sherwood Processing Complex, a primary destination for liquids-rich natural gas in northern West Virginia and one of the largest natural gas processing facilities in the United States.The Mountaineer Midstream system currently provides midstream services for the Marcellus Shale reportable segment.For additional information relating to our business and gathering systems, see the "Trends and Outlook" and "Results of Operations" sections in Item 7. MD&A.We believe that our gathering systems in the Core Focus Areas are positioned for long-term growth through further development by our customers and increased utilization of our gathering systems. We intend to continue expanding our operations and creating additional scale in our Core Focus Areas through the execution of new, and the expansion of existing, strategic partnerships with our existing and prospective customers.We believe that our customers in our Legacy Areas will pursue a slower pace of drilling and completion activity than customers in our Core Focus Areas. As a result, volume throughput in our Legacy Areas could decline or experience a lower rate of growth than our gathering systems in our Core Focus Areas. In general, our gathering systems in our Legacy Areas have a more mature base of connected wells, larger and longer-lived MVCs and experience lower volume throughput decline rates as compared to our gathering systems in our Core Focus Areas. We will continue to evaluate divestitures or joint ventures of certain of our gathering systems included in our Core Focus Areas or our Legacy Areas, which could result in a reallocation of capital or other resources to repay outstanding debt and other liabilities and fixed capital obligations, or re-invest in our Core Focus Areas.22which isand owned and operated by Epping, isare subject to FERC’s jurisdiction and oversight pursuant to FERC's authority under the NGA and the ICA, respectively. Epping and Epping hasDouble E have tariffs on file with FERC a tariff for interstate movements of crude oil on the pipeline. Additionally, in October 2020, Double E received FERC approval of its application to construct and operate the Double E Project, pursuant to Section 7(c) of the Natural Gas Act. The Double E Project is anticipated to provide interstate natural gas transmission service from the Delaware Basin in southeastern New Mexico to delivery points in and around the Waha Hub in Texas, will be subject to FERC jurisdiction. In 2018, FERC solicited public comment on its current policy on the certification of construction of new pipeline facilities, although it has not made any determinations yet on whether to make any changes to that policy. FERC.2016,2021, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%minus 0.21%. 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 terminatedFERC’s orders establishing this rulemaking on February 20, 2020 without adopting any part of the proposal. FERC completed its five-year review of its index adjustment by issuing an order on December 17, 2020 adopting a new annual index adjustment of the producer price index for finished goods plus 0.78% to become effective starting July 1, 2021. FERC’s order isare subject to rehearing and possiblepending judicial review. The rates charged by Epping may also be affected by FERC’s March 15, 2018 announcement of a revised policy eliminating the recovery of an income tax allowance in cost-of-service-based rates by FERC-jurisdictional crude oil and natural gas pipelines owned by master limited partnerships. FERC has not required oil pipelines on an industry-wide basis to decrease their rates to implement the new policy, but FERC has stated that the effects of the revised policy statement must be incorporated in annual FERC financial reports made by oil pipelines. The effect of the elimination of the income tax allowance for MLP pipelines, as well as the reduction in the corporate income tax rate resulting from the Tax Cuts and Jobs Act of 2017 (the “Tax Reform Legislation”), was considered in FERC’s five-year review of index rate adjustments which resulted in the December 17, 2020 order adopting a new annual index adjustment for the five-year period starting July 1, 2021.23 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, andwater. The NDIC has recentlyalso adopted reclamation bonding requirements for certain underground gathering pipelines in North Dakota.$1,307,164approximately $1.5 million per day per violation of the NGA, the NGPA, or their implementing rules, regulations, and orders subject to future adjustments for inflation. In addition, the FTC holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1,246,249approximately $1.4 million per violation, subject to future adjustment for inflation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The CFTC is directed under the CEA to prevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to statutory authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,227,202approximately $1.4 million 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.24meethave historically met the DOT definition of gathering lines and arewere 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; andimplement preventive and mitigating actions.imposeimposed several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extendsextended the requirement to conduct integrity assessments beyond “high consequence areas” (“HCAs”) to pipelines in “moderate consequence areas” (“MCAs”). It also includesincluded requirements to reconfirm Maximum Allowable Operating Pressure (“MAOP”), report MAOP exceedances, consider seismicity as a risk factor in integrity management, and use certain safety features on in-line inspection equipment. PHMSA modified the rule in July 2020, in response to a petition for reconsideration, to limit the rule’s recordkeeping requirement related to class location changes to gas transmission pipelines (not gas distribution pipelines) and to clarify that the rule’s reconfirmation requirements related to MAOP is limited to segments without traceable, verifiable and complete pressure test records. The rule concerning hazardous liquids extendsextended 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 addsadded a requirement to make all lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years.•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; or attributable to former operations; and25•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.26("ppb"(“ppb”). The revised standard has been lowered to 70 ppb. The lowered ozone NAAQS could subject us to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements and increased permitting delays and costs. Impacts fromIn October 2022, EPA reclassified the Dallas Fort Worth area as severe nonattainment under the 75 ppb standard and moderate nonattainment under the 70 ppb standard. As part of the same action, EPA also reclassified portions of Weld County, Colorado as severe nonattainment under the 75 ppb standard. In July 2022, EPA notified the State of Texas that it was considering redesignating an area comprising several Texas and New Mexico counties in the Permian Basin as a new ozone nonattainment area. These reclassifications and redesignations in areas where we operate could result in additional fees and more stringent permitting requirements for our operations, among other things. In addition, the EPA reviewed the 2015 70 ppb standard have not yet been determined, as states are still in 2020, but retained the process of incorporatingstandard without revision. However, EPA has announced that it will reconsider the new2020 decision to retain the 2015 standards. Future actions to lower the 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.could similarly result in additional fees or more stringent permitting.("NSPS"(“NSPS”) OOOO for the oil and gas industry, to reduce emissions of greenhouse gases - most notably methane - along with smog-forming VOCs. The revisions, which are published in the Federal Register under Subpart OOOOa, included the addition of methane to the pollutants covered by the rule, along with requirements for detecting and repairing leaks at gathering and boosting stations. The revised rule applies to sources that have been modified, constructed, or reconstructed after September 18, 2015. In August 2020,Further, in November 2021, the EPA issued two final rulesa new proposed rule targeting methane emissions from new and existing oil and gas sources.The proposed rule would: (1) update NSPS OOOOa; (2) adopt a new NSPS OOOOb for sources that rescindedcommence construction, modification or reconstruction after the methane-specific requirements of NSPS OOOO and OOOOa applicable to sourcesdate the proposed rule is published in the productionFederal Register; and processing segments and removed the transmission and storage segment from the source category. However, these 2020 rules are being challenged in the U.S. Court of Appeals for the D.C. Circuit. In addition, President Biden’s January 20, 2021 Executive Order on “Protecting Public Health and the Environment and Restoring Science(3) adopt a new NSPS OOOOc to Tackle the Climate Crisis” directed EPAestablish emissions guidelines, which will inform state plans to consider publishing a proposed rule suspending, revising, or rescinding the 2020 rules, as well as to consider establishing methane and VOC emissionestablish standards for existing sources.The EPA issued a supplemental proposal in November 2022 to update and expand the proposed NSPS OOOOb and OOOOc rules. This supplemental proposal would impose more stringent requirements and include sources not previously regulated under this source category.If finalized, these increasingly stringent requirements, or the application of new requirements to existing facilities, could result in the oiladditional restrictions on operations and gas sector, including the transportation and storage segments.("BLM"(“BLM”) issued a final rule to reduce venting and flaring of natural gas on public and Indian lands. The final rule mirrorsmirrored 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 finalThe rule that rescinded several requirements of this rule. However, in July 2020, the U.S. District Court for the Northern District of Californiawas vacated BLM’s 2018 revision rule. In addition, in October 2020,by a Wyoming federal district judge vacatedin 2020. However, BLM proposed a new rule in November 2022, similarly designed to reduce the 2016waste of natural gas from venting, flaring and flaring rule. Environmental groups appealed the October 2020 decision in December 2020leaks during oil and litigation is ongoing.gas production activities on federal and Indian leases. While the rule, if implemented,finalized, 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.27(intrafacility (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. 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 – such as Colorado, as discussed above – 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, during the 2021-2022 election cycle, Colorado representatives proposed a Colorado ballot initiative Proposition 112, would have substantially increased setback distances for various upstream activities, thereby substantially restricting new oil and gas development into ban hydraulic fracturing on all non-federal land, but the state. Although Proposition 112 was defeated in the November 2018 elections, similar ballot initiatives have been circulated by interested groups for potential consideration in elections. Further, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the Colorado Oil and Gas Conservation Commission (“COGCC”), the state’s oil and gas regulator from fostering oil and gas developmentproposed initiative failed to regulating oil and gas development in a reasonable manner to protect public health and the environment. The new law also allows local governments to impose more restrictive requirements on oil and gas operations than those issued by the state and reduced the oil and gas representation on the COGCC. Further, in November 2020, the COGCC adopted new regulations that increase oil and gas setbacks to a minimum of 2,000 feet from schools and childcare facilities, prohibit routine venting and flaring, increase wildlife protections, and alter certain aspects of the permitting process. These regulations and similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. garner significant support. States also could elect to prohibit hydraulic fracturing altogether, as New York, Maryland, Oregon, 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. These initiatives and similar efforts in Colorado and elsewhere could restrict oil and gas development in the future.approvinga proposal to issue new regulations requiring green completions of hydraulically-fractured wellsunder the NSPS to expand and corresponding reportingstrengthen emissions reduction requirements that went into effect in 2015. Revisions to the green completion regulations were finalized in June 2016under NSPS OOOOa for new, modified and include additional requirementsreconstructed oil and natural gas sources, and require states to reduce methane emissions from existing sources nationwide. For further discussion of NSPS OOOOa and VOCs. In August 2020,subsequent actions by the EPA, issued two final rules that rescindedsee the methane-specific requirements of these regulations applicable to sources in the production and processing segments and removed the transmission and storage segment from the source category. However, these 2020 rules are being challenged in the U.S. Court of Appeals for the D.C. Circuit. In addition, President Biden’s January 20, 2021 Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directed EPA to consider publishing a proposed rule suspending, revising, or rescinding the 2020 rules as well as to consider establishing methane and VOC emission standards for existing sources in the oil and gas sector, including the transportation and storage segments.“Air Emissions” section above. 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.lands, including requirements relating to well construction and integrity, handling of wastewater and chemical disclosure. However, in December 2017, the BLM published a final rule rescinding the 2015 rule. The U.S. District Court for the Northern District of California upheld the December 2017 rescission rule in a March 2020 decision. Thedecision, and the State of California and environmental plaintiffs then appealed the decisionappealed. The parties remain in June 2020. Litigation is currently ongoing.recently have also 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.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 havingrequiring federal permits or involving federal funding that have the potential to significantly impact the environment require review under NEPA. Many of our activities are covered under categorical exclusions which resultsresult 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.In addition, shortly after taking office in January 2021,As part of rejoining the Paris Agreement, President Biden issuedannounced that the United States would commit to a 50 to 52 percent reduction from 2005 levels of GHG emissions by 2030 and set the goal of reaching net-zero GHG emissions by 2050. In November 2021, the Biden Administration expanded on this commitment and announced “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” establishing a roadmap to net zero emissions in the United States by 2050 through, among other things, improvements in energy efficiency; decarbonization of energy sources via electricity, hydrogen, and sustainable biofuels; and reductions in non-CO2 GHG emissions, such as methane and nitrous oxide.These initiatives followed a series of executive orders by President Biden designed to address climate change. For example, the Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” called for new regulations and policies to address climate change and suspend, revise, or rescind, prior agency actions that were identified as conflicting with the Biden Administration’s climate policies. Reentry into the Paris Agreement, andnew legislation, or President Biden’s executive orders may result in the development of29Talent development, compensation and retention – We strive to provide our employees with a rewarding work environment, including the opportunity for success and a platform for personal and professional development. We provide a competitive benefits package designed to attract and retain a skilled and diverse workforce. We offer our employees a comprehensive benefits package, which includes company funded health plan options, vision and dental coverage, healthcare savings account, paid time off, parental leave and flexible spending accounts. We also provide professional training and development opportunities as well as education reimbursement. We also offer employees immediate eligibility in our 401(k) plan with company matching program.• the health and safety of our employees include wellness programs with incentives and employee assistance programs.•Inclusion and diversity – We are committed to efforts to increase diversity and foster an inclusive work environment that supports our workforce.In addition to the variety of support services we provide to our employees under normal circumstances, our top priority during the ongoing COVID-19 pandemic remains protecting the health and well-beingsafety of our employees customers, partnersinclude wellness programs with incentives and communities. Since the onset of the COVID-19 pandemic, we have maintained a work-from-home policy for substantially allemployee assistance programs.employees, significantly limited business travel, and we have taken an integrated approach to helping our employees manage their work and personal responsibilities, with a strong focus on employee physical and mental health.2020,2022, the Partnership employed 220252 people who provide direct, full-time support to our operations. None of our employees are covered by collective bargaining agreements, and we have nevernot experienced any business interruption as a result of any labor disputes.ourthis 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. We also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. We may use the Investors section of our website to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. Documents and information on our website are not incorporated by reference herein. The SEC maintains an Internet sitea website 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.Risks Related to COVID-19The COVID-19 pandemic, coupled with other current pressures on oil and gas prices resulting from the OPEC price war, has had, and is expected to continue to have, an adverse impact on our business, results of operations, financial position and cash flows.The ongoing COVID-19 outbreak continues to be a rapidly evolving situation. As of February 20, 2021, the CDC had recorded over 27.8 million cases in the United States and over 490,000 deaths. The pandemic has resulted in widespread adverse impacts on the global economy and on our business, including our customers, employees, supply chain, and distribution network. We are currently unable to predict the ultimate impact that it may have on our business, future results of operations, financial position or cash flows. The extent to which our operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including changes in the severity of the pandemic, countermeasures taken by governments, businesses and individuals to slow the spread of the pandemic, and the development and availability of treatments and vaccines and the extent to which these treatments and vaccines may remain effective as potential new strains of the coronavirus emerge. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.In response to the COVID-19 pandemic, we have modified our business practices, including restricting employee travel, modifying employee work locations, implementing social distancing and enhancing sanitary measures in our facilities. Many of our suppliers, vendors and service providers have made similar modifications. The resources available to employees working remotely may not enable them to maintain the same level of productivity and efficiency, and these and other employees may face additional demands on their time. Our increased reliance on remote access to our information systems increases our exposure to potential cybersecurity breaches. We may take further actions as government authorities require or recommend or as we determine to be in the best interests of our employees, customers, partners and suppliers. There is no certainty that such measures will be sufficient to mitigate the risks posed by the virus, in which case our employees may become sick, our ability to perform critical functions could be impaired, and we may be unable to respond to the needs of our business. The resumption of normal business operations after such interruptions may be delayed or constrained by lingering effects of COVID-19 on our suppliers, third-party service providers, and/or customers.In the first half of 2020, oil prices declined significantly due to increases in supply emanating from a disagreement on production cuts among members of OPEC and certain non-OPEC, oil-producing countries and subsequent hydrocarbon commodity price declines. The resulting supply and demand imbalance disrupted the oil and natural gas exploration and production industry and other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. Although OPEC agreed in April 2020 to cut oil production and extended such production cuts through December 2020, there is no assurance that the agreement will continue to be observed by its members, and the responses of oil and gas producers to the lower demand for, and price of, natural gas, NGLs and crude oil are constantly evolving and remain uncertain. Continued pressure on demand. Such responses could cause our pipelines and storage tanks to reach capacity, thereby forcing producers to experience shut-ins or look to alternative methods of transportation for their products. In addition, the dramatic decrease in oil and gas prices could have substantial negative implications for our revenue sources that are related to or underpinned by commodity prices. As a result, these factors could have a material adverse effect on our business, future results of operations, financial position or cash flows. At this point, we cannot accurately predict the long-term effects current market conditions due to the COVID-19 pandemic and failed OPEC negotiations will have on our business, which will depend on, among other factors, the duration of the outbreak and the extent and overall economic effects of the governmental response to the pandemic.The impact of COVID-19 and the OPEC price war may also exacerbate other risks discussed below, any of which could have a material effect on us. This situation is changing rapidly, and additional impacts may arise that we are not aware of currently.31In May 2020, we suspended distributions to holders of our common units and our Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. We didhave not makemade a distribution on our common units or Series A Preferred Units since we announced suspension of those distributions on May 3, 2020. Because our Series A Preferred Units rank senior to our common units with respect to distribution rights, any quarter in 2020, nor did we make a distributionaccrued amounts on our Series A Preferred Units must first be paid prior to our resumption of distributions to our common unitholders. As of December 31, 2022, the amount of accrued and unpaid distributions on June 15, 2020 or December 15, 2020. the Series A Preferred Units totaled $21.5 million.maydo not expect to pay distributions on the common units or Series A Preferred Units in the foreseeable future, and there are restrictions on our ability to pay distributions under our outstanding indebtedness that restrict our ability to pay cash distributions on any of our equity securities. We intend to use our cash flow to reduce debt and invest in our business.