10q10k10q10k.net

What changed in Summit Midstream Corp's 10-K — 2024 vs 2025

vs

Paragraph-level year-over-year comparison of Summit Midstream Corp's 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+390 added−410 removedSource: 10-K (2026-03-16) vs 10-K (2025-03-11)

Top changes in Summit Midstream Corp's 2025 10-K

390 paragraphs added · 410 removed · 290 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

85 edited+23 added−45 removed139 unchanged
Biggest changeAs 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.
Biggest changeFor 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.
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.
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.
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.
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.
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.
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.
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.
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.
However, in January 2025, President Trump issued executive orders directing the heads of federal agencies to (i) facilitate the leasing of domestic 30 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.
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.
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.
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 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.
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 25 programs, increase penalties for safety violations and establish additional safety requirements.
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 32 investors. It is possible that the financial and other information posted there could be deemed to be material information.
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.
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.
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.
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 26 violator for violations of the anti-market manipulation sections of the CEA.
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.
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. 24 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.
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. 23 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.
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.
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.
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 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.
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. 20 Permian.
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. 19 Permian.
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.
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 2039. The AMIs generally require that any production by our customers within the AMIs will be gathered and/or processed by our assets.
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.
Although most of the state-level initiatives have to date been 31 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.
Although most of the state-level initiatives have to date been 30 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.
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. 18 Our AMIs cover approximately 5.8 million surface acres in the aggregate. Minimum Volume Commitments.
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.
Under these laws, 28 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.
Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior 27 owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.
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.
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.
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. 33
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. 31
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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 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.
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.
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.
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.
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.
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 27 or produced in our operations and that such information be provided to employees, state and local government authorities and the public.
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. 26 Environmental Matters General.
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 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.
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.
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.
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.
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 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.
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.
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. 19 Overview of our Segments The following provides an overview of our reportable segments as of December 31, 2024. Rockies.
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. 18 Overview of our Segments The following provides an overview of our reportable segments as of December 31, 2025. Rockies.
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 .
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 following table provides operating information regarding our Rockies reportable segment as of December 31, 2024.
The following table provides operating information regarding our Rockies reportable segment as of December 31, 2025.
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.
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.
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.
Our integrated assets are strategically located in production basins, including the Williston Basin, DJ Basin, Barnett Shale, Piceance Basin, Permian Basin, and the Arkoma Basin. Our primary business objective is to maximize cash flow and provide cash flow stability for our stakeholders while growing prudently and profitably.
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.
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.
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.
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 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 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.
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.
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.
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.
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.
During the year ended December 31, 2024, these additional activities accounted for approximately 45% of total revenues. Equity Method Investment – Double E.
During the year ended December 31, 2025, these additional activities accounted for approximately 48% of total revenues. Equity Method Investment – Double E.
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.
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 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.
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.
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.
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.
We place a strong emphasis on employee training, operational procedures and enterprise technology, and we intend to continue promoting a high standard with respect to the efficiency of our operations and the safety of all of our constituents. Recent Developments and Highlights The following is a brief listing of significant developments and highlights for the year ended December 31, 2024.
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. 15 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.
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. 22 Mid-Con.
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. 22 Northeast.
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.
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.
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) Piceance 1,338 64 117 8.0 1.6 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.
Aggregate throughput capacity (MMcf/d) Average daily MVCs through 2030 (MMcf/d) Remaining MVCs (Bcf) Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years) Piceance 1,259 26 48 7.5 0.7 AMIs for the Piceance reportable segment cover approximately 434,000 surface acres in the aggregate. Our Piceance reportable segment is comprised of our Grand River gathering system. Grand River system.
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 ______________________________________________ (1) Presented on a gross basis.
The following table provides operating information regarding our Permian reportable segment as of December 31, 2025. Aggregate throughput capacity (MMcf/d) Average daily MVCs through 2030 (MMcf/d) Remaining MVCs (Bcf) Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years) Double E (1) 1,600 1,115 2,621 6.4 6.6 ______________________________________________ (1) Presented on a gross basis.
We own 70% of Double E and operate the pipeline. 21 Piceance. The following table provides operating information regarding our Piceance reportable segment as of December 31, 2024.
We own 70% of Double E and operate the pipeline. 20 Mid-Con. The following table provides operating information regarding our Mid-Con reportable segment as of December 31, 2025.
Aggregate throughput capacity - liquids (Mbbl/d) Aggregate throughput capacity - natural gas (MMcf/d) Average daily MVCs through 2029 (MMcf/d) Remaining MVCs (Bcfe) Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years) Rockies - Williston 225 n/a n/a n/a 4.4 n/a Rockies - DJ (1) 50 220 7 14 7.1 3.6 ______________________________________________ (1) Capacity of 220 MMcf/d represents nameplate processing capacity.
Aggregate throughput capacity - liquids (Mbbl/d) Aggregate throughput capacity - natural gas (MMcf/d) Average daily MVCs through 2030 (MMcf/d) Remaining MVCs (Bcfe) Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years) Rockies - Williston 225 n/a n/a n/a 7.3 n/a Rockies - DJ (1) 146 335 9 39 5.9 2.6 ______________________________________________ (1) Capacity of 335 MMcf/d represents nameplate processing capacity.
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.
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.
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.
The ICA also imposes potential criminal liability for certain violations of the statute. 24 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.
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.
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.
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.
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.
FERC also has the authority to change terms and conditions of 25 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 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.
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.
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.
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.
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.
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.
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.
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.
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.
The alert discussed engineering, design, operations, and maintenance practices that the EPA found that can cause 29 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.
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.
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.
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.
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.
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. 17 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.
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.
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.
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.
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.
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.
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.
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.
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.
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. 23 Northeast.
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. 21 Piceance. The following table provides operating information regarding our Piceance reportable segment as of December 31, 2025.
The following table provides operating information regarding our Mid-Con reportable segment as of December 31, 2024. 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) Mid-Con 440 n/a n/a 7.2 n/a AMIs for the Mid-Con reportable segment cover approximately 2.9 million surface acres.
Throughput capacity (MMcf/d) Average daily MVCs through 2030 (MMcf/d) Remaining MVCs (Bcf) Weighted-average remaining contract life (Years) Weighted-average remaining MVC life (Years) Mid-Con 890 n/a 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.
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.
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.
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.
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.
Gathered natural gas volumes are then compressed, dehydrated, treated and/or processed for delivery to downstream pipelines serving end users.
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.
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.
Such regulations and restrictions could cause delays and impose additional costs and restrictions on our customers. 29 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.
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.
N atural 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.
As a result, future implementation and enforcement of the final rule remains uncertain.
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.

… 73 more changes not shown on this page.

