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What changed in USA Compression Partners, LP's 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of USA Compression Partners, LP's 2023 and 2024 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 2024 report.

+286 added−308 removedSource: 10-K (2025-02-11) vs 10-K (2024-02-13)

Top changes in USA Compression Partners, LP's 2024 10-K

286 paragraphs added · 308 removed · 225 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

42 edited+6 added−15 removed94 unchanged
Biggest changeThe following table provides a summary of our compression units by horsepower as of December 31, 2023: 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 499,752 2,946 — — 499,752 2,946 13.0 % 54.6 % Large horsepower ≥400 and 416,983 715 — — 416,983 715 10.9 % 13.2 % ≥1,000 2,858,925 1,714 52,500 21 2,911,425 1,735 76.1 % 32.2 % Total large horsepower 3,275,908 2,429 52,500 21 3,328,408 2,450 87.0 % 45.4 % Total horsepower 3,775,660 5,375 52,500 21 3,828,160 5,396 100.0 % 100.0 % ________________________ (1) As of December 31, 2023, we had 21 large horsepower units, consisting of 52,500 horsepower, on order for expected delivery during 2024.
Biggest changeWe 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.
Human Capital Management USA Compression Management Services, LLC (“USAC Management”), a wholly owned subsidiary of the General Partner, performs management, administrative and operating services for us, and provides us with personnel to manage and operate our business. All of our employees, including our executive officers, are employees of USAC Management.
Human Capital Management USA Compression Management Services, LLC (“USAC Management”), a wholly owned subsidiary of the General Partner, performs certain management, administrative and operating services for us, and provides us with personnel to manage and operate our business. All of our employees, including our executive officers, are employees of USAC Management.
Legislation to amend the Safe Drinking Water Act (“SDWA”) to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed from time to time and the U.S.
Legislation to amend the Safe Drinking Water Act (“SDWA”) to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed from time to time.
We are not currently responsible for any remedial activities at any properties we use; however, there always is the possibility that our future use of those properties may result in spills or releases of petroleum hydrocarbons, wastes, or other regulated substances into the environment that may cause us to become subject to remediation costs and liabilities under CERCLA, the Resource 8 Table of Contents Conservation and Recovery Act or other environmental laws.
We are not currently responsible for any remedial activities at any properties we use; however, there always is the possibility that our future use of those properties may result in spills or releases of petroleum hydrocarbons, wastes, or other regulated substances into the environment that may cause us to become subject to remediation costs and liabilities under CERCLA, the Resource Conservation and Recovery Act or other environmental laws.
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, 2023, 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, 2024, lead-times for such engines and frames are approximately one year.
In addition, almost half of the states have begun to address GHG emissions, primarily through the planned development of emissions inventories or regional GHG cap-and-trade programs. Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. 6 Table of Contents Independent of the U.S.
In addition, almost half of the states have begun to address GHG emissions, primarily through the planned development of emissions inventories or regional GHG cap-and-trade programs. Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. Independent of the U.S.
In January 2024, the EPA issued a proposed 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.
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.
Seasonality Our results of operations have not historically been materially affected by seasonality, and we do not currently have reason to believe that seasonal fluctuations will have a material impact in the foreseeable future. 4 Table of Contents Insurance We believe that our insurance coverage is customary for the industry and adequate for our business.
Seasonality Our results of operations have not historically been materially affected by seasonality, and we do not currently have reason to believe that seasonal fluctuations will have a material impact in the foreseeable future. Insurance We believe that our insurance coverage is customary for the industry and adequate for our business.
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 39%, 38%, and 39% of our total revenues for the years ended December 31, 2023, 2022, and 2021, respectively.
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.
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.
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.
These larger-horsepower units, which we define as 400 horsepower per unit or greater, represented 87.0% of our total fleet horsepower (including compression units on order) as of December 31, 2023. 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 87.2% 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.
Dual-drive technology offers the ability to switch compression drivers 7 Table of Contents between an electric motor and a natural gas engine, to reduce our emissions of nitrogen oxide, carbon monoxide, carbon dioxide, and VOCs. Water discharge .
Dual-drive technology offers the ability to switch compression drivers between an electric motor and a natural gas engine, to reduce our emissions of nitrogen oxide, carbon monoxide, carbon dioxide, and VOCs. Water discharge .
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.
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.
In any event, our customers assume responsibility under the majority of our standard natural gas compression contracts for obtaining any permits that may be required under the CWA, whether for discharges or developing property by filling wetlands. On January 18, 2023, the EPA and the U.S.
In any event, our customers assume responsibility under the majority of our standard natural gas compression contracts for obtaining any permits that may be required under the CWA, whether for discharges or developing property by filling wetlands. The EPA and the U.S.
We also rely primarily on four vendors, A G Equipment Company, Alegacy Equipment, LLC., Standard Equipment Company, and Genis Holdings LLC, 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.
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.
The information contained on our website does not constitute part of this report. The SEC maintains a website that contains these reports at sec.gov. 9 Table of Contents
The information contained on our website does not constitute part of this report. The SEC maintains a website that contains these reports at sec.gov.
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, 2023, we had 3,775,660 horsepower in our fleet.
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.
As of December 31, 2023, the average age of our compression units was approximately 11 years. Our modern, standardized compression unit fleet is powered primarily by the Caterpillar 3400, 3500, and 3600 engine classes, which range from 401 to 5,000 horsepower per unit.
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.
Congress continues to consider legislation to amend the SDWA. Several states also have proposed or adopted legislative or regulatory restrictions on hydraulic fracturing, including prohibitions on the practice. We cannot predict the future of such legislation and what additional, if any, provisions would be included.
Several states also have proposed or adopted legislative or regulatory restrictions on hydraulic fracturing, including prohibitions on the practice. We cannot predict the future of such legislation and what additional, if any, provisions would be included.
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 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.
On a regional basis, we experience competition from numerous smaller companies that may be able to more quickly adapt to changes within our industry and changes in economic conditions as a whole, more readily take advantage of available opportunities, and adopt more aggressive pricing policies.
Some of our competitors have greater financial and other resources than we do. On a regional basis, we experience competition from numerous smaller companies that may be able to more quickly adapt to changes within our industry and changes in economic conditions as a whole, more readily take advantage of available opportunities, and adopt more aggressive pricing policies.
We operate a modern fleet of compression units, with an average age of approximately 11 years. We acquire our compression units primarily from third-party fabricators who build the units to our specifications, utilizing specific components from original equipment manufacturers and assembling the units in a manner that provides us the ability to meet certain operating condition thresholds.
We acquire our compression units primarily from third-party fabricators who build the units to our specifications, utilizing specific components from original equipment manufacturers and assembling the units in a manner that provides us the ability to meet certain operating condition thresholds.
Suppliers and Service Providers The principal manufacturers of components for our natural gas compression equipment include Caterpillar Inc., Cummins Inc., and Arrow Engine Company for engines; Air-X-Changers and Alfa Laval (US) for coolers; and Ariel Corporation, Cooper Machinery Services Gemini products, and Arrow Engine Company for compressor frames and cylinders.
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.
We primarily enter into fixed-fee contracts whereby our customers are required to pay our monthly fee even during periods of limited or disrupted throughput, which enhances the stability and predictability of our cash flows.
We primarily enter into fixed-fee contracts whereby our customers are required to pay our monthly fee even during periods of limited or disrupted throughput, which enhances the stability and predictability of our cash flows. We bill most of our customers in advance of the service date and also typically utilize annual inflation adjustments in our term contracts.
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.
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.
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.
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.
Environmental Protection Agency (“EPA”) published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines, also known as Quad Z regulations.
Environmental Protection Agency (“EPA”) published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines, also known as Quad Z regulations. The rule requires us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment on certain compressor engines and generators.
After the EPA revises a NAAQS standard, the states are expected to establish revised attainment/non-attainment regions.
In December 2020, the EPA announced its decision to retain, without changes, the 2015 NAAQS. After the EPA revises a NAAQS standard, the states are expected to establish revised attainment/non-attainment regions.
Our modern, flexible fleet of 2 Table of Contents 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.
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.
