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What changed in USA Compression Partners, LP's 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of USA Compression Partners, LP'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.

+327 added−322 removedSource: 10-K (2026-02-17) vs 10-K (2025-02-11)

Top changes in USA Compression Partners, LP's 2025 10-K

327 paragraphs added · 322 removed · 257 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

43 edited+14 added−4 removed95 unchanged
Biggest changeWe intend to continue to selectively add remote monitoring systems to our new and existing fleet during 2025 where beneficial from an operational and financial standpoint. All of our compression units are designed to automatically shut down if operating conditions deviate from a pre-determined range. We adhere to routine, preventive, and scheduled maintenance cycles.
Biggest changeAll of our compression units are designed to automatically shut down if operating conditions deviate from a pre-determined range. We adhere to routine, preventive, and scheduled maintenance cycles. Each of our compression units is subjected to rigorous sizing and diagnostic analyses, including lubricating oil analysis and engine exhaust emission analysis.
The Inflation Reduction Act of 2022 (the “IRA 2022”) imposes a methane emissions charge on certain oil and gas facilities, including onshore petroleum and natural gas production facilities, that emit 25,000 metric tons or more of carbon dioxide equivalent gas per year and exceed certain emissions thresholds.
The Inflation Reduction Act of 2022 (the “IRA 2022”) imposed a methane emissions charge on certain oil and gas facilities, including onshore petroleum and natural gas production facilities, that emit 25,000 metric tons or more of carbon dioxide equivalent gas per year and exceed certain emissions thresholds.
Site remediation . The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state laws may impose strict, joint, and several liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to the release of a hazardous substance into the environment.
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state laws may impose strict, joint, and several liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to the release of a hazardous substance into the environment.
For example, in 2009, the EPA officially published its findings that emissions of carbon dioxide, methane, and other GHGs endanger human health and the environment, allowing the agency to proceed with the adoption of regulations that restrict emissions of GHG under existing provisions of the CAA.
For example, in 2009, the EPA officially published its findings that emissions of carbon dioxide, methane, and other GHGs endanger human health and the environment (the “Endangerment Finding”), allowing the agency to proceed with the adoption of regulations that restrict emissions of GHG under existing provisions of the CAA.
While we believe that our operations are in substantial compliance with applicable environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, we cannot predict whether our cost of compliance will materially increase in the future.
While we believe that our operations are in 5 Table of Contents substantial compliance with applicable environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, we cannot predict whether our cost of compliance will materially increase in the future.
Our customers may have compression demands in conjunction with their field development projects in areas of the U.S. where we are not currently operating, and we continually consider further expansion of our geographic areas of operation in the U.S. based upon the level of customer demand.
Our customers may have compression demands in conjunction with their field development projects in areas of the U.S. where we are not currently operating, and we continually consider further expansion 2 Table of Contents of our geographic areas of operation in the U.S. based upon the level of customer demand.
However, the TCEQ has stated it will consider 6 Table of Contents expanding application of the new air permit program statewide. At this point, we cannot predict the cost to comply with such requirements if the geographic scope is expanded.
However, the TCEQ has stated it will consider expanding application of the new air permit program statewide. At this point, we cannot predict the cost to comply with such requirements if the geographic scope is expanded.
While we generate materials in the course of our operations that may be regulated as hazardous 8 Table of Contents substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA at any site.
While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA at any site.
If additional levels of regulation, restrictions, and permits were required through the adoption of new laws and regulations at the federal or state level, or if the agencies that issue the permits develop new interpretations of those requirements, it could lead to delays, increased operating costs, and process prohibitions that could reduce demand for our compression services, which could materially adversely affect our revenue and results of operations.
If additional levels of regulation, restrictions, and permits were required through the adoption of new laws and regulations at the federal or state level, or if the agencies that issue the permits develop new interpretations of those requirements, it could lead to delays, increased operating costs, and process prohibitions that could reduce demand for our compression services, which could materially adversely affect our revenue and results of operations. 8 Table of Contents Site remediation .
As of December 31, 2024, the average age of our compression units was approximately 12 years. Our modern, standardized compression unit fleet is powered primarily by the Caterpillar 3400, 3500, and 3600 engine classes, which range from 400 to 5,000 horsepower per unit.
As of December 31, 2025, the average age of our compression units was approximately 13 years. Our modern, standardized compression unit fleet as of December 31, 2025 is powered primarily by the Caterpillar 3400, 3500, and 3600 engine classes, which range from 400 to 5,000 horsepower per unit.
We promote employee empowerment, leadership, communication, and personal responsibility to comply with standard operating procedures and regulatory requirements, effective risk reduction processes, and personal wellness. 9 Table of Contents Available Information Our website address is usacompression.com.
We promote employee empowerment, leadership, communication, and personal responsibility to comply with standard operating procedures and regulatory requirements, effective risk reduction processes, and personal wellness. Available Information Our website address is usacompression.com.
We consider our employee relations to be good. Our employees are our greatest asset, and we seek to attract and retain top talent by fostering a culture that is guided by our four pillars of people, culture, equipment, and service.
None of our employees are subject to collective bargaining agreements. We consider our employee relations to be good. Our employees are our greatest asset, and we seek to attract and retain top talent by fostering a culture that is guided by our four pillars of people, culture, equipment, and service.
We also are subject to air regulation at the state level. For example, the Texas Commission on Environmental Quality (“TCEQ”) has finalized revisions to certain air permit programs that significantly increase the air permitting requirements for new and certain existing oil and gas production and gathering sites for 15 counties in the Barnett Shale production area.
For example, the Texas Commission on Environmental Quality (“TCEQ”) has finalized revisions to certain air permit programs that significantly increase the air permitting requirements for new and certain existing oil and gas production and gathering sites for 15 counties in the Barnett Shale production area.
Although it is not currently possible to predict with specificity how any proposed or future GHG legislation, regulation, agreements or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate, including a carbon tax or cap-and-trade program, could result in increased compliance or operating costs, additional operating restrictions, or reduced demand for our services, and could have a material adverse effect on our business, financial condition, and results of operations.
Although a number of these lawsuits have been dismissed, others remain pending and the outcome of these cases remains difficult to predict. 7 Table of Contents Although it is not currently possible to predict with specificity how any proposed or future GHG legislation, regulation, agreements or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate, including a carbon tax or cap-and-trade program, could result in increased compliance or operating costs, additional operating restrictions, or reduced demand for our services, and could have a material adverse effect on our business, financial condition, and results of operations.
We operate a fleet of compression units with an average age of approximately 12 years and a useful life that could potentially extend decades when properly maintained.
We operate a fleet of compression units with an average age of approximately 13 years as of December 31, 2025 and a useful life that could potentially extend decades when properly maintained.
Our goal is operational excellence, which includes maintaining an injury- and incident-free workplace. To achieve this, we strive to hire and maintain a highly qualified and dedicated workforce, and create a safety culture with safety accountability as part of our daily operations.
A portion of our senior management bonuses and field leadership bonuses are dependent on our safety performance. Our goal is operational excellence, which includes maintaining an injury- and incident-free workplace. To achieve this, we strive to hire and maintain a highly qualified and dedicated workforce, and create a safety culture with safety accountability as part of our daily operations.
For example, in 2019, Colorado passed Senate Bill 19-181, which delegates authority to local governments to regulate oil and gas activities and requires the Colorado Oil and Gas Conservation Commission to minimize emissions of methane and other air contaminants.
Some states also have passed legislation or regulations regarding hydraulic fracturing. For example, in 2019, Colorado passed Senate Bill 19-181, which delegates authority to local governments to regulate oil and gas activities and requires the Colorado Oil and Gas Conservation Commission to minimize emissions of methane and other air contaminants.
Suppliers and Service Providers The principal manufacturers of components for our natural gas compression equipment include Caterpillar Inc., Cummins Inc., INNIO Waukesha, and TECO-Westinghouse for engines; Air-X-Changers, Alfa Laval (US), AXH air-coolers, EADS Cooling Solutions, LLC, and R&R Engineering Co. for coolers; and Ariel Corporation, Cooper Machinery Services Gemini 4 Table of Contents products, and Arrow Engine Company for compressor frames and cylinders.
Our ten largest customers accounted for approximately 46%, 41%, and 39% of our total revenues for the years ended December 31, 2025, 2024, and 2023, respectively. 4 Table of Contents Suppliers and Service Providers The principal manufacturers of components for our natural gas compression equipment include Caterpillar Inc., Cummins Inc., INNIO Waukesha, and TECO-Westinghouse for engines; Air-X-Changers, Alfa Laval (US), AXH air-coolers, EADS Cooling Solutions, LLC, and R&R Engineering Co. for coolers; and Ariel Corporation, Cooper Machinery Services Gemini products, and Arrow Engine Company for compressor frames and cylinders.
We provide continuous training opportunities for employees, including training that is required by applicable laws, regulations, standards, and permit conditions. Our safety standards and expectations are clearly communicated to all employees with the expectation that each individual has the obligation to make safety their highest priority. Our safety culture promotes an open environment for discovering, resolving, and sharing safety challenges.
We provide continuous training opportunities for employees, including training that is required by applicable laws, regulations, standards, and permit conditions. Our safety standards and expectations are clearly communicated to all employees with the expectation that each individual has the 9 Table of Contents obligation to make safety their highest priority.
At the state level, many states, including the states in which we or our customers conduct operations, have adopted legal requirements that have imposed new or more stringent permitting, disclosure, or well construction requirements on oil and gas activities.
Other energy legislation and initiatives could include a carbon tax or cap-and-trade program. At the state level, many states, including the states in which we or our customers conduct operations, have adopted legal requirements that have imposed new or more stringent permitting, disclosure, or well construction requirements on oil and gas activities.
Lead-times for new Caterpillar engines and new Ariel compressor frames have in the recent past varied between six months to over one year due to changes in demand and supply allocations, and as of December 31, 2024, lead-times for such engines and frames are approximately one year.
Lead-times for new Caterpillar engines and new Ariel compressor frames have in the recent past varied between six months to over one year due to changes in demand and supply allocations, and as of December 31, 2025, lead-times for such engines and frames have extended beyond one year, and in some cases with certain engine classes, are in excess of two years.
We recognize the need to decrease emissions and integrate alternative energy sources into our operations, and we actively pursue economically beneficial opportunities to reduce our environmental footprint. To that end, we have continued the commercialization of dual-drive technology in our natural gas compression services, deploying our first compression units with dual-drive technology in the third quarter of 2022.
We recognize the need to decrease emissions and integrate alternative energy sources into our operations, and we actively pursue economically beneficial opportunities to reduce our environmental footprint. To that end, we have dual-drive technology as a product offering in our natural gas compression services.
Any changes in, or more stringent enforcement of, existing environmental laws and regulations, or passage of additional environmental laws and regulations that result in more stringent and costly pollution control equipment, waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. 5 Table of Contents We do not believe that compliance with current federal, state, or local laws and regulations will have a material adverse effect on our business, financial position, results of operations, or cash flows.
Any changes in, or more stringent enforcement of, existing environmental laws and regulations, or passage of additional environmental laws and regulations that result in more stringent and costly pollution control equipment, waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position.
Many of these suits allege that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. Although a number of these lawsuits have been dismissed, others remain pending and the outcome of these cases remains difficult to predict.
Many of these suits allege that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.
These capabilities allow our field technicians to identify potential problems and often act on them before such problems result in down-time. Generally, we expect each of our compression units to undergo a major overhaul between service deployment cycles. The timing of these major overhauls depends on multiple factors, including run time and operating conditions.
Generally, we expect each of our compression units to undergo a major overhaul between service deployment cycles. The timing of these major overhauls depends on multiple factors, including run time and operating conditions.
We consistently have provided average service run times at or above the levels required by our customers. In general, our team of field technicians services only our compression fleet and ancillary equipment. In limited circumstances, and for established customers, we will agree to service third-party owned equipment. We do not own any compression fabrication facilities.
We consistently have provided average service run times at or above the levels required by our customers. In general, our team of field technicians services only our compression fleet and ancillary equipment. In certain circumstances we service third-party owned equipment. As a result of the J-W Power Acquisition, we also own two compression fabrication facilities.
We provide compression services to our customers primarily in connection with infrastructure applications, including both allowing for the processing and transportation of natural gas through the domestic pipeline system and enhancing crude oil production through artificial lift processes. As such, our compression services play a critical role in the production, processing, and transportation of both natural gas and crude oil.
Please see “Recent Developments” below for additional information on the J-W Power Acquisition. We provide compression services to our customers primarily in connection with infrastructure applications, including both allowing for the processing and transportation of natural gas through the domestic pipeline system and enhancing crude oil production through artificial lift processes.
We provide compression services to our customers under fixed-fee contracts with initial contract terms that typically range from six months to five years, depending on the application and location of the compression unit. We typically continue to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis.
We provide compression services to our customers under fixed-fee contracts with initial contract terms that, as of December 31, 2025, typically range from six months to five years, depending on the application and location of the compression unit.
However, relying on alternative sources may increase our costs and change the standardized nature of our fleet. We have not experienced any material supply problems to date.
Although we primarily rely on these suppliers, we believe alternative sources for natural gas compression equipment generally are available if needed. However, relying on alternative sources may increase our costs and change the standardized nature of our fleet. We have not experienced any material supply problems to date.
We strive to eliminate unwanted safety events and support our safety culture through a comprehensive program that includes a dedicated field operations-based safety team, monthly employee safety meetings, and safety audits, among other things. A portion of our senior management bonuses and field leadership bonuses are dependent on our safety performance.
Our safety culture promotes an open environment for discovering, resolving, and sharing safety challenges. We strive to eliminate unwanted safety events and support our safety culture through a comprehensive program that includes a dedicated field operations-based safety team, monthly employee safety meetings, and safety audits, among other things.
We have focused our compression services in unconventional resource plays throughout the U.S., including the Utica, Marcellus, Permian, Denver-Julesburg, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, and Haynesville.
As such, our compression services play a critical role in the production, processing, and transportation of both natural gas and crude oil. We have focused our compression services in unconventional resource plays throughout the U.S., including the Utica, Marcellus, Permian, Denver-Julesburg, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, and Haynesville, and following the J-W Power Acquisition, the Bakken.
In addition, in December 2023, the EPA issued rules to further reduce methane and VOC emissions from new and existing sources in the oil and gas sector. Any additional regulation of air emissions from the oil and gas sector could result in increased expenditures for pollution control equipment, which could impact our customers’ operations and negatively impact our business.
Any additional regulation of air emissions from the oil and gas sector could result in increased expenditures for pollution control equipment, which could impact our customers’ operations and negatively impact our business. 6 Table of Contents We also are subject to air regulation at the state level.
As of December 31, 2024, USAC Management had 854 full-time employees. In addition, under our shared services model with Energy Transfer, in late 2024 we began utilizing the services of Energy Transfer employees in certain departments such as information technology, accounting, and human resources. None of our employees are subject to collective bargaining agreements.
As of December 31, 2025, USAC Management had 885 full-time employees. An additional 594 employees were added as a result of the J-W Power Acquisition. In addition, under our shared services model with Energy Transfer we utilize the services of Energy Transfer employees in certain departments such as information technology, accounting, and human resources.
However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector, which could have an adverse effect on our ability to obtain external financing. 7 Table of Contents Finally, some scientists have concluded that increasing concentrations of GHG in Earth’s atmosphere may produce climate changes that have significant weather-related effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events.
However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector, which could have an adverse effect on our ability to obtain external financing.
Our modern, flexible fleet of compression units, which have been designed to be rapidly deployed and redeployed throughout the country, provides us with opportunities to expand into other areas with both new and existing customers. 2 Table of Contents We also own and operate a fleet of equipment used to provide natural gas treating services, such as carbon dioxide and hydrogen sulfide removal and natural gas cooling and dehydration, to natural gas producers and midstream companies.
Our modern, flexible fleet of compression units, which have been designed to be rapidly deployed and redeployed throughout the country, provides us with opportunities to expand into other areas with both new and existing customers.
Any limitations or bans on hydraulic fracturing at the federal level could increase the costs of operations for our customers who operate on federal land, and negatively impact our business. Some states also have passed legislation or regulations regarding hydraulic fracturing.
Hydraulic fracturing involves the injection of water, sand, and chemicals under pressure into the rock formation to stimulate oil and gas production. Any limitations or bans on hydraulic fracturing at the federal level could increase the costs of operations for our customers who operate on federal land, and negatively impact our business.
We have been providing compression services since 1998 and completed our initial public offering in January 2013. On April 2, 2018, we acquired all of the equity interests in CDM Resource Management LLC and CDM Environmental & Technical Services LLC (the “CDM Acquisition”). As of December 31, 2024, we had 3,862,102 horsepower in our fleet.
We have been providing compression services since 1998 and completed our initial public offering in January 2013. As of December 31, 2025, we had 3.9 million horsepower in our fleet.
Customers Our customers consist of approximately 275 companies in the energy industry, including major integrated oil companies, public and private independent exploration and production companies, and midstream companies. Our ten largest customers accounted for approximately 41%, 39%, and 38% of our total revenues for the years ended December 31, 2024, 2023, and 2022, respectively.