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

87 edited+23 added−27 removed309 unchanged
Biggest changeThe 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.
Biggest changeThe 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. 48 For additional information on PHMSA regulations relating to pipeline safety, see “—A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenues to decline or our operation and maintenance expenses to increase.” Climate change legislation, regulatory initiatives, and litigation could result in increased operating costs and reduced demand for the services we provide.
The 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 43 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.
The Amended and Restated ABL Facility will mature on the earliest of (a) July 26, 2029, (b) July 31, 2029 if either (i) the outstanding amount of the 2029 Secured Notes (or any refinancing debt permitted under the Amended and Restated ABL Facility in respect thereof that has a final maturity date, scheduled amortization or any other scheduled repayment, mandatory prepayment, mandatory redemption or sinking fund obligation prior to the date that is 91 days after the Amended and Restated ABL Termination Date (provided, that the terms of such permitted refinancing debt may (x) require the payment of interest from time to time and (y) include customary mandatory redemptions, prepayments or offers to purchase with proceeds of asset sales or upon the occurrence of a change of control)) on such date equals or exceeds $50.0 million or (ii) the outstanding amount of such debt described in clause (i) above on such date is less than $50.0 million and Liquidity (as defined in the Amended and Restated ABL Agreement) at any time on or after such date is less than the sum of (A) such outstanding amount and (B) the greater of (x) 10% of the aggregate Commitments (as defined in the Amended and Restated ABL Agreement) then in effect and (y) $50.0 million (and, for the avoidance of doubt, once the Amended and Restated ABL Termination Date occurs it may not be unwound as a result of Liquidity (as defined in the Amended and Restated ABL Agreement) increasing on a subsequent date), or (c) any date on which the aggregate Commitments terminate thereunder.
(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.
(including the ongoing debates related to the U.S. federal government budget), volatility and disruption in global capital and credit markets (including those resulting from geopolitical events, such as the Russian invasion of Ukraine or ongoing conflict in the Middle East), uncertainty regarding increases or decreases in interest rates resulting from changes in the federal funds rate range targeted by the Federal Reserve, pandemics, epidemics and other outbreaks, such as COVID-19, or other adverse developments that affect financial institutions.
In 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.
For example, in January 2025, PHMSA submitted a final rule to the Federal Register to amend regulations to reduce methane emissions from new and existing gas transmission, distribution, and regulated gas gathering pipelines with strengthened leakage survey and patrolling requirements, performance standards for advanced leak detection programs, leak grading and repair criteria with mandatory repair timelines, requirements for mitigation of emissions from blowdowns, pressure relief device design, configuration, and maintenance requirements, clarified requirements for investigating failures, and expanded reporting requirements.
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.
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. 54 Our operations depend on the use of sophisticated IT and OT systems.
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.
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 38 capitalize on other attractive expansion opportunities.
The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing. 47 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.
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.
A future government shutdown could delay the receipt of any federal regulatory approvals. 40 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.
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.
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.
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 44 realize under these arrangements decrease in periods of low natural gas prices.
Any shortfall of revenue, representing the difference between “recourse 48 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.
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.
While our facilities currently are subject to limited state and local regulation, there is a risk that state or local laws will be changed or reinterpreted, which may materially affect our operations, operating costs and revenues. We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
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. 47 We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
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.
Further, absent a material change to our business, we do not expect to pay dividends on the common stock in the foreseeable future, and our outstanding indebtedness currently restricts our ability to pay cash dividends on any of our equity securities. We intend to use our cash flow to reduce debt and invest in our business.
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 45 exceeds the sum of the undiscounted cash flows expected to result from the asset’s use and eventual disposal.
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 addition, inflation may adversely affect customers’ financing costs, cash flows, and profitability, which could adversely impact their operations and our ability to offer credit and collect receivables. An increase in interest rates will cause our debt service obligations to increase.
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. 43 An increase in interest rates will cause our debt service obligations to increase.
Numerous governmental 49 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.
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.
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.
However, Congress has in the past considered, and may in the future consider, legislation to regulate hydraulic fracturing by federal agencies. Many states have 45 already adopted laws and/or regulations that require disclosure of the chemicals used in hydraulic fracturing.
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.
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 46 FERC. FERC may also initiate reviews of an interstate pipeline’s rates.
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.
New data protection laws at the federal, state, international, national, provincial, and local levels, including Colorado, Connecticut, Virginia, and Utah legislation, the GDPR and the CCPA, pose increasingly complex compliance challenges and potentially elevate our costs.
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.
Violations of the NGA or NGPA, or the rules, regulations, and orders issued by FERC thereunder could result in the imposition of administrative and criminal remedies, including without limitation, revocation of certain authorities, disgorgement of ill-gotten gains, and civil penalties of up to approximately $1.6 million per day per violation of the NGA or its implementing regulations, subject to future adjustment for inflation.
In addition, the 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; 34 • 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.
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; 32 • fluctuations in our working capital needs; • our ability to borrow funds and access the debt and equity capital markets; • restrictions contained in our debt agreements; • the amount of cash reserves established by us; • not receiving anticipated shortfall payments from our customers; • adverse legal judgments, fines and settlements; • dividends, if any, paid on our Series A Preferred Stock or on the preferred stock of our subsidiaries; and • other business risks affecting our cash levels.
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 39 populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from such events.
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 37 populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from such events.
There can be no assurance that any such efforts would be successful or would provide similar financial and operational results. 35 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.
There can be no assurance that any such efforts would be successful or would provide similar financial and operational results. 33 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.
These types of interruptions could negatively impact our ability to meet our contractual obligations to our customers and thereby give 38 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.
These 36 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.
Additionally, the lingering absence of regulatory equivalency across jurisdictions may increase compliance costs and make it more costly to satisfy regulatory obligations. 52 We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from various groups.
Additionally, the lingering absence of regulatory equivalency across jurisdictions may increase compliance costs and make it more costly to satisfy regulatory obligations. 50 We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from various groups.
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. 55 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.
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. 53 The Tall Oak Acquisition, Moonrise Acquisition, and subsequent changes in stock ownership of the Company (including upon the redemption or exchange of the shares of Class B Common Stock and associated Partnership Common Units for common stock) may trigger a limitation on the utilization of net operating loss carryforwards of the Company.
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.
In addition, a failure to comply with the provisions of the New Permian Transmission Facility, the indenture governing the 2029 Secured Notes, and the Amended and Restated ABL Facility could result in a default or an event of default that could enable our lenders and/or senior noteholders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable.
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.
In 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes (the “Endangerment Finding”).
In addition, financial institutions have begun to screen companies such as ours for sustainability performance, including practices related to 53 GHGs and climate change, before providing loans or investing in our equity securities.
In addition, financial institutions have begun to screen companies such as ours for sustainability performance, including practices related to 51 GHGs and climate change, before providing loans or investing in our equity securities.
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.
During the year ended December 31, 2025, we derived 48% of our revenues from (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers in the Rockies, Piceance and Mid-Con segments, (ii) the sale of natural gas we retain from certain Mid-Con customers, (iii) the sale of condensate we retain from our gathering services in the Rockies and Piceance segment and (iv) additional gathering fees that are tied to performance of certain commodity price indexes, which are then added to the fixed gathering rates.
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.
Although inflation in the U.S. had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021 through 2023 due to a substantial increase in money supply, a stimulative fiscal policy, a significant rebound in consumer demand as COVID-19 restrictions were relaxed, the Russia-Ukraine war and worldwide supply chain disruptions resulting from the economic contraction caused by COVID-19 and lockdowns followed by a rapid recovery.
Inflation rose from 5.4% in June 2021 to 7.0% in December 2021 to 8.2% in September 2022. While inflation has declined since the second half of 2022, declining to 2.9% 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.
Inflation rose from 5.4% in June 2021 to 7.0% in December 2021 to 8.2% in September 2022. While inflation has declined since the second half of 2022, declining to 2.7% in December 2025, further increases in inflation in 2026 could increase our labor and other operating costs and the overall cost of capital projects we undertake.
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 54 approval.
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 52 approval.
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.
We may need to raise a significant amount of capital to fund our operations and pay down outstanding indebtedness, including borrowings on the Amended and Restated ABL Facility, the New Permian Transmission Facility, and the 2029 Secured Notes, and may raise such capital through the issuance of newly issued common stock, Preferred Stock or Blank Check Common Stock.
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.
Our ability to make scheduled payments on, or to refinance, our indebtedness obligations, including the Amended and Restated ABL Facility, the New Permian Transmission Facility, and the 2029 Secured Notes, depends on our financial condition, and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control.
We have in the past and may in the future incur losses due to an impairment in the carrying value of our long-lived assets or equity method investments. We recorded long-lived asset impairments of $68.3 million during the year ended December 31, 2024 and $0.5 million in 2023.
We have in the past and may in the future incur losses due to an impairment in the carrying value of our long-lived assets or equity method investments. We recorded long-lived asset impairments of $2.7 million during the year ended December 31, 2025, $68.3 million in 2024, and $0.5 million in 2023.
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.
Depending on our customers’ future development plans, it is possible that the capital required to construct and develop such assets could exceed our ability to finance those expenditures using our cash reserves or available capacity under the Amended and Restated ABL Facility or the New Permian Transmission Facility.
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.
For example, the IRA, signed into law in August 2022, includes a Methane Emissions Reduction Program to incentivize methane emission reductions and impose a WEC on GHG emissions from certain oil and gas facilities that are already required to report under the EPA’s GHG reporting rule.
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.
The operating and financial restrictions and covenants in the New Permian Transmission Facility, the indenture governing the 2029 Secured Notes, the Amended and Restated ABL Facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities.
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.
The provisions of the New Permian Transmission Facility, the indenture governing the 2029 Secured Notes, and the Amended and Restated ABL Facility may affect our ability to obtain future financing and pursue attractive business opportunities as well as affect our flexibility in planning for, and reacting to, changes in business conditions.
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. Inflation could have adverse effects on our results of operation.
Any of these restrictions in the Amended and Restated ABL Facility, the New Permian Transmission Facility and the indenture governing the 2029 Secured Notes could materially adversely affect our business, financial condition, cash flows, and results of operations. Inflation could have adverse effects on our results of operation.
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.
Future terrorist attacks, rumors or threats of war, actual conflicts involving the U.S. or its allies, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the U.S.
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; 36 • 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.
These factors include: • worldwide economic and geopolitical conditions, including the ongoing U.S. military operation in Iran; • global or national health concerns, including the outbreak of pandemic or contagious disease, such as COVID-19, which may reduce demand for crude oil, natural gas, and NGLs because of reduced global or national economic activity; • weather conditions and seasonal trends; • the levels of domestic production and consumer demand; • the availability of imported LNG; • the ability to export LNG; • the availability of transportation and storage systems with adequate capacity; • the volatility and uncertainty of regional pricing differentials and premiums; 34 • 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.
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.
If the payment of the debt is accelerated, our assets may be insufficient to repay such debt in full, and our equity holders could experience a partial or total loss of their investment.
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.
This settlement resulted in losses amounting to $36.3 million and will be paid over five (5) to six (6) years, of which we have paid principal amounts of $28.0 million as of December 31, 2025, and requires compliance with certain conditions and terms and conditions, which may impact our results of operations or cash flows.
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.
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.
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.
While the Federal Reserve has since lowered its target range multiple times to a current target range of 3.50% to 3.75%, the timing of any potential increases or decreases remains uncertain. Borrowings under the Amended and Restated ABL Facility and the New Permian Transmission Facility bear interest at rates equal to SOFR plus margin.
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.
Similarly, the CCPA, which came into effect on January 1, 2020, and was further amended on January 1, 2023, by the CPRA, imposes specific obligations on businesses that collect personal data from California residents and provides California residents specific rights in relation to their personal data that we or our business partners collect and use.
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. 44 The Amended and Restated ABL Facility also contains covenants requiring Summit Holdings to maintain certain financial ratios and meet certain tests.
For example, the Amended and Restated ABL Facility, the New Permian Transmission Facility and the indenture governing the 2029 Secured Notes, taken together, restrict our ability to, among other things: • incur or guarantee certain additional debt; • make certain cash dividends on or redeem or repurchase certain equity securities; • make payments on certain other indebtedness; • make certain investments and acquisitions; • make certain capital expenditures; • incur certain liens or other encumbrances or permit them to exist; • enter into certain types of transactions with affiliates; • enter into sale and lease-back transactions and certain operating leases; • merge or consolidate with another company or otherwise engage in a change of control transaction; and • transfer, sell or otherwise dispose of certain assets.
The 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.
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.
General market conditions and United States or international economic factors and political events unrelated to our performance may also affect our stock price.
General market conditions and U.S. or international economic factors and political events unrelated to our performance may also affect our stock price.
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.
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.
As of December 31, 2024, the amount of accrued and unpaid dividends on the Series A Preferred Stock totaled $46.4 million.
As of December 31, 2025, the amount of accrued and unpaid dividends on the Series A Preferred Stock totaled $46.6 million.
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.
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.
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.
These “negotiated or discount rate” contracts are not generally subject to adjustment for increased costs, which could be caused by inflation or other factors relating to the specific facilities being used to perform the services and, as a result, our costs could exceed our revenues received under such contracts.
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 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. 41 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.
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. 37 Our industry is highly competitive, and increased competitive pressure could materially adversely affect our business and operating results.
If the total reserves or estimated life of the reserves connected to our gathering systems are less than we anticipate and 35 we are unable to secure additional volumes, it could have a material adverse effect on our business, results of operations and financial condition.
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.
As of December 31, 2025, we had $1.1 billion of indebtedness outstanding and the unused portion of the Amended and Restated ABL Facility totaled $385.7 million after giving effect to certain adjustments that are primarily related to the issuance of $0.8 million in outstanding but undrawn irrevocable standby letters of credit.
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 may not have sufficient available cash from operating surplus each quarter to pay the dividends to holders of our Series A Preferred Stock and common stock. We have not made a distribution on our common stock since we announced suspension of those dividends on May 3, 2020.
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.
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.
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.
The Corps published the draft EIS on September 8, 2023 and tribal and public meetings were held in November and December of 2023. A final EIS was released in December 2025.
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.
The 2029 Secured Notes will mature on October 31, 2029 and have interest payable semi-annually in arrears on each February 15 and August 15. As of December 31, 2025, $825.0 million of the 2029 Secured Notes were outstanding.
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.
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 39 unavailable to us, or only at significantly increased cost. In addition, we have established a corporate strategy intended to meet ESG-related objectives.
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.
In the first half of 2025, Cushing, Oklahoma West Texas Intermediate crude oil spot prices decreased from a monthly average of $75.74 per barrel in January 2025 to a monthly average of $63.54 per barrel in April 2025, before trending downward in the latter half of 2025 to close the year at $57.26 per barrel on December 31, 2025.
In addition, we have established a corporate strategy intended to meet 41 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.
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.
As of January 31, 2025, Henry Hub 12-month strip pricing closed at $3.04 per MMBtu.
As of January 31, 2026, Henry Hub 12-month strip pricing closed at $7.71 per MMBtu.
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.
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.
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 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.
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.
At the international level, the U.S. joined the international community at the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change in Paris, France in 2021, which resulted in the Paris Agreement, pursuant to which signatory countries agreed to nationally determine their contributions and set GHG emission reduction goals.
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.
Based on these findings, the EPA adopted regulations that, among other things, establish Prevention of Significant Deterioration construction and Title V operating permit reviews for certain large stationary sources of GHG emissions. However, in February 2026, the EPA issued a final rule rescinding the Endangerment Finding, asserting that the Endangerment Finding exceeded the agency’s statutory authority.
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. 51 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.
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 49 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.
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.
Our industry is highly competitive, and increased competitive pressure could materially adversely affect our business and operating results. We compete with other midstream companies in our areas of operations, some of which are large companies that have greater financial, managerial, and other resources than we do.
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.
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.
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.
In the first half of 2025, the Henry Hub Natural Gas Spot Price declined from a monthly average of $4.13 per MMBtu in January 2025 to a monthly average of $2.91 per MMBtu in August 2025, before trending upward in the latter months of 2025 to close the year at $4.00 per MMBtu on December 31, 2025.
Any decrease in the volumes that we gather and process could materially adversely affect our business and operating results. The customer volumes that support our business depend on the level of production from natural gas and crude oil wells connected to our systems, the production from which may be less than expected and will naturally decline over time.
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.
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.
The Company expects to pay the accrued and unpaid dividends on the Series A Preferred Stock upon satisfaction of certain notice requirements, which the Company expects to complete by March 31, 2026. Further, absent a material change to our business, we do not expect to pay dividends on the common stock in the foreseeable future.
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.
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. 42 Restrictions in the New Permian Transmission Credit Facility, the indenture governing the 2029 Secured Notes and the Amended and Restated ABL Facility could materially adversely affect our business, financial condition, results of operations and ability to make cash dividends.
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.
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.
Our operations depend on the use of IT and OT systems that could be the target of a cyberattack, including state-sponsored attacks or cyberterrorism. Cybersecurity threats present a large and growing risk to our business, as the oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain midstream activities.
Cybersecurity threats present a large and growing risk to our business as a result of the proliferation of new technologies (including artificial intelligence) thereby increasing the sophistication of cyber-attacks and the oil and gas industry becoming increasingly dependent on digital technologies to conduct day-to-day operations, including certain midstream activities.
Further, several federal governmental agencies (including the EPA) have conducted reviews and studies on the environmental aspects of hydraulic fracturing in the past.
A motion by the State of California to voluntarily dismiss the appeal was granted in September 2025. The March 2015 rule currently remains rescinded. Further, several federal governmental agencies (including the EPA) have conducted reviews and studies on the environmental aspects of hydraulic fracturing in the past.
As a result, future implementation and enforcement of the final rule remains uncertain.
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.

