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x			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

or

o			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from        to        

Securities registered pursuant to Section 12(b) of the Securities Act:

Title of each class			Trading Symbol(s)			Name of each exchange on which registered
Common Units			SMLP			New York Stock Exchange

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

o

Accelerated filer

x

Non-accelerated filer

o

Smaller reporting company

x

Emerging growth company

o

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. o

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to § 240.10D-1(b). o

Class						As of February 24, 2023
Common Units						10,182,763

PART I						14
Item 1.			Business.			14
Item 1A.			Risk Factors.			31
Item 1B.			Unresolved Staff Comments.			63
Item 2.			Properties.			63
Item 3.			Legal Proceedings.			63
Item 4.			Mine Safety Disclosures.			64
PART II						65
Item 5.			Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.			65
Item 7.			Management’s Discussion and Analysis of Financial Condition and Results of Operations.			68
Item 7A.			Quantitative and Qualitative Disclosures about Market Risk.			94
Item 8.			Financial Statements and Supplementary Data.			95
Item 9.			Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.			131
Item 9A.			Controls and Procedures.			131
Item 9B.			Other Information.			133
Item 9C.			Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.			134
Part III						135
Item 10.			Directors, Executive Officers and Corporate Governance.			135
Item 11.			Executive Compensation.			135
Item 12.			Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.			135
Item 13.			Certain Relationships and Related Transactions, and Director Independence.			135
Item 14.			Principal Accounting Fees and Services.			135
Part IV						136
Item 15.			Exhibits, Financial Statement Schedules.			136
Item 16.			Form 10-K Summary.			142
Signature Page						143

•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;

•commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets;

•changes in the availability and cost of capital and the results of our financing efforts, including availability of funds in the credit and/or capital markets;

•restrictions placed on us by the agreements governing our debt and preferred equity instruments;

•the availability, terms and cost of downstream transportation and processing services;

•natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control;

•operational risks and hazards inherent in the gathering, compression, treating and/or processing of natural gas, crude oil and produced water;

•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;

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

•interest rates;

•changes in general economic conditions; and

•certain factors discussed elsewhere in this report.

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.

•Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders.

•Significant prolonged weakness in natural gas, NGL and crude oil prices could reduce throughput on our systems and materially adversely affect our revenues and ability to make cash distributions to our unitholders.

•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.

•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 operations.

•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.

•Restrictions in our debt instruments could materially adversely affect our business, financial condition, results of operations, our ability to make cash distributions to unitholders and the value of our common units.

•Inflation could have adverse effects on our results of operation.

•An increase in interest rates will cause our debt service obligations to increase.

•The phase-out of LIBOR could have adverse effects on our hedging strategies, financial condition, results of operations and cash flows.

•A downgrade of our credit rating could impact our liquidity, access to capital and our costs of doing business, and independent third parties determine our credit ratings outside of our control.

•We have in the past and may in the future incur losses due to an impairment in the carrying value of our long-lived assets or equity method investments.

•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 business is subject to complex and evolving U.S. and international laws and regulations regarding privacy and data protection.

•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.

•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.

•If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

•Our unitholders are required to pay income taxes on their share of our taxable income even if they do not receive any cash distributions from us.

•In 2020, we engaged in 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.

•Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war could have a material adverse effect on our business, financial condition or results of operations.

•Our operations depend on the use of information technology and operational technology systems that could be the target of a cyberattack.