Customers As of December 31, 2025, our customers consisted of approximately 260 companies in the energy industry, including major integrated oil companies, public and private independent exploration and production companies, and midstream companies.
These larger-horsepower units, which we define as 400 horsepower per unit or greater, represented 87.2% of our total fleet horsepower (including compression units on order) as of December 31, 2024. The remainder of our fleet consists of smaller-horsepower units ranging from 40 horsepower to 399 horsepower that are used primarily in gas lift applications.
These larger-horsepower units, which we define as 400 horsepower per unit or greater, represented 87.6% of our total fleet horsepower (including compression units on order) as 3 Table of Contents of December 31, 2025.
As of February 6, 2025, Energy Transfer owned 100% of the membership interest in our General Partner and 46,056,228 of our common units, which constituted a 39% limited partner interest in us.
Under this shared service model, we share personnel and resources in certain departments, including information technology, accounting, and human resources, which increases efficiencies and support across our organization. As of February 12, 2026, Energy Transfer owned 100% of the membership interest in our General Partner and 46,056,228 of our common units, which constituted a 32% limited partner interest in us.
Subsequent to December 31, 2024, we ordered 4 large-horsepower units, consisting of 10,000 horsepower, for expected delivery during 2025. Many of our compression units contain devices that enable us to monitor the units remotely through cellular and satellite networks to supplement our technicians’ on-site monitoring visits.
Many of our compression units contain devices that enable us to monitor the units remotely through cellular and satellite networks to supplement our technicians’ on-site monitoring visits. We intend to continue to selectively add remote monitoring systems to our new and existing fleet during 2026 where beneficial from an operational and financial standpoint.
Each of our compression units is subjected to rigorous sizing and diagnostic analyses, including lubricating oil analysis and engine exhaust emission analysis. We have proprietary field-service automation capabilities that allow our service technicians to electronically record and track operating, technical, environmental, and commercial information at the discrete unit level.
We have proprietary field-service automation capabilities that allow our service technicians to electronically record and track operating, technical, environmental, and commercial information at the discrete unit level. These capabilities allow our field technicians to identify potential problems and often act on them before such problems result in down-time.
In November 2024, the EPA issued a final rule to impose and collect the methane emissions charge authorized under the IRA 2022. We do not believe that this methane fee will have a material adverse effect on our business, financial position, results of operations, or cash flows. Other energy legislation and initiatives could include a carbon tax or cap-and-trade program.
The One Big Beautiful Bill Act, signed by President Trump on July 4, 2025, delays the imposition of the methane emissions charge until calendar year 2034. We do not believe that this methane fee will have a material adverse effect on our business, financial position, results of operations, or cash flows.
Removed
Our Relationship with Energy Transfer LP In late 2024, we began implementing a shared services model with the owner of our General Partner, Energy Transfer. Under this model, we will share personnel and resources in certain departments, including information technology, accounting, and human resources. We believe this will increase efficiencies and support across our organization, while simultaneously reducing administrative costs.
Added
On January 12, 2026, we acquired all of the equity interests in J-W Energy Company (“J-W Energy”) and its subsidiary, J-W Power Company (“J-W Power”), which acquisition we refer to as the J-W Power Acquisition. An additional 1.0 million horsepower was added to our fleet through the J-W Power Acquisition.
Removed
We believe the average age and overall composition of our compressor fleet result in fewer mechanical failures, lower fuel usage, and reduced environmental emissions. 3 Table of Contents The following table provides a summary of our compression units by horsepower as of December 31, 2024: Unit Horsepower Fleet Horsepower Number of Units Horsepower on Order (1) Number of Units on Order (1) Total Horsepower Number of Units Percent of Total Horsepower Percent of Units Small horsepower 495,258 2,908 — — 495,258 2,908 12.8 % 54.0 % Large horsepower ≥400 and 419,980 720 — — 419,980 720 10.8 % 13.4 % ≥1,000 2,946,864 1,752 10,000 4 2,956,864 1,756 76.4 % 32.6 % Total large horsepower 3,366,844 2,472 10,000 4 3,376,844 2,476 87.2 % 46.0 % Total horsepower 3,862,102 5,380 10,000 4 3,872,102 5,384 100.0 % 100.0 % ________________________ (1) As of December 31, 2024, we had no horsepower units on order.
Added
We typically continue to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis.
Removed
We also rely primarily on three vendors, A G Equipment Company, Alegacy Equipment, LLC., and Standard Equipment Company, to package and assemble our compression units. Although we primarily rely on these suppliers, we believe alternative sources for natural gas compression equipment generally are available if needed.
Added
We also own and operate a fleet of equipment used to provide natural gas treating services, such as carbon dioxide and hydrogen sulfide removal and natural gas cooling and dehydration, to natural gas producers and midstream companies. Additionally, as a result of the J-W Power Acquisition, we also own and operate specialized manufacturing facilities for the manufacture of compression units.
Removed
In addition, from time to time, there have been various proposals to regulate hydraulic fracturing at the federal level. Hydraulic fracturing involves the injection of water, sand, and chemicals under pressure into the rock formation to stimulate oil and gas production.
Added
Recent Developments On January 12, 2026, the Partnership and USA Compression Partners, LLC, a wholly owned subsidiary of the Partnership, completed the J-W Power Acquisition, pursuant to which USA Compression Partners, LLC purchased all of the issued and outstanding capital stock of J-W Energy from Westerman, Ltd. for aggregate consideration of approximately $860.0 million, subject to customary purchase price adjustments, consisting of (i) 18,175,323 common units representing limited partner interests in the Partnership and (ii) approximately $430.0 million in cash.
Added
Upon consummation of the J-W Power Acquisition, J-W Power and J-W Energy became wholly owned indirect subsidiaries of the Partnership. The J-W Power Acquisition added approximately 0.8 million active horsepower and 1.0 million total horsepower to our fleet across key regions including the Northeast, Mid-Con, Rockies, Gulf Coast, Bakken and Permian Basin.
Added
J-W Power also owns and operates specialized manufacturing facilities that support its internal compression requirements and those of third-party customers. Our Relationship with Energy Transfer LP We share certain services with the owner of our General Partner, Energy Transfer.
Added
The remainder of our fleet as of December 31, 2025 consists of smaller-horsepower units ranging from 40 horsepower to 399 horsepower that are used primarily in gas lift applications. The unit fleet we acquired as a result of the J-W Power Acquisition consists of primarily of Caterpillar 3300, 3400 and 3500 engine classes.
Added
We believe the average age and overall composition of our compressor fleet result in fewer mechanical failures, lower fuel usage, and reduced environmental emissions.
Added
The following table provides a summary of our compression units by horsepower as of December 31, 2025: Unit Horsepower Fleet Horsepower (1) Number of Units Horsepower on Order Number of Units on Order Total Horsepower (1) Number of Units Percent of Total Horsepower Percent of Units Small horsepower 488,813 2,878 — — 488,813 2,878 12.4 % 53.4 % Large horsepower ≥400 and 422,920 722 — — 422,920 722 10.6 % 13.4 % ≥1,000 2,982,599 1,764 63,250 28 3,045,849 1,792 77.0 % 33.2 % Total large horsepower 3,405,519 2,486 63,250 28 3,468,769 2,514 87.6 % 46.6 % Total horsepower 3,894,332 5,364 63,250 28 3,957,582 5,392 100.0 % 100.0 % ________________________ (1) As a result of the J-W Power Acquisition, in January 2026 we added approximately 0.8 million active horsepower and 1.0 million total horsepower.
Added
We also rely on several vendors, including Standard Equipment Company, a subsidiary of Energy Transfer, to package and assemble our compression units. Additionally, J-W Power owns specialized manufacturing facilities that support its internal compression requirements and those of third-party customers.
Added
We do not believe that compliance with current federal, state, or local laws and regulations will have a material adverse effect on our business, financial position, results of operations, or cash flows.
Added
In addition, in December 2023, the EPA issued rules to further reduce methane and VOC emissions from new and existing sources in the oil and gas sector.
Added
On August 1, 2025, the EPA proposed rescinding the Endangerment Finding. It remains uncertain how EPA’s rescindment of the Endangerment Finding, once final, will impact future regulation of GHG emissions. In addition, from time to time, there have been various proposals to regulate hydraulic fracturing at the federal level.
Added
Finally, some scientists have concluded that increasing concentrations of GHG in Earth’s atmosphere may produce climate changes that have significant weather-related effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events.

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

105 edited+26 added−32 removed230 unchanged
Biggest changeThe General Partner and its affiliates, including Energy Transfer, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders. • The Partnership Agreement limits the General Partner’s fiduciary duties to our unitholders. • The Partnership Agreement restricts the remedies available to our unitholders for actions taken by the General Partner that otherwise might constitute breaches of fiduciary duty. • The Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units. • We may issue additional limited partner interests without the approval of unitholders, subject to certain Preferred Unit approval rights, which would dilute unitholders’ existing ownership interests and may increase the risk that we will not have sufficient available cash to maintain or increase our per-common-unit distribution level. • Energy Transfer may sell, and the holders of the Preferred Units have sold and may continue to sell, our common units in the public or private markets, and such sales could have an adverse impact on the trading price of our common units. • The General Partner has a call right that may require holders of our common units to sell their common units at an undesirable time or price. • Unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business. • Unitholders may have liability to repay distributions that were wrongfully distributed to them. • Our Partnership Agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our General Partner’s directors, officers, or other employees.
Biggest changeThe General Partner and its affiliates, including Energy Transfer, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders. • The Partnership Agreement limits the General Partner’s fiduciary duties to our unitholders. • The Partnership Agreement restricts the remedies available to our unitholders for actions taken by the General Partner that otherwise might constitute breaches of fiduciary duty. • The Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units. • We may issue additional limited partner interests without the approval of unitholders which would dilute unitholders’ existing ownership interests and may increase the risk that we will not have sufficient available cash to maintain or increase our per-common-unit distribution level. • Energy Transfer and Westerman, Ltd. may sell our common units in the public or private markets, and such sales could have an adverse impact on the trading price of our common units. • The General Partner has a call right that may require holders of our common units to sell their common units at an undesirable time or price.
The IRS may challenge this treatment, which could adversely affect the value of our common units. • We generally prorate our items of income, gain, loss, and deduction for federal income tax purposes between transferors and transferees of our units each month based on the ownership of our units on the first day of each month, 11 Table of Contents instead of on the basis of the date a particular unit is transferred.
The IRS may challenge this treatment, which could adversely affect the value of our common units. 11 Table of Contents • We generally prorate our items of income, gain, loss, and deduction for federal income tax purposes between transferors and transferees of our units each month based on the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred.
For example, the Partnership Agreement: • provides that whenever the General Partner makes a determination or takes, or declines to take, any other action in its capacity as the General Partner, the General Partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by the Partnership Agreement, Delaware law, or any other law, rule, or regulation, or at equity; • provides that the General Partner will not have any liability to us, or our unitholders, for decisions made in its capacity as general partner so long as such decisions are made in good faith, meaning that it believed that the decisions were in the best interest of the Partnership; • provides that the General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and 25 Table of Contents • provides that the General Partner will not be in breach of its obligations under the Partnership Agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is: • approved by the conflicts committee of the Board, although the General Partner is not obligated to seek such approval; • approved by the vote of a majority of our outstanding common units, excluding any common units owned by the General Partner and its affiliates; • on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or • fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
For example, the Partnership Agreement: • provides that whenever the General Partner makes a determination or takes, or declines to take, any other action in its capacity as the General Partner, the General Partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by the Partnership Agreement, Delaware law, or any other law, rule, or regulation, or at equity; • provides that the General Partner will not have any liability to us, or our unitholders, for decisions made in its capacity as general partner so long as such decisions are made in good faith, meaning that it believed that the decisions were in the best interest of the Partnership; • provides that the General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and • provides that the General Partner will not be in breach of its obligations under the Partnership Agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is: • approved by the conflicts committee of the Board, although the General Partner is not obligated to seek such approval; • approved by the vote of a majority of our outstanding common units, excluding any common units owned by the General Partner and its affiliates; • on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or • fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could 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 access to and costs of capital.
Unfavorable ESG ratings and activism directed at shifting funding away from companies with energy-related assets could 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 access to and costs of capital.
This determination can affect the amount of cash that is distributed to our unitholders; • the General Partner determines which costs it incurs are reimbursable by us; • the General Partner may cause us to borrow funds in order to permit the payment of cash distributions; • the Partnership Agreement permits us to classify up to $36.6 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings, or other sources that otherwise would constitute capital surplus; 24 Table of Contents • the Partnership Agreement does not restrict the General Partner from causing us to pay it or its affiliates for any services rendered to us, or entering into additional contractual arrangements with any of these entities on our behalf; • the General Partner currently limits, and intends to continue limiting, its liability for our contractual and other obligations; • the General Partner may exercise its right to call and purchase all of our common units not owned by it and its affiliates if together those entities at any time own more than 80% of our common units; • the General Partner controls the enforcement of the obligations that it and its affiliates owe to us; and • the General Partner decides whether to retain separate counsel, accountants, or others to perform services for us.
This determination can affect the amount of cash that is distributed to our unitholders; • the General Partner determines which costs it incurs are reimbursable by us; • the General Partner may cause us to borrow funds in order to permit the payment of cash distributions; • the Partnership Agreement permits us to classify up to $36.6 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings, or other sources that otherwise would constitute capital surplus; • the Partnership Agreement does not restrict the General Partner from causing us to pay it or its affiliates for any services rendered to us, or entering into additional contractual arrangements with any of these entities on our behalf; • the General Partner currently limits, and intends to continue limiting, its liability for our contractual and other obligations; • the General Partner may exercise its right to call and purchase all of our common units not owned by it and its affiliates if together those entities at any time own more than 80% of our common units; • the General Partner controls the enforcement of the obligations that it and its affiliates owe to us; and • the General Partner decides whether to retain separate counsel, accountants, or others to perform services for us.
Risk Factor Summary Risks Related to Our Business • We may not generate sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to the General Partner, to enable us to make cash distributions on our common units at the current level. • An extended reduction in the demand for, or production of, natural gas or crude oil could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders. • We have several key customers.
Risk Factor Summary Risks Related to Our Business • We may not generate sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to the General Partner, to enable us to make cash distributions on our common units at the current level. • A reduction in the demand for, or production of, natural gas or crude oil could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders. • We have several key customers.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, including: • the levels of our maintenance and expansion capital expenditures; • the level of our operating costs and expenses; • our debt service requirements and other liabilities; • state sales and use taxes that may be levied on us by the states in which we operate; • fluctuations in our working capital needs; • restrictions contained in the Credit Agreement or the Indentures (the “Indentures”) governing the Senior Notes 2027 and Senior Notes 2029 (collectively, the “Senior Notes”); • the cost of acquisitions; • fluctuations in interest rates; • the financial condition of our customers; • our ability to borrow funds and access the capital markets; and • the amount of cash reserves established by the General Partner. 12 Table of Contents An extended reduction in the demand for, or production of, natural gas or crude oil could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, including: • the levels of our maintenance and expansion capital expenditures; • the level of our operating costs and expenses; • our debt service requirements and other liabilities; • state sales and use taxes that may be levied on us by the states in which we operate; • fluctuations in our working capital needs; • restrictions contained in the Credit Agreement or the Indentures (the “Indentures”) governing the Senior Notes 2029 and Senior Notes 2033 (collectively, the “Senior Notes”); • the cost of acquisitions; • fluctuations in interest rates; • the financial condition of our customers; • our ability to borrow funds and access the capital markets; and • the amount of cash reserves established by the General Partner. 12 Table of Contents A reduction in the demand for, or production of, natural gas or crude oil could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders.
Our debt level, including any increases in interest rates, may limit our flexibility in obtaining additional financing, pursuing other business opportunities, and paying distributions. As of December 31, 2024, we had $2.5 billion of total debt, net of amortized deferred financing costs, outstanding under our Credit Agreement and Senior Notes.
Our debt level, including any increases in interest rates, may limit our flexibility in obtaining additional financing, pursuing other business opportunities, and paying distributions. As of December 31, 2025, we had $2.5 billion of total debt, net of amortized deferred financing costs, outstanding under our Credit Agreement and Senior Notes.
The difficulties of integrating future acquisitions with our business include, among other things: • operating a larger combined organization in new geographic areas and new lines of business; • hiring, training, or retaining qualified personnel to manage and operate our growing business and assets; • integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees; • diversion of management’s attention from our existing business; • assimilation of acquired assets and operations, including additional regulatory programs; • loss of customers; • loss of key employees; • maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and • integrating new technology systems for financial reporting.
The difficulties of integrating past and future acquisitions with our business include, among other things: • operating a larger combined organization in new geographic areas and new lines of business; 16 Table of Contents • hiring, training, or retaining qualified personnel to manage and operate our growing business and assets; • integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees; • diversion of management’s attention from our existing business; • assimilation of acquired assets and operations, including additional regulatory programs; • loss of customers; • loss of key employees; • maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and • integrating new technology systems for financial reporting.