… 57 more changes not shown on this page.

Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

6 edited+0 added−1 removed5 unchanged
Biggest changeThe 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.
Biggest changeIn particular, our current SVP, E&O has over 10 years of experience leading IT and OT physical security and cybersecurity. The SVP, E&O is supported by critical internal positions within the Company, including but not limited to the Director of Information Technology, Vice President of Operational Technology and dedicated IT and OT resources with cybersecurity responsibilities.
The SVP, E&O is further supported by various external parties, including but not limited to cybersecurity service providers, consultants, and other third parties engaged on an as-needed basis. 57 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.
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.
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. Management of Cybersecurity Matters The Company’s management assumes executive responsibility for assessing, identifying, and managing cybersecurity risks and incidents.
The Audit Committee reports to the entire Board of Directors periodically regarding its oversight of cybersecurity matters. In developing such updates to the Board of Directors, the Audit Committee relies in large part on periodic updates from the Company’s management. Management of Cybersecurity Matters The Company’s management assumes executive responsibility for assessing, identifying, and managing cybersecurity risks and incidents.
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.
These processes include, but are not limited to: • Maintaining an updated inventory and management of digital assets; • Ensuring familiarity and compliance with cybersecurity frameworks, including the National Institute of Standards and Technology’s Cybersecurity Framework and ISO 27001; • Updating and maintaining an internal incident response plan, including conducting cybersecurity incident drills to periodically assess the adequacy of the incident response plan; • Conducting risk assessments of the Company’s cybersecurity policies, practices, and tools; • Employing appropriate antivirus, anti-malware, firewall, endpoint detection and response, backup and recovery software, multifactor authentication, virtual private network, account change monitoring, patch management, web content filter, spam filter and reporting, and vulnerability management software; • Conducting regular vulnerability scans of the Company’s digital and operational infrastructure; • Requiring employees to complete a Cybersecurity Awareness Program, which includes computer-based training; and • Reviewing and evaluating developments in the threat landscape.
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.
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. 55 The SVP, E&O holds key skills, experience, and competencies related to the management of cybersecurity matters.
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.
As of March 16, 2026, the Company’s business strategy, operations, or financial condition have not been materially affected by any cybersecurity threats or incidents.
Removed
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.

Item 2. Properties

Properties — owned and leased real estate

1 edited+0 added−0 removed5 unchanged
Biggest changeWe 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.
Biggest changeWe believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits, and licenses with the exception of certain ordinary course encumbrances and permits with governmental entities that have been applied for, but not yet issued. In addition, we lease various office spaces to support our operations. 56

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

8 edited+1 added−0 removed6 unchanged
Biggest changeFiberspar 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.
Biggest changeOn May 3, 2022, Fiberspar Corporation (“Fiberspar”) filed a petition in the District Court of Harris County, Texas alleging, before costs and interest, over $5.0 million owed but not paid for orders of pipeline product from Fiberspar. The petition asserts causes of action for breach of contract and suit on sworn account.
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.
The Consent Agreement settles a complaint brought by the NDIC in an administrative action against the Companies for alleged violations of the North Dakota Administrative Code (“NDAC”) arising from the 2015 Blacktail Release on the following terms: (i) the Companies admit to three counts of violating the NDAC; (ii) the Companies agree to follow the terms and conditions of the Consent Decree, including payment of penalty and reimbursement amounts set forth in the Consent Decree; and (iii) specified conditions in the Consent Decree regarding operation and testing of certain existing produced water pipelines shall survive until those pipelines are properly abandoned.
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.
Department of Interior, and (b) the State of North Dakota, on behalf of the North Dakota Department of Environmental Quality and the North Dakota Game and Fish Department, lodged with the U.S. District Court; (ii) a Plea Agreement with the U.S., by and through the U.S.
Attorney for the District of North Dakota, and the Environmental Crimes Section of the DOJ; and (iii) a Consent Agreement with the North Dakota Industrial Commission (together, the “Global Settlement”).
Attorney for the District of North Dakota, and the Environmental Crimes Section of the DOJ; and (iii) a Consent Agreement with the NDIC (together, the “Global Settlement”).
A civil action on the same claims had been filed by Fiberspar 58 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.
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.
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.
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 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. Item 4. Mine Safety Disclosures. Not applicable. 59 PART II
On December 6, 2021, the U.S. District Court accepted the Plea Agreement. This Global Settlement resulted in losses amounting to $36.3 million and will be paid over five to six years. As of December 31, 2025, we have paid principal amounts totaling $28.0 million and we intend to fully satisfy all monetary obligations by December 31, 2026. Item 4.
We are unable to predict the final outcome of this matter. Global Settlement.
The case is pending in the District Court of Harris County, Texas and a trial date has been set for April 2026. We are unable to predict the final outcome of this matter. Global Settlement.
Added
Mine Safety Disclosures. Not applicable. 57 PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