See our consolidated financial statements, and the notes thereto, in Part II, Item 8 “Financial Statements and Supplementary Data” for financial information on our operations and assets; such information is incorporated herein by reference. Our Operations Compression Services We provide compression services for a fixed monthly service fee.
Our assets and operations are organized into a single reportable segment and all are located and operated within the U.S. See our consolidated financial statements, and the notes thereto, in Part II, Item 8 “Financial Statements and Supplementary Data” for financial information on our operations and assets; such information is incorporated herein by reference.
For example, in 2015, the EPA finalized a rule strengthening the primary and secondary standards 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.
In recent years, the EPA has lowered the National Ambient Air Quality Standards (“NAAQS”) for several air pollutants. For example, in 2015, the EPA finalized a rule strengthening the primary and secondary standards for ground-level ozone, both of which are eight-hour concentration standards of 70 parts per billion (the “2015 NAAQS”).
Changes to the jurisdictional reach of the CWA could cause our customers to face increased costs and delays due to additional permitting and regulatory requirements, and possible challenges to permitting decisions. Safe Drinking Water Act. A significant portion of our customers’ natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process.
Safe Drinking Water Act. A significant portion of our customers’ natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process.
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. The OSHA Total Recordable Incident Rate (“TRIR”) is a key performance indicator by which we evaluate the success of our safety program.
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.
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.
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.
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. Our goal is operational excellence, which includes maintaining an injury- and incident-free workplace.
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.
Our business largely focuses on compression services serving infrastructure applications, including centralized natural gas gathering systems and processing facilities, which utilize large horsepower compression units, typically in shale plays. We also provide compression services in more mature basins, including gas lift applications on crude oil wells targeted by horizontal drilling techniques.
We believe we are well-positioned to meet these changing operating conditions due to the operational design flexibility inherit within our compression-unit fleets. Our business includes compression services serving infrastructure applications, including centralized natural gas gathering systems and processing facilities, which utilize large-horsepower compression units and also gas lift applications on crude oil wells targeted by horizontal drilling techniques.
We provide compression services in shale plays throughout the U.S., including the Utica, Marcellus, Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara, and Fayetteville shales. Demand for our services is driven by the domestic production of 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.
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 2024 where beneficial from an operational and financial standpoint.
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.
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. Each of our compression units is subjected to rigorous sizing and diagnostic analyses, including lubricating oil analysis and engine exhaust emission analysis.
We 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.
We have proprietary field-service automation capabilities that allow our service technicians to electronically record and track operating, 3 Table of Contents 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.
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.
Furthermore, changes in production volumes and pressures of shale plays over time require a wider range of compression service levels than in conventional basins. We believe we are well-positioned to meet these changing operating conditions due to the operational design flexibility inherit within our compression-unit fleets.
According to studies promulgated by the EIA, the production and transportation volumes in these unconventional plays, namely tight oil and gas shale plays, are expected to collectively increase over the long term. Furthermore, changes in production volumes and pressures of shale plays over time require a wider range of compression service levels than in conventional basins.
As of December 31, 2023, USAC Management had 822 full-time employees. None of our employees are subject to collective bargaining agreements. We consider our employee relations to be good.
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.
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As such, we have focused our activities in areas with attractive natural gas and crude oil production, which generally are found in these shale and unconventional resource plays. According to studies promulgated by the EIA, the production and transportation volumes in these shale plays are expected to collectively increase over the long term.
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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.
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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 assets and operations are organized into a single reportable segment and all are located and operated within the U.S.
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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.
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We believe the average age and overall composition of our compressor fleet result in fewer mechanical failures, lower fuel usage, and reduced environmental emissions.
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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.
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Some of our competitors have a broader geographic scope and greater financial and other resources than we do.
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Given the significant ownership, we believe Energy Transfer will be motivated to promote and support the successful execution of the shared services model, as well as our overall business strategy.
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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.
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For additional information on our related party transactions with entities affiliated with Energy Transfer, see Note 14 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. Our Operations Compression Services We provide compression services for a fixed monthly service fee.
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The rule requires us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment on certain compressor engines and generators. 5 Table of Contents In recent years, the EPA has lowered the National Ambient Air Quality Standards (“NAAQS”) for several air pollutants.
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Army Corps of Engineers have changed the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA from time to time. Changes to the jurisdictional reach of the CWA could cause our customers to face increased costs and delays due to additional permitting and regulatory requirements, and possible challenges to permitting decisions.
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At the federal level, the government could seek to pursue legislative, regulatory, or executive initiatives that may impose significant restrictions on fossil-fuel exploration and production and use, such as limitations or bans on hydraulic fracturing of oil and gas wells, bans or restrictions on new leases for production of minerals on federal properties, and imposing restrictive requirements on new pipeline infrastructure or fossil-fuel export facilities.
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At the international level, nearly 200 nations entered into an international climate agreement at the 2015 United Nations Framework Convention on Climate Change in Paris, under which participating countries did not assume any binding obligation to reduce future emissions of GHGs but instead pledged to voluntarily limit or reduce future emissions.
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The Paris Agreement went into effect on November 4, 2016, and the U.S. formally rejoined in February 2021. The U.S. has established an economy-wide target of reducing its net GHG emissions by 50-52 percent below 2005 levels by 2030 and achieving net zero GHG emissions economy-wide by no later than 2050.
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In addition, certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement.
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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.
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Army Corps of Engineers issued a final rule revising the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA (“2023 WOTUS Rule”). On May 25, 2023, the U.S. Supreme Court invalidated parts of the 2023 WOTUS Rule in its decision in Sackett vs. EPA .
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In response to Sackett , the EPA issued a final rule conforming its definition of WOTUS to the Sackett decision and narrowing federal jurisdiction under the CWA. That rule became effective on September 8, 2023.
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TRIR provides a measure of occupational safety performance for the year by calculating the number of recordable incidents compared to the total number of hours worked by all employees. Out of approximately 1.85 million hours worked in 2023, our TRIR was 0.65 for 2023 versus the 2023 industry average of 0.90.
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We believe our low TRIR speaks to our investment in and focus on safety. Available Information Our website address is usacompression.com.

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

82 edited+12 added−23 removed273 unchanged
Biggest changeIn 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 2026 and Senior Notes 2027 (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.
Biggest changeIn 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.
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; • 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 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.
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.
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.
(along with its affiliated funds, “EIG”) in connection with our private placement of Preferred Units and warrants to EIG, EIG Management Company, LLC has the right to designate one of the members of the Board for so long as the holders of the Preferred Units hold more than 5% of the Partnership’s outstanding common units in the aggregate (taking into account the common units that would be issuable upon conversion of the Preferred Units and exercise of the warrants).
(along with its affiliated funds, “EIG”) in connection with our private placement of Preferred Units and warrants to EIG, EIG Management Company, LLC has the right to designate one of the members of the Board for so long as the holders of the Preferred Units hold more than 5% of the Partnership’s outstanding common units in the aggregate (taking into account the common units that would be issuable upon conversion of the Preferred Units).
The 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. 10 Table of Contents • 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.
The 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.
These conflicts include the following situations, among others: • neither the Partnership Agreement nor any other agreement requires Energy Transfer to pursue a business strategy that favors us; • Energy Transfer and its affiliates are not prohibited from engaging in businesses or activities that are in direct competition with us or from offering business opportunities or selling assets to our competitors; • the General Partner is allowed to take into account the interests of parties other than us, such as its owner, in resolving conflicts of interest; • the Partnership Agreement limits the liability of and reduces the fiduciary duties owed by the General Partner, and also restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty; • except in limited circumstances, the General Partner has the power and authority to conduct our business without unitholder approval; 24 Table of Contents • the General Partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership interests, and the creation, reduction, or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders; • the General Partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus.
These conflicts include the following situations, among others: • neither the Partnership Agreement nor any other agreement requires Energy Transfer to pursue a business strategy that favors us; • Energy Transfer and its affiliates are not prohibited from engaging in businesses or activities that are in direct competition with us or from offering business opportunities or selling assets to our competitors; • the General Partner is allowed to take into account the interests of parties other than us, such as its owner, in resolving conflicts of interest; • the Partnership Agreement limits the liability of and reduces the fiduciary duties owed by the General Partner, and also restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty; • except in limited circumstances, the General Partner has the power and authority to conduct our business without unitholder approval; • the General Partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership interests, and the creation, reduction, or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders; • the General Partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus.
