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(Exact name of registrant as specified in its charter)

(State or other jurisdiction of

incorporation or organization)

(Address of principal executive offices)

(I.R.S. Employer

Identification No.)

(Zip Code)

(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

o

Accelerated filer

x

Non-accelerated filer

o

Smaller reporting company

x

Emerging growth company

o

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

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, 2024 was $378,667,239.

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

Portions of the registrant’s definitive proxy statement relating to its 2025 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2024, are incorporated by reference into Part III of this Annual Report on Form 10-K where indicated.

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 ability to achieve the strategic and other objectives relating to the Tall Oak Acquisition;

•the risk that we are unable to integrate Tall Oak’s operations in a successful manner and in the expected time period;

•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 gathering, compression, treating and/or processing of natural gas, crude oil and produced water;

•our ability to comply with the terms of the agreements comprising the Global Settlement;

•weather conditions and terrain in certain areas in which we operate;

•physical and financial risks associated with climate change;

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

•timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule;

•our ability to finance our obligations related to capital expenditures, including through opportunistic asset divestitures or joint ventures and the impact any such divestitures or joint ventures could have on our results;

•the effects of existing and future laws and governmental regulations, including environmental, safety and climate change requirements and federal, state and local restrictions or requirements applicable to oil and/or gas drilling, production or transportation;

•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.

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:

•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.

•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.

•The failure to successfully integrate the business and operations of Tall Oak in the expected time frame may adversely affect the Company’s future results.

•Restrictions in the Permian Transmission Credit Facilities, 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.

•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.

•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.

•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.

The following chart provides a summarized view of our legal entity structure as of December 31, 2024:

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.

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, following the Tall Oak Acquisition, the Arkoma Basin. Our primary business objective is to maximize cash flow and provide cash flow stability for its 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 Tall Oak Acquisition), or asset divestitures (such as the Utica Sale or the Mountaineer Transaction) 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 Tall Oak Acquisition) or opportunistic divestitures (such as the Utica Sale or the Mountaineer Transaction), 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.

The following is a brief listing of significant developments and highlights for the year ended December 31, 2024. Additional information regarding these items may be found elsewhere in this Annual Report.

•Strategic review. Subsequent to the October 2023 announcement of our strategic review, we executed the following transactions in order to maximize shareholder value:

•Summit Utica Sale. On March 22, 2024, we completed the Utica Sale 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.

•Mountaineer Transaction. On May 1, 2024, we completed the Mountaineer Transaction for a cash sale price of $70.0 million, subject to customary post-closing adjustments. Mountaineer Midstream was the owner of midstream assets located in the Marcellus Shale. Prior to closing the Mountaineer Transaction, we sold related compression assets located in the Marcellus Shale to a compression service provider for approximately $5 million in April 2024.

•Debt Reduction and Maturity Optimization. Over the course of 2024, the Company optimized its indebtedness by reducing debt, lowering its borrowing cost, and extending its debt maturities. These optimization transactions included the following:

•2026 Secured Notes Excess Cash Flow Offer. On March 27, 2024, Summit Holdings and Finance Corp. commenced a cash tender offer to purchase up to $19.3 million aggregate principal amount of the outstanding 2026 Secured Notes at 100% of the principal amount plus accrued and unpaid interest. The 2024 ECF Offer expired on April 24, 2024 with $13.6 million aggregate principal amount of the 2026 Secured Notes tendered and validly accepted and $5.7 million of declined proceeds.

•2026 Secured Notes Asset Sale Offer. On May 7, 2024, Summit Holdings and Finance Corp. commenced a cash tender offer to purchase up to $215.0 million aggregate principal amount of the outstanding 2026 Secured Notes at 100% of the principal amount plus accrued and unpaid interest. The 2026 Secured Notes Asset Sale Offer expired on June 5, 2024 with $6.9 million aggregate principal amount of the 2026 Secured Notes tendered and validly accepted and $208.1 million of declined proceeds.

•2026 Unsecured Notes Redemption. On June 7, 2024, Summit Holdings and Finance Corp. delivered a redemption notice with respect to all $209.5 million aggregate principal amount of the 2026 Unsecured Notes. The 2026 Unsecured Notes Redemption was funded with declined proceeds from the 2024 ECF Offer and the 2026 Secured Notes Asset Sale Offer and proceeds from the Mountaineer Transaction and the Utica Sale and settled on June 24, 2024.

•Issuance of 2029 Secured Notes. On July 26, 2024, Summit Holdings issued $575.0 million aggregate principal amount of the 2029 Secured Notes.

•2026 Secured Notes Tender Offer and Redemption. On July 26, 2024, concurrently with closing the offering of the Initial 2029 Secured Notes, Summit Holdings and Finance Corp. consummated a cash tender offer to purchase any and all of the outstanding 2026 Secured Notes. Summit Holdings and Finance Corp. accepted for payment and made payment for $649.8 million aggregate principal amount of the 2026 Secured Notes validly tendered in the 2026 Secured Notes Tender Offer. On July 26, 2024, concurrently with consummation of the 2026 Secured Notes Tender Offer, Summit Holdings and Finance Corp. delivered a notice of redemption to holders of 2026 Secured Notes for the redemption of all $114.7 million aggregate principal amount of 2026 Secured Notes not purchased in the 2026 Secured Notes Tender Offer, at a price equal to 102.125% of the principal amount thereof, plus accrued and unpaid interest to the redemption date. On July 26, 2024, concurrently with delivery of a notice of redemption, Summit Holdings and Finance Corp. irrevocably deposited $121.2 million in aggregate principal amount of non-callable United States Treasury securities, which included amounts for principal, interest, and premium, with the trustee to satisfy and discharge the 2026 Secured Notes until redeemed on October 15, 2024 with the funds deposited with the trustee. On October 15, 2024, the 2026 Secured Notes were fully repaid.