11 edited+9 added−3 removed5 unchanged
Biggest changeSee Note 19 - Subsequent Events to the consolidated financial statements. Subsidiary Series A Preferred Units Permian Holdco had 93,039 Subsidiary Series A Preferred Units outstanding as of December 31, 2024.
Biggest changeThe Company expects to pay the accrued and unpaid dividends on the Series A Preferred Stock upon satisfaction of certain notice requirements, which the Company expects to complete by March 31, 2026. Subsidiary Series A Preferred Units Permian Holdco had 93,039 Subsidiary Series A Preferred Units outstanding as of December 31, 2025.
Distributions on the Subsidiary Series A Preferred Units are cumulative and compounding and are payable quarterly in arrears 21 days after the quarter ending March, June, September and December of each year (each, a “Subsidiary Series A Preferred Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Subsidiary Series A Preferred Distribution Payment Date, in each case, when, as, and if declared by the board of directors of Permian Holdco out of legally available funds for such purpose.
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 58 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.
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.
Upon the consummation of the Corporate Reorganization, all accumulated and unpaid distributions on the Series A Preferred Units were deemed by the Series A Certificate of Designation to be Series A Unpaid Cash Dividends (as defined in the Series A Certificate of Designation), and any rights to accumulated and unpaid distributions on such Series A Preferred Units were discharged.
The distribution rate is 7.00% per annum of the $1,000 issue amount per outstanding Permian Holdco Subsidiary Series A Preferred Unit.
The distribution rate is 7.00% per annum of the $1,000 issue amount per outstanding Subsidiary Series A Preferred Unit.
Preferred Unit Dividends and Distributions Series A Preferred Stock The Company had 65,508 shares of Series A Preferred Stock outstanding as of December 31, 2024 and $46.4 million of accrued and unpaid dividends.
Preferred Unit Dividends and Distributions Series A Preferred Stock The Company had 65,508 shares of Series A Preferred Stock outstanding as of December 31, 2025, and $46.6 million of accrued and unpaid dividends.
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 60 contained in the Amended and Restated Limited Liability Company Agreement of Permian Holdco.
If the Subsidiary Series A Preferred Units were redeemed on December 31, 2025, the redemption amount would be $141.9 million, when considering the applicable multiple of invested capital metric and make-whole amount provisions contained in the Amended and Restated Limited Liability Company Agreement of Permian Holdco.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. Our common stock trades on the NYSE under the ticker symbol “SMC”. As of December 31, 2024, there were approximately 72 holders of our common stock and one holder of our non-economic Class B Common Stock.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. Our common stock trades on the NYSE under the ticker symbol “SMC.” As of December 31, 2025, there were approximately 70 holders of our common stock and one holder of our non-economic Class B Common Stock.
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.
Because our Series A Preferred Stock ranks senior to our common stock with respect to dividend rights, any accrued dividends on our Series A Preferred Stock must first be paid prior to the initiation of dividends to our holders of common stock. Our Board of Directors reinstated cash dividends on our Series A Preferred Stock beginning on March 14, 2025.
Issuer Purchases of Equity Securities We made no repurchases of our common stock or common units of the Partnership during the quarter or year ended December 31, 2024. Item 6. [Reserved] 61
Unregistered Sales of Equity Securities We did not sell any unregistered equity securities during the quarter or year ended December 31, 2025. Issuer Purchases of Equity Securities We made no repurchases of our common stock or common units of the Partnership during the quarter or year ended December 31, 2025.
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.
In these instances, the brokers or other nominees are included in the number of registered holders, but the underlying holders of the common stock that hold such stock in “street name” are not. During the year ended December 31, 2025, w e did not pay any dividends on our shares 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.
The Company expects to pay the accrued and unpaid dividends on the Series A Preferred Stock upon satisfaction of certain notice requirements, which the Company expects to complete by March 31, 2026. Absent a material change to our business, we do not expect to pay dividends to holders of our common stock in the foreseeable future.
Removed
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.
Added
Our Board of Directors reinstated cash dividends on our Series A Preferred Stock beginning on March 14, 2025. During the year ended December 31, 2025, we paid cash dividends totaling $13.4 million on our Series A Preferred Stock.
Removed
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.
Added
As of December 31, 2025, the amount of accrued and unpaid dividends on the Series A Preferred Stock totaled $46.6 million.
Removed
See Note 12 - Equity and Mezzanine Equity to the consolidated financial statements for additional details. Unregistered Sales of Equity Securities 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.
Added
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.
Added
During the year ended December 31, 2025, cash dividend payments totaling $13.4 million were paid. In March 2026, the Company’s Board of Directors approved the payment of any and all accrued and unpaid dividends on the Company’s Series A Preferred Stock, including the $46.6 million of accrued and unpaid dividends outstanding as of December 31, 2025.
Added
The use of proceeds from the New Permian Transmission Facility will be used to, among other things, redeem in full the Subsidiary Series A Preferred Units. See “Part II Item 9 B. Other Information” and Note 12 - Equity and Mezzanine Equity to the consolidated financial statements for additional details.
Added
STOCK PERFORMANCE GRAPH The following graph compares, for the last five years, the performance of our common stock to the S&P 500 Index and our peer group. The chart assumes that the value of our investment in our common stock and each index was $100 as of December 31, 2020, and that all dividends were reinvested.
Added
The stock performance shown on the graph below is not indicative of future price performance. Our peer group consists of the following: 59 Antero Midstream Corporation Archrock, Inc. Delek Logistics Partners, LP DT Midstream, Inc. Excelerate Energy, Inc. Enerflex Ltd. Enterprise Products Partners L.P. Energy Transfer, L.P. Gibson Energy Inc. Genesis Energy, LP Hess Midstream LP Kodiak Gas Services, Inc.
Added
Kinder Morgan, Inc. Kinetik Holdings Inc. Cheniere Energy, Inc. MPLX LP New Fortress Energy Inc. NGL Energy Partners LP Oil States International Inc. ONEOK, Inc. Plains All American Pipeline, L.P. Targa Resources Corp. USA Compression Partners, LP Western Midstream Partners, LP The Williams Companies, Inc. Select Water Solutions, Inc.
Added
The information in this Form 10-K appearing under the heading “Stock Performance Graph” is being “furnished” pursuant to Item 2.01(e) of Regulation S-K under the Securities Act and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act of the Exchange Act except to the extent that we specifically request that it be treated as such.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

