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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


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

For the fiscal year ended December 31, 2025


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

For the transition period from to

Commission file number: 001-42201

Summit Midstream Corporation

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of

incorporation or organization)

910 Louisiana Street, Suite 4200

Houston, TX

(Address of principal executive offices)

99-3056990

(I.R.S. Employer

Identification No.)

77002

(Zip Code)

(832) 413-4770

(Registrant’s telephone number, including area code)

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


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.01 per share	SMC	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. o Yes x No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes x No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).x Yes o No

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. x

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.☐

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes x No

The aggregate market value of voting stock held by non-affiliates of the registrant as of June 30, 2025 was $300,292,924.

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:


Class						As of March 15, 2026
Common Stock, par value $0.01 per share						12,440,219
Class B Common Stock, par value $0.01 per share						6,524,467

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement relating to its 2026 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2025, are incorporated by reference into Part III of this Annual Report on Form 10-K where indicated.

TABLE OF CONTENTS


PART I		15
Item 1.	Business.	15
Item 1A.	Risk Factors.	32
Item 1B.	Unresolved Staff Comments.	55
Item 1C.	Cybersecurity Risk Management, Strategy, and Governance	55
Item 2.	Properties.	56
Item 3.	Legal Proceedings.	57
Item 4.	Mine Safety Disclosures.	57

PART II		58
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	58
Item 6.	[Reserved]	60
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	61
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk.	85
Item 8.	Financial Statements and Supplementary Data.	86
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	126
Item 9A.	Controls and Procedures.	126
Item 9B.	Other Information.	128
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections .	129

Part III		130
Item 10.	Directors, Executive Officers and Corporate Governance.	130
Item 11.	Executive Compensation.	130
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	130
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	130
Item 14.	Principal Accounting Fees and Services.	130

Part IV		131
Item 15.	Exhibits, Financial Statement Schedules.	131
Item 16.	Form 10-K Summary.	135

Signature Page		136

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officers and employees during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings, or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries are also forward-looking statements. These forward-looking statements involve various risks and uncertainties, including, but not limited to, those described in Item 1A. Risk Factors included in this Annual Report on Form 10-K (this “Annual Report”).

Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this paragraph. These risks and uncertainties include, among others:

•our decision whether to pay, or our ability to grow, our cash dividends;

•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, freshwater deliveries, and produced water volumes produced within proximity of our assets;

•failure or delays by our customers in achieving expected production in their natural gas, crude oil and produced water projects;

•competitive conditions in our industry and their impact on our ability to connect hydrocarbon supplies to our gathering and processing assets or systems;

•actions or inactions taken or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers;

•our ability to divest of certain of our assets to third parties on attractive terms, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets;

•the ability to attract and retain key management personnel;

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

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

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

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

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

•the current and potential future impact of pandemics on our business, results of operations, financial position, or cash flows;

•operational risks and hazards inherent in the transmission, 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 transmission, 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;

•the effects of litigation;

•interest rates;

•changes in general economic conditions; and

•certain factors discussed elsewhere in this report.

Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of our common stock, Series A Preferred Stock and 2029 Secured Notes.

The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this document may not in fact occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.

Risk Factors Summary

This summary briefly lists the principal risks and uncertainties facing our business, which are only a select portion of those risks. A more complete discussion of those risks and uncertainties is set forth in Part I, Item 1A of this Annual Report. Additional risks not presently known to us or that we currently deem immaterial may also affect us. If any of these risks occur, our business, financial condition, or results of operations could be materially and adversely affected.

Our business is subject to the following principal risks and uncertainties:

Risks Related to 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 dividends to holders of our Series A Preferred Stock and common stock.

•We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of our customers could materially adversely affect our revenues, cash flows, and results of operations.

•We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties and any material nonpayment or nonperformance by one or more of these parties could materially adversely affect our financial and operating results.

•Significant prolonged weakness in natural gas, NGL and crude oil prices could reduce throughput on our systems and materially adversely affect our revenues and results of operations.

•Because of the natural decline in production from our customers' existing wells, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes that we gather and process could materially adversely affect our business and operating results.

•If our customers do not increase the volumes they provide to our gathering systems, our results of operations and financial condition may be materially adversely affected.

•Certain of our gathering and processing agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.

•We have not obtained independent evaluations of all of the reserves connected to our gathering systems; therefore, in the future, customer volumes on our systems could be less than we anticipate.

•Our industry is highly competitive, and increased competitive pressure could materially adversely affect our business and operating results.

•We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.

•If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, our revenues and cash flows could be materially adversely affected.

•We have had and continue to have discussions with unaffiliated third parties with respect to potential strategic

transactions.

•Tariffs and other trade measures could adversely affect our business, results of operations, financial position, and cash flows.

Risks Related to Our Finances

•Limited access to and/or availability of the commercial bank market or debt and equity capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements.

•We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects, and may limit our flexibility to obtain financing 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 the New Permian Transmission Facility, the indenture governing the 2029 Secured Notes and the Amended and Restated ABL Facility could materially adversely affect our business, financial condition, results of operations and ability to make cash dividends.

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

•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.

Regulatory and Environmental Policy Risks

•We settled a matter that was previously under investigation by federal and state regulatory agencies regarding a pipeline rupture and release of produced water by one of our subsidiaries. The resulting compliance requirements of the settlement may impact our results of operations or cash flows.

•We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. As a result, we may be required to expend significant funds for legal defense or to settle claims. Any such loss, if incurred, could be material.

•A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenues to decline or our operation and maintenance expenses to increase.

•Increased regulation of hydraulic fracturing could result in reductions or delays in customer production, which could materially adversely impact our revenues.

•We are subject to FERC jurisdiction, federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements and state, and local regulation and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced.

•We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.

Risks Related to the Common Stock and Series A Preferred Stock

•The price of the common stock or Series A Preferred Stock may experience volatility.

•Our Governing Documents contain provisions that may make it difficult for a third party to acquire control of the Company, even if a change in control would result in the purchase of your shares of common stock or Series A Preferred Stock at a premium to the market price or would otherwise be beneficial to you.

•We do not expect to pay dividends on our common stock for the foreseeable future.

•The value of our common stock may be diluted by future equity issuances and shares eligible for future sale may have adverse effects on our share price.

Risks Related to Tax

•The Company is a holding company, and its principal asset is our ownership of Partnership Common Units. Accordingly, we are dependent upon distributions from SMLP to pay dividends, if any, and to pay taxes and other expenses.

•The Tall Oak Acquisition and subsequent changes in stock ownership of the Company (including upon the redemption or exchange of the shares of Class B Common Stock and associated Partnership Common Units for common stock) may trigger a limitation on the utilization of net operating loss carryforwards of the Company.

•If SMLP were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, the Company and SMLP might be subject to potentially significant tax inefficiencies.

ORGANIZATIONAL CHART

The following chart provides a summarized view of our legal entity structure as of December 31, 2025:

COMMONLY USED OR DEFINED TERMS


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, which were fully repaid on August 16, 2024
2026 Secured Notes			Summit Holdings’ and Finance Corp.’s 8.500% senior secured second lien notes due October 2026, which were fully repaid on October 15, 2024


2026 Secured Notes Asset Sale Offer			the cash tender offer by Summit Holdings and Finance Corp. to purchase up to $215.0 million aggregate principal amount of the outstanding 2026 Secured Notes, pursuant to which $6.9 million aggregate principal amount of the 2026 Secured Notes was tendered and validly accepted, which settled on June 6, 2024
2026 Secured Notes Tender Offer			the cash tender offer by Summit Holdings and Finance Corp. to purchase any and all of the outstanding 2026 Secured Notes, pursuant to which $649.8 million aggregate principal amount of the 2026 Secured Notes was tendered and validly accepted, which settled on July 26, 2024
2026 Unsecured Notes			Summit Holdings’ and Finance Corp.’s 12.00% senior unsecured notes due October 2026, which were fully repaid on June 24, 2024
2029 Secured Notes			Summit Holdings’ 8.625% Senior Secured Second Lien Notes due October 2029
A&R Partnership Agreement			the Sixth Amended and Restated Agreement of Limited Partnership of SMLP, by and among the Company, the General Partner, and Tall Oak Parent, dated as of December 2, 2024
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
ABL Facility			the asset-based lending credit facility governed by the ABL Agreement
Additional 2029 Secured			the $250,000,000 in aggregate principal amount of 2029 Secured Notes issued on January 10, 2025
Amended and Restated ABL Agreement			Amended and Restated Loan and Security Agreement, dated as of July 26, 2024, among Summit Holdings, as borrower, SMLP and certain subsidiaries from time to time party thereto, as guarantors, Bank of America, N.A., as agent, and Bank of America, N.A., Royal Bank of Canada, Regions Capital Markets, TD Securities (USA) LLC, JPMorgan Chase Bank, N.A, Citizens Bank, N.A., and Truist Bank, as joint lead arrangers and joint bookrunners
Amended and Restated ABL Facility			the asset-based lending credit facility governed by the Amended and Restated ABL Agreement


ABL Facility			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
ASC			Accounting Standards Codification
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
ASU			Accounting Standards Update
Audit Committee			the audit committee of the Board of Directors
Bbl			one barrel; used for crude oil and produced water and equivalent to 42 U.S. gallons
Bcf			one billion cubic feet
Bcf/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
BLM			Bureau of Land Management
Board of Directors			the board of directors of Summit Midstream Corporation
CAA			Clean Air Act

CCPA			California Consumer Privacy Act, as amended by the California Privacy Rights Act
CEA			Commodity Exchange Act
CERCLA			Comprehensive Environmental Response, Compensation, and Liability Act
CFTC			Commodity Futures Trading Commission

Class B Common Stock			Class B common stock of the Company, par value $0.01 per share
common stock			common stock of the Company, par value $0.01 per share
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

Corporate Reorganization			the August 1, 2024 consummation of a transaction that resulted in SMLP becoming a wholly owned subsidiary of a newly formed Delaware corporation, Summit Midstream Corporation (taxed as a C-corporation)
Corps			U.S. Army Corps of Engineers
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
DOI			U.S. Department of the Interior
DOJ			U.S. Department of Justice
DOT			U.S. Department of Transportation
Double E			Double E Pipeline, LLC
Double E Pipeline			a 135 mile, 1.6 Bcf/d, FERC-regulated interstate natural gas transmission pipeline provides transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha hub in Texas


Dth/d			one million British Thermal Units per day

EPA			Environmental Protection Agency
Epping			Epping Transmission Company, LLC
Epping Pipeline			an interstate crude oil pipeline in North Dakota, owned and operated by Epping
EPS			earnings or loss per share

ESA			Endangered Species Act
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
Fundare			Fundare Resources Company, LLC
GAAP			accounting principles generally accepted in the United States of America
GDPR			European Union General Data Protection Regulation
General Partner			Summit Midstream GP, LLC
GHG			greenhouse gas(es)



Grand River			Grand River Gathering, LLC


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 as reaffirmed and modified by the Notice of Reaffirmation
IRA			Inflation Reduction Act
IRS			Internal Revenue Service
IT			information technology
LIBOR			London Interbank Offered Rate
LNG			liquefied natural gas
MAOP			Maximum Allowable Operating Pressure
Mbbl/d			one thousand barrels per day

MDTQ			maximum daily transportation quantity
Meadowlark Midstream			Meadowlark Midstream Company, LLC
MMBtu			metric 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
Moonrise			Moonrise Midstream, LLC
Moonrise Acquisition			the acquisition of Moonrise from Fundare for approximately $90.0 million, consisting of (i) a $70.0 million cash payment and (ii) the issuance of 462,265 shares of common stock of the Company
Mountaineer Midstream			Mountaineer Midstream Company, LLC
Mountaineer Transaction			the sale of the Mountaineer Midstream system to Antero Midstream LLC for a cash sale price of $70 million, subject to customary post-closing adjustments
MVC			minimum volume commitment
NAAQS			national ambient air quality standard


NEPA			National Environmental Policy Act
New Permian Transmission Facility			the March 16, 2026, $440.0 million refinancing of the Permian Transmission Credit Facilities and the Permian Term Loan Facility, in the form of a new term loan facility
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
Notice of Reaffirmation			Notice and Reaffirmation of Intercreditor Agreement, dated as of July 26, 2024, 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 and collateral agent for the initial second lien claimholders, acknowledged and agreed to by Summit Holdings and the other grantors referred to therein
NYSE			New York Stock Exchange

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


OT			operational technology
Partnership Common Units			common units representing limited partner interests of SMLP
PHMSA			Pipeline and Hazardous Materials Safety Administration
play			a proven geological formation that contains commercial amounts of hydrocarbons

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 Facilities			the credit facilities governed by the Credit Agreement, dated as of March 8, 2021, among Summit Permian Transmission, 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
ppb			parts per billion
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


SEC			U.S. 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) stock-based and noncash compensation, (vii) impairments and (viii) other noncash expenses or losses, less other noncash income or gains
Series A Certificate of Designation			the Certificate of Designation of Series A Floating Rate Cumulative Redeemable Perpetual Preferred Stock of the Company
Series A Preferred Stock			Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock issued by the Company
Series A Preferred Units			Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units issued by SMLP
shortfall payment			the payment received from a counterparty when its volume throughput does not meet its MVC for the applicable period
SMC LTIP			Summit Midstream Corporation 2024 Long-Term Incentive Plan
SMLP			Summit Midstream Partners, LP
SMLP LTIP			SMLP 2022 Long-Term Incentive Plan


SOFR			Secured Overnight Financing Rate
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 Permian Transmission			Summit Permian Transmission, LLC
Summit Utica			Summit Midstream Utica, LLC
Tall Oak			Tall Oak Midstream Operating, LLC
Tall Oak Acquisition			the consummation of the transaction contemplated by the Tall Oak Business Contribution Agreement


Tall Oak Business Contribution Agreement			the Business Contribution Agreement, dated as of October 1, 2024, by and among the Company, SMLP, and Tall Oak Parent, pursuant to which Tall Oak Parent contributed all of its equity interests in Tall Oak to SMLP in exchange for total consideration equal to $425.0 million
Tall Oak Parent			Tall Oak Midstream Holdings, LLC
Tcfe			the equivalent of one trillion cubic feet
the Company			Summit Midstream Corporation and its subsidiaries
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


U.S.			United States of America
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
Up-C tax structure			a corporate structure that consists of a public C Corporation (PubCo) and an operating partnership (OpCo), which acts as the subsidiary.
Utica Sale			the sale of Summit Utica to a subsidiary of MPLX LP for a cash sale price of $625.0 million, subject to customary post-closing adjustments
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

PART I

ITEM 1. BUSINESS

Summit Midstream Corporation, a Delaware corporation (including its subsidiaries, collectively, “we”, “our”, “us”, “SMC”, or “the Company”), is a value-driven company focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental United States. The Company’s business activities are primarily conducted through various operating subsidiaries, each of which is owned or controlled by its subsidiary holding company, Summit Holdings.

The Company was incorporated under the laws of the State of Delaware on May 14, 2024 for the purpose of effecting the Corporate Reorganization of Summit Midstream Partners, LP, a Delaware master limited partnership, in which the Company was incorporated to serve as the new parent holding company of SMLP. The Company’s common stock is listed on the New York Stock Exchange under the ticker symbol “SMC.” SMLP was formed in May 2012, and prior to August 1, 2024, SMLP’s common units were listed on NYSE under the ticker symbol “SMLP.”

The Company’s executive offices are located at 910 Louisiana Street, Suite 4200, Houston, Texas 77002, and can be reached by phone at 832-413-4770. The Company also maintains regional field offices in close proximity to its areas of operation to support the operation and development of the Company’s midstream assets.

Our Business Strategies

We operate a differentiated midstream platform that is built for long-term, sustainable value creation. Our integrated assets are strategically located in production basins, including the Williston Basin, DJ Basin, Barnett Shale, Piceance Basin, Permian Basin, and the Arkoma Basin. Our primary business objective is to maximize cash flow and provide cash flow stability for our stakeholders while growing prudently and profitably. We intend to accomplish this objective by executing the following strategies:

•Capital structure optimization. We seek to maximize stakeholder value. Our capital structure currently consists of common equity (including the Company’s common stock and Class B common stock and associated Partnership Common Units of SMLP), 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 our 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, asset acquisitions (such as the Moonrise Acquisition), or asset divestitures with the objective of increasing long-term stakeholder value.

•Portfolio management. We seek to maximize stakeholder value by strategically managing our portfolio of midstream assets and allocating capital based on appropriate risk-informed cash flow assumptions. This may include value enhancing acquisitions (such as the Moonrise Acquisition) or opportunistic divestitures, re-allocation of capital to new or existing areas, and development of joint ventures (such as Double E) involving our existing midstream assets or new investment opportunities.

•Maintaining 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.

Recent Developments and Highlights

The following is a brief listing of significant developments and highlights for the year ended December 31, 2025, and up through the filing date of this Form 10-K. Additional information regarding these items may be found elsewhere in this Annual Report.

•Moonrise Acquisition. On March 10, 2025, we completed the acquisition of Moonrise Midstream, LLC (the “Moonrise Acquisition”) from Fundare Resources Company, LLC for approximately $90.0 million, consisting of (i) a $70.0 million cash payment and (ii) the issuance of 462,265 shares of our common stock. The Moonrise Acquisition expanded our existing footprint in the DJ Basin and provides our DJ Basin customers with additional processing capacity and flow assurance. The Moonrise Acquisition represents the continued execution of our consolidation efforts in the DJ Basin.

•Resumption of Series A Preferred Stock Dividend. On February 28, 2025, we announced that our Board of Directors approved the resumption of a quarterly cash dividend on our Series A Preferred Stock. During 2025, we paid $13.4 million of dividends on our Series A Preferred Stock. In March 2026, the Company’s Board of Directors approved the payment of any and all accrued and unpaid dividends on the Company’s Series A Preferred Stock, including the $46.6 million of accrued and unpaid dividends outstanding as of December 31, 2025. The Company expects to pay the accrued and unpaid dividends on the Series A Preferred Stock upon satisfaction of certain notice requirements, which the Company expects to complete by March 31, 2026.

•Integration of acquired businesses. We spent significant time throughout 2025 integrating both the Moonrise Acquisition and the Tall Oak Acquisition into our existing operations. Activities included conforming the acquired businesses to our operating policies and procedures and attaining acquisition synergies, including rationalizing compression equipment.

•Commercial success. During 2025, we executed several new commercial agreements with both existing and new customers, including a 10-year extension of a gathering agreement with a key customer in the Williston Basin and a new 15-year agreement with a key customer in the Williston Basin. Additionally, in 2025 Double E executed a new precedent agreement for 100 MMcf/d of firm capacity tied to an expansion of a processing plant located in Lea County, New Mexico. Subsequent to December 31, 2025, Double E (i) executed an agreement which includes 210 MMcf/d of firm capacity, with the first tranche of volume set to begin flowing in the fourth quarter of 2026, and an 11-year term and (ii) executed an agreement which includes 230 MMcf/d of firm capacity, with the first tranche of volume set to begin flowing in the fourth quarter of 2027, and over an 11-year term.

•Summit Permian Transmission and Permian Holdco Refinancing. In March 2026, we completed a $440.0 million refinancing of our Permian Transmission Credit Facilities in the form of the New Permian Transmission Facility with a maturity in March 2031. The New Permian Transmission Facility consists of $340.0 million in initial term loan commitments, $50.0 million in delayed draw commitments, and a $50.0 million uncommitted incremental facility. The use of proceeds of the New Permian Transmission Facility includes, among other things, repayment in full of the Permian Transmission Credit Facilities and redemption in full of the outstanding Subsidiary Series A Preferred Units. In connection with the New Permian Transmission Facility, Summit Permian Transmission entered into a $7.0 million letter of credit arrangement.

Our Midstream Assets

Our midstream assets primarily gather natural gas produced from pad sites, wells and central receipt points connected to our systems. Gathered natural gas volumes are then compressed, dehydrated, treated, and/or processed for delivery to downstream pipelines serving end users. We also contract with producers to gather crude oil and produced water from wells connected to our systems for delivery to downstream pipelines and to third-party rail terminals in the case of crude oil and to third-party disposal wells in the case of produced water. We generally refer to most of the services our systems provide as gathering services. We also provide natural gas transmission services via the Double E Pipeline, a long-haul natural gas pipeline in which we indirectly own a 70% equity interest and serve as the pipeline’s operator. The Double E Pipeline provides natural gas transportation services from multiple receipt points in the Permian Basin to various delivery points in and around the Waha hub in Texas.

Reportable Segments. As of December 31, 2025, 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 fees for gathering or processing hydrocarbons, gathering produced water, or transporting residue natural gas.

•Rockies – Includes our 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 Piceance and Mid-Con 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 fees for gathering and/or processing natural gas.

•Mid-Con – Includes our midstream assets located in the Barnett Shale and the Arkoma Basin.

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

Industry Overview and Commercial Arrangements

We compete with other midstream companies, producers, and intrastate and interstate pipelines. Competition for volumes is primarily based on reputation, commercial terms, acreage dedications, service levels, access to end-use markets, geographic proximity of existing assets to a producer’s acreage, and available gathering and processing capacity. We may also face competition to gather production outside of our AMIs and attract producer volumes to our gathering systems.

We earn revenue by providing gathering, compression, treating and/or processing services pursuant to primarily long-term and fee-based gathering and processing agreements with some of the largest and most active producers in North America. Through our equity method investment in the Double E Pipeline, we earn revenue by providing high pressure transportation services, as both firm and interruptible service, for residue natural gas in the Permian Basin. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure.

The significant features of our transportation and gathering and processing agreements, and the gathering and transportation systems to which they relate, are discussed in more detail below. For additional operating and financial performance information, on a consolidated basis and by reportable segment, see the “Results of Operations” section in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Areas of Mutual Interest. The vast majority of our gathering and processing agreements contain AMIs, some of which extend through 2040. The AMIs generally require that any production by our customers within the AMIs will be gathered and/or processed by our assets. In general, our customers have not leased acreage that cover our entire AMIs but, to the extent that they have leased acreage within our AMI, or lease additional acreage within our AMIs, any production from wells within that AMI will be dedicated to our systems.

Under certain of our gathering agreements, we have agreed to construct pipeline laterals to connect our gathering systems to producer pad sites located within the AMI. However, in certain circumstances we may choose not to pursue a pad connection opportunity presented by a customer if we believe that the investment would not meet our internal return expectations. Under this scenario, the customer may, in certain circumstances, construct the gathering infrastructure itself and sell it to us at a price equal to their cost plus an applicable profit margin, or, in some cases, we may release the relevant acreage dedication from the AMI.

Our AMIs cover approximately 5.9 million surface acres in the aggregate.

Minimum Volume Commitments. Certain of our gathering and/or processing agreements contain MVCs which, like AMIs, benefit from the development and ongoing operation of a gathering system because they provide a minimum contracted monthly or annual revenue stream. Some of our MVCs, including those of affiliates, extend through 2031. To the extent a customer does not meet its contractual MVC, it is obligated to make an MVC shortfall payment to us to cover the shortfall of required volume throughput not shipped or processed, either on a monthly or annual basis. We have designed our MVC provisions to ensure that we will generate a minimum amount of revenue from each customer over the life of the associated gathering and/or processing agreement, by either collecting gathering or processing fees on actual throughput or from cash payments to cover any MVC shortfall.

As of December 31, 2025, we had remaining MVCs totaling 0.1 Tcfe, our MVCs had a weighted-average remaining life of 2.0 years, and these MVC’s average approximately 43 MMcfe/d through 2029.

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 2025, aggregate natural gas volume throughput averaged 904 MMcf/d and crude oil and produced water volume throughput averaged 73 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, Piceance and Mid-Con segments, (ii) the sale of natural gas we retain from certain Mid-Con customers, (iii) the sale of condensate we retain from our gathering services in the Rockies, Mid-Con 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, 2025, these additional activities accounted for approximately 48% of total revenues.

Equity Method Investment – Double E. We have an equity method investment in the Double E Pipeline, a 1.6 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 operator of the joint venture and have made all required capital contributions to Double E. As of December 31, 2025, the Company owns a 70% interest in Double E. A subsidiary of ExxonMobil Corporation is our joint venture partner and owns the remaining 30%.

Equity Method Investment – Ohio Gathering. Through March 22, 2024, we owned an equity method investment in Ohio Gathering, which was comprised of a natural gas gathering system and condensate stabilization facility located in the core of the Utica Shale in southeastern Ohio. On March 22, 2024, we completed the disposition of Summit Utica to a subsidiary of MPLX LP for a cash sale price of $625.0 million, subject to customary post-closing adjustments. Summit Utica was the owner of (i) approximately 36% of the issued and outstanding equity interests in OGC, (ii) approximately 38% of the issued and outstanding equity interests in OCC (together with OGC, Ohio Gathering) and (iii) midstream assets located in the Utica Shale. Ohio Gathering was the owner of a natural gas gathering system and condensate stabilization facility located in Belmont and Monroe counties in the Utica Shale in southeastern Ohio.