•2025 Senior Notes Redemption. On July 17, 2024, Summit Holdings and Finance Corp. delivered a conditional notice of redemption to holders of 2025 Senior Notes for the redemption of all $49.8 million aggregate principal amount of outstanding 2025 Senior Notes, at a price equal to 100.000% of the principal amount thereof, plus accrued and unpaid interest to the redemption date, conditioned on closing of the offering of the Initial 2029 Secured Notes. On July 26, 2024, concurrently with closing of the offering of the Initial 2029 Secured Notes, Summit Holdings and Finance Corp. irrevocably deposited $50.6 million in aggregate principal amount of non-callable United States Treasury securities, which included amounts for principal and interest, with the trustee to satisfy and discharge the 2025 Senior Notes until redeemed with the funds deposited with the trustee. On August 16, 2024, the 2025 Senior Notes were fully repaid.

•Corporate Reorganization. On August 1, 2024, following unitholder approval at SMLP’s Special Meeting of Unitholders on July 18, 2024, SMLP consummated a previously announced transaction that resulted in SMLP becoming a wholly owned subsidiary of the Company. Upon the consummation of the Corporate Reorganization, each outstanding common unit of SMLP was converted into the right to receive 1.000 shares of common stock of the Company and each outstanding Series A Preferred Unit was converted into the right to receive 1.000 shares of Series A Preferred Stock of the Company, with the liquidation preference of each share of Series A Preferred Stock initially equal to $1,000 and the Series A Certificate of Designation deeming all accumulated and unpaid distributions on the Series A Preferred Units to be Series A Unpaid Cash Dividends (as defined in the Series A Certificate of Designation) per share of Series A Preferred Stock, which constituted all consideration to be paid in respect to such Series A Preferred Units, and any rights to accumulated and unpaid distributions on such Series A Preferred Units were discharged.

•Tall Oak Acquisition. On December 2, 2024, the Company completed the transaction contemplated in the Tall Oak Business Contribution Agreement, 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. Total consideration consisted of (i) a $155.0 million cash payment, (ii) cash earn-out payments of up to $25.0 million subject to Tall Oak and its customers meeting certain development requirements and (iii) the issuance of 7,471,008 shares of Class B Common Stock of the Company and 7,471,008 Partnership Common Units of SMLP (causing SMLP to be treated as a partnership for U.S. federal income tax purposes), that are exchangeable into an equivalent quantity of the Company’s common stock on a 1:1 exchange ratio. Upon completion of the Tall Oak Acquisition, the Company and Tall Oak Parent jointly owned SMLP, each with economic and voting rights, and Tall Oak Parent owned exchangeable non-economic Class B Common Stock with Company voting rights (the “Up-C Structure”).

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 Double E, a long-haul natural gas pipeline in which we indirectly own a 70% equity interest and serve as the pipeline’s operator. Double E provides natural gas transportation services from multiple receipt points in the Permian Basin to various delivery points in and around the Waha hub in Texas.

Reportable Segments. As of December 31, 2024, our reportable segments are below along with management’s categorization of the primary commodity driving customer drilling and completion decisions for each segment:

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

•Rockies – Includes our 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 fixed fees for gathering natural gas.

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

•Mid-Con – Includes our midstream assets located in the Barnett Shale and, following the Tall Oak Acquisition, the Arkoma Basin.

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 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 2039. 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 5.8 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, 2024, we had remaining MVCs totaling 0.1 Tcfe, our MVCs had a weighted-average remaining life of 2.4 years, and these MVC’s average approximately 90 MMcfe/d through 2028.

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 2024, aggregate natural gas volume throughput averaged 862 MMcf/d and crude oil and produced water volume throughput averaged 72 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, 2024, these additional activities accounted for approximately 45% of total revenues.

Equity Method Investment – Double E. We have an equity method investment in Double E, a 1.5 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, 2024, the Company owns a 70% interest in Double E. A subsidiary of ExxonMobil Corporation is our joint venture partner.

Equity Method Investment – Ohio Gathering. Up until 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.

The following provides an overview of our reportable segments as of December 31, 2024.

The following table provides operating information regarding our Rockies reportable segment as of December 31, 2024.

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(1)Capacity of 220 MMcf/d represents nameplate processing capacity. Operational capacity is estimated at approximately 180 MMcf/d. Weighted average remaining life excludes interruptible off-load contracts.

AMIs for the Rockies reportable segment total approximately 2.5 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 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. Bison Oil and Gas IV, Chevron Corporation, Civitas Resources, Inc., a large U.S. independent crude oil and natural gas company, 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 220 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 30 miles of gathering pipeline with delivery into the Pony Express pipeline.

The following table provides operating information regarding our Permian reportable segment as of December 31, 2024.

			Aggregate throughput capacity (MMcf/d)						Average daily MVCs through 2029 (MMcf/d)						Remaining MVCs (Bcf)						Weighted-average remaining contract life (Years)						Weighted-average remaining MVC life (Years)
Double E (1)			1,500						1,106						3,012						7.4						7.6

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

Double E. Double E 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, a large U.S. independent crude oil and natural gas company, Marathon Oil Corporation, which merged with ConocoPhillips in November 2024, 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 67% of its estimated capacity of 1,500,000 Dth/d.

Volume throughput is received from multiple processing plants, including Enlink’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. In 2023, Double E executed a new 40 MMcf/d contract with a large U.S. independent crude oil and natural gas company, which includes a connection to the Janus Processing Plant. The take-or-pay contract has a 10-year term from March 1, 2025.

In 2024, Double E executed a new agreement with Matador Resources Company, which consolidated Matador’s two existing agreements and added an incremental 75 MMcf/d of firm transport capacity to support the expansion of their Marlan processing plant. Matador’s new consolidated agreement has a 10-year term from the effective date, which occurred on May 1, 2024.

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

The following table provides operating information regarding our Piceance reportable segment as of December 31, 2024.