89 edited+44 added−44 removed57 unchanged
Biggest changeYear 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. 63 Key Matters for the Year ended December 31, 2024.
Biggest changeYear ended December 31, 2025 2024 2023 (In thousands) Net loss $ (1,906) $ (113,175) $ (38,947) Reportable Segment Adjusted EBITDA Rockies $ 106,935 $ 93,827 $ 87,390 Permian 33,980 31,227 24,207 Mid-Con 92,377 30,645 26,171 Piceance 44,774 52,704 59,749 Northeast — 30,634 94,249 Net cash provided by operating activities $ 133,595 $ 61,771 $ 126,906 Net cash provided by (used in) select investing activities: Capital expenditures (1) 89,042 53,611 68,905 Investment in Double E equity method investee 3,816 3,880 3,500 Cash consideration paid for Moonrise Acquisition, net of cash acquired (69,997) — — Cash consideration paid for Tall Oak Acquisition, net of cash acquired — (154,154) — Proceeds from Utica Sale (excluding Ohio Gathering) — 292,266 — Proceeds from sale of Ohio Gathering — 332,734 — Proceeds from Mountaineer Transaction — 69,304 — Net cash provided by (used in) select financing activities: Issuance of Additional 2029 Secured Notes 258,438 — — Borrowings on Amended and Restated ABL Facility 133,000 305,000 70,000 Debt repayments - ABL Facility (325,000) (313,000) (87,000) Debt repayments - Permian Transmission Term Loan (12,324) (15,524) (10,507) Distribution on Series A Preferred Shares (13,393) — — Distributions on Subsidiary Series A Preferred Shares (6,513) (6,513) (6,512) Issuance of 2029 Secured Notes — 565,800 — Debt repayments - Redemption of 2026 Unsecured Notes — (209,510) — Debt repayments - 2026 Secured Notes (Excess Cash Flow Offer) — (13,626) — Debt repayments - 2026 Secured Notes (2026 Secured Notes Asset Sale Offer) — (6,910) — Debt repayments - 2025 Senior Notes Redemption — (49,783) — Debt repayments - 2026 Secured Notes Redemption — (764,464) — Debt repayments - Repurchase of 2025 Senior Notes — — (29,650) Issuance of 2026 Unsecured Notes — — 29,480 ________________________________ (1) See “Liquidity and Capital Resources” herein and Note 18 - Segment Information to the consolidated financial statements for additional information on capital expenditures. 62 Key Matters for the Year ended December 31, 2025.
In connection with the consummation of the Corporate Reorganization, the Partnership Agreement was amended to, among other things, reflect that all of the issued and outstanding limited partnership interests of the Partnership are held by Summit Midstream Corporation. For information on the Corporate Reorganization, see Note 1 - Organization, Business Operations, Corporate Reorganization and Presentation and Consolidation.
In connection with the consummation of the Corporate Reorganization, the Partnership Agreement was amended to, among other things, reflect that all of the issued and outstanding limited partnership interests of the Partnership are held by Summit Midstream Corporation. For information on the Corporate Reorganization, see Note 1 - Organization, Corporate Reorganization, Business Operations and Presentation and Consolidation.
As of December 31, 2024, 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.
As of December 31, 2025, the Amended and Restated ABL Facility will mature on the earliest of (a) July 26, 2029, (b) July 31, 2029 if either (i) the outstanding amount of the 2029 Secured Notes (or any refinancing debt permitted under the Amended and Restated ABL Facility in respect thereof that has a final maturity date, scheduled amortization or any other scheduled repayment, mandatory prepayment, mandatory redemption or sinking fund obligation prior to the date that is 91 days after the Amended and Restated ABL Termination Date (provided, that the terms of such permitted refinancing debt may (x) require the payment of interest from time to time and (y) include customary mandatory redemptions, prepayments or offers to purchase with proceeds of asset sales or upon the occurrence of a change of control)) on such date equals or exceeds $50.0 million or (ii) the outstanding amount of such debt described in clause (i) above on such date is less than $50.0 million and Liquidity (as defined in the Amended and Restated ABL Agreement) at any time on or after such date is less than the sum of (A) such outstanding amount and (B) the greater of (x) 10% of the aggregate Commitments (as defined in the Amended and Restated ABL Agreement) then in effect and (y) $50.0 million (and, for the avoidance of doubt, once the Amended and Restated ABL Termination Date occurs it may not be unwound as a result of Liquidity (as defined in the Amended and Restated ABL Agreement) increasing on a subsequent date), or (c) any date on which the aggregate Commitments terminate thereunder.
Management estimates the fair value of assets and liabilities based upon quoted market prices, the carrying value of the acquired assets and widely accepted valuation techniques, including discounted cash flows and market multiple analysis. Unanticipated events or circumstances may occur which could affect the accuracy of our fair value estimates, including assumptions regarding industry economic factors and business strategies.
Management estimates the fair value of assets and liabilities based upon quoted market prices, the carrying value of the acquired assets and widely accepted valuation techniques, 83 including discounted cash flows, and market multiple analysis. Unanticipated events or circumstances may occur which could affect the accuracy of our fair value estimates, including assumptions regarding industry economic factors and business strategies.
Credit and Counterparty Concentration Risks We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. Certain of our customers may be temporarily unable to meet their current obligations.
Credit and Counterparty Concentration Risks We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits, and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. 82 Certain of our customers may be temporarily unable to meet their current obligations.
Interest expense does not include the impact of gains or losses from our interest rate swaps entered into for the Permian Transmission Credit Facilities. 79 Liquidity and Capital Resources We rely primarily on internally generated cash flows as well as current cash balance and external financing sources, including commercial bank borrowings, and the issuance of debt, equity and preferred equity securities, and proceeds from potential asset divestitures to fund our capital expenditures.
Interest expense does not include the impact of gains or losses from our interest rate swaps entered into for the Permian Transmission Credit Facilities. 78 Liquidity and Capital Resources We rely primarily on internally generated cash flows as well as our current cash balance and external financing sources, including commercial bank borrowings, the issuance of debt, equity, and preferred equity securities, and proceeds from potential asset divestitures, to fund our capital expenditures.
With the divestiture of Ohio Gathering in March 2024, proportional adjusted EBITDA includes financial results from December 1, 2023 through March 22, 2024 ($2.5 million for March 1, 2024 - March 22, 2024). Year ended December 31, 2024 .
With the divestiture of Ohio Gathering in March 2024, Proportional Adjusted EBITDA includes financial results from December 1, 2023 through March 22, 2024 ($2.5 million for March 1, 2024 - March 22, 2024). Year ended December 31, 2025 .
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. 67 How We Evaluate Our Operations We currently conduct and report our operations in the midstream energy industry through four reportable segments: Rockies, Permian, Piceance and Mid-Con.
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. 65 How We Evaluate Our Operations We currently conduct and report our operations in the midstream energy industry through four reportable segments: Rockies, Permian, Piceance, and Mid-Con.
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.
As a result, the following discussion for the year ended December 31, 2025 should be read in conjunction with the consolidated financial statements and notes thereto included in this Annual Report. Among other things, the consolidated financial statements and the related notes include more detailed information regarding the basis of presentation for the following information.
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. 62 The following table presents certain consolidated and reportable segment financial data.
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. 61 The following table presents certain consolidated and reportable segment financial data.
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.
During the year ended December 31, 2024, we divested of our Northeast operations, which consisted of midstream assets located in the Marcellus shale play and midstream assets located in the Utica shale play together with our equity method investment in Ohio Gathering that was focused on the Utica Shale.
There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. We are in compliance with all covenants contained in the indenture governing the 2029 Secured Notes, the Amended and Restated ABL Facility and the Permian Transmission Credit Facilities.
There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. We are in compliance with all covenants contained in the indenture governing the 2029 Secured Notes, the Amended and Restated ABL Facility and the New Permian Transmission Facility.
Cash flows used in investing activities during the year ended December 31, 2024 primarily reflected: • $332.7 million of cash inflows from the proceeds of the sale Ohio Gathering; • $292.3 million of cash inflows from the proceeds of the Utica Sale (excluding Ohio Gathering); • $69.3 million of cash inflows from the proceeds of the Mountaineer Transaction; • $4.4 million of cash inflows from the sale of compressor equipment; partially offset by • $154.2 million of cash outflows from the Tall Oak Acquisition; and • $53.6 million of cash outflows for capital expenditures.
Investing activity cash flows during the year ended December 31, 2024 primarily reflected: • $332.7 million of cash inflows from the proceeds of the sale Ohio Gathering; • $292.3 million of cash inflows from the proceeds of the Utica Sale (excluding Ohio Gathering); • $69.3 million of cash inflows from the proceeds of the Mountaineer Transaction; • $4.4 million of cash inflows from the sale of compressor equipment; partially offset by • $154.2 million of cash outflows from the Tall Oak Acquisition; and • $53.6 million of cash outflows for capital expenditures.
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.
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.
Overview We are a value-oriented company focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental United States. Our financial results are driven primarily by volume throughput across our gathering systems and by expense management.
Overview We are a value-oriented company focused on developing, owning, and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental U.S. Our financial results are driven primarily by volume throughput across our gathering systems and by expense management.
Segment adjusted EBITDA decreased $63.6 million compared to the year ended December 31, 2023, primarily as the result of the sale of our Mountaineer Midstream system and the disposition of Summit Utica, the owner of our previously owned equity method investment, Ohio Gathering. 78 Corporate and Other Overview for the Years Ended December 31, 2024 and 2023 Corporate and Other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, transaction costs, acquisition integration costs, interest expense and losses on early extinguishment of debt.
Segment Adjusted EBITDA decreased $30.6 million compared to the year ended December 31, 2024, as the result of the sale of our Mountaineer Midstream system and the disposition of Summit Utica, the owner of our previously owned equity method investment, Ohio Gathering. 77 Corporate and Other Overview for the Years Ended December 31, 2025 and 2024 Corporate and Other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, transaction costs, acquisition integration costs, interest expense, and losses on early extinguishment of debt.
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.
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. 64 Capital markets availability and cost of capital.
Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period. 83 Critical Accounting Estimates The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.
Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period. Critical Accounting Estimates The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the U.S.
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.
Despite these decreases, over the next several years we expect natural gas prices will continue to support continued upstream industry activity by producers focused on natural gas production. In addition, certain of our gathering systems are directly affected by crude oil supply and demand dynamics.
The 2029 Secured Notes mature on October 31, 2029 and have interest payable semi-annually in arrears on each February 15 and August 15. As of December 31, 2024, the outstanding balance of the 2029 Secured Notes was $575.0 million, and we subsequently issued an additional $250.0 million of the 2029 Secured Notes on January 10, 2025.
On January 10, 2025, we issued an additional $250.0 million of the 2029 Secured Notes. The 2029 Secured Notes mature on October 31, 2029 and have interest payable semi-annually in arrears on each February 15 and August 15. As of December 31, 2025, the outstanding balance of the 2029 Secured Notes was $825.0 million. Other.
Due to the imprecise nature of the projections and assumptions utilized in determining fair value, actual results can and often do, differ from our estimates. As of December 31, 2024, we had net property, plant and equipment with a carrying value of approximately $1.8 billion and net intangible assets with a carrying value of approximately $154.3 million.
Due to the imprecise nature of the projections and assumptions utilized in determining fair value, actual results can and often do, differ from our estimates. As of December 31, 2025, we had net property, plant and equipment with a carrying value of approximately $1.8 billion and net intangible assets with a carrying value of approximately $153.6 million.
As of December 31, 2024, our material off-balance sheet arrangements and transactions include (i) letters of credit outstanding against our Amended and Restated ABL Facility aggregating to $0.8 million and (ii) letters of credit outstanding against our Permian Transmission Credit Facilities aggregating to $10.5 million.
As of December 31, 2025, our material off-balance sheet arrangements and transactions include (i) letters of credit outstanding against our Amended and Restated ABL Facility aggregating to $0.8 million and (ii) letters of credit outstanding against our Permian Transmission Credit Facilities aggregating to $13.0 million.
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 inflation has declined since the second half of 2022, declining to 2.7% in December 2025, further increases in inflation in 2026 could increase our operating costs and the overall cost of capital projects we undertake.
Northeast Year ended December 31, 2024 2023 Percentage Change Average daily throughput (MMcf/d) 202 692 (71)% Average daily throughput (MMcf/d) (Ohio Gathering) 212 779 (73)% On March 22, 2024, we completed the disposition of Summit Utica, the owner of our previously owned equity method investment, Ohio Gathering, and on May 1, 2024, we completed the disposition of our Mountaineer Midstream system.
Northeast Year ended December 31, 2025 2024 Percentage Change Average daily throughput (MMcf/d) — 202 (100)% Average daily throughput (MMcf/d) (Ohio Gathering) — 212 (100)% On March 22, 2024, we completed the disposition of Summit Utica, the owner of our previously owned equity method investment, Ohio Gathering, and on May 1, 2024, we completed the disposition of our Mountaineer Midstream system.
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.
We believe that our current cash balance, internally generated cash flow, our Amended and Restated ABL Facility, the New Permian Transmission Facility and access to debt or equity capital markets will be adequate to finance our strategic initiatives.
For additional information, see the Northeast and Permian sections herein under the caption “Segment Overview for the Years Ended December 31, 2024 and 2023.” 70 Volumes – Gas.
For additional information, see the Northeast and Permian sections herein under the caption “Segment Overview for the Years Ended December 31, 2025 and 2024.” 68 Volumes – Gas.
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.
Natural Gas, NGLs and Condensate Sales . Natural gas, NGLs and condensate sales revenue increased $70.0 million compared to the year ended December 31, 2024, primarily reflecting: • a $53.9 million increase in the Rockies segment; • a $16.8 million increase in the Mid-Con segment; offset by • a $0.7 million decrease in the Piceance segment. Costs and expenses.