•the volumes we gather, treat and process;the level of production of natural gas and crude oil (and associated volumes of produced water) from wells connected to our gathering systems, which is dependent in part on the demand for, and the market prices of, crude oil, natural gas and NGLs;damage to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters, accidents and acts of terrorism;leaks or accidental releases of hazardous materials into the environment;weather conditions and seasonal trends;changes in the fees we charge for our services;changes in contractual MVCs and our customer’s capacity to make MVC shortfall payments when due;the level of competition from other midstream energy companies in our areas of operation;changes in the level of our operating, maintenance and general and administrative expenses;regulatory action affecting the supply of, or demand for, crude oil, natural gas and NGLs, the fees we can charge, how we contract for services, our existing contracts, our operating and maintenance costs or our operating flexibility; and��prevailing economic and market conditions.•the level and timing of capital expenditures we make;the level of our operating, maintenance and general and administrative expenses, including reimbursements of expenses incurred on our behalf by our General Partner;the cost of acquisitions, if any;our ability to sell assets, if any, and the price that we may receive for such assets;our debt service requirements and other liabilities;fluctuations in our working capital needs;our ability to borrow funds and access the debt and equity capital markets;restrictions contained in our debt agreements;the amount of cash reserves established by our General Partner;not receiving anticipated shortfall payments from our customers;32distributions paid on our Series A Preferred Units, if any, or on the preferred stock of our subsidiaries; andother business risks affecting our cash levels.Basin gathering systemsegment accounts for over 10% of our aggregatedconsolidated 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.TheAn extended low commodity price environment has negatively impactedimpacts 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.33Additionally, 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.•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• of drilling rigs and other costs of production and equipment.34Table of Contentsdrilling permits and the regulation of hydraulic fracturing; and•worldwide economic and geopolitical conditions;global or national health concerns, including the outbreak of pandemic or contagious disease, such as COVID-19, which may continue to reduce demand for crude oil, natural gas and NGLs because of reduced global or national economic activity;weather conditions and seasonal trends;the levels of domestic production and consumer demand;the availability of imported liquefied natural gas (“LNG”);the ability to export LNG;the availability of transportation and storage systems with adequate capacity;the volatility and uncertainty of regional pricing differentials and premiums;•the price and availability of alternative fuels, including alternative fuels that benefit from government subsidies;the effect of energy conservation measures;the nature and extent of governmental regulation and taxation; andthe anticipated future prices of crude oil, natural gas and other hydrocarbon products, including NGLs.Any significant decrease in the demand for natural gas and crude oil could reduce the volumes of natural gas and crude oil that we gather and process, which could adversely affect our business and operating results.The volumes of natural gas and crude oil that we gather and process depend on the supply and demand for natural gas and crude oil and other hydrocarbon products in the areas served by our assets. Natural gas and crude oil compete with other forms of energy available to users, including electricity, coal, other fuels and alternative energy sources. Increased demand for such forms of energy at the expense of natural gas and crude oil could lead to a reduction in demand for our services. Any such reduction could result in a decline in our revenues and cash flows and materially adversely affect our ability to make cash distributions to our unitholders.3536•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; andthe effects of federal, state or local regulations on the contracting practices of our customers.We have a relatively limited ownership history with respect to certainour 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.37•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; andinadequate 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.•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; andother hazards that could also result in personal injury and loss of life, pollution and suspension of operations.38 future gathering system acquisitions, couldsuch as the 2022 DJ Acquisitions, can 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.39personnel.A shortagein the midstream energy industry could reduce employee productivity and increase costs, which could have a material adverse effect onthroughout our business and results of operations.We have from time to time encountered shortages for these types of skilled labor. If we continue to 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.40our Revolvingthe ABL Facility or the Permian Transmission Credit Facility.unitholders.unitholders, if any. Our ability to obtain financing or to access the capital markets for future debt or equity offerings may be limited by (i) our financial condition at the time of any such financing or offering, (ii) covenants in our debt agreements, (iii) restrictions imposed by our Series A Preferred Units, (iv) general economic conditions and contingencies, (v) increasing disfavor among many investors towards investments in fossil fuel companies and (vi) general weakness in the debt and equity capital markets and other uncertainties that are beyond our control. In addition, lenders are facing increasing pressure to curtail their lending activities to companies in the oil and natural gas industry. Furthermore, market demand for equity issued by master limited partnerships has been significantly lower in recent years than it has been historically, which may make it more challenging for us to finance our expansion capital expenditures and acquisition capital expenditures with the issuance of additional equity.didhave not makemade a distribution on our common units with respect to any quarter in 2020, nor did we make a distribution on ouror Series A Preferred Units since we announced suspension of those distributions on June 15, 2020 or December 15,May 3, 2020, and these suspensions of distributions may further reduce demand for our common units or Series A Preferred Units. Because our Series A Preferred Units rank senior to our common units with respect to distribution rights, any accrued amounts on our Series A Preferred Units must first be paid prior to our resumption of distributions to our common unitholders. As of December 31, 2022, the amount of accrued and unpaid distributions on the Series A Preferred Units totaled $21.5 million. Further, we maydo not expect to pay distributions on the common units or Series A Preferred Units in the foreseeable future, and there are restrictions on our ability to pay distributions under our outstanding indebtedness that restrict our ability to pay cash distributions on any of our equity securities. As such, if we are unable to raise expansion capital, we may lose the opportunity to make acquisitions, pursue new organic development projects, or to gather, treat and process new production volumes from our customers with whom we have agreed to construct and develop midstream assets in the future. Even if we are successful in obtaining external funds for expansion capital expenditures through the capital markets, the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional units representing limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to pay distributions to our unitholders, which could materially decrease our ability to pay such distributions.2020,2022, we had $1.3$1.5 billion of indebtedness outstanding and the unused portion of our $1.1 billion Revolving Creditthe ABL Facility totaled $238.9$64.1 million subjectafter giving effect to an issuedthe issuance of $5.9 million in outstanding but undrawn letterirrevocable standby letters of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of December 31, 2020 was approximately $105 million. See Note 9 - Debt of the notes to our consolidated financial statements included in Item 8 of this reportAnnual Report for further discussion of our debt obligations, including debt maturities for the next five years and thereafter.obligations. 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; andlimiting our flexibility in responding to changing business and economic conditions.41Table of Contents•Restrictions in our Revolving Credit Facility and Senior Notes indentures could materially adversely affect our business, financial condition, resultsoperations, ability to make cash distributions to unitholders and value of our common units.We are dependent upon the earnings and cash flows generated by our operations to meet our debt service obligations and to make cash distributions to our unitholders, if any. The operating and financial restrictions and covenants in our Revolving Credit Facility, our Senior Notes indentures and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders. For example, our Revolving Credit Facility and Senior Notes indentures, taken together, restrict our ability to, among other things:
Contents•incur or guarantee certain additional debt;•make certain cash distributions on or redeem or repurchase certain units;•make certain investments and acquisitions;•make certain capital expenditures;•incur certain liens or permit them to exist;•enter into certain types of transactions with affiliates;•enter into sale and lease-back transactions and certain operating leases;•merge or consolidate with another company or otherwise engage in a change of control transaction; and•transfer, sell or otherwise dispose of certain assets.Our Revolving Credit Facility and Senior Notes indentures also contain covenants requiring us to maintain certain financial ratios and meet certain tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot guarantee that we will meet those ratios and tests. Based upon the terms of our Revolving Credit Facility and total outstanding debt of $1.3 billion (inclusive of $494 million of senior unsecured notes, net of debt issuance costs), our total leverage ratio first lien secured leverage ratio (as defined in the credit agreement) as of December 31, 2020, were 5.1 to 1.0 and 3.2 to 1.0, respectively, relative to maximum threshold limits of 5.75x and 3.5x.The provisions of our Revolving Credit Facility and Senior Notes indentures may affect our ability to obtain future financing and pursue attractive business opportunities as well as affect our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our Revolving Credit Facility or Senior Notes indentures could result in a default or an event of default that could enable our lenders and/or senior noteholders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, the lenders under our Revolving Credit Facility could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. The Revolving Credit Facility also has cross default provisions that apply to any other indebtedness we may have and the Senior Notes indentures have cross default provisions that apply to certain other indebtedness. Any of these restrictions in our Revolving Credit Facility and Senior Notes indentures could materially adversely affect our business, financial condition, cash flows and results of operations.our Revolving Creditthe ABL Facility, the 2026 Secured Notes and ourthe 2025 Senior Notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.42 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 theus,it, if at all, and the proceeds of any such dispositions may not be adequate to meet any debt service obligations then due.between the relevantamong our other debt agreements), the lenders under our Revolving Creditthe ABL 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 Notesdebt agreements were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to our creditors. 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.$13.1 million and $60.5$91.6 million in 20202022 and 2019, respectively. In 2019, we also recorded an impairment of our equity method investment$10.2 million in Ohio Gathering of $329.7 million and a loss of $6.3 million related to a long-lived asset impairment on OCC.2021. 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- andmarket-and income-based approaches. We evaluate our equity method investmentinvestments 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 lower432020,2022, we derived 13%18% of our revenues from (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers onin the Williston Basin,Rockies, Permian and Piceance Basin, and Permian Basin segments, (ii) natural gas and crude oil marketing services in and around our gathering systems, (iii) the sale of natural gas we retain from certain Barnett Shale customers, and (iv)(iii) the sale of condensate we retain from our gathering services in the Piceance Basin segment.segment and (iv) additional gathering fees that are tied to performance of certain commodity price indexes, which are then added to the fixed gathering rates. Consequently, our existing operations and cash flows have direct exposure to commodity price risk. Although we will seek to limit our commodity price exposure with new customers in the future, our efforts to obtain fee-based contractual terms may not be successful or the local market for our services may not support fee-based gathering and processing agreements. For example, we have percent-of-proceeds contracts with certain natural gas producer customers and we may, in the future, enter into additional percent-of-proceeds contracts with these customers or other customers or enter into keep-whole arrangements, which would increase our exposure to commodity price risk, as the revenues generated from those contracts directly correlate with the fluctuating price of the underlying commodities.If we fail to maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.As a publicly traded partnership, we are subject to the public reporting requirements of the Exchange Act, including the rules thereunder that will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Effective internal controls are necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We prepare our consolidated financial statements in accordance with GAAP. Our efforts to maintain our internal controls may not be successful and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002.Given the difficulties inherent in the design and operation of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our or our independent registered public accounting firm’s future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls over financial reporting could subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.aresettled a matter that was previously under investigation by federal and state regulatory agencies overregarding a pipeline rupture and release of produced water by one of our subsidiaries. The resolutionresulting compliance requirements of this matter could have a material adverse effect onthe settlement may impact our results of operations or cash flows.is under investigationwhich was investigated by federal and state agencies pursuantagencies. This settlement resulted in losses amounting to various laws that$36.3 million and will be paid over six years, of which we have paid $8.0 million as of December 31, 2022 and requires compliance with certain conditions and terms and conditions which may give rise to criminal and civil liability. A loss arising from this incident is probable, and the ultimate outcome could have a material adverse effect onimpact our results of operations or cash flows. We have accrued a loss contingency for this incident but cannot predict whether any actual loss, if one were to occur, would be materially higher or lower than such accrual.44In 2016, the NDIC adopted rule changes that resulted in additional construction and monitoring requirements for certain underground gathering pipelines, including, but not limited to, those that transport produced water. The NDIC also adopted reclamation bonding requirements for certain underground gathering pipelines. At the federal level,For example, PHMSA has issued new proposed and final rules concerning pipeline safety in recent years. In November 2021, PHMSA issued a final rule that extended pipeline safety requirements to onshore gas gathering pipelines. The rule requires all onshore gas gathering pipeline operators to comply with PHMSA’s incident and annual reporting requirements. It also extends existing pipeline safety requirements to a new category of gas gathering pipelines, “Type C” lines, which generally include high-pressure pipelines that are larger than 8.625 inches in diameter. Safety requirements applicable to Type C lines vary based on pipeline diameter and potential failure consequences. The final rule became effective in May 2022 and operators were required to comply with the applicable safety requirements by November 2022. In addition, in August 2022, PHMSA issued a final rule that established new or additional requirements for natural gas transmission lines related to the management of change process, integrity management, corrosion control standards, and pipeline inspections and repairs. To thatthe extent these or other new proposed or final rules create additional1.A.1A. Risk Factors. in 2018 the Colorado state ballot included a proposed 2,500 foot setback for oil and gas development from occupied structures and certain other areas. While the proposal did not pass, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the COGCC from fostering oil and gas development to regulating oil and gas development in a reasonable manner to protect public health and the environment. The new law also allows local governments to impose more restrictive requirements on oil and gas operations than those issued by the state. Further,As part of its implementation of this new law, in November 2020 the COGCC adopted new regulations that increase oil and gas setbacks to a minimum of 2,000 feet from schools and childcare facilities, prohibit routine venting and flaring, increase wildlife protections, and alter certain aspects of the permitting process. These regulations and similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. Regulatory agencies establish and, from time to time, change priorities, which may result in additional burdens on us, such as additional reporting requirements and more frequent audits of operations. Our operations and the markets in which we participate are affected by these laws, regulations and interpretations and may be affected by changes to them or their implementation, which may cause us to realize materially lower revenues or incur materially increased operation and maintenance costs or both.45 Colorado ballot initiative Proposition 112, would have substantially increased setback distances for various upstream activities, thereby substantially restricting new oil and gas development into ban hydraulic fracturing on all non-federal land, but the state. Although Proposition 112 was defeated in the November 2018 elections, similar ballot initiatives have been circulated by interested groups for potential consideration in elections. Further, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the COGCC from fostering oil and gas developmentproposed initiative failed to regulating oil and gas development in a reasonable manner to protect public health and the environment. The new law also allows local governments to impose more restrictive requirements on oil and gas operations than those issued by the state. Further, in November 2020, the COGCC adopted new regulations that increase oil and gas setbacks to a minimum of 2,000 feet from schools and childcare facilities, prohibit routine venting and flaring, increase wildlife protections, and alter certain aspects of the permitting process. These regulations and similar efforts in Colorado and elsewhere could restrict oil and gas development in the future.garner significant support. States also could elect to prohibit hydraulic fracturing altogether, as New York, Maryland, Oregon 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.approvinga proposal to issue new regulations requiring green completions of hydraulically-fractured wellsunder the NSPS to expand and corresponding reportingstrengthen emissions reduction requirements (NSPS OOOO) that went into effect in 2015. Revisions to the green completion regulations (NSPS OOOOa) were finalized in June 2016under NSPS OOOOa for new, modified and include additional requirementsreconstructed oil and natural gas sources, and require states to reduce methane emissions from existing sources nationwide. For further discussion of NSPS OOOOa and VOCs. In August 2020,subsequent actions by the EPA, issued two final rules that rescindedsee the methane-specific requirements“Environmental Matters—Air Emissions” section of NSPS OOOO and OOOOa applicable to sources in the production and processing segments and removed the transmission and storage segment from the source category. However, these 2020 rules are being challenged in the U.S. CourtItem 1. Business of Appeals for the D.C. Circuit. In addition, President Biden’s January 20, 2021 Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directed EPA to consider publishing a proposed rule suspending, revising, or rescinding the 2020 rules, as well as to consider establishing methane and VOC emission standards for existing sources in the oil and gas sector, including the transportation and storage segments.this Annual Report. 