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.
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.
Energy Transfer may, and the Preferred Unitholders may continue to, sell such common units. Any sales of these common units in the public or private markets could have an adverse impact on the price of our common units.
Energy Transfer may, and the Preferred Unitholders have and may continue to, sell our common units. Any sales of these common units in the public or private markets could have an adverse impact on the price of our common units.
Financial covenants in the Credit Agreement permit a maximum leverage ratio of 5.25 to 1.00 (except that we 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.
Financial covenants in the 14 Table of Contents Credit Agreement permit a maximum leverage ratio of 5.25 to 1.00 (except that we 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.
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 CDM Acquisition, which significantly increased our size and expanded the geographic areas in which we operate.
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.
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.
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.
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, 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. • 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.
If our operating results are not sufficient to service our current or future indebtedness, we could be forced to take actions such as reducing the level of distributions on our common units, curtailing or 14 Table of Contents delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital.
If our operating results are not sufficient to service our current or future indebtedness, we could be forced to take actions such as reducing the level of distributions on our common units, curtailing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital.
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 29 Table of Contents 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 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.
An increase in interest rates may cause the market price of our common units to decline. The market price of master limited partnership units, like other yield-oriented securities, may be affected by, among other factors, implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities 26 Table of Contents for investment decision-making purposes.
An increase in interest rates may cause the market price of our common units to decline. The market price of master limited partnership units, like other yield-oriented securities, may be affected by, among other factors, implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes.
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.
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.
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 39%, 38%, and 39% of our total revenues for the years ended December 31, 2023, 2022, and 2021, 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 41%, 39%, and 38% of our total revenues for the years ended December 31, 2024, 2023, and 2022, respectively.
The decline in commodity prices and the demand for and production of crude oil and natural gas resulted in a decline in the demand for our compression services, which caused a reduction of our revenues and our cash available for distribution in 2020 and 2021.
The decline in commodity prices and the demand for and production of crude oil and natural gas resulted in a decline in the demand for our compression services, which caused a reduction of our revenues and our cash available for distribution.
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.
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.
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.
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.
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”).
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”).
In January 2024, the EPA issued a proposed rule to impose and collect the methane emissions charge authorized under the IRA 2022. In addition, federal or state governmental agencies could seek to pursue legislative, regulatory, or executive initiatives that restrict GHG emissions. Other energy legislation and initiatives could include a carbon tax or cap-and-trade program. Independent of the U.S.
In November 2024, the EPA issued a final rule to impose and collect the methane emissions charge authorized under the IRA 2022. In addition, federal or state governmental agencies could seek to pursue legislative, regulatory, or executive initiatives that restrict GHG emissions. Other energy legislation and initiatives could include a carbon tax or cap-and-trade program. Independent of the U.S.
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.
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.
By purchasing a unit, a unitholder agrees to become bound by the provisions of the Partnership Agreement, including the provisions discussed above. 25 Table of Contents 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.
By purchasing a unit, a unitholder agrees to become bound by the provisions of the Partnership Agreement, including the provisions discussed above. 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.
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.
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.
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.
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.
Additionally, under Delaware law, the General Partner has 27 Table of Contents unlimited liability for the obligations of the Partnership, such as our debts and environmental liabilities, except for those contractual obligations of the Partnership that are expressly made without recourse to the General Partner.
Additionally, under Delaware law, the General Partner has unlimited liability for the obligations of the Partnership, such as our debts and environmental liabilities, except for those contractual obligations of the Partnership that are expressly made without recourse to the General Partner.
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, 2023, we had $2.3 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, 2024, we had $2.5 billion of total debt, net of amortized deferred financing costs, outstanding under our Credit Agreement and Senior Notes.
In addition, our ability to service our debt under the Credit Agreement could be impacted by market interest rates, as all of our outstanding borrowings under the Credit Agreement are subject to variable interest rates that fluctuate with changes in market interest rates.
In addition, our ability to service our debt under the Credit Agreement could be impacted by market interest rates, as all of our outstanding borrowings under the Credit Agreement are subject to variable interest rates that fluctuate with changes in market interest rates. While the U.S.
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 8, 2024, Energy Transfer beneficially owns an aggregate of 46,056,228 common units in us.
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.
These factors include, among others, the potential adoption of new government regulations, including those related to fuel conservation measures and climate change regulations, technological advances in fuel economy, and energy generation 22 Table of Contents devices.
These factors include, among others, the potential adoption of new government regulations, including those related to fuel conservation measures and climate change regulations, technological advances in fuel economy, and energy generation devices.
We face significant competition that may cause us to lose market share and reduce our cash available for distribution. The natural gas compression business is highly competitive. Some of our competitors have a broader geographic scope and greater financial and other resources than we do.
We face significant competition that may cause us to lose market share and reduce our cash available for distribution. The natural gas compression business is highly competitive. Some of our competitors have greater financial and other resources than we do.
For the year ended December 31, 2023, approximately 22% 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, 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.
As of December 31, 2023, the General Partner and its affiliates (including Energy Transfer), beneficially own an aggregate of approximately 46% 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, 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.
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; 16 Table of Contents • enter into agreements restricting our subsidiaries’ ability to pay distributions; and • consolidate, merge, or sell all or substantially all of our assets.
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.
Also, because distributions on our common units are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will not be entitled to receive distributions covering any prior periods if we later recommence paying distributions on our common units.
Also, because distributions on our common units are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our 17 Table of Contents common unitholders will not be entitled to receive distributions covering any prior periods if we later recommence paying distributions on our common units.
If we do not pay the required distributions on the Preferred Units, we will be unable to pay distributions on our common units. 17 Table of Contents Additionally, because distributions on the Preferred Units are cumulative, we will have to pay all unpaid accumulated distributions on the Preferred Units before we can pay any distributions on our common units.
If we do not pay the required distributions on the Preferred Units, we will be unable to pay distributions on our common units. Additionally, because distributions on the Preferred Units are cumulative, we will have to pay all unpaid accumulated distributions on the Preferred Units before we can pay any distributions on our common units.
To the extent possible under applicable rules, the General Partner may pay such taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, elect to issue a revised Schedule K-1 to each unitholder and former unitholder with respect to an audited and adjusted return.
To the extent possible under applicable rules, the General Partner may pay such taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, elect to issue Form 8986, effectively taking the place of a revised Schedule K-1, to each unitholder and former unitholder with respect to an audited and adjusted return.
Our ability to incur additional debt also is subject to limitations in the Credit Agreement, including certain financial covenants. As of December 31, 2023, our leverage ratio under the Credit Agreement was 4.10x.
Our ability to incur additional debt also is subject to limitations in the Credit Agreement, including certain financial covenants. As of December 31, 2024, our leverage ratio under the Credit Agreement was 4.02x.
For example, for the years ended December 31, 2023, 2022, and 2021, we evaluated the future deployment of our idle fleet assets under then-current market conditions and retired 42, 15, and 26 compression units, respectively, representing approximately 37,700, 3,200, and 11,000 of aggregate horsepower, respectively, that previously were used to provide compression services in our business.
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.
We also rely primarily on four vendors, A G Equipment Company, Alegacy Equipment, LLC., Standard Equipment Company, and Genis Holdings LLC, to package and assemble our compression units.
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.
A prolonged or severe sudden downturn in the economic environment could cause an impairment of identifiable intangible assets and reduce our earnings. We have recorded $245.7 million of identifiable intangible assets, net, as of December 31, 2023.
A prolonged or severe sudden downturn in the economic environment could cause an impairment of identifiable intangible assets and reduce our earnings. We have recorded $216.3 million of identifiable intangible assets, net, as of December 31, 2024.
In addition, a small portion of our fleet is used in gas lift applications in connection with crude oil production using horizontal drilling techniques. During periods of low crude oil prices, we typically experience pressure on service rates and utilization from our customers in gas lift applications, and we experienced such effects in 2020, as an example.