2015 Blacktail Release			a 2015 rupture of our four-inch produced water gathering pipeline near Williston, North Dakota
2022 DJ Acquisitions			the acquisition of Outrigger DJ Midstream LLC from Outrigger Energy II LLC, and each of Sterling Energy Investments LLC, Grasslands Energy Marketing LLC and Centennial Water Pipelines LLC from Sterling Investment Holdings LLC
2025 Senior Notes			Summit Holdings' and Finance Corp.’s 5.75% senior unsecured notes due April 2025
2026 Secured Notes			Summit Holdings' and Finance Corp.’s 8.500% senior secured second lien notes due 2026
2026 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			Loan and Security Agreement, dated as of November 2, 2021, among Summit Holdings, as borrower, SMLP and certain subsidiaries from time to time party thereto, as guarantors, Bank of America, N.A., as agent, ING Capital LLC, Royal Bank of Canada and Regions Bank, as co-syndication agents, and Bank of America, N.A., ING Capital LLC, RBC Capital Markets and Regions Capital Markets, as joint lead arrangers and joint bookrunners
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 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
COD			cancellation of debt
Collateral 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
condensate			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, if established
Co-Issuers			Summit Holdings and Finance Corp.
CWA			Clean Water Act
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 Pipeline			a 1.35 Bcf per day, FERC-regulated interstate natural gas transmission pipeline that 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 hub in Texas
Double E Project			the development and construction of the Double E Pipeline
dry gas			natural gas primarily composed of methane where heavy hydrocarbons and water either do not exist or have been removed through processing or treating
Dth/d			one million British Thermal Units per day
ECP			Energy Capital Partners II, LLC and its parallel and co-investment funds
EPA			Environmental Protection Agency
Epping			Epping Transmission Company, LLC
Epping Pipeline			an interstate crude oil pipeline in North Dakota, owned and operated by Epping
EPU			earnings or loss per unit

Exchange Act			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			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 Summit Niobrara
hub			geographic location of a storage facility and multiple pipeline interconnections
ICA			Interstate Commerce Act
Intercreditor Agreement			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 first lien claimholders, Regions Bank, as second lien representative for the initial second lien claimholders and as collateral agent for the initial second lien claimholders, acknowledged and agreed to by Summit Holdings and the other grantors referred to therein
IRS			Internal Revenue Service
LIBOR			London Interbank Offered Rate
Mbbl/d			one thousand barrels per day
MD&A			Management's Discussion and Analysis of Financial Condition and Results of Operations
MDTQ			maximum daily transportation quantity
Meadowlark Midstream			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			the equivalent of one million cubic feet per day; determined using a ratio of six thousand cubic feet of natural gas to one barrel of liquids
Mountaineer Midstream			Mountaineer Midstream Company, LLC
MVC			minimum volume commitment
NAAQS			national ambient air quality standard
NEPA			National Environmental Policy Act
NDIC			North Dakota Industrial Commission
NGA			Natural Gas Act
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
Obligor Group			the Co-Issuers and the Guarantor Subsidiaries
OCC			Ohio Condensate Company, L.L.C.
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
PHMSA			Pipeline and Hazardous Materials Safety Administration
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 term loan 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

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			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 issued by the Partnership
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
SMPH Term Loan			SMPH Holdings’ term loan, governed by the Term Loan Agreement, dated as of March 21, 2017, among SMP Holdings, as borrower, the lenders party thereto and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent and Collateral Agent

SPCC			Spill Prevention Control and Countermeasure
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
Tax Reform Legislation			the Tax Cuts and Jobs Act of 2017
Tcfe			the equivalent of one trillion cubic feet
the Partnership			Summit Midstream Partners, LP and its subsidiaries
the Partnership Agreement			the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership dated May 28, 2020, as amended by Amendment No. 1 to the Fourth Amended and Restated Agreement of Limited Partnership, dated February 23, 2023
throughput volume			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
unconventional resource 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 of all of our midstream assets. We have cultivated strong producer relationships by focusing on customer service and 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 expand our midstream services reach and optimize the utilization of our midstream assets for our customers.

•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.

•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.

Reportable Segments. As of December 31, 2022, our reportable segments are below along with management’s categorization of the primary commodity driving customer drilling and completion decisions for each segment:

Oil price driven. Our cash flows in the Rockies and Permian segments are primarily influenced by the prevailing price of crude oil because the drilling and completion decisions by our customers in these segments are based on well economics most heavily tied to crude oil prices. Our customers’ decisions to drill and complete wells in these segments therefore result in higher volume throughput and cash flows for our midstream assets in which we collect fixed fees for gathering or processing hydrocarbons, gathering produced water, or transporting residue natural gas.

•Rockies – Includes our wholly owned midstream assets located in the Williston Basin and the DJ Basin.

