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What changed in USA Compression Partners, LP's 10-K — 2022 vs 2023

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Paragraph-level year-over-year comparison of USA Compression Partners, LP's 2022 and 2023 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 2023 report.

+248 added−242 removedSource: 10-K (2024-02-13) vs 10-K (2023-02-14)

Top changes in USA Compression Partners, LP's 2023 10-K

248 paragraphs added · 242 removed · 200 edited across 7 sections

Item 1. Business

Business — how the company describes what it does

25 edited+2 added−4 removed124 unchanged
Biggest changeWe are managed by our general partner, USA Compression GP, LLC (the “General Partner”), which is wholly owned by Energy Transfer. 1 Table of Contents All references in this section to the Partnership, as well as the terms “our,” “we,” “us,” and “its” refer to USA Compression Partners, LP, together with its consolidated subsidiaries, unless the context otherwise requires or where otherwise indicated.
Biggest changeAll references in this section to the Partnership, as well as the terms “our,” “we,” “us,” and “its” refer to USA Compression Partners, LP, together with its consolidated subsidiaries, unless the context otherwise requires or where otherwise indicated. 1 Table of Contents Overview We believe that we are one of the largest independent providers of natural gas compression services in the U.S. in terms of total compression fleet horsepower.
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. 7 Table of Contents Water discharge .
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 .
We operate a modern fleet of compression units, with an average age of approximately 11 years. We acquire our compression units 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 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.
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 2023 where beneficial from an operational and financial standpoint.
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.
As of December 31, 2022, 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, 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.
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.
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.
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 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.
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 38%, 39%, and 35% of our total revenues for the years ended December 31, 2022, 2021, and 2020, 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 39%, 38%, and 39% of our total revenues for the years ended December 31, 2023, 2022, and 2021, respectively.
Our customers may have compression demands in conjunction with their field 2 Table of Contents development projects in areas of the U.S. where we are not currently operating, and we continually consider further expansion of our geographic areas of operation in the U.S. based upon the level of customer demand.
Our customers may have compression demands in conjunction with their field development projects in areas of the U.S. where we are not currently operating, and we continually consider further expansion of our geographic areas of operation in the U.S. based upon the level of customer demand.
For example, in 2009, the EPA officially published its findings that emissions of carbon dioxide, methane, and 6 Table of Contents other GHGs endanger human health and the environment, allowing the agency to proceed with the adoption of regulations that restrict emissions of GHG under existing provisions of the CAA.
For example, in 2009, the EPA officially published its findings that emissions of carbon dioxide, methane, and other GHGs endanger human health and the environment, allowing the agency to proceed with the adoption of regulations that restrict emissions of GHG under existing provisions of the CAA.
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.
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.
These larger-horsepower units, which we define as 400 horsepower per unit or greater, represented 87.1% of our total fleet horsepower (including compression units on order) as of December 31, 2022. 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 87.0% 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.
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 1.65 million hours worked in 2022, our TRIR was 0.12 for 2022 versus the 2022 industry average of 0.70.
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.
Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases (“GHGs”). In recent years, the U.S. Congress has considered legislation to reduce GHG emissions.
Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases (“GHGs”). The U.S. Congress, from time to time, has considered legislation to reduce GHG emissions.
For example, the Texas Commission on Environmental Quality (“TCEQ”) has finalized revisions to certain air permit programs that significantly increase the air permitting requirements for new and certain existing oil and gas production and gathering sites for 15 counties in the Barnett Shale production area.
We also are subject to air regulation at the state level. For example, the Texas Commission on Environmental Quality (“TCEQ”) has finalized revisions to certain air permit programs that significantly increase the air permitting requirements for new and certain existing oil and gas production and gathering sites for 15 counties in the Barnett Shale production area.
Although lead-times for new Caterpillar engines and new Ariel compressor frames have in the recent past varied between six months and one year due to changes in demand and supply allocations, as of December 31, 2022, lead-times for such engines and frames are slightly more than 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, 2023, lead-times for such engines and frames are approximately one year.
We cannot provide any assurance that the costs and liabilities associated with the future imposition of such remedial obligations upon us would not have a material adverse effect on our operations or financial position. 8 Table of Contents Safety and health .
We cannot provide any assurance that the costs and liabilities associated with the future imposition of such remedial obligations upon us would not have a material adverse effect on our operations or financial position. Safety and health . The Occupational Safety and Health Act (“OSHA”) and comparable state laws strictly govern the protection of the health and safety of employees.
None of our employees are subject to collective bargaining agreements. We consider our employee relations to be good. Our employees are our greatest asset, and we seek to attract and retain top talent by fostering a culture that is guided by our four pillars of people, culture, equipment, and service.
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.
While specific rules and regulations under the IRA 2022 have yet to be released, 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 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.
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, 2022, we had 3,716,854 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, 2023, we had 3,775,660 horsepower in our fleet.
Any additional regulation of air emissions from the oil and gas sector could result in increased expenditures for pollution control equipment, which could impact our customers’ operations and negatively impact our business. We also are subject to air regulation at the state level.
In addition, in December 2023, the EPA issued rules to further reduce methane and VOC emissions from new and existing sources in the oil and gas sector. Any additional regulation of air emissions from the oil and gas sector could result in increased expenditures for pollution control equipment, which could impact our customers’ operations and negatively impact our business.
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. Several lawsuits challenging the final rule have been filed in federal court. In addition, the U.S. Supreme Court has granted review of Sackett vs.
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 .
Human Capital Management USA Compression Management Services, LLC (“USAC Management”), a wholly owned subsidiary of the General Partner, performs certain management and other administrative services for us, such as accounting, corporate development, finance, and legal. All of our employees, including our executive officers, are employees of USAC Management. As of December 31, 2022, USAC Management had 730 full-time employees.
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.
ITEM 1. Business USA Compression Partners, LP (the “Partnership”) is a growth-oriented Delaware limited partnership.
ITEM 1. Business USA Compression Partners, LP (the “Partnership”) is a growth-oriented Delaware limited partnership. We are managed by our general partner, USA Compression GP, LLC (the “General Partner”), which is wholly owned by Energy Transfer.
The following table provides a summary of our compression units by horsepower as of December 31, 2022: Unit Horsepower Fleet Horsepower Number of Units Horsepower on Order (1) Number of Units on Order Total Horsepower Number of Units Percent of Total Horsepower Percent of Units Small horsepower 502,012 2,956 — — 502,012 2,956 12.9 % 54.2 % Large horsepower ≥400 and 428,947 732 — — 428,947 732 11.1 % 13.4 % ≥1,000 2,785,895 1,698 165,000 66 2,950,895 1,764 76.0 % 32.4 % Total large horsepower 3,214,842 2,430 165,000 66 3,379,842 2,496 87.1 % 45.8 % Total horsepower 3,716,854 5,386 165,000 66 3,881,854 5,452 100.0 % 100.0 % ________________________ (1) As of December 31, 2022, we had 66 large horsepower units, consisting of 165,000 horsepower, on order for delivery during 2023.
The 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.
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Overview We believe that we are one of the largest independent providers of natural gas compression services in the U.S. in terms of total compression fleet horsepower. We have been providing compression services since 1998 and completed our initial public offering in January 2013.
Added
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.
Removed
In addition, in November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and gas sector. In November 2022, the EPA issued a supplemental proposal to expand its November 2021 proposed rule.
Added
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.
Removed
EPA , which involves issues related to CWA scope and jurisdiction. The Court’s decision in Sackett , which is expected in the coming months, could impact the validity of the final rule and trigger further regulatory action.
Removed
The Occupational Safety and Health Act (“OSHA”) and comparable state laws strictly govern the protection of the health and safety of employees.

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

79 edited+14 added−11 removed285 unchanged
Biggest changeIf the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or if we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced. • The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial, or administrative changes or differing interpretations, possibly applied on a retroactive basis. • Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us. • If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced. • Tax gain or loss on the disposition of our common units could be more or less than expected. • Unitholders will be subject to limitation on their ability to deduct interest expense incurred by us. • Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units. • We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased.
Biggest changeUnitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from them with respect to that income. • If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced. • Tax gain or loss on the disposition of our common units could be more or less than expected. • Unitholders will be subject to limitation on their ability to deduct interest expense incurred by us. • Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units. • We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased.
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 in 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 2020 and 2021.