Overview of our Segments

The following provides an overview of our reportable segments as of December 31, 2025.

Rockies.

The following table provides operating information regarding our Rockies reportable segment as of December 31, 2025.


	Aggregate throughput capacity - liquids (Mbbl/d)	Aggregate throughput capacity - natural gas (MMcf/d)	Average daily MVCs through 2030 (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	7.3	n/a
Rockies - DJ (1)	146	335	9	39	5.9	2.6

______________________________________________

(1)Capacity of 335 MMcf/d represents nameplate processing capacity. Operational capacity is estimated at approximately 235 MMcf/d. Weighted average remaining life excludes interruptible off-load contracts.

AMIs for the Rockies reportable segment total approximately 2.6 million surface acres in the aggregate.

Our Rockies reportable segment is comprised of our Polar and Divide system and the Niobrara G&P system.

Polar and Divide system. The Polar and Divide system, which is located primarily in Williams and Divide counties in northwestern North Dakota, owns, operates, and is currently developing crude oil and produced water gathering systems and transmission pipelines serving multiple customers that are targeting crude oil production from the Bakken and Three Forks shale formations. The Polar and Divide system is underpinned by long-term, fee-based gathering agreements, which include acreage dedications. Chord Energy Corporation, Kraken Resources, Formentera, and Zavanna LLC are the key customers of the Polar and Divide system. Crude oil that is gathered by the Polar and Divide system is delivered to interconnects with (i) the Dakota Access Pipeline, (ii) the COLT Hub rail facility and (iii) Enbridge Inc’s North Dakota Pipeline System. Produced water is delivered to third-party or producer owned disposal facilities.

Niobrara G&P system. The Niobrara G&P system is located 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. As of December 31, 2025, Bison Oil and Gas IV, Chevron Corporation, SM Energy Company, Fundare and Verdad Resources are the key customers of the Niobrara G&P system and have underpinned our volume throughput with acreage dedications and MVCs.

The Niobrara G&P system operates a low-pressure associated natural gas gathering system, and natural gas processing plants with processing capacity of up to 335 MMcf/d.

Residue gas can be delivered to the Cheyenne Plains, Colorado Interstate Gas, Tallgrass Interstate Gas Transmission, Trailblazer Pipeline and Southern Star and processed NGLs are delivered to the Overland Pass Pipeline and the P66 NGL System.

Additionally, the system has discrete freshwater infrastructure that consists of 19 water wells and other infrastructure to provide its customers with up to approximately 55,000 barrels per day of fresh water for well completion activities. The crude gathering system includes approximately 55 miles of gathering pipeline with delivery into the Pony Express pipeline.

Permian.

The following table provides operating information regarding our Permian reportable segment as of December 31, 2025.


	Aggregate throughput capacity (MMcf/d)	Average daily MVCs through 2030 (MMcf/d)	Remaining MVCs (Bcf)	Weighted-average remaining contract life (Years)	Weighted-average remaining MVC life (Years)
Double E (1)	1,600	1,115	2,621	6.4	6.6

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(1) Presented on a gross basis. Existing MVC’s contractually increased to 1.0 Bcf/d beginning in November 2024. As of December 31, 2025, we owned a 70% interest in Double E.

Double E. The Double E Pipeline is a 135 mile 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 1.1 Bcf/d of long-term take-or-pay contracts with ExxonMobil Corporation, ConocoPhillips Company, EOG Resources Inc. and Matador Resources Company.

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 MDTQs 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 63% of its estimated capacity of 1,600,000 Dth/d.

Volume throughput is received from multiple processing plants, including ONEOK’s Lobo plant, San Mateo’s Marlan plant, XTO Energy’s Cowboy plant, Targa Resources Corp.’s Roadrunner plant, San Mateo’s Black River plant, and Energy Transfer’s Carlsbad plant, EOG Resources Inc.’s Janus plant and the Janus Processing Plant. In 2025, Double E executed a new precedent agreement with Producers Midstream for 100 MMcf/d of firm capacity on the Double E Pipeline with an expected in-service date during the fourth quarter of 2026 and a 10-year term.

Subsequent to December 31, 2025, Double E (i) executed an agreement which includes 210 MMcf/d of firm capacity, with the first tranche of volume set to begin flowing in the fourth quarter of 2026, and an 11-year term and (ii) executed an agreement which includes 230 MMcf/d of firm capacity, with the first tranche of volume set to begin flowing in the fourth quarter of 2027, and over an 11-year term.

We own 70% of Double E and operate the pipeline.

Mid-Con.

The following table provides operating information regarding our Mid-Con reportable segment as of December 31, 2025.

Throughput capacity (MMcf/d)

Average daily MVCs through 2030 (MMcf/d)

Remaining MVCs (Bcf)

Weighted-average remaining contract life (Years)

Weighted-average remaining MVC life (Years)

Mid-Con

890

n/a

7.1

n/a

AMIs for the Mid-Con reportable segment cover approximately 2.9 million surface acres.

Our Mid-Con reportable segment is comprised of the DFW Midstream and the Tall Oak systems.

DFW Midstream system. The DFW Midstream system is primarily located in southeastern Tarrant County, in north-central Texas near the Dallas-Fort Worth metroplex. 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 long-term, fee-based gathering agreements with TotalEnergies Gas & Power North America, Inc. and other customers. TotalEnergies Gas & Power North America, Inc. is the key customer for DFW Midstream.

The DFW Midstream system includes natural gas gathering pipelines located under both private and public property and is partially located along existing electric transmission corridors. Compression on the system is powered by electricity. To offset the costs we incur to operate the system’s electric-drive compressors, we either pass through a portion of the power expense to our customers or retain and sell a fixed percentage of the natural gas that we gather.

The DFW Midstream system currently has five primary interconnections with third-parties, primarily intrastate pipelines. These interconnections enable us to connect our customers, directly or indirectly, with the major natural gas market hubs in Texas and Louisiana.

Tall Oak system. Following the Tall Oak Acquisition, we operate assets in central Oklahoma. Gathering and processing services are provided pursuant to long-term, primarily fee-based contracts with producers, that are primarily targeting liquids-rich natural gas production from the Woodford and Caney formations. Volume throughput on the Tall Oak system is underpinned by acreage dedications and Calyx Energy is the key customer.

The Tall Oak system’s residue gas has access to MarkWest’s Arkoma Connector and Energy Transfer’s Enable Oklahoma Intrastate Transmission and Enable Gas Transmission connections. NGL’s have access to ONEOK’s NGL system and Targa’s Grand Prix pipeline.

Piceance.

The following table provides operating information regarding our Piceance reportable segment as of December 31, 2025.


	Aggregate throughput capacity (MMcf/d)	Average daily MVCs through 2030 (MMcf/d)	Remaining MVCs (Bcf)	Weighted-average remaining contract life (Years)	Weighted-average remaining MVC life (Years)
Piceance	1,259	26	48	7.5	0.7

AMIs for the Piceance reportable segment cover approximately 434,000 surface acres in the aggregate.

Our Piceance reportable segment is comprised of our Grand River gathering system.

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, QB Energy, and Flywheel Energy. Volume throughput on the Grand River system is underpinned with acreage dedications and MVCs. The Grand River system is primarily a low-pressure gathering system located in western Colorado that gathers natural gas produced from directional wells targeting the liquids-rich Mesaverde formation. The Grand River system also gathers natural gas produced from the Mancos and Niobrara shale formations. Natural gas gathered and/or processed on the Grand River system is compressed, dehydrated, processed, and/or discharged to downstream pipelines serving (i) the Meeker Processing Complex and (ii) the Williams Processing Complex. Residue gas has access to multiple pipelines and end markets. In addition, certain of our gathering agreements with our customers on the Grand River system permit us to retain, and monetize for our own account, condensate volumes that naturally discharge from the liquids-rich natural gas as it moves across our system.

Northeast.

During the year ended December 31, 2024, we divested of our Northeast operations which consisted of midstream assets located in the Marcellus shale play and midstream assets located in the Utica shale play together with our previously owned equity method investment in Ohio Gathering that was focused on the Utica Shale.

Our Customers

The systems that we operate and/or have significant ownership interests in have a diverse group of customers and counterparties comprising affiliates and/or subsidiaries of some of the largest natural gas and crude oil producers in North America.

Regulation of the Natural Gas and Crude Oil Industries

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

Regulation of Crude Oil and Natural Gas Exploration, Production and Sales. Sales of crude oil and NGLs are not currently regulated and are transacted at market prices. In 1989, the U.S. Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas. FERC, which has the authority under the NGA to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to its regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or FERC (with respect to the resale of gas in interstate commerce), however, could re-impose price controls in the future.

Exploration and production operations are subject to various types of federal, state, and local regulation, including, but not limited to, permitting, well location, methods of drilling, well operations and conservation of resources. While these regulations do not directly apply to our business, they may affect our customers’ ability to produce natural gas.

Regulation of the Gathering and Transportation of Natural Gas and Crude Oil. We believe that the majority of our natural gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC. Our Double E Pipeline, which is an interstate natural gas pipeline located in New Mexico and Texas, and the Epping Pipeline, an interstate crude oil pipeline located in North Dakota and owned and operated by Epping, are subject to FERC’s jurisdiction and oversight pursuant to FERC’s authority under the NGA and the ICA, respectively. Epping and Double E have tariffs on file with FERC.

In addition to approving and regulating the construction and operation of interstate natural gas pipelines, FERC also regulates such pipelines’ rates and terms and conditions of service, including transportation service agreements and negotiated rate agreements.

Under FERC’s ICA jurisdiction, rates for interstate movements of liquids by pipelines are currently regulated primarily through an annual indexing methodology, under which pipelines increase or decrease their existing rates in accordance with a FERC-specified adjustment that sets a rate ceiling. This adjustment, which may be positive or negative in a given year, is subject to review every five years. FERC recently initiated the proceeding to set the index for the five year period commencing on July 1, 2026. FERC has proposed to use the producer price index for finished goods minus 1.42%. This proceeding is currently pending.

Under current FERC regulations, liquids pipelines can request a rate increase that exceeds the rate obtained through the indexing methodology by using a cost-of-service approach, but a pipeline must establish that a substantial divergence exists between its actual costs and the rates resulting from the indexing methodology.

The ICA permits interested persons to challenge proposed new or changed rates and authorizes FERC to suspend the effectiveness of such rates for up to seven months and investigate such rates. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rate during the term of the investigation. FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Under certain circumstances, FERC could limit Epping’s ability to set rates based on costs or could order reduced rates and reparations to complaining shippers for up to two years prior to the date of a complaint. FERC also has the authority to change terms and conditions of service if it determines that they are unjust and unreasonable or unduly discriminatory or preferential. The ICA also imposes potential criminal liability for certain violations of the statute.

FERC has jurisdiction over, among other things, the construction, ownership and commercial operation of pipelines and related facilities used in the transportation and storage of natural gas in interstate commerce, including the modification, extension, enlargement, and abandonment of such facilities. FERC also has jurisdiction over the rates, charges and term and conditions of service for the transportation and storage of natural gas in interstate commerce. With respect to transportation rates, FERC exercises its ratemaking authority by applying cost-of-service principles to limit the maximum and minimum levels of tariff-based recourse rates; however, it also allows for discounted or negotiated rates as an alternative to cost-based rates. In addition, FERC regulations also restrict interstate natural gas pipelines from sharing certain transportation or customer information with marketing affiliates and require that the transmission function personnel of interstate natural gas pipelines operate independently of the marketing function personnel of the pipeline or its affiliates.

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. 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.

Intrastate pipelines, which may include some pipelines that perform gathering functions, may be subject to safety regulation by the DOT, although typically state regulatory authorities (operating under a federal certification) perform this function. State regulatory authorities also have jurisdiction over the rates and practices of intrastate pipelines and gathering systems, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight of gathering systems and intrastate pipelines varies from state to state. In Texas, we are regulated as a gas utility and have filed tariffs with the Railroad Commission of Texas to establish rates and terms of service for our DFW Midstream system assets. We have not been required to file tariffs in the other states in which we operate, although we are required to submit shape files and other information regarding the location and construction of underground gathering pipelines in North Dakota. The states in which we operate have adopted complaint-based regulation that allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve access issues and rate grievances, among other matters. State authorities in the states in which we operate generally have not initiated investigations of the rates or practices of gathering systems or intrastate pipelines in the absence of a complaint. State regulation of intrastate pipelines continues to evolve and may become more stringent in the future.

Natural gas, crude oil and produced water production, gathering and transportation, including the construction of new gathering facilities and expansion of existing gathering facilities may also be subject to local regulation, such as approval and permit requirements.

Statutory Compliance and Anti-Market Manipulation Rules. We are subject to the anti-market manipulation and penalty provisions in the NGA and the NGPA, as amended by the Energy Policy Act of 2005, which authorize FERC to impose fines of up to approximately $1.5 million per day per violation of the NGA, the NGPA, or their implementing rules, regulations and orders, subject to future adjustments for inflation. In addition, the FTC holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to approximately $1.5 million per violation, subject to future adjustment for inflation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The CFTC is directed under the CEA to prevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to statutory authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of approximately $1.5 million per day per violation, subject to future adjustment for inflation, or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation.

Safety and Maintenance. We are subject to regulation by the DOT, which establishes federal safety standards for the design, construction, operation and maintenance of natural gas and crude oil pipeline facilities. In the Pipeline Safety Act of 1992, Congress expanded the DOT’s regulatory authority to include regulated gathering lines that had previously been exempt from federal jurisdiction. Additional legislation has been passed over the years to reauthorize federal funding for federal pipeline

programs, increase penalties for safety violations and establish additional safety requirements. For example, in December 2020, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020 became law, reauthorizing PHMSA for funding through 2023 and requiring, among other things, rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual and pressure control recordkeeping requirements for gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines. Legislation is currently pending to extend the reauthorization of PHMSA.

The DOT has delegated the implementation of pipeline safety requirements to PHMSA, which has adopted and enforces safety standards and procedures applicable to a limited number of our pipelines. In addition, many states, including the states in which we operate, have adopted regulations that are identical to or more restrictive than existing PHMSA regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high-population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream system is located. While the majority of our pipelines have historically met the DOT definition of gathering lines, and were thus exempt from the integrity management requirements of PHMSA, we also operate a limited number of pipelines that are subject to the integrity management requirements. Those regulations require operators, including us, to:

•perform ongoing assessments of pipeline integrity;

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

•maintain processes for data collection, integration and analysis;

•repair and remediate pipelines as necessary;

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

•implement preventive and mitigating actions.

In addition, PHMSA has jurisdiction over 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.

PHMSA has also imposed requirements on onshore gas transmission systems and hazardous liquids pipelines in recent years. PHMSA may issue an emergency order without advance notice or opportunity for a hearing; require pipelines to conduct integrity assessments beyond high consequence areas (“HCAs”) to pipelines in “moderate consequence areas”; and require reporting regarding MAOP, including reporting MAOP exceedances, considering seismicity as a risk factor in integrity management and using certain safety features on in-line inspection equipment. The rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events and added a requirement to make all lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. PHMSA also requires natural gas transmission lines to meet certain requirements related to the management of change process, integrity management, corrosion control standards and pipeline inspections, and repairs. In January 2025, PHMSA submitted a final rule to the Federal Register that amends regulations to reduce methane emissions from new and existing gas transmission, distribution and regulated gas gathering pipelines with strengthened leakage survey and patrolling requirements, performance standards for advanced leak detection programs, leak grading and repair criteria with mandatory repair timelines, requirements for mitigation of emissions from blowdowns, pressure relief device design, configuration and maintenance requirements, clarified requirements for investigating failures and expanded reporting requirements. However, before the final rule could be published in the Federal Register,

President Trump issued a “regulatory freeze” executive order. As a result, the final rule was not published in the Federal

Register and has not gone into effect. A bill, H.R. 4818, was introduced in the U.S. House of Representatives in July 2025 to

effectuate the January 2025 final rule. This bill is pending.

Gathering systems like ours are also subject to a number of other federal and state laws and regulations, including the Federal Occupational Safety and Health Act and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the Occupational Safety and Health Administration hazard communication standard, EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and the public.

Environmental Matters

General. Our operation of pipelines and other assets for the gathering, treating, transportation and/or processing of natural gas and the gathering of crude oil and produced water is subject to stringent and complex federal, state, and local laws and regulations relating to the protection of the environment. As an owner or operator of these assets, we must comply with these laws and regulations at the federal, state, and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

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

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

•delaying system modification or upgrades during permit reviews;

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

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

Failure to comply with these laws and regulations may trigger administrative, civil, and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons, or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, or other waste products into the environment.

The trend in environmental regulation has historically been to place more stringent requirements, resulting in more restrictions and limitations, on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing and future regulations.

The following is a discussion of the material environmental laws and regulations that relate to our business.

Hazardous Substances and Waste. Our operations are subject to environmental laws and regulations relating to the management and release of solid and hazardous wastes and other substances, including hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. Furthermore, the Toxic Substances Control Act and analogous state laws impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities. CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

We also generate industrial wastes that are subject to the requirements of the RCRA and comparable state statutes. While the RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation, and disposal of hazardous wastes. Although we generate minimal hazardous waste, it is possible that non-hazardous wastes, which could include wastes currently generated during our operations, will in the future be designated as hazardous wastes and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes and expansion of the definition of hazardous materials to include new substances, such as per- and polyfluoroalkyl substances.

We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although we believe that the previous operators utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal, without our knowledge. These properties and the wastes disposed thereon may be subject to CERCLA, the RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior

owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

Air Emissions. Our operations are subject to the federal CAA and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and also impose various monitoring, control, and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions, or restrictions on operations and criminal enforcement actions. Furthermore, we may be required to incur certain capital expenditures in the future to obtain and maintain operating permits and approvals for air pollutant emitting sources.

In October 2015, the EPA issued a new lower NAAQS for ozone. The previous ozone standard was set at 75 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, the 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, the EPA also reclassified portions of Weld County, Colorado as severe nonattainment under the 75 ppb standard. In July 2022, the 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. However, the EPA deprioritized the redesignation of the Permian Basin in 2023. Such 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. Future actions to lower the standard could similarly result in additional fees or more stringent permitting.

In June 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 sought to: (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 sought to impose more stringent requirements and include sources not previously regulated under this source category. In December 2023, the EPA announced its final methane rules, later published on March 8, 2024, which impose several new methane emission requirements on the oil and gas industry. 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. However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. In addition, in March 2025, the EPA announced that it would reconsider the final methane rules, including NSPS OOOOb and OOOOc. In December 2025, the EPA issued a final rule that extends several compliance deadlines in the 2024 NSPS and Emissions Guidelines for OOOOb and OOOOc. Consequently, future implementation and enforcement of the final rules remains uncertain at this time.

In November 2016, the BLM issued a final rule to reduce venting and flaring of natural gas on public and Indian lands. The final rule mirrored many of the requirements found in NSPS OOOOa, with additional natural gas royalty requirements for flared volumes at sites already connected to gas capture infrastructure. The rule was vacated by a Wyoming federal district judge in 2020. However, the BLM finalized a new rule in April 2024, similarly designed to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on federal and Indian leases. In April 2024, North Dakota, Montana, Texas, Wyoming, and Utah filed a lawsuit in federal district court challenging the rule. In September 2024, the court granted a preliminary injunction enjoining the BLM from enforcing the rule in the plaintiff states and the litigation remains ongoing. The rule, which went into effect in all other states on June 10, 2024, is expected to have little or no direct impact on our operations. In November 2025, the BLM announced that it would postpone enforcement of two provisions from the April 2024 rule that were originally set to take effect in December 2025. These provisions include requirements for measurement devices and sampling for flares with flow rates between 1,050 and 6,000 Mcf per month, as well as the obligation for operators to submit leak detection and repair plans to the state BLM office. However, our customers that are primarily upstream wellhead operators may be impacted by the requirements in this rule.

In past years, the EPA has also demonstrated an increased focus on CAA compliance for natural gas gathering operations. For example, in September 2019, the EPA issued an enforcement alert noting that the EPA identified CAA noncompliance caused by unauthorized and/or excess emissions from depressurizing pig launchers and receivers in natural gas gathering operations. The alert discussed engineering, design, operations and maintenance practices that the EPA found that can cause noncompliance and summarizes engineering solutions to reduce emissions. This increased focus on natural gas gathering operations and any resulting enforcement actions by the EPA or state agencies could subject us to monetary penalties, injunctions, conditions, or restrictions on operations.

Water Discharges. The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into regulated waters, which impacts our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits require us to control storm water runoff from some of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. Except as otherwise disclosed in this annual report, we believe that we are in substantial compliance with all applicable requirements of the CWA and analogous state laws and regulations relating to water discharges.

Oil Pollution Control Act. The OPA requires the preparation of an SPCC plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the U.S. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility’s operations comply with the requirements. To be in compliance, the facility’s SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security and training. Certain of our facilities are classified as SPCC-regulated facilities. We believe that they are in substantial compliance with all applicable requirements of OPA.

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 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 California, 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 could restrict oil and gas development in the future.

The EPA has also moved forward with various regulatory actions, including new regulations under the NSPS to expand and strengthen emissions reduction requirements under NSPS OOOOa for new, modified, and reconstructed oil and natural gas sources and require states to reduce methane emissions from existing sources nationwide. For further discussion of NSPS OOOOa and subsequent actions by the EPA, see the “Air Emissions” section above. The BLM has also asserted regulatory authority over aspects of the hydraulic fracturing process and issued a final rule in March 2015 that established more stringent standards for performing hydraulic fracturing on federal and Indian lands, including requirements relating to well construction and integrity, handling of wastewater and chemical disclosure. However, in December 2017, the BLM published a final rule rescinding the 2015 rule. The U.S. District Court for the Northern District of California upheld the December 2017 rescission rule in a March 2020 decision and the State of California and environmental plaintiffs appealed. A motion by the State of California to voluntarily dismiss the appeal was granted in September 2025. The March 2015 rule currently remains rescinded

Further, several federal governmental agencies (including the EPA) have conducted reviews and studies on the environmental aspects of hydraulic fracturing, including the EPA. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing.

State and federal regulatory agencies have also focused on a possible connection between the hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. Some state regulatory agencies, including those in Colorado, Oklahoma and Texas, have modified their regulations or guidance to account for induced seismicity. These developments could result in additional regulation and restrictions on the use of injection disposal wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on our customers.

Additionally, certain of our customers produce oil and gas on federal lands. On January 20, 2021, the Acting Secretary for the DOI signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. In April 2024, the DOI issued a final rule updating its onshore oil and gas leasing program, which includes revised royalty rates and bonding requirements and attempts to direct oil and gas development away from wildlife habitat and cultural sites. However, in January 2025, President Trump issued executive orders directing the heads of federal agencies to (i) facilitate the leasing of domestic energy resources, including on federal lands and (ii) identify and begin the processes to suspend, revise, or rescind all agency actions that impose an undue burden on the identification, development, or use of domestic energy resources. In addition, in September 2025, the DOI announced its intent to rescind the April 2024 rule. As a result, future implementation and enforcement of the final rule remains uncertain.

If new or more stringent federal, state, or local legal restrictions relating to drilling activities or to the hydraulic fracturing process are adopted, this could result in a reduction in the supply of natural gas and/or crude oil that our customers produce and could thereby adversely affect our revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for our customers, which could ultimately decrease end-user demand for our services and could have a material adverse effect on our business.

Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species.

National Environmental Policy Act. 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. However, in January 2025, President Trump issued an executive order requiring the White House Council on Environmental Quality (“CEQ”) to propose rescinding the NEPA regulations and provide guidance regarding promulgating consistent NEPA implementing regulations at the agency level. The executive order also instructs federal agencies to adhere to only the relevant legislated requirements for environmental reviews and to prioritize efficiency and certainty over any other objectives in such reviews. In February 2025, CEQ issued an interim final rule to withdraw the NEPA implementing regulations. In January 2026, CEQ finalized the February 2025 rule, immediately rescinding NEPA implementing regulations. The potential impact of further changes to the NEPA regulations and statutory text therefore remains uncertain and could affect our operations.

Climate Change. The EPA has adopted regulations under the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis.

EPA rules also require the reporting of GHG emissions from specified large GHG-emitting sources in the U.S., including onshore and offshore oil and natural gas systems. We are required to report under these rules for our assets that have GHG emissions above the reporting thresholds. In October 2015, the EPA issued revisions to Subpart W of the GHG reporting rule to include reporting requirements for gathering and booster stations, onshore natural gas transmission pipelines and completions and workovers of oil wells with hydraulic fracturing. This development resulted in increased monitoring and reporting for our operations and for upstream producers for whom we provide midstream services. Further, the IRA, signed into law in August 2022, included a Methane Emissions Reduction Program to incentivize methane emission reductions and imposed a “Waste Emissions Charge” (“WEC”) on GHG emissions from certain oil and gas facilities. Emissions reported under the GHG reporting rule would be the basis for any payments under the Methane Emissions Reduction Program. However, in March 2025, President Trump signed Congress’ Joint Resolution of Disapproval of the WEC and in May 2025, the EPA issued a final rule removing the WEC regulations from the Code of Federal Regulations. In July 2025, the One Big Beautiful Bill Act postponed the WEC’s effective date to 2034. Consequently, future implementation and enforcement of these rules remains uncertain at this time.

focused on large sources of GHG emissions, such as electric power plants, it is possible that certain components of our operations, such as our gas-fired compressors, could become subject to state-level GHG-related regulation.