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.lands, including requirements relating to well construction and integrity, handling of wastewater and chemical disclosure. However, in December 2017, the BLM published a final rule rescinding the 2015 rule. The U.S. District Court for the Northern District of California upheld the December 2017 rescission rule in a March 2020 decision. Thedecision, and the State of California and environmental plaintiffs then appealed the decisionappealed. The parties remain in June 2020. Litigation is currently ongoing.includingin the EPA.past. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing.recently have also 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.46our proposedthe Double E Project, for which FERC approved the implementation plan in January 2021, and which is anticipated to provideprovides interstate natural gas transmission service from southeastern New Mexico to the Waha Hubhub in Texas, will beis subject to FERC jurisdiction once completed. FERC may includeunder the NGA with respect to post-construction remediation activities, operations, and rates and terms and conditions on its issuance of service. Pursuant to 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 ofNGA, Double E Pipeline’s existing interstate natural gas pipelines, FERC also regulates such pipelines’transportation rates and terms and conditions of service includingmay be challenged by complaint and are subject to prospective change by FERC. Additionally, rate changes and changes to terms and conditions of service proposed by a regulated natural gas interstate pipeline may be protested and such changes can be delayed and may ultimately be rejected by FERC. FERC may also initiate reviews of an interstate pipeline’s rates. We cannot guarantee that any new or existing tariff rate for service on our FERC-regulated pipelines would not be rejected or modified by the FERC or subjected to refunds. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on our business, financial condition and results of operations.agreementsprovider and a customer may mutually agree to sign a contract for service at a “negotiated rate,” which is generally fixed between the natural gas pipeline and the shipper for the contract term and does not necessarily vary with changes in the level of cost-based “recourse rates,” provided that the affected customer is willing to agree to such rates and that the FERC has accepted the negotiated rate agreement. These “negotiated or discount rate” contracts are not generally subject to adjustment for increased costs which could be caused by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated or discounted rates, under current FERC policy, may be recoverable from other shippers in certain circumstances. For example, the FERC may recognize this shortfall in the determination of prospective rates in a future rate agreements.which authorizeand also must comply with the other applicable provisions of the NGA and NGPA and FERC’s rules, regulations, and orders concerning the Double E Pipeline’s interstate natural gas pipeline business, including those that require us to provide firm and interruptible transportation service on an open access basis that is not unduly discriminatory or preferential. Violations of the NGA or NGPA, or the rules, regulations, and orders issued by FERC to impose finesthereunder could result in the imposition of administrative and criminal remedies, including without limitation, revocation of certain authorities, disgorgement of ill-gotten gains, and civil penalties of up to $1,307,164approximately $1.5 million per day per violation of the NGA or its implementing regulations, subject to future adjustment for inflation. In addition, the FTC holds$1,246,249approximately $1.4 million per violation, subject to future adjustment for inflation. The CFTC is directed under the CEA to prevent price manipulation in the commodity, futures and swaps markets, including the energy markets. Pursuant to the Dodd-Frank Act, and other authority, the CFTC has adopted additional anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity, futures and swaps markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,227,202approximately $1.4 million 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.47necessary."Environmental Matters "“Environmental Matters” section of Item 1. Business. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and requisite permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.48new presidential administrationBiden Administration is considering revisions to the leasing and Democratic control of Congress resulting from the 2020 elections may result in increased restrictions onpermitting programs for oil and gas production activities, development on federal lands, which could materially adversely affect our industry and our financial condition and results of operations.meethave historically met the DOT definition of gathering lines and arewere 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; andimplement preventive and mitigating actions."Regulation“Regulation of the Natural Gas and Crude Oil Industries—Safety and Maintenance"Maintenance” section of Item 1. Business.In July 2018,Business and the PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline. The associated notice of proposed rulemaking, issued October 14, 2020, proposes to amend the requirements for gas transmission pipeline segments that experience a“A change in class location by offering an alternative setlaws and regulations applicable to our assets or services, or the interpretation or implementation of requirements operators could use, based on implementing integrity management principlesexisting laws and pipe eligibility criteria,regulations may cause our revenues to manage certain pipeline segments where the class location has changed from a Class 1 location to a Class 3 location. In October 2019, the PHMSA issued three new final rules. One rule, which became effective in December 2019, establishes procedures to implement the expanded emergency order enforcement authority set forth in an October 2016 interim final rule. Among other things, this rule allows the PHMSA to issue an emergency order without advance noticedecline or opportunity for a hearing. The other two rules, which became effective in July 2020, impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extends the requirement to conduct integrity assessments beyond “high consequence areas” (HCAs) to pipelines in “moderate consequence areas” (MCAs). It also includes requirements to reconfirm Maximum Allowable Operating Pressure (MAOP), report MAOP exceedances, consider seismicity as a risk factor in integrity management, and use certain safety features on in-line inspection equipment. The49rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events, and adds a requirement to make all lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. Further, in December 2020, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020 became law, reauthorizing PHMSA for funding through 2023 and requiring, among other things, rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for gas distribution operators;expenses to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines. While we believe that we are in compliance with existing safety laws and regulations, increased penalties for safety violations and potential regulatory changes could have a material adverse effect on our operations, operating and maintenance expenses and revenues.revisionsInflation Reduction Act, signed into law in August 2022, includes a Methane Emissions Reduction Program to the NSPS found in 40 CFR 60 subpart OOOO (and OOOOa) includeincentivize methane emission reduction requirements. In August 2020, the EPA issued two final rules that rescinded the methane-specific requirements of NSPS OOOOreductions and OOOOa applicable to sources in the production and processing segments and removed the transmission and storage segmentimpose a fee on GHG emissions from the source category. However, these 2020 rules are being challenged in the U.S. Court of Appeals for the D.C. Circuit. In addition, President Biden’s January 20, 2021 Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directed EPA to consider publishing a proposed rule suspending, revising, or rescinding the 2020 rules, as well as to consider establishing methane and VOC emission standards for existing sources in thecertain oil and gas sector, including the transportation and storage segments.January 2019, the governorJune 2022, as part of New Mexico signed an executive order that includes a goal of reducingGovernor-directed statewide initiative to reduce GHG emissions by at least 45% by 2030. The executive order directs the New Mexico Energy, Minerals and Natural Resources Department (“EMNRD”) and2030, the New Mexico Environment Department (“NMED”) to jointly develop a statewide, enforceable regulatory framework to secure reductions in oil and gas sector methane emissions. The executive order also creates a Climate Change Task Force to evaluate and develop regulatory strategies to reach the 45% reduction goal. In July 2020, NMED released draftfinalized new rules that would establish emissions standards for VOCs and nitrogen oxides for oil and gas production and processing sources located in certain areas of the state with high ozone concentrations. We cannot currently determine the effect of these proposed regulations and other regulatory initiatives to implement the Governor’s directive to reduce GHG emissions, that could, if implemented, impact the business, reputation, financial condition or results of our operations in New Mexico or that of our customers upstream of the Double E Pipeline. Similarly, EMNRD released draftin April 2021, the New Mexico Department of Energy, Minerals, and Natural Resources (“EMNRD”) finalized new rules concerning venting and flaring of natural gas. Neither agency has yet issued aEMNRD’s final rule. Although we cannot currently determine the effectrule could impose new or increased costs and obligations on our customers upstream of the proposed regulations developed by the EMNRD and the NMED or other potential regulatory strategies that may be suggested by the Climate Change Task Force, if implemented they could be material to the business, reputation, financial condition or results of operations of our Summit Permian system."Environmental“Environmental Matters—Climate Change" sectionChange” and “Environmental Matters—Air Emissions” sections of Item 1. Business.50In addition, shortly after taking office in January 2021,As part of rejoining the Paris Agreement, President Biden issuedannounced that the United States would commit to a 50 to 52 percent reduction from 2005 levels of GHG emissions by 2030 and set the goal of reaching net-zero GHG emissions by 2050. In November 2021, the Biden Administration expanded on this commitment and announced “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” establishing a roadmap to net zero emissions in the United States by 2050 through, among other things, improvements in energy efficiency; decarbonization of energy sources via electricity, hydrogen, and sustainable biofuels; and reductions in non-CO2 GHG emissions, such as methane and nitrous oxide. These initiatives followed a series of executive orders by President Biden designed to address climate change. Reentry into the Paris Agreement, andnew legislation, or President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations, which could have a material adverse effect on our business and that of our customers.The implementationunder the Dodd-Frank Act that establishes federal oversight over 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.Thehas proposed federal positionadopted rules that place limits on positions in certain core futures and equivalent swaps contracts in the major energy and other markets, withfor or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions provided that various conditions are satisfied. If finalized, the position limits rule and itstransactions. We do not expect these regulations to materially impede our hedging activity at this time, but a 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.51In 2013, theThisThe application of this interpretation may have an impact on our ability to enter into certain forwards or may impose additional requirements with respect to certain transactions.lacklingering absence of regulatory equivalency across jurisdictions may increase compliance costs and make it more costly to satisfy regulatory obligations.52dredge-and-fill activities fordischarges of dredged or fill material associated with pipeline and other utility line construction projects, to the extent it was used to authorize construction of new oil and gas pipelines. Environmental groups had alleged that the Corps failed to consult with federal wildlife agencies as required by the Endangered Species Act. The court’s decision vacated NWP 12 until the Corps completes consultation with the applicable federal wildlife agencies. On July 6, 2020, the U.S. Supreme Court granted in part the Corps’ request to stay the U.S. District Court’s decision to allow the use of NWP 12 for utility line activities, including new oil and gas pipelines, pending the outcome of the appeal to the U.S. Court of Appeals for the Ninth Circuit and any subsequent petition for review to the U.S. Supreme Court. Litigation is currently ongoing. In addition,Act (“ESA”). However, in January 2021, the EPA and Corps reissued NWP 12 as a general permit specific to oil and gas pipelines, moving other utility line activities into separate general permits. However,The U.S. Court of Appeals for the Ninth Circuit subsequently held that the Corps’ January 2021 reissuance rendered the prior challenge moot. In May 2021, environmental groups once again filed suit in the U.S. District Court for the District of Montana, seeking vacatur of the reissued NWP 12. Environmental groups allege that the reissuance isof NWP 12 violated the ESA, National Environmental Policy Act, and Clean Water Act, among other things. In September 2022, the agency actions listedU.S. District Court for reviewMontana dismissed the ESA consultation challenges as moot and dismissed the remainder of the lawsuit without prejudice. The Corps has announced that it will be reviewing all the nationwide permits for consistency with Administration policies, which could result in accordance withadditional limitations on the January 20, 2021 Executive Order: “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.”use of nationwide permits. Limitations on the use of NWP 12 may make it more difficult to permit our projects, require consideration of alternative construction or siting, which may impose additional costs and delays, and could cause us to lose potential and current customers and limit our growth and revenue.Indian Tribes.tribes. The court’s decision requires the pipeline to shut down operations by August 5, 2020 but was stayed by the U.S. Court of Appeals for the District of Columbia Circuit. On January 26, 2021, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision affirming the district court’s holding that the easement should be vacated but reversing the requirement to shut down the pipeline. The Court of Appeals left it to the Corps to determine how to proceed after the loss of the easement, and while the District Court has received briefing on whetherCorps declined to enjoin the operation ofshut down the pipeline, asit did not formally approve the pipeline’s ongoing operation without an easement. Dakota Access filed for rehearing en banc on April 12, 2021, which the Court of Appealsresult. petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General and plaintiffs, and Dakota Access has filed its reply.Court’s ruling orCourt terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. On January 20, 2022, the Standing Rock Sioux Tribe withdrew as a decision bycooperating agency on the Corpsdraft EIS, prompting the USACE to ordertemporarily pause on the pipeline to shut down.draft EIS. The USACE now estimates that the draft EIS will be published sometime in the spring of 2023. If the Dakota Access Pipeline is forced to shut down, this could have a material adverse effect on our business, financial condition and results of operations associated with the Polar and Divide System,system, which interconnects with the Dakota Access Pipeline.53Internationalinternational laws and regulations regarding privacy and data protection (“data protection laws”). Many of these data protection laws and regulations are subject to change and uncertain interpretation, and could result in claims, increased cost of operations or otherwise harm our business.specific lawsdata protection laws. The collection, use, and regulations. The transfer and use of this data, both domestically and across international bordersinternationally, is becoming increasingly complex. The regulatory environment surrounding and the collection, use, 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, Connecticut, Virginia and Utah legislation, the European Union General Data Protection Regulation (“GDPR”) and the California Consumer Privacy Act, as amended by the California Privacy Rights Act (“CCPA”), pose increasingly complex compliance challenges and potentially elevate our costs.vendors and subcontractors, from an establishment in the European Union.business partners. 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, givesimposes specific obligations on businesses that collect personal data from California residents and provides California residents specific rights in relation to their personal information, requiresdata that companies take certain actions, including notifications for security incidentswe or our business partners collect and may apply to activities regarding personal information that is collected by us, directly or indirectly, from California residents.use. 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, withand carries the possibility for significant financial penalties for noncompliance that may materially adversely affect our business, reputation, results of operations, and cash flows.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.54AsAlthough we have not made a distribution on our common units or Series A Preferred Units since we announced suspension of those distributions on May 3, 2020 and do not expect to pay distributions on thewe may make cash distributions during periods when we report net losses for GAAP purposes and may notbe unable to make cash distributions during periods when we report net income for GAAP purposes.•our quarterly distributions, if any;our quarterly or annual earnings or those of other companies in our industry;the loss of a large customer;announcements by our customers or others regarding our customers or changes in our customers’ credit ratings, liquidity position, leverage profile and/or other financial or credit-related metrics;announcements by our competitors of significant contracts or acquisitions;changes in accounting standards, policies, guidance, interpretations or principles;general economic and geopolitical conditions;the failure of securities analysts to cover our common units or changes in financial estimates by analysts; andother factors described in these Risk Factors.•whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in our best interests, and will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as such decisions are made in good faith;55•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•i.approved by the Conflicts Committee, if established, although our General Partner is not obligated to seek such approval;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.approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates;approved by the Conflicts Committee, although our General Partner is not obligated to seek such approval;ii.iii.on terms no less favorable to us than those generally being provided to or available from unrelated third parties; orapproved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates;iii.iv.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.on terms no less favorable to us than those generally being provided to or available from unrelated third parties; oriv.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.We may issue additionaland anyhaving an issue price of less than $100.0 million. As a result, under our Partnership Agreement, we may now issue additional 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)arrears) and without the approval of holders of our common unitholders.•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; andcausing the market price of the common units to decline.56ToAlthough we have not made a distribution on our common units or Series A Preferred Units since we announced suspension of those distributions on May 3, 2020 and do not expect to pay distributions on the common units or Series A Preferred Units in the foreseeable future, 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.upon whichwith like voting rights that 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.