These factors include, among others, the potential adoption of new government regulations, including those related to 22 Table of Contents fuel conservation measures and climate change regulations, technological advances in fuel economy, and energy generation 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 22 Table of Contents devices.
The COVID-19 pandemic that began in early 2020 caused volatility in the capital markets and negatively impacted the worldwide economy, including the oil and gas industry. Demand for crude oil and natural gas declined in 2020 due in part to the COVID-19 pandemic and associated government-imposed restrictions and decreased consumer demand.
For example, the COVID-19 pandemic that began in early 2020 caused volatility in the capital markets and negatively impacted the worldwide economy, including the oil and gas industry. Demand for crude oil and natural gas declined in 2020 due in part to the COVID-19 pandemic and associated government-imposed restrictions and decreased consumer demand.
Additionally, in March 2022, the SEC announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.
In March 2022, the SEC announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.
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; 19 Table of Contents • maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and • integrating new technology systems for financial reporting.
The difficulties of integrating past and future acquisitions with our business include, among other things: • operating a larger combined organization in new geographic areas and new lines of business; • 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 Credit Agreement and the Indentures contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability to: • incur additional indebtedness; • pay dividends or make other distributions or repurchase or redeem equity interests; • prepay, redeem, or repurchase certain debt; • issue certain preferred units or similar equity securities; • make investments; • sell assets; • incur liens; • enter into transactions with affiliates; • alter the businesses we conduct; • enter into agreements restricting our subsidiaries’ ability to pay distributions; and • consolidate, merge, or sell all or substantially all of our assets.
The 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.
A discontinuation of our services by a significant number of these customers could have a material adverse effect on our business, results of operations, financial condition, and cash available for distribution. • Our debt level, including any increases in interest rates, may limit our flexibility in obtaining additional financing, pursuing other business opportunities, and paying distributions. • We depend on a limited number of suppliers and are vulnerable to product shortages and price increases, which could have a negative impact on our results of operations. • We may be unable to grow our cash flows if we are unable to expand our business, which could limit our ability to maintain or increase the level of distributions to our common unitholders. • We may be unable to grow successfully through acquisitions, which may negatively impact our operations and limit our ability to maintain or increase the level of distributions on our common units. • Our ability to fund purchases of additional compression units and expansion capital expenditures in the future is dependent on our ability to access external capital, and if we are unable to access this external capital, we may be limited in our ability to grow our operations or maintain or increase our distributions.
A discontinuation of our services by a significant number of these customers could have a material adverse effect on our business, results of operations, financial condition, and cash available for distribution. • Our debt level, including any increases in interest rates, may limit our flexibility in obtaining additional financing, pursuing other business opportunities, and paying distributions. • We depend on a limited number of suppliers and are vulnerable to product shortages and price increases, which could have a negative impact on our results of operations. • We may be unable to grow our cash flows if we are unable to expand our business, which could limit our ability to maintain or increase the level of distributions to our common unitholders. • Our ability to fund purchases of additional compression units and expansion capital expenditures in the future is dependent on our ability to access external capital, and if we are unable to access this external capital, we may be limited in our ability to grow our operations or maintain or increase our distributions.
See Note 10 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.
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.
We may be unable to effect any of these actions on terms satisfactory to us or at all. We depend on a limited number of suppliers and are vulnerable to product shortages and price increases, which could have a negative impact on our results of operations.
We may be unable to affect any of these actions on terms satisfactory to us or at all. We depend on a limited number of suppliers and are vulnerable to product shortages and price increases, which could have a negative impact on our results of operations.
As of December 31, 2022, 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, 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.
See Part I, Item 3 “Legal Proceedings” and Note 16 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information regarding certain proceedings to which we are a party.
See Part I, Item 3 “Legal Proceedings” and Note 17 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information regarding certain proceedings to which we are a party.
Financial covenants in the Credit Agreement permit a maximum leverage ratio of not greater than 5.50 to 1.00 through the third fiscal quarter of 2023 and 5.25 to 1.00 thereafter (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 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.
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.
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.
For example, subsequent to the CDM Acquisition the attrition rate of specialized field technicians exceeded our projections and, as a result, we incurred unanticipated costs in 2018 to utilize third-party contractors to service our compression units at a greater cost than we would have incurred to compensate employees to perform the same work.
For example, subsequent to the CDM Acquisition the attrition rate of specialized field technicians exceeded our projections and, as a result, we incurred 19 Table of Contents unanticipated costs in 2018 to utilize third-party contractors to service our compression units at a greater cost than we would have incurred to compensate employees to perform the same work.
Given the wide variety of locations in which we operate, and the numerous environmental permits and other authorizations that are applicable to our operations, we may occasionally identify or be notified of technical violations of certain requirements existing under various permits or other authorizations. We could be subject to penalties for any noncompliance in the future.
Given the wide variety of locations in which we operate, and the numerous environmental permits and other authorizations that 20 Table of Contents are applicable to our operations, we may occasionally identify or be notified of technical violations of certain requirements existing under various permits or other authorizations. We could be subject to penalties for any noncompliance in the future.
In August 2022, the IRA 2022 was passed, which imposes a methane emissions charge on certain oil and gas facilities, including onshore petroleum and natural gas production facilities, that emit 25,000 metric tons or more of carbon dioxide equivalent gas per year and exceed certain emissions thresholds.
In August 2022, the IRA 2022 was passed, which imposes a methane emissions charge on certain oil and gas facilities, including onshore petroleum and natural gas production facilities, that emit 25,000 metric tons or more of carbon dioxide equivalent gas per year and exceed certain 21 Table of Contents emissions thresholds.
To the extent we issue additional equity securities, including common units and preferred units, the payment of distributions on those additional securities may increase the risk that we will 16 Table of Contents be unable to maintain or increase our per-common-unit distribution level.
To the extent we issue additional equity securities, including common units and preferred units, the payment of distributions on those additional securities may increase the risk that we will be unable to maintain or increase our per-common-unit distribution level.
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, 2022, we had $2.1 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, 2023, we had $2.3 billion of total debt, net of amortized deferred financing costs, outstanding under our Credit Agreement and Senior Notes.
The General Partner and its affiliates, including Energy Transfer, have 10 Table of Contents 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. • 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. 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 demand for our compression services depends on the continued demand for, and production of, natural gas and crude oil. Demand may be affected by, among other factors, natural gas prices, crude oil prices, weather, availability of alternative energy sources, global health pandemics (such as COVID-19), governmental regulation, geopolitical events, and the overall demand for energy.
The demand for our compression services depends on the continued demand for, and production of, natural gas and crude oil. Demand may be affected by, among other factors, natural gas prices, crude oil prices, weather, availability of alternative energy sources, governmental regulation, geopolitical events, global health pandemics, and the overall demand for energy.
For the year ended December 31, 2022, approximately 29% 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, 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 example, as of December 31, 2022, one customer accounted for 13% 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, 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.
As of December 31, 2022, the General Partner and its affiliates (including Energy Transfer), beneficially own an aggregate of approximately 47% 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, 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.
Our operations may require new or amended facility permits or 20 Table of Contents licenses from time to time with respect to storm water discharges, waste handling, or air emissions relating to equipment operations, which subject us to new or revised permitting conditions that may be onerous or costly to comply with.
Our operations may require new or amended facility permits or licenses from time to time with respect to storm water discharges, waste handling, or air emissions relating to equipment operations, which subject us to new or revised permitting conditions that may be onerous or costly to comply with.
Weak economic conditions and widespread financial distress, including as a result of 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, 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.
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.
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.
Our ability to incur additional debt also is subject to limitations in the Credit Agreement, including certain financial covenants. As of December 31, 2022, our leverage ratio under the Credit Agreement was 4.76x.
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.
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, 2022, 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 $6.5 million.
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.
Following disputes between the members of OPEC+ about production levels and the price of crude oil, and amid the outbreak of COVID-19, the price of crude oil declined rapidly beginning in March 2020.
For example, in 2020, following disputes between the members of OPEC+ about production levels and the price of crude oil, and amid the outbreak of COVID-19, the price of crude oil declined rapidly beginning in March of that year.
Risk Factor Summary Risks Related to Our Business • We may not generate sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to the General Partner, to enable us to make cash distributions on our common units at the current level. • An extended reduction in the demand for, or production of, natural gas or crude oil could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders. • Pandemics and other public health crises, including the ongoing global COVID-19 pandemic, may have an adverse effect on our business and results of operations. • We have several key customers.