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, which acquired Caerus Oil and Gas’ Piceance assets in August 2024, and Terra Energy Partners. Volume throughput on the Grand River system is underpinned with acreage dedications and MVCs. The Grand River system is primarily a low-pressure gathering system located in western Colorado that gathers natural gas produced from directional wells targeting the liquids-rich Mesaverde formation. The Grand River system also gathers natural gas produced from the Mancos and Niobrara shale formations. Natural gas gathered and/or processed on the Grand River system is compressed, dehydrated, processed and/or discharged to downstream pipelines serving (i) the Meeker Processing Complex, (ii) the Williams Processing Complex, (iii) the TransColorado Pipeline system and (iv) SourceGas. Processed NGLs from Grand River are injected into the Mid-America Pipeline system or delivered to local markets. 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.

The following table provides operating information regarding our Mid-Con reportable segment as of December 31, 2024.

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

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

DFW Midstream system. The DFW Midstream system is primarily located in southeastern Tarrant County, in north-central Texas. We considers 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 Transmission and Enable Gas Transmission connections. NGL’s have access to ONEOK’s NGL system and Targa’s Grand Prix pipeline.

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.

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.

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 Epping Pipeline interstate crude oil pipeline, which is 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 pipeline are currently regulated primarily through an annual indexing methodology, under which pipelines increase or decrease their existing rates in accordance with a FERC-specified adjustment that sets a rate ceiling. This adjustment, which may be positive or negative in a given year, is subject to review every five years. There is currently some uncertainty regarding the index pricing. During the last review period, FERC set the index level in December 2020 (the “Initial Order”), however, both pipelines and pipeline customers sought rehearing of the Initial Order and in January 2022, FERC issued a rehearing order setting a lower index price prospectively (the “Rehearing Order”). Pipelines challenged the Rehearing Order at the D.C. Circuit and on July 26, 2024, the D.C. Circuit vacated the Rehearing Order, which will increase the index price back to the Initial Order levels. On October 17, 2024, FERC issued a supplemental notice of proposed rulemaking proposing to reduce the index price back down to the Rehearing Order price and the proposal is now pending at FERC.

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. On November 18, 2021, we entered into negotiated rate agreements with an average term of 10 years from the in-service date of the pipeline and with total MDTQ’s that increase from 585,000 Dth/d during the first year of the agreement to 1,000,000 Dth/d in the fourth year, which equates to approximately 67% of its capacity of 1,500,000 Dth/d. When capacity is available and offered for sale, the rates (which include reservation, commodity, surcharges, and fixed fuel and lost and unaccounted for charges) and the terms and conditions at which such capacity is sold are subject to regulatory approval and oversight. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on our business, financial condition and results of operations.

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.

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.

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

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

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

We also generate industrial wastes that are subject to the requirements of the RCRA and comparable state statutes. While the RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Although we generate minimal hazardous waste, it is possible that non-hazardous wastes, which could include wastes currently generated during our operations, will in the future be designated as hazardous wastes and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes 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. However, the EPA has announced that it will reconsider the 2020 decision to retain the 2015 standards. Future actions to lower the standard could similarly result in additional fees or more stringent permitting.

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, 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. 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 proposed a new rule in November 2022, 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. However, our customers that are primarily upstream wellhead operators may be impacted by the requirements in this rule.

In recent years, the EPA has also demonstrated an increased focus on CAA compliance for natural gas gathering operations. For example, in September 2019, 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 United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility's operations comply with the requirements. To be in compliance, the facility's SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security and training. Certain of our facilities are classified as SPCC-regulated facilities. We believe that they are in substantial compliance with all applicable requirements of OPA.

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 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. The parties remain in settlement discussions.

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.

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.

As a result, future implementation and enforcement of the final rule remains uncertain.

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 immediately withdraw the 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 GHG emission limits from motor vehicles as well as establish PSD construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis.

EPA rules also require the reporting of GHG emissions from specified large GHG-emitting sources in the United States, including onshore and offshore oil and natural gas systems. We are required to report under these rules for our assets that have GHG emissions above the reporting thresholds. In October 2015, the EPA issued revisions to Subpart W of the GHG reporting rule to include reporting requirements for gathering and booster stations, onshore natural gas transmission pipelines, and completions and workovers of oil wells with hydraulic fracturing. This development resulted in increased monitoring and reporting for our operations and for upstream producers for whom we provide midstream services. Further, the IRA, signed into law in August 2022, includes a Methane Emissions Reduction Program to incentivize methane emission reductions and imposes a “Waste Emissions Charge” on GHG emissions from certain oil and gas facilities. Emissions reported under the GHG reporting rule will be the basis for any payments under the Methane Emissions Reduction Program. However, petitions for reconsideration to the EPA are pending and litigation in the D.C. Circuit has commenced. In November 2024, the EPA finalized regulations to implement the IRA’s Waste Emissions Charge, which became effective in January 2025. The Waste Emissions Charge for 2024 is $900 per ton of methane emitted over permitted methane emissions thresholds, and increases to $1,200 in 2025, and $1,500 in 2026. 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, on February 27, 2025, the United States Senate voted to overturn the Waste Emissions Charge by passing a resolution through the Congressional Review Act, which allows Congress to reverse new federal rules with a simple majority vote. 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). Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that certain components of our operations, such as our gas-fired compressors, could become subject to state-level GHG-related regulation.

At the international level, in February 2021, pursuant to the Paris Agreement, the Biden Administration announced reentry of the U.S. into the Paris Agreement (an international agreement from the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change in Paris, France, which resulted in an agreement for signatory countries to nationally determine their contributions and set GHG emission reduction goals) along with a new “nationally determined contribution” for U.S. GHG emissions that would achieve emissions reductions of at least 50% relative to 2005 levels by 2030. In September 2021, the United States and the European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution by at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. In December 2023, at the 28th Conference of the Parties to the United Nations Framework Convention on Climate Change, member countries issued the first global stocktake, which calls on parties, including the U.S., to contribute to transitioning away from fossil fuels, reduce methane emissions, and increase renewable energy capacity, amongst other things, to achieve net zero by 2050. Most recently, at the 29th Conference of the Parties to the United Nations Framework Convention on Climate Change (“COP29”), delegates approved rules to operationalize international carbon markets under Article 6 of the Paris Agreement, including a new Paris Agreement Crediting Mechanism to trade UN-approved carbon credits. Additionally, participants at COP29 representing 159 countries met to review progress toward the goals of the Global Methane Pledge and the addition of nearly $500 million in new grant funding for methane abatement. In January 2025, President Trump issued an executive order directing the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. However, various state and local governments have vowed to continue to enact regulations to further the goals of the Paris Agreement. 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.