•Permian – Includes our equity method investment in Double E.

Natural gas price driven. Our cash flows in the Northeast, Piceance and Barnett segments are primarily influenced by the prevailing price of natural gas because the drilling, completion and recompletion decisions by our customers in these segments are based on well economics most heavily tied to natural gas and NGL prices. Our customers’ decisions to drill, complete or recomplete wells in these segments therefore result in higher throughput and cash flows for those segments in which we collect fixed fees for gathering natural gas.

•Northeast – Includes our wholly owned midstream assets located in the Utica and Marcellus shale plays and our equity method investment in Ohio Gathering that is focused on the Utica Shale.

•Piceance – Includes our wholly owned midstream assets located in the Piceance Basin.

•Barnett – Includes our wholly owned midstream assets located in the Barnett Shale.

For additional information on our MVCs, see Note 4 – Revenue and Note 8 – Deferred Revenue to the consolidated financial statements.

Throughput and Commodity Price Exposure. Our financial results are primarily driven by volume throughput across our gathering systems and by expense management. During 2022, aggregate natural gas volume throughput averaged 1,208 MMcf/d and crude oil and produced water volume throughput averaged 62 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 Rockies, Permian and Piceance segments, (ii) the sale of natural gas we retain from certain Barnett customers, (iii) the sale of condensate we retain from our gathering services in the Rockies and Piceance 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, 2022, these additional activities accounted for approximately 18% of total revenues.

Equity Method Investment – Ohio Gathering. We have an equity method investment in Ohio Gathering, which comprises a natural gas gathering system and condensate stabilization facility located in the core of the Utica Shale in southeastern Ohio. Our joint venture partner in Ohio Gathering may elect to fund 100% of a capital call if we choose not to fund our proportionate share of such capital call. In 2022 and 2021, we chose to not fund capital calls in Ohio Gathering because the investment did not meet our corporate objectives and as a result, our ownership interest in that venture was reduced to 37.2% as of December 31, 2022 from 37.8% as of December 31, 2021. MPLX LP (“MPLX”) is the operator of the Ohio Gathering joint venture and our joint venture partner.

Equity Method Investment – Double E. We have an equity method investment in Double E, a 1.35 Bcf/d FERC-regulated interstate natural gas transmission pipeline that 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 hub in Texas. We are the

						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)
Northeast (1)						1,770						221						403						7.2						4.0
Ohio Gathering (2)						1,100						n/a						n/a						9.1						n/a

______________________________________________

(1) Includes our wholly owned assets, Summit Utica system and Mountaineer Midstream system

(2) Presented on a gross basis. As of December 31, 2022, we owned approximately a 37.2% interest in OGC and approximately a 38.2% interest in OCC.

Summit Utica system. The Summit Utica system is a natural gas gathering system located in Belmont and Monroe counties in southeastern Ohio and serves producers targeting the dry gas reserves 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. Ascent Resources is the key customer of Summit Utica, and the AMIs from our customers for this system cover approximately 115,000 surface acres in the aggregate.

Mountaineer Midstream system. The Mountaineer Midstream system, within the Marcellus shale, is located in Doddridge and Harrison counties in West Virginia where it gathers natural gas under 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.

Ohio Gathering. Ohio Gathering comprises a natural gas gathering system and condensate stabilization facility located in the core of the Utica Shale in southeastern Ohio. The gathering system spans the condensate, liquids-rich and dry gas windows of the Utica Shale for multiple producers that are targeting production from the Utica and Point Pleasant shale formations across Belmont, Monroe, Guernsey, Harrison and Noble counties in southeastern Ohio. Ohio Gathering is operated by our partner, 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 and the AMIs from our customers for this system cover approximately 830,000 surface acres in the aggregate.

			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
Rockies - DJ (1)			50						220						13						26						8.4						5.4

(1)Capacity of 220 MMcf/d represents nameplate processing capacity. Operational capacity is estimated at approximately 190 MMcf/d.