Risk Factor Summary Risks Related to Our Business • We may not generate sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to the General Partner, to enable us to make cash distributions on our common units at the current level. • An extended reduction in the demand for, or production of, natural gas or crude oil could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders. • We have several key customers.
Pandemics, such as the COVID-19 pandemic, or other public health crises could significantly reduce the demand for, price of, and level of production of natural gas and crude oil, which could have an adverse impact on our business and results of operations.
Pandemics and other public health crises could significantly reduce the demand for, price of, and level of production of natural gas and crude oil, which could have an adverse impact on our business and results of operations.
As a result, we recorded impairments of compression equipment of $1.5 million, $5.1 million, and $8.1 million for the years ended December 31, 2022, 2021, and 2020, respectively. 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 $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 of this limitation, the amount of taxable income allocated to our 30 Table of Contents unitholders in the taxable year in which the limitation is in effect will increase, and any future limitations on our ability to deduct business interest may similarly increase taxable income allocated to our unitholders.
As a result of this limitation, the amount of taxable income allocated to our unitholders in the taxable year in which the limitation is in effect will increase, which was $95.1 million for tax year 2022, and any future limitations on our ability to deduct business interest may similarly increase taxable income allocated 30 Table of Contents to our unitholders.
A reduction in the demand for, price of, and level of production of natural gas and crude oil in the regions where we provide compression services potentially could cause: • a negative impact on our results of operations and financial condition; • the deterioration of the financial condition of our customers, suppliers, and vendors; • a hindrance on our ability to pay distributions, service our debt and other liabilities, and comply with certain restrictive financial covenants in the Credit Agreement and the Indentures; • renegotiations of our service contracts at lower rates; and • additional costs to us, which could be significant, in connection with litigation and bankruptcies resulting from customer financial deterioration.
A resurgence of COVD-19, or the emergence of a different pandemic, could once again reduce the demand for, price of, and level of production of natural gas and crude oil in the regions where we provide compression services, which potentially could cause: • a negative impact on our results of operations and financial condition; 15 Table of Contents • the deterioration of the financial condition of our customers, suppliers, and vendors; • a hindrance on our ability to pay distributions, service our debt and other liabilities, and comply with certain restrictive financial covenants in the Credit Agreement and the Indentures; • renegotiations of our service contracts at lower rates; and • additional costs to us, which could be significant, in connection with litigation and bankruptcies resulting from customer financial deterioration.
For example, for the years ended December 31, 2022, 2021, and 2020, we evaluated the future deployment of our idle fleet assets under then-existing market conditions and retired 15, 26, and 37 compressor units, respectively, for a total of approximately 3,200, 11,000, and 15,000 aggregate horsepower, respectively, that previously were used to provide compression services in our business.
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.
The Credit Agreement has an aggregate commitment of $1.6 billion (subject to availability under our borrowing base), with a further potential increase of up to $200 million. 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, 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 Partnership Agreement requires us to distribute all of our available cash to our unitholders (excluding prudent operating reserves). We expect that we will rely primarily on cash generated by operating activities and, where necessary, borrowings under the Credit Agreement, and the issuance of debt and equity securities, to fund expansion capital expenditures.
The Partnership Agreement requires us to distribute all of our available cash to our unitholders (excluding prudent operating reserves). We expect that we will rely primarily on cash generated by operating activities and, where necessary, borrowings under the Credit Agreement, to fund operating costs and working capital requirements.
Energy Transfer and the holders of the Preferred Units may sell our common units in the public or private markets, and such sales could have an adverse impact on the trading price of our common units. As of December 31, 2022, 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 8, 2024, Energy Transfer beneficially owns an aggregate of 46,056,228 common units in us.
We have granted certain registration rights to Energy Transfer and its affiliates with respect to any common units they own, and have filed a registration statement with the SEC for the benefit of the holders of the Preferred Units with respect to any common units they may receive upon conversion of the Preferred Units or exercise of the Warrants, some of which have already been exercised in exchange for common units.
We have granted certain registration rights to Energy Transfer and its affiliates with respect to any common units they own, and have filed a registration statement with the SEC for the benefit of the Preferred Unitholders with respect to any common units they may receive upon conversion of the Preferred Units or exercise of the warrants.
The Partnership Agreement restricts or limits our ability (subject to certain exceptions) to: • pay distributions on any junior securities, including our common units, prior to paying the quarterly distribution payable to the holders of the Preferred Units, including any previously accrued and unpaid distributions; • issue any securities that rank senior to or pari passu with the Preferred Units; however, we will be able to issue an unlimited number of securities ranking junior to the Preferred Units, including junior preferred units and additional common units; and • incur Indebtedness (as defined in the Credit Agreement) if, after giving pro forma effect to such incurrence, the Leverage Ratio (as defined in the Credit Agreement) determined as of the last day of the most recently ended fiscal quarter would exceed 6.5x, subject to certain exceptions. 18 Table of Contents A prolonged or severe sudden downturn in the economic environment, such as the severe impact of the COVID-19 pandemic, could cause an impairment of identifiable intangible assets and reduce our earnings.
The Partnership Agreement restricts or limits our ability (subject to certain exceptions) to: • pay distributions on any junior securities, including our common units, prior to paying the quarterly distribution payable to the holders of the Preferred Units, including any previously accrued and unpaid distributions; • issue any securities that rank senior to or pari passu with the Preferred Units; however, we will be able to issue an unlimited number of securities ranking junior to the Preferred Units, including junior preferred units and additional common units; and • incur Indebtedness (as defined in the Credit Agreement) if, after giving pro forma effect to such incurrence, the Leverage Ratio (as defined in the Credit Agreement) determined as of the last day of the most recently ended fiscal quarter would exceed 6.5x, subject to certain exceptions.
Our unitholders will be treated as partners to whom we will allocate taxable income. Unitholders are required to pay federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income, irrespective of whether they receive cash distributions from us.
Unitholders are required to pay federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income, irrespective of whether they receive cash distributions from us.
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 $51.6 million per quarter, or $206.3 million per year, based on the number of common units outstanding as of February 9, 2023.
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.
The Preferred Unit distributions require $12.2 million quarterly, or $48.8 million annually, based on the number of Preferred Units outstanding 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 $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.
If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units.
Tax gain or loss on the disposition of our common units could be more or less than expected. If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units.
A significant failure, compromise, breach, or interruption of our information systems could result in a disruption of our operations, customer dissatisfaction, damage to our reputation, a loss of customers or revenues, and potential regulatory fines.
A significant failure, compromise, breach, or interruption of our information systems or inadequacies in our incident response processes could result in loss of confidential information, a disruption of our operations, customer dissatisfaction, damage to our reputation, a loss of customers or revenues, privacy or cybersecurity related litigation, and potential regulatory fines.
Additionally, if COVID-19 or other pandemics were to significantly spread into our workforce, this could hinder our ability to provide services and otherwise perform our contractual obligations to our customers.
Additionally, if any pandemic were to significantly spread into our workforce, this could hinder our ability to provide services and otherwise perform our contractual obligations to our customers.
We have recorded $275.0 million of identifiable intangible assets, net, as of December 31, 2022. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business. These events could cause us to record impairments of identifiable intangible assets.
Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business. These events could cause us to record impairments of identifiable intangible assets.
Our financial results also could be adversely affected if our information systems are breached or an employee causes our information systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating such systems. Terrorist attacks, the threat of terrorist attacks, or other sustained military campaigns may adversely impact our results of operations.
Our financial results also could be adversely affected if our or our vendors’ information systems are breached or an employee causes our information systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating such systems.
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 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.
The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the energy industry in general, and on us in particular, are not known at this time.
Terrorist attacks, the threat of terrorist attacks, or other sustained military campaigns may adversely impact our results of operations. The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the energy industry in general, and on us in particular, are not known at this time.
These declines had, and may again in the future have, a negative impact on many of our customers involved in the domestic exploration and production of crude oil and natural gas, which in turn had and may again have, an adverse effect on our business and results of operations.
This reduced demand also contributed to a decline in commodity prices and production. These declines had a negative impact on many of our customers involved in the domestic exploration and production of crude oil and natural gas, which in turn had an adverse effect on our business and results of operations.
These preferences could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.
The Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.
Climate change continues to attract considerable public and scientific attention. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases (“GHGs”). In recent years, the U.S. Congress has considered legislation to reduce GHG emissions.
Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases (“GHGs”). The U.S. Congress, from time to time, has considered legislation to reduce GHG emissions.
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.
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.
However, we may not be able to obtain equity or debt financing on terms favorable to us or at all. To the extent we are unable to finance growth through external sources efficiently, our ability to maintain or increase the level of distributions on our common units could be significantly impaired.
To the extent we are unable to finance growth through external sources efficiently, our ability to maintain or increase the level of distributions on our common units could be significantly impaired.
Any sales of these common units in the public or private markets could have an adverse impact on the price of our common units. The General Partner has a call right that may require holders of our common units to sell their common units at an undesirable time or price.
The 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.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.
Unitholders are encouraged to consult their tax advisors with respect to the consequences of transactions that may result in income and gain to unitholders. If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.
Such vertical integration, increases in vertical integration, or use of alternative technologies could result in decreased demand for our compression services, which may have a material adverse effect on our business, results of operations, financial condition, and reduce our cash available for distribution.
Such vertical integration, increases in vertical integration, or use of alternative technologies could result in decreased demand for our 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.
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. 27 Table of Contents The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business.
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.
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.
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.
The duration of any pandemic, including COVID-19, and the magnitude of its repercussions cannot be reasonably estimated at this time, and depending on the duration and severity of the pandemic, it could materially adversely affect our financial condition and results of operations. 13 Table of Contents We have several key customers.
The duration of any pandemic and the magnitude of its repercussions cannot be reasonably estimated, and depending on the duration and severity of the pandemic, it could materially adversely affect our financial condition and results of operations.
Additionally, if we are not able to pass along increases to our costs due to inflation on parts, fluids, labor, and other aspects of our business, it may adversely affect our results of operations and cash flows. 15 Table of Contents We may be unable to grow our cash flows if we are unable to expand our business, which could limit our ability to maintain or increase the level of distributions to our common unitholders.
Additionally, if we are not able to pass along increases to our costs due to inflation on parts, fluids, labor, and other aspects of our business, it may adversely affect our results of operations and cash flows.
Accordingly, distributions to a non-U.S. unitholder will be subject to a combined withholding tax rate equal to the sum of the highest applicable effective tax rate and 10%.
We intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to such 10% withholding tax. Accordingly, distributions to a non-U.S. unitholder will be subject to a combined withholding tax rate equal to the sum of the highest applicable effective tax rate and 10%.
As of February 9, 2023, we had outstanding borrowings under the Credit Agreement of $677.0 million.
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.
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.
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.
The loss of any of these customers would result in a decrease in our revenues and cash available for distribution. We provide compression services under contracts with several key customers. 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.
Further, if demand for our services decreases, we may be asked to renegotiate our service contracts at lower rates. We have several key customers. The loss of any of these customers would result in a decrease in our revenues and cash available for distribution. We provide compression services under contracts with several key customers.
In addition, nonperformance by suppliers or vendors who have committed to provide us with critical products or services could raise our costs or interfere with our ability to successfully conduct our business. All of the above may be exacerbated in the future by the COVID-19 pandemic and the governmental responses thereto.
In addition, nonperformance by suppliers or vendors who have committed to provide us with critical products or services could raise our costs or interfere with our ability to successfully conduct our business. The Preferred Units have rights, preferences, and privileges that are not held by, and are preferential to the rights of, holders of our common units.
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, and as a result, the risks associated with such an event continue to increase.
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.
Our ten largest customers accounted for approximately 38%, 39%, and 35% of our total revenues for the years ended December 31, 2022, 2021, and 2020, 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 39%, 38%, and 39% of our total revenues for the years ended December 31, 2023, 2022, and 2021, respectively.
For example, our customers could seek to preserve capital by using lower-cost providers, not renewing month-to-month contracts, or determining not to enter into any new compression service contracts. A significant decline in commodity prices may cause certain of our customers to reconsider their near-term capital budgets, which may impact large-scale natural gas infrastructure and crude oil production activities.
For example, our customers could seek to preserve capital or reduce expenses by using lower-cost providers of compression services, not renewing month-to-month contracts, determining not to enter into any new compression service contracts, or seeking lower contract prices for our services.
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. A discontinuation of our services by a significant number of these customers could have a material adverse effect on our business, results of operations, financial condition, and cash available for distribution.
A discontinuation of our services by a significant number of these customers could have a material adverse effect on our business, results of operations, financial condition, and cash available for distribution. Our contracts typically have initial terms between six months to five years, depending on the application and location of the compression unit.
Any additional regulation of air emissions from the oil and gas sector could result in increased expenditures for pollution control equipment, which could impact our customers’ operations and negatively impact our business. 21 Table of Contents Climate change legislation, regulatory initiatives, and litigation could result in increased compliance costs and restrictions on our customers’ operations, which could materially adversely affect our cash flows and results of operations.
Climate change legislation, regulatory initiatives, and litigation could result in increased compliance costs and restrictions on our customers’ operations, which could materially adversely affect our cash flows and results of operations. Climate change continues to attract considerable public and scientific attention.
As of December 31, 2022, we had outstanding borrowings under the Credit Agreement of $646.0 million, $954.0 million 14 Table of Contents of availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $333.1 million.
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.
If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties, and interest, our cash available for distribution to our unitholders may be reduced. Tax gain or loss on the disposition of our common units could be more or less than expected.
If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties, and interest, our cash available for distribution to our unitholders may be reduced. See Note 17 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information regarding the current IRS examination.
A principal focus of our strategy is to maintain or increase our per-common-unit distribution by expanding our business over time. Our future growth will depend on several factors, some of which we cannot control.
We may be unable to grow our cash flows if we are unable to expand our business, which could limit our ability to maintain or increase the level of distributions to our common unitholders. A principal focus of our strategy is to maintain or increase our per-common-unit distribution by expanding our business over time.
Reduced demand for our services could adversely affect our business, results of operations, financial condition, and cash flows. 17 Table of Contents We are exposed to counterparty credit risk.
A significant decline in commodity prices may cause certain of our customers to reconsider their near-term capital budgets, which may impact large-scale natural gas infrastructure and crude oil production activities. Reduced demand for our services could adversely affect our business, results of operations, financial condition, and cash flows. We are exposed to counterparty credit risk.
At the end of December 2020, the North American rig count was 351 rigs, the price of WTI crude oil was $48.35 per barrel, and Henry Hub natural gas spot prices were $2.36 per MMBtu.
During 2020, the North American rig count reached a low of 247 rigs in August of 2020, down from 790 rigs at the end of January of that year, the price of WTI crude oil briefly went negative in April 2020, down from $51.58 per barrel at the end of January of that year, and Henry Hub natural gas spot reached a low of $1.33 per MMBtu in September 2020, down from $1.91 per MMBtu at the end of January of that year.
In addition, in November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and gas sector. In November 2022, the EPA issued a supplemental proposal to expand its November 2021 proposed rule.
In addition, in December 2023, the EPA issued rules to further reduce methane and VOC emissions from new and existing sources in the oil and gas sector. Any additional regulation of air emissions from the oil and gas sector could result in increased expenditures for pollution control equipment, which could impact our customers’ operations and negatively impact our business.
Removed
For example, the North American rig count, as measured by Baker Hughes, hit a 2014 peak of 1,931 rigs on September 12, 2014, and at that time, Henry Hub natural gas spot prices were $3.82 per one million British thermal units (“MMBtu”), and West Texas Intermediate (“WTI”) crude oil spot prices were $92.18 per barrel.

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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, 2022, 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, 2023, our headquarters consisted of 19,225 square feet of leased office space located at 111 Congress Avenue, Austin, Texas 78701.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeITEM 3. Legal Proceedings From time to time, we and our subsidiaries may be involved in various claims and litigation arising in the ordinary course of business.
Biggest changeITEM 3. Legal Proceedings From time to time, we and our subsidiaries may be involved in various claims and litigation arising in the ordinary course of business. In management’s opinion, the resolution of such matters is not expected to have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
Removed
In management’s opinion, the resolution of such matters is not expected to have a material adverse effect on our consolidated financial position, results of operations, or cash flows. 33 Table of Contents ITEM 4. Mine Safety Disclosures None. 34 Table of Contents PART II
Added
See Note 17 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report for more information on certain of these proceedings. ITEM 4. Mine Safety Disclosures None. 34 Table of Contents PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeThe holders of the Preferred Units are entitled to receive cumulative quarterly cash distributions equal to $24.375 per Preferred Unit.