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

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

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

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

As of December 31, 2024, the Company employed 272 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.

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.

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 or Series A Preferred Stock, or prior to the Corporate Reorganization, our Series A Preferred Units or our common units, 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, 2024, the amount of accrued and unpaid dividends on the Series A Preferred Stock totaled $46.4 million.

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 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, including the Subsidiary Series A Preferred Units; and

•other business risks affecting our cash levels.

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.

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.

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 2024, the Henry Hub Natural Gas Spot Price declined from a monthly average of $3.18 per MMBtu in January 2024 to a monthly average of $1.49 per MMBtu in March 2024, before trending upward in the latter three quarters of 2024 to close the year at $3.40 per MMBtu on December 31, 2024. As of January 31, 2025, Henry Hub 12-month strip pricing closed at $3.04 per MMBtu. In the first half of 2024, Cushing, Oklahoma West Texas Intermediate crude oil spot prices increased from a monthly average of $74.15 per barrel in January 2024 to a monthly average of $85.35 per barrel in April 2024, before trending downward in the latter half of 2024 to close the year at $72.44 per barrel on December 31, 2024. As of January 31, 2025, West Texas Intermediate 12-month strip pricing closed at $72.53 per barrel.

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;

•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 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.

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 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.

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.

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.

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.

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.

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 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 (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.

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 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 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.

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, which currently includes certain ESG targets.

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 while others may disagree with the ESG initiatives and targets we have set. 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).

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 Permian Transmission Credit Facilities.

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 the continued 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 or Series A Preferred Stock, or prior to the Corporate Reorganization, the common units or Series A Preferred Units, since we announced suspension of those distributions on May 3, 2020, and these suspensions of 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, 2024, the amount of accrued and unpaid dividends on the Series A Preferred Stock totaled $46.4 million. 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.

As of December 31, 2024, we had $1.0 billion of indebtedness outstanding, and the unused portion of the Amended and Restated ABL Facility totaled $194.2 million after giving effect 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.

Our ability to make scheduled payments on, or to refinance, our indebtedness obligations, including the Amended and Restated ABL Facility, the Permian Transmission Credit Facilities 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, 2024, $575.0 million of the 2029 Secured Notes were outstanding, and we subsequently issued an additional $250.0 million of the 2029 Secured Notes on January 10, 2025. As of March 11, 2025, $825.0 million of the 2029 Secured Notes were outstanding. See Note 19 – Subsequent Events, for additional information.

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), and (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.

The Company believes that the acquisition of the Tall Oak will result in certain benefits, including certain cost synergies and operational efficiencies. However, to realize these anticipated benefits, the businesses of the Company and Tall Oak must be successfully combined. The success of the Tall Oak Acquisition will depend on the Company’s ability to realize these anticipated benefits from integrating the business of Tall Oak into the Company. The actual integration may result in additional and unforeseen expenses or delays. If the Company is not able to successfully integrate Tall Oak’s business and operations, or if there are delays in combining the businesses, the anticipated benefits of the Tall Oak Acquisition may not be realized fully or at all or may take longer to realize than expected.

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 Permian Transmission Credit Facilities, 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 Permian Transmission Credit Facilities 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 Permian Transmission Credit Facilities, 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 Permian Transmission Credit Facilities, 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 equityholders 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. Any of these restrictions in the Amended and Restated ABL Facility, the Permian Transmission Credit Facilities and the indenture governing the 2029 Secured Notes could materially adversely affect our business, financial condition, cash flows and results of operations.

Although inflation in the United States 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 2.9% in December 2024, further increases in inflation in 2025 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.

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 4.25% to 4.50% the timing of any potential increases or decreases remains uncertain. Borrowings under the Amended and Restated ABL Facility and the Permian Transmission Credit Facilities 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.

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 recorded long-lived asset impairments of $68.3 million during the year ended December 31, 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.

During the year ended December 31, 2024, we derived 45% 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.

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 $21.3 million as of December 31, 2024 and requires compliance with certain conditions and terms and conditions, which may impact our results of operations or cash flows.

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.

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, the PHMSA has issued new proposed and final rules concerning pipeline safety in recent years. In November 2021, PHMSA issued a final rule that extended pipeline safety requirements to onshore gas gathering pipelines. The rule requires all onshore gas gathering pipeline operators to comply with PHMSA’s incident and annual reporting requirements. It also extended existing pipeline safety requirements to a new category of gas gathering pipelines, “Type C” lines, which generally include high-pressure pipelines that are larger than 8.625 inches in diameter.

Safety requirements applicable to Type C lines vary based on pipeline diameter and potential failure consequences. The final rule became effective in May 2022. In addition, in August 2022, PHMSA issued a final rule that established new or additional requirements for natural gas transmission lines related to the management of change process, integrity management, corrosion control standards, and pipeline inspections and repairs. 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. 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.

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. The parties remain in settlement discussions.

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. As a result, future implementation and enforcement of the final rule remains uncertain.

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.

We have certain long-term fixed priced natural gas and crude oil transportation contracts that cannot be adjusted even if our costs increase. As a result, our costs could exceed our revenues. 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 maximum daily transportation quantities that increases 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 67% of its capacity of 1,500,000 Dth/d; these contracts are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts. It is possible that costs to perform services under our “negotiated or discount rate” contracts will exceed the negotiated or discounted rates. It is also possible with respect to discounted rates that if our filed “recourse rates” should ever be reduced below applicable discounted rates, we would only be allowed by FERC to charge the lower recourse rates, since FERC policy does not allow discount rates to be charged to the extent that they exceed applicable recourse rates. If these events were to occur, it could decrease the cash flow realized by our assets.