Piceance Year ended December 31, 2024 2023 Percentage Change Aggregate average daily throughput (MMcf/d) 291 304 (4%) 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.
Piceance Year ended December 31, 2025 2024 Percentage Change Aggregate average daily throughput (MMcf/d) 258 291 (11%) Volume throughput for the year ended December 31, 2025 decreased 11% compared to the year ended December 31, 2024, primarily as a result of natural production declines. Financial data for our Piceance reportable segment follows.
Trends and Outlook Our business has been, and we expect our future business to continue to be, affected by the following key trends: • Ongoing impact of political and economic conditions and events in foreign oil and natural gas producing countries on commodity prices, including the 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.
Trends and Outlook Our business has been, and we expect our future business to continue to be, affected by the following key trends: • Ongoing impact of political and economic conditions and events in foreign oil and natural gas producing countries on commodity prices, including the ongoing U.S. military operation in Iran, the current Russia-Ukraine conflict, international sanctions against Russia, the U.S. military operation in Venezuela, and other sustained military campaigns; • Natural gas, NGL and crude oil supply and demand dynamics; • Actions of OPEC and its allies, including the ability and willingness of the members of OPEC and other exporting nations to agree to and maintain oil price and production controls; • Production from U.S. shale plays; • Capital markets availability and cost of capital; and • Inflation and shifts in operating costs. 63 Our expectations are based on assumptions made by us and information currently available to us.
For additional information on our reportable segments, see the “Segment Overview for the Years Ended December 31, 2024 and 2023” section herein.
For additional information on our reportable segments, see the “Segment Overview for the Years Ended December 31, 2025 and 2024” section herein.
During the year ended December 31, 2024, these additional activities accounted for approximately 45% of our total revenues.
During the year ended December 31, 2025, these additional activities accounted for approximately 48% of our total revenues.
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.
Volumes – Liquids. Crude oil and produced water volume throughput for the Rockies segment increased 1 Mbbl/d for the year ended December 31, 2025 compared to the year ended December 31, 2024. For additional information on volumes, see the “Segment Overview for the Years Ended December 31, 2025 and 2024” section herein. Revenues.
Cash flows used in financing activities during the year ended December 31, 2024 primarily reflected: • $764.5 million of cash outflows for the 2026 Secured Notes Tender Offer and redemption of 2026 Secured Notes; • $313.0 million of cash outflows for repayments on the Amended and Restated ABL Facility; • $209.5 million of cash outflows from the redemption of 2026 Unsecured Notes; • $49.8 million of cash outflows from the redemption of 2025 Senior Notes; • $23.8 million of cash outflows for debt extinguishment costs; • $15.5 million of cash outflows for repayments on the Permian Transmission Term Loan; • $13.6 million of cash outflows for the Excess Cash Flow Offer; • $6.9 million of cash outflows for the 2026 Secured Notes Asset Sale Offer; offset by • $565.8 million of cash inflows from the issuance of the 2029 Secured Notes; • $305.0 million of cash inflows from borrowings on the Amended and Restated ABL Facility.
Financing activity cash flows during the year ended December 31, 2024 primarily reflected: • $764.5 million of cash outflows for the 2026 Secured Notes Tender Offer and redemption of 2026 Secured Notes; • $313.0 million of cash outflows for repayments on the Amended and Restated ABL Facility; • $209.5 million of cash outflows from the redemption of 2026 Unsecured Notes; • $49.8 million of cash outflows from the redemption of 2025 Senior Notes; • $23.8 million of cash outflows for debt extinguishment costs; • $15.5 million of cash outflows for repayments on the Permian Transmission Term Loan; • $13.6 million of cash outflows for the Excess Cash Flow Offer; • $6.9 million of cash outflows for the 2026 Secured Notes Asset Sale Offer; offset by • $565.8 million of cash inflows from the issuance of the 2029 Secured Notes; and • $305.0 million of cash inflows from borrowings on the Amended and Restated ABL Facility. 81 Contractual Obligations Update The Company’s cash flows generated from operations are the primary source for funding various contractual obligations.
We estimate that our 2025 capital program will range from $65.0 million to $75.0 million, including between $15.0 million and $20.0 million of maintenance capital expenditures. We estimate that we will make an additional investment in our Double E equity method investee of approximately $5.0 million.
We estimate that our 2026 capital program will range from $85.0 million to $105.0 million, including between $15.0 million and $20.0 million of maintenance capital expenditures. We estimate that we will make an additional investment in our Double E equity method investee of approximately $35.0 million.
Northeast Year ended December 31, 2024 2023 Percentage Change Revenues: (Dollars in thousands) Gathering services and related fees $ 18,851 $ 63,805 (70)% Total revenues 18,851 63,805 (70)% Costs and expenses: Operation and maintenance 2,259 8,862 (75%) General and administrative 220 867 (75)% Depreciation and amortization 4,248 17,856 (76)% Gain on asset sales, net (21) (7) 200% Long-lived asset impairment 67,916 — N/A Total costs and expenses 74,622 27,578 171% Add: Depreciation and amortization 4,248 17,856 Adjustments related to capital reimbursement activity (20) (81) Gain on asset sales, net (21) (7) Long-lived asset impairment 67,916 — Proportional adjusted EBITDA for Ohio Gathering (1) 14,282 40,125 Other — 129 Segment adjusted EBITDA $ 30,634 $ 94,249 (67%) _________________ * Not considered meaningful (1) SMLP recorded its financial results of its investment in Ohio Gathering on a one-month lag based on financial information available to us during the reporting period.
Northeast Year ended December 31, 2025 2024 Percentage Change Revenues: (Dollars in thousands) Gathering services and related fees $ — $ 18,851 (100)% Total revenues — 18,851 (100)% Costs and expenses: Operation and maintenance — 2,259 (100%) General and administrative — 220 (100)% Depreciation and amortization — 4,248 (100)% Gain on asset sales, net — (21) (100)% Long-lived asset impairment — 67,916 N/A Total costs and expenses — 74,622 (100%) Add: Depreciation and amortization — 4,248 Adjustments related to capital reimbursement activity — (20) Gain on asset sales, net — (21) Long-lived asset impairment — 67,916 Proportional Adjusted EBITDA for Ohio Gathering (1) — 14,282 Other — — Segment Adjusted EBITDA $ — $ 30,634 (100%) _________________ * Not considered meaningful (1) SMLP recorded its financial results of its investment in Ohio Gathering on a one-month lag based on financial information available to us during the reporting period.
Gain on sale of equity method investment is related to disposition of our equity method investment Ohio Gathering in March of 2024. Interest Expense .
In 2024, we recognized a gain on sale of equity method investment related to the disposition of our equity method investment, Ohio Gathering, in March of 2024. Interest Expense .
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 .
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 .
Details of cash flows from operating activities follow. Cash flows from operating activities for the year ended December 31, 2024, primarily reflected: • a net loss of $113.2 million plus adjustments of $192.9 million for non-cash items; and • a $18.0 million change in working capital accounts.
Operating activity cash flows during the year ended December 31, 2024 primarily reflected: 80 • a net loss of $113.2 million plus adjustments of $192.9 million for non-cash items; and • a $18.0 million outflow due to changes in working capital accounts. Investing activities. Details of investing cash flows follow.
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.
Crude oil prices decreased in 2025, with the average daily Cushing, Oklahoma West Texas Intermediate crude oil spot price average of $76.63 per barrel during 2024 decreasing to an average of $65.39 per barrel during 2025, representing a 15% decrease. As of January 31, 2026, West Texas Intermediate 12-month strip pricing closed at $60.26 per barrel.
Mid-Con Year ended December 31, 2024 2023 Percentage Change Average daily throughput (MMcf/d) 241 183 32% 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.
Mid-Con Year ended December 31, 2025 2024 Percentage Change Average daily throughput (MMcf/d) 497 241 106% Volume throughput increased 106% for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily as a result of the Tall Oak Acquisition, 38 wells that came online during 2025, and the resumption of previous production curtailments associated with reductions in commodity pricing, partially offset by natural production declines.
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.
Although we operate solely in the U.S., certain events and conditions in foreign oil and natural gas producing countries, such as the ongoing U.S. military operation in Iran, Russia’s invasion of Ukraine, and the recent change in Venezuela’s political leadership, could have potential effects on us, including, but not limited to, volatility in currencies and commodity prices, higher inflation, cost and supply chain pressures and availability and disruptions in banking systems and capital markets.
See Note 19 - Subsequent Events to the consolidated financial statements for additional information. 80 Amended and Restated ABL Facility. Concurrently with the issuance of the 2029 Secured Notes, on July 26, 2024, Summit Holdings, as borrower, amended and restated its existing first-lien, senior secured credit agreement, with SMLP, consisting of a $500.0 million asset-based revolving credit facility.
Concurrently with the issuance of the 2029 Secured Notes, on July 26, 2024, Summit Holdings, as borrower, amended and restated its existing first-lien, senior secured credit agreement, with SMLP, consisting of a $500.0 million asset-based revolving credit facility.
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.
During 2025, the number of active crude oil drilling rigs in the continental U.S. decreased from 483 in December 2024 to 412 in December 2025, according to Baker Hughes.
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 .
General and administrative expense increased $5.5 million for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily due to increased employee salaries and benefit expense, as well as certain professional and other expenses associated with acquisition diligence costs. Depreciation and amortization .
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.
Gathering services and related fees increased $54.8 million compared to the year ended December 31, 2024, primarily reflecting: • a $85.9 million increase in the Mid-Con segment; offset by • a $18.9 million decrease in the Northeast segment; • a $11.7 million decrease in the Piceance segment; • a $0.5 million decrease in the Rockies segment.
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. 75 Piceance. Volume throughput for our Piceance reportable segment follows.
Segment Adjusted EBITDA increased $2.8 million compared to the year ended December 31, 2024 primarily as a result of an increase in Proportional Adjusted EBITDA from our equity method investment in Double E due to increased volumes described above. 74 Mid-Con. Volume throughput for our Mid-Con reportable segment follows.
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.
Natural gas throughput volumes increased 42 MMcf/d for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily reflecting: • a volume throughput increase of 21 MMcf/d for the Rockies segment; • a volume throughput increase of 256 MMcf/d for the Mid-Con segment; offset by • a volume throughput decrease of 33 MMcf/d for the Piceance segment; • a volume throughput decrease of 202 MMcf/d for the Northeast segment.
General and administrative expense attributable to Corporate and Other increased by $13.5 million compared to the year ended December 31, 2023, primarily due to increased employee salaries and benefit expense, as well as certain professional and other expenses associated with our Corporate Reorganization. Interest Expense .
For the year ended December 31, 2025, general and administrative expense attributable to Corporate and Other increased by $3.0 million compared to the year ended December 31, 2024, primarily due to increased employee salaries and benefit expense, as well as certain professional and other expenses associated with the evaluation of acquisitions.
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 .
Loss on early extinguishment of debt in 2024 is primarily related to amortization of debt issuance costs in connection with extinguishments of our 2026 Unsecured Notes, 2026 Secured Notes and 2025 Senior Notes. Income taxes . For the year ended December 31, 2025, the Company recorded an income tax benefit of $0.5 million.
Rockies Year ended December 31, 2024 2023 Percentage Change Aggregate average daily throughput - natural gas (MMcf/d) 128 113 13% Aggregate average daily throughput - liquids (Mbbl/d) 72 78 (8)% Natural gas .
Rockies Year ended December 31, 2025 2024 Percentage Change Aggregate average daily throughput - natural gas (MMcf/d) 149 128 16% Aggregate average daily throughput - liquids (Mbbl/d) 73 72 1% Natural gas .
For the year ended December 31, 2024, cash paid for capital expenditures totaled $53.6 million which included $11.7 million of maintenance capital expenditures. For the year ended December 31, 2024, we contributed $3.9 million to Double E.
For the year ended December 31, 2025, cash paid for capital expenditures totaled $89.0 million which included $17.3 million of maintenance capital expenditures. For the year ended December 31, 2025, we contributed $3.8 million to Double E.
Cash Flows Year ended December 31, 2024 2023 (In thousands) Net cash provided by operating activities $ 61,771 $ 126,906 Net cash provided by (used in) investing activities 487,059 (74,756) Net cash used in financing activities (540,276) (49,036) Net change in cash, cash equivalents and restricted cash $ 8,554 $ 3,114 The components of the net change in cash, cash equivalents and restricted cash were as follows: Operating activities.
Cash Flows Year ended December 31, 2025 2024 (In thousands) Net cash provided by operating activities $ 133,595 $ 61,771 Net cash provided by (used in) investing activities (163,150) 487,059 Net cash provided by (used in) financing activities 24,035 (540,276) Net change in cash, cash equivalents, and restricted cash $ (5,520) $ 8,554 The components of the net change in cash, cash equivalents and restricted cash were as follows: Operating activities.
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.
During 2025, the number of active natural gas drilling rigs in the continental U.S. increased from 102 in December 2024 to 125 in December 2025, according to Baker Hughes.
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 .
In 2024, we recognized a gain on sale of business primarily in connection with the disposition of the Utica midstream business in March of 2024. 69 Gain on sale of equity method investment .
Mid-Con Year ended December 31, 2024 2023 Percentage Change (Dollars in thousands) Revenues: Gathering services and related fees $ 45,659 $ 37,508 22% Natural gas, NGLs and condensate sales 1,717 778 121% Other revenues (1) 9,515 6,831 39% Total revenues 56,891 45,117 26% Costs and expenses: Cost of natural gas and NGLs 129 — * Operation and maintenance 24,366 18,255 33% General and administrative 1,349 1,299 * Depreciation and amortization 16,767 15,233 * Integration costs 39 — * Gain on asset sales, net — (73) (100%) Total costs and expenses 42,650 34,714 23% Add: Depreciation and amortization (1) 17,705 16,171 Integration costs 39 — Adjustments related to capital reimbursement activity (1,340) (1,316) Gain on asset sales, net — (73) Other — 986 Segment adjusted EBITDA $ 30,645 $ 26,171 17% _________________ *Not considered meaningful (1) Includes the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues.
Mid-Con Year ended December 31, 2025 2024 Percentage Change (Dollars in thousands) Revenues: Gathering services and related fees $ 131,538 $ 45,659 188% Natural gas, NGLs and condensate sales 18,554 1,717 981% Other revenues (1) 9,140 9,515 (4%) Total revenues 159,232 56,891 180% Costs and expenses: Cost of natural gas and NGLs 9 129 * Operation and maintenance 63,676 24,366 161% General and administrative 2,316 1,349 72% Depreciation and amortization 33,389 16,767 99% Transaction costs 16 — * Integration costs 2,665 39 * Gain on asset sales, net (195) — * Total costs and expenses 101,876 42,650 139% Add: Depreciation and amortization (1) 34,327 17,705 Transaction costs 16 — Integration costs 2,665 39 Adjustments related to capital reimbursement activity (1,847) (1,340) Gain on asset sales, net (195) — Other 55 — Segment Adjusted EBITDA $ 92,377 $ 30,645 201% _________________ *Not considered meaningful (1) Includes the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues.