Biggest changeThe holders of the Preferred Units are entitled to receive cumulative quarterly cash distributions equal to $24.375 per Preferred Unit. The Preferred Units are convertible, at the option of the holder, into common units in accordance with the terms of our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).
On or after 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.
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.
As of February 9, 2023, we had outstanding 500,000 Preferred Units representing limited partner interests in the Partnership, all of which were held by EIG Veteran Equity Aggregator LP and FS Energy and Power Fund (collectively, the “Preferred Unitholders”). The Preferred Units rank senior to our common units with respect to distributions and liquidation rights.
As 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.
ITEM 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Our Partnership Interests As of February 9, 2023, we had 98,257,639 common units outstanding. Energy Transfer owns 100% of the membership interests in the General Partner and, as of February 9, 2023, beneficially owns approximately 47% 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 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.
The number of record holders does not include holders of common units held in “street name” or persons, partnerships, associations, corporations, or other entities identified in security position listings maintained by depositories. There is no established public trading market for the Preferred Units, all of which are owned by the Preferred Unitholders.
The number of record holders does not include holders of common units held in “street name” or persons, partnerships, associations, corporations, or other entities identified in security position listings maintained by depositories. Selected Information from the Partnership Agreement Set forth below is a summary of the significant provisions of the Partnership Agreement that relate to available cash.
Our common units, which represent limited partner interests in us, are listed on the NYSE under the symbol “USAC.” Holders At the close of business on February 9, 2023, based on information received from the transfer agent of the common units, we had 62 holders of record of our common units.
Our common units, which represent limited partner interests in us, are listed on the NYSE under the symbol “USAC.” There is no established public trading market for the Preferred Units, all of which are owned by the Preferred Unitholders.
Removed
The Preferred Units are convertible, at the option of the holder, into common units in accordance with the terms of our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”) as follows: one third on or after April 2, 2021, two thirds on or after April 2, 2022, and 100% on or after April 2, 2023.
Added
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.
Removed
Please read Part II, Item 8 “Financial Statements and Supplementary Data – Note 10 – Preferred Units and – Note 11 – Partners’ Capital (Deficit)”. Selected Information from the Partnership Agreement Set forth below is a summary of the significant provisions of the Partnership Agreement that relate to available cash.

Item 7. Management's Discussion & Analysis

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

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Biggest changeFinancial Results of Operations Year ended December 31, 2022, compared to the year ended December 31, 2021 The following table summarizes our results of operations for the periods presented (dollars in thousands): Year Ended December 31, Increase 2022 2021 (Decrease) Revenues: Contract operations $ 673,214 $ 609,450 10.5 % Parts and service 15,729 11,228 40.1 % Related party 15,655 11,967 30.8 % Total revenues 704,598 632,645 11.4 % Costs and expenses: Cost of operations, exclusive of depreciation and amortization 234,336 194,389 20.6 % Depreciation and amortization 236,677 238,769 (0.9) % Selling, general, and administrative 61,278 56,082 9.3 % Loss (gain) on disposition of assets 1,527 (2,588) * Impairment of compression equipment 1,487 5,121 (71.0) % Total costs and expenses 535,305 491,773 8.9 % Operating income 169,293 140,872 20.2 % Other income (expense): Interest expense, net (138,050) (129,826) 6.3 % Other 91 107 (15.0) % Total other expense (137,959) (129,719) 6.4 % Net income before income tax expense 31,334 11,153 180.9 % Income tax expense 1,016 874 16.2 % Net income $ 30,318 $ 10,279 195.0 % ________________________ * Not meaningful. 39 Table of Contents Contract operations revenue .
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.
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.
We believe DCF Coverage Ratio is an important measure of operating performance because it permits management, investors, and others to assess our ability to pay cash distributions to common unitholders out of the cash flows that we generate.
We believe DCF Coverage Ratio is an important measure of operating performance because it permits management, investors, and others to assess our ability to pay distributions to common unitholders out of the cash flows that we generate.
Additionally, average revenue per revenue-generating horsepower per month associated with our compression services provided on a month-to-month basis did not differ significantly from the average revenue per revenue-generating horsepower per month associated with our compression services provided under contracts in their primary term during the period. Parts and service revenue .
Average revenue per revenue-generating horsepower per month associated with our compression services provided on a month-to-month basis did not differ significantly from the average revenue per revenue-generating horsepower per month associated with our compression services provided under contracts in their primary term during the period. Parts and service revenue .
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. Interest on the Senior Notes 2027 is payable semi-annually in arrears on each of March 1 and September 1.
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 primary circumstances supporting these impairments were: (i) unmarketability of units into the foreseeable future, (ii) excessive maintenance costs associated with certain fleet assets, and (iii) excessive retrofitting costs that likely would prevent certain units from securing customer acceptance. These compression units were written down to their respective 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.
The primary circumstances supporting these impairments were: (i) unmarketability of units into the foreseeable future, (ii) excessive maintenance costs associated with certain fleet assets, and (iii) excessive retrofitting costs that likely would prevent certain units from securing customer acceptance. These compression units were written down to their respective 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.
We evaluate the financial strength of our customers by reviewing the aging of their receivables owed to us, our collection experience with the customer, correspondence, financial information, and third-party credit ratings. We evaluate the business climate in which our customers operate by reviewing various publicly available materials regarding our customers’ industry, including the solvency of various companies in the industry.
We evaluate the financial strength of our customers by reviewing the aging of their receivables owed to us, our collection experiences with the customer, correspondence, financial information, and third-party credit ratings. We evaluate the business climate in which our customers operate by reviewing various publicly available materials regarding our customers’ industry, including the solvency of various companies in the industry.
Coverage Ratios DCF Coverage Ratio is defined as the period’s DCF divided by distributions declared to common unitholders in respect of such period.
DCF Coverage Ratio DCF Coverage Ratio is defined as the period’s DCF divided by distributions declared to common unitholders in respect of such period.
Such distributions are treated as non-cash transactions in the accompanying Consolidated Statements of Cash Flows included in Part II, Item 8 “Financial Statements and Supplementary Data” of this report. See Note 11 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for more information regarding the DRIP.
Such distributions are treated as non-cash transactions in the accompanying Consolidated Statements of Cash Flows included in Part II, Item 8 “Financial Statements and Supplementary Data” of this report. See Note 12 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for more information regarding the DRIP.
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 48 Table of Contents our assets.
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.
For the year ended December 31, 2022, we recognized a reversal of $0.7 million of our provision for expected credit losses. Favorable market conditions for customers, attributable to sustained increases in commodity prices, was the primary factor supporting the recorded decrease to the allowance for credit losses for the year ended December 31, 2022.
For the year ended December 31, 2022, we recognized a reversal of $0.7 million to the provision for expected credit losses. Favorable market conditions for customers, attributable to sustained increases in commodity prices, was the primary factor supporting the recognized decrease to the allowance for credit losses for the year ended December 31, 2022.
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, and other.
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 expect that anticipated crude oil production increases likewise will increase associated natural gas production volumes throughout 2023, thereby increasing demand for our compression services, particularly in the Permian and Delaware Basins.
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 increase in DCF Coverage Ratio for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to the increase in DCF, partially offset by increased distributions due to an increase in the number of outstanding common units.
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 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 2023.
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.
Discussion and analysis of our operating highlights and financial results of operations for the year ended December 31, 2021, compared to the year ended December 31, 2020, 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 filed for the year ended December 31, 2021, with the SEC on February 15, 2022.
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.
In addition, the Partnership’s obligations under the Credit Agreement are secured by: (i) substantially all of the Partnership’s assets and substantially all of the assets of the guarantors party to the Credit Agreement, excluding real property and other customary exclusions; and (ii) all of the equity interests of the Partnership’s U.S. restricted subsidiaries (subject to customary exceptions).
In addition, under the Credit Agreement the Partnership’s Secured Obligations (as defined therein) are secured by: (i) substantially all of the Partnership’s assets and substantially all of the assets of the guarantors party to the Credit Agreement, excluding real property and other customary exclusions; and (ii) all of the equity interests of the Partnership’s U.S. restricted subsidiaries (subject to customary exceptions).
