UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the fiscal year ended December 31, 2024 |
| or |
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| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 001-35779
USA Compression Partners, LP
(Exact name of registrant as Specified in its charter) | | | | | |
| Delaware | 75-2771546 |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
8117 Preston Road, Suite 510A
Dallas, Texas 75225
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (512) 473-2662
Securities registered pursuant to Section 12(b) of the Act:
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| Title of each class | | Trading Symbol(s) | | Name of each exchange on which registered |
| Common Units Representing Limited Partner Interests | | USAC | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” or an “emerging growth company” in Rule 12b-2 of the Exchange Act.
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| Large accelerated filer | ☒ | Accelerated filer | ☐ |
| Non-accelerated filer | ☐ | Smaller reporting company | ☐ |
| | Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The aggregate market value of common units held by non-affiliates of the registrant as of June 30, 2024, the last business day of the registrant’s most recently completed second fiscal quarter was $1.7 billion. This calculation does not reflect a determination that such persons are affiliates for any other purpose.
As of February 6, 2025, there were 117,528,971 common units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: NONE
Glossary
The abbreviations, acronyms, and industry terminology used in this Annual Report are defined as follows:
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| Credit Agreement | | Seventh Amended and Restated Credit Agreement, dated as of December 8, 2021, by and among USA Compression Partners, LP, as borrower, the guarantors party thereto from time to time, the lenders party thereto from time to time, as may be amended from time to time, and any predecessor thereto if the context so dictates |
| CPI | | Consumer Price Index for all Urban Consumers |
| DERs | | distribution equivalent rights |
| | |
| DRIP | | distribution reinvestment plan |
| EBITDA | | earnings before interest, taxes, depreciation, and amortization |
| EIA | | United States Energy Information Agency |
| Energy Transfer | | Energy Transfer LP |
| Exchange Act | | Securities Exchange Act of 1934, as amended |
| GAAP | | generally accepted accounting principles of the United States of America |
| LNG | | Liquefied natural gas |
| NYSE | | New York Stock Exchange |
| Preferred Units | | Series A Preferred Units representing limited partner interests in USA Compression Partners, LP |
| SEC | | United States Securities and Exchange Commission |
| Senior Notes 2026 | | $725.0 million aggregate principal amount of senior notes due on April 1, 2026 |
| Senior Notes 2027 | | $750.0 million aggregate principal amount of senior notes due on September 1, 2027 |
| Senior Notes 2029 | | $1.0 billion aggregate principal amount of senior notes due on March 15, 2029 |
| SOFR | | Secured Overnight Financing Rate |
| U.S. | | United States of America |
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PART I
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This report contains “forward-looking statements.” All statements other than statements of historical fact contained in this report are forward-looking statements, including, without limitation, statements regarding our plans, strategies, prospects, and expectations concerning our business, results of operations, and financial condition. Many of these statements can be identified by words such as “believe,” “expect,” “intend,” “project,” “anticipate,” “estimate,” “continue,” “if,” “outlook,” “will,” “could,” “should,” or similar words or the negatives thereof.
Known material factors that could cause our actual results to differ from those represented within these forward-looking statements are described below, in Part I, Item 1A “Risk Factors” and in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things:
•changes in economic conditions of the crude oil and natural gas industries, including any impact from the ongoing military conflict involving Russia and Ukraine or the conflict in the Middle East;
•changes in general economic conditions, including inflation or supply chain disruptions;
•changes in the long-term supply of and demand for crude oil and natural gas;
•competitive conditions in our industry, including competition for employees in a tight labor market;
•our ability to realize the anticipated benefits of the shared services integration with Energy Transfer;
•changes in the availability and cost of capital, including changes to interest rates;
•renegotiation of material terms of customer contracts;
•actions taken by our customers, competitors, and third-party operators;
•operating hazards, natural disasters, epidemics, pandemics, weather-related impacts, casualty losses, and other matters beyond our control;
•the deterioration of the financial condition of our customers, which may result in the initiation of bankruptcy proceedings with respect to certain customers;
•the restrictions on our business that are imposed under our long-term debt agreements;
•information technology risks including the risk from cyberattacks, cybersecurity breaches, and other disruptions to our information systems;
•the effects of existing and future laws and governmental regulations; and
•the effects of future litigation.