Niobrara G&P system. 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 Colorado. Gathering and processing services on the Niobrara G&P system are provided pursuant to long-term, fee-based and percentage of proceeds agreements with producers that are primarily targeting crude oil production from the Niobrara and Codell shale formations. Chevron 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.

			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)
Double E (1)			1,350						964						3,177						8.8						8.8

______________________________________________

(1) Presented on a gross basis. Existing MVC’s contractually increase to 1.0 Bcf/d beginning in November 2024. As of December 31, 2022, we owned a 70% interest in Double E.

Double E. Double E is a 135 mile, 1.35 Bcf/d, FERC-regulated interstate natural gas transmission pipeline that commenced operations in November 2021 and provides transportation service from receipt points in the Delaware Basin to various delivery points in and around the Waha hub 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 and operates the pipeline.

			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

Grand River system. Grand River is primarily located in Garfield County, one of the largest natural gas producing counties in Colorado. The Grand River system provides natural gas gathering services pursuant to primarily long-term and fee-based agreements with multiple producers, including its key customers, Caerus Oil and Gas and Terra Energy Partners. Volume throughput on the Grand River system is underpinned with acreage dedications and MVCs.

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

DFW Midstream system. The DFW Midstream system is primarily located in southeastern Tarrant County, in north-central Texas. We consider this area to be the core of the Barnett Shale because of the quality of the geology and the high production profile of the wells drilled to date in our service area. The DFW Midstream system is underpinned by a long-term, fee-based gathering agreements with Total Gas & Power North America, Inc. (“Total”) and other customers. Total is the key customer for DFW Midstream.

General. Sales by producers of natural gas, crude oil, condensate and NGLs are currently made at market prices. However, gathering and transportation services are subject to various types of regulation, which may affect certain aspects of our business and the market for our services. FERC regulates the transportation of natural gas in interstate commerce and the interstate transportation of crude oil, petroleum products and NGLs. FERC regulation includes reviewing and accepting or approving rates and other terms and conditions for such transportation services and authorizing and regulating the construction and operation of interstate natural gas pipelines. FERC is also authorized to prevent and sanction market manipulation in natural gas markets while the FTC is authorized to prevent and sanction market manipulation in petroleum markets and the CFTC is authorized to prevent and sanction fraud and price manipulations in the commodity and futures markets, including the energy futures markets. State and municipal regulations may apply to the production and gathering of certain natural gas, the construction and operation of natural gas and crude oil facilities and the rates and practices of gathering systems and intrastate pipelines.

Pursuant to the NGA, existing interstate natural gas transportation and storage rates and terms and conditions of service may 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. Double E currently holds authority from the FERC to charge and collect (i) “recourse rates,” which are the maximum cost-based rates an interstate natural gas pipeline may charge for its services under its tariff; (ii) “discount rates,” which are rates offered by the natural gas pipeline to shippers at discounts vis-à-vis the recourse rates and that fall within the cost-based maximum and minimum rate levels set forth in the natural gas pipeline's tariff; and (iii) “negotiated rates,” which are rates negotiated and agreed to by the pipeline and the shipper for the contract term that may fall within or outside of the cost-based maximum and minimum rate levels set forth in the tariff, and which are individually filed with the FERC for review and acceptance. On November 18, 2021, we entered into negotiated rate agreements with an average term of 10 years from the in-service date of the pipeline 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. When capacity is available and offered for sale, the rates (which include reservation, commodity, surcharges, and fixed fuel and lost and unaccounted for charges) and the terms and conditions at which such capacity is sold are subject to regulatory approval and oversight. 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.

•perform ongoing assessments of pipeline integrity;

•identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

•maintain processes for data collection, integration and analysis;

•repair and remediate pipelines as necessary;

•adopt and maintain procedures, standards and training programs for control room operations; and

•implement preventive and mitigating actions.

In addition, PHMSA has taken recent action to regulate gathering systems, which includes integrity management requirements. 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.

•requiring the installation of pollution-control equipment or otherwise restricting the way we operate;

•limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;

•delaying system modification or upgrades during permit reviews;

•requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and

•enjoining the operations of facilities deemed to be in non-compliance with permits or permit requirements issued pursuant to or imposed by such environmental laws and regulations.