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. 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 $1.5 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.

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.

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.”

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 “Waste Emissions Charge” 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, petitions for reconsideration to the EPA are pending and litigation in the D.C. Circuit has commenced. In November 2024, the EPA finalized regulations to implement the IRA’s Waste Emissions Charge, which became effective in January 2025. The Waste Emissions Charge for 2024 is $900 per ton of methane emitted over permitted methane emissions thresholds, and increases to $1,200 in 2025, and $1,500 in 2026.

The Waste Emissions Charge and other related initiatives targeting methane emissions could impose additional costs on our operations. 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. 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. 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.

At the international level, in February 2021, pursuant to the Paris Agreement, the Biden Administration announced reentry of the U.S. into the Paris Agreement (an international agreement from the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change in Paris, France, which resulted in an agreement for signatory countries to nationally determine their contributions and set GHG emission reduction goals) along with a new “nationally determined contribution” for U.S. GHG emissions that would achieve emissions reductions of at least 50% relative to 2005 levels by 2030. In September 2021, the United States and the European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution by at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. In December 2023, at the 28th Conference of the Parties to the United Nations Framework Convention on Climate Change, member countries issued the first global stocktake, which calls on parties, including the U.S., to contribute to global efforts to transition away from fossil fuels, reduce methane emissions, triple renewable energy capacity and double energy efficiency improvements by 2030, among other things, to achieve net zero by 2050. While the stocktake agreement is not legally binding and has no enforcement mechanism, the United States could pass further legislation based on the agreement. Most recently, at COP29, delegates approved rules to operationalize international carbon markets under Article 6 of the Paris Agreement, including a new Paris Agreement Crediting Mechanism to trade UN-approved carbon credits. Additionally, participants at COP29 representing 159 countries met to review progress toward the goals of the Global Methane Pledge and the addition of nearly $500 million in new grant funding for methane abatement. In January 2025, President Trump issued an executive order directing the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. However, various state and local governments in the U.S. have vowed to continue to enact regulations to further the goals of the Paris Agreement. 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. While the Supreme Court’s June 2024 decision in Loper Bright Enterprises v. Raimondo to overrule Chevron U.S.A. Inc. v. Natural Resources Defense Council, Inc. ended the concept of general deference to regulatory agency interpretations of laws and introduced new complexity for federal agencies and administration of climate change policy and regulatory programs, many of these initiatives could continue.

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.

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 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. As a result, any future revisions to nationwide permits, including NWP 12, are uncertain at this time. 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 is expected to be completed by the Corps in 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.

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 recent 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, 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.

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 United States 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.

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 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.

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 and the Permian Transmission Credit Facilities 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.

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 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.

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.

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

Cybersecurity threats present a large and growing risk to our business, as the oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of 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. 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. 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.

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 Company management.

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 30 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;

•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 11, 2025, the Company’s business strategy, operations, or financial condition have not been materially affected by and are not likely to be materially affected by, any cybersecurity threats or incidents.

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 space to support our operations.

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. Fiberspar is currently seeking a total of approximately $8.5 million in damages consisting of $5.0 million from allegedly owed but not paid for orders of pipeline product, plus prejudgment interest and attorney’s fees. The petition asserts causes of action for breach of contract and suit on sworn account. A civil action on the same claims had been filed by Fiberspar in 2016 but was dismissed without prejudice pursuant to a standstill and tolling agreement that expired in 2021.

We filed an answer on September 6, 2022 denying Fiberspar’s claims and asserting counter claims. The case is pending in the District Court of Harris County, Texas. We are unable to predict the final outcome of this matter.

Global Settlement. On August 4, 2021, 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 United States, by and through the U.S. Attorney for the District of North Dakota, and the Environmental Crimes Section of the DOJ; and (iii) a Consent Agreement with the North Dakota Industrial Commission (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 North Dakota Industrial Commission 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, of which we have paid principal amounts of $21.3 million as of December 31, 2024.

Our common stock trades on the NYSE under the ticker symbol “SMC”. As of December 31, 2024, there were approximately 72 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.

We have not paid any dividends on our shares of common stock or shares of Series A Preferred Stock, or prior to the Corporate Reorganization, our common units or our Series A Preferred Units, since we announced a suspension of those distributions on May 3, 2020. We paid cash distributions on our Subsidiary Series A Preferred Units totaling $6.5 million in 2024 and 2023 and accrued an additional $1.6 million in 2024 which was subsequently paid in 2025.

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) per share of Series A Preferred Stock, 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. As of December 31, 2024, the amount of accrued and unpaid dividends on the Series A Preferred Stock totaled $46.4 million. 

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.

The Company had 65,508 shares of Series A Preferred Stock outstanding as of December 31, 2024 and $46.4 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. See Note 19 - Subsequent Events to the consolidated financial statements.

Permian Holdco had 93,039 Subsidiary Series A Preferred Units outstanding as of December 31, 2024.

Distributions on the Subsidiary Series A Preferred Units are cumulative and compounding and are payable quarterly in arrears 21 days after the quarter ending March, June, September and December of each year (each, a “Subsidiary Series A Preferred Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Subsidiary Series A Preferred Distribution Payment Date, in each case, when, as, and if declared by the board of directors of Permian Holdco out of legally available funds for such purpose.

The distribution rate is 7.00% per annum of the $1,000 issue amount per outstanding Permian Holdco Subsidiary Series A Preferred Unit. If the Subsidiary Series A Preferred Units were redeemed on December 31, 2024, the redemption amount would be $134.1 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.

See Note 12 - Equity and Mezzanine Equity to the consolidated financial statements for additional details.