New factors emerge from time to time, and it is not possible for us to predict or anticipate all factors that could affect results reflected in the forward-looking statements contained herein. Should one or more of the risks or uncertainties described in this Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements included in this report are based on information available to us as of the date of this report and speak only as of the date of this report. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing cautionary statements.
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.
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.
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. On April 2, 2018, we acquired all of the equity interests in CDM Resource Management LLC and CDM Environmental & Technical Services LLC (the “CDM Acquisition”).
As of December 31, 2024, we had 3,862,102 horsepower in our fleet. We provide compression services to our customers primarily in connection with infrastructure applications, including both allowing for the processing and transportation of natural gas through the domestic pipeline system and enhancing crude oil production through artificial lift processes. As such, our compression services play a critical role in the production, processing, and transportation of both natural gas and crude oil.
We have focused our compression services in unconventional resource plays throughout the U.S., including the Utica, Marcellus, Permian, Denver-Julesburg, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, and Haynesville. According to studies promulgated by the EIA, the production and transportation volumes in these unconventional plays, namely tight oil and gas shale plays, are expected to collectively increase over the long term. Furthermore, changes in production volumes and pressures of shale plays over time require a wider range of compression service levels than in conventional basins. We believe we are well-positioned to meet these changing operating conditions due to the operational design flexibility inherit within our compression-unit fleets.
Our business includes compression services serving infrastructure applications, including centralized natural gas gathering systems and processing facilities, which utilize large-horsepower compression units and also gas lift applications on crude oil wells targeted by horizontal drilling techniques. Gas lift is a process by which natural gas is injected into the production tubing of an existing producing well to reduce hydrostatic pressure and allow the oil to flow at a higher rate. This process, and other artificial-lift technologies are critical to the enhancement of oil production from horizontal wells operating in tight shale plays.
We operate a fleet of compression units with an average age of approximately 12 years and a useful life that could potentially extend decades when properly maintained. We 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. Our standard new-build compression units generally are configured for multiple compression stages, which allows us to operate our units across a broad range of operating conditions. The design flexibility of our units, particularly in midstream applications, allows us to enter into longer-term contracts and reduces the redeployment risk of our horsepower in the field. Our modern and standardized fleet, decentralized field level operating structure and technical proficiency in predictive and preventive maintenance and overhaul operations have enabled us to achieve average service run times consistently at or above the levels required by our customers and maintain high overall utilization rates for our fleet.
As part of our services, we engineer, design, operate, service, and repair our compression units and maintain related support inventory and equipment. The compression units in our modern fleet are designed to be easily adaptable to fit our customers’ changing compression requirements. Focusing on the needs of our customers and providing them with reliable and flexible compression services in geographic areas of attractive production helps us to generate stable and predictable cash flows in the near term.
We provide compression services to our customers under fixed-fee contracts with initial contract terms that typically range from six months to five years, depending on the application and location of the compression unit. We typically continue to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. We primarily enter into fixed-fee contracts whereby our customers are required to pay our monthly fee even during periods of limited or disrupted throughput, which enhances the stability and predictability of our cash flows. We bill most of our customers in advance of the service date and also typically utilize annual inflation adjustments in our term contracts. We are not directly exposed to commodity price risk because we do not take title to the natural gas or crude oil involved in our services and because the natural gas used as fuel by our compression units is supplied by our customers without cost to us.
We provide compression services to major oil companies and independent producers, processors, gatherers and transporters of natural gas and crude oil. Regardless of the application for which our services are provided, our customers rely on the availability of the equipment used to provide compression services and our expertise to maximize the throughput of product, reduce fuel costs and minimize emissions. Our customers may have compression demands in conjunction with their field development projects in areas of the U.S. where we are not currently operating, and we continually consider further expansion of our geographic areas of operation in the U.S. based upon the level of customer demand. Our 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.
We also own and operate a fleet of equipment used to provide natural gas treating services, such as carbon dioxide and hydrogen sulfide removal and natural gas cooling and dehydration, to natural gas producers and midstream companies.
Our assets and operations are organized into a single reportable segment and all are located and operated within the U.S. See our consolidated financial statements, and the notes thereto, in Part II, Item 8 “Financial Statements and Supplementary Data” for financial information on our operations and assets; such information is incorporated herein by reference.
Our Relationship with Energy Transfer LP
In late 2024, we began implementing a shared services model with the owner of our General Partner, Energy Transfer. Under this model, we will share personnel and resources in certain departments, including information technology, accounting, and human resources. We believe this will increase efficiencies and support across our organization, while simultaneously reducing administrative costs.