At the international level, the U.S. joined the international community at the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change in Paris, France in 2015, which resulted in the Paris Agreement, an agreement for signatory countries to nationally determine their contributions and set GHG emission reduction goals. In January 2025, President Trump issued an executive order directing the immediate notice to the United Nations of the U.S.’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. The withdrawal became effective in January 2026. The U.S. did not send an official delegation to COP30 and on January 7, 2026, President Trump announced the formal withdrawal of the U.S. from the United Nations Framework Convention on Climate Change in a presidential memorandum. At the same time, various state and local governments have committed to continue furthering the goals of the Paris Agreement and many of these initiatives are expected to continue. Adoption of additional regulations or changes to existing regulations related to climate change could have a material adverse effect on our business and that of our customers.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products and those of our customers, by making our products more or less desirable than competing sources of energy. For example, a number of local governments across the country have banned or considered instituting bans on gas-fired appliances in newly constructed homes and other buildings. To the extent that our products are competing with higher GHG-emitting energy sources, our products would become more desirable in the market with more stringent limitations on GHG emissions. Conversely, to the extent that our products are competing with lower GHG-emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions.

Other Information

Human Capital Resources. We recognize that our continued ability to attract, retain and motivate exceptional employees is vital to ensuring our long-term competitive advantage and the ability to create value for our shareholders. Our employees are critical to our long-term success and are essential to helping us meet our goals. Among other things, we support and incentivize our employees in the following ways:

•Talent development, compensation, and retention – We strive to provide our employees with a rewarding work environment, including the opportunity for success and a platform for personal and professional development. We provide a competitive benefits package designed to attract and retain a skilled 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 – We are committed to efforts to foster an inclusive work environment that strengthens our workforce.

As of December 31, 2025, the Company employed 296 people who provide direct, full-time support to our operations. None of our employees are covered by collective bargaining agreements and we have not experienced any business interruption as a result of any labor disputes.

Availability of Reports. We make certain filings with the SEC, including, among other filings, 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, https://www.sec.gov.

Item 1A. Risk Factors.

You should carefully consider the following risk factors in addition to the other information included in this Annual Report. Each of these risk factors could adversely affect our business, operating results, and financial condition, as well as adversely affect the value of an investment in our common stock.

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 dividends to holders of our Series A Preferred Stock and common stock.

We may not have sufficient available cash from operating surplus each quarter to pay the dividends to holders of our Series A Preferred Stock and common stock. We have not made a distribution on our common stock since we announced suspension of those dividends on May 3, 2020. Because our Series A Preferred Stock rank senior to our common stock with respect to divided rights, any accrued amounts on our Series A Preferred Stock must first be paid prior to our resumption of dividends to our holders of common stock. As of December 31, 2025, the amount of accrued and unpaid dividends on the Series A Preferred Stock totaled $46.6 million. In March 2026, the Company’s Board of Directors approved the payment of any and all accrued and unpaid dividends on the Company’s Series A Preferred Stock, including the $46.6 million of accrued and unpaid dividends outstanding as of December 31, 2025. The Company expects to pay the accrued and unpaid dividends on the Series A Preferred Stock upon satisfaction of certain notice requirements, which the Company expects to complete by March 31, 2026.

Further, absent a material change to our business, we do not expect to pay dividends on the common stock in the foreseeable future, and our outstanding indebtedness currently restricts our ability to pay cash dividends on any of our equity securities. We intend to use our cash flow to reduce debt and invest in our business.

The amount of cash we can distribute on our common stock principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

•the volumes we gather, 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;

•adverse economic impacts from epidemics, including disruptions in demand for oil, natural gas and other petroleum products, supply chain disruptions, and decreased productivity resulting from illness, travel restrictions, quarantine, or government mandates; and

•prevailing economic and market conditions.

In addition, the actual amount of cash we have available for distribution to our holders of common stock depends on other factors, some of which are beyond our control, including:

•the level and timing of capital expenditures we make;

•the level of our operating, maintenance and general and administrative expenses;

•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 us;

•not receiving anticipated shortfall payments from our customers;

•adverse legal judgments, fines and settlements;

•dividends, if any, paid on our Series A Preferred Stock or on the preferred stock of our subsidiaries; and

•other business risks affecting our cash levels.

We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of our customers could materially adversely affect our revenues, cash flows, and results of operations.

Certain of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our customers could have a material adverse effect on our revenues, cash flows, and results of operations. We expect our exposure to concentrated risk of nonpayment or nonperformance to continue as long as we remain substantially dependent on a relatively small number of customers for a significant portion of our revenues.

If any of our customers curtail or reduce production in our areas of operation, it could reduce throughput on our systems and, therefore, materially adversely affect our revenues, cash flows, and results of operations.

Further, we are subject to the risk of non-payment or non-performance by our larger customers. We cannot predict the extent to which our customers’ businesses would be impacted if conditions in the energy industry deteriorate, nor can we estimate the impact such conditions would have on any of our customers’ abilities to execute their drilling and development programs or perform under our gathering and processing agreements. An extended low commodity price environment negatively impacts natural gas producers causing some producers in the industry significant economic stress, including, in certain cases, to file for bankruptcy protection or to renegotiate contracts. To the extent that any customer is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any material non-payment or non-performance by our customers could adversely affect our business and operating results.

We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties and any material nonpayment or nonperformance by one or more of these parties could materially adversely affect our financial and operating results.

Although we attempt to assess the creditworthiness and associated liquidity of our customers, suppliers and contract counterparties, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition, and cash flows. In addition, there can be no assurance that our contract counterparties will perform or adhere to existing or future contractual arrangements, including making any required shortfall payments or other payments due under their respective contracts.

The policies and procedures we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, if necessary, requiring credit support, cannot fully eliminate counterparty credit risks. To the extent our policies and procedures prove to be inadequate, our financial and operational results may be negatively impacted.

Some of our counterparties may be highly leveraged, have limited financial resources and/or have recently experienced a rating agency downgrade and will be subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. In addition, volatility in commodity prices could have a negative impact on our counterparties, which, in turn, could have a negative impact on their ability to meet their obligations to us.

Any material nonpayment or nonperformance by any of our counterparties or suppliers could require us to pursue substitute counterparties or suppliers for the affected operations or reduce our operations. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.

Significant prolonged weakness in natural gas, NGL and crude oil prices could reduce throughput on our systems and materially adversely affect our revenues and results of operations.

Lower natural gas, NGL and crude oil prices could negatively impact exploration, development and production of natural gas and crude oil, thereby resulting in reduced throughput on our gathering systems. If natural gas, NGL and/or crude oil prices decrease, it could cause sustained reductions in exploration or production activity in our areas of operation and result in a further reduction in throughput on our systems, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. In the first half of 2025, the Henry Hub Natural Gas Spot Price declined from a monthly average of $4.13 per MMBtu in January 2025 to a monthly average of $2.91 per MMBtu in August 2025, before trending upward in the latter months of 2025 to close the year at $4.00 per MMBtu on December 31, 2025. As of January 31, 2026, Henry Hub 12-month strip pricing closed at $7.71 per MMBtu. In the first half of 2025, Cushing, Oklahoma West Texas Intermediate crude oil spot prices decreased from a monthly average of $75.74 per barrel in January 2025 to a monthly average of $63.54 per barrel in April 2025, before trending downward in the latter half of 2025 to close the year at $57.26 per barrel on December 31, 2025. As of January 31, 2026, West Texas Intermediate 12-month strip pricing closed at $60.26 per barrel. Currently, oil prices are experiencing significant volatility due to the ongoing U.S. military operation in Iran.

Because of the natural decline in production from our customers’ existing wells, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes that we gather and process could materially adversely affect our business and operating results.

The customer volumes that support our business depend on the level of production from natural gas and crude oil wells connected to our systems, the production from which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our systems, we must obtain new sources of volume throughput. The primary factors affecting our ability to obtain new sources of volume throughput include (i) the level of successful drilling activity in our areas of operation and (ii) our ability to compete for new volumes on our systems.

We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling and production decisions, which are affected by, among other things:

•the availability and cost of capital;

•prevailing and projected hydrocarbon commodity prices;

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

•levels of reserves;

•geological considerations;

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

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

Fluctuations in energy prices can also greatly affect the development of new crude oil and natural gas reserves. Drilling and production activities generally decrease as commodity prices decrease. In general terms, the prices of crude oil, natural gas, and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include:

•worldwide economic and geopolitical conditions, including the ongoing U.S. military operation in Iran;

•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 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 cost and availability of alternative energy sources;

•the nature and extent of governmental regulation and taxation; and

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

Because of these factors, even if new crude oil or natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, those reductions could reduce our revenues and cash flows and materially adversely affect our results of operations.

In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems, as several of the formations in the unconventional resource plays in which we operate generally have higher initial production rates and steeper production decline curves than wells in more conventional basins and may have steeper production decline curves than initially anticipated. Should we determine that the economics of our gathering, treating, transportation, and processing assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, revenues associated with these assets will decline over time. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time, which will reduce our cash available for distribution.

Many of our costs are fixed and do not vary with our throughput. These costs will not decline ratably or at all should we experience a reduction in throughput, which could result in a decline in our revenues and cash flows and materially adversely affect our results of operations and financial condition.

If our customers do not increase the volumes they provide to our gathering systems, our results of operations and financial condition may be materially adversely affected.

If we are unsuccessful in attracting new customers and/or new gathering opportunities with existing customers, our results of operations will be impaired. Our customers are not obligated to provide additional volumes to our gathering systems and they may determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. Reductions by our customers in our areas of mutual interest could result in reductions in throughput on our systems and materially adversely impact our results of operations and financial condition.

Certain of our gathering and processing agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.

We designed those gathering and processing agreements that contain MVC provisions to generate stable cash flows for us over the life of the MVC contract term while also minimizing our direct commodity price risk. Under certain of these MVCs, our customers agree to ship a minimum volume on our gathering systems or send a minimum volume to our processing plants or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. In addition, our gathering and processing agreements may also include an aggregate MVC, which represents the total amount that the customer must flow on our gathering system or send to our processing plants (or an equivalent monetary amount) over the MVC term. If such customer’s actual throughput volumes are less than its MVC for the contracted measurement period, it must make a shortfall payment to us at the end of the applicable measurement period. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped or processed for the applicable period and the MVC for the applicable period, multiplied by the applicable fee. To the extent that a customer’s actual throughput volumes are above or below its MVC for the applicable contracted measurement period, certain of our gathering agreements contain provisions that allow the customer to use the excess volumes or the shortfall payment to credit against future excess volumes or future shortfall payments, which could have a material adverse effect on our results of operations, financial condition, and cash flows.

We have not obtained independent evaluations of all of the reserves connected to our gathering systems; therefore, in the future, customer volumes on our systems could be less than we anticipate.

We do not routinely obtain or update independent evaluations of the reserves connected to our systems. Moreover, even if we did obtain independent evaluations of all of the reserves connected to our systems, such evaluations may prove to be incorrect. Crude oil and natural gas reserve engineering requires subjective estimates of underground accumulations of crude oil and natural gas and assumptions concerning future crude oil and natural gas prices, future production levels and operating and development costs.

Accordingly, we may not have accurate estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems are less than we anticipate and

we are unable to secure additional volumes, it could have a material adverse effect on our business, results of operations and financial condition.

Our industry is highly competitive, and increased competitive pressure could materially adversely affect our business and operating results.

We compete with other midstream companies in our areas of operations, some of which are large companies that have greater financial, managerial, and other resources than we do. In addition, some of our competitors may have assets in closer proximity to natural gas and crude oil supplies and may have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct gathering systems that would create additional competition for the services we provide to our customers. Because our customers do not have leases that cover the entirety of our areas of mutual interest, non-customer producers that lease acreage within any of our areas of mutual interest may choose to use one of our competitors for their gathering and/or processing service needs.

In addition, our customers may develop their own gathering systems outside of our areas of mutual interest. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be materially adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations and financial condition.

We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.

Our gathering, treating, transportation, and processing contracts have terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing customers or enter into new contracts with other customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. Moreover, we may be unable to obtain areas of mutual interest from new customers in the future, and we may be unable to renew existing areas of mutual interest with current customers as and when they expire. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

•the level of existing and new competition to provide gathering and/or processing services in our areas of operation;

•the macroeconomic factors affecting gathering, treating, 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.

To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenues and cash flows could decline.

If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, our revenues and cash flows could be materially adversely affected.

Our gathering systems connect to third-party pipelines and other midstream facilities, such as processing plants, rail terminals and produced water disposal facilities. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable due to issues including, but not limited to, testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from other hazards. In addition, we do not have interconnect agreements with all of these pipelines and other facilities and the agreements we do have may be terminated in certain circumstances and/or on short notice. If any of these pipelines or other midstream facilities become unavailable for any reason, or, if these third parties are otherwise unwilling to receive or transport the natural gas, crude oil and produced water that we gather and/or process, our revenues, cash flows, and results of operations could be materially adversely affected.

Crude oil and natural gas production and gathering may be adversely affected by weather conditions and terrain, which in turn could negatively impact the operations of our gathering, treating, transportation, and processing facilities and our construction of additional facilities.

Extended periods of below freezing weather and unseasonably wet weather conditions, especially in North Dakota, Colorado and Texas, can be severe and can adversely affect crude oil and natural gas operations due to the potential shut-in of producing wells or decreased drilling activities. These types of interruptions could result in a decrease in the volumes supplied to our gathering systems. Further, delays and shutdowns caused by severe weather may have a material negative impact on the continuous operations of our gathering, treating, transporting, and processing systems, including interruptions in service. These

types of interruptions could negatively impact our ability to meet our contractual obligations to our customers and thereby give rise to certain termination rights and/or the release of dedicated acreage. Any resulting terminations or releases could materially adversely affect our business and results of operations.

We also may be required to incur additional costs and expenses in connection with the design and installation of our facilities due to their locations and surrounding terrain. We may be required to install additional facilities, incur additional capital and operating expenditures, or experience interruptions in or impairments of our operations to the extent that the facilities are not designed or installed correctly. For example, certain of our pipeline facilities are located in locations with significant elevation changes, which may require specially designed facilities and special installation considerations. If such facilities are not designed or installed correctly, do not perform as intended, or fail, we may be required to incur significant expenditures to correct or repair the deficiencies, or may incur significant damages to or loss of facilities, and our operations may be interrupted as a result of deficiencies or failures. In addition, such deficiencies may cause damage to the surrounding environment, including slope failures, stream impacts, and other natural resource damages, and we may as a result also be subject to increased operating expenses or environmental penalties and fines.

Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, wildfires, droughts and floods, changes in weather patterns, extreme temperatures, and other climatic events. While we cannot predict with any certainty at this time whether we will be affected by these possibilities, severe weather associated with climate change could result in disruptions or delays to our operations, damage to our assets and facilities and increased operating costs, any of which could materially adversely affect our business and results of operations.

Interruptions in operations at any of our facilities may adversely affect our operations and cash flows available for dividends.

Our operations depend upon the infrastructure that we have developed and constructed. Any significant interruption at any of our gathering, treating, transporting, or processing facilities, or in our ability to provide gathering, treating, transporting, or processing services, could adversely affect our operations and cash flows available for dividends. Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as:

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

•restrictions imposed by governmental authorities or court proceedings;

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

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

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

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

Any significant interruption at any of our gathering, treating, transporting, or processing facilities, or in our ability to provide gathering, treating, transporting, or processing services, could adversely affect our operations.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant incident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant incidents or events for which we are insured, our operations and financial results could be materially adversely affected.

Our operations are subject to all of the risks and hazards inherent in the operation of gathering, treating, transporting, and processing systems, including:

•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.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage. The location of certain of our systems in or near

populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from such events.

These events may also result in the curtailment or suspension of our operations. A natural disaster or any event such as those described above affecting the areas in which we and our customers operate could have a material adverse effect on our operations. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on portions or all of our gathering systems. Potential customer impacts arising from service interruptions on segments of our gathering systems could include limitations on our ability to satisfy customer requirements, obligations to temporarily waive MVCs during times of constrained capacity, temporary or permanent release of production dedications, and solicitation of existing customers by others for potential new projects that would compete directly with our existing services. Such circumstances could materially adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business and results of operations.

Although we have a range of insurance programs providing varying levels of protection for public liability, damage to property, loss of income and certain environmental hazards, we may not be insured against all causes of loss, claims or damage that may occur. If a significant incident or event occurs for which we are not fully insured, it could materially adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of industry or market conditions, including any reluctance by insurance companies to insure oil and gas operations for political or other reasons, premiums, and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, with regard to the assets we have acquired, we have limited indemnification rights to recover from the seller of the assets in the event of any potential environmental liabilities.

We have had and continue to have discussions with unaffiliated third parties with respect to potential strategic transactions.

We have had and continue to have discussions with unaffiliated third parties with respect to potential strategic transactions (each such transaction, a “Potential Transaction”). These discussions include Potential Transactions that would be material acquisitions. There can be no assurance that these discussions will result in the consummation of a Potential Transaction. If the Board of Directors decides to proceed with a Potential Transaction, or any other strategic alternative, it may not be at a valuation that our investors view as attractive relative to the value of our standalone business. Depending on the structure of any such Potential Transaction, we may be required to seek the approval of the transaction from our stockholders and raise additional equity or debt financing in connection with such Potential Transaction. In addition, the closing of any such transaction would be dependent upon a number of factors that may be beyond our control, including, among other factors, market conditions, and regulatory factors.

Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal, and economic risks, which could materially adversely affect our results of operations and financial condition.

The construction of new assets, including for example, the Double E Pipeline, which was placed into service in November 2021, involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control.

Such construction projects may also require the expenditure of significant amounts of capital and financing, traditional or otherwise, that may not be available on economically acceptable terms or at all. If we undertake these projects, our revenue may not increase immediately upon the expenditure of funds for a particular project and they may not be completed on schedule, at the budgeted cost, or at all.

Moreover, we could construct facilities to capture anticipated future production growth in a region where such growth does not materialize or only materializes over a period materially longer than expected. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate due to the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could materially adversely affect our results of operations and financial condition.

In addition, the construction of additions or modifications to our existing gathering, treating, transporting, and processing assets and the construction of new midstream assets may require us to obtain federal, state, and local regulatory environmental or other authorizations. The approval process for gathering, treating, transporting, and processing activities has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering, treating, transporting, and processing activities in new production areas. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions. In addition, various officials and candidates at the federal, state, and local levels have made climate-related pledges or proposed banning hydraulic fracturing altogether. As a result, we may be unable to obtain such authorizations and may, therefore, be unable to connect new volumes to our systems or

capitalize on other attractive expansion opportunities. A future government shutdown could delay the receipt of any federal regulatory approvals. Additionally, it may become more expensive or difficult for us to obtain authorizations or to renew existing authorizations. If the cost of renewing or obtaining new authorizations increases materially, our cash flows could be materially adversely affected.

We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate or if our pipelines are not properly located within the boundaries of such rights-of-way. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies either perpetually or for a specific period of time. If we were to be unsuccessful in renegotiating rights-of-way, we might have to relocate our pipelines and related infrastructure. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition.

Our ability to operate our business effectively could be impaired if we fail to attract and retain key personnel, and a shortage of skilled labor in the midstream energy industry could reduce employee productivity and increase costs, which could have a material adverse effect on our business and results of operations.

Our ability to operate our business and implement our strategies depends on our continued ability to attract and retain highly skilled personnel with midstream energy industry experience and competition for these persons in the midstream energy industry is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.

Furthermore, as a result of labor shortages, we have experienced difficulty in recruiting and hiring skilled labor throughout our organization. The operation of gathering, treating, transporting, and processing systems requires skilled laborers in multiple disciplines such as equipment operators, mechanics, and engineers, among others. If we continue to experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our employees, our business and results of operations could be materially adversely affected.

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.

Increased public attention on climate change and corresponding changes in consumer, commercial and industrial preferences and behavior regarding energy use and generation may result in:

•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 relating to a transition from oil and gas to alternative energy sources and a lower-carbon economy may reduce the demand for natural gas and crude oil and other products made from hydrocarbons. Any significant decrease in the demand for natural gas and crude oil resulting from such developments could reduce the volumes of natural gas and crude oil that we gather and process, which could adversely affect our business and operating results.

Furthermore, if any such developments reduce the desirability of participating in the midstream oil and gas industry, then such developments could also reduce the availability to us of necessary third-party services or facilities that we rely on, which could increase our operational costs and have an adverse effect on our business and results of operations.

Such developments and accompanying societal expectations on companies to address climate change, investor, and societal expectations regarding voluntary environmental, social and governance (“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. In addition, we have established a corporate strategy intended to meet ESG-related objectives. However, we cannot guarantee that our strategy will meet our ESG-related objectives on the timelines communicated or at all. Such initiatives are voluntary, not binding on our business or management and subject to change. We may determine in our discretion that it is not feasible or practical to implement or complete certain of our ESG-related initiatives, or to meet previously set goals and targets based on cost, timing, or other considerations. If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters (or meet ESG-related goals and targets that we have set), as they continue to evolve, if we are perceived to have not responded appropriately or quickly enough to growing concern for ESG and sustainability issues, regardless of whether there is a regulatory or legal requirement to do so, or if estimates, assumptions, and/or third-party information we currently believe to be reasonable are subsequently considered erroneous or misinterpreted, we may suffer from reputational damage and our business, financial condition, and/or stock price could be materially and adversely affected.

Further, our operations, projects and growth opportunities require us to have strong relationships with various key stakeholders, including our stockholders, employees, suppliers, customers, local communities, and others. We may face pressure from stakeholders, many of whom are increasingly focused on climate change, to prioritize sustainable energy practices and reduce our carbon footprint. At the same time, others may disagree with the ESG initiatives we have set and recent political developments could subject the Company to increased risk of criticism or litigation risks from certain “anti-ESG” parties. If we do not successfully manage expectations across these varied stakeholder interests, it could erode stakeholder trust and thereby affect our brand and reputation.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to ESG and sustainability matters. These ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG and sustainability ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. To the extent unfavorable ESG and sustainability ratings negatively affect our reputation, it may also harm our ability to attract or retain employees or customers.

Furthermore, negative public perception regarding the oil and gas industry resulting from, among other things, concerns raised by advocacy groups about climate change, emissions, hydraulic fracturing, seismicity, or oil spills may lead to increased litigation risk and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens, including enhanced disclosure obligations, and increased risk of litigation. More broadly, the enactment of climate change-related policies and initiatives across the market at the corporate level and/or investor community level may in the future result in increases in our compliance costs and other operating costs and have other adverse effects (e.g., greater potential for governmental investigations or litigation, driving down demand for our products, or stimulating demand for alternative forms of energy that do not rely on combustion of fossil fuels).

Tariffs and other trade measures could adversely affect our business, results of operations, financial position, and cash flows.

The cost of raw materials, parts, and components that are manufactured and supplied for our operations may be adversely affected by tariffs imposed by the U.S. government on products imported into the U.S. and tariffs or other retaliatory trade measures imposed by other jurisdictions. Tariffs and other trade restrictions could also disrupt our supply chain and logistics, restrict or limit the availability of materials or supplies, and cause adverse financial impacts due to volatility in foreign exchange rates and interest rates or inflationary pressures on raw materials and energy. We may not be able to fully mitigate the impact of these increased costs or pass price increases on to our customers. While tariffs and other retaliatory trade measures imposed by other countries on U.S. goods have not yet had a significant impact on our business or results of operations, we cannot predict further developments, and such existing or future tariffs could have a material adverse effect on our results of operations, financial position, and cash flows. Recently, the U.S. has proposed changes in trade policies that include export control restrictions, the negotiation or termination of trade agreements, the imposition of higher tariffs on imports into the U.S., increased economic sanctions on individuals, companies, or countries, and other government regulations affecting trade between the U.S. and other countries, and a number of other nations have proposed similar measures directed at trade with the U.S. in response. As a result of these developments, there may be greater restrictions and economic disincentives on international trade that could adversely affect our business. It may be time-consuming and expensive for us to alter our business operations to adapt to or comply with any such changes, and any failure to do so could have a material adverse effect on our business, results of operations, and financial position.

Risks Related to Our Finances

Limited access to and/or availability of the commercial bank market or debt and equity capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements.