The Partnership also must maintain, on a consolidated basis, as of the last day of each fiscal quarter a Total Leverage Ratio (as defined in the Credit Agreement) of not greater than 5.50 to 1.00 through the third fiscal quarter of 2023 and 5.25 to 1.00 thereafter (except that the Partnership may increase the applicable Total Leverage Ratio by 0.25 for any fiscal quarter during which a Specified Acquisition (as defined in the Credit Agreement) occurs and the following two fiscal quarters, but in no event shall the maximum Total Leverage Ratio exceed 5.50 to 1.00 for any fiscal quarter as a 43 Table of Contents 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.
The Partnership also must maintain, on a consolidated basis, as of the last day of each fiscal quarter a Total Leverage Ratio (as defined in the Credit Agreement) of not greater than 5.25 to 1.00 (except that the Partnership may increase the applicable Total Leverage Ratio by 0.25 for any fiscal quarter during which a Specified Acquisition (as defined in the Credit Agreement) occurs and the following two fiscal quarters, but in no event shall the maximum Total Leverage Ratio exceed 5.50 to 1.00 for any fiscal quarter as a result of such increase); an Interest Coverage Ratio (as defined in the Credit Agreement) of not less than 2.50 to 1.00; and a Secured Leverage Ratio (as defined in the Credit Agreement) of not greater than 3.00 to 1.00 or less than 0.00 to 1.00.
The $4.5 million increase in parts and service revenue for the year ended December 31, 2022, compared to the year ended December 31, 2021, 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 $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.
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, proceeds from insurance recovery, and other, less distributions on Preferred Units and maintenance capital expenditures.
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.
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, 2022, and 2021, were $23.8 million and $19.5 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, 2023 and 2022, were $25.2 million and $23.8 million, respectively.
During 2021 and throughout 2022, the general energy industry recovered substantially from the low commodity prices and reduced economic activity of 2020, driven by continued demand growth for crude oil and natural gas that occurred as worldwide economic recovery from COVID-19 lock-downs commenced.
Since 2020, the general energy industry recovered substantially from the low commodity prices and reduced economic activity, driven by continued demand growth for crude oil and natural gas that occurred as worldwide economic recovery from COVID-19 lock-downs commenced.
As a result, we recorded impairments of compression equipment of $1.5 million and $5.1 million for the years ended December 31, 2022, and 2021, respectively.
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.
Horsepower utilization based on revenue-generating horsepower and fleet horsepower was 86.1% and 80.4% as of December 31, 2022, and 2021, 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 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.
Therefore, measures that exclude these cost elements have material limitations. To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating activities as determined under GAAP, as well as DCF, to evaluate our financial performance and liquidity.
To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating activities as determined under GAAP, as well as DCF, to evaluate our financial performance and liquidity.
Our expansion capital expenditures for the years ended December 31, 2022, and 2021, were $145.1 million and $40.2 million, respectively. As of December 31, 2022, we had binding commitments to purchase $159.3 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, 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.
We currently plan to spend approximately $26.0 million in maintenance capital expenditures during 2023, 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 $260.0 million and $270.0 million in expansion capital expenditures for 2023.
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.
Other Commitments As of December 31, 2022, other commitments include operating and finance lease payments totaling $24.9 million, of which we expect to make payments of $5.1 million to be settled in the next twelve months.
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.
As a result of our evaluations during the years ended December 31, 2022 and 2021, we retired 15 and 26 compression units, respectively, for a total of approximately 3,200 and 11,000 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, 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 .
Average horsepower utilization based on revenue-generating horsepower and fleet horsepower was 82.9% and 79.8% for the years ended December 31, 2022, and 2021, respectively.
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.
Our DCF Coverage Ratio, as presented, may not be comparable to similarly titled measures of other companies. 47 Table of Contents The following table summarizes our DCF Coverage Ratio for the periods presented (dollars in thousands): Year Ended December 31, 2022 2021 DCF $ 221,499 $ 209,128 Distributions for DCF Coverage Ratio (1) $ 205,559 $ 203,978 DCF Coverage Ratio 1.08 x 1.03 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. 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.
The expected increase in crude oil production is due in part to the expectation that crude oil prices will remain economic for producers. The EIA estimates that West Texas Intermediate crude oil prices will average $77 per barrel and $72 per barrel for 2023 and 2024, respectively.
The estimated increase in crude oil production is due in part to the expectation that crude oil prices will remain economic for producers. The EIA Outlook estimates that West Texas Intermediate crude oil prices will average $78 per barrel and $75 per barrel for 2024 and 2025, respectively.
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. 44 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, 2022 2021 Total revenues $ 704,598 $ 632,645 Cost of operations, exclusive of depreciation and amortization (234,336) (194,389) Depreciation and amortization (236,677) (238,769) Gross margin $ 233,585 $ 199,487 Depreciation and amortization 236,677 238,769 Adjusted gross margin $ 470,262 $ 438,256 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, 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).
DRIP During the years ended December 31, 2022, and 2021, distributions of $2.1 million and $1.8 million, respectively, were reinvested under the DRIP resulting in the issuance of 124,255 and 118,399 common units, respectively.
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.
The $27.6 million increase in Adjusted EBITDA for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to a $32.0 million increase in Adjusted gross margin, partially offset by a $4.4 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses.
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.
Horsepower utilization based on revenue-generating horsepower and fleet horsepower increased to 86.1% as of December 31, 2022, compared to 80.4% as of December 31, 2021.
Horsepower utilization based on revenue-generating horsepower and fleet horsepower increased to 90.9% as of December 31, 2023, compared to 86.1% as of December 31, 2022.
For the years ended December 31, 2022, and 2021, we evaluated the future deployment of our idle fleet assets under then-existing market conditions and retired 15 and 26 compressor units, respectively, for a total of approximately 3,200 and 11,000 aggregate horsepower, respectively, that previously were used to provide compression services in our business.
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.
The increase primarily was due to an increase in revenue-generating horsepower and an increase in horsepower that is under contract but not yet generating revenue, which was driven by a combination of the redeployment of certain previously idle compression units as well as new units added to our fleet.
The increase primarily was due to an increase in revenue-generating horsepower, which was driven by a combination of the redeployment of certain previously idle compression units as well as the deployment of new compression units added to the fleet.
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.
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.
Our determination of the allowance for credit losses requires us to make estimates and judgments regarding our customers’ ability to pay amounts due. We continuously evaluate the financial strength of our customers and the overall business climate in which our customers operate, and make adjustments to the allowance for credit losses as necessary.
We continuously evaluate the financial strength of our customers and the overall business climate in which our customers operate, and make adjustments to the allowance for credit losses as necessary.
Year Ended December 31, 2022 2021 Increase Fleet horsepower (at period end) (1) 3,716,854 3,689,018 0.8 % Total available horsepower (at period end) (2) 3,826,854 3,689,018 3.7 % Revenue-generating horsepower (at period end) (3) 3,199,548 2,964,206 7.9 % Average revenue-generating horsepower (4) 3,067,279 2,951,013 3.9 % Average revenue per revenue-generating horsepower per month (5) $ 17.35 $ 16.60 4.5 % Revenue-generating compression units (at period end) 4,116 3,942 4.4 % Average horsepower per revenue-generating compression unit (6) 765 750 2.0 % Horsepower utilization (7): At period end 91.8 % 82.7 % 9.1 % Average for the period (8) 88.6 % 82.7 % 5.9 % ________________________ (1) Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order).
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).
Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing comparable GAAP measures, understanding the differences between the measures, and incorporating this knowledge into their decision making. 45 Table of Contents The following table reconciles Adjusted EBITDA to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands): Year Ended December 31, 2022 2021 Net income $ 30,318 $ 10,279 Interest expense, net 138,050 129,826 Depreciation and amortization 236,677 238,769 Income tax expense 1,016 874 EBITDA $ 406,061 $ 379,748 Interest income on capital lease — 48 Unit-based compensation expense (1) 15,894 15,523 Transaction expenses (2) 27 34 Severance charges 982 494 Loss (gain) on disposition of assets 1,527 (2,588) Impairment of compression equipment (3) 1,487 5,121 Adjusted EBITDA $ 425,978 $ 398,380 Interest expense, net (138,050) (129,826) Non-cash interest expense 7,265 9,765 Income tax expense (1,016) (874) Interest income on capital lease — (48) Transaction expenses (27) (34) Severance charges (982) (494) Other (851) (2,742) Changes in operating assets and liabilities (31,727) (8,702) Net cash provided by operating activities $ 260,590 $ 265,425 ________________________ (1) For the years ended December 31, 2022, and 2021, unit-based compensation expense included $4.4 million and $4.2 million, respectively, of cash payments related to quarterly payments of DERs on outstanding phantom unit awards and $1.3 million and $0.3 million, respectively, related to the cash portion of any 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, 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.