In addition, a portion of our fleet is used in gas lift applications in connection with crude oil production using horizontal drilling techniques. During periods of low crude oil prices, we typically experience pressure on service rates and utilization from our customers in gas lift applications, and we have experienced such effects in the past.
Such claims or actions could result in liability to our customers for property damage, exposure to waste and other hazardous materials, nuisance, or personal injuries, and require our customers to expend additional resources or incur substantial costs or losses.
Such claims or actions could result in liability to our customers for property damage, exposure to waste and other hazardous materials, nuisance, or personal injuries, and require our customers to expend additional resources or incur substantial costs or losses. This could in turn adversely affect the demand for our services.
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.
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.
Weak economic conditions and widespread financial distress, such as what resulted from the COVID-19 pandemic, did and could again reduce the liquidity of our customers, suppliers, or vendors, making it more difficult for them to meet their obligations to us. We therefore are subject to heightened risks of loss resulting from nonpayment or nonperformance by our customers, suppliers, and vendors.
Weak economic conditions and widespread financial distress, have in the past and could again reduce the liquidity of our customers, suppliers, or vendors, making it more difficult for them to meet their obligations to us. We therefore are subject to heightened risks of loss resulting from nonpayment or nonperformance by our customers, suppliers, and vendors.
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 $54.1 million per quarter, or $216.3 million per year, based on the number of common units outstanding as of February 8, 2024.
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.
As of February 8, 2024, we had outstanding borrowings under the Credit Agreement of $927.5 million and outstanding letters of credit of $0.5 million.
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.
During times when the natural gas or crude oil markets weaken, such as during the COVID-19 pandemic, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services.
The deterioration of the financial condition of our customers could adversely affect our business. During times when the natural gas or crude oil markets weaken our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services.
The substantial majority of the components for our natural gas compression equipment are supplied by Caterpillar Inc., Cummins Inc., and Arrow Engine Company for engines; Air-X-Changers and Alfa Laval (US) for coolers; and Ariel Corporation, Cooper Machinery Services Gemini products, and Arrow Engine Company for compressor frames and cylinders.
The substantial majority of the components for our natural gas compression equipment are supplied by 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.
As of December 31, 2023, we had $725.0 million and $750.0 million aggregate principal amount outstanding on our Senior Notes 2026 and Senior Notes 2027, respectively. The Senior Notes 2026 and Senior Notes 2027 accrue interest at the rate of 6.875% per year.
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. The Senior Notes 2027 and Senior Notes 2029 accrue interest at the rate of 6.875% and 7.125% per year, respectively.
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.
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 Preferred Units are convertible into common units in accordance with the terms of the Partnership Agreement by the holders of the Preferred Units or by us in certain circumstances.
The Preferred Units are convertible into common units in accordance with the terms of the Partnership Agreement by the holders of the Preferred Units or by us in certain circumstances. In 2024, holders of our Preferred Units converted an aggregate of 320,000 Preferred Units.
The Preferred Unit distributions require $11.2 million quarterly, or $44.9 million annually, based on the number of Preferred Units outstanding as of February 8, 2024 and the distribution rate of $24.375 per Preferred Unit per quarter, or $97.50 per Preferred Unit per year.
The Preferred Unit distributions require $4.4 million quarterly, or $17.6 million annually, based on the number of Preferred Units outstanding as of February 6, 2025 and the distribution rate of $24.375 per Preferred Unit per quarter, or $97.50 per Preferred Unit per year.
For example, Section 404 requires us to, among other things, review and report annually on the effectiveness of our internal control over financial reporting.
For example, Section 404 requires us to, among other things, review and report annually on the effectiveness of our internal control over financial reporting. In addition, our independent registered public accountants are required to assess the effectiveness of our internal control over financial reporting.
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; • our ratio of taxable income to distributions may increase; • the relative voting strength of each previously outstanding common unit may be diminished; and • the market price of our common units may decline.
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.
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. 12 Table of Contents In particular, lower natural gas or crude oil prices over the long term could result in a decline in the production of natural gas or crude oil, respectively, resulting in reduced demand for our compression services.
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.
For example, as of December 31, 2023, one customer accounted for 17% of our trade accounts receivable, net balance. If this customer was 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, 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, for the year ended December 31, 2020, we recognized a $619.4 million impairment of goodwill as a result of the economic downturn caused by the response to COVID-19.
For example, for the year ended December 31, 2020, we recognized a $619.4 million impairment of goodwill as a result of an economic downturn that occurred that year.
If we do not achieve our expected growth, we may not be able to maintain or increase the level of distributions on our common units, likely causing the market price of our common units to decline. Pandemics and other public health crises may have an adverse effect on our business and results of operations.
If we do not achieve our expected growth, we may not be able to maintain or increase the level of distributions on our common units, likely causing the market price of our common units to decline.
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.
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.
As of December 31, 2023, we had outstanding borrowings under the Credit Agreement of $871.8 million and $728.2 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $529.1 million was available to be drawn.
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.
Our obligations to the holders of the Preferred Units also could limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.
Our obligations to the holders of the Preferred Units also could limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition. See Note 11 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
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. 13 Table of Contents 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.
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.
After the expiration of the initial term, the contract continues on a month-to-month or longer basis until terminated by us or our customers upon notice as provided for in the applicable contract.
Our contracts typically have initial terms between six months to five years, depending on the application and location of the compression unit. After the expiration of the initial term, the contract continues on a month-to-month or longer basis until terminated by us or our customers upon notice as provided for in the applicable contract.
Our reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner.
Our reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. In addition, supply chain disruptions (including those caused by geopolitical events) may harm our suppliers and further complicate existing supply chain constraints.
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.
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.
The Credit Agreement has an aggregate commitment of $1.6 billion (subject to availability under our borrowing base). The Credit Agreement matures on December 8, 2026, except that if any portion of the Senior Notes 2026 are outstanding on December 31, 2025, the Credit Agreement will mature on December 31, 2025.
The Credit Agreement has an aggregate commitment of $1.6 billion (subject to availability under our borrowing base). The Credit Agreement matures on December 8, 2026.
See Note 11 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data.” Restrictions in the Partnership Agreement related to the Preferred Units may limit our ability to make distributions to our common unitholders and our ability to capitalize on acquisition and other business opportunities.
Restrictions in the Partnership Agreement related to the Preferred Units may limit our ability to make distributions to our common unitholders and our ability to capitalize on acquisition and other business opportunities.
A 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. Based on our December 31, 2023, 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 $8.7 million.
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.
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. 11 Table of Contents 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.
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.
Please read Part III, Item 10 “Directors, Executive Officers, and Corporate Governance”. 28 Table of Contents 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 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.
In addition, our independent registered public accountants are required to assess the effectiveness of our internal control over financial reporting. 32 Table of Contents Any failure to develop, implement, or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations.
Any failure to develop, implement, or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations.
If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders. 31 Table of Contents A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units.
A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units.
Generally, our deduction for business interest is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and for taxable years beginning on or after January 1, 2022, shall be reduced by depreciation and amortization to the extent such depreciation or amortization is not capitalized into cost of goods sold with respect to inventory.
Generally, our deduction for business interest is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income.
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. Our ability to comply with those covenants and meet those financial ratios and tests can be affected by events beyond our control, including prevailing economic, financial, and industry conditions.
Our ability to comply with those covenants and meet those financial ratios and tests can be affected by events beyond our control, including prevailing economic, financial, and industry conditions. If market or other conditions deteriorate, our ability to comply with these covenants may be impaired.
As a result, we recorded impairments of compression equipment of $12.3 million, $1.5 million, and $5.1 million for the years ended December 31, 2023, 2022, and 2021, respectively. 18 Table of Contents Our ability to manage and grow our business effectively may be adversely affected if we lose key management or operational personnel.
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 of February 8, 2024, the holders of our Preferred Units (the “Preferred Unitholders”) have converted a portion of their Preferred Units into 1,998,850 common units, in accordance with the formula set forth in our Partnership Agreement.
As of February 6, 2025, the holders of our Preferred Units (the “Preferred Unitholders”) have converted a portion of their Preferred Units into 15,990,804 common units, in accordance with the formula set forth in our Partnership Agreement. Additionally, the warrants held by the Preferred Unitholders have been exercised and net settled in full for 2,894,796 common units.
Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method.
Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.
All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition, and cash available for distribution.
All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition, and cash available for distribution. Implementing the shared services model with Energy Transfer will be a complex and time-consuming process. Disruptions to our systems or operations caused by the implementation may have a material adverse impact on us.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeFor more information on this risk, read 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.” Governance Our IT leadership updates the Cybersecurity Steering Committee on cybersecurity risks and incidents, ensuring that management is kept aware of USAC’s cybersecurity postures and risks.
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.
We use industry-leading security tools, regularly perform security risk assessments and tool reviews with independent third parties to evaluate program effectiveness, and regularly update our security roadmap. Our IT department monitors industry news and updates to stay aware of the cybersecurity landscape, including incidents or issues that may arise involving our third-party service providers.
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.
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. Our IT department stays informed of current developments in cybersecurity threats and preventative measures and continuously updates our cybersecurity program based on this knowledge.
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.
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. We require all our employees to take monthly training and testing on cybersecurity threats, including how to recognize and properly respond to phishing and social engineering schemes.
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.
Our collaboration with these third parties includes regular audits, threat assessments, and consultation on security enhancements. These partnerships enable us to access specialized knowledge and insights which we leverage to continuously improve and modernize our cybersecurity program.
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.
As of the date of this report, we have not identified any risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, that have materially affected us, our business strategy, results of operation or financial condition.
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.
Removed
ITEM 1C. Cybersecurity Risk Management and Strategy Our cybersecurity program is led by our IT department and our Cybersecurity Steering Committee, which consists of IT leadership and certain of our senior management.
Added
ITEM 1C. Cybersecurity Description of Processes for Assessing, Identifying and Managing Cybersecurity Risks The information and operational technology infrastructure we use is important to the operation of our business and to our ability to perform day-to-day operations.
Removed
Additionally, our Cybersecurity Steering Committee 33 Table of Contents meets on a regular basis to assess, identify and manage material cyber risks. We also engage with a range of external specialists, including cybersecurity firms, consultants, and auditors in evaluating and testing our cybersecurity risk management systems, as well as specialized third-party companies that assist in monitoring our information systems.
Added
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.
Removed
We perform cybersecurity diligence on certain of our third-party service providers, and for third-party service providers with access to our internal information systems, we require them to review and agree to our relevant cybersecurity policies. Our cybersecurity program is designed to align with the National Institute of Standards and Technology’s five-phase Cybersecurity Framework (Identify-Protect-Detect-Respond-Recover).
Added
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.
Removed
We have deployed a phishing detection system to report suspicious emails, which are flagged for further review. We install and regularly update antivirus software on all company managed systems and workstations to detect and prevent malicious code from impacting our systems.
Added
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.
Removed
We have an incident response plan in place in the event of a cybersecurity incident to guide our response and mitigation actions, which includes requiring our IT team to escalate incidents of a certain severity to the appropriate members of management.
Added
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”).
Removed
While we have designed our cybersecurity program with the purpose of minimizing risk and protecting our assets, no cybersecurity measures can eliminate all risks. Therefore, there remains a possibility that we could experience a cybersecurity incident that could have a material impact on our business, results of operations, and financial condition.
Added
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.
Removed
The Cybersecurity Steering Committee is overseen by, and management periodically provides an update to, the Audit Committee of our Board of Directors regarding our cybersecurity posture and risks, ensuring that the Audit Committee has knowledge and oversight of significant cybersecurity matters and can provide guidance on critical cybersecurity issues.
Added
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).
Added
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.
Added
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.
Added
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
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.
Added
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.
Added
Additionally, we endeavor to require these providers to adhere to our security standards and protocols.
Added
Cybersecurity incident response is a component of both the Partnership’s cybersecurity program and the Partnership’s business continuity plans, which are designed to limit service interruptions and provide for continued business operation in the event of disaster, whether physical, environmental or cyber in nature.
Added
However, we recognize that cybersecurity threats are continually evolving, and there remains a risk that a cybersecurity incident could potentially negatively impact the Partnership. Despite the implementation of our cybersecurity processes, we cannot guarantee that a significant cybersecurity attack will not occur.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.

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, 2023, our headquarters consisted of 19,225 square feet of leased office space located at 111 Congress Avenue, Austin, Texas 78701.
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.

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. 34 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. 35 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 changeAs of February 8, 2024, we had outstanding 460,000 Preferred Units representing limited partner interests in the Partnership, all of which were held by EIG Veteran Equity Aggregator LP and FS Specialty Lending Fund (collectively, the “Preferred Unitholders”). The Preferred Units rank senior to our common units with respect to distributions and liquidation rights.
Biggest changeAs 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.
Issuer Purchases of Equity Securities None. Sales of Unregistered Securities; Use of Proceeds from Sale of Securities None. 35 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. 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]
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 8, 2024, based on information received from the transfer agent of the common units, we had 68 holders of record of our common units.
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.
As of April 2, 2023, we have the option to redeem all or any portion of the Preferred Units then outstanding, subject to certain minimum redemption threshold amounts, for a redemption price set forth in the Partnership Agreement.
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.
ITEM 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Our Partnership Interests As of February 8, 2024, we had 103,001,911 common units outstanding. Energy Transfer owns 100% of the membership interests in the General Partner and, as of February 8, 2024, beneficially owns approximately 45% 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 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 7. Management's Discussion & Analysis

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

82 edited+23 added−36 removed62 unchanged
Biggest changeThe above-stated factors also drove the increase in average horsepower utilization based on revenue-generating horsepower and fleet horsepower for the year ended December 31, 2023 as compared to the year ended December 31, 2022. 39 Table of Contents Financial Results of Operations Year ended December 31, 2023, compared to the year ended December 31, 2022 The following table summarizes our results of operations for the periods presented (dollars in thousands): Year Ended December 31, Increase 2023 2022 (Decrease) Revenues: Contract operations $ 802,562 $ 673,214 19.2 % Parts and service 21,890 15,729 39.2 % Related party 21,726 15,655 38.8 % Total revenues 846,178 704,598 20.1 % Costs and expenses: Cost of operations, exclusive of depreciation and amortization 284,708 234,336 21.5 % Depreciation and amortization 246,096 236,677 4.0 % Selling, general, and administrative 72,714 61,278 18.7 % Loss (gain) on disposition of assets (1,667) 1,527 * Impairment of compression equipment 12,346 1,487 * Total costs and expenses 614,197 535,305 14.7 % Operating income 231,981 169,293 37.0 % Other income (expense): Interest expense, net (169,924) (138,050) 23.1 % Gain on derivative instrument 7,449 — * Other 127 91 39.6 % Total other expense (162,348) (137,959) 17.7 % Net income before income tax expense 69,633 31,334 122.2 % Income tax expense 1,365 1,016 34.4 % Net income $ 68,268 $ 30,318 125.2 % ________________________ * Not meaningful.
Biggest changeThe 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.
Because we use capital assets, depreciation, impairment of compression equipment, loss (gain) on disposition of assets, and the interest cost of acquiring compression equipment also are necessary elements of our aggregate costs. Unit-based compensation expense related to equity awards granted to employees also is a meaningful business expense. Therefore, measures that exclude these cost elements have material limitations.
Because we use capital assets, depreciation, impairment of assets, loss (gain) on disposition of assets, and the interest cost of acquiring compression equipment also are necessary elements of our aggregate costs. Unit-based compensation expense related to equity awards granted to employees also is a meaningful business expense. Therefore, measures that exclude these cost elements have material limitations.
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.
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 units were written down to their estimated salvage values, if any.
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.
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.
Additionally, our compliance with state and local sales tax regulations is subject to audit by various taxing authorities. Certain taxing authorities have either claimed or issued an assessment that specific operational processes, which we and others in our industry regularly conduct, result in transactions that are subject to state sales taxes.
Additionally, our compliance with federal, state, and local tax regulations is subject to audit by various taxing authorities. Certain taxing authorities have either claimed or issued an assessment that specific operational processes, which we and others in our industry regularly conduct, result in transactions that are subject to taxes.
(3) 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. (4) Reflects actual maintenance capital expenditures for the period presented.
(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.