To expand our asset base, whether through acquisitions or organic growth, we will need to make expansion capital expenditures. We also frequently consider and enter into discussions with third parties regarding potential acquisitions. In addition, the terms of certain of our gathering and processing agreements also require us to spend significant amounts of capital, over a short period of time, to construct and develop additional midstream assets to support our customers’ development projects. Depending on our customers’ future development plans, it is possible that the capital required to construct and develop such assets could exceed our ability to finance those expenditures using our cash reserves or available capacity under the Amended and Restated ABL Facility or the New Permian Transmission Facility.

We plan to use cash from operations, incur borrowings, and/or sell additional shares of capital stock or other securities to fund our future expansion capital expenditures. Our ability to obtain financing or to access the capital markets for future debt or equity offerings may be limited by (i) our financial condition at the time of any such financing or offering, (ii) covenants in our debt agreements, (iii) restrictions imposed by our Series A Preferred Stock, (iv) general economic conditions and contingencies, (v) increasing disfavor among many investors towards investments in fossil fuel companies and (vi) general weakness in the debt and equity capital markets and other uncertainties that are beyond our control, including political uncertainty in the U.S. (including the ongoing debates related to the U.S. federal government budget), volatility and disruption in global capital and credit markets (including those resulting from geopolitical events, such as the Russian invasion of Ukraine or ongoing conflict in the Middle East), uncertainty regarding increases or decreases in interest rates resulting from changes in the federal funds rate range targeted by the Federal Reserve, pandemics, epidemics and other outbreaks, such as COVID-19, or other adverse developments that affect financial institutions. In addition, lenders are facing increasing pressure to curtail their lending activities to companies in the oil and natural gas industry.

We have not made a dividend on our common stock since we announced the suspension of payments of distributions on May 3, 2020. Additionally, we have accrued and unpaid dividends on our Series A Preferred Stock. The suspensions of dividends and the accrued and unpaid dividends may further reduce demand for our common stock or Series A Preferred Stock. Because our Series A Preferred Stock ranks senior to our common stock with respect to distribution rights, any accrued amounts on our Series A Preferred Stock must first be paid prior to our resumption of dividends to holders of our common stock. As of December 31, 2025, the amount of accrued and unpaid dividends on the Series A Preferred Stock totaled $46.6 million. In March 2026, the Company’s Board of Directors approved the payment of any and all accrued and unpaid dividends on the Company’s Series A Preferred Stock, including the $46.6 million of accrued and unpaid dividends outstanding as of December 31, 2025. The Company expects to pay the accrued and unpaid dividends on the Series A Preferred Stock upon satisfaction of certain notice requirements, which the Company expects to complete by March 31, 2026. Further, absent a material change to our business, we do not expect to pay dividends on the common stock in the foreseeable future. Additionally, our debt agreements restrict our ability to pay cash dividends on any of our equity securities. As such, if we are unable to raise expansion capital, we may lose the opportunity to make acquisitions, pursue new organic development projects, or to gather, treat and process new production volumes from our customers with whom we have agreed to construct and develop midstream assets in the future. Even if we are successful in obtaining external funds for expansion capital expenditures through the capital markets, the terms thereof could limit our ability to pay dividends to our common equity holders.

We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects, and may limit our flexibility to obtain financing and to pursue other business opportunities.

As of December 31, 2025, we had $1.1 billion of indebtedness outstanding and the unused portion of the Amended and Restated ABL Facility totaled $385.7 million after giving effect to certain adjustments that are primarily related to the issuance of $0.8 million in outstanding but undrawn irrevocable standby letters of credit. Our existing and future debt services obligations could have significant consequences, including among other things:

•limiting our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes and/or obtaining such financing on favorable terms;

•reducing our funds available for operations, future business opportunities, and cash dividends by that portion of our cash flow required to make interest payments on our debt;

•increasing our vulnerability to competitive pressures or a downturn in our business or the economy generally; and

•limiting our flexibility in responding to changing business and economic conditions.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, and other factors, many of which are beyond our control, such as commodity prices and governmental regulation.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful.

Our ability to make scheduled payments on, or to refinance, our indebtedness obligations, including the Amended and Restated ABL Facility, the New Permian Transmission Facility, and the 2029 Secured Notes, depends on our financial condition, and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our operating cash flows, and capital resources are insufficient to fund our debt service obligations, we may be forced to adopt alternative financing strategies, such as reducing or delaying investments and capital expenditures, selling assets, seeking additional capital or restructuring or refinancing our indebtedness, some or all of which may not be available to us on terms acceptable to us, if at all, or such alternative strategies may yield insufficient funds to make required payments on our indebtedness.

The 2029 Secured Notes will mature on October 31, 2029 and have interest payable semi-annually in arrears on each February 15 and August 15. As of December 31, 2025, $825.0 million of the 2029 Secured Notes were outstanding.

The Amended and Restated ABL Facility will mature on the earliest of (a) July 26, 2029, (b) July 31, 2029 if either (i) the outstanding amount of the 2029 Secured Notes (or any refinancing debt permitted under the Amended and Restated ABL Facility in respect thereof that has a final maturity date, scheduled amortization or any other scheduled repayment, mandatory prepayment, mandatory redemption or sinking fund obligation prior to the date that is 91 days after the Amended and Restated ABL Termination Date (provided, that the terms of such permitted refinancing debt may (x) require the payment of interest from time to time and (y) include customary mandatory redemptions, prepayments or offers to purchase with proceeds of asset sales or upon the occurrence of a change of control)) on such date equals or exceeds $50.0 million or (ii) the outstanding amount of such debt described in clause (i) above on such date is less than $50.0 million and Liquidity (as defined in the Amended and Restated ABL Agreement) at any time on or after such date is less than the sum of (A) such outstanding amount and (B) the greater of (x) 10% of the aggregate Commitments (as defined in the Amended and Restated ABL Agreement) then in effect and (y) $50.0 million (and, for the avoidance of doubt, once the Amended and Restated ABL Termination Date occurs it may not be unwound as a result of Liquidity (as defined in the Amended and Restated ABL Agreement) increasing on a subsequent date), or (c) any date on which the aggregate Commitments terminate thereunder.

Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets, including the market for senior secured or unsecured notes, and our financial condition at the time. Any refinancing of our indebtedness could be at higher interest rates, may require the pledging of collateral, and may require us to comply with more onerous covenants than we are currently subject to, which could further restrict our business operations. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations.

The agreements governing our debt place certain restrictions on our ability to dispose of assets and our use of the proceeds from such dispositions. We may not be able to consummate those dispositions on terms acceptable to us, if at all, and the proceeds of any such dispositions may not be adequate to meet any debt service obligations then due.

Further, if for any reason we are unable to meet our debt service and principal repayment obligations, or if we fail to comply with the financial covenants in the documents governing our debt, we would be in default under the terms of the agreements governing our debt, which would allow our creditors under those agreements to declare all outstanding indebtedness thereunder to be due and payable (which would in turn trigger cross-acceleration or cross-default rights among our other debt agreements), the lenders under the Amended and Restated ABL Facility could terminate their commitments to extend credit, and the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. If the amounts outstanding under our debt agreements were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to our creditors.

Restrictions in the New Permian Transmission Credit Facility, the indenture governing the 2029 Secured Notes and the Amended and Restated ABL Facility could materially adversely affect our business, financial condition, results of operations and ability to make cash dividends.

We are dependent upon the earnings and cash flows generated by our operations to meet our debt service obligations and to make cash dividends. The operating and financial restrictions and covenants in the New Permian Transmission Facility, the indenture governing the 2029 Secured Notes, the Amended and Restated ABL Facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, the Amended and Restated ABL Facility, the New Permian Transmission Facility and the indenture governing the 2029 Secured Notes, taken together, restrict our ability to, among other things:

•incur or guarantee certain additional debt;

•make certain cash dividends on or redeem or repurchase certain equity securities;

•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 Amended and Restated ABL Facility also contains covenants requiring Summit Holdings to maintain certain financial ratios and meet certain tests. Summit Holdings’ ability to meet those financial ratios and tests can be affected by events beyond its control, and we cannot guarantee that Summit Holdings will meet those ratios and tests.

The provisions of the New Permian Transmission Facility, the indenture governing the 2029 Secured Notes, and the Amended and Restated ABL Facility may affect our ability to obtain future financing and pursue attractive business opportunities as well as affect our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of the New Permian Transmission Facility, the indenture governing the 2029 Secured Notes, and the Amended and Restated ABL Facility could result in a default or an event of default that could enable our lenders and/or senior noteholders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, the lenders under the Amended and Restated ABL Facility could proceed against the collateral granted to them to secure such debt. If the payment of the debt is accelerated, our assets may be insufficient to repay such debt in full, and our equity holders could experience a partial or total loss of their investment. The Amended and Restated ABL Facility also has cross default provisions that apply to any other indebtedness we may have, and the indenture governing the 2029 Secured Notes have cross default provisions that apply to certain other indebtedness. The New Permian Transmission Facility also has cross default provisions that apply to certain other indebtedness that Permian Transmission or Double E may have. Any of these restrictions in the Amended and Restated ABL Facility, the New Permian Transmission Facility and the indenture governing the 2029 Secured Notes could materially adversely affect our business, financial condition, cash flows, and results of operations.

Inflation could have adverse effects on our results of operation.

Although inflation in the U.S. had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021 through 2023 due to a substantial increase in money supply, a stimulative fiscal policy, a significant rebound in consumer demand as COVID-19 restrictions were relaxed, the Russia-Ukraine war and worldwide supply chain disruptions resulting from the economic contraction caused by COVID-19 and lockdowns followed by a rapid recovery. Inflation rose from 5.4% in June 2021 to 7.0% in December 2021 to 8.2% in September 2022.

While inflation has declined since the second half of 2022, declining to 2.7% in December 2025, further increases in inflation in 2026 could increase our labor and other operating costs and the overall cost of capital projects we undertake. An increase in inflation rates could negatively affect our profitability and cash flows, due to higher wages, higher operating costs, higher financing costs, and/or higher supplier prices. We may be unable to pass along such higher costs to its customers. In addition, inflation may adversely affect customers’ financing costs, cash flows, and profitability, which could adversely impact their operations and our ability to offer credit and collect receivables.

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

Between March 2022 and July 2023, the Federal Reserve raised its target range for the federal funds rate by 5.25%, to a high of 5.25% to 5.50% from July 2023 to September 2024. While the Federal Reserve has since lowered its target range multiple times to a current target range of 3.50% to 3.75%, the timing of any potential increases or decreases remains uncertain. Borrowings under the Amended and Restated ABL Facility and the New Permian Transmission Facility bear interest at rates equal to SOFR plus margin. The interest rates are subject to adjustment based on fluctuations in SOFR, as applicable. An increase in the interest rates associated with our floating rate debt would increase our debt service costs and affect our results of operations and cash flow available for payments of our debt obligations. In addition, an increase in interest rates could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.

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.

Moody’s Investors Service, Inc., Standard & Poor’s Ratings Services or Fitch Ratings, Inc. assign ratings to our senior unsecured credit from time to time. A downgrade of our credit rating could increase our future cost of borrowing and could require us to post collateral with third parties, including our hedging arrangements, which could negatively impact our available liquidity and increase our cost of debt. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when we are experiencing significant working capital requirements or otherwise lacking liquidity, our results of operations, financial condition, and cash flows could be adversely affected.

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

We recorded long-lived asset impairments of $2.7 million during the year ended December 31, 2025, $68.3 million in 2024, and $0.5 million in 2023. When evidence exists that we will not be able to recover a long-lived asset’s carrying value through future cash flows, we write down the carrying value of the asset to its estimated fair value. We test long-lived assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. With respect to property, plant and equipment, and our amortizing intangible assets, the carrying value of a long-lived asset is not recoverable if the carrying value exceeds the sum of the undiscounted cash flows expected to result from the asset’s use and eventual disposal. In this situation, we recognize an impairment loss equal to the amount by which the carrying value exceeds the asset’s fair value. We determine fair value using either a market-based approach, an income-based approach in which we discount the asset’s expected future cash flows to reflect the risk associated with achieving the underlying cash flows, or a mixture of both market-and income-based approaches. We evaluate our equity method investments for impairment whenever events or circumstances indicate that a decline in fair value is other than temporary. Any impairment determinations involve significant assumptions and judgments. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to impairment charges. Adverse changes in our business or the overall operating environment, such as lower commodity prices, may affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows.

A portion of our revenues are directly exposed to changes in crude oil, natural gas and NGL prices, and our exposure may increase in the future.

During the year ended December 31, 2025, we derived 48% of our revenues from (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers in the Rockies, Piceance and Mid-Con segments, (ii) the sale of natural gas we retain from certain Mid-Con customers, (iii) the sale of condensate we retain from our gathering services in the Rockies and Piceance segment and (iv) additional gathering fees that are tied to performance of certain commodity price indexes, which are then added to the fixed gathering rates. Consequently, our existing operations and cash flows have direct exposure to commodity price risk. Although we will seek to limit our commodity price exposure with new customers in the future, our efforts to obtain fee-based contractual terms may not be successful or the local market for our services may not support fee-based gathering and processing agreements. For example, we have percent-of-proceeds contracts with certain natural gas producer customers and we may, in the future, enter into additional percent-of-proceeds contracts with these customers or other customers or enter into keep-whole arrangements, which would increase our exposure to commodity price risk, as the revenues generated from those contracts directly correlate with the fluctuating price of the underlying commodities.

Furthermore, we may acquire or develop additional midstream assets in the future that have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatility of natural gas and crude oil prices could have a material adverse effect on our business, results of operations and financial condition. For example, for a small portion of the natural gas gathered on our systems, we purchase natural gas from producers prior to delivering the natural gas to pipelines where we typically resell the natural gas under arrangements including sales at index prices. Generally, the gross margins we

realize under these arrangements decrease in periods of low natural gas prices. If we expand the implementation of such natural gas purchase and sale arrangements within our business, such fluctuations could materially affect our business.

Regulatory and Environmental Policy Risks

We settled a matter that was previously under investigation by federal and state regulatory agencies regarding a pipeline rupture and release of produced water by one of our subsidiaries. The resulting compliance requirements of the settlement may impact our results of operations or cash flows.

On August 4, 2021, we settled an incident involving a produced water disposal pipeline owned by our subsidiary Meadowlark Midstream that resulted in a discharge of materials into the environment, which was investigated by federal and state agencies. This settlement resulted in losses amounting to $36.3 million and will be paid over five (5) to six (6) years, of which we have paid principal amounts of $28.0 million as of December 31, 2025, and requires compliance with certain conditions and terms and conditions, which may impact our results of operations or cash flows.

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. As a result, we may be required to expend significant funds for legal defense or to settle claims. Any such loss, if incurred, could be material.

Expenditures made by us for the payment of litigation related costs, including legal defense costs and settlement payments, if any, reduce our cash flows available for debt service and dividends. Any such expenditures, if incurred, could be material.

A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenues to decline or our operation and maintenance expenses to increase.

Various aspects of our operations are subject to regulation by the various federal, state, and local departments and agencies that have jurisdiction over participants in the energy industry. The regulation of our activities and the natural gas and crude oil industries frequently change as they are reviewed by legislators and regulators. For example, in January 2025, PHMSA submitted a final rule to the Federal Register to amend regulations to reduce methane emissions from new and existing gas transmission, distribution, and regulated gas gathering pipelines with strengthened leakage survey and patrolling requirements, performance standards for advanced leak detection programs, leak grading and repair criteria with mandatory repair timelines, requirements for mitigation of emissions from blowdowns, pressure relief device design, configuration, and maintenance requirements, clarified requirements for investigating failures, and expanded reporting requirements. However, before the final rule could be published in the Federal Register, President Trump issued a “regulatory freeze” executive order, withdrawing the rule and preventing its publication in the Federal Register. In addition, the U.S. House of Representatives has not passed H.R. 4818, a bill introduced in July 2025 to effectuate the January 2025 final rule. To the extent these or other new proposed or final rules create additional requirements for our pipelines, they could have a material adverse effect on our operations, operating and maintenance expenses and revenues. For additional information on the potential risks associated with PHMSA requirements, see “—We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements.”

In addition, the adoption of proposals for more stringent legislation, regulation or taxation of drilling activity could directly curtail such activity or increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for our services. For example, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the Colorado Energy and Carbon Management Commission (“ECMC,” formerly the Colorado Oil and Gas Conservation Commission) from fostering oil and gas development to regulating oil and gas development in a reasonable manner to protect public health and the environment. The law also allows local governments to impose more restrictive requirements on oil and gas operations than those issued by the state. As part of its implementation of this law, in November 2020 the ECMC adopted new regulations that increase oil and gas setbacks to a minimum of 2,000 feet from schools and childcare facilities, prohibit routine venting and flaring, increase wildlife protections, and alter certain aspects of the permitting process. In addition, in May 2024, the Governor of Colorado signed into law Senate Bill 24-230, which imposes a production fee that applies to all oil and gas produced by a producer in the state on or after July 1, 2025, to fund clean transit initiatives. These regulations and similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. Regulatory agencies establish and, from time to time, change priorities, which may result in additional burdens on us, such as additional reporting requirements and more frequent audits of operations. Our operations and the markets in which we participate are affected by these laws, regulations and interpretations and may be affected by changes to them or their implementation, which may cause us to realize materially lower revenues or incur materially increased operation and maintenance costs or both.

Increased regulation of hydraulic fracturing could result in reductions or delays in customer production, which could materially adversely impact our revenues.

Hydraulic fracturing is an important and increasingly common practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations and is primarily regulated by state agencies. However, Congress has in the past considered, and may in the future consider, legislation to regulate hydraulic fracturing by federal agencies. Many states have

already adopted laws and/or regulations that require disclosure of the chemicals used in hydraulic fracturing. A number of states – 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, Washington, California, 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.

The EPA has also moved forward with various regulatory actions, including announcing final new regulations under the NSPS to expand and strengthen emissions reduction requirements for new, modified, and reconstructed oil and natural gas sources, and require states to reduce methane emissions from existing sources nationwide. The BLM has also asserted regulatory authority over aspects of the hydraulic fracturing process and issued a final rule in March 2015 that established more stringent standards for performing hydraulic fracturing on federal and Indian lands, including requirements relating to well construction and integrity, handling of wastewater and chemical disclosure. However, in December 2017, the BLM published a final rule rescinding the 2015 rule. The U.S. District Court for the Northern District of California upheld the December 2017 rescission rule in a March 2020 decision, and the State of California and environmental plaintiffs appealed. A motion by the State of California to voluntarily dismiss the appeal was granted in September 2025. The March 2015 rule currently remains rescinded.

Further, several federal governmental agencies (including the EPA) have conducted reviews and studies on the environmental aspects of hydraulic fracturing in the past. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing.

Additionally, certain of our customers produce oil and gas on federal lands. On January 20, 2021, the Acting Secretary for the DOI signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. In April 2024, the DOI finalized updates to its onshore oil and gas leasing regulations, including revised royalty rates and bonding requirements and attempts to direct oil and gas development away from wildlife habitat and cultural sites, which could further restrict oil and gas exploration and production on federal lands. However, in January 2025, President Trump issued executive orders directing the heads of federal agencies to (i) facilitate the leasing of domestic energy resources, including on federal lands and (ii) identify and begin the processes to suspend, revise, or rescind all agency actions that impose an undue burden on the identification, development, or use of domestic energy resources. In addition, in September 2025, the DOI announced its intent to rescind the April 2024 rule. As a result, future implementation and enforcement of the final rule remains uncertain.

If new or more stringent federal, state, or local legal restrictions relating to drilling activities or to the hydraulic fracturing process are adopted, this could result in a reduction in the supply of natural gas and/or crude oil that our customers produce, and could thereby adversely affect our revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for our customers, which could ultimately decrease end-user demand for our services and could have a material adverse effect on our business.

We are subject to FERC jurisdiction, federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements and state, and local regulation and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced.

We believe that our natural gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC under the NGA and the NGPA. Interstate movements of crude oil on the Epping Pipeline in North Dakota are subject to FERC jurisdiction under the ICA, and the rates, terms and conditions of service, and practices on the pipeline are subject to review and challenge before FERC.

Additionally, the Double E Pipeline, which provides interstate natural gas transmission service from southeastern New Mexico to the Waha hub in Texas, is subject to FERC jurisdiction under the NGA with respect to post-construction remediation activities, operations, and rates and terms and conditions of service. Pursuant to the NGA, Double E Pipeline’s existing interstate natural gas transportation 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. We cannot guarantee that any new or existing tariff rate for service on our FERC-regulated pipelines would not be rejected or modified by the FERC or subjected to refunds. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on our business, financial condition, and results of operations.

Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate,” which is generally fixed between the natural gas pipeline and the shipper for the contract term and does not necessarily vary with changes in the level of cost-based “recourse rates,” provided that the affected customer is willing to agree to such rates and that the FERC has accepted the negotiated rate agreement. These “negotiated or discount rate” contracts are not generally subject to adjustment for increased costs, which could be caused by inflation or other factors relating to the specific facilities being used to perform the services and, as a result, our costs could exceed our revenues received under such contracts. Any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated or discounted rates, under current FERC policy, may be recoverable from other shippers in certain circumstances. For example, the FERC may recognize this shortfall in the determination of prospective rates in a future rate case. However, if the FERC were to disallow the recovery of such costs from other customers, it could decrease the cash flow realized by our assets.

We are also generally subject to the anti-market manipulation provisions in the NGA, as amended by the Energy Policy Act of 2005, and to FERC’s regulations thereunder, and also must comply with the other applicable provisions of the NGA and NGPA and FERC’s rules, regulations, and orders concerning the Double E Pipeline’s interstate natural gas pipeline business, including those that require us to provide firm and interruptible transportation service on an open access basis that is not unduly discriminatory or preferential. Violations of the NGA or NGPA, or the rules, regulations, and orders issued by FERC thereunder could result in the imposition of administrative and criminal remedies, including without limitation, revocation of certain authorities, disgorgement of ill-gotten gains, and civil penalties of up to approximately $1.6 million per day per violation of the NGA or its implementing regulations, subject to future adjustment for inflation. In addition, the FTC holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in oil markets and has adopted broad rules and regulations prohibiting fraud and market manipulation. The FTC is also authorized to seek fines of up to approximately $1.5 million per violation, subject to future adjustment for inflation. The CFTC is directed under the CEA to prevent price manipulation in the commodity, futures, and swaps markets, including the energy markets. Pursuant to the Dodd-Frank Act, and other authority, the CFTC has adopted additional anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity, futures, and swaps markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of approximately $1.5 million per violation, subject to future adjustment for inflation, or triple the monetary gain to the violator for each violation of the anti-market manipulation provisions of the CEA.

The distinction between federally unregulated natural gas and crude oil pipelines and FERC-regulated natural gas and crude oil pipelines has been the subject of extensive litigation and is determined by FERC on a case-by-case basis. FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC, Congress, or the courts. If our natural gas gathering operations or crude oil operations beyond the Epping Pipeline become subject to FERC jurisdiction under the NGA, the NGPA or the ICA, the result may materially adversely affect the rates we are able to charge and the services we currently provide and may include the potential for a termination of our gathering agreements with our customers. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, the NGPA or the ICA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such services in excess of the rate established by FERC.

We are subject to state and local regulation regarding the construction and operation of our gathering, treating, transporting, and processing systems, as well as state ratable take statutes and regulations. Regulation of the construction and operation of our facilities may affect our ability to expand our facilities or build new facilities and such regulation may cause us to incur additional operating costs or limit the quantities of natural gas and crude oil we may gather, treat, and process. Ratable take statutes and regulations generally require gatherers to take natural gas and crude oil production that may be tendered for gathering without undue discrimination. These requirements restrict our right to decide whose production we gather, treat, and process. Many states have adopted complaint-based regulation of gathering, treating, transporting, and processing activities, which allows producers and shippers to file complaints with state regulators in an effort to resolve access issues, rate grievances, and other matters. Other state and municipal regulations do not directly apply to our business but may nonetheless affect the availability of natural gas and crude oil for gathering, treating, transporting, and processing, including state regulation of production rates, maximum daily production allowable from wells, and other activities related to drilling and operating wells. While our facilities currently are subject to limited state and local regulation, there is a risk that state or local laws will be changed or reinterpreted, which may materially affect our operations, operating costs, and revenues.

We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.

Our gathering, treating, transporting, and processing operations are subject to stringent and complex federal, state, and local environmental laws and regulations, including laws and regulations regarding the discharge of materials into the environment or otherwise relating to environmental protection, including, for example, the CAA, the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Water Act, the Oil Pollution Control Act, the Resource Conservation and Recovery Act, the ESA and the Toxic Substances Control Act. It is possible that future changes in environmental laws, regulations, or enforcement policies, including judicial or agency opinions or orders, could impose additional requirements or give rise to claims for damages to persons, property, natural resources, or the environment.

These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and requisite permits may result in the assessment of significant administrative, civil, and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.

There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbons and other wastes and potential emissions and discharges related to our operations. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering systems pass, and on which certain of our facilities are located, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. In addition, changes in environmental laws occur frequently, and any such changes that result in additional permitting obligations or more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance.

Revisions to the leasing and permitting programs for oil and gas development on federal lands could materially adversely affect our industry and our financial condition, and results of operations.