These factors include our ability to: • develop new business and enter into service contracts with new customers; • retain our existing customers and maintain or expand the services we provide them; 15 Table of Contents • maintain or increase the fees we charge, and the margins we realize, from our compression services; • recruit and train qualified personnel and retain valued employees; • expand our geographic presence; • effectively manage our costs and expenses, including costs and expenses related to growth; • complete accretive acquisitions; • obtain required debt or equity financing on favorable terms for our existing and new operations; and • meet customer-specific contract requirements or pre-qualifications.
These factors include our ability to: • develop new business and enter into service contracts with new customers; • retain our existing customers and maintain or expand the services we provide them; • maintain or increase the fees we charge, and the margins we realize, from our compression services; • recruit and train qualified personnel and retain valued employees; • expand our geographic presence; • effectively manage our costs and expenses, including costs and expenses related to growth; • complete accretive acquisitions; • obtain required debt or equity financing on favorable terms for our existing and new operations; and • meet customer-specific contract requirements or pre-qualifications.
Under our cash distribution policy, the amount of cash we can distribute to our unitholders principally depends on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things: • the level of production of, demand for, and price of natural gas and crude oil, particularly the level of production in the regions where we provide compression services; • the fees we charge, and the margins we realize, from our compression services; • the cost of achieving organic growth in current and new markets; • the ability to effectively integrate any assets or businesses we acquire; • the level of competition from other companies; and • prevailing global and regional economic and regulatory conditions, and their impact on us and our customers.
Under our cash distribution policy, the amount of cash we can distribute to our unitholders principally depends on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things: • the level of production of, demand for, and price of natural gas and crude oil, particularly the level of production in the regions where we provide compression services; • the fees we charge, and the margins we realize, from our compression services; • the cost of achieving organic growth in current and new markets; • the ability to effectively integrate any assets or businesses we acquire, including the J-W Power Acquisition; • the level of competition from other companies; and • prevailing global and regional economic and regulatory conditions, and their impact on us and our customers.
For example, in 2015, the EPA finalized a rule strengthening the primary and secondary National Ambient Air Quality Standards (“NAAQS”) for ground level ozone, both of which are eight-hour concentration standards of 70 parts per billion (the “2015 NAAQS”). In December 2020, the EPA announced its decision to retain, without changes, the 2015 NAAQS.
For example, in 2015, the EPA finalized a rule strengthening the primary and secondary National Ambient Air Quality Standards (“NAAQS”) for ground level ozone, both of 20 Table of Contents which are eight-hour concentration standards of 70 parts per billion (the “2015 NAAQS”). In December 2020, the EPA announced its decision to retain, without changes, the 2015 NAAQS.
For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale. The ultimate effect of any such allocations will depend on the unitholder’s individual tax position with respect to its units.
For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may 28 Table of Contents be allocated taxable income and gain resulting from the sale. The ultimate effect of any such allocations will depend on the unitholder’s individual tax position with respect to its units.
Distributions generally would be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because taxes would be levied on us as a corporation, our cash 28 Table of Contents available for distribution also would be substantially reduced.
Distributions generally would be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because taxes would be levied on us as a corporation, our cash available for distribution also would be substantially reduced.
Given the wide variety of locations in which we operate, and the numerous environmental permits and other authorizations that 20 Table of Contents are applicable to our operations, we may occasionally identify or be notified of technical violations of certain requirements existing under various permits or other authorizations. We could be subject to penalties for any noncompliance in the future.
Given the wide variety of locations in which we operate, and the numerous environmental permits and other authorizations that are applicable to our operations, we may occasionally identify or be notified of technical violations of certain requirements existing under various permits or other authorizations. We could be subject to penalties for any noncompliance in the future.
Under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our General Partner or to take other action under the Partnership Agreement constituted participation in the “control” of our business.
Under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our General Partner or to take other action under the Partnership 26 Table of Contents Agreement constituted participation in the “control” of our business.
In recent years, there has been a rise in the number of cyberattacks on other companies’ network and 32 Table of Contents information systems by state-sponsored and other criminal organizations, as well as data security incidents caused by human error, vulnerabilities in software and other technologies, or vendor and supply chain incidents.
In recent years, there has been a rise in the number of cyberattacks on other companies’ network and information systems by state-sponsored and other criminal organizations, as well as data security incidents caused by human error, vulnerabilities in software and other technologies, or vendor and supply chain incidents.
Uncertainty surrounding sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil and natural gas supplies and markets for crude oil, natural gas, and NGLs, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.
Uncertainty surrounding sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil and natural gas supplies and markets for crude oil, natural gas, and NGLs, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act 32 Table of Contents of terror.
As a result, 30 Table of Contents distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit also will be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.
As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit also will be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.
Unlike the holders of common stock in a corporation, our common unitholders only have limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Common 23 Table of Contents unitholders have no right to elect the General Partner or the board of directors of the General Partner (the “Board”).
Unlike the holders of common stock in a corporation, our common unitholders only have limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Common unitholders have no right to elect the General Partner or the board of directors of the General Partner (the “Board”).
Such vertical integration, increases in vertical integration, or use of alternative technologies could result in decreased demand for our compression services, which may have a material adverse effect on our business, results of operations, financial condition, and reduce our cash available for distribution.
Such vertical integration, increases in vertical integration, or use of alternative technologies could result in decreased demand for our 13 Table of Contents compression services, which may have a material adverse effect on our business, results of operations, financial condition, and reduce our cash available for distribution.
If so, such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss on the disposition.
If so, such unitholder would no longer 30 Table of Contents be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss on the disposition.
In certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction subject to this limitation in future taxable years. Unitholders should consult their tax advisors regarding the impact of this business interest deduction limitation on an investment in our units.
In certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction 29 Table of Contents subject to this limitation in future taxable years. Unitholders should consult their tax advisors regarding the impact of this business interest deduction limitation on an investment in our units.
Increasing attention to, and societal expectations on companies to address, climate change and other environmental and social impacts, investor and societal expectations regarding voluntary environmental, social, and governance (“ESG”) disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for fossil fuels and consequently demand for our services, reduced profits, increased risk of investigations and litigation, and negative impacts on the value of our assets and access to capital.
Focus on companies to address, climate change and other environmental and social impacts, investor and societal expectations regarding environmental, social, and governance (“ESG”) disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for fossil fuels and consequently demand for our services, reduced profits, increased risk of investigations and litigation, and negative impacts on the value of our assets and access to capital.
Federal Reserve has begun lowering interest rates, macroeconomic circumstances may change, resulting in delays or reversal of such actions, which may result in a prolonged high-interest rate environment. Any substantial increase in the interest rates applicable to our variable-rate indebtedness outstanding could have a material negative impact on our cash available for distribution.
Federal Reserve has lowered interest rates recently, macroeconomic circumstances may change, resulting in delays or reversal of such actions, which may result in a prolonged high-interest rate environment. Any substantial increase in the interest rates applicable to our variable-rate indebtedness outstanding could have a material negative impact on our cash available for distribution.
Although we may from time to time consult with professional appraisers regarding valuation 31 Table of Contents matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets.
Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets.
Risks Related to Governmental Legislation and Regulation • We and our customers are subject to substantial environmental regulation, and changes in these regulations could increase our and their costs or liabilities and result in decreased demand for our services. 10 Table of Contents • New regulations, proposed regulations, and proposed modifications to existing regulations under the Clean Air Act, if implemented, could result in increased compliance costs.
Risks Related to Governmental Legislation and Regulation • We and our customers are subject to substantial environmental regulation, and changes in these regulations could increase our and their costs or liabilities and result in decreased demand for our services. • New regulations, proposed regulations, and proposed modifications to existing regulations under the Clean Air Act, if implemented, could result in increased compliance costs.
Any extended reduction in the demand for natural gas or crude oil could depress the level of production activity and result in a decline in the demand for our compression services, which could result in a reduction in our revenues and our cash available for distribution.
Any extended reduction in the demand for natural gas or crude oil could depress the level of production activity and result in a decline in the demand for our compression services, which has in the past and in the future could result in a reduction in our revenues and our cash available for distribution.
The loss of one of these key customers may have a greater effect on our financial results than for a company with a more diverse customer base. Our ten largest customers accounted for approximately 41%, 39%, and 38% of our total revenues for the years ended December 31, 2024, 2023, and 2022, respectively.
The loss of one of these key customers may have a greater effect on our financial results than for a company with a more diverse customer base. Our ten largest customers accounted for approximately 46%, 41%, and 39% of our total revenues for the years ended December 31, 2025, 2024, and 2023, respectively.
In addition, because we distribute all of our available cash, excluding prudent operating reserves, we may not grow as quickly as businesses that are able to reinvest their available cash to expand ongoing operations.
In addition, because we distribute all of our available cash, excluding prudent 15 Table of Contents operating reserves, we may not grow as quickly as businesses that are able to reinvest their available cash to expand ongoing operations.
This entitles the General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates, or our limited partners.
This entitles the General Partner to consider only the interests and factors that 24 Table of Contents it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates, or our limited partners.
For the year ended December 31, 2024, approximately 14% of our compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize our services following expiration of the primary term of their contracts. These customers can generally terminate their month-to-month compression services contracts on 30 days’ written notice.
For the year ended December 31, 2025, approximately 19% of our compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize our services following expiration of the primary term of their contracts. These customers can generally terminate their month-to-month compression services contracts on 30 days’ written notice.
We may issue additional limited partner interests without the approval of unitholders, subject to certain Preferred Unit approval rights, which would dilute unitholders’ existing ownership interests and may increase the risk that we will not have sufficient available cash to maintain or increase our per-common-unit distribution level.
We may issue additional limited partner interests without the approval of unitholders, which would dilute unitholders’ existing ownership interests and may increase the risk that we will not have sufficient available cash to maintain or increase our per-common-unit distribution level.
As of December 31, 2024, the General Partner and its affiliates (including Energy Transfer), beneficially own an aggregate of approximately 39% of our outstanding common units. Unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.
As of December 31, 2025, the General Partner and its affiliates (including Energy Transfer), beneficially own an aggregate of approximately 36% of our outstanding common units. Unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.
Severe financial problems encountered by our customers, suppliers, and vendors could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements.
Severe financial problems encountered by our customers, suppliers, and vendors could limit our ability to collect amounts owed to us, 17 Table of Contents or to enforce the performance of obligations owed to us under contractual arrangements.
For example, legislative, regulatory, or executive actions intended to reduce emissions of GHGs, such as the IRA 2022, could increase the cost of consuming crude oil and natural gas, or provide incentives to encourage alternative forms of energy, thereby potentially causing a reduction in the demand for crude oil and natural gas.
For example, legislative, regulatory, or executive actions intended to reduce emissions of GHGs could increase the cost of consuming crude oil and natural gas, or provide incentives to encourage alternative forms of energy, thereby potentially causing a reduction in the demand for crude oil and natural gas.
Conflicts of interest will arise between the General Partner and its owner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, the General Partner may favor its own interests and the interests of its owner over our interests and the interests of our unitholders.
Conflicts of interest will arise between the General Partner and its owner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of 23 Table of Contents interest, the General Partner may favor its own interests and the interests of its owner over our interests and the interests of our unitholders.
Energy Transfer owns and controls the General Partner and appoints all of the officers and a majority of the directors of the General Partner, some of whom also are officers and directors of Energy Transfer.
Energy Transfer owns and controls the General Partner and appoints all of the officers and directors of the General Partner, some of whom also are officers and directors of Energy Transfer.
Similarly, any claims, even if fully indemnified or insured, could negatively impact our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future.
Similarly, any claims, even if fully indemnified or insured, could negatively 19 Table of Contents impact our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future.
Cybersecurity breaches and other disruptions of our information systems could compromise our information and operations and expose us to liability, which would cause our business and reputation to suffer. We rely on our information technology infrastructure to process, transmit, and store electronic information critical to our business activities.
Cybersecurity breaches and other disruptions of our information systems, or those of our service providers, could compromise our information and operations and expose us to liability, which would cause our business and reputation to suffer. We rely on our information technology infrastructure to process, transmit, and store electronic information critical to our business activities.
In August 2022, the IRA 2022 was passed, which imposes a methane emissions charge on certain oil and gas facilities, including onshore petroleum and natural gas production facilities, that emit 25,000 metric tons or more of carbon dioxide equivalent gas per year and exceed certain 21 Table of Contents emissions thresholds.
In August 2022, the IRA 2022 was passed, which imposed a methane emissions charge on certain oil and gas facilities, including onshore petroleum and natural gas production facilities, that emit 25,000 metric tons or more of carbon dioxide equivalent gas per year and exceed certain emissions thresholds.
There is a risk that we could ultimately be liable for obligations relating to the CDM Acquisition for which indemnification is not available, which could materially adversely affect our business, results of operations, and cash flow.
There is a risk that we could ultimately be liable for obligations relating to the J-W Power Acquisition for which indemnification is not available, which could materially adversely affect our business, results of operations and cash flow.
Congress, and as discussed in detail in Item 1 “Business – Our Operations – Governmental Regulations”, the EPA has taken steps to adopt regulations controlling GHG emissions under its existing CAA authority.
Independent of the U.S. Congress, and as discussed in detail in Item 1 “Business – Our Operations – Governmental Regulations”, the EPA has taken steps to adopt regulations controlling GHG emissions under its existing CAA authority.
The Credit Agreement and the Indentures contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability to: • incur additional indebtedness; • pay dividends or make other distributions or repurchase or redeem equity interests; • prepay, redeem, or repurchase certain debt; • issue certain preferred units or similar equity securities; • make investments; • sell assets; • incur liens; • enter into transactions with affiliates; • alter the businesses we conduct; • enter into agreements restricting our subsidiaries’ ability to pay distributions; and • consolidate, merge, or sell all or substantially all of our assets. 16 Table of Contents In addition, the Credit Agreement contains certain operating and financial covenants that require us to maintain specified financial ratios and satisfy other financial condition tests.
The Credit Agreement and the Indentures contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability to: • incur additional indebtedness; • pay dividends or make other distributions or repurchase or redeem equity interests; • prepay, redeem, or repurchase certain debt; • issue certain preferred units or similar equity securities; • make investments; • sell assets; • incur liens; • enter into transactions with affiliates; • alter the businesses we conduct; • enter into agreements restricting our subsidiaries’ ability to pay distributions; and • consolidate, merge, or sell all or substantially all of our assets.
The general partner interest or the control of the General Partner may be transferred to a third party without unitholder consent. The General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the common unitholders.
The General Partner may transfer its general partner interest to a third-party in a merger or in a sale of all or substantially all of its assets without the consent of the common unitholders.
Common unitholders’ voting rights are further restricted by a provision of the Partnership Agreement providing that any units held by a person or group that owns 20% or more of such class of units then outstanding, other than, with respect to our common units, the General Partner, its affiliates, their direct transferees, and their indirect transferees approved by the General Partner (which approval may be granted in its sole discretion) and persons who acquired such common units with the prior approval of the General Partner, cannot vote on any matter.
Common unitholders’ voting rights are further restricted by a provision of the Partnership Agreement providing that any units held by a person or group that owns 20% or more of such class of units then outstanding, other than, with respect to our common units, the General Partner, its affiliates, their direct transferees, and their indirect transferees approved by the General Partner (which approval may be granted in its sole discretion) and persons who acquired such common units with the prior approval of the General Partner, cannot vote on any matter. 25 Table of Contents The general partner interest or the control of the General Partner may be transferred to a third-party without unitholder consent.
For example, as of December 31, 2024, two customers accounted for 12% and 11% of our trade accounts receivable, net balance, respectively. If these customers were to enter bankruptcy or failed to pay us, it could adversely affect our business, results of operations, financial condition, and cash flows.
For example, as of December 31, 2025 and 2024, one customer accounted for 12% and 11% of our trade accounts receivable, net balance, respectively. If this customer were to enter bankruptcy or failed to pay us, it could adversely affect our business, results of operations, financial condition, and cash flows.
Nonpayment and nonperformance by our customers, suppliers, or vendors could reduce our revenues, increase our expenses, and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows, and ability to make distributions to our unitholders.
We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, suppliers, or vendors could reduce our revenues, increase our expenses, and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows, and ability to make distributions to our unitholders.
For example, for the years ended December 31, 2024, 2023, and 2022, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 2, 42, and 15 compression units, respectively, representing approximately 1,260, 37,700, and 3,200 of aggregate horsepower, respectively, that previously were used to provide compression services in our business.
For example, for the years ended December 31, 2025, 2024, and 2023, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 28, 2, and 42 compression and treating units, respectively, representing approximately 19,005, 1,260, and 37,700 of aggregate horsepower, respectively, that previously were used to provide compression and treating services in our business.
Integration of assets acquired in future acquisitions with our existing business can be complex, time-consuming, and costly, particularly in the case of material acquisitions such as the CDM Acquisition, which significantly increased our size and expanded the geographic areas in which we operate.
