NYSE: SMC

•Capital structure optimization. We seek to maximize stakeholder value. Our capital structure currently consists of common equity (including the Company’s common stock and Class B common stock and associated Partnership Common Units of SMLP), preferred equity, and indebtedness that is comprised of debt securities and borrowings under our revolving credit facilities, a portion of which is secured by substantially all of our assets. We intend to optimize our capital structure in the future by reducing our indebtedness with free cash flow, and when appropriate, we may pursue opportunistic capital markets transactions, asset acquisitions (such as the Moonrise Acquisition), or asset divestitures with the objective of increasing long-term stakeholder value.

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

•Maintaining focus on fee-based revenue with minimal direct commodity price exposure. We intend to maintain our focus on providing midstream services under primarily long-term and fee-based contracts. We believe that our focus on fee-based revenues with minimal direct commodity price exposure is essential to maintaining stable cash flows.

•Maintaining strong producer relationships to maximize utilization of all of our midstream assets. We have cultivated strong producer relationships by focusing on customer service and reliable project execution and by operating our assets safely and reliably over time. We believe that our strong producer relationships will create future opportunities to expand our midstream services reach and optimize the utilization of our midstream assets for our customers.

•Continuing to prioritize safe and reliable operations. We believe that providing safe, reliable, and efficient operations is a key component of our business strategy. We place a strong emphasis on employee training, operational procedures, and enterprise technology, and we intend to continue promoting a high standard with respect to the efficiency of our operations and the safety of all of our constituents.

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Recent Developments and Highlights

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

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

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

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

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

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

Our Midstream Assets

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

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Reportable Segments. As of December 31, 2025, our reportable segments are below along with management’s categorization of the primary commodity driving customer drilling and completion decisions for each segment:

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

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

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

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

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

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

Industry Overview and Commercial Arrangements

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

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

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

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

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

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

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

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

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

Throughput and Commodity Price Exposure. Our financial results are primarily driven by volume throughput across our gathering systems and by expense management. During 2025, aggregate natural gas volume throughput averaged 904 MMcf/d and crude oil and produced water volume throughput averaged 73 Mbbl/d. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure, which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk or volatility. We also earn a portion of our revenues from the following activities that directly expose us to fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers in the Rockies, Piceance and Mid-Con segments, (ii) the sale of natural gas we retain from certain Mid-Con customers, (iii) the sale of condensate we retain from our gathering services in the Rockies, Mid-Con and Piceance segments and (iv) additional gathering fees that are tied to performance of certain commodity price indexes, which are then added to the fixed gathering rates. During the year ended December 31, 2025, these additional activities accounted for approximately 48% of total revenues.

Equity Method Investment – Double E. We have an equity method investment in the Double E Pipeline, a 1.6 Bcf/d FERC-regulated interstate natural gas transmission pipeline that commenced operations in November 2021 and provides transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha hub in Texas. We are the operator of the joint venture and have made all required capital contributions to Double E. As of December 31, 2025, the Company owns a 70% interest in Double E. A subsidiary of ExxonMobil Corporation is our joint venture partner and owns the remaining 30%.

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

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Overview of our Segments

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

Rockies.

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

Aggregate throughput capacity -

liquids (Mbbl/d)Aggregate throughput capacity -

natural gas (MMcf/d)Average daily MVCs through 2030 (MMcf/d)
Remaining MVCs (Bcfe)

Weighted-average remaining contract life (Years)

Weighted-average remaining MVC life (Years)

Rockies - Williston225n/a
n/a

n/a
7.3
n/a

Rockies - DJ (1)
1463359395.92.6

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

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

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

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

Niobrara G&P system. The Niobrara G&P system is located in rural Weld, Morgan and Logan Counties, and in Cheyenne County of Nebraska. Weld County is the largest crude oil and natural gas producing county in Colorado. Gathering and processing services on the Niobrara G&P system are provided pursuant to long-term, fee-based, and percentage of proceeds agreements with producers that are primarily targeting crude oil production from the Niobrara and Codell shale formations. As of December 31, 2025, Bison Oil and Gas IV, Chevron Corporation, SM Energy Company, Fundare and Verdad Resources are the key customers of the Niobrara G&P system and have underpinned our volume throughput with acreage dedications and MVCs.

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

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

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

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Permian.