We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements.

The DOT, through PHMSA, has adopted and enforces safety standards, and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations that are identical to or more restrictive than existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream Services LLC system is located. While the majority of our pipelines have historically met the DOT definition of gathering lines and were thus exempt from PHMSA’s integrity management requirements, we also operate a limited number of pipelines that are subject to the integrity management requirements. The regulations require operators, including us, to:

•perform ongoing assessments of pipeline integrity;

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

•maintain processes for data collection, integration and analysis;

•repair and remediate pipelines as necessary;

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

•implement preventive and mitigating actions.

For additional information on PHMSA regulations relating to pipeline safety, see “—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.”

Climate change legislation, regulatory initiatives, and litigation could result in increased operating costs and reduced demand for the services we provide.

The U.S. Congress has considered legislation to restrict or regulate emissions of GHGs, such as carbon dioxide and methane, that may be contributing to global warming and energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. For example, the IRA, signed into law in August 2022, includes a Methane Emissions Reduction Program to incentivize methane emission reductions and impose a WEC on GHG emissions from certain oil and gas facilities that are already required to report under the EPA’s GHG reporting rule. Emissions reported under the GHG reporting rule will be the basis for any payments under the Methane Emissions Reduction Program. However, in March 2025, President Trump signed Congress’ Joint Resolution of Disapproval of the WEC and in May 2025, the EPA issued a final rule removing the WEC regulations from the Code of Federal Regulations. In July 2025, the One Big Beautiful Bill Act postponed the WEC’s effective date to 2034. Consequently, future implementation and enforcement of these rules remains uncertain at this time.

In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. In general, the number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). It is possible that certain components of our operations, such as our gas-fired compressors, could become subject to state-level GHG-related regulation. For example, in June 2022, as part of a Governor-directed statewide initiative to reduce GHG emissions by at least 45% by 2030, the New Mexico Environment Department finalized rules that establish emissions standards for volatile organic compounds and nitrogen oxides for oil and gas production and processing sources located in certain areas of the state with high ozone concentrations. Similarly, due to recent legislation approved in May 2024, the Colorado Department of Public Health and Environment is now required to propose rules to the Colorado Air Quality Control Commission to reduce nitrogen oxide emissions that oil and gas operations generate by 50% by 2030 relative to 2017 levels. We cannot currently determine the effect of these proposed regulations and other regulatory initiatives to implement state directives to reduce GHG emissions, that could, if implemented, impact the business, reputation, financial condition, or results of our operations or that of our customers. In addition, in April 2021, the New Mexico Department of Energy, Minerals, and Natural Resources (“EMNRD”) finalized rules concerning venting and flaring of natural gas. EMNRD’s final rule could impose new or increased costs and obligations on our customers upstream of the Double E Pipeline.

Independent of Congress, the EPA has adopted regulations under its existing CAA authority. In 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes (the “Endangerment Finding”). Based on these findings, the EPA adopted regulations that, among other things, establish Prevention of Significant Deterioration construction and Title V operating permit reviews for certain large stationary sources of GHG emissions. However, in February 2026, the EPA issued a final rule rescinding the Endangerment Finding, asserting that the Endangerment Finding exceeded the agency’s statutory authority. That same month, a coalition of environmental and public health organizations filed suit challenging the rescission. The implications of the February 2026 rule, including any subsequent changes to existing emissions standards, and the ultimate outcome of the related litigation remain uncertain.

At the international level, the U.S. joined the international community at the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change in Paris, France in 2021, which resulted in the Paris Agreement, pursuant to which signatory countries agreed to nationally determine their contributions and set GHG emission reduction goals. In January 2025, President Trump issued an executive order directing the immediate notice to the United Nations of the U.S.’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. The withdrawal became effective in January 2026. The U.S. did not send an official delegation to COP30, and on January 7, 2026, President Trump announced the formal withdrawal of the U.S. from the United Nations Framework Convention on Climate Change in a presidential memorandum. At the same time, various state and local governments in the U.S. have committed to continue furthering the goals of the Paris Agreement, and many of these initiatives are expected to continue. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon intensive sectors.

Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal or state laws or implementing regulations

that may be adopted to address climate change and GHG emissions could require us to incur increased operating costs and could materially adversely affect demand for our services. The potential increase in the costs of our operations resulting from any legislation or regulation to address climate change or restrict emissions of GHG could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions, adhere to alternative energy requirements and administer and manage a GHG emissions program. While we may be able to include some or all of such increased costs in the rates we charge, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

In the Dodd-Frank Act, Congress adopted comprehensive financial reform legislation that establishes federal oversight over and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. Under this legislation, the CFTC and the SEC and other regulatory authorities have promulgated rules and regulations, including rules and regulations relating to the regulation of certain swaps market participants, such as swap dealers, the clearing of certain swaps through central counterparties, the execution of certain swaps on designated contract markets or swap execution facilities, mandatory margin requirements for uncleared swaps, and the reporting and recordkeeping of swaps. In light of the continuing adjustment of the regulations, we cannot predict the ultimate effect of the rules and regulations on our business. Any new regulations or modifications to existing regulations could increase the cost of derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, or increase our exposure to less creditworthy counterparties.

In October 2020, the CFTC adopted rules that place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. We do not expect these regulations to materially impede our hedging activity at this time, but a companion rule on aggregation among entities under common ownership or control may have an impact on our ability to hedge our exposure to certain enumerated commodities.

The CFTC has implemented final rules regarding mandatory clearing of certain classes of interest rate swaps and certain classes of index credit default swaps. Mandatory trading on designated contract markets or swap execution facilities of certain interest rate swaps and index credit default swaps also began in 2014. At this time, the CFTC has not proposed any rules designating other classes of swaps, including physical commodity swaps, for mandatory clearing. The CFTC and prudential banking regulators also adopted mandatory margin requirements on uncleared swaps between swap dealers and certain other counterparties. Although we may qualify for a commercial end-user exception from the mandatory clearing, trade execution and certain uncleared swaps margin requirements, mandatory clearing and trade execution requirements and uncleared swaps margin requirements applicable to other market participants, such as swap dealers, may affect the cost and availability of the swaps that we use for hedging.

Under the Dodd-Frank Act, the CFTC is also directed generally to prevent price manipulation and fraud in the following two markets: (i) physical commodities traded in interstate commerce, including physical energy and other commodities, and (ii) financial instruments, such as futures, options, and swaps. The CFTC has adopted additional anti-market manipulation, anti-fraud and disruptive trading practices regulations that prohibit, among other things, fraud and price manipulation in the physical commodities, futures, options, and swaps markets. Should we violate these laws and regulations, we could be subject to CFTC enforcement action, material penalties, and sanctions.

We currently enter into forward contracts with third parties to buy power and sell natural gas in an attempt to mitigate our exposure to fluctuations in the price of natural gas with respect to those volumes. The CFTC has finalized an interpretation clarifying whether and when certain forwards with volumetric optionality are to be regulated as forwards or qualify as options on commodities and therefore swaps. The application of this interpretation to any particular situation may impact our ability to enter into certain forwards or may impose additional requirements with respect to certain transactions.

In addition to the Dodd-Frank Act, regulators within the European Union and other foreign regulators have adopted and implemented local reforms generally comparable with the reforms under the Dodd-Frank Act. Enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties or may make any transactions involving cross-border swaps more expensive and burdensome. Additionally, the lingering absence of regulatory equivalency across jurisdictions may increase compliance costs and make it more costly to satisfy regulatory obligations.

We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from various groups.

We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from environmental groups, landowners, local groups, and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt, or delay the development or operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or other facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could have a material adverse effect on our business, financial condition, and results of operations. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business.

For example, in an April 15, 2020 ruling, amended May 11, 2020, the U.S. District Court for the District of Montana issued an order invalidating the Corps 2017 reissuance of Nationwide Permit 12 (“NWP 12”), the general permit governing discharges of dredged or fill material associated with pipeline and other utility line construction projects, to the extent it was used to authorize construction of new oil and gas pipelines. Environmental groups had alleged that the Corps failed to consult with federal wildlife agencies as required by the ESA. However, in January 2021, the EPA and Corps reissued NWP 12 as a general permit specific to oil and gas pipelines, moving other utility line activities into separate general permits. The U.S. Court of Appeals for the Ninth Circuit subsequently held that the Corps’ January 2021 reissuance rendered the prior challenge moot. In May 2021, environmental groups once again filed suit in the U.S. District Court for the District of Montana, seeking vacatur of the reissued NWP 12. In September 2022, the U.S. District Court for Montana dismissed the ESA consultation challenges as moot and dismissed the remainder of the lawsuit without prejudice after the Corps announced in March 2022 that it was undertaking a formal review of all nationwide permits. However, in January 2025, President Trump issued executive orders directing (i) the Corps to use emergency authorities and nationwide permits to grant approvals for energy projects under Section 404 of the CWA and (ii) the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. In December 2025, the Corps announced the reissuance of NWP 12 as part of the 2026 Nationwide Permits. To the extent that limitations are imposed on the use of NWP 12 in the future, such limitations could make it more difficult to permit our projects, require consideration of alternative construction or siting, which may impose additional costs and delays, and could cause us to lose potential and current customers and limit our growth and revenue.

In addition, on July 6, 2020, the U.S. District Court for the District of Columbia issued an order vacating a Corps Mineral Leasing Act easement for the Dakota Access Pipeline in a lawsuit filed by the Standing Rock Sioux Tribe and other Native American tribes. The court’s decision requires the pipeline to shut down operations by August 5, 2020 but was stayed by the U.S. Court of Appeals for the District of Columbia Circuit. On January 26, 2021, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision affirming the district court’s holding that the easement should be vacated but reversing the requirement to shut down the pipeline. The Court of Appeals left it to the Corps to determine how to proceed after the loss of the easement, and while the Corps declined to shut down the pipeline, it did not formally approve the pipeline’s ongoing operation without an easement. Dakota Access filed for rehearing en banc on April 12, 2021, which the Court of Appeals denied. On September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General and plaintiffs, and Dakota Access has filed its reply.

The Dakota Access Pipeline continues to operate pending the Corps’ ongoing development of a court-ordered environmental impact statement for the project. On June 22, 2021, the District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. On January 20, 2022, the Standing Rock Sioux Tribe withdrew as a cooperating agency on the draft Environmental Impact Statement (“EIS”), prompting the Corps to temporarily pause on the draft EIS. The Corps published the draft EIS on September 8, 2023 and tribal and public meetings were held in November and December of 2023. A final EIS was released in December 2025. If the Dakota Access Pipeline is forced to shut down, this could have a material adverse effect on our business, financial condition, and results of operations associated with the Polar and Divide system, which interconnects with the Dakota Access Pipeline.

Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in an increasing number of financial institutions, funds, individual investors and other sources of capital restricting or eliminating their investment in fossil fuel-related activities. In addition, financial institutions have begun to screen companies such as ours for sustainability performance, including practices related to

GHGs and climate change, before providing loans or investing in our equity securities. There is also a risk that financial institutions may adopt policies that have the effect of reducing the funding provided to the fossil fuel sector, such as the adoption of net zero financed emissions targets. Ultimately, this could make it more difficult to secure funding for exploration and production activities or energy infrastructure related projects or adversely impact our cost of capital, and consequently could both indirectly affect demand for our services and directly affect our ability to fund construction or other capital projects. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable in order to improve our sustainability performance and to meet the specific requirements to maintain access to capital or perform services for certain customers.

Our business is subject to complex and evolving United States and international laws and regulations regarding privacy and data protection (“data protection laws”). Many of these data protection laws are subject to change and uncertain interpretation, and could result in claims, increased cost of operations or otherwise harm our business.

Along with our own data and information that we collect and retain in the normal course of our business, we and our business partners collect and retain significant volumes of certain other types of data, some of which are subject to data protection laws. The regulatory environment surrounding the collection, use, transfer, and protection of such data, both domestically and internationally, is becoming increasingly complex, constantly evolving, and is subject to frequent significant change. New data protection laws at the federal, state, international, national, provincial, and local levels, including Colorado, Connecticut, Virginia, and Utah legislation, the GDPR and the CCPA, pose increasingly complex compliance challenges and potentially elevate our costs.

Complying with these jurisdictional requirements could increase the costs and complexity of compliance procedures, and violations of applicable data protection laws can result in significant penalties. For example, the GDPR applies to activities regarding personal data that may be conducted by us, directly or indirectly through business partners. Failure to comply could result in significant penalties of up to a maximum of 4% of our global turnover that may materially adversely affect our business, reputation, results of operations, and cash flows. Similarly, the CCPA, which came into effect on January 1, 2020, and was further amended on January 1, 2023, by the CPRA, imposes specific obligations on businesses that collect personal data from California residents and provides California residents specific rights in relation to their personal data that we or our business partners collect and use. As interpretation and enforcement of the CCPA evolves, it creates a range of new compliance obligations, which could necessitate we change our business practices, and carries the possibility for significant financial penalties for noncompliance that may materially adversely affect our business, reputation, results of operations, and cash flows.

As noted below, we are also subject to the possibility of information security breaches, which themselves may result in material financial and reputational exposure under such data protection laws. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.

Risks Related to the Common Stock and Series A Preferred Stock

The price of the common stock or Series A Preferred Stock may experience volatility.

The price of our common stock or the Series A Preferred Stock may be volatile. In addition to the risk factors described above, some of the factors that could affect the price of our common stock are quarterly increases or decreases in revenue or earnings, changes in revenue or earnings estimates by the investment community, sales of the common stock by significant stockholders, a turnover of the investor base as a result of the Corporate Reorganization, short-selling of the common stock or Series A Preferred Stock by investors, issuance of a significant number of shares for equity-based compensation or to raise additional capital to fund our operations, changes in market valuations of similar companies and speculation in the press or investment community about our financial condition, or results of operations, as well as any doubt about its ability to continue as a going concern. General market conditions and U.S. or international economic factors and political events unrelated to our performance may also affect our stock price. For these reasons, investors should not rely on recent trends in the price of the common stock or Series A Preferred Stock to predict the future price of the common stock or Series A Preferred Stock or our future financial results.

Our Governing Documents contain provisions that may make it difficult for a third party to acquire control of the Company, even if a change in control would result in the purchase of your shares of common stock or Series A Preferred Stock at a premium to the market price or would otherwise be beneficial to you.

There are provisions in our amended and restated certificate of incorporation (the “Charter”), our amended and restated bylaws (the “Bylaws”) and the Certificate of Designation of Series A Floating Rate Cumulative Redeemable Perpetual Preferred Stock (the “Series A Certificate of Designation” and, together with the Charter and the Bylaws, the “Governing Documents”) that may make it difficult for a third party to acquire control of the Company, even if a change in control would result in the purchase of your shares of common stock or Series A Preferred Stock at a premium to the market price or would otherwise be beneficial to you. For example, the Charter authorizes the Board of Directors to issue preferred stock, $0.01 par value per share (“Preferred Stock”), and common stock, $0.01 par value per share (“ Blank Check Common Stock”), without stockholder

approval. If the Board of Directors elects to issue Preferred Stock or Blank Check Common Stock, it could be more difficult for a third party to acquire the Company.

In addition, provisions of the Governing Documents, including a classified Board of Directors and limitations on stockholder actions by written consent and on stockholder proposals and director nominations at meetings of stockholders, could make it more difficult for a third party to acquire control of the Company. Certain provisions of the DGCL may also discourage takeover attempts that have not been approved by the Board of Directors.

We do not expect to pay dividends on our common stock for the foreseeable future.

We do not expect to pay dividends for the foreseeable future. In addition, the Amended and Restated ABL Facility may limit our subsidiaries subject thereto from distributing cash to the Company, without the prior consent of the lenders under the Amended and Restated ABL Facility, thereby limiting our ability to pay dividends to equity holders, other than dividends payable solely in additional equity interests in the Company.

The value of our common stock may be diluted by future equity issuances and shares eligible for future sale may have adverse effects on our share price.

We cannot predict the effect of future sales of shares or the availability of shares for future sales, on the market price of or the liquidity of the market for the shares. Sales of substantial amounts of shares, or the perception that such sales could occur, could adversely affect the prevailing market price of the shares. Such sales, or the possibility of such sales, could also make it difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.

In the Tall Oak Acquisition, we issued 7,471,008 shares of Class B Common Stock to Tall Oak Parent in exchange for 100% of the equity interests in Tall Oak. Such shares of Class B Common Stock are exchangeable for shares of our common stock at the election of the holder for no additional consideration. Pursuant to that certain Investor and Registration Rights Agreement, dated as of December 2, 2024, 6,524,467 shares of Class B Common Stock and associated Partnership Common Units that were issued and subsequently transferred by Tall Oak Parent to Tailwater Energy Fund III, LP (“Tailwater”) and its designees may not be transferred until one year after closing, after which time 50% of such securities will be available for resale, with the remaining 50% available for resale two years after closing. With respect to the 946,541 shares of Class B Common Stock and associated Partnership Common Units issued to Tall Oak Parent and subsequently transferred to Tall Oak Midstream Investments, LLC (“TOMI”), TOMI exercised its exchange right in full on January 1, 2025. However, TOMI may not sell the common stock received upon exchange until six months after the closing, after which time 50% of such common stock will be available for resale, with the remainder of the common stock held by TOMI being available for resale one year after the closing. Tailwater and TOMI may decide to reduce their investment in the Company at any time thereafter. Any such sales of our equity securities, or expectations thereof, could have the effect of depressing the market price for our common stock.

Our authorized capital stock consists of 42,000,000 shares of common stock, 500,000 shares of Preferred Stock and 30,000,000 shares of Blank Check Common Stock, a significant portion of which are currently unissued. We may need to raise a significant amount of capital to fund our operations and pay down outstanding indebtedness, including borrowings on the Amended and Restated ABL Facility, the New Permian Transmission Facility, and the 2029 Secured Notes, and may raise such capital through the issuance of newly issued common stock, Preferred Stock or Blank Check Common Stock. Such issuance and sale of equity could be dilutive to the interests of existing stockholders.

Risks Related to Tax

The Company is a holding company, and its principal asset is our ownership of Partnership Common Units. Accordingly, we are dependent upon distributions from SMLP to pay dividends, if any, and to pay taxes and other expenses.

The Company is a holding company whose principal asset is Partnership Common Units, and the Company has no independent means of generating revenue. SMLP is, and will continue to be, treated as a partnership for U.S. federal and applicable state and local income tax purposes and, as such, will generally not be subject to applicable federal, state, and local income taxes. SMLP’s taxable income will be allocated to holders of Partnership Common Units, including us. Accordingly, the Company will incur income taxes on its allocable share of any taxable income of SMLP.

In addition, the Up-C Structure confers certain benefits upon Tall Oak Parent and its transferees that will not benefit the holders of common stock and Series A Preferred Stock to the same extent as it will benefit the holders of Tall Oak Parent and its transferees. If SMLP makes distributions to Tall Oak Parent or its transferees, Tall Oak Parent or its transferees can distribute such amounts to holders of Tall Oak Parent or its transferees without reduction for taxes. However, because the Company must pay corporate-level taxes, amounts ultimately distributed as dividends, if any, in the future, to holders of common stock and Series A Preferred Stock are expected to be less on a per share basis than the amounts distributed by Tall Oak Parent or its transferees to their respective holders on a per unit basis. This and other aspects of the Up-C Structure may adversely impact the future trading market for the common stock and Series A Preferred Stock.

The Tall Oak Acquisition, Moonrise Acquisition, and subsequent changes in stock ownership of the Company (including upon the redemption or exchange of the shares of Class B Common Stock and associated Partnership Common Units for common stock) may trigger a limitation on the utilization of net operating loss carryforwards of the Company.

The Company’s ability to utilize U.S. net operating loss carryforwards to reduce future taxable income depends on many factors, including its future income, which cannot be assured. Section 382 and 383 of the Code generally impose an annual limitation on the amount of net operating losses and certain other tax attributes that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382 of the Code). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of such corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change occurs, utilization of net operating losses by the Company would be subject to an annual limitation under Section 382, generally determined by, subject to certain adjustments, multiplying (1) the fair market value of its stock immediately before the ownership change by (2) the long-term tax-exempt rate published by the IRS for the month in which the ownership change occurs. Any unused annual limitation may be carried over to later years. In addition, an ownership change may arise as a result of subsequent changes in the Company’s stock ownership, including as a result of redemptions or exchanges of shares of Class B Common Stock and associated Partnership Common Units for common stock, which would trigger a limitation on the Company’s ability to utilize net operating loss carryforwards.

If SMLP were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, the Company and SMLP might be subject to potentially significant tax inefficiencies.

Our intent is to cause SMLP to be operated in a manner such that SMLP does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, the exchange of shares of Class B Common Stock for common stock or other transfers of Partnership Common Units could cause SMLP to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that exchanges or other transfers of Partnership Common Units qualify for one or more of such safe harbors. For example, we intend to limit the number of holders of Partnership Common Units, and the A&R Partnership Agreement provides for certain limitations on the ability of holders of common units to transfer their common units and provides the General Partner with the right to impose restrictions on the ability of limited partners to exchange their Partnership Common Units for common stock pursuant to the redemption right to the extent the General Partner believes there is a material risk that SMLP would be a publicly traded partnership as a result of such exercise. If, notwithstanding our intent above, SMLP were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, the Company and SMLP might be subject to potentially significant tax inefficiencies, such as two layers of corporate taxation if the Company were unable to file a consolidated U.S. federal income tax return with SMLP.

Risks Related to Terrorism and Cyberterrorism

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

Terrorist attacks and threats, escalation of military activity, or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the U.S. or its allies, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the U.S. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, and results of operations. Our insurance may not protect us against such occurrences.

Our operations depend on the use of IT and OT systems that could be the target of a cyberattack, including state-sponsored attacks or cyberterrorism.

Cybersecurity threats present a large and growing risk to our business as a result of the proliferation of new technologies

(including artificial intelligence) thereby increasing the sophistication of cyber-attacks and the oil and gas industry becoming increasingly dependent on digital technologies to conduct day-to-day operations, including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of remote communication devices has increased rapidly. Industrial control systems now control large scale processes that can include multiple sites and long distances, such as oil and gas pipelines.

Our operations depend on the use of sophisticated IT and OT systems. These systems, as well as those of our customers, business partners and counterparties, may become the target of cyber-attacks or information security breaches including but not limited to ransomware, phishing attacks, denial of service attacks, viruses, malware, and the exploitation of software

vulnerabilities. Additionally, increased remote access to information systems by employees and contractors can increase exposure to potential cybersecurity incidents.

Any such cyber-attacks or information security breaches could have a material adverse effect on our revenues and increase our operating and capital costs and could reduce the amount of cash otherwise available for distribution. A cyber-incident involving our IT or OT systems, or that of our customers, business partners or counterparties, could disrupt our business plans and negatively impact our reputation and operations in the following ways, among others:

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

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

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

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

•business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation or a negative impact on the price of our common stock or Series A Preferred Stock.

Cyber-incidents and related business interruptions could result in expensive and time-consuming remediation efforts, disproportionate attention of management, damage to our reputation or a negative impact on the price of our common stock or Series A Preferred Stock. In addition, certain cyberattacks and related incidents, such as reconnaissance or surveillance by threat actors, may remain undetected for an extended period notwithstanding our monitoring and detection efforts. As a result, we may be required to incur additional costs to modify or enhance our IT or OT systems to prevent or remediate any such attacks. Despite the efforts we take to detect, mitigate, and eliminate threats and respond to cyber-incidents, the techniques used by those who wish to obtain unauthorized access, and possibly disable or sabotage systems and/or abscond with information and data, continue to evolve, and we may not be able to anticipate and protect against all such threats. Finally, readily evolving laws and regulations governing cybersecurity pose increasingly complex compliance technical challenges, and failure to comply with these laws could result in penalties and legal liability.

Item 1B. Unresolved Staff Comments.

Not applicable.

Item 1C. Cybersecurity Risk Management, Strategy and Governance.

Cybersecurity Oversight and Management

Board Oversight of Cybersecurity Matters

The Audit Committee is tasked with overseeing the Company’s cybersecurity matters. Pursuant to the Audit Committee’s charter, one of the Audit Committee’s responsibilities is to discuss the Company’s major risk exposures with management, including those related to cybersecurity, and the steps taken by management to monitor and control such exposures, including the Company’s risk assessment and risk management guidelines, policies and practices.

The Audit Committee reports to the entire Board of Directors periodically regarding its oversight of cybersecurity matters. In developing such updates to the Board of Directors, the Audit Committee relies in large part on periodic updates from the Company’s management.

Management of Cybersecurity Matters

The Company’s management assumes executive responsibility for assessing, identifying, and managing cybersecurity risks and incidents.

In particular, the Senior Vice President, Engineering and Operations (“SVP, E&O”) reports directly to the President, Chief Executive Officer, and Chairman of the Board and holds the highest level of executive responsibility for assessing and managing all cybersecurity threats, incidents, and risks at the Company, as well as developing and implementing all cybersecurity risk management, strategy, and governance recommendations.