Integration of assets acquired in past acquisitions or future acquisitions with our existing business can be complex, time-consuming, and costly, particularly in the case of material acquisitions such as the J-W Power Acquisition, which increased our size and expanded the geographic areas in which we operate.
For example, our customers could seek to preserve capital or reduce expenses by using lower-cost providers of compression services, not renewing month-to-month contracts, determining not to enter into any new compression service contracts, or seeking lower contract prices for our services.
Our customers could seek to preserve capital or reduce expenses by using lower-cost providers of compression services, not renewing month-to-month contracts, determining not to enter into any new compression service contracts, seeking lower contract prices for our services, or delaying or eliminating orders for the manufacture of compression units.
Also, recent activism directed at shifting funding away from companies with energy-related assets could result in a reduction of funding for the energy sector overall, which could have an adverse effect on our ability to obtain external financing as well as negatively affect the cost of, and terms for, financing to fund capital expenditures or other aspects of our business. 22 Table of Contents Increased attention to ESG matters and conservation measures may adversely impact our business.
Also, recent activism directed at shifting funding away from companies with energy-related assets could result in a reduction of funding for the energy sector overall, which could have an adverse effect on our ability to obtain external financing as well as negatively affect the cost of, and terms for, financing to fund capital expenditures or other aspects of our business.
Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from them with respect to that income. • If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced. • Tax gain or loss on the disposition of our common units could be more or less than expected. • Unitholders will be subject to limitation on their ability to deduct interest expense incurred by us. • Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units. • We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased.
Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from them with respect to that income. • If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced. • Unitholders will be subject to limitation on their ability to deduct interest expense incurred by us. • We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit 29 Table of Contents adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units. • As a result of investing in our common units, you will likely become subject to state and local taxes and income tax return filing requirements in jurisdictions where we operate or own or acquire properties.
The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units. • As a result of investing in our common units, you will likely become subject to state and local taxes and income tax return filing requirements in jurisdictions where we operate or own or acquire properties. • We may have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.
The Partnership Agreement does not limit the number or timing of additional limited partner interests that we may issue, including limited partner interests that are convertible into or senior to our common units, without the approval of our common unitholders as long as the newly issued limited partner interests are not senior to, or pari passu with, the Preferred Units.
The Partnership Agreement does not limit the number or timing of additional limited partner interests that we may issue, including limited partner interests that are convertible into or senior to our common units, without the approval of our common unitholders.
In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future. 26 Table of Contents Our issuance of additional common units, including pursuant to our DRIP, or other equity securities of equal or senior rank, such as additional preferred units, will have the following effects: • our existing common unitholders’ proportionate ownership interest in us will decrease; • our amount of cash available for distribution to common unitholders may decrease; • the relative voting strength of each previously outstanding common unit may be diminished; and • the market price of our common units may decline.
Our issuance of additional common units, including pursuant to our DRIP, or other equity securities of equal or senior rank, such as additional preferred units, will have the following effects: • our existing common unitholders’ proportionate ownership interest in us will decrease; • our amount of cash available for distribution to common unitholders may decrease; • the relative voting strength of each previously outstanding common unit may be diminished; and • the market price of our common units may decline.
As a result, we recorded impairments of compression equipment of $0.3 million, $12.3 million, and $1.5 million for the years ended December 31, 2024, 2023, and 2022, respectively.
As a result, we recorded impairments of compression and treating equipment of $7.8 million, $0.3 million, and $12.3 million for the years ended December 31, 2025, 2024, and 2023, respectively.
Disruptions to our systems or operations caused by the implementation may have a material adverse impact on us. • Our customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, increasing the number of compression units they currently own, or using alternative technologies for enhancing crude oil production, which could result in a decrease in our revenues and cash available for distribution to unitholders. • A significant portion of our services are provided to customers on a month-to-month basis, and we cannot be sure that such customers will continue to utilize our services.
The loss of any of these customers would result in a decrease in our revenues and cash available for distribution. • We face significant competition that may cause us to lose market share and reduce our cash available for distribution. • Our customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, increasing the number of compression units they currently own, or using alternative technologies for enhancing crude oil production, which could result in a decrease in our revenues and cash available for distribution to unitholders. • A significant portion of our services are provided to customers on a month-to-month basis, and we cannot be sure that such customers will continue to utilize our services.
Based on our December 31, 2024, variable-rate indebtedness outstanding, a one percent increase in the effective interest rate would result in an annual increase in our interest expense of approximately $7.7 million.
Based on our December 31, 2025, variable-rate indebtedness 14 Table of Contents outstanding, a one percent increase in the effective interest rate would result in an annual increase in our interest expense of approximately $8.0 million.
As of December 31, 2024, we had outstanding borrowings under the Credit Agreement of $772.1 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $827.1 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $782.5 million was available to be drawn.
As of December 31, 2025, we had outstanding borrowings under the Credit Agreement of $795.0 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $954.2 million of remaining unused availability, all of which was available to be drawn, inclusive of restrictions related to compliance with applicable financial covenants.
Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business. These events could cause us to record impairments of identifiable intangible assets.
We have recorded $186.9 million of identifiable intangible assets, net, as of December 31, 2025. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business. These events could cause us to record impairments of identifiable intangible assets.
A discontinuation of our services by a significant number of these customers could have a material adverse effect on our business, results of operations, financial condition, and cash available for distribution. • Our debt level, including any increases in interest rates, may limit our flexibility in obtaining additional financing, pursuing other business opportunities, and paying distributions. • We depend on a limited number of suppliers and are vulnerable to product shortages and price increases, which could have a negative impact on our results of operations. • We may be unable to grow our cash flows if we are unable to expand our business, which could limit our ability to maintain or increase the level of distributions to our common unitholders. • Our ability to fund purchases of additional compression units and expansion capital expenditures in the future is dependent on our ability to access external capital, and if we are unable to access this external capital, we may be limited in our ability to grow our operations or maintain or increase our distributions.
A discontinuation of our services by a significant number of these customers could have a material adverse effect on our business, results of operations, financial condition, and cash available for distribution. • Our debt level, including any increases in interest rates, may limit our flexibility in obtaining additional financing, pursuing other business opportunities, and paying distributions. • We depend on a limited number of suppliers and are vulnerable to product shortages and price increases, which could have a negative impact on our results of operations. • We may be unable to grow our cash flows if we are unable to expand our business, which could limit our ability to maintain or increase the level of distributions to our common unitholders. 10 Table of Contents • Our ability to fund purchases of additional compression units and expansion capital expenditures in the future is dependent on our ability to access external capital, and if we are unable to access this external capital, we may be limited in our ability to grow our operations or maintain or increase our distributions. • Integration of assets acquired in past acquisitions or future acquisitions with our existing business can be complex, time-consuming, and costly, particularly in the case of material acquisitions such as the J-W Power Acquisition, which increased our size and expanded the geographic areas in which we operate.
Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations. Such ESG matters also may impact our customers or suppliers, which may adversely impact our business, financial condition, or results of operations.
Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.
The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove the General Partner, and Energy Transfer currently owns over 33 1/3% of our outstanding common units.
The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove the General Partner, and Energy Transfer currently owns approximately 32% of our outstanding common units, making any effort to remove the General Partner difficult.
To make cash distributions at our current distribution rate of $0.525 per common unit per quarter, or $2.10 per common unit per year, we will require available cash of $61.7 million per quarter, or $246.8 million per year, based on the number of common units outstanding as of February 6, 2025.
To make cash distributions at our current distribution rate of $0.525 per common unit per quarter, or $2.10 per common unit per year, we will require available cash of $76.1 million per quarter, or $304.4 million per year, based on the number of common units outstanding as of February 12, 2026.
We performed due diligence in connection with the CDM Acquisition and attempted to verify the representations made by Energy Transfer in connection therewith, but there may be unknown and contingent liabilities of which we are currently unaware.
The J-W Power Acquisition could expose us to additional unknown and contingent liabilities. We performed due diligence in connection with the J-W Power Acquisition and attempted to verify the representations made by J-W Power, J-W Energy, and Westerman, Ltd. in connection therewith, but there may be unknown and contingent liabilities of which we are currently unaware.
Although it is not currently possible to predict with specificity how the IRA 2022 or any proposed or future GHG legislation, regulation, agreements, or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate, including a carbon tax or cap-and-trade program, could result in increased compliance or operating costs, additional operating restrictions, or reduced demand for our services, and could have a material adverse effect on our business, financial condition, and results of operations.
Although it is not currently possible to predict with specificity how any proposed or future GHG legislation, regulation, agreements, or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate, including a carbon tax or cap-and-trade program, could result in increased compliance or operating costs, additional operating restrictions, or reduced demand for our services, and could have a material adverse effect on our business, financial condition, and results of operations. 21 Table of Contents Climate change may increase the frequency and severity of weather events that could result in severe personal injury, property damage, and environmental damage, which could curtail our or our customers’ operations and otherwise materially adversely affect our cash flows.
For tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. Our U.S.
If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. Our U.S. Federal income tax returns for years 2019 and 2020 are currently under examination by the IRS.
If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or if we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced. • The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial, or administrative changes or differing interpretations, possibly applied on a retroactive basis. • Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.
If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or if we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced. • Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.
There are no limitations in the Partnership Agreement on our ability to issue additional equity securities, including securities ranking senior to the common units, subject to certain restrictions in the Partnership Agreement limiting our ability to issue units senior to or pari passu with the Preferred Units.
There are no limitations in the Partnership Agreement on our ability to issue additional equity securities, including securities ranking senior to the common units.
Our “business interest” has been subject to limitation under these rules by $105.5 million and $95.1 million for tax years 2023 and 2022, respectively. As a result, our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us and allocated to them.
Our “business interest” has been subject to limitation under these rules in prior tax years, and may be subject to limitations in the future. As a result, our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us and allocated to them.
Energy Transfer has agreed to indemnify us for losses or claims relating to the operation of the business or otherwise only to a limited extent and for a limited period of time, and certain of Energy Transfer’s indemnification obligations have lapsed.
Westerman, Ltd. has agreed to indemnify us for losses or claims relating to the operation of the business or otherwise only to a limited extent and for a limited period of time.
Energy Transfer may sell, and the holders of the Preferred Units have sold and may continue to sell, our common units in the public or private markets, and such sales could have an adverse impact on the trading price of our common units. As of February 6, 2025, Energy Transfer beneficially owns an aggregate of 46,056,228 common units in us.
Energy Transfer and Westerman, Ltd. may sell our common units in the public or private markets, and such sales could have an adverse impact on the trading price of our common units. As of February 12, 2026, Energy Transfer beneficially owns an aggregate of 46,056,228 common units and Westerman, Ltd. owns an aggregate of 18,175,323 of our common units.
This could result in significant disruptions or require a disproportionate amount of our management’s attention, and may result in unforeseen 13 Table of Contents operational or administrative difficulties or costs. We may encounter significant delays to this integration, which would further exacerbate these effects.
Integrating these functions with Energy Transfer has required, and will continue to require, substantial time, resources, and coordination. This could result in significant disruptions or require a disproportionate amount of our management’s attention, and may result in unforeseen operational or administrative difficulties or costs. We may encounter significant delays to this integration, which would further exacerbate these effects.
Liabilities to partners on account of their interest in the Partnership and liabilities that are nonrecourse to the Partnership are not counted for purposes of determining whether a distribution is permissible. 27 Table of Contents Our Partnership Agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers, or other employees.
Our Partnership Agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers, or other employees.
Accordingly, unitholders do not have the same protections afforded to investors in certain corporations that are subject to all of the NYSE corporate governance requirements. Please read Part III, Item 10 “Directors, Executive Officers, and Corporate Governance”. Tax Risks to Common Unitholders Our tax treatment depends on our status as a partnership for federal income tax purposes.
Accordingly, unitholders do not have the same protections afforded to investors in certain corporations 27 Table of Contents that are subject to all of the NYSE corporate governance requirements. Please read Part III, Item 10 “Directors, Executive Officers, and Corporate Governance”.
Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our units. We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
We may be unable to grow successfully through acquisitions, which may negatively impact our operations and limit our ability to maintain or increase the level of distributions on our common units. From time to time, we may choose to make business acquisitions to pursue market opportunities, increase our existing capabilities, and expand into new geographic areas of operations.
We may be unable to grow successfully through acquisitions, which may negatively impact our operations and limit our ability to maintain or increase the level of distributions on our common units.
Our ability to grow or even to continue our current level of service to our current customers could be adversely impacted if we are unable to successfully hire, train, and retain these important personnel.
Our ability to grow or even to continue our current level of service to our current customers could be adversely impacted if we are unable to successfully hire, train, and retain these important personnel. Implementing the shared services model with Energy Transfer has been and will continue to be a complex and time-consuming process.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeFor additional information on cybersecurity risks, see Part I, Item 1A “Risk Factors – General Risk Factors –Cybersecurity breaches and other disruptions of our information systems could compromise our information and operations and expose us to liability, which would cause our business and reputation to suffer.” Board of Directors’ Oversight and Management’s Role Under the shared services cybersecurity program, Energy Transfer’s Chief Information Officer oversees the functions of IT, cybersecurity, infrastructure and IT governance (including the Energy Transfer IT team) and has more than 35 years of experience leading business technology functions.
Biggest changeFor additional information on cybersecurity risks, see Part I, Item 1A “Risk Factors – General Risk Factors –Cybersecurity breaches and other disruptions of our information systems, or those of our service providers, could compromise our information and operations and expose us to liability, which would cause our business and reputation to suffer.” Board of Directors’ Oversight and Management’s Role Under the shared services cybersecurity program, Energy Transfer’s Chief Information Officer is responsible for assessing and managing our material risks from cybersecurity threats, including cybersecurity threat prevention, detection, mitigation and remediation, and oversees the functions of IT, cybersecurity, infrastructure and IT governance (including the IT team).
A successful attack on our information system or operational technology system could have significant consequences to the business, including the interruption of key services that our customers depend on. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security.
A successful attack on our information system or operational technology system could have significant consequences to our business, including the interruption of key services that our customers depend on. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security.
Employees are required to use multifactor authentication and keep their passwords confidential, among other measures. We recognize that third-party service providers may introduce cybersecurity risks. In an effort to mitigate these risks, before contracting with certain technology services providers, when possible, we conduct due diligence to evaluate their cybersecurity capabilities.
Employees are required to use multifactor authentication and keep their passwords confidential, among other measures. We recognize that third-party service providers may introduce cybersecurity risks. In an effort to mitigate these risks, before contracting with certain technology service providers, when possible, we conduct due diligence to evaluate their cybersecurity capabilities.
Our cyber incident response plan requires IT team members who detect suspicious activity in our IT environment to escalate that activity to a supervisor who then evaluates the threat. If necessary, the suspicious activity is reported to Energy Transfer’s Chief Information Officer, if applicable.
Our cyber incident response plan requires IT team members who detect suspicious activity in our IT environment to escalate that activity to a supervisor who then evaluates the threat. If necessary, the suspicious activity is reported to Energy Transfer’s Chief Information Officer.
Impact of Risks from Cybersecurity Threats As of the date of this Annual Report on Form 10-K, though the Partnership and our service providers have experienced certain cybersecurity incidents, we are not aware of any previous cybersecurity threats that have materially affected, or are reasonably likely to materially affect, the Partnership, either financially or operationally.
As of the date of this Annual Report on Form 10-K, though the Partnership and our service providers have experienced certain cybersecurity incidents, we are not aware of any cybersecurity threats that have materially affected, or are reasonably likely to materially affect, the Partnership, either financially or operationally.
The members of the Energy Transfer IT team have over 50 years of combined experience in the field of IT, including 20 years dedicated to cybersecurity, and hold various certifications, including Global Industrial Cyber Security Professional (GICSP), Certified Information Systems Security Professional (CISSP) and Certified Ethical Hacker (CEH) certifications. Our internal cybersecurity program is led by USAC’s IT department.
The members of the IT team have over 50 years of combined experience in the field of IT, including 20 years dedicated to cybersecurity, and hold various certifications, including Global Industrial Cyber Security Professional (GICSP), Certified Information Systems Security Professional (CISSP) and Certified Ethical Hacker (CEH) certifications.
It uses various processes as part of its efforts to maintain the confidentiality, integrity and availability of our systems, including security threat intelligence, incident response, identity and access management, supply-chain security assessments, endpoint extended detection and response protection, network segmentation, data encryption, event monitoring and a Security Operations Center (SOC). Our internal cybersecurity program is led by USAC’s IT department.
Through this cybersecurity program, we use various processes as part of our efforts to maintain the confidentiality, integrity and availability of our systems, including security threat intelligence, incident response, identity and access management, supply-chain security assessments, endpoint extended detection and response protection, network segmentation, data encryption, event monitoring and a Security Operations Center (SOC).
Our IT leadership provides periodic cybersecurity program updates to senior management and to the 34 Table of Contents Audit Committee. Management also updates the Audit Committee as new risks are identified and the steps taken to mitigate such risks.
The IT team provides periodic cybersecurity program updates to senior management and to the Audit Committee. Management also updates the Audit Committee as new risks are identified and regarding the steps taken to mitigate such risks. The Audit Committee reviews periodic reporting and updates regarding our cybersecurity risk management.