As of February 6, 2025, Energy Transfer owned 100% of the membership interest in our General Partner and 46,056,228 of our common units, which constituted a 39% limited partner interest in us. Given the significant ownership, we believe Energy Transfer will be motivated to promote and support the successful execution of the shared services model, as well as our overall business strategy.
For additional information on our related party transactions with entities affiliated with Energy Transfer, see Note 14 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
Our Operations
Compression Services
We provide compression services for a fixed monthly service fee. As part of our services, we engineer, design, operate, service, and repair our fleet of compression units and maintain related support inventory and equipment. In certain instances, we also engineer, design, install, operate, service, and repair certain ancillary equipment used in conjunction with our compression services. We consistently have provided average service run times at or above the levels required by our customers. In general, our team of field technicians services only our compression fleet and ancillary equipment. In limited circumstances, and for established customers, we will agree to service third-party owned equipment. We do not own any compression fabrication facilities.
Our Compression Fleet
The fleet of compression units that we own and use to provide compression services consists of specially engineered compression units that utilize standardized components, principally engines manufactured by Caterpillar Inc. and compressor frames and cylinders manufactured by Ariel Corporation. Our units can be rapidly and cost effectively modified for specific customer applications. As of December 31, 2024, the average age of our compression units was approximately 12 years. Our modern, standardized compression unit fleet is powered primarily by the Caterpillar 3400, 3500, and 3600 engine classes, which range from 400 to 5,000 horsepower per unit. These larger-horsepower units, which we define as 400 horsepower per unit or greater, represented 87.2% of our total fleet horsepower (including compression units on order) as of December 31, 2024. The remainder of our fleet consists of smaller-horsepower units ranging from 40 horsepower to 399 horsepower that are used primarily in gas lift applications. We believe the average age and overall composition of our compressor fleet result in fewer mechanical failures, lower fuel usage, and reduced environmental emissions.
The following table provides a summary of our compression units by horsepower as of December 31, 2024:
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| 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 | | | | | | | | | | | | | | | | |
| <400 | | 495,258 | | | 2,908 | | | — | | | — | | | 495,258 | | | 2,908 | | | 12.8 | % | | 54.0 | % |
| Large horsepower | | | | | | | | | | | | | | | | |
| ≥400 and <1,000 | | 419,980 | | | 720 | | | — | | | — | | | 419,980 | | | 720 | | | 10.8 | % | | 13.4 | % |
| ≥1,000 | | 2,946,864 | | | 1,752 | | | 10,000 | | | 4 | | | 2,956,864 | | | 1,756 | | | 76.4 | % | | 32.6 | % |
| Total large horsepower | | 3,366,844 | | | 2,472 | | | 10,000 | | | 4 | | | 3,376,844 | | | 2,476 | | | 87.2 | % | | 46.0 | % |
| Total horsepower | | 3,862,102 | | | 5,380 | | | 10,000 | | | 4 | | | 3,872,102 | | | 5,384 | | | 100.0 | % | | 100.0 | % |
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(1)As of December 31, 2024, we had no horsepower units on order. Subsequent to December 31, 2024, we ordered 4 large-horsepower units, consisting of 10,000 horsepower, for expected delivery during 2025.
Many of our compression units contain devices that enable us to monitor the units remotely through cellular and satellite networks to supplement our technicians’ on-site monitoring visits. We intend to continue to selectively add remote monitoring systems to our new and existing fleet during 2025 where beneficial from an operational and financial standpoint. All of our compression units are designed to automatically shut down if operating conditions deviate from a pre-determined range.
We adhere to routine, preventive, and scheduled maintenance cycles. Each of our compression units is subjected to rigorous sizing and diagnostic analyses, including lubricating oil analysis and engine exhaust emission analysis. We have proprietary field-service automation capabilities that allow our service technicians to electronically record and track operating, technical, environmental, and commercial information at the discrete unit level. These capabilities allow our field technicians to identify potential problems and often act on them before such problems result in down-time.
Generally, we expect each of our compression units to undergo a major overhaul between service deployment cycles. The timing of these major overhauls depends on multiple factors, including run time and operating conditions. A major overhaul involves the periodic rebuilding of the unit to materially extend its economic useful life or to enhance the unit’s ability to fulfill broader or more diversified compression applications. Because our compression fleet is comprised of units of varying horsepower that have been placed into service with staggered initial on-line dates, we are able to schedule overhauls in a way that avoids excessive annual maintenance capital expenditures and minimizes the revenue impacts of down-time.