Other than the shares of Class B Common Stock issued to Tall Oak Parent in the Tall Oak Acquisition, we did not sell any unregistered equity securities during the quarter or year ended December 31, 2024.

We made no repurchases of our common stock or common units of the Partnership during the quarter or year ended December 31, 2024.

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, 2024 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).

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 United States.

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, 2024, these additional activities accounted for approximately 45% 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, 2024 and 2023” section herein.

			Year ended December 31,
			2024						2023
			(In thousands)
Net loss			$	(113,175)					$	(38,947)
Reportable segment adjusted EBITDA
Rockies			$	93,827					$	87,390
Permian			31,227						24,207
Piceance			52,704						59,749
Mid-Con			30,645						26,171
Northeast			30,634						94,249
Net cash provided by operating activities			$	61,771					$	126,906
Capital expenditures(1)			53,611						68,905
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						—
Investment in Double E equity method investee			3,880						3,500
Net cash provided by (used in) financing activities
Debt repayments - ABL Facility			(313,000)						(87,000)
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 - Repurchase of 2025 Senior Notes			—						(29,650)
Debt repayments - Permian Transmission Term Loan			(15,524)						(10,507)
Debt repayments - 2025 Senior Notes Redemption			(49,783)						—
Debt repayments - 2026 Secured Notes Redemption			(764,464)						—
Borrowings on Amended and Restated ABL Facility			305,000						70,000
Issuance of 2029 Secured Notes			565,800						—
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, 2024. The following is a brief listing of significant developments and highlights which are items reflected in our financial results for the fiscal year ended December 31, 2024. Additional information regarding these items may be found elsewhere in this Annual Report.

•Strategic review. Subsequent to the October 2023 announcement of our strategic review, we executed the following transactions in order to maximize shareholder value:

•Summit Utica Sale. On March 22, 2024, we completed the Utica Sale 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.

•Mountaineer Transaction. On May 1, 2024, we completed the Mountaineer Transaction for a cash sale price of $70.0 million, subject to customary post-closing adjustments. Mountaineer Midstream was the owner of midstream assets located in the Marcellus Shale. Prior to closing the Mountaineer Transaction, we sold related compression assets located in the Marcellus Shale to a compression service provider for approximately $5 million in April 2024.

•Debt Reduction and Maturity Optimization. Over the course of 2024, the Company optimized its indebtedness by reducing debt, lowering its borrowing cost, and extending its debt maturities. These optimization transactions included the following:

•2026 Secured Notes Excess Cash Flow Offer. On March 27, 2024, Summit Holdings and Finance Corp. commenced a cash tender offer to purchase up to $19.3 million aggregate principal amount of the outstanding 2026 Secured Notes at 100% of the principal amount plus accrued and unpaid interest. The 2024 ECF Offer expired on April 24, 2024 with $13.6 million aggregate principal amount of the 2026 Secured Notes tendered and validly accepted and $5.7 million of declined proceeds.

•2026 Secured Notes Asset Sale Offer. On May 7, 2024, Summit Holdings and Finance Corp. commenced a cash tender offer to purchase up to $215.0 million aggregate principal amount of the outstanding 2026 Secured Notes at 100% of the principal amount plus accrued and unpaid interest. The 2026 Secured Notes Asset Sale Offer expired on June 5, 2024 with $6.9 million aggregate principal amount of the 2026 Secured Notes tendered and validly accepted and $208.1 million of declined proceeds.

•2026 Unsecured Notes Redemption. On June 7, 2024, Summit Holdings and Finance Corp. delivered a redemption notice with respect to all $209.5 million aggregate principal amount of the 2026 Unsecured Notes. The 2026 Unsecured Notes Redemption was funded with declined proceeds from the 2024 ECF Offer and the 2026 Secured Notes Asset Sale Offer and proceeds from the Mountaineer Transaction and the Utica Sale and settled on June 24, 2024.

•Issuance of 2029 Secured Notes. On July 26, 2024, Summit Holdings issued $575.0 million aggregate principal amount of the 2029 Secured Notes.

•2026 Secured Notes Tender Offer and Redemption. On July 26, 2024, concurrently with closing the offering of the Initial 2029 Secured Notes, Summit Holdings and Finance Corp. consummated a cash tender offer to purchase any and all of the outstanding 2026 Secured Notes. Summit Holdings and Finance Corp. accepted for payment and made payment for $649.8 million aggregate principal amount of the 2026 Secured Notes validly tendered in the 2026 Secured Notes Tender Offer. On July 26, 2024, concurrently with consummation of the 2026 Secured Notes Tender Offer, Summit Holdings and Finance Corp. delivered a notice of redemption to holders of 2026 Secured Notes for the redemption of all $114.7 million aggregate principal amount of 2026 Secured Notes not purchased in the 2026 Secured Notes Tender Offer, at a price equal to 102.125% of the principal amount thereof, plus accrued and unpaid interest to the redemption date. On July 26, 2024, concurrently with delivery of notice of redemption, Summit Holdings and Finance Corp. irrevocably deposited $121.2 million in aggregate principal amount of non-callable United States Treasury securities, which included amounts for principal, interest, and premium, with the trustee to satisfy and discharge the 2026 Secured Notes until redeemed on October 15, 2024 with the funds deposited with the trustee. On October 15, 2024, the 2026 Secured Notes were fully repaid.

•2025 Senior Notes Redemption. On July 17, 2024, Summit Holdings and Finance Corp. delivered a conditional notice of redemption to holders of 2025 Senior Notes for the redemption of all $49.8 million aggregate principal amount of outstanding 2025 Senior Notes, at a price equal to 100.000% of the principal amount thereof, plus accrued and unpaid interest to the redemption date, conditioned on closing of the offering of the Initial 2029 Secured Notes. On July 26, 2024, concurrently with closing of the offering of the Initial 2029 Secured Notes, Summit Holdings and Finance Corp. irrevocably deposited $50.6 million in aggregate principal amount of non-callable United States Treasury securities, which included amounts for principal and interest, with the trustee to satisfy and discharge the 2025 Senior Notes until redeemed with the funds deposited with the trustee. On August 16, 2024, the 2025 Senior Notes were fully repaid.