•we were conducting business in a state but had not complied with that particular state's partnership statute; oran 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.57accumulateaccumulated and arewere cumulative at the rate of 9.50% per annum of $1,000, the liquidation preference of the Series A Preferred Units and (ii) on and after December 15, 2022, distributions on the Series A Preferred Units will accumulate for each distribution period at a percentage of $1,000 equal to the three-month LIBOR plus a spread of 7.43%. On May 3, 2020, we announced the suspension of distributions payable on both our common units and our Series A Preferred Units. We didhave not makemade a distribution on our common units with respect to any quarter in 2020, nor did we make a distribution on ouror Series A Preferred Units since we announced suspension of those distributions on June 15,May 3, 2020 and do not expect to pay distributions on the common units or December 15, 2020. Series A Preferred Units in the foreseeable future. As of December 31, 2020,2022, the amount of accrued and unpaid distributions on the Series A Preferred Units was $15.8$21.5 million. Unpaid distributions on the Series A Preferred Units will continue to accrue.earlierfirst quarter of June 30, 2022, orwhich is the first full quarter following the date the Double E pipeline isPipeline was placed in service.585.5%2025 Senior Notes or the 2025 Senior2026 Secured Notes co-issued by Summit Holdings and its 100% owned finance subsidiary, Finance Corp.partnerships.59under 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.60We have recent transactions that generated substantial COD income on a per unit basis relative to the trading price of our common units. We may engage in other transactions that result in substantial COD income or other gains in the future, and such events may cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to the unitholder. under the Tax Reform Legislation, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and inincome. In the case of taxable years beginning before January 1, 2022, our adjusted taxable income is computed by taking into account any deduction allowable for depreciation, amortization, or depletion. For our 2020 taxable year, the Coronavirus Aid, Relief, and Economic Security Act increases the 30% adjusted taxable income limitation to 50%, unless we elect not to apply such increase, and for purposes of determining our 50% adjusted taxable income limitation, we may elect to substitute our 2020 adjusted taxable income with our 2019 adjusted taxable income.61Under the Tax Reform Legislation, anAn exempt organization is required to independently compute its UBTI from each separate unrelated trade or business which may prevent an exempt organization from utilizing losses we allocate to the organization against the organization’s UBTI from other sources and vice versa. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and applicable state tax returns and pay tax on their share of our taxable income.UnderTax Reform Legislation,United States on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.However,Under the U.S. Treasury and the IRS have suspended these rules for transfers of certain publicly traded partnership interests, including transfers of our common units, that occur before January 1, 2022. Under recently finalized Treasury Regulations, such withholding will be required on open market transactions, but in the case of a transfer made through a broker, a partner’s share of liabilities will be excluded from the amount realized. In addition, the obligation to withhold will be imposed on the broker instead of the transferee (and we will generally not be required to withhold from the transferee amounts that should have been withheld by the transferee but were not withheld). These withholding obligations will apply to transfers of our common units occurring on or after January 1, 2022.Although aA holder of Series A Preferred Units couldmay recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, and 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.December. 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.626364andover long distances, such as oil and gas pipelines.Our ITThese systems, and networks, as well as those of our customers, vendorsbusiness partners 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 sensitivebreaches. Any such cyber-attacks or proprietary information as well as disrupt our operations, damage our reputation or damage our facilities or those of third parties, whichsecurity breaches could have a material adverse effect on our revenues and increase our operating and capital costs whichand 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. and related infrastructure, or that of our customers, venders andbusiness partners or 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,•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 deliberate corruption of our financial or operational data could result in events of non-compliance, which could lead to regulatory fines or penalties; andbusiness interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation or a negative impact on the price of our units.65under leases to support our operations.Beginning2015, the U.S. Department of Justice (“DOJ”) issued grand jury subpoenas to Summit Investments,state court alleging that the Partnership our General Partnerowes Fiberspar $5.0 million or more for orders of pipeline product from Fiberspar. The petition asserts causes of action for breach of contract and Meadowlark Midstream requesting certain materials relatedsuit on sworn account. A civil action on the same claims had been filed by Fiberspar in 2016 but was dismissed without prejudice pursuant to a standstill and tolling agreement that expired in 2021. We filed an incident involvinganswer on September 6, 2022 denying Fiberspar’s claims and asserting counter claims. The case is pending in the District Court of Harris County, Texas. We are unable to predict the final outcome of this matter. produced water disposal pipeline owned and operated by Meadowlark Midstream, that resulted inwhich at the time was a dischargewholly owned subsidiary of materialsSummit Investments, (together with Meadowlark Midstream, the “Companies”). The Companies entered into the environment (“Meadowlark Rupture”). On June 19, 2015, Meadowlark Midstreamfollowing agreements to resolve the U.S. federal and Summit Investments received a complaint from the North Dakota Industrial Commission seeking approximately $2.5 million in fines and other fees relatedstate governments’ environmental claims against the Companies with respect to the incident. This matter is also under investigation by2015 Blacktail Release: (i) a Consent Decree with (a) the DOJ, on behalf of the U.S. Environmental Protection Agency and the U.S. Department of Interior, and (b) the State of North Dakota, Officeon behalf of the Attorney General, the North Dakota Department of Environmental Quality and the North Dakota Game and Fish Department. The government’s investigation is still ongoing. During this time,Department, lodged with the Partnership has entered into tolling agreementsU.S. District Court; (ii) a Plea Agreement with both the DOJUnited States, by and through the U.S. Attorney for the District of North Dakota, and the Environmental Crimes Section of the DOJ; and (iii) a Consent Agreement with the North Dakota attorney general,Industrial Commission.were most recently extendedwill include payment in full of certain components of the fines and penalty amounts; and (iv) compliance with the remedial measures in the Consent Decree.May 7, 2021. There can be no assurance that these tolling agreements$36.3 million and will be extended. Discussions with the DOJ and other agencies regarding a resolutionpaid over six years, of this matter are ongoing. Liability for this incident could arise under civil and misdemeanor and felony criminal statutes, including under the Clean Water Act. In accordance with GAAP, the Partnership has accrued a $17.0which we have paid $8.0 million loss contingency for this matter as of December 31, 2020. While the Partnership believes a loss for claims and/or actions arising from the Meadowlark Rupture, whether in a negotiated settlement or as a result of litigation, is probable, due to the complexity of resolving the numerous issues surrounding this matter, at this time we cannot reasonably predict whether any actual loss, if incurred, would be materially higher or lower than the accrued amount.The following additional matters are disclosed pursuant to requirements of Item 103 of the SEC’s Regulation S-K. We do not currently believe that the eventual outcome of such matters could have a material adverse effect on our business, financial condition, results of operations or cash flows. A petition was filed in the District Court of Arapahoe County, Colorado, by Samuel Engineering, Inc. against Meadowlark Midstream and Summit Niobrara. The matter was later transferred to the District Court of Denver County, Colorado, where it is currently pending. The plaintiff was a contractor hired to perform engineering, procurement, and construction services for Summit Niobrara’s gas processing plant located in Weld County, Colorado. The plaintiff is seeking damages for alleged non-payment for such services. Separately, a demand for arbitration was filed in Houston, Texas by 2022.against Summit Permian. The claimant(“MCSI”) initiated an arbitration in that matter was a contractor hiredDecember 2020 related to perform engineering, procurement, andthe construction services for Summit Permian’s gas processing plant locatedof Summit’s Lane Gas Processing Plant in Eddy County, New Mexico.Mexico (the “Lane Plant”). MCSI was the EPC contractor on the Lane Plant under a lump sum contract. This matter has been resolved as of the date of this filing with no material impact to the Partnership.claimant isrelief requested by Verdad includes an unspecified amount of damages as well as declaratory relief. We are unable to predict the final outcome of this matter.damages for alleged non-payment for such services.We previously discloseddamages. Highpoint asserted counterclaims alleging that Sterling breached the Highpoint Agreement. In October 2021, after a legal proceeding initiatedbench trial, the court found against Sterling and in favor of Highpoint’s counterclaims. The court awarded Highpoint $2.4 million in damages. In December 2021, Sterling posted an appeal bond and filed its Notice of Appeal. In February 2022, the DistrictColorado Court of Tarrant County, Texas by Sage Natural Resources, LLC against us and certainAppeals granted Sterling’s Motion to Stay Execution of our affiliates. That legal proceeding was terminated byJudgment. The case remains pending before the court’s dismissalappeals court. We are unable to predict the final outcome of the lawsuit with prejudice.66 limited partner common units ticker symbol “SMLP,” trade on the NYSE.NYSE under the ticker symbol “SMLP”. As of December 31, 2020,2022, there were approximately 8,4897,196 common unitholders, including beneficial owners of common units held in street name.On January 29, 2020, the Board of Directors declared a distribution of $0.125 per unit (an amount before giving effect to the Reverse Unit Split) for the quarterly period ended December 31, 2019. The distribution, which totaled $11.7 million, was paid on February 14, 2020, prior to the GP Buy-In Transaction, to unitholders of record at the close of business on February 7, 2020. In May 2020, the Partnership suspended distributions to holders of its common units and its Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. per our tax records.didhave not makemade a distribution on our common units with respect to any quarter in 2020, nor did we make a distribution on ouror Series A Preferred Units since we announced a suspension of those distributions on June 15,May 3, 2020. We paid distributions in-kind on our Subsidiary Series A Preferred Units in 2020, or December 15, 2020.InOn May 3, 2020, the Partnershipwe suspended distributions to holders of itsour common units and suspended payments of distributions to holders of itsour Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. Because our Series A Preferred Units rank senior to our common units with respect to distribution rights, any accrued amounts on our Series A Preferred Units must first be paid prior to our resumption of distributions to our common unitholders. As of December 31, 2020,2022, the amount of accrued and unpaid distributions on the Series A Preferred Units totaled $15.8$21.5 million. the Partnership is unablewe do not expect to forecast when it will resumepay distributions to holders of itsour common units andor Series A Preferred Units.We mayHowever, we do not intend to pay distributions on the common units or Series A Preferred Units in the foreseeable future, and there are restrictions onin the agreements for our ability to pay distributions under our outstanding indebtedness that restrictlimiting our ability to pay cash distributions on any of our equity securities.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.•Series A Preferred Units contain covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions notwithstanding our stated cash distribution policy.67•Our General Partner has the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those cash reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our General Partner in good faith will be binding on our unitholders.•Although our Partnership Agreement requires us to distribute all of our available cash, our Partnership Agreement, including the provisions requiring us to distribute all of our available cash, may be amended. We can amend our Partnership Agreement with the consent of our General Partner and the approval of a majority of the outstanding common units.•Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our General Partner, taking into consideration the terms of our Partnership Agreement.•Under Delaware law, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.•We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase.•If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly distribution rate to service or repay our debt or fund expansion capital expenditures.Preferred Unit Distributions$1,000. During$1,000 per Series A Preferred Unit and as a result of exchange transactions completed in 2020, 2021 and 2022, the year ended December 31, 2020, we exchanged 62,816Partnership had 65,508 Series A Preferred Units for 837,547 SMLP common units and completed a cash tender offer whereby we tendered 75,075 Series A Preferred Units for $25.0 million in cash. Asoutstanding as of December 31, 2020, we have 162,109 Series A Preferred Units outstanding.the Partnershipwe suspended payments of distributions to holders of itsour Series A Preferred Units, and we did not make a distribution on our Series A Preferred Units on June 15, 2020in 2022 or 2021.15, 2020.arewere payable semi-annually in arrears on the 15th day of each June and December through and including December 15, 2022, and, thereafter,after December 15, 2022, are payable 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.iswas 9.50% per annum of the $1,000 liquidation preference per Series A Preferred Unit. On and afterBeginning 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 1312 - Partners' Capital and Mezzanine Capital to the consolidated financial statements for additional details.30,00030,057 and 55,251 Subsidiary Series A Preferred Units, respectively, representing limited partner interests in Permian Holdco at a price of $1,000 per unit. Permian Holdco usedDuring the net proceedsyears ended December 31, 2022 and 2021, we elected to make PIK distributions and issued 1,600 and 6,131 Subsidiary Series A Preferred Units, respectively, to the holders of $48.7the Subsidiary Series A Preferred Units.$27.4accrued an additional $1.6 million respectively, (after deducting offering expenses) to fund capital calls associated with the Double E Project.68Table. Additionally, we paid distributions in-kind on our Subsidiary Series A Preferred Units in 2020, 2021 and portions of Contents2022.hashad the option to pay this distribution in-kind until the earlierfirst quarter of June 30, 2022, orwhich is the first full quarter following the date the Double E pipeline isPipeline was placed in service. See Note 1312 - Partners' Capital and Mezzanine Capital to the consolidated financial statements for additional details.July 2020, the PartnershipJanuary 2022, we completed the Preferred Exchange Offer. The2022 Preferred Exchange Offer, expired on July 28, 2020, and on July 31, 2020, the Partnershipwhereby we issued 837,5472,853,875 SMLP common units, net of units withheld for withholding taxes, in exchange for 62,81677,939 Series A Preferred Units. Upon closing the settlement of the 2022 Preferred Exchange Offer, we eliminated $66.5$92.6 million of the Series A Preferred Unit liquidation preference amount, inclusive of accrued distributions due as of the settlement date. The PartnershipWe did not receive any cash proceeds from the 2022 Preferred Exchange Offer.In May 2020,Partnership closed the GP Buy-In Transaction whereby the Partnership acquired from its then private equity sponsor, ECP, (i) Summit Investments, which owned the Partnership’s General Partner, and (ii) through its indirect ownership of SMP Holdings, 3,415,646 of its common units. Consideration paid to ECP included a $35.0 million cash payment and warrants to purchase up to 666,667 common units.Equity Compensation PlansThe 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.6920202022 should be read in conjunction with the consolidated financial statements and notes thereto included in this Annual Report. Among other things, the consolidated financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in Forward-Looking Statements. Actual results may differ materially from those contained in any forward-looking statements. The discussion of our financial condition and results of operations for the years ended December 31, 2019 and December 31, 2018 included in Exhibit 99.2, Updated 2019 Annual Report on Form 10-K - Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, of our Form 8-K dated August 7, 2020, is incorporated by reference into this MD&A.We classify our midstream energy infrastructure assets into two categories, our Core Focus Areas and our Legacy Areas. Further details on our Focus Areas and Legacy Areas are summarized below.•Core Focus Areas. Core producing areas of basins in which we expect our gathering systems to experience greater long-term growth, driven by our customers’ ability to generate more favorable returns and support sustained drilling and completion activity in varying commodity price environments. In the near-term, we expect to concentrate the majority of our capital expenditures in our Core Focus Areas. Our Utica Shale, Ohio Gathering, Williston Basin, DJ Basin and Permian Basin reportable segments (as described below) comprise our Core Focus Areas.•Legacy Areas. Production basins in which we expect volume throughput on our gathering systems to experience relatively lower long-term growth compared to our Core Focus Areas, given that our customers require relatively higher commodity prices to support drilling and completion activities in these basins. Upstream production served by our gathering systems in our Legacy Areas is generally more mature, as compared to our Core Focus Areas, and the decline rates for volume throughput on our gathering systems in the Legacy Areas are typically lower as a result. We expect to continue to decrease our near-term capital expenditures in these Legacy Areas. Our Piceance Basin, Barnett Shale and Marcellus Shale reportable segments (as described below) comprise our Legacy Areas.Williston Basin,Rockies, Permian and Piceance Basin, and Permian Basin segments, (ii) the sale of natural gas we retain from certain Barnett Shalesegment customers, and (iii) the sale of condensate we retain from our gathering services in the Piceance Basin segment.segment and (iv) additional gathering fees that are tied to the performance of certain commodity price indexes which are then added to the fixed gathering rates. During the year ended December 31, 2020,2022, these additional activities accounted for approximately 13%18% of our total revenues.70"Segment“Segment Overview for the Years Ended December 31, 20202022 and 2019”2021” section herein.Year ended December 31, 2022 2021 (In thousands) Net loss $ (123,461) $ (19,949) Reportable segment adjusted EBITDA Northeast $ 77,046 $ 83,287 Rockies 57,810 64,517 Permian 18,051 6,614 Piceance 60,055 76,131 Barnett 31,624 36,729 Net cash provided by operating activities $ 98,744 $ 165,099 30,472 25,030 Cash consideration paid for the acquisition of Outrigger DJ, net of cash acquired (166,631) — Cash consideration paid for the acquisition of Sterling DJ, net of cash acquired (139,896) — Proceeds from the disposition of the Lane G&P System, net of cash sold in the transaction 75,020 — Proceeds from the disposition of Bison Midstream, net of cash sold in the transaction 38,920 — Investment in Double E equity method investee 8,444 148,699 Net cash provided by (used in) financing activities Borrowings from ABL Facility 293,000 300,000 Repayments of ABL Facility (230,000) (33,000) Repayments of Revolving Credit Facility — (857,000) Repayments of Permian Transmission Term Loan (4,647) — Borrowings from 2026 Secured Notes 84,371 689,500 Borrowings from Permian Transmission Credit Facility — 160,000 Repayment of 2022 Senior Notes — (234,047) 2017 - Segment Information to the consolidated financial statements for additional information on capital expenditures.712020.2022. The following items are reflected in our financial results for the fiscal year ended December 31, 2020:2022:•GP Buy-In Transaction. In May 2020, the Partnership completed the GP Buy-In Transaction whereby the Partnership acquired from its then private equity sponsor, ECP, (i) Summit Investments, which indirectly owned the Partnership’s General Partner, (ii) through its ownership of SMP Holdings, 3,415,646 of its common units and (iii) a deferred purchase price obligation receivable owed by the Partnership. Consideration paid to ECP included a $35.0 million cash payment and warrants to purchase up to 666,667 common units. In connection with the closing of the GP Buy-In Transaction, ECP’s management resigned from the Board of Directors and fully exited its investment in the Partnership (other than retaining the aforementioned warrants). Refer to Note 1 – Organization, Business Operations and Presentation and Consolidation for details.Suspension of common and preferred unit distributions. In May 2020, and in conjunction with the GP Buy-In Transaction, the Partnership suspended distributions to holders of its common units and its Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. The suspension of distributions enabled the Partnership to retain an incremental $76 million per annum of operating cash flow and reallocate this retained cash to indebtedness reduction, liability management transactions and other corporate initiatives. The unpaid cash distributions on the Series A Preferred Units continue to accrue semi-annually, until paid.