We believe that our customers, by outsourcing their compression requirements, can achieve higher compression run-times, which translates into increased volumes of either natural gas or crude oil production and, therefore, increased revenues. Utilizing our compression services also allows our customers to reduce their operating, maintenance, and equipment costs by allowing us to efficiently manage their changing compression needs. In many of our service contracts, we guarantee our customers availability (as described below) ranging from 95% to 98%, depending on field-level requirements.
Marketing and Sales
Our marketing and client service functions are performed on a coordinated basis by our sales team and field technicians. Salespeople, applications engineers, and field technicians qualify, analyze, and scope new compression applications as well as regularly visit our customers to ensure customer satisfaction, determine a customer’s needs related to existing services being provided, and determine the customer’s future compression service requirements. This ongoing communication allows us to quickly identify and respond to our customers’ compression requirements.
Customers
Our customers consist of approximately 275 companies in the energy industry, including major integrated oil companies, public and private independent exploration and production companies, and midstream companies. Our ten largest customers accounted for approximately 41%, 39%, and 38% of our total revenues for the years ended December 31, 2024, 2023, and 2022, respectively.
Suppliers and Service Providers
The principal manufacturers of components for our natural gas compression equipment include Caterpillar Inc., Cummins Inc., INNIO Waukesha, and TECO-Westinghouse for engines; Air-X-Changers, Alfa Laval (US), AXH air-coolers, EADS Cooling Solutions, LLC, and R&R Engineering Co. for coolers; and Ariel Corporation, Cooper Machinery Services Gemini
products, and Arrow Engine Company for compressor frames and cylinders. We also rely primarily on three vendors, A G Equipment Company, Alegacy Equipment, LLC., and Standard Equipment Company, to package and assemble our compression units. Although we primarily rely on these suppliers, we believe alternative sources for natural gas compression equipment generally are available if needed. However, relying on alternative sources may increase our costs and change the standardized nature of our fleet. We have not experienced any material supply problems to date. Lead-times for new Caterpillar engines and new Ariel compressor frames have in the recent past varied between six months to over one year due to changes in demand and supply allocations, and as of December 31, 2024, lead-times for such engines and frames are approximately one year. Please read Part I, Item 1A “Risk Factors – Risks Related to Our Business – 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”.
Competition
The compression services business is highly competitive. Some of our competitors have greater financial and other resources than we do. On a regional basis, we experience competition from numerous smaller companies that may be able to more quickly adapt to changes within our industry and changes in economic conditions as a whole, more readily take advantage of available opportunities, and adopt more aggressive pricing policies. Additionally, the historical availability of attractive financing terms from financial institutions and equipment manufacturers has made the purchase of individual compression units more affordable to our customers. We believe that we compete effectively on the basis of price, equipment availability, customer service, flexibility in meeting customer needs, quality and reliability of our compressors, and related services. Please read Part I, Item 1A “Risk Factors – Risks Related to Our Business – We face significant competition that may cause us to lose market share and reduce our cash available for distribution”.
Seasonality
Our results of operations have not historically been materially affected by seasonality, and we do not currently have reason to believe that seasonal fluctuations will have a material impact in the foreseeable future.
Insurance
We believe that our insurance coverage is customary for the industry and adequate for our business. As is customary in the energy services industry, we review our safety equipment and procedures, and carry insurance against most, but not all, risks of our business. Losses and liabilities not covered by insurance would increase our costs. The compression business can be hazardous, involving unforeseen circumstances such as uncontrollable flows of gas or well fluids, fires and explosions, or environmental damage. To address the hazards inherent in our business, we maintain insurance coverage that, subject to significant deductibles, includes physical damage coverage, third-party general liability insurance, employer’s liability, environmental and pollution, and other coverage, although coverage for environmental- and pollution-related losses is subject to significant limitations. Under the terms of our standard compression services contract, we are responsible for maintaining insurance coverage on our compression equipment. Please read Part I, Item 1A “Risk Factors – General Risk Factors – We do not insure against all potential losses and could be seriously harmed by unexpected liabilities”.