The SVP, E&O holds key skills, experience, and competencies related to the management of cybersecurity matters. In particular, our current SVP, E&O has over 10 years of experience leading IT and OT physical security and cybersecurity.

The SVP, E&O is supported by critical internal positions within the Company, including but not limited to the Director of Information Technology, Vice President of Operational Technology and dedicated IT and OT resources with cybersecurity responsibilities. The SVP, E&O is further supported by various external parties, including but not limited to cybersecurity service providers, consultants, and other third parties engaged on an as-needed basis.

The Company’s management has processes in place by which it is informed of and monitors the prevention, detection, mitigation, and remediation of cybersecurity risks. These processes include, but are not limited to:

•Maintaining an updated inventory and management of digital assets;

•Ensuring familiarity and compliance with cybersecurity frameworks, including the National Institute of Standards and Technology’s Cybersecurity Framework and ISO 27001;

•Updating and maintaining an internal incident response plan, including conducting cybersecurity incident drills to periodically assess the adequacy of the incident response plan;

•Conducting risk assessments of the Company’s cybersecurity policies, practices, and tools;

•Employing appropriate antivirus, anti-malware, firewall, endpoint detection and response, backup and recovery software, multifactor authentication, virtual private network, account change monitoring, patch management, web content filter, spam filter and reporting, and vulnerability management software;

•Conducting regular vulnerability scans of the Company’s digital and operational infrastructure;

•Requiring employees to complete a Cybersecurity Awareness Program, which includes computer-based training; and

•Reviewing and evaluating developments in the threat landscape.

The Company’s management also has processes in place to oversee and identify material risks from cybersecurity threats associated with its use of third-party service providers. These processes include, but are not limited to:

•Maintaining an inventory of all third-party vendors engaged by the Company and assessing each vendor’s level of access to the Company’s IT and OT systems and information; and

•Implementing access controls that restrict vendor access to only specific Company systems and information necessary to perform their service.

The SVP, E&O provides updates to the Audit Committee at its quarterly meetings regarding management of the Company’s cybersecurity matters, including any new cybersecurity threats, incidents, risks, risk management solutions, trainings or education, infrastructure upgrades, or governance changes.

As of March 16, 2026, the Company’s business strategy, operations, or financial condition have not been materially affected by any cybersecurity threats or incidents.

Item 2. Properties.

A description of our properties is included in Item 1. Business, and is incorporated herein by reference. For additional information on our midstream assets and their capacities, see Item 1. Business.

Our real property falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our gathering systems and other major facilities are located are owned by us in fee title, and we believe that we have valid title to these lands. The remainder of the land on which our major facilities are located are held by us pursuant to long-term leases or easements between us and the underlying fee owner or permits with governmental authorities. We believe that we have valid leasehold estates or fee ownership in such lands or valid permits with governmental authorities. We have no knowledge of any material challenge to the underlying fee title of any material lease, easement, right-of-way, permit, or license held by us or to our title to any material lease, easement, right-of-way, permit, or license. We believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits, and licenses with the exception of certain ordinary course encumbrances and permits with governmental entities that have been applied for, but not yet issued.

In addition, we lease various office spaces to support our operations.

Item 3. Legal Proceedings.

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the ordinary course of business, we are not currently a party to any significant legal or governmental proceedings, except as described below. In addition, we are not aware of any significant legal or governmental proceedings contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

Fiberspar Corporation. On May 3, 2022, Fiberspar Corporation (“Fiberspar”) filed a petition in the District Court of Harris County, Texas alleging, before costs and interest, over $5.0 million owed but not paid 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 and a trial date has been set for April 2026. We are unable to predict the final outcome of this matter.

Global Settlement. On August 4, 2021, SMLP 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 U.S., 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 NDIC (together, the “Global Settlement”).

The Consent Decree provides for, among other requirements and subject to the conditions therein, (i) payment of total civil penalties and reimbursement of assessment costs of approximately $21.25 million, with the federal portion of penalties payable over up to five years and the state portion of penalties payable over up to, for the federal and state civil amounts, six years and, for the federal criminal amounts, five years, with interest accruing at, for the federal and state civil amounts, a fixed rate of 3.25% and, for the federal criminal amounts, a variable rate set by statute; (ii) continuation of remediation efforts at the site of the 2015 Blacktail Release; (iii) other injunctive relief, including, but not limited to, control room management, an environmental management system audit, training, and reporting; and (iv) no admission of liability to the U.S. or North Dakota. The Consent Decree was entered by the U.S. District Court on September 28, 2021.

The Consent Agreement settles a complaint brought by the NDIC in an administrative action against the Companies for alleged violations of the North Dakota Administrative Code (“NDAC”) arising from the 2015 Blacktail Release on the following terms: (i) the Companies admit to three counts of violating the NDAC; (ii) the Companies agree to follow the terms and conditions of the Consent Decree, including payment of penalty and reimbursement amounts set forth in the Consent Decree; and (iii) specified conditions in the Consent Decree regarding operation and testing of certain existing produced water pipelines shall survive until those pipelines are properly abandoned.

Under the Plea Agreement, the Companies agreed to, among other requirements and subject to the conditions therein, (i) enter guilty pleas for one charge of negligent discharge of a harmful quantity of oil and one charge of knowing failure to immediately report a discharge of oil; (ii) sentencing that includes payment of a fine of $15.0 million plus mandatory special assessments over a period of up to five years with interest accruing at the federal statutory rate; (iii) organizational probation for a minimum period of three years from sentencing on December 6, 2021, which will include payment in full of certain components of the fines and penalty amounts; and (iv) compliance with the remedial measures in the Consent Decree.

On December 6, 2021, the U.S. District Court accepted the Plea Agreement. This Global Settlement resulted in losses amounting to $36.3 million and will be paid over five to six years. As of December 31, 2025, we have paid principal amounts totaling $28.0 million and we intend to fully satisfy all monetary obligations by December 31, 2026.

Item 4. Mine Safety Disclosures.

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our common stock trades on the NYSE under the ticker symbol “SMC.” As of December 31, 2025, there were approximately 70 holders of our common stock and one holder of our non-economic Class B Common Stock. The number of holders of our common stock does not include holders that have common stock held for them in “street name,” meaning that the stock is held for their accounts by a broker or other nominee. In these instances, the brokers or other nominees are included in the number of registered holders, but the underlying holders of the common stock that hold such stock in “street name” are not.

During the year ended December 31, 2025, we did not pay any dividends on our shares of common stock. Our Board of Directors reinstated cash dividends on our Series A Preferred Stock beginning on March 14, 2025. During the year ended December 31, 2025, we paid cash dividends totaling $13.4 million on our Series A Preferred Stock.

Our Dividend Policy and Restrictions on Dividends

General

On May 3, 2020, we suspended distributions to holders of our common units and suspended payments of distributions to holders of our Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. Upon the consummation of the Corporate Reorganization, all accumulated and unpaid distributions on the Series A Preferred Units were deemed by the Series A Certificate of Designation to be Series A Unpaid Cash Dividends (as defined in the Series A Certificate of Designation), and any rights to accumulated and unpaid distributions on such Series A Preferred Units were discharged. Because our Series A Preferred Stock ranks senior to our common stock with respect to dividend rights, any accrued dividends on our Series A Preferred Stock must first be paid prior to the initiation of dividends to our holders of common stock. Our Board of Directors reinstated cash dividends on our Series A Preferred Stock beginning on March 14, 2025. As of December 31, 2025, the amount of accrued and unpaid dividends on the Series A Preferred Stock totaled $46.6 million. In March 2026, the Company’s Board of Directors approved the payment of any and all accrued and unpaid dividends on the Company’s Series A Preferred Stock, including the $46.6 million of accrued and unpaid dividends outstanding as of December 31, 2025. The Company expects to pay the accrued and unpaid dividends on the Series A Preferred Stock upon satisfaction of certain notice requirements, which the Company expects to complete by March 31, 2026.

Absent a material change to our business, we do not expect to pay dividends to holders of our common stock in the foreseeable future. Any future dividend payments will depend on our financial condition, market conditions and other matters deemed relevant by the Board of Directors. Additionally, our ability to pay dividends is subject to restrictions on dividends under our Amended and Restated ABL Facility and the indenture governing the 2029 Senior Notes.

Preferred Unit Dividends and Distributions

Series A Preferred Stock

The Company had 65,508 shares of Series A Preferred Stock outstanding as of December 31, 2025, and $46.6 million of accrued and unpaid dividends.

Dividends on our Series A Preferred Stock are cumulative and compounding and are payable quarterly in arrears on the 15th day of March, June, September and December of each year (each, a “Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Distribution Payment Date, in each case, when, as, and if declared by the Board of Directors out of legally available funds for such purpose.

The dividend rate for our Series A Preferred Stock is equal to the three-month SOFR plus a spread of 7.69%. See Note 12 - Equity and Mezzanine Equity to the consolidated financial statements for additional details. On February 28, 2025, we announced the resumption of dividends to holders of shares of Series A Preferred Stock. During the year ended December 31, 2025, cash dividend payments totaling $13.4 million were paid. In March 2026, the Company’s Board of Directors approved the payment of any and all accrued and unpaid dividends on the Company’s Series A Preferred Stock, including the $46.6 million of accrued and unpaid dividends outstanding as of December 31, 2025. The Company expects to pay the accrued and unpaid dividends on the Series A Preferred Stock upon satisfaction of certain notice requirements, which the Company expects to complete by March 31, 2026.

Subsidiary Series A Preferred Units

Permian Holdco had 93,039 Subsidiary Series A Preferred Units outstanding as of December 31, 2025.

Distributions on the Subsidiary Series A Preferred Units are cumulative and compounding and are payable quarterly in arrears 21 days after the quarter ending March, June, September and December of each year (each, a “Subsidiary Series A Preferred Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the

applicable Subsidiary Series A Preferred Distribution Payment Date, in each case, when, as, and if declared by the board of directors of Permian Holdco out of legally available funds for such purpose.

The distribution rate is 7.00% per annum of the $1,000 issue amount per outstanding Subsidiary Series A Preferred Unit. If the Subsidiary Series A Preferred Units were redeemed on December 31, 2025, the redemption amount would be $141.9 million, when considering the applicable multiple of invested capital metric and make-whole amount provisions contained in the Amended and Restated Limited Liability Company Agreement of Permian Holdco. The use of proceeds from the New Permian Transmission Facility will be used to, among other things, redeem in full the Subsidiary Series A Preferred Units. See “Part II Item 9 B. Other Information” and Note 12 - Equity and Mezzanine Equity to the consolidated financial statements for additional details.

Unregistered Sales of Equity Securities

We did not sell any unregistered equity securities during the quarter or year ended December 31, 2025.

Issuer Purchases of Equity Securities

We made no repurchases of our common stock or common units of the Partnership during the quarter or year ended December 31, 2025.

STOCK PERFORMANCE GRAPH

The following graph compares, for the last five years, the performance of our common stock to the S&P 500 Index and our peer group. The chart assumes that the value of our investment in our common stock and each index was $100 as of December 31, 2020, and that all dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance.

Our peer group consists of the following:

Antero Midstream Corporation

Archrock, Inc.

Delek Logistics Partners, LP

DT Midstream, Inc.

Excelerate Energy, Inc.

Enerflex Ltd.

Enterprise Products Partners L.P.

Energy Transfer, L.P.

Gibson Energy Inc.

Genesis Energy, LP

Hess Midstream LP

Kodiak Gas Services, Inc.

Kinder Morgan, Inc.

Kinetik Holdings Inc.

Cheniere Energy, Inc.

MPLX LP

New Fortress Energy Inc.

NGL Energy Partners LP

Oil States International Inc.

ONEOK, Inc.

Plains All American Pipeline, L.P.

Targa Resources Corp.

USA Compression Partners, LP

Western Midstream Partners, LP

The Williams Companies, Inc.

Select Water Solutions, Inc.

The information in this Form 10-K appearing under the heading “Stock Performance Graph” is being “furnished” pursuant to Item 2.01(e) of Regulation S-K under the Securities Act and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act of the Exchange Act except to the extent that we specifically request that it be treated as such.

Item 6. [Reserved]

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

This Management’s Discussion and Analysis of Financial Condition and Results of Operations is intended to inform the reader about matters affecting the financial condition and results of operations of the Company and its subsidiaries. As a result, the following discussion for the year ended December 31, 2025 should be read in conjunction with the consolidated financial statements and notes thereto included in this Annual Report. Among other things, the consolidated financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in Forward-Looking Statements. Actual results may differ materially from those contained in any forward-looking statements.

Unless the context requires otherwise or unless otherwise noted, all references to “Summit Midstream,” the “Company,” “we,” “us,” “our” or like terms are to Summit Midstream Corporation (including its subsidiaries) for the periods after August 1, 2024, the date the Corporate Reorganization was consummated. For the periods prior to August 1, 2024, unless the context requires otherwise or unless otherwise noted, all reference to “Summit Midstream,” or the “Company” are to Summit Midstream Partners, LP. (including its subsidiaries).

Overview

We are a value-oriented company focused on developing, owning, and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental U.S.

Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating, and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn a portion of our revenues from the following activities that directly expose us to fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers in the Rockies, Piceance and Mid-Con segments, (ii) the sale of natural gas we retain from certain Mid-Con segment customers, (iii) the sale of condensate we retain from our gathering services in the Rockies and Piceance segment and (iv) additional gathering fees that are tied to the performance of certain commodity price indexes which are then added to the fixed gathering rates. During the year ended December 31, 2025, these additional activities accounted for approximately 48% of our total revenues.

We also have indirect exposure to changes in commodity prices such that persistently low commodity prices may cause our customers to delay and/or cancel drilling and/or completion activities or temporarily shut-in production, which would reduce the volumes of natural gas and crude oil (and associated volumes of produced water) that we gather. If certain of our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, the associated MVCs, if any, ensure that we will earn a minimum amount of revenue.

The following table presents certain consolidated and reportable segment financial data. For additional information on our reportable segments, see the “Segment Overview for the Years Ended December 31, 2025 and 2024” section herein.


	Year ended December 31,
	2025		2024		2023
	(In thousands)
Net loss	$	(1,906)	$	(113,175)	$	(38,947)
Reportable Segment Adjusted EBITDA
Rockies	$	106,935	$	93,827	$	87,390
Permian	33,980		31,227		24,207
Mid-Con	92,377		30,645		26,171
Piceance	44,774		52,704		59,749
Northeast	—		30,634		94,249

Net cash provided by operating activities	$	133,595	$	61,771	$	126,906

Net cash provided by (used in) select investing activities:
Capital expenditures(1)	89,042		53,611		68,905
Investment in Double E equity method investee	3,816		3,880		3,500
Cash consideration paid for Moonrise Acquisition, net of cash acquired	(69,997)		—		—
Cash consideration paid for Tall Oak Acquisition, net of cash acquired	—		(154,154)		—
Proceeds from Utica Sale (excluding Ohio Gathering)	—		292,266		—
Proceeds from sale of Ohio Gathering	—		332,734		—
Proceeds from Mountaineer Transaction	—		69,304		—

Net cash provided by (used in) select financing activities:
Issuance of Additional 2029 Secured Notes	258,438		—		—
Borrowings on Amended and Restated ABL Facility	133,000		305,000		70,000
Debt repayments - ABL Facility	(325,000)		(313,000)		(87,000)
Debt repayments - Permian Transmission Term Loan	(12,324)		(15,524)		(10,507)
Distribution on Series A Preferred Shares	(13,393)		—		—
Distributions on Subsidiary Series A Preferred Shares	(6,513)		(6,513)		(6,512)
Issuance of 2029 Secured Notes	—		565,800		—
Debt repayments - Redemption of 2026 Unsecured Notes	—		(209,510)		—
Debt repayments - 2026 Secured Notes (Excess Cash Flow Offer)	—		(13,626)		—
Debt repayments - 2026 Secured Notes (2026 Secured Notes Asset Sale Offer)	—		(6,910)		—
Debt repayments - 2025 Senior Notes Redemption	—		(49,783)		—
Debt repayments - 2026 Secured Notes Redemption	—		(764,464)		—
Debt repayments - Repurchase of 2025 Senior Notes	—		—		(29,650)
Issuance of 2026 Unsecured Notes	—		—		29,480

________________________________

(1)See “Liquidity and Capital Resources” herein and Note 18 - Segment Information to the consolidated financial statements for additional information on capital expenditures.

Key Matters for the Year ended December 31, 2025. The following is a brief listing of significant developments and highlights for the fiscal year ended December 31, 2025, and up through the filing date of this Form 10-K. Additional information regarding these items may be found elsewhere in this Annual Report.

•Resumption of Series A Preferred Stock Dividend. On February 28, 2025, we announced that our Board of Directors approved the resumption of a quarterly cash dividend on our Series A Preferred Stock. During 2025, we paid $13.4 million of dividends on our Series A Preferred Stock and as of December 31, 2025, the Series A Preferred Stock had $46.6 million of cumulative unpaid dividends that must be repaid prior to the payment of a common stock dividend. In March 2026, the Company’s Board of Directors approved the payment of any and all accrued and unpaid dividends on the Company’s Series A Preferred Stock, including the $46.6 million of accrued and unpaid dividends outstanding as of December 31, 2025. The Company expects to pay the accrued and unpaid dividends on the Series A Preferred Stock upon satisfaction of certain notice requirements, which the Company expects to complete by March 31, 2026.

Trends and Outlook

Our business has been, and we expect our future business to continue to be, affected by the following key trends:

•Ongoing impact of political and economic conditions and events in foreign oil and natural gas producing countries on commodity prices, including the ongoing U.S. military operation in Iran, the current Russia-Ukraine conflict, international sanctions against Russia, the U.S. military operation in Venezuela, and other sustained military campaigns;

•Natural gas, NGL and crude oil supply and demand dynamics;

•Actions of OPEC and its allies, including the ability and willingness of the members of OPEC and other exporting nations to agree to and maintain oil price and production controls;

•Production from U.S. shale plays;

•Capital markets availability and cost of capital; and

•Inflation and shifts in operating costs.

Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Capital structure optimization and portfolio management. We intend to continue to improve our capital structure in the future by reducing our indebtedness with free cash flow, and when appropriate, we may pursue opportunistic transactions with the objective of increasing long-term shareholder value. This may include opportunistic acquisitions, divestitures, re-allocation of capital to new or existing areas, and development of joint ventures involving our existing midstream assets or new investment opportunities. We believe that our current cash balance, internally generated cash flow, our Amended and Restated ABL Facility, the New Permian Transmission Facility and access to debt or equity capital markets will be adequate to finance our strategic initiatives. To attain our overall corporate strategic objectives, we may conduct an asset divestiture, or divestitures, at a transaction valuation that is less than the net book value of the divested asset.

Ongoing impact of political and economic conditions and events in foreign oil and natural gas producing countries on commodity prices. Although we operate solely in the U.S., certain events and conditions in foreign oil and natural gas producing countries, such as the ongoing U.S. military operation in Iran, Russia’s invasion of Ukraine, and the recent change in Venezuela’s political leadership, could have potential effects on us, 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 to us.

Natural gas, NGL and crude oil supply and demand dynamics. Natural gas continues to be a critical component of energy supply and demand in the U.S. The average spot price of natural gas increased by approximately 61% from 2024 to 2025, primarily due to increasing demand. The average daily Henry Hub Natural Gas Spot Price was $3.52 per MMBtu during 2025, compared with $2.19 per MMBtu during 2024. As of January 31, 2026, Henry Hub 12-month strip pricing closed at $7.71 per MMBtu. During 2025, the number of active natural gas drilling rigs in the continental U.S. increased from 102 in December 2024 to 125 in December 2025, according to Baker Hughes. Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven primarily by global population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation and increase in U.S. LNG exports. Despite these decreases, over the next several years we expect natural gas prices will continue to support continued upstream industry activity by producers focused on natural gas production.

In addition, certain of our gathering systems are directly affected by crude oil supply and demand dynamics. Crude oil prices decreased in 2025, with the average daily Cushing, Oklahoma West Texas Intermediate crude oil spot price average of $76.63 per barrel during 2024 decreasing to an average of $65.39 per barrel during 2025, representing a 15% decrease. As of January 31, 2026, West Texas Intermediate 12-month strip pricing closed at $60.26 per barrel. During 2025, the number of active crude oil drilling rigs in the continental U.S. decreased from 483 in December 2024 to 412 in December 2025, according to Baker Hughes. Despite these decreases, over the next several years we expect that crude oil prices will support continued drilling activity and increasing production in the Williston Basin, Permian Basin, and given the current regulatory environment in Colorado, in rural parts of the DJ Basin where we operate.

Despite improving fundamentals that should support additional development activities, we note that over the last several years there has been an increasing societal opposition to the production of hydrocarbons generally, which may be reflected in legislation, executive orders or regulations that may significantly restrict the domestic production of fossil fuels, including natural gas.

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

Rate of growth in production from U.S. shale plays. Some of our producer customers have adjusted their drilling and completion activities and schedules to manage drilling and completion costs at levels that are achievable using internally generated cash flow from their underlying operations. Historically, as part of a strategy to accelerate production growth, these producers would raise external capital to fund drilling and completion costs in excess of the cash flows generated from their underlying assets. Producers are experiencing increasing pressure from their investors to focus on returning capital and maximizing free cash flow versus re-investing that cash flow into development. In general, we expect our producer customers to maintain moderate completion and production activities across many of our systems relative to our previous expectations as a result of the commodity price environment and a continuation of the general trend of producers constraining drilling and completion activity to levels that can be satisfied with internally generated cash flow.

Capital markets availability and cost of capital. Capital markets conditions, including but not limited to availability and higher borrowing costs, could affect our ability to access the debt and equity capital markets, to the extent necessary, to fund our future growth. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

The borrowings under our Amended and Restated ABL Facility, which have a variable interest rate, expose us to the risk of increasing interest rates.

Inflation and operating costs. The annual rate of inflation in the U.S. hit 6.5% in December 2022, one of the highest increases in more than three decades, as measured by the Consumer Price Index. While inflation has declined since the second half of 2022, declining to 2.7% in December 2025, further increases in inflation in 2026 could 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.

How We Evaluate Our Operations

We currently conduct and report our operations in the midstream energy industry through four reportable segments: Rockies, Permian, Piceance, and Mid-Con. Each of our reportable segments provides midstream services in a specific geographic area and our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations (see Note 18 - Segment Information to the consolidated financial statements). Our management uses a variety of financial and operational metrics to analyze our consolidated and segment performance and we view these metrics as important factors in evaluating our profitability. These metrics include (i) throughput volume, (ii) revenues, (iii) operation and maintenance expenses, (iv) capital expenditures and (v) Segment Adjusted EBITDA.

We review these metrics on a regular basis for consistency and trend analysis. There have been no changes in the composition or characteristics of these metrics during the year ended December 31, 2025.

During the year ended December 31, 2024, we divested of our Northeast operations, which consisted of midstream assets located in the Marcellus shale play and midstream assets located in the Utica shale play together with our equity method investment in Ohio Gathering that was focused on the Utica Shale.

Throughput Volume

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

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

•successful drilling activity within our AMIs;

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

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

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

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

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

Revenues

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

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

Operation and Maintenance Expenses

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

Our operation and maintenance expenses also include costs that are reimbursed by our customers, which are included in Other revenues.

Capital Expenditures

Our business is capital intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities.

We categorize our capital expenditures as either:

•maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or

•expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.

Segment Adjusted EBITDA

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

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

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

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

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

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

Summit Midstream Corporation Tax Structure. We operate the Company in an Up-C tax structure whereby the Company owns 65% of SMLP as of December 31, 2025 and certain Tailwater Capital, LLC entities (“Tailwater Capital”) own the remaining 35% of SMLP as a noncontrolling interest. If Tailwater Capital converted their 6.5 million SMLP partnership units and 6.5 million Class B shares on December 31, 2025 for the Company’s common stock, the following adjustments would occur to the Company’s balance sheet and common shares outstanding.


	December 31, 2025		Hypothetical Conversion		Post Conversion
Total Assets	$	2,387,609	$	—	$	2,387,609
Total Liabilities and Equity	$	2,387,609	$	—	$	2,387,609

Outstanding Share Summary	December 31, 2025		Hypothetical Conversion		Post Conversion
Common Stock	12,262,320		6,524,467		18,786,787
Class B Common Stock	6,524,467		(6,524,467)		—

Additional Information. For additional information, see the “Results of Operations” section herein and the notes to the consolidated financial statements contained in Item 8. Financial Statements and Supplementary Data.

Results of Operations

Consolidated Overview for the Years Ended December 31, 2025 and 2024

Below is a discussion of changes in our results of operations for 2025 compared to 2024. A discussion of changes in our results of operations for 2024 compared to 2023 has been omitted from this Form 10-K, but may be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Form 10-K for the year ended December 31, 2024 as filed with the SEC on March 11, 2025.

The following table presents certain consolidated data and volume throughput for the years ended December 31, 2025 and 2024.