The shared services cybersecurity program seeks to use a defense-in-depth approach for cybersecurity management, layers of technology, policies and training at all levels of the enterprise designed to keep our assets secure and operational.
Coast Guard (USCG), the shared services cybersecurity program seeks to follow industry cybersecurity standards and protect our infrastructure against cyber attacks from domestic and international threats. The shared services cybersecurity program seeks to use a defense-in-depth approach for cybersecurity management, layers of technology, policies and training at all levels of the enterprise designed to keep our assets secure and operational.
In the normal course of business, we may collect and store certain sensitive information of the Partnership, including proprietary and confidential business information, trade secrets, intellectual property, sensitive third-party and employee information, and certain personally identifiable information.
In the normal course of business, we may collect and store certain sensitive information of the Partnership, including proprietary and confidential business information, trade secrets, intellectual property, sensitive third-party and employee information, and certain personally identifiable information. We are part of Energy Transfer’s shared services cybersecurity program for assessing, identifying and managing material risks from cybersecurity threats.
Management (including representatives from the legal, human resources and IT departments) is notified by the IT team whenever a discovered cybersecurity incident may potentially have a significant impact on us or our customers. Our Audit Committee is ultimately responsible for assessing and managing the Partnership’s material risks from cybersecurity threats.
Management (including representatives from the legal, human resources, IT and, as appropriate, ET’s corporate security department) is notified by the IT team whenever a discovered cybersecurity incident may potentially have a significant impact on our business operations. Our Audit Committee is responsible for the oversight of cybersecurity risks.
In an effort to validate the effectiveness of our cybersecurity programs and assess such program’s compliance with legal and regulatory requirements, we engage third-party service providers to perform audits, assessments, and penetration tests. These partnerships enable us to access specialized knowledge and insights which we leverage to continuously improve and modernize our cybersecurity programs.
In an effort to validate the effectiveness of our cybersecurity program and assess such program’s compliance with legal and regulatory requirements, we and the IT team engage third-party service providers to perform audits, assessments, and penetration tests. Cybersecurity awareness among our employees is promoted with regular training and awareness programs.
All employees who have access to our systems are required to undergo cybersecurity training at least annually and, under the shared services cybersecurity program, our employees will be required to review and acknowledge our cybersecurity policies each year. User access controls have been implemented to limit unauthorized access to sensitive information and critical systems.
All employees who have access to our systems are required to undergo annual cybersecurity training and, each year, our employees must review and acknowledge our cybersecurity policies. Further, the IT team is trained to understand how to manage, use and protect personally identifiable information. User access controls have been implemented to limit unauthorized access to sensitive information and critical systems.
This program includes processes that are modeled after the National Institute of Standards and Technology’s Cybersecurity Framework and focuses on using business drivers to guide cybersecurity activities.
This program includes processes that are modeled after the National Institute of Standards and Technology’s Cybersecurity Framework and focuses on using business drivers to guide cybersecurity activities. This program is managed by Energy Transfer’s Chief Information Officer, who is supported by a team of full-time employees tasked with conducting day-to-day information technology (“IT”) operations (collectively, the “IT team”).
In creating and implementing this cybersecurity program, the Energy Transfer IT team engages with the guidance of the Federal Bureau of Investigation (FBI), Cybersecurity and Infrastructure Security Agency (CISA), Transportation Security Administration (TSA) and the U.S. Coast Guard (USCG).
Furthermore, we consider cybersecurity risks as part of, and have incorporated the shared services cybersecurity program into, our overall risk management processes. Through engagement with the guidance of the Federal Bureau of Investigation (FBI), Cybersecurity and Infrastructure Security Agency (CISA), Transportation Security Administration (TSA) and the U.S.
Removed
As part of the shared services integration with Energy Transfer, we are transitioning to a shared services cybersecurity program for assessing, identifying and managing material risks from cybersecurity threats.
Added
Additionally, the IT team endeavors to include cybersecurity requirements in contracts with technology service providers under the shared services model and endeavors to require them to adhere to security standards and protocols.
Removed
As we are in the midst of that transition, currently certain of our information systems are operating under the shared services cybersecurity program, while certain other information systems remain under our internal USAC cybersecurity program. We expect that once the shared services implementation is complete, all of our information systems will operate under the shared services cybersecurity program.
Added
Further, the IT team also endeavors to engage with any third-party service providers under the shared services model with access to personally identifiable employee information to evaluate their security controls. Finally, Energy Transfer maintains cybersecurity insurance coverage, which coverage extends to us.
Removed
The shared services cybersecurity program is managed by a team of full-time Energy Transfer employees, overseen by its Chief Information Officer, that are tasked with conducting day-to-day information technology (“IT”) operations (collectively, the “Energy Transfer IT team”).
Added
Impact of Risks from Cybersecurity Threats The energy industry’s increasing dependence on information technology and operational technology to support critical functions has heightened its vulnerability to cybersecurity incidents. Consequently, the global surge in cybersecurity incidents, whether caused by intentional attacks or accidental events, presents a significant challenge to our sector.
Removed
USAC’s internal cybersecurity program is designed to align with the National Institute of Standards and Technology’s Cybersecurity Framework. USAC’s IT department stays informed of current developments in cybersecurity threats, including incidents or issues that may arise involving our third-party 33 Table of Contents service providers, and preventative measures and continuously updates our cybersecurity program based on this knowledge.
Added
As cybersecurity threats grow in complexity and scale, preventing, detecting, mitigating and remediating these incidents remains a continuous and increasingly demanding task for the industry. Compliance with evolving cybersecurity reporting requirements presents significant challenges. These regulations necessitate timely and detailed reporting of cyber incidents, demanding substantial resources and robust internal processes to ensure adherence.
Removed
It utilizes industry-leading security tools and regularly performs security risk assessments and tool reviews with independent third parties to evaluate program effectiveness, and regularly updates our security roadmap. USAC’s IT department monitors industry news and updates to stay aware of the cybersecurity landscape, including incidents or issues that may arise involving USAC’s third-party service providers.
Added
Failure to comply could result in legal penalties, increased regulatory scrutiny and reputational damage. Moreover, the dynamic nature of these requirements may lead to overlapping or 33 Table of Contents inconsistent obligations, further complicating compliance efforts. Monitoring these developments and integrating them into our cybersecurity and compliance frameworks is essential to mitigate potential risks.
Removed
We have integrated cybersecurity risk management into our overall risk management system, ensuring that cybersecurity risks are taken into consideration when managing business objectives and operational needs. Cybersecurity awareness among our employees is promoted with regular training and awareness programs.
Added
Additionally, we are in the process of integrating the assets and operations we acquired in the J-W Power Acquisition, and until these assets and operations are fully integrated into our information systems, they may have incomplete cybersecurity controls applied.
Removed
Additionally, we endeavor to require these providers to adhere to our security standards and protocols.
Added
Energy Transfer’s Chief Information Officer has more than 35 years of experience leading business technology functions. The IT team supports the Chief Information Officer in our efforts to comply with applicable cybersecurity standards, establish effective cybersecurity protocols and protect the integrity, confidentiality and availability of our IT infrastructure.
Removed
The members of our IT leadership team have an average of over 25 years of experience in IT operations and over 10 years of experience in IT security, including cybersecurity risk identification and mitigation.

Item 2. Properties

Properties — owned and leased real estate

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Biggest changeITEM 2. Properties We do not currently own or lease any material facilities or properties for storage or maintenance of our compression units. As of December 31, 2024, our headquarters consisted of leased office space located at 8117 Preston Road, Dallas, Texas 75225.
Biggest changeITEM 2. Properties As of December 31, 2025, we did not own or lease any material facilities or properties for storage or maintenance of our compression units. Our headquarters consists of leased office space located at 8115 Preston Road, Suite 700, Dallas, Texas 75225.
Added
As a result of the J-W Power Acquisition, we acquired two manufacturing facilities for the fabrication of compression units located in Longview, Texas and Kilgore, Texas.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeSee Note 17 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report for more information on certain of these proceedings. ITEM 4. Mine Safety Disclosures None. 35 Table of Contents PART II
Biggest changeSee Note 17 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report for more information on certain of these proceedings. ITEM 4. Mine Safety Disclosures None. 34 Table of Contents PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeOur common units, which represent limited partner interests in us, are listed on the NYSE under the symbol “USAC.” There is no established public trading market for the Preferred Units, all of which are owned by the Preferred Unitholders.
Biggest changeOur common units, which represent limited partner interests in us, are listed on the NYSE under the symbol “USAC.” Holders At the close of business on February 12, 2026, based on information received from the transfer agent of the common units, we had 65 holders of record of our common units.
Issuer Purchases of Equity Securities None. Sales of Unregistered Securities; Use of Proceeds from Sale of Securities None. 36 Table of Contents Equity Compensation Plan For disclosures regarding securities authorized for issuance under equity compensation plans, see Part III, Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters”. ITEM 6. [RESERVED]
Issuer Purchases of Equity Securities None. Sales of Unregistered Securities; Use of Proceeds from Sale of Securities None. Equity Compensation Plan For disclosures regarding securities authorized for issuance under equity compensation plans, see Part III, Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters”. ITEM 6. [RESERVED]
Available Cash The Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date, first to the holders of the Preferred Units and then to the common unitholders.
Available Cash The Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.
ITEM 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Our Partnership Interests As of February 6, 2025, we had 117,528,971 common units outstanding. Energy Transfer owns 100% of the membership interests in the General Partner and, as of February 6, 2025, beneficially owns approximately 39% of our outstanding common units.
ITEM 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Our Partnership Interests As of February 12, 2026, we had 144,972,358 common units outstanding. Energy Transfer owns 100% of the membership interests in the General Partner and, as of February 12, 2026, beneficially owns approximately 32% of our outstanding common units.
Removed
As of February 6, 2025, we had 180,000 Preferred Units outstanding representing limited partner interests in the Partnership, all of which were held by EIG Veteran Equity Aggregator LP and FSSL Finance BB AssetCo LLC (collectively, the “Preferred Unitholders”). The Preferred Units rank senior to our common units with respect to distributions and liquidation rights.
Removed
The holders of the Preferred Units are entitled to receive cumulative quarterly cash distributions equal to $24.375 per Preferred Unit. The Preferred Units are convertible, at the option of the holder, into common units in accordance with the terms of our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).
Removed
We have the option to redeem all or any portion of the Preferred Units outstanding, subject to certain minimum redemption threshold amounts, for a redemption price set forth in the Partnership Agreement.
Removed
On or after April 2, 2028, each holder of the Preferred Units will have the right to require us to redeem all or a portion of their Preferred Units, subject to certain minimum redemption threshold amounts, for a redemption price set forth in the Partnership Agreement, which we may elect to pay up to 50% in common units, subject to certain additional limits.
Removed
Please read Part II, Item 8 “Financial Statements and Supplementary Data – Note 11 – Preferred Units and – Note 12 – Partners’ Deficit”. Holders At the close of business on February 6, 2025, based on information received from the transfer agent of the common units, we had 67 holders of record of our common units.

Item 7. Management's Discussion & Analysis

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

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Biggest changeThe Partnership also must maintain, on a consolidated basis, as of the last day of each fiscal quarter a Total Leverage Ratio (as defined in the Credit Agreement) of not greater than 5.25 to 1.00 (except that the Partnership may increase the applicable Total Leverage Ratio by 0.25 for any fiscal quarter during which a Specified Acquisition (as defined in the Credit Agreement) occurs and the following two fiscal quarters, but in no event shall the maximum Total Leverage Ratio exceed 5.50 to 1.00 for any fiscal quarter as a result of such increase); an Interest Coverage Ratio (as defined in the Credit Agreement) of not less than 2.50 to 1.00; and a Secured Leverage Ratio (as defined in the Credit Agreement) of not greater than 3.00 to 1.00 or less than 0.00 to 1.00.
Biggest changeAmounts borrowed and repaid under the Credit Agreement may be re-borrowed, subject to borrowing base availability. 43 Table of Contents The Credit Agreement also contains various financial covenants, including covenants requiring us to maintain: • a minimum EBITDA to interest coverage ratio of 2.50 to 1.00, determined as of the last day of each fiscal quarter, with EBITDA and interest expense annualized for the most-recent fiscal quarter; • a ratio of total secured indebtedness to EBITDA not greater than 3.00 to 1.00 or less than 0.00 to 1.00, determined as of the last day of each fiscal quarter, with EBITDA annualized for the most-recent fiscal quarter; and • a funded debt-to-EBITDA ratio, defined in the Credit Agreement as the Total Leverage Ratio, determined as of the last day of each fiscal quarter with EBITDA annualized for the most-recent fiscal quarter, of not greater than 5.50 to 1.00 or less than 0.00 to 1.00.
The remainder of unit-based compensation expense for all periods was related to non-cash adjustments to the unit-based compensation liability. (2) Represents certain expenses related to potential and completed transactions and other items. We believe it is useful to investors to exclude these expenses.
The remainder of unit-based compensation expense for all periods was related to non-cash adjustments to the unit-based compensation liability. (2) Represents certain expenses related to potential and completed transactions and other items. We believe it is useful to investors to exclude these expenses.
This amount represents the write-off of deferred financing costs of $4.3 million and the difference between (i) the purchase price of U.S. government securities of $748.8 million and (ii) the aggregate outstanding principal balance and accrued interest of the Senior Notes 2026 of $748.1 million at the time of Defeasance.
This amount represents the write-off of deferred financing costs of $4.3 million and the difference between (i) the purchase price of U.S. government securities of $748.8 million and (ii) the aggregate outstanding principal balance and accrued interest of the Senior Notes 2026 of $748.1 million at the time of Defeasance.
The primary circumstances supporting these impairments were: (i) unmarketability of certain compression units into the foreseeable future, (ii) excessive maintenance costs associated with certain fleet assets, and (iii) prohibitive retrofitting costs that likely would prevent certain compression units from securing customer acceptance. These compression units were written down to their estimated salvage values, if any.
The primary circumstances supporting these impairments were: (i) unmarketability of certain compression units into the foreseeable future, (ii) excessive maintenance costs associated with certain fleet assets, and (iii) prohibitive retrofitting costs that likely would prevent certain compression units from securing customer acceptance. These compression and treating units were written down to their estimated salvage values, if any.
We deliver natural gas compression services in connection with domestic natural gas production that primarily occurs in natural gas basins, such as the Marcellus, Utica, and Haynesville Shales, and in crude oil basins where “associated” natural gas is produced alongside crude oil, such as in the Permian and Denver-Julesburg Basins, Eagle Ford, and the Mid-Continent.
We deliver natural gas compression services in connection with domestic natural gas production that primarily occurs in natural gas basins, such as the Marcellus, Utica, and Haynesville Shales, and in crude oil basins where “associated” natural gas is produced alongside crude oil, such as in the Permian and Denver-Julesburg Basins, Eagle Ford, Bakken and the Mid-Continent.
The increases in revenue-generating horsepower, average horsepower per revenue-generating compression unit, horsepower utilization, and horsepower utilization based on revenue-generating horsepower and fleet horsepower as of and for the year ended December 31, 2024, compared to December 31, 2023, primarily were driven by the addition and deployment of new, and redeployment of existing, large-horsepower compression units due to increased demand for our services consistent with an overall increase in crude oil and natural gas produced within the U.S.
The increases in revenue-generating horsepower, average horsepower per revenue-generating compression unit, and average horsepower utilization based on revenue-generating horsepower and fleet horsepower as of and for the year ended December 31, 2025, compared to December 31, 2024, primarily were driven by the addition and deployment of new, and redeployment of existing, large-horsepower compression units due to increased demand for our services consistent with an overall increase in crude oil and natural gas produced within the U.S.
However, we continue to believe that overall, the long-term demand for our compression services will continue given the necessity of compression in facilitating the transportation and processing of natural gas as well as the production of crude oil. 38 Table of Contents Operating Highlights The following table summarizes certain horsepower and horsepower-utilization percentages for the periods presented and excludes certain gas-treating assets for which horsepower is not a relevant metric.
However, we continue to believe that overall, the long-term demand for our compression services will continue given the necessity of compression in facilitating the transportation and processing of natural gas as well as the production of crude oil. 37 Table of Contents Operating Highlights The following table summarizes certain horsepower and horsepower-utilization percentages for the periods presented and excludes certain gas-treating assets for which horsepower is not a relevant metric.
If our current cash flow projections prove to be inaccurate, we expect to be able to remain in compliance with such financial covenants by taking one or more of the following actions: issue equity in a public or private offering; request a modification of our covenants from 44 Table of Contents our bank group; reduce distributions from our current distribution rate or suspend distributions altogether; delay discretionary capital spending and reduce operating expenses; or obtain an equity infusion pursuant to the terms of the Credit Agreement.
If our current cash flow projections prove to be inaccurate, we expect to be able to remain in compliance with such financial covenants by taking one or more of the following actions: issue equity in a public or private offering; request a modification of our covenants from our bank group; reduce distributions from our current distribution rate or suspend distributions altogether; delay discretionary capital spending and reduce operating expenses; or obtain an equity infusion pursuant to the terms of the Credit Agreement.