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 2024.
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.
The $6.2 million increase in parts and service revenue for the year ended December 31, 2023, compared to the year ended December 31, 2022, 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 $2.0 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.
Discussion and analysis of our operating highlights and financial results of operations for the year ended December 31, 2022, compared to the year ended December 31, 2021, 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, 2022, filed with the SEC on February 14, 2023.
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.
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 Delaware 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, and the Mid-Continent.
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, 2023 and 2022, were $25.2 million and $23.8 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, 2024 and 2023, were $31.9 million and $25.2 million, respectively.
We define Adjusted EBITDA as EBITDA plus impairment of compression equipment, 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 (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, certain transaction expenses, loss (gain) on disposition of assets, loss on extinguishment of debt, loss (gain) on derivative instrument, and other.
Based on discussions with the IRS, we estimate a potential range of loss from a final imputed underpayment of $0 to approximately $26.4 million, including interest, for potential adjustments resulting from the IRS examinations.
Based on discussions with the IRS, we estimate a potential range of loss from a final imputed underpayment of $0 to approximately $28.3 million, including interest, for potential adjustments resulting from the IRS examinations.
If our projections of cash flows associated with our units decline, we may have to record an impairment of compression equipment in future periods.
If our projections of cash flows associated with our units decline, we may have to record an impairment of assets in future periods.
The EIA Outlook expects dry natural gas production to increase by 1.5 billion cubic feet per day (“bcf/d”) in 2024 and by 1.3 bcf/d in 2025, 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 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.
Total available horsepower excludes new horsepower on order for which we do not have an executed compression services contract. (3) Revenue-generating horsepower is horsepower under contract for which we are billing a customer. (4) Calculated as the average of the month-end revenue-generating horsepower for each of the months in the period.
Total available horsepower excludes new horsepower expected to be delivered for which we do not have an executed compression services contract. (3) Revenue-generating horsepower is horsepower under contract for which we are billing a customer. (4) Calculated as the average of the month-end revenue-generating horsepower for each of the months in the period.
(7) Horsepower utilization is calculated as (i) the sum of (a) revenue-generating horsepower, (b) horsepower in our fleet that is under contract, but is not yet generating revenue, and (c) horsepower not yet in our fleet that is under contract but not yet generating revenue and that is subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair.
(7) Horsepower utilization is calculated as (i) the sum of (a) revenue-generating horsepower, (b) horsepower in our fleet that is under contract, but is not yet generating revenue, and (c) horsepower not yet in our fleet that is under contract but not yet generating revenue and that is expected to be delivered, divided by (ii) total available horsepower less idle horsepower that is under repair.
Horsepower utilization based on revenue-generating horsepower and fleet horsepower was 90.9% and 86.1% as of December 31, 2023, and 2022, 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 92.4% 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.
For the years ended December 31, 2023 and 2022, we evaluated the future deployment of our idle fleet assets under then-current market conditions and retired 42 and 15 compression units, respectively, representing approximately 37,700 and 3,200 of aggregate horsepower, respectively, that previously were used to provide compression services in our business.
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.
(2) Total available horsepower is revenue-generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract but not yet generating revenue and that is subject to a purchase order, and idle horsepower.
(2) Total available horsepower is revenue-generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract but not yet generating revenue and that is expected to be delivered, and idle horsepower.
As a result, we recorded impairments of compression equipment of $12.3 million and $1.5 million for the years ended December 31, 2023, and 2022, respectively.
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.
According to the EIA Outlook, the U.S. witnessed record LNG exports of 11.8 bcf/d during 2023 and expects LNG exports to set new records of 12.4 bcf/d and 14.4 bcf/d in 2024 and 2025, 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 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.
The $12.3 million and $1.5 million impairments of compression equipment during the years ended December 31, 2023 and 2022, respectively, primarily resulted from our evaluation of the future deployment of our idle fleet assets under then-current market conditions.
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.
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 49 Table of Contents our assets.
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.
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, 2023 2022 Total revenues $ 846,178 $ 704,598 Cost of operations, exclusive of depreciation and amortization (284,708) (234,336) Depreciation and amortization (246,096) (236,677) Gross margin $ 315,374 $ 233,585 Depreciation and amortization 246,096 236,677 Adjusted gross margin $ 561,470 $ 470,262 Adjusted EBITDA We define EBITDA as net income (loss) before net interest expense, depreciation and amortization expense, and income tax expense (benefit).
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 $86.0 million increase in Adjusted EBITDA for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to a $91.2 million increase in Adjusted gross margin, partially offset by a $5.1 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses. DCF.
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.
Other Commitments As of December 31, 2023, other commitments include operating and finance lease payments totaling $22.7 million, of which we expect to make payments of $5.4 million to be settled in the next twelve months.
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.
As of December 31, 2023, we were in compliance with all of our covenants under the Credit Agreement. As of February 8, 2024, we had outstanding borrowings under the Credit Agreement of $927.5 million and outstanding letters of credit of $0.5 million.
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.
Average horsepower utilization based on revenue-generating horsepower and fleet horsepower was 89.2% and 82.9% for the years ended December 31, 2023, and 2022, respectively.
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.
Our DCF Coverage Ratio, as presented, may not be comparable to similarly titled measures of other companies. 48 Table of Contents The following table summarizes our DCF Coverage Ratio for the periods presented (dollars in thousands): Year Ended December 31, 2023 2022 DCF $ 281,113 $ 221,499 Distributions for DCF Coverage Ratio (1) $ 208,856 $ 205,559 DCF Coverage Ratio 1.35 x 1.08 x ________________________ (1) Represents distributions to the holders of our common units as of the record date.
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 Senior Notes 2026 are due on April 1, 2026, and accrue interest at the rate of 6.875% per year. Interest on the Senior Notes 2026 is payable semi-annually in arrears on each of April 1 and October 1. The Senior Notes 2027 are due on September 1, 2027, and accrue interest at the rate of 6.875% per year.
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.
As a result of our evaluations during the years ended December 31, 2023 and 2022, we retired 42 and 15 compression units, respectively, with approximately 37,700 and 3,200 aggregate horsepower, respectively, that previously were used to provide compression services in our business. Interest expense, net .
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.
DRIP During the years ended December 31, 2023 and 2022, distributions of $1.9 million and $2.1 million, respectively, were reinvested under the DRIP resulting in the issuance of 87,808 and 124,255 common units, respectively.
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.
In 2024 and 2025, the EIA Outlook expects U.S. crude oil production growth to continue, albeit at a slower rate, estimating average production of 13.2 million bpd for 2024 and 13.4 million bpd in 2025, which would represent new records for annual average crude oil production.
In 2025 and 2026, the EIA Outlook expects U.S. crude oil production growth to continue, albeit at a lower crude oil price, estimating average production of 13.5 million bpd for 2025 and 13.6 million bpd in 2026, which would represent new records for annual average crude oil production.
Recent Accounting Pronouncements See Part II, Item 8 “Financial Statements and Supplementary Data”, Note 18 for recent accounting pronouncements affecting us. 50 Table of Contents
Recent Accounting Pronouncements See Part II, Item 8 “Financial Statements and Supplementary Data”, Note 19 for recent accounting pronouncements affecting us.
DCF should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), cash flows from operating activities, or any other measure presented in accordance with GAAP.
DCF should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), cash flows from operating activities, or any other measure presented in accordance with GAAP. Moreover, our DCF, as presented, may not be comparable to similarly titled measures of other companies.
We currently plan to spend approximately $32.0 million in maintenance capital expenditures during 2024, including parts consumed from inventory. Without giving effect to any equipment that we may acquire pursuant to any future acquisitions, we currently have budgeted between $115.0 million and $125.0 million in expansion capital expenditures for 2024.
We currently have budgeted between $38.0 million and $42.0 million in maintenance capital expenditures during 2025, including parts consumed from inventory. Without giving effect to any equipment that we may acquire pursuant to any future acquisitions, we currently have budgeted between $120.0 million and $140.0 million in expansion capital expenditures for 2025.