	Year ended December 31,
	2025		2024		Percentage change
	(In thousands)
Revenues:
Gathering services and related fees	$	255,677	$	200,844	27%
Natural gas, NGLs and condensate sales	265,059		195,027		36%
Other revenues	41,355		33,748		23%
Total revenues	562,091		429,619		31%
Costs and expenses:
Cost of natural gas and NGLs	149,139		114,996		30%
Operation and maintenance	149,139		100,968		48%
General and administrative	61,018		55,562		10%
Depreciation and amortization	114,159		100,647		13%
Transaction costs	4,900		30,956		(84%)
Acquisition integration costs	8,143		165		*
Loss on asset sales, net	486		1		*
Long-lived asset impairment	2,725		68,260		*
Total costs and expenses	489,709		471,555		4%
Other income, net	783		4,188		(81%)
Gain (loss) on interest rate swaps	(1,037)		4,127		(125%)
Gain (loss) on sale of business	(582)		82,187		*
Gain on sale of equity method investment	—		126,261		*
Interest expense	(94,737)		(115,446)		(18%)
Loss on early extinguishment of debt	—		(50,075)		*
Income from equity method investees	20,784		24,197		(14%)
Income (loss) before income taxes	(2,407)		33,503		(107%)
Income tax benefit (expense)	501		(146,678)		*

Net loss	$	(1,906)	$	(113,175)	(98%)

Volume throughput (1):
Aggregate average daily throughput - natural gas (MMcf/d)	904		862		5%
Aggregate average daily throughput - liquids (Mbbl/d)	73		72		1%

_________________

*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, 2025 and 2024.”

Volumes – Gas. Natural gas throughput volumes increased 42 MMcf/d for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily reflecting:

•a volume throughput increase of 21 MMcf/d for the Rockies segment;

•a volume throughput increase of 256 MMcf/d for the Mid-Con segment; offset by

•a volume throughput decrease of 33 MMcf/d for the Piceance segment;

•a volume throughput decrease of 202 MMcf/d for the Northeast segment.

Volumes – Liquids. Crude oil and produced water volume throughput for the Rockies segment increased 1 Mbbl/d for the year ended December 31, 2025 compared to the year ended December 31, 2024.

For additional information on volumes, see the “Segment Overview for the Years Ended December 31, 2025 and 2024” section herein.

Revenues. Total revenues increased $132.5 million during the year ended December 31, 2025 compared to the year ended December 31, 2024 comprised of a $54.8 million increase in gathering services and related fees, a $70.0 million increase in natural gas, NGLs and condensate sales and a $7.6 million increase in Other revenues.

Gathering services and related fees. Gathering services and related fees increased $54.8 million compared to the year ended December 31, 2024, primarily reflecting:

•a $85.9 million increase in the Mid-Con segment; offset by

•a $18.9 million decrease in the Northeast segment;

•a $11.7 million decrease in the Piceance segment;

•a $0.5 million decrease in the Rockies segment.

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales revenue increased $70.0 million compared to the year ended December 31, 2024, primarily reflecting:

•a $53.9 million increase in the Rockies segment;

•a $16.8 million increase in the Mid-Con segment; offset by

•a $0.7 million decrease in the Piceance segment.

Costs and expenses. Total costs and expenses increased $18.2 million during the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily reflecting:

Cost of Natural Gas and NGLs. Costs of Natural Gas and NGL’s increased $34.1 million for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily as a result of the Tall Oak Acquisition and the Moonrise Acquisition.

Operation and Maintenance. Operation and maintenance expense increased $48.2 million for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily as a result of the Tall Oak Acquisition and the Moonrise Acquisition, partially offset by the disposition of our Mountaineer Midstream system.

General and administrative. General and administrative expense increased $5.5 million for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily due to increased employee salaries and benefit expense, as well as certain professional and other expenses associated with acquisition diligence costs.

Depreciation and amortization. Depreciation and amortization expense increased $13.5 million for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily due to the Moonrise Acquisition and the Tall Oak Acquisition.

Transaction costs. During the year ended December 31, 2025, transaction costs primarily relate to the Moonrise Acquisition and Tall Oak Acquisition. In 2024, transaction costs primarily relate to the Tall Oak Acquisition and the Utica Sale.

Acquisition integration costs. Acquisition and integration costs in 2025 primarily relate to fees paid to third-party service providers to integrate the Tall Oak Acquisition and the Moonrise Acquisition into the Company’s operational platform.

Long-lived asset impairments. In 2025, we recognized impairments of $2.7 million, primarily related to the abandonment of aged pipeline that was no longer economical under the terms of our commercial arrangements. In 2024, we recognized impairments of $68.3 million primarily in connection with the Mountaineer Transaction.

Gain on sale of business. In 2024, we recognized a gain on sale of business primarily in connection with the disposition of the Utica midstream business in March of 2024.

Gain on sale of equity method investment. In 2024, we recognized a gain on sale of equity method investment related to the disposition of our equity method investment, Ohio Gathering, in March of 2024.

Interest Expense. Interest expense decreased $20.7 million during the year ended December 31, 2025 compared to the year ended December 31, 2024 primarily due to $44.6 million of reduced interest expense as a result of the 2026 Secured Notes Tender Offer and the Asset Sale Offer that occurred in July 2024 and May 2024, respectively, and $12.0 million of reduced interest expense due to the full repayment and discharge of the 2026 Unsecured Notes in June 2024. The decrease was partially offset by $49.1 million of increased borrowing costs in connection with the issuance of the 2029 Secured Notes in July 2024 and January 2025. See Note 9 – Debt to the consolidated financial statements for additional details. Interest expense does not include the impact of gains or losses from our interest rate swaps entered into for the Permian Transmission Credit Facilities.

Loss on early extinguishment of debt. Loss on early extinguishment of debt in 2024 is primarily related to amortization of debt issuance costs in connection with extinguishments of our 2026 Unsecured Notes, 2026 Secured Notes and 2025 Senior Notes.

Income taxes. For the year ended December 31, 2025, the Company recorded an income tax benefit of $0.5 million. The income tax benefit includes the impact from the allocation of income from SMLP to SMC as a result of the Company’s Up-C tax structure.

Segment Overview for the Years Ended December 31, 2025 and 2024

Rockies.

Volume throughput for our Rockies reportable segment follows.


	Rockies
	Year ended December 31,
	2025	2024	Percentage Change
Aggregate average daily throughput - natural gas (MMcf/d)	149	128	16%
Aggregate average daily throughput - liquids (Mbbl/d)	73	72	1%

Natural gas. Natural gas volume throughput for the year ended December 31, 2025 increased 16% compared to the year ended December 31, 2024, primarily reflecting 99 new well connections that came online during 2025 and additional throughput associated with the Moonrise Acquisition, partially offset by natural production declines.

Liquids. Liquids volume throughput for the year ended December 31, 2025 increased 1% compared to the year ended December 31, 2024, primarily reflecting 11 new well connections that came online during 2025 and additional throughput associated with the Moonrise Acquisition, partially offset by natural production declines.

Financial data for our Rockies reportable segment follows.


	Rockies
	Year ended December 31,
	2025		2024		Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	62,760	$	63,219	(1%)
Natural gas, NGLs and condensate sales	244,478		190,535		28%
Other revenues	22,113		14,757		50%
Total revenues	329,351		268,511		23%
Costs and expenses:
Cost of natural gas and NGLs	148,456		113,714		31%
Operation and maintenance	62,279		49,849		25%
General and administrative	6,438		4,785		35%
Depreciation and amortization	41,586		36,319		15%
Integration costs	65		—		*
(Gain) loss on asset sales, net	(6)		30		(120%)
Long-lived asset impairment	2,725		344		692%
Total costs and expenses	261,543		205,041		28%
Add:
Depreciation and amortization	41,586		36,319
Integration costs	65		—
Adjustments related to capital reimbursement activity	(6,977)		(6,348)
(Gain) loss on asset sales, net	(6)		30
Long-lived asset impairment	2,725		344
Other	1,734		12
Segment Adjusted EBITDA	$	106,935	$	93,827	14%

_________________

* Not considered meaningful

Year ended December 31, 2025. Segment Adjusted EBITDA increased $13.1 million compared to the year ended December 31, 2024 primarily as a result of margin mix and the Moonrise Acquisition.

The Company is providing additional financial and operational details below for its liquids related activities within its Rockies segment (in thousands):


Rockies liquids	Year Ended December 31,
	2025		2024
Gathering services and related fees	$	46,304	$	47,626
MVC shortfall (payments) in gathering services and related fees	—		—
Gathering services and related fees included in costs of goods sold	475		621
Adjustments related to capital reimbursement activity	(494)		(374)

The Company is providing below additional financial and operational details for its natural gas and other related activities within its Rockies segment (in thousands):


Rockies natural gas and other	Year Ended December 31,
	2025		2024
Gathering services and related fees	$	16,456	$	15,593
MVC shortfall (payments) in gathering services and related fees	(554)		(1,556)
Gathering services and related fees included in costs of goods sold	57,574		50,007
Adjustments related to capital reimbursement activity	(6,483)		(5,974)

Permian.

Volume throughput for our Permian reportable segment follows.


	Permian
	Year ended December 31,
	2025	2024	Percentage Change
Average daily throughput (MMcf/d) (Double E)	730	573	27%

Volume throughput for Double E increased 27% compared to the year ended December 31, 2024, as a result of increased throughput volumes from its customers.

The following table presents the MVC quantities that Double E’s shippers have contracted for under firm transportation service agreements and related negotiated rate agreements, excluding three new precedent agreements totaling 100 MMcf/d, 210 MMcf/d and 230 MMcf/d of firm capacity. The 100 MMcf/d agreement has a 10-year term and is expected to be placed into service in the fourth quarter of 2026. The 210 MMcf/d agreement has an 11-year term and will be implemented in two tranches: 70 MMcf/d is expected to be placed into service in the fourth quarter of 2026, with the remaining 140 MMcf/d anticipated to be placed into service in the third quarter of 2028. The 230 MMcf/d agreement has over an 11-year term and will be implemented in three tranches: 100 MMcf/d is expected to be placed into service in the fourth quarter of 2027, 80 MMcf/d in the fourth quarter of 2028, and an additional 50 MMcfd in the second quarter of 2029.


Weighted average MVC quantities for the year ended December 31,			(MMBtu/day)



2026			1,115,000
2027			1,115,000
2028			1,115,000
2029			1,115,000
2030			1,115,000
2031			1,009,521
2032			240,000
2033			240,000
2034			105,753
2035			9,863

Financial data for our Permian reportable segment follows.


	Permian
	Year ended December 31,
	2025		2024		Percentage Change
	(Dollars in thousands)
Revenues:
Other revenues	$	3,641	$	3,641	—%
Total revenues	3,641		3,641		—%
Costs and expenses:
General and administrative	197		169		17%
Transaction costs	27		—		*
Total costs and expenses	224		169		33%
Add:
Transaction costs	27		—
Proportional Adjusted EBITDA for Double E	30,536		27,755
Segment Adjusted EBITDA	$	33,980	$	31,227	9%

_________________

* Not considered meaningful

Year ended December 31, 2025. Segment Adjusted EBITDA increased $2.8 million compared to the year ended December 31, 2024 primarily as a result of an increase in Proportional Adjusted EBITDA from our equity method investment in Double E due to increased volumes described above.

Mid-Con.

Volume throughput for our Mid-Con reportable segment follows.


	Mid-Con
	Year ended December 31,
	2025	2024	Percentage Change
Average daily throughput (MMcf/d)	497	241	106%

Volume throughput increased 106% for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily as a result of the Tall Oak Acquisition, 38 wells that came online during 2025, and the resumption of previous production curtailments associated with reductions in commodity pricing, partially offset by natural production declines.

Financial data for our Mid-Con reportable segment follows.


	Mid-Con
	Year ended December 31,
	2025		2024		Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	131,538	$	45,659	188%
Natural gas, NGLs and condensate sales	18,554		1,717		981%
Other revenues (1)	9,140		9,515		(4%)
Total revenues	159,232		56,891		180%
Costs and expenses:
Cost of natural gas and NGLs	9		129		*
Operation and maintenance	63,676		24,366		161%
General and administrative	2,316		1,349		72%
Depreciation and amortization	33,389		16,767		99%
Transaction costs	16		—		*
Integration costs	2,665		39		*
Gain on asset sales, net	(195)		—		*

Total costs and expenses	101,876		42,650		139%
Add:
Depreciation and amortization (1)	34,327		17,705
Transaction costs	16		—
Integration costs	2,665		39
Adjustments related to capital reimbursement activity	(1,847)		(1,340)
Gain on asset sales, net	(195)		—

Other	55		—
Segment Adjusted EBITDA	$	92,377	$	30,645	201%

_________________

*Not considered meaningful

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

Year ended December 31, 2025. Segment Adjusted EBITDA increased $61.7 million compared to the year ended December 31, 2024 primarily as a result of the Tall Oak Acquisition and increased volume throughput discussed above.

Piceance.

Volume throughput for our Piceance reportable segment follows.


	Piceance
	Year ended December 31,
	2025	2024	Percentage Change
Aggregate average daily throughput (MMcf/d)	258	291	(11%)

Volume throughput for the year ended December 31, 2025 decreased 11% compared to the year ended December 31, 2024, primarily as a result of natural production declines.

Financial data for our Piceance reportable segment follows.


	Piceance
	Year ended December 31,
	2025		2024		Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	61,379	$	73,115	(16%)
Natural gas, NGLs and condensate sales	2,027		2,775		(27%)
Other revenues	6,461		5,109		26%
Total revenues	69,867		80,999		(14%)
Costs and expenses:
Cost of natural gas and NGLs	674		1,138		(41%)
Operation and maintenance	23,160		23,964		(3%)
General and administrative	1,287		1,298		(1%)
Depreciation and amortization	37,569		42,012		(11%)
(Gain) loss on asset sales, net	687		(8)		(8688%)

Total costs and expenses	63,377		68,404		(7%)
Add:
Depreciation and amortization	37,569		42,012

Adjustments related to capital reimbursement activity	(199)		(2,201)
(Gain) loss on asset sales, net	687		(8)

Other	227		306
Segment Adjusted EBITDA	$	44,774	$	52,704	(15%)

_________________

* Not considered meaningful

Year ended December 31, 2025. Segment Adjusted EBITDA decreased $7.9 million compared to the year ended December 31, 2024, primarily as a result of lower volume throughput discussed above as well as contractual step-downs.

Northeast.

Volume throughput for the Northeast reportable segment follows.


	Northeast
	Year ended December 31,
	2025	2024	Percentage Change
Average daily throughput (MMcf/d)	—	202	(100)%
Average daily throughput (MMcf/d) (Ohio Gathering)	—	212	(100)%

On March 22, 2024, we completed the disposition of Summit Utica, the owner of our previously owned equity method investment, Ohio Gathering, and on May 1, 2024, we completed the disposition of our Mountaineer Midstream system.

Financial data for our Northeast reportable segment follows.


	Northeast
	Year ended December 31,
	2025		2024		Percentage Change
Revenues:	(Dollars in thousands)

Gathering services and related fees	$	—	$	18,851	(100)%

Total revenues	—		18,851		(100)%
Costs and expenses:
Operation and maintenance	—		2,259		(100%)
General and administrative	—		220		(100)%
Depreciation and amortization	—		4,248		(100)%
Gain on asset sales, net	—		(21)		(100)%
Long-lived asset impairment	—		67,916		N/A
Total costs and expenses	—		74,622		(100%)
Add:
Depreciation and amortization	—		4,248
Adjustments related to capital reimbursement activity	—		(20)
Gain on asset sales, net	—		(21)
Long-lived asset impairment	—		67,916
Proportional Adjusted EBITDA for Ohio Gathering (1)	—		14,282
Other	—		—
Segment Adjusted EBITDA	$	—	$	30,634	(100%)

_________________

*Not considered meaningful

(1) SMLP recorded its financial results of its investment in Ohio Gathering on a one-month lag based on financial information available to us during the reporting period. With the divestiture of Ohio Gathering in March 2024, Proportional Adjusted EBITDA includes financial results from December 1, 2023 through March 22, 2024 ($2.5 million for March 1, 2024 - March 22, 2024).

Year ended December 31, 2025. Segment Adjusted EBITDA decreased $30.6 million compared to the year ended December 31, 2024, as the result of the sale of our Mountaineer Midstream system and the disposition of Summit Utica, the owner of our previously owned equity method investment, Ohio Gathering.

Corporate and Other Overview for the Years Ended December 31, 2025 and 2024

Corporate and Other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, transaction costs, acquisition integration costs, interest expense, and losses on early extinguishment of debt. Corporate and Other includes intercompany eliminations.


	Corporate and Other
	Year ended December 31,
	2025	2024	Percentage Change
	(Dollars in thousands)
Costs and expenses:
General and administrative	50,780	47,741	6%
Transaction costs	4,857	30,956	(84%)
Acquisition integration costs	5,413	126	*
Interest expense	94,737	115,446	(18%)

_________________

* Not considered meaningful

General and administrative. For the year ended December 31, 2025, general and administrative expense attributable to Corporate and Other increased by $3.0 million compared to the year ended December 31, 2024, primarily due to increased employee salaries and benefit expense, as well as certain professional and other expenses associated with the evaluation of acquisitions. For the year ended December 31, 2025, general and administrative costs include $7.8 million of noncash stock-based compensation and $1.7 million of severance expense. For the year ended December 31, 2024, general and administrative expenses include $8.6 million of noncash stock-based compensation and $0.1 million of severance expense.

Transaction costs. During the year ended December 31, 2025, transaction costs primarily relate to the Moonrise Acquisition and the Tall Oak Acquisition. In 2024, transaction costs primarily relate to the Tall Oak Acquisition and Utica Sale.

See Note 9 – Debt to the consolidated financial statements for additional details. Interest expense does not include the impact of gains or losses from our interest rate swaps entered into for the Permian Transmission Credit Facilities.

Liquidity and Capital Resources

We rely primarily on internally generated cash flows as well as our current cash balance and external financing sources, including commercial bank borrowings, the issuance of debt, equity, and preferred equity securities, and proceeds from potential asset divestitures, to fund our capital expenditures. We believe that our Amended and Restated ABL Facility and Permian Transmission Credit Facility, together with internally generated cash flows, current cash balance and access to debt or equity capital markets, will be adequate to finance our operations for the next twelve months, and based on current expectations, the long-term, without adversely impacting our liquidity.

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2025, our material off-balance sheet arrangements and transactions include (i) letters of credit outstanding against our Amended and Restated ABL Facility aggregating to $0.8 million and (ii) letters of credit outstanding against our Permian Transmission Credit Facilities aggregating to $13.0 million. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources.

We are in compliance with all covenants contained in the indenture governing the 2029 Secured Notes, the Amended and Restated ABL Facility and the New Permian Transmission Facility. The Amended and Restated ABL Facility requires that Summit Holdings not permit (i) the First Lien Net Leverage Ratio (as defined in the Amended and Restated ABL Agreement) as of the last day of any fiscal quarter to be greater than 2.50:1.00, or (ii) the Interest Coverage Ratio (as defined in the Amended and Restated ABL Agreement) as of the last day of any fiscal quarter to be less than 2.00:1.00. As of December 31, 2025, the First Lien Net Leverage Ratio was 0.48:1.00 and the Interest Coverage Ratio was 2.70:1.00. Beginning on June 30, 2026, the New Permian Transmission Facility will require Summit Permian Transmission to meet certain minimum debt service coverage ratios and, beginning on March 31, 2027, certain maximum total debt to EBITDA ratios.

Amended and Restated ABL Facility. Concurrently with the issuance of the 2029 Secured Notes, on July 26, 2024, Summit Holdings, as borrower, amended and restated its existing first-lien, senior secured credit agreement, with SMLP, consisting of a $500.0 million asset-based revolving credit facility. As of December 31, 2025, the Amended and Restated ABL Facility will mature on the earliest of (a) July 26, 2029, (b) July 31, 2029 if either (i) the outstanding amount of the 2029 Secured Notes (or any refinancing debt permitted under the Amended and Restated ABL Facility in respect thereof that has a final maturity date, scheduled amortization or any other scheduled repayment, mandatory prepayment, mandatory redemption or sinking fund obligation prior to the date that is 91 days after the Amended and Restated ABL Termination Date (provided, that the terms of such permitted refinancing debt may (x) require the payment of interest from time to time and (y) include customary mandatory redemptions, prepayments or offers to purchase with proceeds of asset sales or upon the occurrence of a change of control)) on such date equals or exceeds $50.0 million or (ii) the outstanding amount of such debt described in clause (i) above on such date is less than $50.0 million and Liquidity (as defined in the Amended and Restated ABL Agreement) at any time on or after such date is less than the sum of (A) such outstanding amount and (B) the greater of (x) 10% of the aggregate Commitments (as defined in the Amended and Restated ABL Agreement) then in effect and (y) $50.0 million (and, for the avoidance of doubt, once the Amended and Restated ABL Termination Date occurs it may not be unwound as a result of Liquidity (as defined in the Amended and Restated ABL Agreement) increasing on a subsequent date), or (c) any date on which the aggregate Commitments terminate thereunder. As of December 31, 2025, there was $113.0 million outstanding under the Amended and Restated ABL Facility and the available borrowing capacity totaled $385.7 million after giving effect to certain adjustments that are primarily related to the issuance of $0.8 million of outstanding but undrawn irrevocable standby letters of credit.

New Permian Transmission Facility. On March 16, 2026, Summit Permian Transmission completed a $440.0 million refinancing of the Permian Transmission Credit Facilities in the form of a new term loan facility (the “New Permian Transmission Facility”) bearing interest at SOFR plus 4.00% per annum and with a maturity in March 2031. The New Permian Transmission Facility consists of $340.0 million in initial term loan commitments, $50.0 million in delayed draw commitments (with a commitment fee of 1.00% per annum) and a $50.0 million uncommitted incremental facility. The use of proceeds of the New Permian Transmission Facility includes, among other things, repayment in full of the Permian Transmission Credit Facilities and redemption in full of the Subsidiary Series A Preferred Units. In connection with the New Permian Transmission Facility, Summit Permian Transmission entered into a $7.0 million letter of credit arrangement.

2029 Secured Notes. On July 26, 2024, Summit Holdings issued $575.0 million aggregate principal amount of 8.625% Senior Secured Second Lien Notes due 2029. The 2029 Secured Notes are guaranteed on a senior second-priority basis by Summit Midstream Corporation and certain of Summit Midstream Corporation’s existing and future subsidiaries and are secured on a second-priority basis by substantially the same collateral that is pledged for the benefit of the lenders under the Amended and Restated ABL Facility. On January 10, 2025, we issued an additional $250.0 million of the 2029 Secured Notes. The 2029 Secured Notes mature on October 31, 2029 and have interest payable semi-annually in arrears on each February 15 and August 15. As of December 31, 2025, the outstanding balance of the 2029 Secured Notes was $825.0 million.

Other. We may in the future use a combination of cash, secured or unsecured borrowings and issuances of our common stock or other securities and the proceeds from asset sales to retire or refinance our outstanding debt or Series A Preferred Stock through privately negotiated transactions, open market repurchases, redemptions, exchange offers, tender offers or otherwise, but we are under no obligation to do so.

Cash Flows


	Year ended December 31,
	2025		2024
	(In thousands)
Net cash provided by operating activities	$	133,595	$	61,771
Net cash provided by (used in) investing activities	(163,150)		487,059
Net cash provided by (used in) financing activities	24,035		(540,276)
Net change in cash, cash equivalents, and restricted cash	$	(5,520)	$	8,554

The components of the net change in cash, cash equivalents and restricted cash were as follows:

Operating activities. Details of operating cash flows follow.

Operating activity cash flows during the year ended December 31, 2025 primarily reflected:

•a net loss of $1.9 million plus adjustments of $148.3 million for non-cash items; and

•a $12.8 million outflow due to changes in working capital accounts.

Operating activity cash flows during the year ended December 31, 2024 primarily reflected:

•a net loss of $113.2 million plus adjustments of $192.9 million for non-cash items; and

•a $18.0 million outflow due to changes in working capital accounts.

Investing activities. Details of investing cash flows follow.

Investing activity cash flows during the year ended December 31, 2025 primarily reflected:

•$89.0 million of cash outflows for capital expenditures; and

• $70.0 million of cash outflows from the Moonrise Acquisition.

Investing activity cash flows during the year ended December 31, 2024 primarily reflected:

•$332.7 million of cash inflows from the proceeds of the sale Ohio Gathering;

•$292.3 million of cash inflows from the proceeds of the Utica Sale (excluding Ohio Gathering);

•$69.3 million of cash inflows from the proceeds of the Mountaineer Transaction;

•$4.4 million of cash inflows from the sale of compressor equipment; partially offset by

•$154.2 million of cash outflows from the Tall Oak Acquisition; and

•$53.6 million of cash outflows for capital expenditures.

Financing activities. Details of financing cash flows follow.