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

Aggregate throughput capacity (MMcf/d)Average daily MVCs through 2030 (MMcf/d)Remaining MVCs (Bcf)Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years)

Double E (1)
1,6001,1152,6216.46.6

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

Double E. The Double E Pipeline is a 135 mile FERC-regulated interstate natural gas transmission pipeline that commenced operations in November 2021 and provides transportation service from receipt points in the Delaware Basin to various delivery points in and around the Waha hub in Texas. Double E is underpinned by 1.1 Bcf/d of long-term take-or-pay contracts with ExxonMobil Corporation, ConocoPhillips Company, EOG Resources Inc. and Matador Resources Company.

In 2021, we entered into negotiated rate agreements with an average term of 10 years from the in-service date of the pipeline, which occurred on November 18, 2021 and with total MDTQs that increase from 585,000 Dth/d during the first year of the agreement to 1,000,000 Dth/d in the fourth year, which equates to approximately 63% of its estimated capacity of 1,600,000 Dth/d.

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

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

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

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Mid-Con.

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

Throughput capacity (MMcf/d)Average daily MVCs through 2030 (MMcf/d)Remaining MVCs (Bcf)Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years)

Mid-Con890n/a
n/a
7.1
n/a

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

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

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

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

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

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

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

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Piceance.

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

Aggregate throughput capacity (MMcf/d)Average daily MVCs through 2030 (MMcf/d)Remaining MVCs (Bcf)Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years)

Piceance1,25926487.50.7

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

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

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

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Northeast.

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

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Our Customers

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

Regulation of the Natural Gas and Crude Oil Industries

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

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

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

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

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

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

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

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

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

Pursuant to the NGA, existing interstate natural gas transportation and storage rates and terms and conditions of service may be challenged by complaint and are subject to prospective change by FERC. Additionally, rate changes and changes to terms and conditions of service proposed by a regulated natural gas interstate pipeline may be protested and such changes can be delayed and may ultimately be rejected by FERC. FERC may also initiate reviews of an interstate pipeline’s rates. Double E currently holds authority from the FERC to charge and collect (i) “recourse rates,” which are the maximum cost-based rates an interstate natural gas pipeline may charge for its services under its tariff; (ii) “discount rates,” which are rates offered by the natural gas pipeline to shippers at discounts vis-à-vis the recourse rates and that fall within the cost-based maximum and minimum rate levels set forth in the natural gas pipeline’s tariff; and (iii) “negotiated rates,” which are rates negotiated and agreed to by the pipeline and the shipper for the contract term that may fall within or outside of the cost-based maximum and minimum rate levels set forth in the tariff and which are individually filed with the FERC for review and acceptance. When capacity is available and offered for sale, the rates (which include reservation, commodity, surcharges, and fixed fuel and lost and unaccounted for charges) and the terms and conditions at which such capacity is sold are subject to regulatory approval and oversight. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on our business, financial condition, and results of operations.

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

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

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

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

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

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

•perform ongoing assessments of pipeline integrity;

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

•maintain processes for data collection, integration and analysis;

•repair and remediate pipelines as necessary;

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

•implement preventive and mitigating actions.

In addition, PHMSA has jurisdiction over gathering systems, which includes integrity management requirements. In November 2021, PHMSA issued a final rule that extended pipeline safety requirements to onshore gas gathering pipelines. The rule requires all onshore gas gathering pipeline operators to comply with PHMSA’s incident and annual reporting requirements. It also extends existing pipeline safety requirements to a new category of gas gathering pipelines, “Type C” lines, which generally include high-pressure pipelines that are larger than 8.625 inches in diameter. Safety requirements applicable to Type C lines vary based on pipeline diameter and potential failure consequences.

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

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

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

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

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

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Environmental Matters

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

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

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

•delaying system modification or upgrades during permit reviews;

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

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

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

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

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

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

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

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

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

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

In October 2015, the EPA issued a new lower NAAQS for ozone. The previous ozone standard was set at 75 ppb. The revised standard has been lowered to 70 ppb. The lowered ozone NAAQS could subject us to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements and increased permitting delays and costs. In October 2022, the EPA reclassified the Dallas Fort Worth area as severe nonattainment under the 75 ppb standard and moderate nonattainment under the 70 ppb standard. As part of the same action, the EPA also reclassified portions of Weld County, Colorado as severe nonattainment under the 75 ppb standard. In July 2022, the EPA notified the State of Texas that it was considering redesignating an area comprising several Texas and New Mexico counties in the Permian Basin as a new ozone nonattainment area. However, the EPA deprioritized the redesignation of the Permian Basin in 2023. Such reclassifications and redesignations in areas where we operate could result in additional fees and more stringent permitting requirements for our operations, among other things. In addition, the EPA reviewed the 2015 70 ppb standard in 2020, but retained the standard without revision. Future actions to lower the standard could similarly result in additional fees or more stringent permitting.