The $59.6 million increase in DCF for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) a $91.2 million increase in Adjusted gross margin, (ii) a $6.2 million increase in cash received on derivative instrument, and (iii) a $1.0 million decrease in distributions on Preferred Units, partially offset by (iv) a $31.9 million increase in cash interest expense, net, (v) a $5.1 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses, and (vi) a $1.5 million increase in maintenance capital expenditures.
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.
Loss (gain) on disposition of assets. The $1.7 million gain on disposition of assets for the year ended December 31, 2023, and the $1.5 million loss on disposition of assets for the year ended December 31, 2022, were related to various asset disposals. Impairment of compression equipment .
Loss (gain) on disposition of assets. The $4.9 million loss on disposition of assets for the year ended December 31, 2024, and the $1.7 million gain on disposition of assets for the year ended December 31, 2023, were related to various asset transactions. Impairment of assets .
The $129.3 million increase in contract operations revenue for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) an 8.7% 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) an 8.5% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with increased production levels in the basins in which we operate, and (iii) a $24.2 million increase in revenue attributable to natural gas treating services.
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.
Cash Flows The following table summarizes our sources and uses of cash for the years ended December 31, 2023 and 2022, (in thousands): Year Ended December 31, 2023 2022 Net cash provided by operating activities $ 271,885 $ 260,590 Net cash used in investing activities (232,653) (129,945) Net cash used in financing activities (39,256) (130,610) Net cash provided by operating activities .
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 .
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, 2023 2022 Net income $ 68,268 $ 30,318 Interest expense, net 169,924 138,050 Depreciation and amortization 246,096 236,677 Income tax expense 1,365 1,016 EBITDA $ 485,653 $ 406,061 Unit-based compensation expense (1) 22,169 15,894 Transaction expenses (2) 46 27 Severance charges 841 982 Loss (gain) on disposition of assets (1,667) 1,527 Gain on derivative instrument (7,449) — Impairment of compression equipment (3) 12,346 1,487 Adjusted EBITDA $ 511,939 $ 425,978 Interest expense, net (169,924) (138,050) Non-cash interest expense 7,279 7,265 Income tax expense (1,365) (1,016) Transaction expenses (46) (27) Severance charges (841) (982) Cash received on derivative instrument 6,245 — Other 1,448 (851) Changes in operating assets and liabilities (82,850) (31,727) Net cash provided by operating activities $ 271,885 $ 260,590 ________________________ (1) For the years ended December 31, 2023 and 2022, unit-based compensation expense included $4.4 million and $4.4 million, respectively, of cash payments related to quarterly payments of DERs on outstanding phantom unit awards and $0.3 million and $1.3 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. 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.
Adjusted gross margin. The $91.2 million increase in Adjusted gross margin for the year ended December 31, 2023, compared to the year ended December 31, 2022, was due to a $141.6 million increase in revenues, offset by a $50.4 million increase in cost of operations, exclusive of depreciation and amortization. Adjusted EBITDA.
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.
The demand for domestic natural gas also continues to benefit from the construction of LNG export infrastructure, which enables industry participants to benefit from attractive global natural gas prices.
Growth in power demands from the development of artificial intelligence is also expected to increase demand. Finally, the demand for domestic natural gas also continues to benefit from the construction of LNG export infrastructure, which enables industry participants to benefit from attractive global natural gas prices.
Revolving Credit Facility As of December 31, 2023, we had outstanding borrowings under the Credit Agreement of $871.8 million and $728.2 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $529.1 million was available to be drawn.
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.
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 2024. 42 Table of Contents Because we distribute all of our available cash, which excludes prudent operating reserves, we expect to fund any future expansion capital expenditures or acquisitions primarily with capital from external financing sources, such as borrowings under the Credit Agreement and issuances of debt and equity securities, including under the DRIP.
Because we distribute all of our available cash, which excludes prudent operating reserves, we expect to fund any future expansion capital expenditures or acquisitions primarily with capital from external financing sources, such as borrowings under the Credit Agreement and issuances of debt and equity securities, including under the DRIP.
The $31.9 million increase in interest expense, net for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to higher weighted-average interest rates and increased borrowings under the Credit Agreement.
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 $102.7 million increase in net cash used in investing activities for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to a $104.3 million increase in capital expenditures, for purchases of new compression units, overhauls and major improvements, and purchases of other equipment, partially offset by a $1.7 million increase in proceeds from disposition of property and equipment. 43 Table of Contents Net cash used in financing activities .
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 $81.8 million increase in gross margin for the year ended December 31, 2023, compared to the year ended December 31, 2022, was due to (i) a $141.6 million increase in revenues, offset by (ii) a $50.4 million increase in cost of operations, exclusive of depreciation and amortization, and (iii) a $9.4 million increase in depreciation and amortization.
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.
Derivative Instrument In April 2023, we entered into an interest-rate swap to manage interest-rate risk associated with the floating-rate Credit Agreement, and in October 2023, we modified this interest-rate swap. See Note 8 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for more information regarding the interest-rate swap.
Derivative Instrument During the year ended December 31, 2024, we elected to terminate the interest-rate swap we previously used to manage interest-rate risk associated with the floating-rate Credit Agreement, see Note 8 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for more information regarding the interest-rate swap.
The $11.3 million increase in net cash provided by operating activities for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) an increase in cash inflows from a $91.2 million increase in Adjusted gross margin, partially offset by (ii) a $45.2 million increase in inventory purchases and (iii) a $34.6 million increase in cash paid for interest expense, net of capitalized amounts.
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.
Interest on the Senior Notes 2027 is payable semi-annually in arrears on each of March 1 and September 1. For more detailed descriptions of the Senior Notes 2026 and Senior Notes 2027, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
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”.
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 compression equipment, impairment of goodwill, certain transaction expenses, severance charges, loss (gain) on disposition of assets, change in fair value of derivative instrument, proceeds from insurance recovery, and other, less distributions on Preferred Units and maintenance capital expenditures.
(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.
The 1.6% increase in fleet horsepower as of December 31, 2023, compared to December 31, 2022, primarily was due to compression units added to our fleet to meet incremental demand from customers for our compression services, partially offset by compression units impaired since the previous period.
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.
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.
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.
The $50.4 million increase in cost of operations for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) a $26.0 million increase in direct expenses, primarily driven by fluids and parts due to higher costs and increased usage associated with increased revenue-generating horsepower, (ii) a $13.6 million increase in direct labor costs due to increased headcount associated with increased revenue-generating horsepower and higher employee costs, (iii) a $5.1 million increase in retail parts and service expenses, for which a corresponding increase in parts and service revenue also occurred, (iv) a $1.6 million increase in other indirect expenses primarily due to increased consumption and costs of supplies associated with increased revenue-generating horsepower, (v) a $1.5 million increase in expenses related to our vehicle fleet, primarily due to increased usage and maintenance costs associated with increased revenue-generating horsepower, and (vi) a $1.4 million increase in non-income taxes associated with increased revenue-generating horsepower in taxable jurisdictions.
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 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, 2023 2022 Net income $ 68,268 $ 30,318 Non-cash interest expense 7,279 7,265 Depreciation and amortization 246,096 236,677 Non-cash income tax benefit (52) (151) Unit-based compensation expense (1) 22,169 15,894 Transaction expenses (2) 46 27 Severance charges 841 982 Loss (gain) on disposition of assets (1,667) 1,527 Change in fair value of derivative instrument (1,204) — Impairment of compression equipment (3) 12,346 1,487 Distributions on Preferred Units (47,775) (48,750) Maintenance capital expenditures (4) (25,234) (23,777) DCF $ 281,113 $ 221,499 Maintenance capital expenditures 25,234 23,777 Transaction expenses (46) (27) Severance charges (841) (982) Distributions on Preferred Units 47,775 48,750 Other 1,500 (700) Changes in operating assets and liabilities (82,850) (31,727) Net cash provided by operating activities $ 271,885 $ 260,590 ________________________ (1) For the years ended December 31, 2023 and 2022, unit-based compensation expense included $4.4 million and $4.4 million, respectively, of cash payments related to quarterly payments of DERs on outstanding phantom unit awards and $0.3 million and $1.3 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. 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.