(4) Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows. (5) Reflects actual maintenance capital expenditures for the period presented.
(5) Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows. (6) Reflects actual maintenance capital expenditures for the period presented.
We define Adjusted EBITDA as EBITDA plus impairment of assets, impairment of goodwill, interest income on capital leases, unit-based compensation expense (benefit), severance charges, certain transaction expenses, loss (gain) on disposition of assets, loss on extinguishment of debt, loss (gain) on derivative instrument, and other.
We define Adjusted EBITDA as EBITDA plus impairment of assets, impairment of goodwill, interest income on capital leases, unit-based compensation expense (benefit), severance charges and other employee costs, certain transaction expenses, loss (gain) on disposition of assets, loss on extinguishment of debt, loss (gain) on derivative instrument, and other.
(4) Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows. 47 Table of Contents Distributable Cash Flow We define DCF as net income (loss) plus non-cash interest expense, non-cash income tax expense (benefit), depreciation and amortization expense, unit-based compensation expense (benefit), impairment of assets, impairment of goodwill, certain transaction expenses, severance charges, loss (gain) on disposition of assets, loss on extinguishment of debt, change in fair value of derivative instrument, proceeds from insurance recovery, and other, less distributions on Preferred Units and maintenance capital expenditures.
(5) Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows. 46 Table of Contents Distributable Cash Flow We define DCF as net income (loss) plus non-cash interest expense, non-cash income tax expense (benefit), depreciation and amortization expense, unit-based compensation expense (benefit), impairment of assets, impairment of goodwill, certain transaction expenses, severance charges and other employee costs, loss (gain) on disposition of assets, loss on extinguishment of debt, change in fair value of derivative instrument, proceeds from insurance recovery, and other, less distributions on Preferred Units and maintenance capital expenditures.
Liquidity and Capital Resources Overview We operate in a capital-intensive industry, and our primary liquidity needs include financing the purchase of additional compression units, making other capital expenditures, servicing our debt, funding working capital, and paying cash distributions on our outstanding preferred and common equity.
Liquidity and Capital Resources Overview We operate in a capital-intensive industry, and our primary liquidity needs include financing the purchase of additional compression units, making other capital expenditures, servicing our debt, funding working capital, and paying cash 41 Table of Contents distributions on our outstanding preferred and common equity.
The $82.7 million increase in contract operations revenue for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) an 8.3% increase in average revenue per revenue-generating horsepower per month, as a result of higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit, (ii) a 6.0% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with an overall increase in crude oil and natural gas produced within the U.S., partially offset by (iii) an $8.9 million decrease in revenue attributable to natural gas treating services.
The $26.7 million increase in contract operations revenue for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) a 4.7% increase in average revenue per revenue-generating horsepower per month, as a result of higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit, (ii) a 0.9% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with an overall increase in crude oil and natural gas produced within the U.S., partially offset by (iii) a $7.8 million decrease in revenue attributable to natural gas treating services activity.
Once a final partnership imputed underpayment, if any, is determined, our General Partner may elect to either pay the imputed underpayment (including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised information statement to each unitholder, and former unitholder, with respect to an audited and adjusted return.
Once determined, our General Partner may elect to either pay the imputed underpayment, if any, (including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised information statement to each unitholder, or former unitholder as applicable, with respect to an audited and adjusted return.
Over the past several years, increased natural gas production in the U.S., driven by large volumes of associated gas produced from shale sources, has been a major driver of an overall decline in natural gas prices.
Over the past several years, increased natural gas production in the U.S., driven by large volumes of associated gas produced from shale sources, has been a major driver in natural gas prices.
The EIA Outlook expects dry natural gas production to increase by 1.4 billion cubic feet per day (“bcf/d”) in 2025 and by 2.7 bcf/d in 2026, resulting in record dry natural gas production each year. Significant demand for natural gas is driven by domestic power generation which has benefited from a lower-price environment.
The EIA Outlook expects dry natural gas production to increase by 1.4 billion cubic feet per day (“bcf/d”) in 2026 and by 0.9 bcf/d in 2027, resulting in record dry natural gas production each year. Significant demand for natural gas is driven by domestic power generation which has benefited from a lower-price environment.
We classify capital expenditures as maintenance or expansion on an individual-asset basis. Over the long term, we expect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleet increases. Our aggregate maintenance capital expenditures for the years ended December 31, 2024 and 2023, were $31.9 million and $25.2 million, respectively.
We classify capital expenditures as maintenance or expansion on an individual-asset basis. Over the long term, we expect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleet increases. Our aggregate maintenance capital expenditures for the years ended December 31, 2025 and 2024, were $39.4 million and $31.9 million, respectively.
The $30.6 million decrease in net cash used in investing activities for the year ended December 31, 2024, compared to the year ended December 31, 2023, was due to (i) a $33.7 million decrease in capital expenditures, for purchases of new compression units, overhauls and major improvements, and purchases of other equipment, and (ii) a $1.0 million increase in proceeds from insurance recovery, partially offset by (iii) a $4.0 million decrease in proceeds from disposition of property and equipment.
The $87.1 million decrease in net cash used in investing activities for the year ended December 31, 2025, compared to the year ended December 31, 2024, was due to (i) an $87.6 million decrease in capital expenditures, for purchases of new compression units, overhauls and major improvements, and purchases of other equipment, and (ii) a $0.9 million increase in proceeds from disposition of property and equipment, partially offset by (iii) a $1.4 million decrease in proceeds from insurance recovery.
The $5.0 million loss on extinguishment of debt for the year ended December 31, 2024 resulted from the satisfaction and discharge of the Senior Notes 2026, which constituted a legal defeasance under GAAP (the “Defeasance”).
The $3.0 million loss on extinguishment of debt for the year ended December 31, 2025 resulted from the redemption of our Senior Notes 2027. The $5.0 million loss on extinguishment of debt for the year ended December 31, 2024 resulted from the satisfaction and discharge of the Senior Notes 2026, which constituted a legal defeasance under GAAP (the “Defeasance”).
The longer-term outlook for commodity prices remains constructive and we are increasing our new, large-horsepower compression unit order in 2025 to meet our customer needs. We expect total capital to be between $158.0 million and $182.0 million in 2025 and are beginning to evaluate new, large-horsepower compression unit orders for 2026.
The longer-term outlook for commodity prices remains constructive and we are increasing our new, large-horsepower compression unit order in 2026 to meet our customer needs. We expect total capital to be between $290.0 million and $320.0 million in 2026 and are beginning to evaluate new, large-horsepower compression unit orders for 2027.
Horsepower utilization based on revenue-generating horsepower and fleet horsepower was 92.4% and 90.9% as of December 31, 2024, and 2023, respectively. (8) Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period.
Horsepower utilization based on revenue-generating horsepower and fleet horsepower was 92.1% and 92.4% as of December 31, 2025, and 2024, respectively. (8) Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period.
The Senior Notes 2027 are due on September 1, 2027, and accrue interest at the rate of 6.875% per year. Interest on the Senior Notes 2027 is payable semi-annually in arrears on each of March 1 and September 1. The Senior Notes 2029 are due on March 15, 2029, and accrue interest at the rate of 7.125% per year.
The Senior Notes 2029 are due on March 15, 2029, and accrue interest at the rate of 7.125% per year. Interest on the Senior Notes 2029 is payable semi-annually in arrears on each of March 15 and September 15. The Senior Notes 2033 are due on October 1, 2033, and accrue interest at the rate of 6.250% per year.
The EIA Outlook estimates that annual U.S. crude oil production set a record of 13.2 million bpd in 2024, due to production growth in the Permian.
The EIA Outlook estimates that annual U.S. crude oil production set a record of 13.6 million bpd in 2025, due to production growth in the Permian.
According to the EIA Outlook, the U.S. witnessed record LNG exports of 12.0 bcf/d during 2024 and expects LNG exports to set new records of 14.1 bcf/d and 16.2 bcf/d in 2025 and 2026, respectively, as new LNG export capacity continues to ramp up creating incremental baseload global demand.
According to the EIA Outlook, the U.S. witnessed record LNG exports of 15.0 bcf/d during 2025 and expects LNG exports to set new records of 16.4 bcf/d and 18.1 bcf/d in 2026 and 2027, respectively, as new LNG export capacity continues to ramp up creating incremental baseload global demand.
The 2.3% increase in fleet horsepower as of December 31, 2024, compared to December 31, 2023, primarily was driven by new compression units added to our fleet to meet incremental demand from customers for our compression services.
The 0.8% increase in fleet horsepower as of December 31, 2025, compared to December 31, 2024, primarily was driven by new compression units added to our fleet to meet incremental demand from customers for our compression services.
For the years ended December 31, 2024 and 2023, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 2 and 42 compression units, respectively, representing approximately 1,260 and 37,700 of aggregate horsepower, respectively, that previously were used to provide compression services in our business.
For the years ended December 31, 2025 and 2024, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 28 and 2 compression and treating units, respectively, representing approximately 19,005 and 1,260 of aggregate horsepower, respectively, that previously were used to provide compression and treating services in our business.
The $0.9 million and $12.3 million impairments of assets during the years ended December 31, 2024 and 2023, respectively, primarily resulted from our evaluation of the future deployment of our idle fleet assets under then-current market conditions.
Impairment of assets . The $7.8 million and $0.9 million impairments of assets during the years ended December 31, 2025 and 2024, respectively, primarily resulted from our evaluation of the future deployment of our idle fleet assets under then-current market conditions.
As a result, we recorded impairments of compression equipment of $0.3 million and $12.3 million for the years ended December 31, 2024, and 2023, respectively.
As a result, we recorded impairments of compression and treating equipment of $7.8 million and $0.3 million for the years ended December 31, 2025, and 2024, respectively.
Natural gas prices averaged $2.20 per million British thermal units (“MMBtu”) in 2024 and the EIA Outlook expects natural gas prices to increase on average to $3.10/MMBtu and $4.00/MMBtu in 2025 and 2026, respectively, driven by the expectation that domestic natural gas inventories remain at or below previous five-year averages.
Natural gas prices averaged $3.53 per million British thermal units (“MMBtu”) in 2025 and the EIA Outlook expects natural gas prices to average $3.46/MMBtu and $4.59/MMBtu in 2026 and 2027, respectively, driven by the expectation that domestic natural gas inventories remain at or below previous five-year averages.
The $74.2 million increase in DCF for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $76.3 million increase in Adjusted gross margin, (ii) a $30.2 million decrease in distributions on Preferred Units following the conversion of 320,000 Preferred Units into 15,990,804 common units, and (iii) a $0.6 million increase in cash received on derivative instrument, partially offset by (iv) a $22.1 million increase in cash interest expense, net, (v) a $6.7 million increase in maintenance capital expenditures, and (vi) a $4.2 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses.
The $30.4 million increase in DCF for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) a $31.6 million increase in Adjusted gross margin, (ii) a $9.3 million decrease in distributions on Preferred Units following the conversion of 180,000 Preferred Units into 8,994,826 common units, and (iii) a $5.9 million decrease in cash interest expense, net, partially offset by (iv) a $7.5 million increase in maintenance capital expenditures, (v) a $6.9 million decrease in cash received on derivative instrument, and (vi) $1.1 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, transaction expenses, severance charges and other employee costs.
Average horsepower utilization based on revenue-generating horsepower and fleet horsepower was 91.7% and 89.2% for the years ended December 31, 2024, and 2023, respectively.
Average horsepower utilization based on revenue-generating horsepower and fleet horsepower was 92.0% and 91.7% for the years ended December 31, 2025, and 2024, respectively.
The applicable margin for borrowings varies (a) in the case of SOFR loans, from 2.00% to 2.75% per annum, and (b) in the case of Alternate Base Rate loans, from 1.00% to 1.75% per annum, and are determined based on a total-leverage-ratio pricing grid.
The applicable margin for borrowings varies (a) in the case of Daily Simple SOFR and SOFR loans, from 1.75% to 2.50% per annum, and (b) in the case of Alternate Base Rate loans and one-month SOFR loans, from 0.75% to 1.50% per annum, and will be determined based on a total leverage ratio pricing grid.
As a result of our evaluations during the years ended December 31, 2024 and 2023, we retired 2 and 42 compression units, respectively, with approximately 1,260 and 37,700 aggregate horsepower, respectively, that previously were used to provide compression services in our business.
As a result of our evaluations during the years ended December 31, 2025 and 2024, we retired 28 and 2 compression units, respectively, with approximately 19,005 and 1,260 aggregate horsepower, respectively, that previously were used to provide compression services in our business. Interest expense, net .
The $2.0 million increase in parts and service revenue for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to an increase in maintenance work performed on units at customer locations that are outside the scope of our core maintenance activities and that are offered as a convenience, and in directly reimbursable freight and crane charges that are the financial responsibility of the customers.
The $2.8 million decrease in parts and service revenue for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to a decrease in maintenance work performed on units outside the scope of our core maintenance activities, and in directly reimbursable freight and crane charges that are the financial responsibility of the customers.
Revolving Credit Facility As of December 31, 2024, we had outstanding borrowings under the Credit Agreement of $772.1 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $827.1 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $782.5 million was available to be drawn.
Revolving Credit Facility As of December 31, 2025, we had outstanding borrowings under the Credit Agreement of $795.0 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $954.2 million of remaining unused availability all of which was available to be drawn, inclusive of restrictions related to compliance with applicable financial covenants.
We believe DCF Coverage Ratio is an important measure of operating performance because it permits management, investors, and others to assess our ability to pay distributions to common unitholders out of the cash flows that we generate.
We believe DCF Coverage Ratio is an important measure of operating performance because it permits management, investors, and others to assess our ability to pay distributions to common unitholders out of the cash flows that we generate. Our DCF Coverage Ratio, as presented, may not be comparable to similarly titled measures of other companies.
The primary circumstances supporting these impairments were: (i) unmarketability of certain compression units into the foreseeable future, (ii) excessive maintenance costs associated with certain fleet assets, and (iii) prohibitive retrofitting costs that likely would prevent certain compression units from securing customer acceptance. These compression units were written down to their estimated salvage values, if any.
The primary circumstances supporting these impairments were: (i) unmarketability of certain compression units into the foreseeable future, (ii) excessive maintenance costs associated with certain 49 Table of Contents fleet assets, and (iii) prohibitive retrofitting costs that likely would prevent certain compression units from securing customer acceptance.
DRIP During the years ended December 31, 2024 and 2023, distributions of $1.6 million and $1.9 million, respectively, were reinvested under the DRIP resulting in the issuance of 65,352 and 87,808 common units, respectively.
DRIP During the years ended December 31, 2025 and 2024, distributions of $0.2 million and $1.6 million, respectively, were reinvested under the DRIP resulting in the issuance of 7,832 and 65,352 common units, respectively.
The $23.5 million increase in interest expense, net for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to increased aggregate borrowings and higher aggregate weighted-average interest rates under the Credit Agreement and refinanced senior notes. Loss on extinguishment of debt.
The $6.1 million decrease in interest expense, net for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to lower aggregate weighted-average interest rates under the Credit Agreement and refinanced senior notes. Loss on extinguishment of debt.
The $100.1 million increase in net cash used in financing activities for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $748.8 million increase in investments in government securities purchased in connection with the Defeasance of the Senior Notes 2026, (ii) a $325.6 million decrease in net borrowings under the Credit Agreement, (iii) an $18.2 million increase in deferred financing costs driven by the issuance of the Senior Notes 2029, and (iv) a $31.8 million increase in common unit distributions, partially offset by (v) a 1.0 billion increase in proceeds from issuance of the Senior Notes 2029, (vi) a $24.4 million decrease in Preferred Unit distributions, and (vii) a $1.1 million decrease in cash paid related to net settlement of unit-based awards.
The $131.4 million increase in net cash used in financing activities for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) an increase of $750 million in payments on senior notes, (ii) a $250 million decrease in proceeds from issuance of senior notes, (iii) a $13.4 million increase in common unit distributions, and (iv) a $3.2 million increase in payments related to net settlement of unit-based awards, partially offset by (v) a $748.8 million decrease in investments in government securities purchased in connection with the Defeasance of the Senior Notes 2026, (vi) a $122.7 million increase in net borrowings under the Credit Agreement, and (vii) $11.7 million decrease in Preferred Unit distributions.
The $28.0 million increase in cost of operations for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $17.2 million increase in direct labor costs due to increased headcount associated with increased revenue-generating horsepower and higher employee costs, (ii) a $12.3 million increase in direct expenses, primarily driven by increased spending on parts resulting from higher costs and increased usage associated with increased revenue-generating horsepower, (iii) a $2.2 million increase in other indirect expenses due to increased usage associated with increased revenue-generating horsepower, and (iv) a $1.4 million increase in retail parts and service expenses, for which a corresponding increase in parts and service revenue also occurred, partially offset by (v) a $3.6 million decrease in outside maintenance costs due to reduced use of third-party labor during the current period and (vi) a $1.4 million decrease in non-income taxes.