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.
Liquids volume throughput for the year ended December 31, 2025 increased 1% compared to the year ended December 31, 2024, primarily reflecting 11 new well connections that came online during 2025 and additional throughput associated with the Moonrise Acquisition, partially offset by natural production declines. Financial data for our Rockies reportable segment follows.
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: Weighted average MVC quantities for the year ended December 31, (MMBTU/day) 2025 1,068,630 2026 1,115,000 2027 1,115,000 2028 1,115,000 2029 1,115,000 2030 1,115,000 2031 1,009,521 2032 240,000 2033 240,000 2034 105,753 2035 9,863 Financial data for our Permian reportable segment follows.
Weighted average MVC quantities for the year ended December 31, (MMBtu/day) 2026 1,115,000 2027 1,115,000 2028 1,115,000 2029 1,115,000 2030 1,115,000 2031 1,009,521 2032 240,000 2033 240,000 2034 105,753 2035 9,863 Financial data for our Permian reportable segment follows.
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.
As of the date of filing, there have been no material impacts to us. Natural gas, NGL and crude oil supply and demand dynamics. Natural gas continues to be a critical component of energy supply and demand in the U.S. The average spot price of natural gas increased by approximately 61% from 2024 to 2025, primarily due to increasing demand.
The average 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.
The average daily Henry Hub Natural Gas Spot Price was $3.52 per MMBtu during 2025, compared with $2.19 per MMBtu during 2024. As of January 31, 2026, Henry Hub 12-month strip pricing closed at $7.71 per MMBtu.
Permian Year ended December 31, 2024 2023 Percentage Change (Dollars in thousands) Revenues: Other revenues $ 3,641 $ 3,570 2% Total revenues 3,641 3,570 2% Costs and expenses: General and administrative 169 308 (45%) Transaction costs — 75 * Total costs and expenses 169 383 (56%) Add: Transaction costs — 75 Proportional adjusted EBITDA for Double E 27,755 20,945 Segment adjusted EBITDA $ 31,227 $ 24,207 29% _________________ * Not considered meaningful Year ended December 31, 2024 .
Permian Year ended December 31, 2025 2024 Percentage Change (Dollars in thousands) Revenues: Other revenues $ 3,641 $ 3,641 —% Total revenues 3,641 3,641 —% Costs and expenses: General and administrative 197 169 17% Transaction costs 27 — * Total costs and expenses 224 169 33% Add: Transaction costs 27 — Proportional Adjusted EBITDA for Double E 30,536 27,755 Segment Adjusted EBITDA $ 33,980 $ 31,227 9% _________________ * Not considered meaningful 73 Year ended December 31, 2025 .
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.
The following is a brief listing of significant developments and highlights for the fiscal year ended December 31, 2025, and up through the filing date of this Form 10-K . Additional information regarding these items may be found elsewhere in this Annual Report. • Moonrise Acquisition.
Our operations and maintenance expenses also include costs that are reimbursed by our customers, which are included in Other revenues. 68 Segment Adjusted EBITDA Segment adjusted EBITDA is a supplemental financial measure used by management and by external users of our financial statements such as investors, commercial banks, research analysts and others.
Segment Adjusted EBITDA 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.
Rockies Year ended December 31, 2024 2023 Percentage Change (Dollars in thousands) Revenues: Gathering services and related fees $ 63,219 $ 65,869 (4%) Natural gas, NGLs and condensate sales 190,535 173,688 10% Other revenues 14,757 15,474 (5%) Total revenues 268,511 255,031 5% Costs and expenses: Cost of natural gas and NGLs 113,714 110,105 3% Operation and maintenance 49,849 50,246 (1%) General and administrative 4,785 4,185 14% Depreciation and amortization 36,319 36,148 0% Integration costs — 553 * Gain on asset sales, net 30 (127) (124%) Long-lived asset impairment 344 540 (36%) Total costs and expenses 205,041 201,650 2% Add: Depreciation and amortization 36,319 36,148 Integration costs — 553 Adjustments related to capital reimbursement activity (6,348) (3,378) Gain on asset sales, net 30 (127) Long-lived asset impairment 344 540 Other 12 273 Segment adjusted EBITDA $ 93,827 $ 87,390 7% _________________ 73 * Not considered meaningful Year ended December 31, 2024 .
Rockies Year ended December 31, 2025 2024 Percentage Change (Dollars in thousands) Revenues: Gathering services and related fees $ 62,760 $ 63,219 (1%) Natural gas, NGLs and condensate sales 244,478 190,535 28% Other revenues 22,113 14,757 50% Total revenues 329,351 268,511 23% Costs and expenses: Cost of natural gas and NGLs 148,456 113,714 31% Operation and maintenance 62,279 49,849 25% General and administrative 6,438 4,785 35% Depreciation and amortization 41,586 36,319 15% Integration costs 65 — * (Gain) loss on asset sales, net (6) 30 (120%) Long-lived asset impairment 2,725 344 692% Total costs and expenses 261,543 205,041 28% Add: Depreciation and amortization 41,586 36,319 Integration costs 65 — Adjustments related to capital reimbursement activity (6,977) (6,348) (Gain) loss on asset sales, net (6) 30 Long-lived asset impairment 2,725 344 Other 1,734 12 Segment Adjusted EBITDA $ 106,935 $ 93,827 14% _________________ * Not considered meaningful 71 Year ended December 31, 2025 .
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. 66 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.
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.
Year ended December 31, 2024 2023 Percentage change (In thousands) Revenues: Gathering services and related fees $ 200,844 $ 248,223 (19%) Natural gas, NGLs and condensate sales 195,027 179,254 9% Other revenues 33,748 31,426 7% Total revenues 429,619 458,903 (6%) Costs and expenses: Cost of natural gas and NGLs 114,996 112,462 2% Operation and maintenance 100,968 100,741 —% General and administrative 55,562 42,135 32% Depreciation and amortization 100,647 122,764 (18%) Transaction costs 30,956 1,251 * Acquisition integration costs 165 2,654 * (Gain) loss on asset sales, net 1 (260) (100%) Long-lived asset impairment 68,260 540 * Total costs and expenses 471,555 382,287 23% Other income, net 4,188 865 * Gain on interest rate swaps 4,127 1,830 126% Gain (loss) on sale of business 82,187 (47) * Gain on sale of equity method investment 126,261 — N/A Interest expense (115,446) (140,784) (18%) Loss on early extinguishment of debt (50,075) (10,934) * Income from equity method investees 24,197 33,829 (28%) Income (loss) before income taxes 33,503 (38,625) (187%) Income tax expense (146,678) (322) * Net loss $ (113,175) $ (38,947) 191% Volume throughput (1) : Aggregate average daily throughput - natural gas (MMcf/d) 862 1,292 (33%) Aggregate average daily throughput - liquids (Mbbl/d) 72 78 (8%) _________________________________________________ * Not considered meaningful (1) Excludes volume throughput for Ohio Gathering and Double E.
Year ended December 31, 2025 2024 Percentage change (In thousands) Revenues: Gathering services and related fees $ 255,677 $ 200,844 27% Natural gas, NGLs and condensate sales 265,059 195,027 36% Other revenues 41,355 33,748 23% Total revenues 562,091 429,619 31% Costs and expenses: Cost of natural gas and NGLs 149,139 114,996 30% Operation and maintenance 149,139 100,968 48% General and administrative 61,018 55,562 10% Depreciation and amortization 114,159 100,647 13% Transaction costs 4,900 30,956 (84%) Acquisition integration costs 8,143 165 * Loss on asset sales, net 486 1 * Long-lived asset impairment 2,725 68,260 * Total costs and expenses 489,709 471,555 4% Other income, net 783 4,188 (81%) Gain (loss) on interest rate swaps (1,037) 4,127 (125%) Gain (loss) on sale of business (582) 82,187 * Gain on sale of equity method investment — 126,261 * Interest expense (94,737) (115,446) (18%) Loss on early extinguishment of debt — (50,075) * Income from equity method investees 20,784 24,197 (14%) Income (loss) before income taxes (2,407) 33,503 (107%) Income tax benefit (expense) 501 (146,678) * Net loss $ (1,906) $ (113,175) (98%) Volume throughput (1) : Aggregate average daily throughput - natural gas (MMcf/d) 904 862 5% Aggregate average daily throughput - liquids (Mbbl/d) 73 72 1% _________________ * Not considered meaningful (1) Excludes volume throughput for Ohio Gathering and Double E.
As of December 31, 2024, there was $305.0 million outstanding under the Amended and Restated ABL Facility and the available borrowing capacity totaled $194.2 million after giving effect to the issuance thereunder of $0.8 million of outstanding but undrawn irrevocable standby letters of credit. 2029 Secured Notes .
As of December 31, 2025, there was $113.0 million outstanding under the Amended and Restated ABL Facility and the available borrowing capacity totaled $385.7 million after giving effect to certain adjustments that are primarily related to the issuance of $0.8 million of outstanding but undrawn irrevocable standby letters of credit. New Permian Transmission Facility .
Corporate and Other includes intercompany eliminations. Corporate and Other Year ended December 31, 2024 2023 Percentage Change (Dollars in thousands) Costs and expenses: General and administrative 47,741 34,287 39% Transaction costs 30,956 1,176 * Interest expense 115,446 140,784 (18%) _________________ * Not considered meaningful Transaction costs .
Corporate and Other includes intercompany eliminations. Corporate and Other Year ended December 31, 2025 2024 Percentage Change (Dollars in thousands) Costs and expenses: General and administrative 50,780 47,741 6% Transaction costs 4,857 30,956 (84%) Acquisition integration costs 5,413 126 * Interest expense 94,737 115,446 (18%) _________________ * Not considered meaningful General and administrative .
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 .
Total revenues increased $132.5 million during the year ended December 31, 2025 compared to the year ended December 31, 2024 comprised of a $54.8 million increase in gathering services and related fees, a $70.0 million increase in natural gas, NGLs and condensate sales and a $7.6 million increase in Other revenues. Gathering services and related fees .
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.
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.
See Note 19 – Subsequent Events, for additional information. (3) Amounts include mandatory principal repayments of $16.6 million in 2025, $17.0 million in 2026 and $17.8 million in 2027. (4) Global Settlement amounts in the table exclude interest owed on the unpaid portion. See Note 10 - Commitments and Contingencies to the consolidated financial statements for additional details.
(3) Global Settlement amounts in the table exclude interest owed on the unpaid portion. See Note 10 - Commitments and Contingencies to the consolidated financial statements for additional details.
Piceance Year ended December 31, 2024 2023 Percentage Change (Dollars in thousands) Revenues: Gathering services and related fees $ 73,115 $ 81,041 (10%) Natural gas, NGLs and condensate sales 2,775 4,788 (42%) Other revenues 5,109 5,588 * Total revenues 80,999 91,417 (11%) Costs and expenses: Cost of natural gas and NGLs 1,138 2,357 (52%) Operation and maintenance 23,964 23,441 * General and administrative 1,298 1,189 9% Depreciation and amortization 42,012 52,014 (19%) Gain on asset sales, net (8) (45) (82%) Total costs and expenses 68,404 78,956 (13%) Add: Depreciation and amortization 42,012 52,014 Adjustments related to capital reimbursement activity (2,201) (5,099) Gain on asset sales, net (8) (45) Other 306 418 Segment adjusted EBITDA $ 52,704 $ 59,749 (12%) _________________ * Not considered meaningful Year ended December 31, 2024 .
Piceance Year ended December 31, 2025 2024 Percentage Change (Dollars in thousands) Revenues: Gathering services and related fees $ 61,379 $ 73,115 (16%) Natural gas, NGLs and condensate sales 2,027 2,775 (27%) Other revenues 6,461 5,109 26% Total revenues 69,867 80,999 (14%) Costs and expenses: Cost of natural gas and NGLs 674 1,138 (41%) Operation and maintenance 23,160 23,964 (3%) General and administrative 1,287 1,298 (1%) Depreciation and amortization 37,569 42,012 (11%) (Gain) loss on asset sales, net 687 (8) (8688%) Total costs and expenses 63,377 68,404 (7%) Add: Depreciation and amortization 37,569 42,012 Adjustments related to capital reimbursement activity (199) (2,201) (Gain) loss on asset sales, net 687 (8) Other 227 306 Segment Adjusted EBITDA $ 44,774 $ 52,704 (15%) _________________ * Not considered meaningful Year ended December 31, 2025 .
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 .
Total costs and expenses increased $18.2 million during the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily reflecting: Cost of Natural Gas and NGLs.
Permian Year ended December 31, 2024 2023 Percentage Change Average daily throughput (MMcf/d) (Double E) 573 305 88% Volume throughput for Double E increased 88% compared to the year ended December 31, 2023.
Volume throughput for our Permian reportable segment follows. Permian Year ended December 31, 2025 2024 Percentage Change Average daily throughput (MMcf/d) (Double E) 730 573 27% Volume throughput for Double E increased 27% compared to the year ended December 31, 2024, as a result of increased throughput volumes from its customers.
Cash flows from operating activities for the year ended December 31, 2023, primarily reflected: • a net loss of $38.9 million plus adjustments of $185.5 million for non-cash items; and • a $19.7 million change in working capital accounts. 81 Investing activities. Details of cash flows from investing activities follow.
Details of operating cash flows follow. Operating activity cash flows during the year ended December 31, 2025 primarily reflected: • a net loss of $1.9 million plus adjustments of $148.3 million for non-cash items; and • a $12.8 million outflow due to changes in working capital accounts.
Year ended December 31, 2024 . Segment adjusted EBITDA increased $4.5 million compared to the year ended December 31, 2023 primarily as a result of increased volume throughput partially offset by production curtailments discussed above and unfavorable margin mix. 77 Northeast. Volume throughput for the Northeast reportable segment follows.
Year ended December 31, 2025 . Segment Adjusted EBITDA increased $61.7 million compared to the year ended December 31, 2024 primarily as a result of the Tall Oak Acquisition and increased volume throughput discussed above. 75 Piceance. Volume throughput for our Piceance reportable segment follows.
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.
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. 66 Our operation and maintenance expenses also include costs that are reimbursed by our customers, which are included in Other revenues.
Additional Information. For additional information, see the “Results of Operations” section herein and the notes to the consolidated financial statements contained in Item 8.
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. 67 Results of Operations Consolidated Overview for the Years Ended December 31, 2025 and 2024 Below is a discussion of changes in our results of operations for 2025 compared to 2024.
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.
Interest expense decreased $20.7 million during the year ended December 31, 2025 compared to the year ended December 31, 2024 primarily due to $44.6 million of reduced interest expense as a result of the 2026 Secured Notes Tender Offer and the Asset Sale Offer that occurred in July 2024 and May 2024, respectively, and $12.0 million of reduced interest expense due to the full repayment and discharge of the 2026 Unsecured Notes in June 2024.
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 71 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.
Interest expense decreased $20.7 million during the year ended December 31, 2025 compared to the year ended December 31, 2024 primarily due to $44.6 million of reduced interest expense as a result of the 2026 Secured Notes Tender Offer and the Asset Sale Offer that occurred in July 2024 and May 2024, respectively, and $12.0 million of reduced interest expense due to the full repayment and discharge of the 2026 Unsecured Notes in June 2024.
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.
Natural gas volume throughput for the year ended December 31, 2025 increased 16% compared to the year ended December 31, 2024, primarily reflecting 99 new well connections that came online during 2025 and additional throughput associated with the Moonrise Acquisition, partially offset by natural production declines. Liquids .