Year Ended December 31, 2023 2022 Increase Fleet horsepower (at period end) (1) 3,775,660 3,716,854 1.6 % Total available horsepower (at period end) (2) 3,831,444 3,826,854 0.1 % Revenue-generating horsepower (at period end) (3) 3,433,775 3,199,548 7.3 % Average revenue-generating horsepower (4) 3,328,999 3,067,279 8.5 % Average revenue per revenue-generating horsepower per month (5) $ 18.86 $ 17.35 8.7 % Revenue-generating compression units (at period end) 4,237 4,116 2.9 % Average horsepower per revenue-generating compression unit (6) 792 765 3.5 % Horsepower utilization (7): At period end 94.3 % 91.8 % 2.5 % Average for the period (8) 93.4 % 88.6 % 4.8 % ________________________ (1) Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order).
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.
The $11.4 million increase in selling, general, and administrative expense for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) a $6.3 million increase 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, 2023, (ii) a $2.2 million increase to the allowance for credit losses, resulting from a $1.5 million increase to the provision for expected credit losses in the current period versus a $0.7 million reversal of previously recognized credit losses in the prior comparable period, and (iii) a $2.1 million increase in employee-related expenses, driven by increased headcount and higher employee costs.
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.
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.
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.
Depreciation and amortization expense . The $9.4 million increase in depreciation and amortization expense for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to new compression units placed in service to meet incremental demand from customers and overhauls and major improvements to compression units. Selling, general, and administrative expense .
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 .
The $7.4 million gain on derivative instrument for the year ended December 31, 2023 resulted from the increase in fair value of the interest-rate swap due to an increase in the interest-rate forward curve during the year.
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 $91.4 million decrease in net cash used in financing activities for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) an $96.2 million increase in net borrowings under the Credit Agreement, partially offset by (ii) a $3.5 million increase in cash paid related to net settlement of unit-based awards and (iii) a $1.6 million increase in common unit distributions.
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.
We had no derivative instruments outstanding for the year ended December 31, 2022. 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) 2023 2022 (Decrease) Gross margin $ 315,374 $ 233,585 35.0 % Adjusted gross margin $ 561,470 $ 470,262 19.4 % Adjusted gross margin percentage (2) 66.4 % 66.7 % (0.3) % Adjusted EBITDA $ 511,939 $ 425,978 20.2 % Adjusted EBITDA percentage (2) 60.5 % 60.5 % — % DCF $ 281,113 $ 221,499 26.9 % DCF Coverage Ratio 1.35 x 1.08 x 25.0 % ________________________ (1) Adjusted gross margin, Adjusted EBITDA, Distributable Cash Flow (“DCF”), and DCF Coverage Ratio are all non-GAAP financial measures.
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.
Our expansion capital expenditures for the years ended December 31, 2023 and 2022, were $275.4 million and $145.1 million, respectively. As of December 31, 2023, we had binding commitments to purchase $53.4 million worth of additional compression units and serialized parts, all of which is expected to be settled within the next twelve months.
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.
As of December 31, 2023, we had 52,500 large horsepower on order for expected delivery during 2024.
As of December 31, 2024, we had no horsepower on order. Subsequent to December 31, 2024, the Partnership ordered 10,000 large horsepower for expected delivery during 2025.
We expect that anticipated crude oil production increases likewise will increase associated natural gas production volumes throughout 2024, thereby increasing demand for our compression services, particularly in the Permian and Delaware Basins.
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.
For a more detailed description of the Credit Agreement, including the covenants and restrictions contained therein, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data.”. 44 Table of Contents Senior Notes As of December 31, 2023, we had $725.0 million and $750.0 million aggregate principal amount outstanding on our Senior Notes 2026 and Senior Notes 2027, respectively.
For a more detailed description of the Credit Agreement, including the covenants and restrictions contained therein, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
DCF Coverage Ratio . The increase in DCF Coverage Ratio for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to the increase in DCF, partially offset by increased distributions due to an increase in the number of outstanding common units.
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.
Our business largely focuses on compression services serving infrastructure applications, including centralized natural gas gathering systems and processing facilities, which utilize large horsepower compression units, typically in shale plays. We also provide compression services in more mature basins, including gas lift applications on crude oil wells targeted by horizontal drilling techniques.
We believe we are well-positioned to meet these changing operating conditions due to the operational design flexibility inherit within our compression-unit fleets. Our business includes compression services serving infrastructure applications, including centralized natural gas gathering systems and processing facilities, which utilize large-horsepower compression units and also gas lift applications on crude oil wells targeted by horizontal drilling techniques.
Further, the EIA Outlook expects U.S natural gas consumption to increase another 2.4 bcf/d in 2025, driven primarily by LNG exports while baseload demand remains consistent, and for demand growth to exceed supply growth by 1.0 bcf/d in 2025.
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.
The Partnership’s obligations under the Credit Agreement are guaranteed by the guarantors party to the Credit Agreement, which currently consists of all of the Partnership’s subsidiaries.
The Credit Agreement provides for an asset-based revolving credit facility to be made available to the Partnership in an aggregate amount of $1.6 billion. The Partnership’s obligations under the Credit Agreement are guaranteed by the guarantors party to the Credit Agreement, which currently consists of all of the Partnership’s subsidiaries.
Natural gas prices averaged $2.54 per million British thermal units (“MMBtu”) in 2023 and the EIA Outlook expects natural gas prices to increase on average to $2.66/MMBtu and $2.95/MMBtu in 2024 and 2025, 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.
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.
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.
Our DCF excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these excluded items may vary among companies. 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.
Our DCF excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these excluded items may vary among companies.
Overview We provide compression services in shale plays throughout the U.S., including the Utica, Marcellus, Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara, and Fayetteville shales. Demand for our services is driven by the domestic production of natural gas and crude oil.
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.
Unit-based compensation expense related to equity awards granted to employees also is a meaningful business expense. Therefore, measures that exclude these cost elements have material limitations.
Because we use capital assets, depreciation, impairment of assets, loss (gain) on disposition of assets, the interest cost of acquiring compression equipment, and maintenance capital expenditures are necessary components of our aggregate costs. Unit-based compensation expense related to equity awards granted to employees also is a meaningful business expense. Therefore, measures that exclude these cost elements have material limitations.
The 3.5% increase in average horsepower per revenue-generating compression unit for the year ended December 31, 2023, compared to the year ended December 31, 2022, was driven by both the redeployment of, and addition of new, large-horsepower compression units. Horsepower utilization increased to 94.3% as of December 31, 2023, compared to 91.8% as of December 31, 2022.
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 EIA Outlook estimates that annual U.S. crude oil production averaged 12.9 million bpd in 2023, up 1.0 million bpd from 2022, primarily due to production growth in the Permian region of western Texas and eastern New Mexico.
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.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

6 edited+0 added−2 removed5 unchanged
Biggest changeFor 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 April 2023, we entered into an interest-rate swap to manage interest-rate risk associated with the floating-rate Credit Agreement. In October 2023, we modified this interest-rate swap.
Biggest changeFor 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.
Please 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 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.
Please 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.
For further information regarding our interest-rate swap, 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 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.
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, 2023 would result in an annual decrease of approximately $7.5 million and $5.0 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, 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.
Financial Statements and Supplementary Data The financial statements and supplementary information specified by this Item are presented in Part IV, Item 15 “Exhibits and Financial Statement Schedules”. ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure None. 51 Table of Contents
Financial Statements and Supplementary Data The financial statements and supplementary information specified by this Item are presented in Part IV, Item 15 “Exhibits and Financial Statement Schedules”. ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure None.
As of December 31, 2023, we had $871.8 million of variable-rate indebtedness outstanding at a weighted-average interest rate of 7.98%. Based on our December 31, 2023 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 $8.7 million.
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.
Removed
As of December 31, 2023, the interest-rate swap’s notional principal amount was $700 million, with a termination date of December 31, 2025. Under the interest-rate swap, we pay a fixed interest rate, which as of December 31, 2023 was 3.9725%, and receive floating interest rate payments that are indexed to the one-month SOFR.
Removed
Based on the fixed interest rate as of December 31, 2023, a one percent increase or decrease in the SOFR interest-rate forward curve would result in an increase or decrease, respectively, in the fair value of this interest-rate swap of $14.8 million, prior to any discount factors or credit valuation adjustments.

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