In October 2015, the EPA issued a new lower NAAQS for ozone. The previous ozone standard was set at 75 parts per billion (“ppb”). The revised standard has been lowered to 70 ppb. The lowered ozone NAAQS could subject us to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements and increased permitting delays and costs. In 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 in 2020, but retained the standard without revision. However, EPA has announced that it will reconsider the 2020 decision to retain the 2015 standards. Future actions to lower the standard could similarly result in additional fees or more stringent permitting.

On June 3, 2016, the EPA finalized revisions to its 2012 New Source Performance Standard (“NSPS”) OOOO for the oil and gas industry, to reduce emissions of greenhouse gases - most notably methane - along with smog-forming VOCs. The revisions, which are published in the Federal Register under Subpart OOOOa, included the addition of methane to the pollutants covered by the rule, along with requirements for detecting and repairing leaks at gathering and boosting stations. Further, in November 2021, the EPA issued a 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 commence construction, modification or reconstruction after the date the proposed rule is published in the Federal Register; and (3) adopt a new NSPS OOOOc to establish emissions guidelines, which will inform state plans to establish 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 additional restrictions on operations and increased compliance costs for us or our customers.

Hydraulic Fracturing. Hydraulic fracturing is an important practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations, and is primarily regulated by state agencies. 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 ballot initiative to ban hydraulic fracturing on all non-federal land, but the proposed initiative failed to 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.

Interior has since resumed leasing. However, the Biden Administration continues to evaluate federal leasing and could impose additional restrictions in the future.

National Environmental Policy Act. 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 requiring 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 result 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.

Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions. The agreement entered into force in November 2016 after over 70 countries, including the United States, ratified or otherwise consented to be bound by the agreement. In November 2019, the United States submitted formal notification to the United Nations that it intended to withdraw from the agreement. However, on January 20, 2021, President Biden signed an “Acceptance on Behalf of the United States of America” that reversed the prior withdrawal, and the United States officially rejoined the Paris Agreement on February 19, 2021. As part of rejoining the Paris Agreement, President Biden announced 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, new legislation, or President Biden’s executive orders may result in the development of

•Talent development, compensation and retention – We strive to provide our employees with a rewarding work environment, including the opportunity for success and a platform for personal and professional development. We provide a competitive benefits package designed to attract and retain a skilled and diverse workforce. We offer our employees a comprehensive benefits package, which includes company funded health plan options, vision and dental coverage, healthcare savings account, paid time off, parental leave and flexible spending accounts. We also provide professional training and development opportunities as well as education reimbursement. We also offer employees immediate eligibility in our 401(k) plan with company matching program.

•Health and safety – Employee health and safety in the workplace is one of our core values. Some of the ways in which we support the health and safety of our employees include wellness programs with incentives and employee assistance programs.

•Inclusion and diversity – We are committed to efforts to increase diversity and foster an inclusive work environment that supports our workforce.

Availability of Reports. We make certain filings with the SEC, including, among other filings, this 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 a 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.

We may not have sufficient available cash from operating surplus each quarter to pay the distributions to holders of our common units. 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. 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.

•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

•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;

•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;

•distributions paid on our Series A Preferred Units, if any, or on the preferred stock of our subsidiaries, including our Subsidiary Series A Preferred Units; and

•other business risks affecting our cash levels.

•the availability and cost of capital;

•prevailing and projected hydrocarbon commodity prices;

•demand for crude oil, natural gas and other hydrocarbon products, including NGLs;

•levels of reserves;

•geological considerations;

•environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

•the availability of drilling rigs and other costs of production and equipment.

•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 nature and extent of governmental regulation and taxation; and

•the anticipated future prices of crude oil, natural gas and other hydrocarbon products, including NGLs.

•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

•the effects of federal, state or local regulations on the contracting practices of our customers.