•Corporate Reorganization. On August 1, 2024, following unitholder approval at SMLP’s Special Meeting of Unitholders on July 18, 2024, SMLP consummated a previously announced transaction that resulted in SMLP becoming a wholly owned subsidiary of the Company. Upon the consummation of the Corporate Reorganization, each outstanding common unit of SMLP was converted into the right to receive 1.000 shares of common stock of the Company and each outstanding Series A Preferred Unit was converted into the right to receive 1.000 shares of Series A Preferred Stock of the Company, with the liquidation preference of each share of Series A Preferred Stock initially equal to $1,000 and the Series A Certificate of Designation deeming all accumulated and unpaid distributions on the Series A Preferred Units to be Series A Unpaid Cash Dividends (as defined in the Series A Certificate of Designation) per share of Series A Preferred Stock, which constituted all consideration to be paid in respect to such Series A Preferred Units, and any rights to accumulated and unpaid distributions on such Series A Preferred Units were discharged.

•Tall Oak Acquisition. On December 2, 2024, the Company completed the transaction contemplated in the Tall Oak Business Contribution Agreement, 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. Total consideration consisted of (i) a $155.0 million cash payment, (ii) cash earn-out payments of up to $25.0 million subject to Tall Oak and its customers meeting certain development requirements and (iii) the issuance of 7,471,008 shares of Class B Common Stock of the Company and 7,471,008 Partnership Common Units of SMLP (causing SMLP to be treated as a partnership for U.S. federal income tax purposes), that are exchangeable into an equivalent quantity of the Company’s common stock on a 1:1 exchange ratio. Upon completion of the Tall Oak Acquisition, the Company’s tax structure shifted to the Up-C Structure.

Key Matters for the Year ended December 31, 2023. The following items are reflected in our financial results for the fiscal year ended 2023:

•Strategic review. As we previously announced in October 2023, based on our then-recent and expected financial performance, as well as interest received from third parties for potential transactions, ranging from the sale of specific assets to consideration for the whole SMLP, our Board of Directors engaged external advisors to evaluate strategic alternatives for us with the goal of maximizing value for our unitholders. These alternatives included, but were not limited to, continued execution of our business plan, sale of assets, refinancing parts or the entirety of our capital structure, sale of SMLP by merger or cash, or any combination of these and other alternatives. The strategic review concluded in 2024 and is discussed above.

•Refinancing of 2025 Senior Notes. In November 2023, we entered into a private agreement to issue a total of $209.5 million aggregate principal amount of 2026 Unsecured Notes in exchange for $180.0 million aggregate principal amount of our existing 2025 Senior Notes and $29.5 million in cash (the “2023 Exchange”). The exchanged 2025 Senior Notes were cancelled. The cash raised was used to repurchase $29.7 million aggregate principal amount of existing 2025 Senior Notes (together with the 2023 Exchange, the “2023 Exchange Transactions”) that were not exchanged. As of December 31, 2023, following the consummation of the 2023 Exchange Transactions, approximately $49.8 million of 2025 Senior Notes remained outstanding.

•Integration of DJ Acquisitions. Our financial results for the year ended December 31, 2023 include our first full year with the assets acquired in the 2022 DJ Acquisitions. During 2023, we worked on integrating the 2022 DJ Acquisitions into our existing DJ Basin assets and began to achieve capital and operating synergies. Those integration efforts continued into 2024.

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 current Russia-Ukraine conflict, the international sanctions against Russia, continued conflict in the Middle East and other sustained military campaigns;

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

•Actions of the 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 Permian Credit Facility, and access to debt or equity 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 United States, certain events and conditions in foreign oil and natural gas producing countries, such as the continued conflict in the Middle East and Russia’s invasion of Ukraine, 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 United States. The average spot price of natural gas decreased by approximately 13% from 2023 to 2024, primarily due to natural gas supply exceeding demand. The average daily Henry Hub Natural Gas Spot Price was $2.19 per MMBtu during 2024, compared with $2.53 per MMBtu during 2023. As of January 31, 2025, Henry Hub 12-month strip pricing closed at 3.04 per MMBtu. During 2024, the number of active natural gas drilling rigs in the continental United States decreased from 120 in December 2023 to 102 in December 2024, 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. Over the next several years, we expect natural gas prices will support continued upstream industry activity by producers focused on natural gas production.

In addition, certain of our gathering systems are directly affected by crude oil supply and demand dynamics. Crude oil prices decreased in 2024, with the average daily Cushing, Oklahoma West Texas Intermediate crude oil spot price average of $77.58 per barrel during 2023 decreasing to an average of $76.63 per barrel during 2024, representing a 1% decrease. As of January 31, 2025, West Texas Intermediate 12-month strip pricing closed at 72.53 per barrel. During 2024, the number of active crude oil drilling rigs in the continental United States decreased from 500 in December 2023 to 483 in December 2024, according to Baker Hughes. Over the next several years, we expect that crude oil prices will support continued drilling activity and increasing production in the Williston Basin, Permian Basin, and given the current regulatory environment in Colorado, in rural parts of the DJ Basin 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 United States hit 6.5% in December 2022, one of the highest increases in more than three decades, as measured by the Consumer Price Index. While inflation has declined since the second half of 2022, declining to 2.9% in December 2024, further increases in inflation in 2024 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.

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.

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 is focused on the Utica Shale.

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.

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.

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

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.

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.

The following table presents certain consolidated data and volume throughput for the years ended December 31, 2024 and 2023.