Financing activity cash flows during the year ended December 31, 2025 primarily reflected:

•$325.0 million of cash outflows for repayments on the Amended and Restated ABL Facility;

•$12.3 million of cash outflows for repayments on the Permian Transmission Term Loan;

•$13.4 million of cash outflows for Distributions to Series A Preferred Shareholders;

•$6.5 million of cash outflows for Distributions to Subsidiary Series A Preferred Unitholders; offset by

•$258.4 million of cash inflows from the issuance of the Additional 2029 Secured Notes; and

•$133.0 million of cash inflows from borrowings on the Amended and Restated ABL Facility.

Financing activity cash flows during the year ended December 31, 2024 primarily reflected:

•$764.5 million of cash outflows for the 2026 Secured Notes Tender Offer and redemption of 2026 Secured Notes;

•$313.0 million of cash outflows for repayments on the Amended and Restated ABL Facility;

•$209.5 million of cash outflows from the redemption of 2026 Unsecured Notes;

•$49.8 million of cash outflows from the redemption of 2025 Senior Notes;

•$23.8 million of cash outflows for debt extinguishment costs;

•$15.5 million of cash outflows for repayments on the Permian Transmission Term Loan;

•$13.6 million of cash outflows for the Excess Cash Flow Offer;

•$6.9 million of cash outflows for the 2026 Secured Notes Asset Sale Offer; offset by

•$565.8 million of cash inflows from the issuance of the 2029 Secured Notes; and

•$305.0 million of cash inflows from borrowings on the Amended and Restated ABL Facility.

Contractual Obligations Update

The Company’s cash flows generated from operations are the primary source for funding various contractual obligations. The table below summarizes the Company’s major commitments as of December 31, 2025 through 2030 (in thousands):


	Total		2026		2027		2028		2029		2030
Amended and Restated ABL Facility, due July 2029 (1)	139,588		$	7,420	$	7,420	$	7,420	$	117,328	$	—
2029 Secured Notes, due October 2029	1,100,730		71,156		71,156		71,156		887,262		—
Permian Transmission Term Loan, due January 2028 (2)	129,297		28,145		23,569		77,583		—		—
Global Settlement for 2015 Blacktail Release (3)	8,333		8,333		—		—		—		—
Tall Oak earn-out	22,000		22,000		—		—		—		—
Lease obligations	7,753		3,398		2,854		816		477		208
Total (4)	$	1,407,701	$	140,452	$	104,999	$	156,975	$	1,005,067	$	208

(1)Amounts include an estimate for interest cost based on either the stated interest rate for fixed rate indebtedness or the interest rate in effect as of December 31, 2025 for variable rate indebtedness.

(2)Amounts include mandatory principal repayments of $21.3 million in 2026, which includes a $4.3 million principal payment that was made in January 2026 and $17.8 million in 2027. These amounts do not reflect the impact of the Summit Permian Transmission and Permian Holdco Refinancing (due March 2031). See Note 19 - Subsequent Events for additional information.

(3)Global Settlement amounts in the table exclude interest owed on the unpaid portion. See Note 10 - Commitments and Contingencies to the consolidated financial statements for additional details.

Capital Requirements

In connection with the consummation of the Corporate Reorganization, the Partnership Agreement was amended to, among other things, reflect that all of the issued and outstanding limited partnership interests of the Partnership are held by Summit Midstream Corporation. For information on the Corporate Reorganization, see Note 1 - Organization, Corporate Reorganization, Business Operations and Presentation and Consolidation.

For the year ended December 31, 2025, cash paid for capital expenditures totaled $89.0 million which included $17.3 million of maintenance capital expenditures. For the year ended December 31, 2025, we contributed $3.8 million to Double E.

We rely primarily on internally generated cash flows, our cash balance as well as external financing sources, including commercial bank borrowings and the issuance of debt, equity, and preferred equity securities, and proceeds from potential asset divestitures to fund our capital expenditures. We believe that our internally generated cash flows, current cash balance, our Amended and Restated ABL Facility and the Permian Transmission Credit Facilities, and access to debt or equity capital markets, will be adequate to finance our operations for the next twelve months without adversely impacting our liquidity.

We estimate that our 2026 capital program will range from $85.0 million to $105.0 million, including between $15.0 million and $20.0 million of maintenance capital expenditures. We estimate that we will make an additional investment in our Double E equity method investee of approximately $35.0 million.

There are a number of risks and uncertainties that could cause our current expectations to change, including, but not limited to, (i) the ability to reach agreements with third parties; (ii) prevailing conditions and outlook in the natural gas, crude oil and NGL industries and markets and (iii) our ability to obtain financing from commercial banks, the capital markets, or other financing sources.

Credit and Counterparty Concentration Risks

We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits, and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.

Certain of our customers may be temporarily unable to meet their current obligations. While this may cause disruption to cash flows, we believe that we are properly positioned to deal with the potential disruption because the vast majority of our gathering assets are strategically positioned at the beginning of the midstream value chain. The majority of our infrastructure is connected directly to our customers’ wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customers’ commodities flow and, in many cases, the only way for our customers to get their production to market.

We have exposure due to nonperformance under our MVC contracts whereby a potential customer may not have the wherewithal to make its MVC shortfall payments when they become due. We typically receive payment for all prior-year MVC shortfall billings in the quarter immediately following billing. Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period.

Critical Accounting Estimates

The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the U.S. The preparation of these financial statements requires management to make estimates and judgments that affect the amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis, based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following describes significant judgments and estimates used in the preparation of our consolidated financial statements.

Long-Lived Assets. Our long-lived assets consist of property, plant and equipment, and intangible assets that have been obtained by multiple business combinations and property, plant and equipment that has been constructed in recent years. The initial recording of a majority of these long-lived assets was at fair value, which is estimated by management primarily utilizing market-related information, asset specific information and other projections on the performance of the assets acquired (including an analysis of discounted cash flows which can involve assumptions on weighted average cost of capital and projected cash flows of the assets acquired). Management reviews this information to determine its reasonableness in comparison to the assumptions utilized in determining the purchase price of the assets in addition to other market-based information that was received through the purchase process and other sources. These projections also include projections on potential and contractual obligations assumed in these acquisitions. Due to the imprecise nature of the projections and assumptions utilized in determining fair value, actual results can and often do, differ from our estimates.

As of December 31, 2025, we had net property, plant and equipment with a carrying value of approximately $1.8 billion and net intangible assets with a carrying value of approximately $153.6 million. When evidence exists that we will not be able to recover a long-lived asset’s carrying value through future cash flows, we write down the carrying value of the asset to its estimated fair value. We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. With respect to property, plant and equipment, and our amortizing intangible assets, the carrying value of a long-lived asset is not recoverable if the carrying value exceeds the sum of the undiscounted cash flows expected to result from the asset’s use and eventual disposal. In this situation, we would recognize an impairment loss equal to the amount by which the carrying value exceeds the asset’s fair value. We determine fair value using a combination of approaches, including a market-based approach and an income-based approach in which we discount the asset’s expected future cash flows to reflect the risk associated with achieving the underlying cash flows. Any impairment determinations involve significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these estimates are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.

We evaluate our equity method investments for impairment when we believe the current fair value may be less than the carrying amount and record an impairment if we believe the decline in value is other than temporary.

Business Combinations. In accordance with accounting guidance for business combinations, we allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We use all available information to estimate fair values. We typically engage outside appraisal firms to assist in the fair value determination of identifiable intangible assets such as trade names and any other significant assets or liabilities. We adjust the preliminary purchase price allocation, as necessary, up to one year after the acquisition closing date as we obtain more information regarding asset valuations and liabilities assumed.

Our purchase price allocation methodology contains uncertainties because it requires management to make assumptions and to apply judgment to estimate the fair value of acquired assets and liabilities. Management estimates the fair value of assets and liabilities based upon quoted market prices, the carrying value of the acquired assets and widely accepted valuation techniques,

including discounted cash flows, and market multiple analysis. Unanticipated events or circumstances may occur which could affect the accuracy of our fair value estimates, including assumptions regarding industry economic factors and business strategies. If actual results are materially different than the assumptions we used to determine fair value of the assets and liabilities acquired through a business combination, it is possible that adjustments to the carrying values of such assets and liabilities will have an impact on our net earnings.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Interest Rate Risk

Our current interest rate risk exposure is largely related to our indebtedness. As of December 31, 2025, we had $825.0 million principal amount of fixed-rate debt, $113.0 million outstanding under our variable rate Amended and Restated ABL Facility and $117.0 million outstanding under our variable rate Permian Transmission Term Loan. As of December 31, 2025, we had $101.5 million of interest rate exposure hedged to offset the impact of changes in interest rates on our Permian Transmission Term Loan. While existing fixed-rate debt mitigates the downside impact of fluctuations in interest rates, future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher overall interest costs. In addition, the borrowings under our Amended and Restated ABL Facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. For the year ended December 31, 2025, a hypothetical 1% increase (decrease) in interest rates on our variable rate debt would have increased (decreased) our interest expense by approximately $2.6 million assuming no changes in amounts drawn or other variables under our Amended and Restated ABL Facility or Permian Transmission Term Loan.

Commodity Price Risk

We generate a majority of our revenues pursuant to primarily long-term and fee-based gathering agreements, many of which include MVCs and AMIs. Currently, our direct commodity price exposure relates to (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds and other processing arrangements with certain of our customers in the Rockies, Piceance and Mid-Con segments, (ii) the sale of natural gas we retain from certain Mid-Con segment customers and (iii) the sale of condensate we retain from certain gathering services in the Piceance segment. Our gathering agreements with certain Mid-Con customers permit us to retain a certain quantity of natural gas that we sell to offset the power costs we incur to operate our electric-drive compression assets. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices on the Henry Hub Index. We sell retainage natural gas at prices that are based on the Atmos Zone 3 Index. By basing the power prices on a system and basin-relevant market, we are able to closely associate the relationship between the compression electricity expense and natural gas retainage sales. We do not enter into risk management contracts for speculative purposes.

Item 8. Financial Statements and Supplementary Data.


Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)			87
Consolidated Balance Sheets			89
Consolidated Statements of Operations			90
Consolidated Statements of Equity			91
Consolidated Statements of Cash Flows			92
Notes to Consolidated Financial Statements			93

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders and the Board of Directors of Summit Midstream Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Summit Midstream Corporation and subsidiaries (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of operations, equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 16, 2026, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Acquisition and Divestitures – Purchase Price Accounting — Refer to Note 3 to the financial statements

Critical Audit Matter Description

As described in Note 3 to the consolidated financial statements, on March 10, 2025, the Company completed the acquisition of Moonrise Midstream LLC, (“Moonrise”) for $70 million in cash and 462,265 shares of Common Stock of the Company. Accordingly, the purchase price was allocated to the assets acquired and liabilities assumed based on their preliminary estimated fair values on the date of acquisition. The valuation of assets acquired are based on preliminary appraisals, available market data, and cost and income approaches. These methods are considered Level 3 fair value estimates and include significant assumptions of future gathering and processing volumes, commodity prices, and operating and capital cost estimates, discounted using a weighted average cost of capital.

We identified the valuation of property, plant and equipment related to the Moonrise acquisition as a critical audit matter because of the significant estimates and assumptions made by management. This required a high degree of auditor judgment and an increased extent of effort, including the involvement of our fair value specialists, when performing audit procedures to evaluate the reasonableness of management's selection of a weighted average cost of capital, and the preliminary fair value of the acquired property, plant and equipment assets.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management's selection of a weighted average cost of capital, and the fair value of acquired property, plant and equipment included the following, among others:

•We tested the effectiveness of controls over the purchase price allocation, including management's controls over the assumptions used in the valuation of property, plant and equipment.

•With the assistance of our fair value specialists, we evaluated the reasonableness of the fair value of acquired property, plant and equipment by:

▪Evaluating the appropriateness of the valuation methodology.

▪Testing the cost to acquire or construct comparable assets and the remaining useful lives used for the cost approach for property, plant and equipment, including comparing such estimates to independent market information to determine reasonableness.

▪Testing the methodology used for the valuation of rights-of-way.

▪Developing a range of independent estimates of the weighted average cost of capital and comparing to the weighted average cost of capital utilized by management.

▪Evaluated management's use of experts related to the valuation of certain acquired assets including qualifications and methodology.

Property, Plant and Equipment, Net - Determination of Impairment Indicators– Refer to Notes 2 and 5 to the financial statements

Critical Audit Matter Description

As described in Notes 2 and 5 to the Company's consolidated financial statements, the Company recorded approximately $1.84 billion of property, plant and equipment, net as of December 31, 2025. The Company tests assets for impairment when events or circumstances indicate the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If the Company concludes that an asset’s carrying value will not be recovered through future cash flows, the Company recognizes an impairment loss on the long-lived asset equal to the amount by which the carrying value exceeds its fair value.

We have identified the determination of impairment indicators for long-lived assets as a critical audit matter due to the significant judgments management makes when determining whether events or changes in circumstances have occurred indicating that the carrying amounts of long-lived assets may not be recoverable. Auditing management’s judgements involved especially challenging auditor judgment due to the nature and extent of audit effort required to address these matters, including the degree of auditor judgment and the extent of specialized knowledge needed.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the identification of impairment indicators for long-lived assets included the following, among others:

•We tested the effectiveness of internal controls over financial reporting related to management’s identification of possible impairment indicators for long-lived assets that may indicate the carrying amount of long-lived assets may not be recoverable.

•We evaluated management’s analysis of impairment indicators by:

▪Assessing whether long-lived assets having indicators of impairment were appropriately identified.

▪Considering industry reports and the impact of macroeconomic factors, such as adverse changes in the regulatory environment, legislation or other factors that may represent impairment indicators not previously contemplated in management's analysis.

▪Evaluating management’s judgments around historical trends, macroeconomic and industry conditions, and whether projections are consistent with the Company’s operating strategy.

▪Inquiry of management over whether long-lived assets may be sold or otherwise disposed of significantly before the end of the assets' previously estimated useful life.

▪Inspecting minutes of the board of directors and committees of executive management to understand if there were factors that would represent potential impairment indicators for long-lived assets.

/s/ Deloitte & Touche LLP

Houston, Texas

March 16, 2026

We have served as the Company’s auditor since 2009.

SUMMIT MIDSTREAM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31, 2025		December 31, 2024
	(In thousands, except share and unit amounts)
ASSETS
Cash and cash equivalents	$	9,274	$	22,822
Restricted cash	10,405		2,377
Accounts receivable	69,752		77,058
Other current assets	7,490		16,014
Total current assets	96,921		118,271
Property, plant and equipment, net	1,844,146		1,785,029
Intangible assets, net	153,564		154,279
Investment in equity method investees	265,583		269,561
Other noncurrent assets	27,395		32,344
TOTAL ASSETS	$	2,387,609	$	2,359,484

LIABILITIES AND EQUITY
Trade accounts payable	$	31,652	$	25,162
Accrued expenses	24,270		38,176
Deferred revenue	10,122		9,595
Ad valorem taxes payable	10,190		9,544
Accrued compensation and employee benefits	12,063		11,222
Accrued interest	30,045		21,711
Accrued environmental remediation	1,710		1,430
Accrued settlement payable	8,333		6,667
Current portion of long-term debt	21,223		16,580
Other current liabilities	27,185		34,714
Total current liabilities	176,793		174,801
Deferred tax liabilities, net	73,635		63,326
Long-term debt, net	1,024,347		976,995
Noncurrent deferred revenue	18,398		25,373
Noncurrent accrued environmental remediation	52		768
Other noncurrent liabilities	6,532		20,150
Total liabilities	1,299,757		1,261,413
Commitments and contingencies (Note 10)

Mezzanine Equity
Subsidiary Series A Preferred Units (93,039 issued and outstanding as of December 31, 2025 and December 31, 2024)	141,296		132,946

Equity
Series A Preferred Stock (65,508 shares authorized, issued and outstanding as of December 31, 2025 and December 31, 2024)	110,468		110,230
Common Stock, $0.01 par value (42,000,000 authorized as of December 31, 2025 and December 31, 2024; 12,262,320 and 10,659,220 issued and outstanding as of December 31, 2025 and December 31, 2024, respectively)	122		106
Class B Common Stock, $0.01 par value (7,471,008 shares authorized as of December 31, 2025 and December 31, 2024; 6,524,467 and 7,471,008 issued and outstanding as of December 31, 2025 and December 31, 2024, respectively)	65		75
Additional paid-in capital	638,427		540,714
Accumulated deficit	(202,902)		(183,333)
Total Company stockholders’ equity	546,180		467,792
Noncontrolling interest	400,376		497,333
Total equity	946,556		965,125
TOTAL LIABILITIES AND EQUITY	$	2,387,609	$	2,359,484

The accompanying notes are an integral part of these consolidated financial statements.

SUMMIT MIDSTREAM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year ended December 31,
	2025		2024		2023
	(In thousands, except per-share amount)
Revenues:
Gathering services and related fees	$	255,677	$	200,844	$	248,223
Natural gas, NGLs and condensate sales	265,059		195,027		179,254
Other revenues	41,355		33,748		31,426
Total revenues	562,091		429,619		458,903
Costs and expenses:
Cost of natural gas and NGLs	149,139		114,996		112,462
Operation and maintenance	149,139		100,968		100,741
General and administrative	61,018		55,562		42,135
Depreciation and amortization	114,159		100,647		122,764
Transaction costs	4,900		30,956		1,251
Acquisition integration costs	8,143		165		2,654
(Gain) loss on asset sales, net	486		1		(260)
Long-lived asset impairment	2,725		68,260		540
Total costs and expenses	489,709		471,555		382,287
Other income, net	783		4,188		865
Gain (loss) on interest rate swaps	(1,037)		4,127		1,830
Gain (loss) on sale of business	(582)		82,187		(47)
Gain on sale of equity method investment	—		126,261		—
Interest expense	(94,737)		(115,446)		(140,784)
Loss on early extinguishment of debt	—		(50,075)		(10,934)
Income from equity method investees	20,784		24,197		33,829
Income (loss) before income taxes	(2,407)		33,503		(38,625)
Income tax benefit (expense)	501		(146,678)		(322)

Net loss	$	(1,906)	$	(113,175)	$	(38,947)
Less: Net income attributable to Subsidiary Series A Preferred Units	(14,863)		(14,806)		(12,581)
Less: Net income attributable to Series A Preferred Stock	(13,631)		(13,337)		(11,566)
Add: Net loss attributable to noncontrolling interest	10,831		5,822		—
Net loss attributable to Summit Midstream Corporation	$	(19,569)	$	(135,496)	$	(63,094)



Net loss per share:
Common stock – basic	$	(1.61)	$	(12.78)	$	(6.11)
Common stock – diluted	$	(1.61)	$	(12.78)	$	(6.11)

Weighted-average number of shares outstanding:
Common stock – basic	12,133		10,600		10,334
Common stock – diluted	12,133		10,600		10,334

The accompanying notes are an integral part of these consolidated financial statements.

SUMMIT MIDSTREAM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS EQUITY


	Partners’ Capital (Before Corporate Reorganization)				Equity (After Corporate Reorganization)
					Summit Midstream Corporation Stockholders
	Series A Preferred Units		Common Limited Partners’ Capital		Series A Preferred Stock		Common Stock Amount, at $0.01 par value		Class B Common Stock Amount, at $0.01 par value		Additional Paid in Capital		Retained Earnings (Deficit)		Non-controlling interest		Total Equity
	(In thousands)
Partners’ capital, December 31, 2022	$	85,327	$	679,491	$	—	$	—	$	—	$	—	$	—	$	—	$	764,818
Net income (loss)	11,566		(63,094)		—		—		—		—		—		—		(51,528)
Equity compensation	—		6,566		—		—		—		—		—		—		6,566
Tax withholdings and associated payments on vested Summit LTIP awards	—		(1,293)		—		—		—		—		—		—		(1,293)

Partners’ capital, December 31, 2023	$	96,893	$	621,670	$	—	$	—	$	—	$	—	$	—	$	—	$	718,563
Net income (loss)	7,668		47,837		5,669		—		—				(183,333)		(5,822)		(127,981)
Equity compensation	—		5,415		—		—		—		3,146		—		—		8,561
Tax withholdings and associated payments on vested Summit LTIP awards	—		(1,882)		—		—		—		(144)		—		—		(2,026)
Corporate Reorganization	(104,561)		(673,040)		104,561		106		—		672,934		—		—		—
Tax impact of Corporate Reorganization	—		—		—		—		—		32,349		—		—		32,349
Tax impact of Up-C Structure	—		—		—		—		—		52,582		—		—		52,582
Issuance of noncontrolling interest (Tall Oak Acquisition)	—		—		—		—		75		(220,153)		—		503,155		283,077
Equity, December 31, 2024	$	—	$	—	$	110,230	$	106	$	75	$	540,714	$	(183,333)	$	497,333	$	965,125
Net income (loss)	—		—		13,631		—		—		—		(19,569)		(10,831)		(16,769)
Dividend paid on Series A Preferred Stock	—		—		(13,393)		—		—		—		—		—		(13,393)
Equity compensation	—		—		—		—		—		7,798		—		—		7,798
Tax withholdings and associated payments on vested Summit LTIP awards	—		—		—		1		—		(3,118)		—		—		(3,117)
Moonrise Acquisition	—		—		—		5		—		17,890		—		—		17,895
Conversion of Class B Common Stock and Partnership Common Units	—		—		—		10		(10)		—		—		—		—
Tax impact of Up-C Structure	—		—		—		—		—		(10,983)		—		—		(10,983)
Equity shift	—		—		—		—		—		86,126		—		(86,126)		—
Equity, December 31, 2025	$	—	$	—	$	110,468	$	122	$	65	$	638,427	$	(202,902)	$	400,376	$	946,556

The accompanying notes are an integral part of these consolidated financial statements.

SUMMIT MIDSTREAM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year ended December 31,
	2025		2024		2023
	(In thousands)
Operating activities:
Net loss	$	(1,906)	$	(113,175)	$	(38,947)
Adjustments to reconcile net loss to net cash provided by operating activities:
Deferred income taxes	(699)		146,831		—
Depreciation and amortization	115,097		101,585		123,702
Noncash lease expense	5,808		1,658		3,773
Amortization of debt issuance costs	4,033		11,439		12,685
Equity compensation	7,798		8,561		6,566
Income from equity method investees	(20,784)		(24,197)		(33,829)
Distributions from equity method investees	28,578		36,190		57,572
(Gain) loss on asset sales, net	486		1		(260)
Foreign currency (gain) loss	—		42		(102)
(Gain) loss on earn-out remeasurement	192		(6)		599
Loss on early extinguishment of debt	—		50,075		10,934
(Gain) loss on sale of business	582		(82,187)		47
Gain on sale of equity method investment	—		(126,261)		—
Unrealized loss on interest rate swaps	4,441		914		3,318
Long-lived asset impairment	2,725		68,260		540
Changes in operating assets and liabilities:
Accounts receivable	9,851		3,004		(3,352)
Trade accounts payable	5,548		1,119		4,483
Accrued expenses	(15,059)		(625)		5,586
Deferred revenue	(6,448)		(5,075)		(6,467)
Ad valorem taxes payable	646		1,001		(1,702)
Accrued interest	8,334		2,413		1,943
Accrued environmental remediation, net	(435)		(739)		(768)
Other, net	(15,193)		(19,057)		(19,415)
Net cash provided by operating activities	133,595		61,771		126,906
Investing activities:
Capital expenditures	(89,042)		(53,611)		(68,905)
Cash consideration paid for the acquisition of Moonrise, net of cash acquired	(69,997)		—		—
Investment in Double E equity method investee	(3,816)		(3,880)		(3,500)
Cash consideration paid for Tall Oak Acquisition, net of cash acquired	—		(154,154)		—
Proceeds from Utica Sale (excluding Ohio Gathering)	—		292,266		—
Proceeds from sale of Ohio Gathering	—		332,734		—
Proceeds from Mountaineer Transaction	—		69,304		—

Proceeds from asset sale	—		4,400		260
Other, net	(295)		—		(2,611)
Net cash provided by (used in) investing activities	(163,150)		487,059		(74,756)
Financing activities:
Issuance of Additional 2029 Secured Notes	258,438		—		—
Borrowings on Amended and Restated ABL Facility	133,000		305,000		70,000
Debt repayments - Amended and Restated ABL Facility	(325,000)		(313,000)		(87,000)
Debt repayments - Permian Transmission Term Loan	(12,324)		(15,524)		(10,507)
Distribution on Series A Preferred Shares	(13,393)		—		—
Distributions on Subsidiary Series A Preferred Units	(6,513)		(6,513)		(6,512)
Issuance of 2029 Secured Notes	—		565,800		—
Debt repayments - Redemption of 2026 Unsecured Notes	—		(209,510)		—
Debt repayments - 2026 Secured Notes (Excess Cash Flow Offer)	—		(13,626)		—
Debt repayments - 2026 Secured Notes (Asset Sale Offer)	—		(6,910)		—
Debt repayments - 2025 Senior Notes Redemption

Summit Midstream Corp 10-K