•unscheduled turnarounds or catastrophic events at our physical plants or pipeline facilities;

•restrictions imposed by governmental authorities or court proceedings;

•labor difficulties that result in a work stoppage or slowdown;

•a disruption in the supply of resources necessary to operate our midstream facilities;

•damage to our facilities resulting from production volumes that do not comply with applicable specifications; and

•inadequate transportation and/or market access to support production volumes, including lack of pipeline, rail terminals, produced water disposal facilities and/or third-party processing capacity.

•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

•other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

•technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in wind, solar and hydrogen power, as well as battery technology);

•increased availability of, and increased demand from consumers and industry for, energy sources other than crude oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and

•development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services.

Such developments and accompanying societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG initiatives and disclosures could, among other things, increase costs related to compliance and stakeholder engagement, increase reputational risk and negatively impact our access to and cost of accessing capital. For example, some prominent investors have announced their intention to no longer invest in the oil and gas sector, citing climate change concerns. If other financial institutions and investors refuse to invest in or provide capital to the oil and gas sector in the future because of these reputational risks, that could result in capital being unavailable to us, or only at significantly increased cost.

•Disruptions in demand for oil, natural gas and other petroleum products;

•Decreased productivity resulting from illness, travel restrictions, quarantine, or government mandates;

•Supply chain disruptions resulting from quarantine requirements, government restrictions, or reduced economic activity as a result of increases in COVID-19 cases;

•Increased challenges in retention of personnel caused by vaccine hesitancy and the resistance of some in our workforce to comply with workplace protocols necessary to ensure the health and safety of our workforce and minimize disruptions to the business, such as vaccine and testing requirements, or the use of personal protective equipment.

Additionally, the effects of the COVID-19 pandemic might worsen the likelihood or the impact of other risks already inherent in our business. The extent to which our operations are impacted by the COVID-19 pandemic will depend largely on future developments, which remain highly uncertain and cannot be accurately predicted.

•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.

•incur or guarantee certain additional debt;

•make certain cash distributions on or redeem or repurchase certain units;

•make payments on certain other indebtedness;

•make certain investments and acquisitions;

•make certain capital expenditures;

•incur certain liens or other encumbrances 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.

The Biden Administration is considering revisions to the leasing and permitting programs for oil and gas development on federal lands, which could materially adversely affect our industry and our financial condition and results of 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

•implement preventive and mitigating actions.

Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions. The agreement entered into force in November 2016 after over 70 countries, including the United States, ratified or otherwise consented to be bound by the agreement. In November 2019, the United States submitted formal notification to the United Nations that it intended to withdraw from the agreement. However, on January 20, 2021, President Biden signed an “Acceptance on Behalf of the United States of America” that, reversed the prior withdrawal, and the United States officially rejoined the Paris Agreement on February 19, 2021. As part of rejoining the Paris Agreement, President Biden announced 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, new 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.

•our quarterly distributions, if any;

•our quarterly or annual earnings or those of other companies in our industry;

•the loss of a large customer;

•announcements by our customers or others regarding our customers or changes in our customers’ credit ratings, liquidity position, leverage profile and/or other financial or credit-related metrics;

•announcements by our competitors of significant contracts or acquisitions;

•changes in accounting standards, policies, guidance, interpretations or principles;

•general economic and geopolitical conditions;

•the failure of securities analysts to cover our common units or changes in financial estimates by analysts; and

•other factors described in these Risk Factors.

•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;

•our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as such decisions are made in good faith;

•our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

•our General Partner will not be in breach of its obligations under the Partnership Agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:

i.approved by the Conflicts Committee, if established, although our General Partner is not obligated to seek such approval;

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;

iii.on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

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.

•decreasing the amount of cash available for distribution on each unit;

•increasing the ratio of taxable income to distributions;

•diminishing the relative voting strength of each previously outstanding unit; and

•causing the market price of the common units to decline.

•we were conducting business in a state but had not complied with that particular state's partnership statute; or

•an investor's right to act with other unitholders to remove or replace our General Partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute control of our business.

In addition, (i) prior to December 15, 2022, distributions on the Series A Preferred Units accumulated and were 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%. 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. As of December 31, 2022, the amount of accrued and unpaid distributions on the Series A Preferred Units was $21.5 million. Unpaid distributions on the Series A Preferred Units will continue to accrue.