Governmental Regulations
We are subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health, safety, and the environment. These regulations include compliance obligations for air emissions, water quality, wastewater discharges, and solid and hazardous waste disposal, as well as regulations designed for the protection of human health and safety, and threatened or endangered species. Compliance with these environmental laws and regulations may expose us to significant costs and liabilities and cause us to incur significant capital expenditures in our operations. We often are obligated to provide information to customers in obtaining permits or approvals in our operations from various federal, state, and local authorities. Permits and approvals can be denied or delayed, which may cause us to lose potential and current customers, interrupt our operations, and limit our growth and revenue. Moreover, failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, imposition of remedial obligations, and the issuance of injunctions delaying or prohibiting operations. Private parties also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. While we believe that our operations are in substantial compliance with applicable environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, we cannot predict whether our cost of compliance will materially increase in the future. Any changes in, or more stringent enforcement of, existing environmental laws and regulations, or passage of additional environmental laws and regulations that result in more stringent and costly pollution control equipment, waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position.
We do not believe that compliance with current federal, state, or local laws and regulations will have a material adverse effect on our business, financial position, results of operations, or cash flows. We cannot assure you, however, that future events such as changes in existing laws or regulations or enforcement policies, the promulgation of new laws or regulations, or the development or discovery of new facts or conditions or unforeseen incidents will not cause us to incur significant costs. The following is a discussion of material environmental and safety laws that relate to our operations. We believe that we are in substantial compliance with all of these environmental laws and regulations. Please read Part I, Item 1A “Risk Factors – Risks Related to Governmental Legislation and Regulation – We and our customers are subject to substantial environmental regulation, and changes in these regulations could increase our and their costs or liabilities and result in decreased demand for our services”.
Air emissions. The Clean Air Act (“CAA”) and comparable state laws regulate emissions of air pollutants from various industrial sources, including natural gas compressors, and impose certain monitoring and reporting requirements. Such emissions are regulated by air emissions permits, which are applied for and obtained through various state or federal regulatory agencies. Our standard natural gas compression contract provides that the customer is responsible for obtaining air emissions permits and assuming the environmental risks related to site operations. In some instances, our customers may be required to aggregate emissions from a number of different sources on the theory that the different sources should be considered a single source. Any such determinations could have the effect of making projects more costly than our customers expected and could require the installation of more costly emissions controls, which may lead some of our customers not to pursue certain projects.
Increased obligations of operators to reduce air emissions of nitrogen oxides and other pollutants from internal combustion engines in transmission service have been imposed by governmental authorities. For example, in 2010, the U.S. Environmental Protection Agency (“EPA”) published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines, also known as Quad Z regulations. The rule requires us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment on certain compressor engines and generators.
In recent years, the EPA has lowered the National Ambient Air Quality Standards (“NAAQS”) for several air pollutants. For example, in 2015, the EPA finalized a rule strengthening the primary and secondary standards for ground-level ozone, both of which are eight-hour concentration standards of 70 parts per billion (the “2015 NAAQS”). In December 2020, the EPA announced its decision to retain, without changes, the 2015 NAAQS. After the EPA revises a NAAQS standard, the states are expected to establish revised attainment/non-attainment regions. State implementation of the 2015 NAAQS could result in stricter permitting requirements, delay, or prohibit our customers’ ability to obtain such permits, and result in increased expenditures for pollution-control equipment, which could impact our customers’ operations, increase the cost of additions to property and equipment, and negatively impact our business.
In 2012, the EPA finalized rules that establish new air emissions controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards (“NSPS”) to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emissions standards to address hazardous air pollutants frequently associated with crude oil and natural gas production and processing activities. The rules established specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks, and other production equipment, as well as the first federal air standards for natural gas wells that are hydraulically fractured. In June 2016, the EPA expanded these regulations when it published additional NSPS, known as Subpart OOOOa, that require certain new, modified, or reconstructed facilities in the oil and gas sector to reduce methane gas and VOC emissions. These Subpart OOOOa standards expanded the 2012 NSPS by mandating certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. 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.
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. The final rule establishes new emissions standards for engines, which could impact the operation of specific categories of engines by requiring the use of alternative engines, compressor packages, or the installation of aftermarket emissions control equipment. The rule became effective for the Barnett Shale production area in April 2011, with the lower emissions standards becoming applicable between 2015 and 2030 depending on the type of engine and the permitting requirements. The cost to comply with the revised air permit programs is not expected to be material at this time. However, the TCEQ has stated it will consider
expanding application of the new air permit program statewide. At this point, we cannot predict the cost to comply with such requirements if the geographic scope is expanded.