The $16.1 million increase in cost of operations for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) a $12.3 million increase in direct labor costs due to increased headcount associated with increased revenue-generating horsepower and higher employee costs, (ii) a $7.9 million increase in direct expenses, primarily driven by increased spending on parts resulting from higher costs and increased usage associated with increased revenue-generating horsepower, (iii) a $1.4 million increase in other indirect expenses due to increased usage associated with increased revenue-generating horsepower, and (iv) a $2.0 million increase in retail parts and service expenses, partially offset by (v) a $5.8 million decrease in fluids expense driven by decreased pricing, (vi) a $1.1 million decrease in vehicle expense due to lower maintenance and repair during the current period, and (vii) a $0.4 million decrease in non-income taxes.
Adjusted gross margin. The $76.3 million increase in Adjusted gross margin for the year ended December 31, 2024, compared to the year ended December 31, 2023, was due to a $104.3 million increase in revenues, offset by a $28.0 million increase in cost of operations, exclusive of depreciation and amortization. Adjusted EBITDA.
Adjusted gross margin. The $31.6 million increase in Adjusted gross margin for the year ended December 31, 2025, compared to the year ended December 31, 2024, was due to a $47.7 million increase in revenues, offset by a $16.1 million increase in cost of operations, exclusive of depreciation and amortization. Adjusted EBITDA.
The $72.3 million increase in Adjusted EBITDA for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to a $76.3 million increase in Adjusted gross margin, partially offset by a $4.2 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses. DCF.
The $29.5 million increase in Adjusted EBITDA for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to a $31.6 million increase in Adjusted gross margin, partially offset by a $1.1 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, transaction expenses, and severance charges and other employee costs.
The $19.6 million increase in related-party revenue for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to revenue recognized from 40 Table of Contents existing customers acquired by Energy Transfer since the previous period that are now classified as related-party revenue in the current period.
The $23.7 million increase in related-party revenue for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to revenue recognized from 39 Table of Contents existing customers acquired by Energy Transfer that are classified as related-party revenue for a full year, as opposed to a partial year in the previous period.
Management compensates for the limitations of DCF as an analytical tool by reviewing comparable GAAP measures, understanding the differences between the measures, and incorporating this knowledge into their decision making. 48 Table of Contents The following table reconciles DCF to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands): Year Ended December 31, 2024 2023 Net income $ 99,575 $ 68,268 Non-cash interest expense 8,748 7,279 Depreciation and amortization 264,756 246,096 Non-cash income tax expense (benefit) 574 (52) Unit-based compensation expense (1) 16,552 22,169 Transaction expenses (2) 133 46 Severance charges 2,430 841 Loss (gain) on disposition of assets 4,939 (1,667) Loss on extinguishment of debt (3) 4,966 — Change in fair value of derivative instrument 1,204 (1,204) Impairment of assets (4) 913 12,346 Distributions on Preferred Units (17,550) (47,775) Maintenance capital expenditures (5) (31,923) (25,234) DCF $ 355,317 $ 281,113 Maintenance capital expenditures 31,923 25,234 Transaction expenses (133) (46) Severance charges (2,430) (841) Distributions on Preferred Units 17,550 47,775 Other 630 1,500 Changes in operating assets and liabilities (61,523) (82,850) Net cash provided by operating activities $ 341,334 $ 271,885 ________________________ (1) For the years ended December 31, 2024 and 2023, unit-based compensation expense included $3.9 million and $4.4 million, respectively, of cash payments related to quarterly payments of DERs on outstanding phantom unit awards and $0.2 million and $0.3 million, respectively, related to the cash portion of the settlement of phantom unit awards upon vesting.
Management compensates for the limitations of DCF as an analytical tool by reviewing comparable GAAP measures, understanding the differences between the measures, and incorporating this knowledge into their decision making. 47 Table of Contents The following table reconciles DCF to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands): Year Ended December 31, 2025 2024 Net income $ 111,319 $ 99,575 Non-cash interest expense 8,554 8,748 Depreciation and amortization 284,816 264,756 Non-cash income tax expense 466 574 Unit-based compensation expense (1) 4,342 16,552 Transaction expenses (2) 1,914 133 Severance charges and other employee costs (3) 4,455 2,430 Other 2,876 — Loss on disposition of assets 3,820 4,939 Loss on extinguishment of debt (4) 3,006 4,966 Change in fair value of derivative instrument — 1,204 Impairment of assets (5) 7,811 913 Distributions on Preferred Units (8,288) (17,550) Maintenance capital expenditures (6) (39,414) (31,923) DCF $ 385,677 $ 355,317 Maintenance capital expenditures 39,414 31,923 Transaction expenses (1,914) (133) Severance charges and other employee costs (4,455) (2,430) Distributions on Preferred Units 8,288 17,550 Other (2,876) 630 Changes in operating assets and liabilities (29,872) (61,523) Net cash provided by operating activities $ 394,262 $ 341,334 ________________________ (1) For the years ended December 31, 2025 and 2024, unit-based compensation expense included $2.0 million and $3.9 million, respectively, of cash payments related to quarterly payments of DERs on outstanding unit awards.
The $5.7 million and $7.4 million gains on derivative instrument for the years ended December 31, 2024 and 2023, respectively, resulted from the change in fair value of the interest-rate swap due to changes in the interest-rate forward curve and cash received during the respective periods. Income tax expense.
The $5.7 million gain on derivative instrument for the year ended December 31, 2024 resulted from the change in fair value of an interest-rate swap due to changes in the interest-rate forward curve and cash received during the period.
Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing comparable GAAP measures, understanding the differences between the measures, and incorporating this knowledge into their decision making. 46 Table of Contents The following table reconciles Adjusted EBITDA to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands): Year Ended December 31, 2024 2023 Net income $ 99,575 $ 68,268 Interest expense, net 193,471 169,924 Depreciation and amortization 264,756 246,096 Income tax expense 2,231 1,365 EBITDA $ 560,033 $ 485,653 Unit-based compensation expense (1) 16,552 22,169 Transaction expenses (2) 133 46 Severance charges 2,430 841 Loss (gain) on disposition of assets 4,939 (1,667) Loss on extinguishment of debt (3) 4,966 — Gain on derivative instrument (5,684) (7,449) Impairment of assets (4) 913 12,346 Adjusted EBITDA $ 584,282 $ 511,939 Interest expense, net (193,471) (169,924) Non-cash interest expense 8,748 7,279 Income tax expense (2,231) (1,365) Transaction expenses (133) (46) Severance charges (2,430) (841) Cash received on derivative instrument 6,888 6,245 Other 1,204 1,448 Changes in operating assets and liabilities (61,523) (82,850) Net cash provided by operating activities $ 341,334 $ 271,885 ________________________ (1) For the years ended December 31, 2024 and 2023, unit-based compensation expense included $3.9 million and $4.4 million, respectively, of cash payments related to quarterly payments of DERs on outstanding phantom unit awards and $0.2 million and $0.3 million, respectively, related to the cash portion of the settlement of phantom unit awards upon vesting.
Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing comparable GAAP measures, understanding the differences between the measures, and incorporating this knowledge into their decision making. 45 Table of Contents The following table reconciles Adjusted EBITDA to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands): Year Ended December 31, 2025 2024 Net income $ 111,319 $ 99,575 Interest expense, net 187,408 193,471 Depreciation and amortization 284,816 264,756 Income tax expense 4,869 2,231 EBITDA $ 588,412 $ 560,033 Unit-based compensation expense (1) 4,342 16,552 Transaction expenses (2) 1,914 133 Severance charges and other employee costs (3) 4,455 2,430 Loss on disposition of assets 3,820 4,939 Loss on extinguishment of debt (4) 3,006 4,966 Gain on derivative instrument — (5,684) Impairment of assets (5) 7,811 913 Adjusted EBITDA $ 613,760 $ 584,282 Interest expense, net (187,408) (193,471) Non-cash interest expense 8,554 8,748 Income tax expense (4,869) (2,231) Transaction expenses (1,914) (133) Severance charges and other employee costs (4,455) (2,430) Cash received on derivative instrument — 6,888 Other 466 1,204 Changes in operating assets and liabilities (29,872) (61,523) Net cash provided by operating activities $ 394,262 $ 341,334 ________________________ (1) For the years ended December 31, 2025 and 2024, unit-based compensation expense included $2.0 million and $3.9 million, respectively, of cash payments related to quarterly payments of DERs on outstanding unit awards.
Year Ended December 31, 2024 2023 Increase Fleet horsepower (at period end) (1) 3,862,102 3,775,660 2.3 % Total available horsepower (at period end) (2) 3,862,942 3,831,444 0.8 % Revenue-generating horsepower (at period end) (3) 3,567,842 3,433,775 3.9 % Average revenue-generating horsepower (4) 3,528,172 3,328,999 6.0 % Average revenue per revenue-generating horsepower per month (5) $ 20.43 $ 18.86 8.3 % Revenue-generating compression units (at period end) 4,269 4,237 0.8 % Average horsepower per revenue-generating compression unit (6) 829 792 4.7 % Horsepower utilization (7): At period end 94.6 % 94.3 % 0.3 % Average for the period (8) 94.6 % 93.4 % 1.2 % ________________________ (1) Fleet horsepower is horsepower for compression units that have been delivered to us and excludes 20,310 and 21,690 of non-marketable horsepower as of December 31, 2024, and 2023, respectively.
Year Ended December 31, Increase 2025 2024 (Decrease) Fleet horsepower (at period end) (1) 3,894,332 3,862,102 0.8 % Total available horsepower (at period end) (2) 3,901,932 3,862,942 1.0 % Revenue-generating horsepower (at period end) (3) 3,585,452 3,567,842 0.5 % Average revenue-generating horsepower (4) 3,559,300 3,528,172 0.9 % Average revenue per revenue-generating horsepower per month (5) $ 21.38 $ 20.43 4.7 % Revenue-generating compression units (at period end) 4,256 4,269 (0.3 %) Average horsepower per revenue-generating compression unit (6) 847 829 2.2 % Horsepower utilization (7): At period end 94.7 % 94.6 % 0.1 % Average for the period (8) 94.3 % 94.6 % (0.3 %) ________________________ (1) Fleet horsepower is horsepower for compression units that have been delivered to us and excludes 14,985 and 20,310 of non-marketable horsepower as of December 31, 2025, and 2024, respectively.
The $57.6 million increase in gross margin for the year ended December 31, 2024, compared to the year ended December 31, 2023, was due to (i) a $104.3 million increase in revenues, offset by (ii) a $28.0 million increase in cost of operations, exclusive of depreciation and amortization, and (iii) an $18.7 million increase in depreciation and amortization.
The $11.5 million increase in gross margin for the year ended December 31, 2025, compared to the year ended December 31, 2024, was due to (i) a $47.7 million increase in revenues, offset by (ii) a $16.1 million increase in cost of operations, exclusive of depreciation and amortization and (iii) an $20.1 million increase in depreciation and amortization.
General Trends and Outlook A significant portion of our assets are utilized in natural gas infrastructure applications typically located in U.S. onshore shale plays, primarily at centralized gathering systems and processing facilities utilizing large-horsepower compression units.
J‑W Power also owns and operates specialized manufacturing facilities that support its internal compression requirements and those of third‑party customers. General Trends and Outlook A significant portion of our assets are utilized in natural gas infrastructure applications typically located in U.S. onshore shale plays, primarily at centralized gathering systems and processing facilities utilizing large-horsepower compression units.
Our principal sources of liquidity include cash generated by operating activities, borrowings under the Credit Agreement, and issuances of debt and equity securities, including common units under the DRIP. 42 Table of Contents We believe cash generated by operating activities and, where necessary, borrowings under the Credit Agreement will be sufficient to service our debt, fund working capital, fund our estimated expansion capital expenditures, fund our maintenance capital expenditures, and pay distributions to our unitholders through 2025.
We believe cash generated by operating activities and, where necessary, borrowings under the Credit Agreement will be sufficient to service our debt, fund working capital, fund our estimated expansion capital expenditures, fund our maintenance capital expenditures, and pay distributions to our unitholders through 2026.
Depreciation and amortization expense . The $18.7 million increase in depreciation and amortization expense for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) overhauls and major improvements to compression units and (ii) new trucks added to our vehicle fleet. Selling, general, and administrative expense .
Depreciation and amortization expense . The $20.1 million increase in depreciation and amortization expense for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to overhauls and major improvements to compression units. Selling, general, and administrative expense .
Adjusted gross margin should not be considered an alternative to, or more meaningful than, gross margin or any other measure presented in accordance with GAAP. Moreover, our Adjusted gross margin, as presented, may not be comparable to similarly titled measures of other companies. Because we capitalize assets, depreciation and amortization of equipment is a necessary element of our cost structure.
Moreover, our Adjusted gross margin, as presented, may not be comparable to similarly titled measures of other companies. 44 Table of Contents Because we capitalize assets, depreciation and amortization of equipment is a necessary element of our cost structure.
The 8.3% increase in average revenue per revenue-generating horsepower per month for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit. 39 Table of Contents Financial Results of Operations Year ended December 31, 2024, compared to the year ended December 31, 2023 The following table summarizes our results of operations for the periods presented (dollars in thousands): Year Ended December 31, Increase 2024 2023 (Decrease) Revenues: Contract operations $ 885,250 $ 802,562 10.3 % Parts and service 23,897 21,890 9.2 % Related party 41,302 21,726 90.1 % Total revenues 950,449 846,178 12.3 % Costs and expenses: Cost of operations, exclusive of depreciation and amortization 312,726 284,708 9.8 % Depreciation and amortization 264,756 246,096 7.6 % Selling, general, and administrative 72,666 72,714 (0.1) % Loss (gain) on disposition of assets 4,939 (1,667) * Impairment of assets 913 12,346 * Total costs and expenses 656,000 614,197 6.8 % Operating income 294,449 231,981 26.9 % Other income (expense): Interest expense, net (193,471) (169,924) 13.9 % Loss on extinguishment of debt (4,966) — * Gain on derivative instrument 5,684 7,449 (23.7) % Other 110 127 (13.4) % Total other expense (192,643) (162,348) 18.7 % Net income before income tax expense 101,806 69,633 46.2 % Income tax expense 2,231 1,365 63.4 % Net income $ 99,575 $ 68,268 45.9 % ________________________ * Not meaningful.
The 4.7% increase in average revenue per revenue-generating horsepower per month for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit. 38 Table of Contents Financial Results of Operations Year ended December 31, 2025, compared to the year ended December 31, 2024 The following table summarizes our results of operations for the periods presented (dollars in thousands): Year Ended December 31, Increase 2025 2024 (Decrease) Revenues: Contract operations $ 911,955 $ 885,250 3.0 % Parts and service 21,136 23,897 (11.6) % Related party 65,008 41,302 57.4 % Total revenues 998,099 950,449 5.0 % Costs and expenses: Cost of operations, exclusive of depreciation and amortization 328,804 312,726 5.1 % Depreciation and amortization 284,816 264,756 7.6 % Selling, general, and administrative 66,343 72,666 (8.7) % Loss on disposition of assets 3,820 4,939 * Impairment of assets 7,811 913 * Total costs and expenses 691,594 656,000 5.4 % Operating income 306,505 294,449 4.1 % Other income (expense): Interest expense, net (187,408) (193,471) (3.1) % Loss on extinguishment of debt (3,006) (4,966) * Gain on derivative instrument — 5,684 * Other 97 110 (11.8) % Total other expense (190,317) (192,643) (1.2) % Income before income tax expense 116,188 101,806 14.1 % Income tax expense 4,869 2,231 118.2 % Net income $ 111,319 $ 99,575 11.8 % ________________________ * Not meaningful.
Other Commitments As of December 31, 2024, other commitments include operating and finance lease payments totaling $19.3 million, of which we expect to make payments of $5.2 million to be settled in the next twelve months.
We have not ordered any compression units subsequent to December 31, 2025. Other Commitments As of December 31, 2025, other commitments include operating and finance lease payments totaling $18.4 million, of which we expect to make payments of $5.6 million to be settled in the next twelve months.
For more detailed descriptions of the Defeasance, Senior Notes 2027, and Senior Notes 2029, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
Interest on the Senior Notes 2033 is payable semi-annually in arrears on each of April 1 and October 1, commencing on April 1, 2026. For more detailed descriptions of the Senior Notes 2027, Senior Notes 2029, and Senior Notes 2033, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
Maintenance capital expenditures are capital expenditures made to maintain the operating capacity of our assets and extend their useful lives, replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining our existing business and related cash flow.
Maintenance capital expenditures are capital expenditures made to maintain the operating capacity of our assets and extend their useful lives, replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining our existing business and related cash flow. 48 Table of Contents DCF Coverage Ratio DCF Coverage Ratio is defined as the period’s DCF divided by distributions declared to common unitholders in respect of such period.
Overall, the EIA Outlook expects U.S. natural gas demand to outpace production and to increase by 3.2 bcf/d in 2025, primarily reflecting increased exports, both by LNG and pipeline, and stable baseload demand. Further, the EIA Outlook expects U.S natural gas demand to increase another 2.6 bcf/d in 2026, again driven primarily by LNG and pipeline exports, and stable baseload.