•a cyber-attack on a vendor or service provider could result in supply chain disruptions, which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;

•a cyber-attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues;

•a cyber-attack on a communications network or power grid could cause operational disruption, resulting in loss of revenues;

•a deliberate corruption of our financial or operational data could result in events of non-compliance, which could lead to regulatory fines or penalties; and

•business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation or a negative impact on the price of our units.

Fiberspar Corporation. On May 3, 2022, Fiberspar Corporation filed a petition in state court alleging that the Partnership owes Fiberspar $5.0 million or more for orders of pipeline product from Fiberspar. The petition asserts causes of action for breach of contract and suit 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 answer 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.

Global Settlement. On August 4, 2021, the Partnership and several of its subsidiaries entered into agreements to resolve government investigations into the previously disclosed 2015 Blacktail Release, from a pipeline owned and operated by Meadowlark Midstream, which at the time was a wholly owned subsidiary of Summit Investments, (together with Meadowlark Midstream, the “Companies”). The Companies entered into the following agreements to resolve the U.S. federal and North Dakota state governments’ environmental claims against the Companies with respect to the 2015 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, on behalf of the North Dakota Department of Environmental Quality and the North Dakota Game and Fish Department, lodged with the U.S. District Court; (ii) a Plea Agreement with the United 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 Industrial Commission.

Moore Control Systems. Moore Control Systems, Inc. (“MCSI”) initiated an arbitration in December 2020 related to the construction of Summit’s Lane Gas Processing Plant in Eddy County, New 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.

Verdad Resources. Verdad Resources LLC (“Verdad”) filed a complaint in Colorado state court for the district of Weld County against Sterling Energy Investments LLC (“Sterling”), Golden Resources, Inc., and Grasslands Energy Marketing LLC (“Grasslands”) on October 20, 2022, and amended on December 6, 2022 to exclude Golden Resources, Inc. as a defendant. In connection with the 2022 DJ Acquisitions, Sterling and Grasslands became subsidiaries of the Partnership. Verdad claims that Sterling did not have the right to assess marketing fees passed through from Grasslands’ purchase and resale of residue natural gas and natural gas liquids from Sterling. The relief 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.

Highpoint Operating Corporation. Sterling and Highpoint Operating Corporation (“Highpoint”) are parties to a gas gathering agreement (the “Highpoint Agreement”). Sterling sued Highpoint in Colorado state court for the district of Denver County on June 15, 2020, alleging that Highpoint breached the Highpoint Agreement and seeking damages. Highpoint asserted counterclaims alleging that Sterling breached the Highpoint Agreement. In October 2021, after a bench 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 Colorado Court of Appeals granted Sterling’s Motion to Stay Execution of Judgment. The case remains pending before the appeals court. We are unable to predict the final outcome of this matter.

•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.

•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

•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.

As of December 31, 2022, we had 93,039 Subsidiary Series A Preferred Units outstanding and during fiscal year ended December 31, 2022 we made $3.3 million of cash distributions to holders of the Subsidiary A Preferred Units and accrued an additional $1.6 million in 2022 which was subsequently paid in 2023. Additionally, we paid distributions in-kind on our Subsidiary Series A Preferred Units in 2020, 2021 and portions of 2022.

			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
Capital expenditures(1)			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)

•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.

•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.

•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, 2021. The following items are reflected in our financial results for the fiscal year ended 2021:

•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.

•Loss on ECP Warrants. On August 5, 2021, the ECP Entities cashlessly exercised all of their ECP Warrants for an aggregate of 414,447 SMLP common units, net of the exercise price, as calculated pursuant to Section 3(c) of the ECP Warrants (the “ECP Warrant Exercise"). During the year ended December 31, 2021, the Partnership recognized a $13.6 million non-cash loss related to the ECP Warrants.

•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;

•Capital markets availability and cost of capital; and

•Inflation and shifts in operating costs.

Strategic DJ Acquisitions. 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.