There can be no assurance that future requirements compelling the installation of more sophisticated emissions control equipment would not have a material adverse impact on our business, financial condition, results of operations, and cash available for distribution.
Climate change. 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. The Inflation Reduction Act of 2022 (the “IRA 2022”) imposes a methane emissions charge on certain oil and gas facilities, including onshore petroleum and natural gas production facilities, that emit 25,000 metric tons or more of carbon dioxide equivalent gas per year and exceed certain emissions thresholds. In November 2024, the EPA issued a final rule to impose and collect the methane emissions charge authorized under the IRA 2022. We do not believe that this methane fee will have a material adverse effect on our business, financial position, results of operations, or cash flows. Other energy legislation and initiatives could include a carbon tax or cap-and-trade program. At the state level, many states, including the states in which we or our customers conduct operations, have adopted legal requirements that have imposed new or more stringent permitting, disclosure, or well construction requirements on oil and gas activities. 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. Congress, the EPA undertook to adopt regulations controlling GHG emissions under its existing CAA authority. 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. In 2009 and 2010, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles and required the reporting of GHG emissions in the U.S. from specified large GHG emissions sources, including petroleum and natural gas facilities such as natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year.
In addition, from time to time, there have been various proposals to regulate hydraulic fracturing at the federal level. Hydraulic fracturing involves the injection of water, sand, and chemicals under pressure into the rock formation to stimulate oil and gas production. Any limitations or bans on hydraulic fracturing at the federal level could increase the costs of operations for our customers who operate on federal land, and negatively impact our business.
Some states also have passed legislation or regulations regarding hydraulic fracturing. For example, in 2019, Colorado passed Senate Bill 19-181, which delegates authority to local governments to regulate oil and gas activities and requires the Colorado Oil and Gas Conservation Commission to minimize emissions of methane and other air contaminants. Some local communities have adopted additional restrictions for oil and gas activities, such as requiring greater setbacks, and some groups are petitioning local governments to ban hydraulic fracturing. If additional regulatory measures are adopted that ban or restrict production of natural gas through hydraulic fracturing, our customers could experience delays, limitations, or prohibitions on their activities. Such delays, limitations, or prohibitions could result in decreased demand for our services.
Litigation risks also are increasing, as several cities, local governments, and other plaintiffs have sued companies engaged in the exploration and production of fossil fuels in state and federal courts, alleging various legal theories to recover for the impacts of alleged global warming effects, such as rising sea levels. Many of these suits allege that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. Although a number of these lawsuits have been dismissed, others remain pending and the outcome of these cases remains difficult to predict.
Although it is not currently possible to predict with specificity how any proposed or future GHG legislation, regulation, agreements or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate, including a carbon tax or cap-and-trade program, could result in increased compliance or operating costs, additional operating restrictions, or reduced demand for our services, and could have a material adverse effect on our business, financial condition, and results of operations. Notwithstanding potential risks related to climate change, the EIA estimates that crude oil and natural gas will continue to represent a major share of energy use through 2050. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector, which could have an adverse effect on our ability to obtain external financing.
Finally, some scientists have concluded that increasing concentrations of GHG in Earth’s atmosphere may produce climate changes that have significant weather-related effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. If any of those effects were to occur, they could have an adverse effect on our or our customers’ assets and operations, or result in increased cost or difficulty obtaining insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas liquids (“NGLs”) and natural gas generally is impacted by periods of colder weather and warmer weather, so any changes in climate could affect the market for these fuels, and thus demand for our services. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our services could be affected by increased temperature volatility.
We recognize the need to decrease emissions and integrate alternative energy sources into our operations, and we actively pursue economically beneficial opportunities to reduce our environmental footprint. To that end, we have continued the commercialization of dual-drive technology in our natural gas compression services, deploying our first compression units with dual-drive technology in the third quarter of 2022. Dual-drive technology offers the ability to switch compression drivers between an electric motor and a natural gas engine, to reduce our emissions of nitrogen oxide, carbon monoxide, carbon dioxide, and VOCs.