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(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, 2024 and 2023.” Volumes – Gas. Natural gas throughput volumes decreased 430 MMcf/d for the year ended December 31, 2024 compared to the year ended December 31, 2023, primarily reflecting:

•a volume throughput decrease of 490 MMcf/d for the Northeast segment;

•a volume throughput decrease of 13 MMcf/d for the Piceance segment; offset by

•a volume throughput increase of 58 MMcf/d for the Mid-Con segment;

•a volume throughput increase of 15 MMcf/d for the Rockies segment.

Volumes – Liquids. Crude oil and produced water volume throughput for the Rockies segment decreased 6 Mbbl/d for the year ended December 31, 2024 compared to the year ended December 31, 2023.

For additional information on volumes, see the “Segment Overview for the Years Ended December 31, 2024 and 2023” section herein.

Revenues. Total revenues decreased $29.3 million during the year ended December 31, 2024 compared to the year ended December 31, 2023 comprised of a $47.4 million decrease in gathering services and related fees, offset by a $15.8 million increase in natural gas, NGLs and condensate sales and a $2.3 million increase in Other revenues.

Gathering services and related fees. Gathering services and related fees decreased $47.4 million compared to the year ended December 31, 2023, primarily reflecting:

•a $45.0 million decrease in the Northeast segment;

•a $7.9 million decrease in the Piceance segment;

•a $2.7 million decrease in the Rockies segment; offset by

•an $8.2 million increase in the Mid-Con segment.

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales revenue increased $15.8 million compared to the year ended December 31, 2023, primarily reflecting:

•a $16.8 million increase in the Rockies segment;

•a $0.9 million increase in the Mid-Con segment; offset by

•a $2.0 million decrease in the Piceance segment.

Costs and expenses. Total costs and expenses increased $89.3 million during the year ended December 31, 2024 compared to the year ended December 31, 2023, primarily reflecting:

General and administrative. General and administrative expense increased $13.4 million for the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily due to increased employee salaries and benefit expense, as well as professional and other expenses associated with our Corporate Reorganization.

Depreciation and amortization. Depreciation and amortization expense decreased $22.1 million for the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily due to the sale of our Mountaineer Midstream system and disposition of Summit Utica during 2024 as well as a reduction to amortization expense in connection with certain intangible assets that became fully amortized in December 2023.

Transaction costs. Transaction costs during 2024 were primarily related to the Utica Sale that closed on March 22, 2024, the Mountaineer Transaction that closed on May 1, 2024, the Tall Oak Acquisition which closed on December 2, 2024 and the costs incurred in connection with our Corporate Reorganization and strategic alternatives review.

Long-lived asset impairments. In 2024, we recognized impairments of $68.3 million primarily in connection with the Mountaineer Transaction.

Gain on sale of business. Gain on sale of business is primarily related to the gain recognized in connection with the disposition of the Utica midstream business in March of 2024.

Gain on sale of equity method investment. Gain on sale of equity method investment is related to disposition of our equity method investment Ohio Gathering in March of 2024.

Interest Expense. Interest expense decreased $25.3 million during the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily due to $27.3 million of reduced interest expense as a result of the 2026 Secured Notes Tender Offer and the 2026 Secured Notes Asset Sale Offer that occurred in July 2024 and May 2024, respectively, $16.0 million of reduced interest expense as a result of decreased borrowings on the Amended and Restated ABL Facility, $11.9 million of reduced interest expense as a result of the exchange and repurchase of $209.7 million of the 2025 Senior Notes that occurred in November 2023, partially offset by $21.4 million of increased borrowing costs on the 2029 Secured Notes issued in July 2024 and $8.9 million of increased borrowing costs on the 2026 Unsecured Notes issued in November 2023.

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. Effective August 1, 2024, we became a corporation and therefore subject to United States federal and state income taxes. Prior to this date SMLP was treated as a partnership for federal and state income tax purposes, in which SMLP’s taxable income or loss was passed through to its unitholders.

Volume throughput for our Rockies reportable segment follows.

Natural gas. Natural gas volume throughput in 2024 increased 13% compared to the year ended December 31, 2023, primarily reflecting 92 new well connections that came online during 2024, partially offset by winter related interruptions which occurred during the first quarter of 2024.

For the years ended December 31, 2024 and 2023, costs of natural gas and NGLs includes $50.6 million and $39.6 million, respectively, of gathering fees collected under percentage of proceeds arrangements.

Liquids. Liquids volume throughput in 2024 decreased 8% compared to the year ended December 31, 2023, primarily due to natural production declines, offset by 37 new well connections that came online during 2024.

Financial data for our Rockies reportable segment follows.

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Year ended December 31, 2024. Segment adjusted EBITDA increased $6.4 million compared to the year ended December 31, 2023 primarily as a result of increased natural gas throughput as described above, partially offset by a decrease in liquids throughput and lower natural gas and NGL pricing.

Volume throughput for our Permian reportable segment follows.

Volume throughput for Double E increased 88% compared to the year ended December 31, 2023.

The following table presents the MVC quantities that Double E’s shippers have contracted to with firm transportation service agreements and related negotiated rate agreements:

Financial data for our Permian reportable segment follows.

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Year ended December 31, 2024. Segment adjusted EBITDA increased $7.0 million compared to the year ended December 31, 2023 primarily as a result of an increase in proportional adjusted EBITDA from our equity method investment in Double E.

Volume throughput for our Piceance reportable segment follows.

Volume throughput decreased 4% in 2024 compared to the year ended December 31, 2023, primarily as a result of natural production declines.

Financial data for our Piceance reportable segment follows.

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Year ended December 31, 2024. Segment adjusted EBITDA decreased $7.0 million compared to the year ended December 31, 2023, primarily related to a decrease in volume throughput described above, contractual step-downs associated with MVC shortfall payments and a reduction in condensate margin.

Volume throughput for our Mid-Con reportable segment follows.

Volume throughput increased 32% compared to the year ended December 31, 2023, primarily as a result of 27 wells that came online during 2024 and the acquisition of Tall Oak in December 2024, partially offset by temporary production curtailments associated with reductions in commodity pricing.

Financial data for our Mid-Con reportable segment follows.