Ongoing impact of the current Russia-Ukraine conflict and the international sanctions against Russia on commodity prices. Although the Partnership does not operate in Ukraine, Russia or other parts of Europe, there are certain impacts arising from Russia’s invasion of Ukraine that could have a potential effect on the Partnership, including, but not limited to, volatility in currencies and commodity prices, higher inflation, cost and supply chain pressures and availability and disruptions in banking systems and capital markets. As of the date of filing, there have been no material impacts on the Partnership.

The borrowings under our ABL Facility, which have a variable interest rate, expose us to the risk of increasing interest rates. Additionally, 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 and operating costs. The annual rate of inflation in the United States hit 6.5% in December 2022, one of the highest increases in more than three decades, as measured by the Consumer Price Index. We expect that continued inflation in 2023 will increase our operating costs and the overall cost of capital projects we undertake. While some of our fee arrangements escalate based on changes in price indexes, 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 labor force shortages.

•successful drilling activity within our AMIs;

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

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

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

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

•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.

			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)					*
Volume throughput (1):
Aggregate average daily throughput - natural gas (MMcf/d)			1,208						1,356						(11%)
Aggregate average daily throughput - liquids (Mbbl/d)			62						63						(2%)

*Not considered meaningful

(1)Excludes volume throughput for Ohio Gathering and Double E. For additional information, see the Northeast and Permian sections herein under the caption “Segment Overview for the Years Ended December 31, 2022 and 2021”.

•a volume throughput decrease of 113 MMcf/d for the Northeast segment.

•a volume throughput decrease of 20 MMcf/d for the Piceance segment.

•a volume throughput decrease of 12 MMcf/d for the Permian segment.

•a volume throughput decrease of 1 MMcf/d for the Barnett segment.

•a volume throughput decrease of 2 MMcf/d for the Rockies segment.

•a $14.6 million decrease in the Piceance, primarily due to the expiration of approximately $10.1 million of a customer’s minimum volume commitment and decreased volume throughput;

•an $8.2 million decrease in the Northeast, primarily due to decreased volume throughput,

•a $7.0 million decrease in the Rockies, primarily due to decreased volume throughput and the expiration of a customer’s minimum volume commitment contract in the DJ Basin; and

•a $4.6 million decrease in the Permian, primarily due to the disposition of the Lane G&P System in June 2022.

•a $10.9 million increase in the Rockies reportable segment, primarily due to the 2022 DJ Acquisitions, partially offset by the disposition of Bison Midstream;

•$1.6 million increase in the Piceance reportable segment;

•a $2.2 million increase in the Barnett reportable segment; partially offset by

•an $11.3 million decrease in the Permian reportable segment, primarily due to the disposition of the Lane G&P System in June 2022.

			Northeast
			Year ended December 31,
			2022						2021						Percentage Change
Average daily throughput (MMcf/d)			652						765						(15)%
Average daily throughput (MMcf/d) (Ohio Gathering)			674						526						28%

			Northeast
			Year ended December 31,
			2022						2021						Percentage Change
Revenues:			(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			30,656						27,074
Other			7						—
Segment adjusted EBITDA			$	77,046					$	83,287					(7%)

*Not considered meaningful

			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)%

			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			(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
Adjustments related to capital reimbursement activity			(431)						(1,885)
Gain on asset sales, net			(63)						(56)
Long-lived asset impairment			7,068						5,564
Other			188						56
Segment adjusted EBITDA			$	57,810					$	64,517					(10%)

			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

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

			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
Adjustments related to capital reimbursement activity			(63)						—
Gain on asset sales, net			(13)						—
Long-lived asset impairment			84,516						595
Proportional adjusted EBITDA for Double E			14,762						1,948
Other			(2)						15
Segment adjusted EBITDA			$	18,051					$	6,614					*

			Piceance
			Year ended December 31,
			2022						2021						Percentage Change
Aggregate average daily throughput (MMcf/d)			306						326						(6%)

			Piceance
			Year ended December 31,
			2022						2021						Percentage Change
			(Dollars in thousands)
Revenues:
Gathering services and related fees			$	80,630					$	95,235