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, 2022 2021 Net income $ 30,318 $ 10,279 Non-cash interest expense 7,265 9,765 Depreciation and amortization 236,677 238,769 Non-cash income tax benefit (151) (42) Unit-based compensation expense (1) 15,894 15,523 Transaction expenses (2) 27 34 Severance charges 982 494 Loss (gain) on disposition of assets 1,527 (2,588) Impairment of compression equipment (3) 1,487 5,121 Distributions on Preferred Units (48,750) (48,750) Maintenance capital expenditures (4) (23,777) (19,477) DCF $ 221,499 $ 209,128 Maintenance capital expenditures 23,777 19,477 Transaction expenses (27) (34) Severance charges (982) (494) Distributions on Preferred Units 48,750 48,750 Other (700) (2,700) Changes in operating assets and liabilities (31,727) (8,702) Net cash provided by operating activities $ 260,590 $ 265,425 ________________________ (1) For the years ended December 31, 2022, and 2021, unit-based compensation expense included $4.4 million and $4.2 million, respectively, of cash payments related to quarterly payments of DERs on outstanding phantom unit awards and $1.3 million and $0.3 million, respectively, related to the cash portion of any settlement of phantom unit awards upon vesting.
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.
The demand for domestic natural gas also continues to benefit from the construction of liquefied natural gas (“LNG”) export infrastructure, which enables industry participants to benefit from attractive global natural gas prices. The U.S. witnessed record LNG exports during 2022 according to the EIA.
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.
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.
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.
As of December 31, 2022, we had 165,000 large horsepower on order for delivery during 2023.
As of December 31, 2023, we had 52,500 large horsepower on order for expected delivery during 2024.
However, we expect the baseload natural gas demand previously described to continue to support long-term domestic natural gas production. Although our business is focused on providing compression services that do not bear direct exposure to commodity prices, our business exhibits indirect exposure to commodity prices as overall levels of drilling activity are influenced by prevailing commodity prices.
Although our business is focused on providing compression services that do not bear direct exposure to commodity prices, our business exhibits indirect exposure to commodity prices as overall levels of drilling activity and production are influenced by prevailing commodity prices.
The $34.1 million increase in gross margin for the year ended December 31, 2022, compared to the year ended December 31, 2021, was due to (i) a $72.0 million increase in revenues and (ii) a $2.1 million decrease in depreciation and amortization, partially offset by (iii) a $39.9 million increase in cost of operations, exclusive of depreciation and amortization.
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 $95.6 million decrease in net cash used in financing activities for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) an $87.1 million increase in net borrowings under the Credit Agreement and (ii) a $9.4 million decrease in financing costs, primarily due to costs incurred related to the amendment and restatement of our Credit Agreement in the prior comparable period, partially offset by (iii) a $1.1 million increase in common unit distributions.
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 $63.8 million increase in contract operations revenue for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) a 4.5% increase in average revenue per revenue-generating horsepower per month, as a result of Consumer Price Index (“CPI”)-based and other price increases on customer contracts that occur as market conditions permit, (ii) a 3.9% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with increased operating activity in the oil and gas industry, and (iii) an increase in revenue attributable to natural gas treating services.
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 above-stated factor also drove the increase in average horsepower utilization based on revenue-generating horsepower and fleet horsepower for the year ended December 31, 2022, as compared to the year ended December 31, 2021.
The above-stated factors also drove the 8.5% increase in the average revenue-generating horsepower for the year ended December 31, 2023 as compared to the year ended December 31, 2022.
Adjusted gross margin and Adjusted gross margin percentage. The $32.0 million increase in Adjusted gross margin for the year ended December 31, 2022, compared to the year ended December 31, 2021, was due to a $72.0 million increase in revenues, partially offset by a $39.9 million increase in cost of operations, exclusive of depreciation and amortization.
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.
For more detailed descriptions of the Senior Notes 2026 and Senior Notes 2027, please refer to Note 9 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
For a more detailed description of our lease obligations, please refer to Note 7 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
The weighted-average interest rate applicable to borrowings under the Credit Agreement was 4.48% and 2.98% for the years ended December 31, 2022, and 2021, respectively, and average outstanding borrowings under our Credit Agreement were $580.4 million for the year ended December 31, 2022, compared to $491.5 million for the year ended December 31, 2021. Income tax expense.
The weighted-average interest rate applicable to borrowings under the Credit Agreement was 7.68% and 4.48% for the years ended December 31, 2023, and 2022, respectively, and average outstanding borrowings under our Credit Agreement were $757.6 million for the year ended December 31, 2023, compared to $580.4 million for the year ended December 31, 2022. Gain on derivative instrument.
In 2023 and 2024, the EIA Outlook expects U.S. crude oil production growth to continue, estimating average production of 12.4 million bpd for 2023 and 12.8 million bpd in 2024, which would represent the highest annual average crude oil production on record.
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.
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) 2022 2021 (Decrease) Gross margin $ 233,585 $ 199,487 17.1 % Adjusted gross margin $ 470,262 $ 438,256 7.3 % Adjusted gross margin percentage (2) 66.7 % 69.3 % (2.6) % Adjusted EBITDA $ 425,978 $ 398,380 6.9 % Adjusted EBITDA percentage (2) 60.5 % 63.0 % (2.5) % DCF $ 221,499 $ 209,128 5.9 % DCF Coverage Ratio 1.08 x 1.03 x 4.9 % ________________________ (1) Adjusted gross margin, Adjusted EBITDA, Distributable Cash Flow (“DCF”), and DCF Coverage Ratio are all non-GAAP financial measures.
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 $39.9 million increase in cost of operations for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) a $19.2 million increase in direct expenses, primarily driven by fluids and parts due to higher costs and increased usage associated with higher revenue-generating horsepower, (ii) a $6.3 million increase in outside maintenance costs due to greater use and higher costs of third-party labor during the current period, (iii) a $3.6 million increase in non-income taxes, primarily due to sales tax refunds received in the prior comparable period, (iv) a $3.4 million increase in direct labor costs due to higher employee costs, (v) a $3.3 million increase in retail parts and service expenses, for which a corresponding increase in parts and service revenue also occurred, and (vi) a $2.8 million increase in expenses related to our vehicle fleet, primarily due to increased fuel costs and increased usage, as well as higher costs of maintenance during the current period.
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 $12.4 million increase in DCF for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) a $32.0 million increase in Adjusted gross margin, partially offset by (ii) a $10.7 million increase in cash interest expense, net, (iii) a $4.4 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses, and (iv) a $4.3 million increase in maintenance capital expenditures. 41 Table of Contents DCF Coverage Ratio .
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 increase in horsepower utilization is the result of increased demand for our services, consistent with increased operating activity in the oil and gas industry. The above-stated factors also drove the increase in average horsepower utilization for the year ended December 31, 2022, as compared to the year ended December 31, 2021.
The increase in horsepower utilization resulted from increased demand for our services, consistent with increased production levels in the basins in which we operate. The above-stated factors also drove the increase in average horsepower utilization for the year ended December 31, 2023 as compared to the year ended December 31, 2022.
Liquidity and Capital Resources Overview We operate in a capital-intensive industry, and our primary liquidity needs are to finance the purchase of additional compression units, make other capital expenditures, service our debt, fund working capital, and pay distributions.
Liquidity and Capital Resources Overview We operate in a capital-intensive industry, and our primary liquidity needs include financing the purchase of additional compression units, making other capital expenditures, servicing our debt, funding working capital, and paying cash distributions on our outstanding preferred and common equity.
On December 8, 2021, the Partnership amended and restated the Credit Agreement. 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 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 provides for an asset-based revolving credit facility to be made available to the Partnership in an aggregate amount of $1.6 billion.
The increase in horsepower utilization based on revenue-generating horsepower and fleet horsepower primarily was driven by the redeployment of certain previously idle compression units due to increased demand for our services, consistent with increased operating activity in the oil and gas industry.
The increase in horsepower utilization based on revenue-generating horsepower and fleet horsepower primarily was driven by the redeployment of certain previously idle compression units as well as the deployment of new compression units added to the fleet.
The remaining change primarily relates to various asset disposals. Impairment of compression equipment . The $1.5 million and $5.1 million impairments of compression equipment during the years ended December 31, 2022 and 2021, respectively, primarily were the result of our evaluations of the future deployment of our idle fleet under then-existing market conditions.