… 97 more changes not shown on this page.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

3 edited+0 added−0 removed8 unchanged
Biggest changeAs of December 31, 2024, we had $575.0 million principal amount of fixed-rate debt, $305.0 million outstanding under our variable rate Amended and Restated ABL Facility and $129.3 million outstanding under our variable rate Permian Transmission Term Loan.
Biggest changeAs of December 31, 2025, we had $825.0 million principal amount of fixed-rate debt, $113.0 million outstanding under our variable rate Amended and Restated ABL Facility and $117.0 million outstanding under our variable rate Permian Transmission Term Loan.
For the year ended December 31, 2024, a hypothetical 1% increase (decrease) in interest rates on our variable rate debt would have increased (decreased) our interest expense by approximately $2.5 million assuming no changes in amounts drawn or other variables under our Amended and Restated ABL Facility or Permian Transmission Term Loan.
For the year ended December 31, 2025, a hypothetical 1% increase (decrease) in interest rates on our variable rate debt would have increased (decreased) our interest expense by approximately $2.6 million assuming no changes in amounts drawn or other variables under our Amended and Restated ABL Facility or Permian Transmission Term Loan.
As of December 31, 2024, we had $116.4 million of interest rate exposure hedged to offset the impact of changes in interest rates on our Permian Transmission Term Loan.
As of December 31, 2025, we had $101.5 million of interest rate exposure hedged to offset the impact of changes in interest rates on our Permian Transmission Term Loan.