As a result of the 2022 DJ Acquisitions, we acquired natural gas gathering and processing systems, a crude oil gathering system, freshwater rights, and a subsurface freshwater delivery system in the DJ Basin. The acquired assets of Outrigger DJ and Sterling DJ are located in Weld, Morgan, and Logan Counties, Colorado and Cheyenne County, Nebraska.•July 2020 Series A Preferred Unit Exchange. In July 2020, the Partnership completed the Preferred Exchange Offer, whereby it issued 837,547 SMLP common units in exchange for 62,816 Series A Preferred Units. Upon closing the Preferred Exchange Offer, it eliminated $66.5 million of the Series A Preferred Unit liquidation preference amount, inclusive of $3.7 million of accrued distributions due as of the settlement date.•Open Market Repurchase of Senior•Financing of 2022 DJ Acquisitions. The 2022 DJ Acquisitions were financed through a combination of cash on hand, borrowings under Summit’s ABL Facility and the issuance of $85.0 million aggregate principal amount of Additional 2026 Secured Notes. Throughout 2020, the Partnership completed its Open Market Repurchases, which resulted in the extinguishment of $32.4 million of face value of the 2022 Senior Notes and $201.8 million of face value of the 2025 Senior Notes. Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 Senior Notes and 2025 Senior Notes, plus accrued interest totaled $150.3 million and the Partnership recognized a $86.4 million gain on the extinguishment of debt related to these Open Market Repurchases during 2020.Debt Tender Offers. In September 2020, the Co-Issuers completed the Debt Tender Offers to purchase a portion of their 2022 Senior Notes and 2025 Senior Notes. Upon completion of the Debt Tender Offers, the Co-Issuers repurchased $33.5 million principal amount of the 2022 Senior Notes and $38.7 million principal amount of the 2025 Senior Notes. Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 and 2025 Senior Notes, plus accrued interest, totaled $48.7 million, and the Partnership recognized a $23.3 million gain on the extinguishment of debt related to the Debt Tender Offers during 2020.TL Restructuring. In November 2020, the Partnership completed the TL Restructuring. All of the Term Loan Lenders participated in the TL Restructuring. As part of the TL Restructuring, the Partnership paid SMP Holdings $26.5 million in cash as consideration to fully settle the deferred purchase price obligation, which SMP Holdings then paid to the Term Loan Lenders. In addition, the Term Loan Lenders executed the Strict Foreclosure on the 2,306,972 common units pledged as collateral under the SMPH Term Loan in full satisfaction of SMP Holdings’ outstanding obligations under the SMPH Term Loan.•December 2020 Series A Preferred Unit Tender. On December 29, 2020, the Partnership completed the Preferred Tender Offer, whereby it accepted 75,075 Series A Preferred Units for a purchase price of $333.00 per Series A Preferred Unit and an aggregate purchase price of $25.0 million. Upon closing the Preferred Tender Offer, it eliminated $82.7 million of the Series A Preferred Unit liquidation preference due as of the settlement date, inclusive of $7.6 million of accrued distributions.•Double E Project. For the year ended December 2020, the Partnership’s proportionate share of capital calls due in 2020 totaled $99.9 million, which includes $2.7 million in capitalized interest, and was funded with $20.6 million of Partnership generated funds and the issuance of $85.3 million of Subsidiary Series A Preferred Units.•2020 Restructuring Costs. In the fourth quarter of 2020, we completed an internal initiative to evaluate and transform our cost structure, enhance margins and improve our competitive position in response to COVID-19 and the related weakening of the economy. For the year ended December 31, 2020, we incurred approximately $5.6 million in restructuring costs relating to this initiative (included in general and administrative expense).72•2020 Impairments. In the fourth quarter of 2020, we recorded $8.6 million of impairments related to certain long-lived assets, of which $5.1 million related to a January 2021 sale of compressor equipment for a total cash purchase price of $8.0 million.2019.2021. The following items are reflected in our financial results for the fiscal year ended 2019:2021:•Equity Method Investment Impairment. In December 2019, we identified certain triggering events which indicated that our equity method investment in Ohio Gathering could be impaired. We completed an other-than-temporary impairment analysis to determine the potential equity method impairment charge to be recorded on our consolidated financial statements. As a result, an impairment charge of approximately $329.7 million was recorded in the loss from equity method investees caption on the consolidated statement of operations.Goodwill Impairment. In September 2019, in connection with our annual impairment evaluation, we determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value and we recognized a goodwill impairment charge of $16.2 million.Disposition. In March 2019, we identified certain triggering events which indicated that certain long-lived assets in the DJ Basin and Barnett Shale reporting segments could be impaired. Consequently, we performed a recoverability assessment of certain assets within these reporting segments. In the DJ Basin, we determined certain processing plant assets related to our 20 MMcf/d plant would no longer be operational due to our expansion plans for the Niobrara G&P system and we recorded an impairment charge of $34.7 million related to these assets. In the Barnett Shale, we determined certain compressor station assets would be shut down and de-commissioned and we recorded an impairment charge of $9.7 million related to these assets.Double E Project. In June 2019, we continued development of the Double E Project after securing firm 10-year commitments under binding precedent agreements for a substantial majority of the pipeline’s initial throughput capacity of 1.35 Bcf of gas per day and executing the joint venture agreement (described below) with an affiliate of Double E’s foundation shipper. The Double E Project, which consists of an approximately 116-mile mainline and related facilities, will provide interstate natural gas transportation service from the Delaware Basin production area to the Waha Hub in Texas.Summit Permian Transmission. In connection with the Double E Project, Summit Permian Transmission contributed total assets of approximately $23.6 million for a 70% ownership interest in Double E. Concurrent with this contribution, Double E distributed $7.3 million to the Partnership.•Double E Financing. In December 2019, as part of our financing for the Double E Project, we formed Permian Holdco, a newly created, unrestricted subsidiary of SMLP that indirectly owns SMLP’s 70% interest in Double E. In connection with the formation of Permian Holdco, we entered into an agreement with TPG Energy Solutions Anthem, L.P. (“TPG”) on December 24, 2019 to fund up to $80 million of Permian Holdco’s future capital calls associated with the Double E Project. Simultaneously, on December 24, 2019, Permian Holdco issued 30,000 Subsidiary Series A Preferred Units to TPG for net proceeds of $27.4 million.•Red Rock. In December 2019, Red Rock Gathering and certain affiliates of SMLP (collectively, “the Red Rock Parties”) entered into a Purchase and Sale Agreement (the “Red Rock PSA”) pursuant to which the Red Rock Parties agreed to sell certain Red Rock Gathering system assets for a cash purchase price of $12.0 million (the “Red Rock Sale”). Prior to closing, we recorded an impairment charge of $14.2 million based on the expected consideration and the carrying value for the Red Rock Gathering system assets. On December 2, 2019, we closed the Red Rock Sale. The impairment is included in the Long-lived asset impairment caption on the consolidated statement of operations. The financial contribution of these assets (a component of the Piceance Basin reportable segment) are included in our consolidated financial statements and footnotes for the period from January 1, 2019 through December 1, 2019.•Tioga Midstream. Until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system in the Williston Basin. On March 22, 2019, we sold the Tioga Midstream system to affiliates of Hess Infrastructure Partners LP for a combined cash purchase price of approximately $90 million and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the carrying value for Tioga Midstream at closing. The gain is included in the Gain on asset sales, net caption on the consolidated statement of operations. The financial results of Tioga Midstream (a component of the Williston Basin reportable segment) are included in our consolidated financial statements and footnotes for the historical periods through March 22, 2019. Refer to Note 18 to the consolidated financial statements for details on the sale of Tioga Midstream.73•2019 Restructuring Costs. In the third quarter of 2019, we began an internal initiative to evaluate and transform our cost structure, enhance margins and improve our competitive position in response to a weakening commodity price backdrop. For the year ended December 31, 2019, we incurred approximately $5.0 million in restructuring costs relating to this initiative (included in general and administrative expense). For the year ended December 31, 2020, we incurred an additional $3.5 million related to this initiative.•Ongoing impact of the COVID-19 pandemic and reduced demand and prices for oil;Natural gas, NGL and crude oil supply and demand dynamics;Production from U.S. shale plays;Capital markets availability and cost of capital; andShifts in operating costs and inflation.reducedfluctuations in demand for oil and prices for oil. natural gas. We arecontinue to closely monitoringmonitor the impact of the outbreak of COVID-19 pandemic, including its variants, on all aspects of our business, including how it has impacted and will impact our customers, employees, supply chain and distribution network. We are unable to predict the ultimate impact that COVID-19 and related factors may have on our business, future results of operations, financial position or cash flows. Given the dynamic nature of the COVID-19 pandemic and related market conditions, we cannot reasonably estimate the period of time that these events will persist or the full extent of the impact they will have on our business. The extent to which our operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including changes in the severity of the pandemic, countermeasures taken by governments, businesses and individuals to slow the spread of the pandemic, and the development and availability of treatments and vaccines and the extent to which these treatments and vaccines may remain effective as potential new strains of the coronavirus emerge. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown. have modified our business practices, including restricting employee travel modifying employee work locations, implementing social distancing and enhancing sanitary measuresutilizing COVID-19 pandemic tax relief in our facilities. Many of our suppliers, vendors and service providers have made similar modifications. The resources available to employees working remotely may not enable them to maintain the same level of productivity and efficiency, and these and other employees may face additional demands on their time. Our increased reliance on remote access to our information systems increases our exposure to potential cybersecurity breaches. We may take further actions as government authorities require or recommend or as we determine to be in the best interests of our employees, customers, partners and suppliers. There is no certainty that such measures will be sufficient to mitigate the risks posed2021 (as allowed by the virus, in which case our employees may become sick, our ability to perform critical functions could be impaired, and we may be unable to respond toConsolidated Appropriations Act, 2021, the needs of our business. The resumption of normal business operations after such interruptions may be delayed or constrained by lingering effects of COVID-19 on our suppliers, third-party service providers, and/or customers.In addition to the significant reduction in global demand for oil and natural gas caused by the economic effects of the COVID-19 pandemic, there were also volatile oil prices during 2020 largely due to a supply and demand imbalance and actions by members of OPEC and other foreign, oil-exporting countries. This disrupted the oil and natural gas exploration and production industry and other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. Over the past several months, we have collaborated extensively with our customer base regarding production reductions and delays to drilling and completion activities in light of the current commodity price backdrop and COVID-19 pandemic. Given74Table of Contents"ERC Tax Credit").continued volatility in market conditions since March 2020, and based20212023 development plans from our customers, we currently expect that 2023 activity will be higher than 2022 and be at an activity level near our 2021 resultshistorical periods prior to be affected by decreased drilling activity.COVID-19.decreasedincreased by approximately 21%66% from 20202021 to 2019,2022, primarily due to natural gas supplydemand exceeding demand.supply. The average daily Henry Hub Natural Gas Spot Price was $2.03$6.45 per MMBtu during 2020,2022, compared with $2.56$3.89 per MMBtu during 2019. Henry Hub closed at $2.36 per MMBtu on December 31, 2020.2021. As of February 18, 2021,January 31, 2023, Henry Hub 12-month strip pricing closed at $3.11$3.41 per MMBtu. Natural gas prices continue to trade at lower-than-averagehigher-than-average historical prices due in part to increasedstrong power sector demand and relatively modest new production growth. In response to the increasing natural gas production and an elevated levelprices, the number of active natural gas in storagedrilling rigs in the continental United States. TheStates increased from 106 in December 2021 to 156 in December 2022, but still remains below the 2017 through 2019 average amount of working natural gas in underground storage in the continental U.S. was 3.05 Tcfe in 2020, which was 23.4% higher than in 2019. In the near term, we believe that until the supply of natural gas in storage has been reduced, natural gas prices are likely177, according to remain constrained.Baker Hughes. 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,generation and increase in U.S. LNG exports. Over the next several years, we expect natural gas prices will support continued upstream industry activity by producers focused on natural gas production. In addition, certain of our gathering systems are directly affected by crude oil supply and demand dynamics. Crude oil prices decreased in 2020, with the average daily Cushing, Oklahoma West Texas Intermediate crude oil spot price decreasing from an average $56.99 per barrel during 2019 to an average of $39.16 per barrel during 2020, representing a 31.3% decrease, reflecting broader market concerns for global oil supply and demand dynamics. In response to the general decrease in crude oil prices, the number of active crude oil drilling rigs in the continental United States decreased from 677 in December 2019 to 267 in December 2020, according to Baker Hughes. Over the next several years, we expect that crude oil prices will support continued drilling activity and increasing production in the Williston Basin, Permian Basin and, given the current regulatory environment in Colorado, in rural parts of the DJ Basin. 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 weoperate. We believe that these long-term capital investments willshould support drilling activity in unconventional shale plays over the long term.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 and equity capital markets to the extent necessary, to fund our future growth. Furthermore, market demand for equity issued by master limited partnerships has been significantly lower in recent years than it has been historically, which may make it more challenging for us to finance our capital expenditures with the issuance of additional equity. We announced the elimination of our common unit distribution in May 2020 beginning with the distribution paid in respect of the secondfirst quarter of 2020, and this action may further reduce demand for our common units. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly.75TableThe borrowings under our ABL Facility, which have a variable interest rate, expose us to the risk of Contentsincreasing interest rates.ShiftsAdditionally, as a result of the 2022 DJ Acquisitions, we utilized our free cash flow generated in 2022 to partially fund the 2022 DJ Acquisitions. As such we will not make an offer to purchase the $50.0 million amount of our 2026 Secured Notes to avoid a 50 basis point increase in the interest rate on the 2026 Secured Notes, resulting in increased annual interest expense of approximately $3.9 million.inflation.the overall cost of capital projects we undertake. Throughout mostWhile some 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 toour fee arrangements escalate based on changes in the prevailing price of crude oilindexes, these fee escalations may not be sufficient to offset an increase in our expenditures. Furthermore, inflation may impact producers economic decision making, which in turn could impact their willingness to develop acreage in areas that are more susceptible to inflationary pressures and natural gas.labor force shortages.76eightfive reportable segments: Utica Shale, Ohio Gathering, Williston Basin, DJ Basin,Northeast, Rockies, Permian, Basin, Piceance Basin, Barnett Shale, and Marcellus Shale.Barnett. Each of our reportable segments provides midstream services in a specific geographic area and our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations (see Note 2017 - Segment Information to the consolidated financial statements). Our management uses a variety of financial and operational metrics to analyze our consolidated and segment performance and we view these metrics as important factors in evaluating our profitability. These metrics include (i) throughput volume, (ii) revenues, (iii) operation and maintenance expenses, (iv) capital expenditures and (iv)(v) segment adjusted EBITDA.•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; andour ability to gather, treat and/or process production that has been released from commitments with our competitors.77•the ability of our assets to generate cash sufficient to make cash distributions and support our indebtedness;the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure;the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities; and•the financial performance of our assets without regard to (i) income or loss from equity method investees, (ii) the impact of the timing of MVC shortfall payments under our gathering agreements or (iii) the timing of impairments or other noncash income or expense items."Results“Results of Operations"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 reportedstatements contained in future periods, see Note 2 to the consolidated financial statements.Item 8. Financial Statements and Supplementary Data.7820202022 and 201920202022 and 2019.2021.Year ended December 31, 2022 2021 Percentage change (In thousands) Revenues: Gathering services and related fees $ 248,358 $ 281,705 (12%) Natural gas, NGLs and condensate sales 86,225 82,768 4% Other revenues 35,011 36,145 (3%) Total revenues 369,594 400,618 (8%) Costs and expenses: Cost of natural gas and NGLs 76,826 81,969 (6%) Operation and maintenance 84,152 74,178 13% General and administrative 44,943 58,166 (23%) Depreciation and amortization 119,055 119,076 —% Transaction costs 6,968 1,677 316% Gain on asset sales, net (507) (369) 37% Long-lived asset impairment 91,644 10,151 803% Total costs and expenses 423,081 344,848 23% Other expense, net (4) (613) * Gain on interest rate swaps 16,414 — Loss on sale of business (1,741) — Loss on ECP Warrants — (13,634) N/A Interest expense (102,459) (66,156) 55% Loss on early extinguishment of debt — (3,523) * Loss before income taxes and equity method investment income (141,277) (28,156) * Income tax (expense) benefit (325) 327 * Income from equity method investees 18,141 7,880 * Net loss $ (123,461) $ (19,949) * Aggregate average daily throughput - natural gas (MMcf/d) 1,208 1,356 (11%) Aggregate average daily throughput - liquids (Mbbl/d) 62 63 (2%) Exclusive ofExcludes volume throughput for Ohio Gathering.Gathering and Double E. For additional information, see the "Ohio Gathering" section herein.22148 MMcf/d for the year ended December 31, 20202022 compared to the year ended December 31, 2019,2021, primarily reflecting:•a volume throughput increase of 5 MMcf/d for the Marcellus Shale segment.•a volume throughput decrease of 88 MMcf/d for the Piceance Basin•a volume throughput decrease of 113 MMcf/d for the Northeast segment.•a volume throughput increase of 85 MMcf/d for the Utica Shale•a volume throughput decrease of 20 MMcf/d for the Piceance segment.•a volume throughput increase of 14•a volume throughput decrease of 12 MMcf/d for the Permian Basin segment.•a volume throughput decrease of 39 MMcf/d for the Barnett Shale segment.volumes atfor the WillistonRockies segment decreased 261 Mbbl/d for the year ended December 31, 20202022 compared to the year ended December 31, 2019.2021, primarily as a result of natural production declines and weather related downtime, offset by 39 new well connections that came online subsequent to December 31, 2021."Segment“Segment Overview for the Years Ended December 31, 20202022 and 2019"2021” section herein.79$60.1$31.0 million during the year ended December 31, 20202022 compared to the prior year primarilyended December 31, 2021 comprised of a $24.0$3.5 million increase in natural gas, NGLs and condensate sales, offset by a $1.1 million decrease in Other revenues, and a $33.3 million decrease in gathering services and related fees and a $37.7 million decrease in natural gas, NGLs and condensate sales.fees.$24.0$33.3 million compared to the year ended December 31, 2019,2021, primarily reflecting:•a $7.2•a $14.6 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting $7.5 million in lower gas gathering revenue attributable to a MVC with a customer in 2019 that expired in 2020.•a $14.7 million decrease in gathering services and related fees in the Piceance, Basin relating to lower volume throughput due to a lack of drilling and completion activity and natural production declines.•a $4.6 million increase in gathering services and related fees in the Utica Shale primarily due to the completion of new wells throughout 2019, and in 2020, and a more favorable volume and gathering rate mix from customers, partially offset by natural production declines from existing wells.•a $18.4 million decrease in gathering services and related fees in the Williston Basin primarily reflecting a decrease in gathering services and related fees attributable to the sale of the Tioga Midstream system on March 22, 2019, whose 2019 financial results are included for the period from January 1, 2019 through March 22, 2019 as well as lower liquids volume throughput, partially offset by the completion of new wells through 2019 and 2020.•a $1.9 million increase in gathering services and related fees in the DJ Basin primarily as a result of ongoing drilling and completion activity across our service area, a more favorable volume and gathering rate mix from customers and the commissioning of our new natural gas processing plant in June 2019, partially offset by natural production declines and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic.•a $6.5 million increase in gathering services and related fees in the Permian Basin primarily as a result of an uptick in customer volumes, partially offset by natural production declines from wells previously put in service.Costs and expenses. Total costs and expenses decreased $76.6 million during the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily reflecting:•a $31.2 million decrease in long-lived asset impairments in the DJ Basin in 2019.•a $16.2 million decrease in goodwill impairment charge relating to the Mountaineer Midstream system in the Marcellus Basin in 2019.•a $14.2 million decrease in long-lived asset impairments relating to the sale of certain Red Rock Gathering system assets in the Piceance Basin in 2019.Cost of natural gas and NGLs. Cost of natural gas and NGLs decreased $26.8 million during the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily driven by lower natural gas, NGL and crude oil marketing activity.Operation and maintenance. Operation and maintenance expense decreased $12.7 million for the year ended December 31, 2020 compared to the year ended December 31, 2019.Depreciation and amortization. The increase in depreciation and amortization expense during 2020 compared to the year ended December 31, 2019 was primarily due to the assets placed into serviceexpiration of approximately $10.1 million of a customer’s minimum volume commitment and decreased volume throughput;Basin.Interest Expense. The decrease in interest expense in the year ended December 31, 2020 compared to the year ended December 31, 2019, was primarily a result of our liability management initiatives which included our Open Market Repurchases and Tender Offers, partially offset by a higher outstanding balance on the Revolving Credit Facility.Gain on early extinguishment of debt. The $203.1 million gain on the early extinguishment of debt is primarily related to liability management initiatives undertaken during 2020 that resulted in a $86.4 million gain from the Open Market Repurchases, a $23.3 million gain from the Debt Tender Offers, and a $93.9 million gain from our TL Restructuring. Further details of our liability management results are summarized below.8081Segment Overview for the Years Ended December 31, 2020 and 2019Utica Shale. The Utica Shale reportable segment includes the Summit Utica system. Volume throughput for our Summit Utica system follows.Volume throughput increased compared to the year ended December 31, 2020 primarily due to new wells that came onlinethe disposition of the Lane G&P System in the fourth quarter of 2019June 2022.through the first three quarters of 2020. In addition, volume throughput was impacted by an increase in temporary production curtailments, completion activityCondensate Sales. Natural gas, NGLs and other operational downtime associated with customers on existing pad sites.Financial data for our Utica Shale reportable segment follows.* Not considered meaningfulYear ended December 31, 2020. Segment adjusted EBITDAcondensate sales revenue increased $3.5 million compared to the year ended December 31, 2019,2021, primarily reflecting:volume throughput previously discussed.Ohio Gathering.2022 DJ Acquisitions, partially offset by the disposition of Bison Midstream; The Ohio Gathering•$1.6 million increase in the Piceance reportable segment;includes OGCprimarily due to the disposition of the Lane G&P System in June 2022.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 usexpenses. Total costs and expenses increased $78.2 million during the reporting period.Gross volume throughput for Ohio Gathering, based on a one-month lag follows.* Not considered meaningfulVolume throughput for the Ohio Gathering system in 2020 decreasedyear ended December 31, 2022 compared to the year ended December 31, 20192021, primarily reflecting:natural production declines on existing wells on the system, fewer well connections, temporary production shut-ins2021 recognition of $10.2 million of certain commercial settlement benefits and wasthe ERC Tax Credit that were not repeated in 2022.completion of new wells.82Financial data for our Ohio Gathering reportable segment, based on a one-month lag follows.Yearfiscal year ended December 31, 20202022 (see Note 10 - Commitments and Contingencies for additional information).Segment adjusted EBITDALoss on ECP Warrants. On August 5, 2021, the ECP Entities cashlessly exercised all of its ECP Warrants for equity method investees decreased $8.1an aggregate of 414,447 SMLP common units, net of the exercise price. During the year ended December 31, 2021, the Partnership recognized a $13.6 million non-cash loss related to the ECP Warrants. There was no comparable non-cash loss during the year ended December 31, 2022.2019,2021 primarily relateddue to lower volume throughput described above.higher interest costs resulting from the higher interest rate resulting from the issuance of the 2026 Secured Notes and borrowings on the Permian Transmission Term Loan, higher amortization expense of debt issuance costs, partially offset by principal reduction payments to our credit facilities (ABL Facility and Revolving Credit Facility) prior to the completion of the 2022 DJ Acquisitions which occurred on December 1, 2022.83Williston Basin reportable segment. Years Ended December 31, 2022 and 2021our Williston Basinthe Northeast reportable segment follows.Northeast Year ended December 31, 2022 2021 Percentage
ChangeAverage daily throughput (MMcf/d) 652 765 (15)% Average daily throughput (MMcf/d) (Ohio Gathering) 674 526 28% Natural gas. Natural gas volumein 2020 increasedfor the Northeast, excluding Ohio Gathering, decreased 15% compared to the year ended December 31, 2019,2021 primarily reflectingdue to natural production declines as well as maintenance related downtime and frac-protect activities that occurred during the completion of newthree months ended June 30, 2022, partially offset by 13 well connections, including 4 wells directly connected to the Summit Utica system and 9 wells behind our TPL-7 connection, that came online during the Bison Midstreamyear ended December 31, 2022.inincreased 28% compared to the fourth quarteryear ended December 31, 2021, primarily as a result of 2019 and through 202028 new well connections that came online during the year ended December 31, 2022, partially offset by natural production declines and frac-protect activities that occurred during the sale of Tioga Midstream.Liquids. Liquids volume throughput in 2020 decreased compared to the yearthree months ended December 31, 2019, primarily associated with natural production declines, deferral of completion activities, shut-ins and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic, partially offset by the completion of new wells throughout 2019 and 2020.Williston BasinNortheast reportable segment follows.Northeast Year ended December 31, 2022 2021 Percentage
ChangeRevenues: (Dollars in thousands) Gathering services and related fees $ 54,392 $ 62,567 (13)% Total revenues 54,392 62,567 (13)% Costs and expenses: Operation and maintenance 7,097 5,672 25% General and administrative 831 599 39% Depreciation and amortization 17,501 17,054 3% Gain on asset sales, net (10) (92) (89)% Long-lived asset impairment — 130 N/A Total costs and expenses 25,419 23,363 9% Add: Depreciation and amortization 17,501 17,054 Adjustments related to capital reimbursement activity (81) (83) Gain on asset sales, net (10) (92) Long-lived asset impairment — 130 Proportional adjusted EBITDA for Ohio Gathering Proportional adjusted EBITDA for Ohio Gathering 30,656 27,074 Other Other 7 — Segment adjusted EBITDA $ 77,046 $ 83,287 (7%) 20202022. Segment adjusted EBITDA decreased $17.4$6.2 million compared to the year ended December 31, 20192021, primarily associated with the decreased liquid volume throughput described above,as a result of revenue decreases from gathering services and the sale of Tioga Midstream in March of 2019. The decrease wasrelated fees, partially offset by the increased natural gas volume throughput described above.a $3.6 million increase in proportional adjusted EBITDA for Ohio Gathering.84DJ BasinRockies reportable segment follows.Rockies Year ended December 31, 2022 2021 Percentage Change Aggregate average daily throughput - natural gas (MMcf/d) 33 35 (6)% Aggregate average daily throughput - liquids (Mbbl/d) 62 63 (2)% Volume. Natural gas volume throughput in 20202022 decreased 6% compared to the year ended December 31, 2019,2021, primarily as a resultreflecting the sale of Bison Midstream in September 2022 and the 2022 DJ Acquisitions in December 2022. Volumes were also impacted by natural production declines shut-ins and fewerweather related downtime that occurred during the three months ended June 30, 2022 and December 31, 2022, partially offset by 22 new well connection through 2020.DJ BasinRockies reportable segment follows.Rockies Year ended December 31, 2022 2021 Percentage Change (Dollars in thousands) Revenues: Gathering services and related fees $ 67,838 $ 74,823 (9%) Natural gas, NGLs and condensate sales 59,208 48,279 23% Other revenues 16,557 21,985 (25%) Total revenues 143,603 145,087 (1%) Costs and expenses: Cost of natural gas and NGLs 52,749 47,984 10% Operation and maintenance 30,260 29,251 3% General and administrative 2,541 1,506 69% Depreciation and amortization 30,532 29,513 3% Gain on asset sales, net Gain on asset sales, net (63) (56) 13% Long-lived asset impairment 7,068 5,564 27% Total costs and expenses 123,087 113,762 8% Add: Depreciation and amortization 30,532 29,513 (431) (1,885) Gain on asset sales, net Gain on asset sales, net (63) (56) Long-lived asset impairment 7,068 5,564 Other Other 188 56 Segment adjusted EBITDA $ 57,810 $ 64,517 (10%) 20202022. Segment adjusted EBITDA increased $0.8decreased $6.7 million compared to the year ended December 31, 2019,2021 primarily associated withdue to lower volume throughput on our natural gas system in the DJ Basin, the expiration of a more favorablecustomer’s minimum volume commitment contract of approximately $2.0 million in the DJ Basin and gathering rate mix from customers.85Summit Permian system provides our midstream services forBison Midstream sale closed in September 2022 and the Permian Basin reportable segment. 2022 DJ Acquisitions were completed on December 1, 2022 which generally resulted in a net neutral impact to Adjusted EBITDA.Basin reportable segment follows.Permian Year ended December 31, 2022 2021 Percentage Change Average daily throughput (MMcf/d) 14 26 (46%) Average daily throughput (MMcf/d) (Double E) 277 124 n/a in 2020 increased compared tofor the year ended December 31, 2019, primarily2022 averaged 277 MMcf per day as a resultcompared to 124 MMcf per day for the period from the date of new well connectionscommencement in November 2021 through December 31, 2021.fourth quarterMVC quantities that Double E’s shippers have contracted to with firm transportation service agreements and related negotiated rate agreements: Weighted average MVC quantities for the year ended December 31, (MMBTU/day) 2022 612,123 2023 831,096 2024 989,507 2025 1,000,000 2026 1,000,178 2027 1,000,000 2028 1,002,562 2029 1,000,000 2030 1,000,000 2031 879,452 Basin reportable segment follows.Permian Year ended December 31, 2022 2021 Percentage
Change(Dollars in thousands) Revenues: Gathering services and related fees $ 3,668 $ 8,230 (55%) Natural gas, NGLs and condensate sales 17,382 28,727 (39%) Other revenues 4,101 3,891 5% Total revenues 25,151 40,848 (38%) Costs and expenses: Cost of natural gas and NGLs 18,007 29,855 (40%) Operation and maintenance 3,082 5,585 (45%) General and administrative 708 757 (6%) Depreciation and amortization 2,736 5,858 (53%) Gain on asset sales, net (13) — Long-lived asset impairment 84,516 595 14104% Total costs and expenses 109,036 42,650 156% Add: Depreciation and amortization 2,736 5,858 (63) — Gain on asset sales, net (13) — Long-lived asset impairment 84,516 595 Proportional adjusted EBITDA for Double E Proportional adjusted EBITDA for Double E 14,762 1,948 Other Other (2) 15 Segment adjusted EBITDA $ 18,051 $ 6,614 * 20202022. Segment adjusted EBITDA increased $5.3$11.4 million compared to the year ended December 31, 2019,2021 primarily as a result of higher volumes throughput described above.86Basin reportable segment follows.Piceance Year ended December 31, 2022 2021 Percentage Change Aggregate average daily throughput (MMcf/d) 306 326 (6%) 20202022 compared to the year ended December 31, 2019,2021, as a result of natural production declines.Basin reportable segment follows.Piceance Year ended December 31, 2022 2021 Percentage
Change(Dollars in thousands) Revenues: Gathering services and related fees $ 80,630 $ 95,235 (15%) Natural gas, NGLs and condensate sales 7,111 5,464 30% Other revenues 5,608 4,786 17% Total revenues 93,349 105,485 (12%) Costs and expenses: Cost of natural gas and NGLs 4,805 3,823 26% Operation and maintenance 23,523 21,664 9% General and administrative 1,280 1,163 10% Depreciation and amortization 51,352 48,773 5% (Gain) loss on asset sales, net (311) (119) 161% Long-lived asset impairment — 3,239 * Total costs and expenses 80,649 78,543 3% Add: Depreciation and amortization 51,352 48,773 Adjustments related to capital reimbursement activity (4,141) (3,271) (Gain) loss on asset sales, net (311) (119) Long-lived asset impairment — 3,239 Other Other 455 567 Segment adjusted EBITDA $ 60,055 $ 76,131 (21%) 20202022. Segment adjusted EBITDA decreased $9.9$16.1 million compared to the year ended December 31, 2019,2021, primarily associated withreflecting the expiration of a customer’s minimum volume throughput decrease described above,commitment contract of approximately $10.1 million in 2021 and a decrease in operations and maintenance expense primarily due to lower compensation expense associated with lower headcount from our cost cutting initiatives.87Shale reportable segment follows.Barnett Year ended December 31, 2022 2021 Percentage Change Average daily throughput (MMcf/d) 203 204 0% decreasedremained consistent in 2020during the year ended December 31, 2022 compared to the year ended December 31, 2019 reflecting2021 primarily related to 12 new well connections in 2022, which were offset by natural production declines partially offset by new volumes from well recompletion and workover activity throughout 2020.Shale reportable segment follows.Barnett Year ended December 31, 2022 2021 Percentage
Change(Dollars in thousands) Revenues: Gathering services and related fees $ 41,830 $ 40,850 2% Natural gas, NGLs and condensate sales 2,503 298 740% 7,763 5,443 43% Total revenues 52,096 46,591 12% Costs and expenses: Operation and maintenance 18,792 8,497 121% General and administrative 1,301 972 34% Depreciation and amortization 15,178 15,195 0% Gain on asset sales, net (85) (101) (16%) Long-lived asset impairment 60 622 (90%) Total costs and expenses 35,246 25,185 40% Add: 16,116 16,133 Adjustments related to capital reimbursement activity (1,322) (1,331) Gain on asset sales, net (85) (101) Long-lived asset impairment 60 622 Other Other 5 — Segment adjusted EBITDA $ 31,624 $ 36,729 (14%) 20202022. Segment adjusted EBITDA decreased $10.9$5.1 million compared to the year ended December 31, 20192021 primarily related toas a result of higher general operating expenses in 2022 that resulted from the decreased volume throughput described above.88Volume throughput increased in 2020 compared to the year ended December 31, 2019, primarily due to new well connection in the third quarter of 2020, partially offset by natural production declines.Financial data for our Marcellus Shale reportable segment follows.*Not considered meaningfulYear ended December 31, 2020. Segment adjusted EBITDA increased $2.0 million compared to the year ended December 31, 2019, primarily associated with the increased volume throughput described above.8920202022 and 2019Corporate and Other Year ended December 31, 2022 2021 Percentage
Change(Dollars in thousands) Revenues: Total revenues $ 1,003 $ 40 * Costs and expenses: General and administrative 38,282 53,169 (28%) Transaction costs 6,968 1,677 316% Interest expense 102,459 66,156 55% Gain on asset sales or disposals (26) — * Gain on early extinguishment of debt — (3,523) * Total Revenues. Total revenues attributable to Corporate and Other was due to gathering services, natural gas, and condensate sales. The decrease of $25.0 million compared to the year ended December 31, 2019 was primarily attributable to the wind down of our marketing group in 2020 as well as lower natural gas activity.Cost of Natural Gas and NGLs. Cost of natural gas and NGLs attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services in 2019. The decrease of $26.1 million compared to the year ended December 31, 2019 was attributable to the wind down of our marketing group in 2020.increaseddecreased by $16.5 million, primarily related to a $17.0 million loss contingency accrual in 2020, see note 11 of the consolidated financial statements for additional information.Transaction costs. Transaction costs recognized during the year ended December 31, 2020 are primarily related to costs associated with our liability management initiatives.Interest Expense. Interest expense decreased $13.1$14.9 million compared to the year ended December 31, 20192021, primarily asrelated to the nonrecurrence of a result$22.4 million loss recognized in 2021 (for the 2015 Blacktail Release), $1.0 million of our liability management initiatives which included our Open Market Repurchases and Tender Offers,an ERC Tax Credit benefit during the year ended December 31, 2021, that did not occur during the year ended December 31, 2022, partially offset by a$2.5 million of employee severance costs incurred during the year ended December 31, 2022. (see Note 10 - Commitments and Contingencies for additional information regarding the 2015 Blacktail Release).outstanding balanceinterest costs resulting from the higher interest rate resulting from the issuance of the 2026 Secured Notes and borrowings on the Permian Transmission Term Loan, higher amortization expense of debt issuance costs, partially offset by principal reduction payments to our credit facilities (ABL Facility and Revolving Credit Facility.GainFacility) prior to the completion of the 2022 DJ Acquisitions which occurred on Early ExtinguishmentDecember 1, 2022.DebtContents. The gain on the early extinguishment of debt is primarily related to liability management initiatives undertaken during 2020 that resulted in a $86.4 million gain from the Open Market Repurchases, a $23.3 million gain from the Debt Tender Offers, and a $93.9 million gain from our TL Restructuring.dependrely primarily on fundsinternally generated cash flow as well as external financing sources, including our ABL Facility and the issuance of debt, equity and preferred equity securities, and proceeds from potential asset divestitures to fund our investments. We believe that our ABL Facility and Permian Transmission Credit Facility, together with internally generated cash flow and access to debt or equity capital markets, will be adequate to finance our operations for the next twelve months without adversely impacting our Revolvingliquidity.cashliquidity or availability of our capital resources.cash equivalents balance, and capital marketsSecurity Agreement, dated as our primary sources of liquidity. Looking forward toNovember 2, 2021 we will seek to reduce indebtedness and extend our indebtedness maturities. As a result, we expect to fund future expenditures from cash generated by our operations, our Revolving Credit Facility, our cash equivalents on hand. If optimal, we may also consider accessing the capital markets, opportunistic divestitures or joint ventures involving our existing midstream assets.DebtRevolving Credit Facility. We have a $1.1 billion senior secured Revolving Credit Facility(the “ABL Agreement”), with a maturity date of May 2022 (see Note 91, 2026. The maturity date of the ABL Facility will spring forward to December 13, 2024 if the consolidated financial statements)outstanding amount of the 2025 Senior Notes on such date equals or exceeds $50.0 million or to January 14, 2025 if any amount of the 2025 Senior Notes is outstanding on such date and Liquidity (as defined in the ABL Agreement) is less than the sum of the outstanding principal amount of the 2025 Senior Notes and the Threshold Amount (as defined in the ABL Agreement). As of December 31, 2020,2022, the outstanding balance of the Revolving CreditABL Facility was $857.0$330.0 million and the unused portion totaled $238.9commitments were $64.1 million, after giving effect to the issuance thereunder of a $4.1$5.9 million90letterletters of credit. BasedThe ABL Facility is secured by a first lien on covenant limits,all of our availableassets and borrowings are subject to a borrowing base comprised of a percentage of eligible accounts receivable of Summit Holdings and its subsidiaries that guarantee the ABL Facility (collectively, the “ABL Facility Guarantors”) and a percentage of eligible above-ground fixed assets including eligible compression units, processing plants, compression stations and related equipment of Summit Holdings and the ABL Facility Guarantors. As of the date of the most recent borrowing base determination, eligible assets totaled $561.0 million, an amount greater than the $400.0 million capacity of the ABL Facility.Revolving CreditABL Facility asto term secured overnight financing rates (“SOFR”). As of December 31, 20202022, the applicable margin under the adjusted term SOFR borrowings was approximately $105 million. 3.25%, the interest rate was 7.45% and the unused portion of the ABL Facility totaled $64.1 million after giving effect to the issuance of $5.9 million in outstanding but undrawn irrevocable standby letters of credit.2020,2022, and as of December 31, 2020,2022, we were in compliance with the financial covenants in the Revolving CreditABL Facility. Our total leverage ratio and senior secured leverage ratioThe ABL Facility requires that Summit Holdings not permit (i) the First Lien Net Leverage Ratio (as defined in the RevolvingABL Agreement) as of the last day of any fiscal quarter to be greater than 2.50:1.00, or (ii) the Interest Coverage Ratio (as defined in the ABL Agreement) as of the last day of any fiscal quarter to be less than 2.00:1.00.Agreement) was 5.1 to 1.0 and 3.2 to 1.0, respectively, relative to maximum threshold limitsFacility. On March 8, 2021 (the “Permian Closing Date”), the Partnership’s unrestricted subsidiary, Permian Transmission, entered into a Credit Agreement which allows for $175.0 million of 5.75 to 1.0 and 3.5 to 1.0. Given further deterioration of market conditions, decreased drilling activity, the deferral of well completions from customers, limitations on our ability to access the capital markets at a competitive cost to fund our capital expenditures and, on a limited scale, temporary production curtailments, we could have total leverage and senior secured leverage ratios that are higher than the levels prescribed in the applicable indebtedness agreements. Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations and cash flows. See Note 9 to the consolidated financial statements for more information on the Revolvingcredit facilities (the “Permian Transmission Credit Facilities”), including a $160.0 million Term Loan Facility and the issuance of the $4.1a $15.0 million letter of credit.2022 Senior Notes.In July 2014, Summit HoldingsWorking Capital Facility. The Permian Transmission Credit Facilities can be used to finance Permian Transmission’s capital calls associated with its investment in Double E, debt service and its 100% owned finance subsidiary, Finance Corp. (together with Summit Holdings, the "Co-Issuers") co-issued $300.0 million of 5.5% senior unsecured notes maturing August 15, 2022 (the "2022 Senior Notes" and, together with the 2025 Senior Notes (defined below), the “Senior Notes”). other general corporate purposes.2020,2022, the applicable margin under adjusted LIBOR borrowings was 2.375%, the interest rate was 6.05% and the unused portion of the Permian Transmission Credit Facilities totaled $4.5 million, subject to a commitment fee of 0.7% after giving effect to the issuance of $10.5 million in outstanding but undrawn irrevocable standby letters of credit. As of December 31, 2022, the Partnership was in compliance with the financial covenants of the Permian Transmission Credit Facilities.2022 Senior Notes is $234.0 million. We pay interest on the 2022 Senior Notes semi-annually in cash in arrears on February 15Permian Transmission Term Loan was $155.4 million, and August 15 of each year. The 2022 Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 2022 Senior Notes are effectively subordinated in right of payment to all secured indebtedness, to the extent of the collateral securing such indebtedness. The Co-Issuers may redeem all or part of the 2022 Senior Notes at a redemption price of 100.000%, plus accrued and unpaid interest, if any. Debt issuance costs of $5.1 million are being amortized over the life of the 2022 Senior Notes. As of and during the year ended December 31, 2020, we were in compliance with the financial covenants governing our 2022of the Permian Transmission Term Loan and Permian Transmission Credit Facility.2025 Senior Notes. In February 2017, the Co-Issuers co-issued $500.0 million of 5.75% senior unsecured notes maturing April 15, 2025 (the “2025 Senior Notes”). As of December 31, 2020,2022, the outstanding balance of the 2025 Senior Notes was $259.5 million. We pay interest on the 2025 Senior Notes semi-annually in cash in arrears on April 15 and October 15 of each year. The 2025 Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations.obligations. The 2025 Senior Notes are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness.104.313%101.438% (with the redemption price declining ratably each April 15 to 100.000% on April 15, 2023), plus accrued and unpaid interest, if any, to, but not including, the redemption date. Debt issuance costs$7.7the 2026 Secured Notes, at a price of 98.5% of face value. Additionally, in November 2022, in connection with the 2022 DJ Acquisitions, we issued an additional $85.0 million of 2026 Secured Notes at a price of 99.26% of their face value. The Co-Issuers pay interest on the 2026 Secured Notes semi-annually on April 15 and October 15 of each year, and the 2026 Secured Notes are being amortized overjointly and severally guaranteed, on a senior second-priority secured basis (subject to permitted liens), by us and each of our restricted subsidiaries that is an obligor under the lifeABL Facility, or under the 2025 Senior Notes on the issue date of the 2026 Secured Notes. As of December 31, 2022, the outstanding balance of the 2026 Secured Notes was $785.0 million.Notes. AsNotes (or any refinancing indebtedness in respect thereof that has a final maturity on or prior to the date that is 91 days after the Initial Maturity Date (as defined in the 2026 Secured Notes Indenture)) is greater than or equal to $50.0 million on January 14, 2025, which is 91 days prior to the scheduled maturity date of the 2025 Senior Notes, then the 2026 Secured Notes will mature on January 14, 2025.duringcontinuing annually through the fiscal year ended 2025, the Partnership is required under the terms of the 2026 Secured Notes Indenture to, if it has Excess Cash Flow (as defined in the 2026 Secured Notes Indenture), and subject to its ability to make such an offer under the ABL Facility, offer to purchase an amount of the 2026 Secured Notes, at 100% of the principal amount plus accrued and unpaid interest, equal to 100% of the Excess Cash Flow generated in the prior year. Generally, if the Partnership does not offer to purchase designated annual amounts of its 2026 Secured Notes or reduce its first lien capacity under the 2026 Secured Notes Indenture per annum from 2023 through 2025, the interest rate on the 2026 Secured Notes is subject to certain rate escalations. Per the terms of the 2026 Secured Notes Indenture, the designated amounts are $50.0 million in aggregate by April 1, 2023, otherwise the interest rate shall automatically increase by 50 basis points per annum; $100.0 million in aggregate by April 1, 2024, otherwise the interest rate shall automatically increase by 100 basis points per annum (minus any amount previously increased); and $200.0 million in aggregate by April 1, 2025, otherwise the interest rate shall automatically increase by 200 basis points per annum (minus any amount previously increased).2020,2022, Double E made distributions to its investors totaling $17.8 million of which the Partnership received $12.5 million of which all amounts were utilized for payment of interest and principal on the Permian Transmission Term Loan and distributions to the holders of the Subsidiary Series A Preferred Units. Currently, we wereexpect Summit Permian Transmission Holdco, LLC will use all of its expected cash receipts in compliance with2023 to pay the financial covenants governing our 2025 Senior Notes.For additional informationcash distribution due on and to redeem portions of the Subsidiary Series A Preferred Units.long-termSeries A Preferred Units was $85.3 million, inclusive of accrued distributions.see Note 9or Series A Preferred Units through privately negotiated transactions, open market repurchases, redemptions, exchange offers, tender offers or otherwise, but we are under no obligation to the consolidated financial statements.Year ended December 31, 2022 2021 (In thousands) Net cash provided by operating activities $ 98,744 $ 165,099 Net cash used in investing activities (226,558) (165,729) Net cash provided by financing activities Net cash provided by financing activities 121,773 4,658 Net change in cash, cash equivalents and restricted cash $ (6,041) $ 4,028 2020,2022, primarily reflected:•net income of $189.1 million plus adjustments of $40.5 million for non-cash items; and$50.0 million increase in working capital accounts.2019,2021, primarily reflected:91Table•net loss of Contents•a $7.3 million increase in cash interest payments;$19.9 million plus adjustments of $179.2 million for non-cash items; and•other changes in working capital.20202022 primarily reflected:•$99.9 million of investments in our equity method investee; and$43.1 million of capital expenditures primarily attributable to the ongoing development of our Williston, DJ, Utica and Permian segments.20192021 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.20202021 primarily reflected:•$145.6 million paid for open market repurchases of the 2022 and 2025 Notes;•$47.5 million paid for tender offer•Refinancing portions of our long-term debt that included proceeds of $300.0 million from the ABL Facility and $689.5 million from the issuance of the 2026 Secured Notes, offset by the repayment of $33.0 million of the ABL Facility and the repayment in full of the $857.0 million Revolving Credit Facility and $234.0 million of the 2022 and 2025 Senior Notes;$41.8 million for the purchase of common units in the GP Buy-In Transaction;•$35.0 million for the repayment of the ECP Loan;•$26.5 million for cash paid in connection with the TL Restructuring;•$25.0 million of cash paid for in connection with the Preferred Tender Offer;•$6.3 million of cash repayments on the SMPH Term loan; and•$6.0 million of distributions offset by;•$180.0 million of net proceeds from borrowings on our Revolving Credit Facility;•$48.7 million in proceeds from the issuance of our Subsidiary Series A Preferred Units and;•$35.0 million in proceeds from the ECP Loan.Cash flows used in financing activities during the year ended December 31, 2019 primarily reflected:•$218.1 million of distributions;•$211.0 million of net borrowings under our Revolving Credit Facility;•$65.3 million payment on Term Loan B; and•$27.4 of net proceeds from the issuance of Subsidiary Series A Preferred Units.Partnership'sPartnership’s cash flows generated from operations are also the primary source for funding various contractual obligations. The table below summarizes the Partnership'sPartnership’s major commitments as of December 31, 20202022 through 2027 (in thousands):Total 2023 2024 2025 2026 2027 $ 294,896 $ 14,919 $ 14,919 $ 265,058 $ — $ — 411,950 24,585 24,585 24,585 338,195 — 1,058,769 70,650 70,650 70,650 846,819 — 114,224 19,672 23,940 24,035 23,410 23,167 28,335 6,667 6,667 6,667 6,667 1,667 Lease obligations 17,398 4,564 4,139 3,762 2,653 2,280 Total $ 1,925,572 $ 141,057 $ 144,900 $ 394,757 $ 1,217,744 $ 27,114 92December 31, 2021 SMLP Obligor Group (In thousands) Total revenues $ — $ 400,619 Total costs and expenses 23,989 317,975 (37,618) 13,931 Income from equity method investees — 9,116 Net income (loss) Net income (loss) $ (37,291) $ 23,047 95Impairment of 2020,2022, we had net property, plant and equipment with a carrying value of approximately $1.8$1.7 billion and net amortizing intangible assets with a carrying value of approximately $200.0$198.7 million. When evidence exists that we will not be able to recover a long-lived asset's carrying value through future cash flows, we write down the carrying value of the asset to its estimated fair value. We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. With respect to property, plant and equipment and our amortizing intangible assets, the carrying value of a long-lived asset is not recoverable if the carrying value exceeds the sum of the undiscounted cash flows expected to result from the asset's use and eventual disposal. In this situation, we would recognize an impairment loss equal to the amount by which the carrying value exceeds the asset's fair value. We determine fair value using a combination of approaches, including a market-based approach and an income-based approach in which we discount the asset's expected future cash flows to reflect the risk associated with achieving the underlying cash flows. Any impairment determinations involve significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these estimates are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.962020,2022, we had $493.5 million$1.0 billion principal amount of fixed-rate Senior Notes and $857.0debt, $330.0 million outstanding under our variable rate Revolving Credit Facility.ABL Facility and $155.4 million outstanding under our variable rate Permian Transmission Term Loan. As of December 31, 2022, we had $139.8 million of interest rate exposure hedged to offset the impact of changes in interest rates on our Permian Transmission Term Loan. 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 CreditABL Facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. For the year ended December 31, 2020,2022, a hypothetical 1% increase (decrease) in interest rates on our variable rate debt would have increased (decreased) our interest expense by approximately $7.7$3.6 million assuming no changes in amounts drawn or other variables under our Revolving CreditABL Facility or Senior Notes.Williston Basin,Rockies, Permian and Piceance Basin, and Permian Basin segments, (ii) the sale of natural gas we retain from certain Barnett Shale segment customers and (iii) the sale of condensate we retain from certain gathering services in the Piceance Basin segment. Our gathering agreements with certain Barnett Shale customers permit us to retain a certain quantity of natural gas that we sell to offset the power costs we incur to operate our electric-drive compression assets. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices on the Henry Hub Index. We sell retainage natural gas at prices that are based on the Atmos Zone 3 Index. By basing the power prices on a system and basin-relevant market, we are able to closely associate the relationship between the compression electricity expense and natural gas retainage sales. We do not enter into risk management contracts for speculative purposes.9798Houston, Texas20202022 and 2019,2021, the related consolidated statements of operations, partners' capital, and cash flows, for each of the two years thenin the period ended December 31, 2022, 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 CompanyPartnership as of December 31, 20202022 and 2019,2021, and the results of its operations and its cash flows for each of the two years thenin the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.We did not audit the financial statements of Ohio Gathering Company, L.L.C. (“Ohio Gathering”) as of and for the year ended December 31, 2019, the Partnership’s investment in which is accounted for by use of the equity method. The accompanying financial statements of the Partnership include its equity investment in Ohio Gathering of $275,000,000 as of December 31, 2019, and its loss from equity method investee in Ohio Gathering of $329,736,000 for the year then ended. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Ohio Gathering for 2019, prior to the 2019 impairment loss discussed in Note 7, which was audited by us, is based solely on the report of the other auditors.2020,2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 4, 2021February 28, 2023, expressed an unqualified opinion on the Partnership's internal control over financial reporting.and the report of other auditors provide a reasonable basis for our opinion.a separate opinionopinions on the critical audit matters or on the accounts or disclosures to which they relate.GP Buy-In TransactionNotes 1 and 14Note 3 to the financial statements13 to the consolidated financial statements, on May 28, 2020,December 1, 2022, the transactions contemplated byPartnership completed the Purchase Agreement (the “GP Buy-In Transaction”acquisitions of Outrigger DJ Midstream LLC (“Outrigger DJ”) closed. As a resultfor cash consideration of $165.0 million, and Sterling Energy Investments LLC, Grasslands Energy Marketing LLC and Centennial Water Pipelines LLC (collectively, “Sterling DJ”) for cash consideration of $140.0 million. The acquisitions of Outrigger DJ and Sterling DJ constituted business combinations and were accounted for using the acquisition method of accounting. The assets acquired and liabilities assumed were recorded at their preliminary estimated fair values at the date of the GP Buy-In Transaction, the Partnership now indirectly owns its General Partner, Summit Midstream Partners LLC (“Summit Investments”). Under GAAP, the GP Buy-In Transaction was deemed a transaction among entities under common control with a change in reporting entity. Although the Partnershipacquisition. The valuation of certain assets, including property, are based on preliminary appraisals. The fair value of acquired equipment is the surviving entitybased on both available market data and cost and income approaches. These methods are considered Level 3 fair value estimates and include significant assumptions of future gathering and processing volumes, commodity prices, and operating and capital cost estimates, discounted using weighted average cost of capital for legal purposes, Summit Investments is the surviving entity for accounting purposes; therefore, the historical financial results included herein prior to the GP Buy-In Transaction are those of Summit Investments.GP Buy-In Transaction as a significantvaluation of property, plant and unusual transactionequipment and intangible assets related to the Outrigger DJ and Sterling DJ acquisitions as a critical audit matter because of the significant estimates and assumptions made by management. This required a high degree of auditor judgment and an increased extent of effort, including the involvement of our fair value specialists, when performing audit effort necessaryprocedures to perform procedures and evaluate the audit evidence obtained relating to management’s accounting forreasonableness of management's selection of a weighted average cost of capital, and the GP Buy-In Transaction due to the pervasive naturepreliminary appraisal and fair value of the GP Buy-In Transaction on the composition of the Partnership’s consolidated financial statementsacquired property, plant and disclosures, including judgements necessary to combine legacy Summit Investments into the Partnership.99evaluatingmanagement's selection of a weighted average cost of capital, and the accounting treatmentpreliminary appraisal and fair value of the GP Buy-in Transactionacquired property, plant and equipment and intangible assets included the following, among others:•We tested the effectiveness of controls over the Partnership’s accounting for significant unusual transactions, including management’s controls over the identification and application of relevant GAAP, and over the combination and presentation of the historical carrying amounts in the consolidated financial statements.We read the GP Buy-In Transaction agreements and evaluated the reasonableness of management’s assessment of the accounting associated with the transaction between entities under common control and the completeness and accuracy of the consolidated financial statements, including the retrospective consolidation of Summit Investments within the Partnership’s consolidated financial statements.•We evaluated the sufficiency of the disclosures in the consolidated financial statements of the Partnership with respect to this matter.Commitments•With the assistance of our fair value specialists, we evaluated the reasonableness of the purchase price allocations of the Outrigger DJ and Contingencies — Environmental Matters —Sterling DJ acquisitions by:115 to the financial statementsIn 2015,learnedrecorded approximately $1.5 billion of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream Company, LLC (“Meadowlark Midstream”) system near Williston, North Dakota (“Meadowlark Rupture”). The U.S. Department of Justice (“DOJ”) issued grand jury subpoenas to Summit Investments, the Partnership, the Partnership’s General Partnerproperty, plant and Meadowlark Midstream requesting certain materials related to the Meadowlark Rupture. Meadowlark Midstream and Summit Investments received a complaint from the North Dakota Industrial Commission seeking fines and other fees related to the incident, and this matter is also under investigation by the U.S. Environmental Protection Agency, the North Dakota Office of the Attorney General, the North Dakota Department of Environmental Quality, and the North Dakota Game and Fish Department. Discussions with the DOJ and other agencies regarding a resolution of this matter are ongoing. Liability for this incident could arise under civil and misdemeanor and felony criminal statutes, including the Clean Water Act.When required, the Partnership records accruals for loss contingencies in accordance with FASB ASC 450, Contingencies. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. Asequipment, net as of December 31, 2020,2022. The Partnership tests assets for impairment when events or circumstances indicate the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If the Partnership has accrued a $17.0 million loss contingency for this matter. Whileconcludes that an asset’s carrying value will not be recovered through future cash flows, the Partnership believes arecognizes an impairment loss for claims and/or actions arising fromon the Meadowlark Rupture, whether in a negotiated settlement or as a result of litigation, is probable, duelong-lived asset equal to the complexity of resolvingamount by which the numerous issues surrounding this matter, at this time the Partnership cannot reasonably predict whether any actual loss, if incurred, would be materially higher or lower than the accrued amount. accrued loss contingencydetermination of impairment indicators for the Meadowlark Rupturelong-lived assets as a critical audit matter becausedue to the significant judgments management makes when determining whether events or changes in circumstances have occurred indicating that the carrying amounts of the challenges of auditinglong-lived assets may not be recoverable. Auditing management’s judgments applied in determining the accrued loss contingency as of December 31, 2020. Specifically, auditing management’s interpretations of the current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events is subjective and requires significantjudgements involved especially challenging auditor judgment due to the complexitynature and extent of resolvingaudit effort required to address these matters, including the numerous issues surrounding this matter.evaluating the accrued loss contingencyidentification of impairment indicators for the Meadowlark Rupturelong-lived assets included the following, among others:•We evaluated management’s analysis of claims and/or actions arising from the Meadowlark Rupture, read Board of Directors meeting minutes, including relevant sub-committee meeting minutes, and compared to responses from internal and external counsel.We obtained letters from the Partnership’s internal and external legal counsel as it relates to potential claims and/or actions arising from the Meadowlark Rupture.We evaluated any events subsequent to December 31, 2020, that might impact our evaluation of claims and/or actions arising from the Meadowlark Rupture, including any related accrual or disclosure.March 4, 2021100December 31,
2022December 31,