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 $5.2 million increase in selling, general, and administrative expense for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) a $2.0 million decrease to the allowance for credit losses, resulting from a $0.7 million reversal of previously recognized credit losses in the current period versus a $2.7 million reversal in the prior comparable period, (ii) a $1.1 million increase in employee-related expenses, (iii) a $0.5 million increase in professional fees, (iv) a $0.5 million increase in severance charges, primarily attributable to the departure of one of our executives during the current period, and (v) a $0.4 million increase in other taxes.
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 $8.2 million increase in interest expense, net for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to higher weighted-average interest rates and increased borrowings under 40 Table of Contents the Credit Agreement, partially offset by a decrease in amortization of debt issuance costs attributable to the amendment and restatement of the Credit Agreement in the prior comparable period.
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 3.7% increase in total available horsepower as of December 31, 2022, compared to December 31, 2021, primarily was due to compression units added to our fleet to meet incremental demand from customers for our compression services. 38 Table of Contents The 7.9% increase in revenue-generating horsepower and 4.4% increase in revenue-generating compression units as of December 31, 2022, compared to December 31, 2021, primarily were driven by the redeployment of certain previously idle compression units due to increased demand for our services, commensurate with increased operating activity in the oil and gas industry.
The 7.3% increase in revenue-generating horsepower and 2.9% increase in revenue-generating compression units as of December 31, 2023, compared to December 31, 2022, primarily were driven by both the redeployment of, and addition of new, large-horsepower compression units due to increased demand for our services commensurate with increased production levels 38 Table of Contents in the basins in which we operate.
The $90.8 million increase in net cash used in investing activities for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to an $89.0 million increase in capital expenditures, for purchases of new compression units, reconfiguration costs, and other equipment. Net cash used in financing activities .
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 .
For a more detailed description of the Credit Agreement, including the covenants and restrictions contained therein, please refer to Note 9 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data.”.
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.
Because we use capital assets, depreciation, impairment of compression equipment, loss (gain) on disposition of assets, the interest cost of acquiring compression equipment, and maintenance capital expenditures are necessary components of our 46 Table of Contents aggregate costs. Unit-based compensation expense related to equity awards granted to employees also is a meaningful business expense.
Moreover, our DCF, as presented, may not be comparable to similarly titled measures of other companies. 47 Table of Contents Because we use capital assets, depreciation, impairment of compression equipment, loss (gain) on disposition of assets, the interest cost of acquiring compression equipment, and maintenance capital expenditures are necessary components of our aggregate costs.
The EIA’s January 2023 Short-Term Energy Outlook (“EIA Outlook”) estimates that annual U.S. crude oil production averaged 11.9 million barrels per day (“bpd”) in 2022, up 0.6 million bpd from 2021, primarily due to production growth in the Permian and Delaware Basins.
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.
For a more detailed description of our lease obligations, please refer to Note 7 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. 42 Table of Contents Cash Flows The following table summarizes our sources and uses of cash for the years ended December 31, 2022, and 2021, (in thousands): Year Ended December 31, 2022 2021 Net cash provided by operating activities $ 260,590 $ 265,425 Net cash used in investing activities (129,945) (39,188) Net cash used in financing activities (130,610) (226,239) Net cash provided by operating activities .
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 .
Revolving Credit Facility As of December 31, 2022, we were in compliance with all of our covenants under the Credit Agreement. As of December 31, 2022, we had outstanding borrowings under the Credit Agreement of $646.0 million, $954.0 million of availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $333.1 million.
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.
For the year ended December 31, 2021, we recognized a reversal of $2.7 million of our provision for expected credit losses. Improved market conditions for customers resulting from improved commodity prices was the primary factor supporting the recorded decrease to the allowance for credit losses for the year ended December 31, 2021.
For the year ended December 31, 2023, we recognized a $1.5 million increase to the provision for expected credit losses. Unfavorable developments related to customers in bankruptcy was the primary factor supporting the recognized increase to the allowance for credit losses for the year ended December 31, 2023.
The 4.5% increase in average revenue per revenue generating horsepower per month for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to select price increases on our existing fleet. The 2.0% increase in average horsepower per revenue-generating compression unit primarily was due to the redeployment of larger-horsepower compression units.
The 8.7% increase in average revenue per revenue-generating horsepower per month for the year ended December 31, 2023, compared to the year ended December 31, 2022, 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.
As a result, the $44.9 million accrued liability and $44.9 million related-party receivable from Energy Transfer was reduced to zero as of December 31, 2022. Allowance for Credit Losses We maintain an allowance for credit losses for our trade accounts receivable based on specific customer collection issues and historical experience.
Allowance for Credit Losses We maintain an allowance for credit losses for our trade accounts receivable based on specific customer collection issues and historical experience. Our determination of the allowance for credit losses requires us to make estimates and judgments regarding our customers’ ability to pay amounts due.
We estimate that the range of losses we could incur is from $0 to approximately $21.8 million, including penalties and interest.
We estimate that the range of losses we could incur is from $0 to approximately $25.8 million, including penalties and interest. Our U.S. federal income tax returns for years 2019 and 2020 currently are under examination by the IRS. The IRS has issued preliminary partnership examination changes, along with imputed underpayment computations, for the 2019 and 2020 tax years.
Depreciation and amortization expense . The $2.1 million decrease in depreciation and amortization expense for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to increased asset disposals and assets reaching the end of their depreciable lives. Selling, general, and administrative expense .
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 .
The $4.8 million decrease in net cash provided by operating activities for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to changes in other working capital, offset by an $18.2 million increase in net income, as adjusted for non-cash items. Net cash used in investing activities .
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.
Conversely, decreased drilling activity may cause demand for new compression services to decline. 37 Table of Contents The broader outlook for commodity prices improved considerably during 2022, and although uncertainty with respect to future natural gas demand may have a varying impact on our business, we believe the longer-term outlook for natural gas fundamentals remains positive for 2023 and beyond.
Although we believe the longer-term outlook for natural gas fundamentals remains positive for 2024 and beyond, the uncertainty created by the heightened tensions in the Middle East, the Russia-Ukraine conflict, the slowing global economy and general geopolitical events on the demand for crude oil and natural gas may have a varying impact on our business.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeSustained low natural gas or crude oil prices over the long term could result in a decline in the production of natural gas or crude oil, which could result in reduced demand for our compression services. We do not intend to hedge our indirect exposure to fluctuating commodity prices.
Biggest changeHowever, the demand for our compression services depends on the continued demand for, and production of, natural gas and crude oil. Sustained low natural gas or crude oil prices over the long term could result in a decline in the production of natural gas or crude oil, which could result in reduced demand for our compression services.
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.
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
Nonpayment and nonperformance by our customers, suppliers, or vendors could reduce our revenues, increase our expenses, and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows, and ability to make distributions to our unitholders.” ITEM 8.
“Risk Factors – Risk Related to Our Business – We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, suppliers, or vendors could reduce our revenues, increase our expenses, and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows, and ability to make distributions to our unitholders.” ITEM 8.
As of December 31, 2022, we had $646.0 million of variable-rate indebtedness outstanding at a weighted-average interest rate of 6.84%. Based on our December 31, 2022 variable-rate indebtedness outstanding, a one percent increase or decrease in the effective interest rate would result in an annual increase or decrease in our interest expense of approximately $6.5 million.
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.
Credit Risk Our credit exposure generally relates to receivables for services provided. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to pay the amount it owes us, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.
If any significant customer of ours should have credit or financial problems resulting in a delay or failure to pay the amount it owes us, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. Please see Part II, Item 1A.
A one percent decrease in average revenue-generating horsepower during the year ended December 31, 2022 would result in an annual decrease of approximately $6.4 million and $4.3 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, 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.
For further information regarding our exposure to interest rate fluctuations on our debt obligations, see Note 9 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. Although we do not currently hedge our variable rate debt, we may, in the future, hedge all or a portion of such debt.
For further information regarding our exposure to interest rate fluctuations on our debt obligations, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. In 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.
Removed
However, the demand for our compression services depends on the continued demand for, and production 49 Table of Contents of, natural gas and crude oil.
Added
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
Please see Part II, Item 1A. “Risk Factors – Risk Related to Our Business – We are exposed to counterparty credit risk.
Added
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.
Added
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.

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