In June 2016, the EPA finalized revisions to its 2012 New Source Performance Standard (“NSPS”) OOOO for the oil and gas industry, to reduce emissions of greenhouse gases - most notably methane - along with smog-forming VOCs. The revisions, which are published in the Federal Register under Subpart OOOOa, included the addition of methane to the pollutants covered by the rule, along with requirements for detecting and repairing leaks at gathering and boosting stations. Further, in November 2021, the EPA issued a new proposed rule targeting methane emissions from new and existing oil and gas sources. The proposed rule sought to: (1) update NSPS OOOOa; (2) adopt a new NSPS OOOOb for sources that commence construction, modification or reconstruction after the date the proposed rule is published in the Federal Register; and (3) adopt a new NSPS OOOOc to establish emissions guidelines, which will inform state plans to establish standards for existing sources. The EPA issued a supplemental proposal in November 2022 to update and expand the proposed NSPS OOOOb and OOOOc rules. This supplemental proposal sought to impose more stringent requirements and include sources not previously regulated under this source category. In December 2023, the EPA announced its final methane rules, later published on March 8, 2024, which impose several new methane emission requirements on the oil and gas industry. These increasingly stringent requirements, or the application of new requirements to existing facilities, could result in additional restrictions on operations and increased compliance costs for us or our customers. However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. In addition, in March 2025, the EPA announced that it would reconsider the final methane rules, including NSPS OOOOb and OOOOc. In December 2025, the EPA issued a final rule that extends several compliance deadlines in the 2024 NSPS and Emissions Guidelines for OOOOb and OOOOc. Consequently, future implementation and enforcement of the final rules remains uncertain at this time.

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

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

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

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

Hydraulic Fracturing. Hydraulic fracturing is an important practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations and is primarily regulated by state agencies. A number of states have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure and well construction requirements on crude oil and/or natural gas drilling activities. For example, during the 2021-2022 election cycle, Colorado representatives proposed a ballot initiative to ban hydraulic fracturing on all non-federal land, but the proposed initiative failed to garner significant support. States also could elect to prohibit hydraulic fracturing altogether, as California, New York, Maryland, Oregon, and Vermont have done. In addition, certain local governments have adopted and additional local governments may adopt, ordinances within their jurisdictions regulating the time, place, and manner of drilling activities in general or hydraulic fracturing activities in particular. These initiatives and similar efforts could restrict oil and gas development in the future.

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

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

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

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

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

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

National Environmental Policy Act. NEPA establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. Major projects requiring federal permits or involving federal funding that have the potential to significantly impact the environment require review under NEPA. Many of our activities are covered under categorical exclusions which result in an expedited NEPA review process. Large upstream and downstream projects with significant cumulative impacts may be subject to longer NEPA review processes, which could impact the timing of those projects and our services associated with them. However, in January 2025, President Trump issued an executive order requiring the White House Council on Environmental Quality (“CEQ”) to propose rescinding the NEPA regulations and provide guidance regarding promulgating consistent NEPA implementing regulations at the agency level. The executive order also instructs federal agencies to adhere to only the relevant legislated requirements for environmental reviews and to prioritize efficiency and certainty over any other objectives in such reviews. In February 2025, CEQ issued an interim final rule to withdraw the NEPA implementing regulations. In January 2026, CEQ finalized the February 2025 rule, immediately rescinding NEPA implementing regulations. The potential impact of further changes to the NEPA regulations and statutory text therefore remains uncertain and could affect our operations.

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

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

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

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

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

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

Other Information

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

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

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

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

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

Availability of Reports. We make certain filings with the SEC, including, among other filings, this annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through our website, www.summitmidstream.com, as soon as reasonably practicable after the date they are filed with, or furnished to, the SEC. We also post announcements, updates, events, investor information, and presentations on our website in addition to copies of all recent news releases. We may use the Investors section of our website to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. Documents and information on our website are not incorporated by reference herein. The SEC maintains a website that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC through the SEC’s website, https://www.sec.gov.

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