2021(In thousands, except unit amounts) ASSETS Cash and cash equivalents $ 11,808 $ 7,349 Restricted cash 1,723 12,223 Accounts receivable 75,287 62,121 Other current assets 8,724 5,676 Total current assets 97,542 87,369 Property, plant and equipment, net 1,718,754 1,726,082 Intangible assets, net 198,718 172,927 Investment in equity method investees 506,677 523,196 Other noncurrent assets 38,273 12,888 TOTAL ASSETS $ 2,559,964 $ 2,522,462 LIABILITIES AND CAPITAL Trade accounts payable $ 14,052 $ 10,498 Accrued expenses 20,601 14,462 Deferred revenue 9,054 10,374 Ad valorem taxes payable 10,245 8,570 Accrued compensation and employee benefits 16,319 11,019 Accrued interest 17,355 12,737 Accrued environmental remediation 1,365 3,068 Accrued settlement payable Accrued settlement payable 6,667 4,833 Current portion of long-term debt Current portion of long-term debt 10,507 — Other current liabilities 11,724 3,676 Total current liabilities 117,889 79,237 Long-term debt, net Long-term debt, net 1,479,855 1,355,072 Noncurrent deferred revenue 37,694 42,570 Noncurrent accrued environmental remediation 2,340 2,538 Other noncurrent liabilities 38,784 32,357 Total liabilities 1,676,562 1,511,774 Mezzanine Capital Subsidiary Series A Preferred Units (93,039 and 91,439 units issued and outstanding at December 31, 2022 and December 31, 2021, respectively) Subsidiary Series A Preferred Units (93,039 and 91,439 units issued and outstanding at December 31, 2022 and December 31, 2021, respectively) 118,584 106,325 Partners Capital Partners Capital Series A Preferred Units (65,508 and 143,447 units issued and outstanding at December 31, 2022 and December 31, 2021, respectively) Series A Preferred Units (65,508 and 143,447 units issued and outstanding at December 31, 2022 and December 31, 2021, respectively) 85,327 169,769 Common limited partner capital (10,182,763 and 7,169,834 units issued and outstanding at December 31, 2022 and December 31, 2021, respectively) Common limited partner capital (10,182,763 and 7,169,834 units issued and outstanding at December 31, 2022 and December 31, 2021, respectively) 679,491 734,594 Total partners capital Total partners capital 764,818 904,363 TOTAL LIABILITIES AND CAPITAL $ 2,559,964 $ 2,522,462 101Year ended December 31, 2022 2021 (In thousands, except per-unit amount) Revenues: Gathering services and related fees $ 248,358 $ 281,705 Natural gas, NGLs and condensate sales 86,225 82,768 Other revenues 35,011 36,145 Total revenues 369,594 400,618 Costs and expenses: Cost of natural gas and NGLs 76,826 81,969 Operation and maintenance 84,152 74,178 General and administrative 44,943 58,166 Depreciation and amortization 119,055 119,076 Transaction costs 6,968 1,677 Gain on asset sales, net (507) (369) Long-lived asset impairment 91,644 10,151 Total costs and expenses 423,081 344,848 Other expense, net Other expense, net (4) (613) Gain on interest rate swaps Gain on interest rate swaps 16,414 — Loss on sale of business Loss on sale of business (1,741) — Loss on ECP Warrants Loss on ECP Warrants — (13,634) Interest expense (102,459) (66,156) Loss on early extinguishment of debt Loss on early extinguishment of debt — (3,523) Loss before income taxes and equity method investment income Loss before income taxes and equity method investment income (141,277) (28,156) Income tax (expense) benefit Income tax (expense) benefit (325) 327 Income from equity method investees Income from equity method investees 18,141 7,880 Net loss Net loss $ (123,461) $ (19,949) Less: Net income attributable to Subsidiary Series A Preferred Units Less: Net income attributable to Subsidiary Series A Preferred Units (17,144) (16,667) Net loss attributable to Summit Midstream Partners, LP Net loss attributable to Summit Midstream Partners, LP $ (140,605) $ (36,616) Less: net income attributable to Series A Preferred Units Less: net income attributable to Series A Preferred Units (8,048) (15,998) Add: deemed capital contribution Add: deemed capital contribution 20,974 8,326 Net loss attributable to common limited partners Net loss attributable to common limited partners $ (127,679) $ (44,288) Net loss per limited partner unit: Net loss per limited partner unit: Common unit – basic $ (12.71) $ (6.57) Common unit – diluted $ (12.71) $ (6.57) Weighted-average limited partner units outstanding: Common units – basic 10,048 6,741 Common units – diluted 10,048 6,741 102PARTNERS'PARTNERS CAPITALPartners Capital Series A Preferred Units Common Limited Partner Capital Total (In thousands) Partners capital, December 31, 2020 $ 174,425 $ 748,466 $ 922,891 Net income (loss) 15,998 (52,614) (36,616) Unit-based compensation — 4,744 4,744 Tax withholdings and associated payments on vested SMLP LTIP awards — (1,733) (1,733) Tax withholdings on Series A Preferred Unit Exchange — (465) (465) Effect of 2021 Preferred Exchange Offer, inclusive of an $8.3 million deemed contribution to common unit holders (20,654) 20,654 — Exercise of ECP Warrants — 15,542 15,542 Partners capital, December 31, 2021 169,769 734,594 904,363 Net income (loss) 8,145 (148,743) (140,598) Unit-based compensation — 3,778 3,778 Tax withholdings and associated payments on vested SMLP LTIP awards — (1,198) (1,198) Tax withholdings on 2022 Preferred Exchange Offer — (2,652) (2,652) LTIP cash to equity conversion — 1,125 1,125 Effect of 2022 Preferred Exchange Offer, inclusive of a $20.9 million deemed contribution to common unit holders (92,587) 92,587 — Partners capital, December 31, 2022 $ 85,327 $ 679,491 $ 764,818 (1)Prior to the GP Buy-in Transaction, common noncontrolling interests reported by Summit Investments included equity interests in SMLP that were not owned by Summit Investments. (2) Includes deemed contributions of $54.9 million and $55.7 million related to the Exchange Offer and Tender Offer, respectively.103Year ended December 31, 2022 2021 (In thousands) Cash flows from operating activities: Net loss Net loss $ (123,461) $ (19,949) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation and amortization 119,993 119,995 Noncash lease expense 885 1,104 Amortization of debt issuance costs 9,326 7,017 Unit-based and noncash compensation 3,778 4,744 Income from equity method investees Income from equity method investees (18,141) (7,880) Distributions from equity method investees 43,040 26,760 Gain on asset sales, net (507) (369) Loss on sale of business Loss on sale of business 1,741 — Loss on extinguishment of debt Loss on extinguishment of debt — 3,245 Loss on ECP Warrants and other Loss on ECP Warrants and other — 13,635 Unrealized (gain) loss on interest rate swaps Unrealized (gain) loss on interest rate swaps (16,016) 779 Long-lived asset impairment 91,644 10,151 Changes in operating assets and liabilities: Accounts receivable 284 (178) Trade accounts payable 2,248 (89) Accrued expenses (2,780) 1,422 Deferred revenue, net (6,082) (5,295) Ad valorem taxes payable 14 (516) Accrued interest 4,618 4,730 Accrued environmental remediation, net (1,901) 2,676 Other, net (9,939) 3,117 Net cash provided by operating activities 98,744 165,099 Cash flows from investing activities: Capital expenditures (30,472) (25,030) Cash consideration paid for the acquisition of Outrigger DJ, net of cash acquired Cash consideration paid for the acquisition of Outrigger DJ, net of cash acquired (166,631) — Cash consideration paid for the acquisition of Sterling DJ, net of cash acquired Cash consideration paid for the acquisition of Sterling DJ, net of cash acquired (139,896) — Proceeds from sale of Lane G&P System, net of cash sold in transaction Proceeds from sale of Lane G&P System, net of cash sold in transaction 75,020 — Proceeds from sale of Bison Midstream, net of cash sold in transaction Proceeds from sale of Bison Midstream, net of cash sold in transaction 38,920 — Proceeds from asset sale Proceeds from asset sale 4,945 8,000 Investment in Double E equity method investee (8,444) (148,699) Net cash used in investing activities (226,558) (165,729) Cash flows from financing activities: Borrowings from 2026 Secured Notes Borrowings from 2026 Secured Notes 84,371 689,500 Repayment of 2022 Senior Notes Repayment of 2022 Senior Notes — (234,047) Borrowings from Permian Transmission Credit Facility Borrowings from Permian Transmission Credit Facility — 160,000 Repayments on Permian Transmission Term Loan Repayments on Permian Transmission Term Loan (4,647) — Borrowings from ABL Facility Borrowings from ABL Facility 293,000 300,000 Repayments of ABL Facility Repayments of ABL Facility (230,000) (33,000) Repayments of Revolving Credit Facility Repayments of Revolving Credit Facility — (857,000) Debt issuance costs (14,409) (20,228) Distributions on Subsidiary Series A Preferred Units Distributions on Subsidiary Series A Preferred Units (3,257) — Proceeds from asset sale — 357 Other, net (3,285) (924) Net cash provided by financing activities Net cash provided by financing activities 121,773 4,658 Net change in cash, cash equivalents and restricted cash (6,041) 4,028 Cash, cash equivalents and restricted cash, beginning of period 19,572 15,544 Cash, cash equivalents and restricted cash, end of period $ 13,531 $ 19,572 1042020,2022, the Partnership indirectly owns its General Partner, and the General Partner is a wholly owned, indirect subsidiary of the Partnership. The General Partner has no assets or liabilities and holds the non-economic general partner interest in the Partnership.GP Buy-In Transaction. On May 28, 2020, the Partnership closed the transactions contemplated by the Purchase Agreement (the “Purchase Agreement”), dated May 3, 2020, with affiliates of its then private equity sponsor, Energy Capital Partners II, LLC (“ECP”), to acquire Summit Investments. The acquisition of Summit Investments resulted in the Partnership acquiring (a) 2.3 million SMLP common units that were pledged as collateral under the SMPH Term Loan, (b) 0.7 million SMLP common units that were not pledged as collateral under the SMPH Term Loan and (c) a deferred purchase price obligation receivable owed by the Partnership. In addition, the Partnership acquired 0.4 million SMLP common units held by an affiliate of ECP. The total purchase price was $35.0 million in cash and warrants giving ECP the right to purchase up to 0.7 million SMLP common units (refer to Note 13 – Partners’ Capital and Mezzanine Capital for additional details). Pursuant to the Purchase Agreement, the Partnership retained any liabilities stemming from the release of produced water from a produced water pipeline operated by Meadowlark Midstream, a subsidiary of the Partnership, that occurred near Williston, North Dakota and was discovered on January 6, 2015. These transactions are collectively referred to as the “GP Buy-In Transaction.”As a result of the GP Buy-In Transaction, the Partnership indirectly owns its General Partner. Following the closing of the GP Buy-In Transaction, the Partnership retired 1.1 million SMLP common units it acquired that were not pledged as collateral under the SMPH Term Loan. The 2.3 million SMLP common units that were pledged as collateral under the SMPH Term Loan were not considered outstanding with respect to voting and distributions under the Partnership Agreement until the closing of the TL Restructuring on November 17, 2020 (refer to Note 10).Under GAAP, the GP Buy-In Transaction was deemed a transaction among entities under common control with a change in reporting entity. Although SMLP is the surviving entity for legal purposes, Summit Investments is the surviving entity for accounting purposes; therefore, the historical financial results included herein, prior to the GP Buy-In Transaction are those of Summit Investments. Prior to the GP Buy-In Transaction, Summit Investments controlled SMLP and SMLP’s financial statements were consolidated into Summit Investments.Reverse Unit Split. On November 9, 2020, after the close of trading on the NYSE, the Partnership effected a 1-for-15 reverse unit split (the “Reverse Unit Split”) of its common units. The common units began trading on a split-adjusted basis on November 10, 2020. Pursuant to the Reverse Unit Split, common unitholders received one common unit for every 15 common units owned at the close of business on November 9, 2020. Immediately prior to the Reverse Unit Split, there were 56,624,887 common units issued and outstanding and immediately after the Reverse Unit Split, the number of issued and outstanding common units decreased to 3,774,992. subsidiariessubsidiaries.105Risks and Uncertainties.The Partnership is closely monitoring the impact of the outbreak of COVID-19 on all aspects of its business, including how it has impacted and will impact its customers, employees, supply chain and distribution network. The Partnership is unable to predict the ultimate impact that COVID-19 may have on its business, future results of operations, financial position or cash flows.Given the dynamic nature of the COVID-19 pandemic and related market conditions, the Partnership cannot reasonably estimate the period of time that these events will persist or the full extent of the impact they will have on its business. The full extent to which the Partnership’s operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including changes in the severity of the pandemic, countermeasures taken by governments, businesses and individuals to slow the spread of the pandemic, and the ability of pharmaceutical companies to develop effective and safe vaccines and therapeutic drugs. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.Useful lives
(In years)(In years)1060tnot provide for any asset retirement obligations as of December 31, 20202022 or 2019.2021.(except goodwill) is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If the Partnership concludes that an asset'sasset’s carrying value will not be recovered through future cash flows, the Partnership recognizes an impairment loss on the long-lived asset equal to the amount by which the carrying value exceeds its fair value. The Partnership determines fair value using a combination of market-based and income-based approaches.Noncontrolling Interest and A noncontrolling interest represents the portion of a consolidated subsidiary that is owned by a third party. Amounts are adjusted by the noncontrolling interest holder’s proportionate share of the subsidiary’s earnings or losses each period and any distributions that are paid. A noncontrolling interest is reported as a107Revenue Recognition.Fee-based arrangements. Under fee-based arrangements, the Partnership receives a fee or fees for one or more of the following services (i) natural gas gathering, treating, compressing and/or processing and (ii) crude oil and/or produced water gathering.• the volume of natural gas that flows through the system and the price at which the Partnership is able to sell the residue natural gas and NGLs.For the contracts described above, the Partnership reflects its revenues in the financial statement captions described below.Financial statement caption:Revenue description:Revenues:Gathering services and related fees•Revenue earned from fee-based gathering, compression, treating and processing services;Natural gas, NGLs and condensate sales•Revenue from the sale of physical natural gas purchased from customers percent-of-proceeds arrangements (Costs are presented within cost of natural gas and NGLs);•Revenue from sale of condensate and NGLs retained from gathering services (Costs are presented within operation and maintenance expense); andOther revenues•Customer reimbursements to the Partnership for costs incurred by the Partnership on customer’s behalf (Recorded on a gross basis).Certain of the Partnership’s gathering and/or processing agreements provide for monthly or annual MVCs. Under these MVCs, customers agree to ship and/or process a minimum volume of production on its gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to the Partnership at the end of the contracted measurement period if its actual throughput volumes are less than its contractual MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that contracted measurement period.The Partnership recognizes customer obligations under their MVCs as revenue and contract assets when (i) it considers it remote that the customer will utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods; (ii) the customer incurs a shortfall in a contract with no banking mechanism or claw back provision; (iii) the customer’s banking mechanism has expired; or (iv) it is remote that the customer will use its unexercised right. In making this determination, the Partnership considers both quantitative and qualitative facts and circumstances, including, but not limited to, contract terms, capacity of the associated pipeline or receipt point and/or expectations regarding future investment, drilling and production.108Unit-Based Compensation. For awards of unit-based compensation, the Partnership determines a grant date fair value and recognizes the related compensation expense in the statements of operations over the vesting period for each respective award.Income Taxes. The Partnership is generally not subject to federal and state income taxes, except as noted below. However, its unitholders are individually responsible for paying federal and state income taxes on their share of its taxable income. Net income or loss for GAAP purposes may differ significantly from taxable income reportable to its unitholders as a result of differences between the tax basis and the GAAP basis of assets and liabilities and the taxable income allocation requirements of the Partnership’s governing documents. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined as the Partnership does not have access to the information about each partner’s tax attributes related to the Partnership.In general, legal entities that are chartered, organized or conducting business in the state of Texas are subject to a franchise tax (the "Texas Margin Tax"). The Texas Margin Tax has the characteristics of an income tax because it is determined by applying a tax rate to a tax base that considers both revenues and expenses. The Partnership’s financial statements reflect provisions for these tax obligations.New accounting standards implemented in this Annual Report.ASU No. 2018-13 Fair Value Measurement (“ASU 2018-13”). ASU 2018-13 updates the disclosure requirements on fair value measurements including new disclosures for the changes in unrealized gains and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. ASU 2018-13 modifies existing disclosures including clarifying the measurement uncertainty disclosure. ASU 2018-13 removes certain existing disclosure requirements including the amount and reasons for transfers between Level 1 and Level 2 fair value measurements and the policy for the timing of transfer between levels. The adoption of ASU 2018-13 on January 1, 2020 did not have a material impact on the Partnership’s consolidated financial statements or disclosures.ASU No. 2016-13 Financial Instruments – Credit Losses (“ASU 2016-13”). ASU 2016-13 requires the use of a current expected loss model for financial assets measured at amortized cost and certain off-balance sheet credit exposures. Under this model, entities will be required to estimate the lifetime expected credit losses on such instruments based on historical experience, current conditions, and reasonable and supportable forecasts. This amended guidance also expands the disclosure requirements to enable users of financial statements to understand an entity’s assumptions, models and methods for estimating expected credit losses. The changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied using a modified retrospective approach. The adoption of ASU 2016-13 on January 1, 2020 did not have a material impact on the Partnership’s consolidated financial statements or disclosures.New accounting standards not yet implemented in this Annual Report.ASU No. 2020-06 Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815 – 40) (“ASU 2020-06”). ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. The ASU is part of the FASB’s simplification initiative, which aims to reduce unnecessary complexity in U.S. GAAP. The ASU’s amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within those fiscal years. The Partnership is currently evaluating the provisions of ASU 2020-06 to determine its impact on the Partnership’s consolidated financial statements and disclosures.ASU No. 2020-04 Reference Rate Reform (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform on financial reporting. The amendments in ASU 2020-04 are effective as of March 12, 2020 through December 31, 2022. The Partnership is currently evaluating the provisions of ASU 2020-04 to determine its impact on the Partnership’s consolidated financial statements and disclosures.3. REVENUEThe majority of the Partnership’s revenue is derived from long-term, fee-based contracts with its customers, which include original terms of up to 25 years. The Partnership recognizes revenue earned from fee-based gathering, compression, treating and processing services in gathering services and related fees. The Partnership also earns revenue in the Williston Basin and Permian109Basin reporting segments from the sale of physical natural gas purchased from its customers under certain percent-of-proceeds arrangements. Under ASC Topic 606, these gathering contracts are presented net within cost of natural gas and NGLs. The Partnership sells natural gas that it retains from certain customers in the Barnett Shale reporting segment to offset the power expenses of the electric-driven compression on the DFW Midstream system. The Partnership also sells condensate and NGLs retained from certain of its gathering services in the Piceance Basin and Permian Basin reporting segments. Revenues from the sale of natural gas and condensate are recognized in Natural gas, NGLs and condensate sales; the associated expense is included in Operation and maintenance expense. Certain customers reimburse the Partnership for costs incurred on their behalf. The Partnership records costs incurred and reimbursed by its customers on a gross basis, with the revenue component recognized in Other revenues.The transaction price in the Partnership’s contracts is primarily based on the volume of natural gas crude oil or produced water transferred by its gathering systems tothat flows through the customer’s agreed upon delivery point multiplied bysystem and 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,price at which the Partnership does not estimate variable consideration becauseis able to sell the performance obligations are completedresidue natural gas and settled on a daily basis. For contracts containing noncash consideration such as fuel received in-kind, the Partnership measures the transaction price at the point of sale when the volume, mix and market price of the commodities are known.The Partnership has contracts with MVCs that are variable and constrained. Contracts with longer than monthly MVCs are reviewed on a quarterly basis and adjustments to those estimates are made during each respective reporting period, if necessary.The transaction price is allocated if the contract contains more than one performance obligation such as contracts that include MVCs. The transaction price allocated is based on the MVC for the applicable measurement period.Performance obligations. NGLs.