Overall, the EIA Outlook expects the increase in U.S. natural gas demand to trail production by 0.9 bcf/d in 2026, primarily reflecting the aforementioned increase in dry natural gas production compared to the expected demand from increased exports, both by LNG and pipeline, and stable baseload demand.
Depreciation is computed on a straight-line basis using useful lives that are estimated based on assumptions and judgments that reflect both historical experience and expectations regarding future use of our assets.
These compression and treating units were written down to their estimated salvage values, if any. Estimated Useful Lives of Property and Equipment Property and equipment is carried at cost. Depreciation is computed on a straight-line basis using useful lives that are estimated based on assumptions and judgments that reflect both historical experience and expectations regarding future use of our assets.
The change in selling, general, and administrative expense for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $5.6 million decrease in unit-based compensation expense, primarily attributable to mark-to-market changes to our unit-based compensation liability that occurred as a result of changes to our per-unit trading price as of December 31, 2024, partially offset by (ii) a $3.2 million increase to professional fees primarily related to an initiative to improve business performance, (iii) a $1.3 million increase in severance charges related to the departure of executives during the current period, and (iv) a $0.6 million increase in employee-related expenses driven by increased headcount.
The $6.3 million decrease in selling, general, and administrative expense for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) an $11.5 million decrease in unit-based compensation expense attributable to lower unit-based compensation expense resulting from the forfeiture and vesting of certain awards by certain former senior management and mark-to-market changes to our unit-based compensation liability that occurred as a result of changes to our per-unit trading price as of December 31, 2025, (ii) a $0.6 million decrease in provision for expected credit losses, (iii) a $0.5 million decrease in employee-related expenses due to decreased administrative headcount and lower employee costs, and (iv) a $0.4 million decrease to professional fees primarily related to an initiative to improve business performance, partially offset by (v) a $2.4 million increase in severance charges and other employee costs primarily related to the departure of certain senior management as well as retention and relocation payments related to the shared services integration during the current year, (vi) a $2.2 million increase in insurance and other administrative expenses, and (vii) a $1.9 million increase in transaction expenses related to the J-W Power Acquisition.
Our DCF Coverage Ratio, as presented, may not be comparable to similarly titled measures of other companies. 49 Table of Contents The following table summarizes our DCF Coverage Ratio for the periods presented (dollars in thousands): Year Ended December 31, 2024 2023 DCF $ 355,317 $ 281,113 Distributions for DCF Coverage Ratio (1) $ 245,990 $ 208,856 DCF Coverage Ratio 1.44 x 1.35 x ________________________ (1) Represents distributions to the holders of our common units as of the record date.
The following table summarizes our DCF Coverage Ratio for the periods presented (dollars in thousands): Year Ended December 31, 2025 2024 DCF $ 385,677 $ 355,317 Distributions for DCF Coverage Ratio (1) $ 266,659 $ 245,990 DCF Coverage Ratio 1.45 x 1.44 x ________________________ (1) Represents distributions to the holders of our common units as of the record date.
Senior Notes As of December 31, 2024, we had $750.0 million and $1.0 billion aggregate principal amount outstanding on our Senior Notes 2027 and Senior Notes 2029, respectively.
Senior Notes As of December 31, 2025, we had $1.0 billion and $750.0 million aggregate principal amount outstanding on our Senior Notes 2029 and Senior Notes 2033, respectively. The Senior Notes 2027 were due on September 1, 2027, and accrued interest at the rate of 6.875% per year.
To compensate for the limitations of Adjusted gross margin as a measure of our performance, we believe it is important to consider gross margin determined under GAAP, as well as Adjusted gross margin, to evaluate our operating profitability. 45 Table of Contents The following table reconciles Adjusted gross margin to gross margin, its most directly comparable GAAP financial measure, for each of the periods presented (in thousands): Year Ended December 31, 2024 2023 Total revenues $ 950,449 $ 846,178 Cost of operations, exclusive of depreciation and amortization (312,726) (284,708) Depreciation and amortization (264,756) (246,096) Gross margin $ 372,967 $ 315,374 Depreciation and amortization 264,756 246,096 Adjusted gross margin $ 637,723 $ 561,470 Adjusted EBITDA We define EBITDA as net income (loss) before net interest expense, depreciation and amortization expense, and income tax expense (benefit).
The following table reconciles Adjusted gross margin to gross margin, its most directly comparable GAAP financial measure, for each of the periods presented (in thousands): Year Ended December 31, 2025 2024 Total revenues $ 998,099 $ 950,449 Cost of operations, exclusive of depreciation and amortization (328,804) (312,726) Depreciation and amortization (284,816) (264,756) Gross margin $ 384,479 $ 372,967 Depreciation and amortization 284,816 264,756 Adjusted gross margin $ 669,295 $ 637,723 Adjusted EBITDA We define EBITDA as net income (loss) before net interest expense, depreciation and amortization expense, and income tax expense (benefit).
Borrowings under the Credit Agreement bear interest at a per-annum interest rate equal to, at the Partnership’s option, either the Alternate Base Rate or SOFR plus the applicable margin. “Alternate Base Rate” means the greatest of (i) the prime rate, (ii) the applicable federal funds effective rate plus 0.50%, and (iii) one-month SOFR rate plus 1.00%.
“Alternate Base Rate” means the greatest of (i) the prime rate, (ii) the federal funds effective rate plus 0.50%, and (iii) one-month SOFR rate plus 1.00%.
Our expansion capital expenditures for the years ended December 31, 2024 and 2023, were $243.5 million and $275.4 million, respectively. As of December 31, 2024, we did not have any binding commitments to purchase additional compression units and serialized parts.
Our expansion capital expenditures for the years ended December 31, 2025 and 2024, were $117.6 million and $243.5 million, respectively. As of December 31, 2025, we had binding commitments to purchase $78.4 million of additional compression units, all of which is expected to be delivered within the next twelve months.
The increase in DCF Coverage Ratio for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to the increase in DCF, partially offset by an increase in distributions from an increase in the number of common units, largely attributable to the conversion of 320,000 Preferred Units into 15,990,804 common units during 2024 and the exercise of warrants for 2,360,488 common units in November 2023.
The slight increase in DCF Coverage Ratio for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to the increase in DCF, offset by an increase in distributions from an increase in the number of common units, largely attributable to the conversion of 180,000 Preferred Units into 8,994,826 common units during 2025 and the issuance of 18,175,323 common units in January 2026 related to the J-W Acquisition.
The $0.9 million increase in income tax expense for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was related to deferred income taxes associated with the Texas Margin Tax. 41 Table of Contents Other Financial Data The following table summarizes other financial data for the periods presented (dollars in thousands): Year Ended December 31, Increase Other Financial Data: (1) 2024 2023 (Decrease) Gross margin $ 372,967 $ 315,374 18.3 % Adjusted gross margin $ 637,723 $ 561,470 13.6 % Adjusted gross margin percentage (2) 67.1 % 66.4 % 0.7 % Adjusted EBITDA $ 584,282 $ 511,939 14.1 % Adjusted EBITDA percentage (2) 61.5 % 60.5 % 1.0 % DCF $ 355,317 $ 281,113 26.4 % DCF Coverage Ratio 1.44 x 1.35 x 6.7 % ________________________ (1) Adjusted gross margin, Adjusted EBITDA, Distributable Cash Flow (“DCF”), and DCF Coverage Ratio are all non-GAAP financial measures.
The following table summarizes other financial data for the periods presented (dollars in thousands): Year Ended December 31, Increase Other Financial Data: (1) 2025 2024 (Decrease) Gross margin $ 384,479 $ 372,967 3.1 % Adjusted gross margin $ 669,295 $ 637,723 5.0 % Adjusted gross margin percentage (2) 67.1 % 67.1 % — % Adjusted EBITDA $ 613,760 $ 584,282 5.0 % Adjusted EBITDA percentage (2) 61.5 % 61.5 % — % DCF $ 385,677 $ 355,317 8.5 % DCF Coverage Ratio 1.45 x 1.44 x 0.7 % ________________________ (1) Adjusted gross margin, Adjusted EBITDA, Distributable Cash Flow (“DCF”), and DCF Coverage Ratio are all non-GAAP financial measures.
Discussion and analysis of our operating highlights and financial results of operations for the year ended December 31, 2023, compared to the year ended December 31, 2022, is included under the headings in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Highlights, Financial Results of Operations, Liquidity and Capital Resources, and Critical Accounting Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 13, 2024.
Discussion and analysis of our operating highlights and financial results of operations for the year ended December 31, 2024, compared to the year ended December 31, 2023, is included under the headings in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Highlights, Financial Results of Operations, Liquidity and Capital Resources, and Critical Accounting Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 11, 2025. 35 Table of Contents Overview We have focused our compression services in unconventional resource plays throughout the U.S., including the Utica, Marcellus, Permian, Denver-Julesburg, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, and Haynesville, and following the J-W Power Acquisition, the Bakken.
As of December 31, 2024, we were in compliance with all of our covenants under the Credit Agreement. As of February 6, 2025, we had outstanding borrowings under the Credit Agreement of $801.5 million and outstanding letters of credit of $0.8 million. The Credit Agreement matures on December 8, 2026.
As of December 31, 2025, we were in compliance with all of our covenants under the Credit Agreement. As of February 12, 2026, we had outstanding borrowings under the Credit Agreement of $1.3 billion and outstanding letters of credit of $2.0 million, which includes borrowings used to pay the cash consideration of the J-W Power Acquisition.
With average natural gas prices down year-over-year and average oil prices relatively flat, we experienced improvements to pricing and fleet utilization for our compression services in 2024, largely tied to associated gas growth from oil plays. 37 Table of Contents Looking ahead, global consumption of petroleum and liquids fuels according to the EIA’s January 2025 Short Term Energy Outlook (“EIA Outlook”) increased in 2024 and is expected to increase over 1.3 million barrels per day (“bpd”) in 2025 and 1.1 million bpd in 2026.
Looking ahead, global consumption of petroleum and liquids fuels according to the EIA’s January 2026 Short Term Energy Outlook (“EIA Outlook”) increased in 2025 and is expected to increase over 1.1 million barrels per day (“bpd”) in 2026 and 0.3 million bpd in 2027.
Cash Flows The following table summarizes our sources and uses of cash for the years ended December 31, 2024 and 2023, (in thousands): Year Ended December 31, 2024 2023 Net cash provided by operating activities $ 341,334 $ 271,885 Net cash used in investing activities (202,014) (232,653) Net cash used in financing activities (139,317) (39,256) Net cash provided by operating activities .
See “See Part I, Item 1 “Recent Developments” for additional information regarding the J-W Power Acquisition. 42 Table of Contents Cash Flows The following table summarizes our sources and uses of cash for the years ended December 31, 2025 and 2024, (in thousands): Year Ended December 31, 2025 2024 Net cash provided by operating activities $ 394,262 $ 341,334 Net cash used in investing activities (114,957) (202,014) Net cash used in financing activities (270,755) (139,317) Net cash provided by operating activities .
For a more detailed description of our lease obligations, please refer to Note 7 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
For a more detailed description of our lease obligations, please refer to Note 7 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. Additionally, as of December 31, 2025, we had entered into a definitive agreement with respect to the J-W Power Acquisition, which closed on January 12, 2026.
The Credit Agreement also contains various customary representations and warranties, affirmative covenants, and events of default. We expect to remain in compliance with our covenants under the Credit Agreement throughout 2025.
We expect to remain in compliance with our covenants under the Credit Agreement throughout 2026.
In addition, the Borrower is required to pay commitment fees based on the daily unused amount of the Credit Agreement in an amount equal to 0.375% per annum. Amounts borrowed and repaid under the Credit Agreement may be re-borrowed, subject to borrowing base availability.
In addition, the Partnership is required to pay commitment fees based on the daily unused amount under the facility in an amount per annum equal to 0.25%.
(3) This loss on extinguishment of debt is a result of the Defeasance of the Senior Notes 2026.
(4) For the year ended December 31, 2025, the loss on extinguishment of debt of $3.0 million is a result of the redemption of our Senior Notes 2027. For the year ended December 31, 2024, the loss on extinguishment of debt is a result of the Defeasance of the Senior Notes 2026.
(3) This loss on extinguishment of debt is a result of the Defeasance of the Senior Notes 2026.
(4) For the year ended December 31, 2025, the loss on extinguishment of debt of $3.0 million is a result of the redemption of our Senior Notes 2027. For the year ended December 31, 2024, the loss on extinguishment of debt is a result of the Defeasance of the Senior Notes 2026.
The IRS has issued preliminary partnership examination changes, along with imputed underpayment computations, for the 2019 and 2020 tax years. Under the Bipartisan Budget Act of 2015, there are several procedural steps, including an appeals process, to complete before a final imputed underpayment, if any, is determined.
Under the Bipartisan Budget Act of 2015, there are several procedural steps to complete before a final imputed underpayment, if any, is determined. Based on discussions with the IRS, we have accrued $2.9 million, which we believe is a reasonable estimate of the potential loss from the aggregate final imputed underpayment for the years 2019 and 2020.
The U.S. crude oil production growth in 2025 and 2026 is expected to come almost entirely from the Permian, which is expected to account for over half of U.S. crude oil production by 2026. We expect that anticipated crude oil production increases likewise will increase associated natural gas production volumes throughout 2025, thereby increasing demand for our compression services.
We expect that anticipated flat crude oil production will continue to yield an increase in associated natural gas production volumes throughout 2026, thereby increasing demand for our compression services.
The $69.4 million increase in net cash provided by operating activities for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) an increase in cash inflows from a $76.3 million increase in Adjusted gross margin and (ii) a $9.3 million decrease in cash paid for interest 43 Table of Contents expense, net of capitalized amounts, driven by the Defeasance of the Senior Notes 2026, partially offset by (iii) a $25.1 million increase in inventory purchases.
The $52.9 million increase in net cash provided by operating activities for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) a $60.8 million decrease in inventory purchases and (ii) a $21.3 million increase in net income excluding non-cash charges, partially offset by (iii) a $27.0 million increase in interest payments due to the timing of payments related to our refinance of our Senior Notes 2026 and (iv) a $2.1 million increase in other working capital.
Interest on the Senior Notes 2029 is payable semi-annually in arrears on each of March 15 and September 15, which commenced on September 15, 2024. Net proceeds from the Senior Notes 2029 were used for the Defeasance, with the remainder used to reduce outstanding borrowings under our Credit Agreement.
Interest on the Senior Notes 2027 was payable semi-annually in arrears on each of March 1 and September 1. On October 15, 2025 the Senior Notes 2027 were redeemed in full at par, plus accrued and unpaid interest, with the net proceeds from the issuance and sale of the Senior Notes 2033, together with borrowings under our Credit Agreement.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

4 edited+0 added−1 removed6 unchanged
Biggest changePlease also read Part I, Item 1A “Risk Factors – Risks Related to Our Business – An extended reduction in the demand for, or production of, natural gas or crude oil could adversely 51 Table of Contents affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders.” Interest Rate Risk We are exposed to market risk due to variable interest rates under the Credit Agreement.
Biggest changePlease also read Part I, Item 1A “Risk Factors – Risks Related to Our Business – A reduction in the demand for, or production of, natural gas or crude oil could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders.” 50 Table of Contents Interest Rate Risk We are exposed to market risk due to variable interest rates under the Credit Agreement.
We do not intend to hedge our indirect exposure to fluctuating commodity prices. A one percent decrease in average revenue-generating horsepower during the year ended December 31, 2024 would result in an annual decrease of approximately $8.6 million and $5.8 million in our revenue and Adjusted gross margin, respectively. Adjusted gross margin is a non-GAAP financial measure.
We do not intend to hedge our indirect exposure to fluctuating commodity prices. A one percent decrease in average revenue-generating horsepower during the year ended December 31, 2025 would result in an annual decrease of approximately $9.1 million and $6.1 million in our revenue and Adjusted gross margin, respectively. Adjusted gross margin is a non-GAAP financial measure.
For further information regarding our interest-rate swap and the termination, see Note 8 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. Credit Risk Our credit exposure generally relates to receivables for services provided.
For further information regarding our exposure to interest rate fluctuations on our debt obligations, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. Credit Risk Our credit exposure generally relates to receivables for services provided.
As of December 31, 2024, we had $772.1 million of variable-rate indebtedness outstanding at a weighted-average interest rate of 6.98%. Based on our December 31, 2024 variable-rate indebtedness outstanding, a one percent increase or decrease, respectively, in the effective interest rate would result in an annual increase or decrease in our interest expense of approximately $7.7 million.
As of December 31, 2025, we had $795.0 million of variable-rate indebtedness outstanding at a weighted-average interest rate of 5.74%. Based on our December 31, 2025 variable-rate indebtedness outstanding, a one percent increase or decrease, respectively, in the effective interest rate would result in an annual increase or decrease in our interest expense of approximately $8.0 million.
Removed
For further information regarding our exposure to interest rate fluctuations on our debt obligations, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. In August 2024, we elected to terminate the interest-rate swap we previously used to manage interest-rate risk associated with the floating-rate Credit Agreement.

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