Water discharge. The Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the U.S. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The CWA also requires the development and implementation of spill prevention, control, and countermeasures, including the construction and maintenance of containment berms and similar structures, if required, to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak at such facilities. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
Our compression operations do not generate process wastewaters that are discharged to waters of the U.S. In any event, our customers assume responsibility under the majority of our standard natural gas compression contracts for obtaining any permits that may be required under the CWA, whether for discharges or developing property by filling wetlands. The EPA and the U.S. Army Corps of Engineers have changed the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA from time to time. Changes to the jurisdictional reach of the CWA could cause our customers to face increased costs and delays due to additional permitting and regulatory requirements, and possible challenges to permitting decisions.
Safe Drinking Water Act. A significant portion of our customers’ natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Legislation to amend the Safe Drinking Water Act (“SDWA”) to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed from time to time. Several states also have proposed or adopted legislative or regulatory restrictions on hydraulic fracturing, including prohibitions on the practice. We cannot predict the future of such legislation and what additional, if any, provisions would be included. If additional levels of regulation, restrictions, and permits were required through the adoption of new laws and regulations at the federal or state level, or if the agencies that issue the permits develop new interpretations of those requirements, it could lead to delays, increased operating costs, and process prohibitions that could reduce demand for our compression services, which could materially adversely affect our revenue and results of operations.
Site remediation. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state laws may impose strict, joint, and several liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the current and former owners and operators of the site where the hazardous substance release occurred and any company that transported, disposed of, or arranged for the transport or disposal of the hazardous substance released at the site. Under CERCLA, such persons may be liable for the costs of remediating the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, where contamination may be present, neighboring landowners and other third parties sometimes file claims for personal injury, property damage, and recovery of response costs. While we generate materials in the course of our operations that may be regulated as hazardous
substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA at any site.
While we do not currently own or lease any material facilities or properties for storage or maintenance of our idle compression units, we may use third-party properties for such storage and possible maintenance and repair activities. In addition, our revenue-generating compression units typically are installed on properties owned or leased by third-party customers and operated by us pursuant to terms set forth in the natural gas compression services contracts executed by those customers. Under most of our natural gas compression services contracts, our customers must contractually indemnify us for certain damages we may suffer as a result of the release into the environment of hazardous and toxic substances. 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 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. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, and similar state statutes require that we organize and, as necessary, disclose information about hazardous materials used or produced in our operations to various federal, state, and local agencies, as well as to employees.
Human Capital Management
USA Compression Management Services, LLC (“USAC Management”), a wholly owned subsidiary of the General Partner, performs certain management, administrative and operating services for us, and provides us with personnel to manage and operate our business. All of our employees, including our executive officers, are employees of USAC Management. As of December 31, 2024, USAC Management had 854 full-time employees. In addition, under our shared services model with Energy Transfer, in late 2024 we began utilizing the services of Energy Transfer employees in certain departments such as information technology, accounting, and human resources. None of our employees are subject to collective bargaining agreements. 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. These four pillars rest on a foundation of safety and guide our values in a manner that respects all people with a commitment to safety and the environments where we operate.
Ethics and Values. We are committed to operating our business in a manner that honors and respects all people and the communities in which we do business. We recognize that people are our most critical resource, and we are committed to hiring and investing in our employee base. We value employees for what they bring to our organization by embracing those from diverse backgrounds, cultures, and experiences. We believe that one of the keys to our successes over time has been the cultivation of an atmosphere of inclusion and respect. These are the principles upon which we build and strengthen relationships among our people, our unitholders, our customers, and those within the communities we support.
We believe strict adherence to our Code of Business Conduct and Ethics is not only right, but is in our best interest and the best interest of our unitholders, our customers, and the industry in general. In all instances, our policies require that the business of the Partnership be conducted in a lawful and ethical manner. Every employee acting on behalf of the Partnership must adhere to our policies. Please refer to Part III, Item 10 “Directors, Executive Officers, and Corporate Governance” for additional information on our Code of Business Conduct and Ethics.
Commitment to Safety. We have a strong commitment to safety. We provide continuous training opportunities for employees, including training that is required by applicable laws, regulations, standards, and permit conditions. Our safety standards and expectations are clearly communicated to all employees with the expectation that each individual has the obligation to make safety their highest priority. Our safety culture promotes an open environment for discovering, resolving, and sharing safety challenges. We strive to eliminate unwanted safety events and support our safety culture through a comprehensive program that includes a dedicated field operations-based safety team, monthly employee safety meetings, and safety audits, among other things. A portion of our senior management bonuses and field leadership bonuses are dependent on our safety performance. Our goal is operational excellence, which includes maintaining an injury- and incident-free workplace. To achieve this, we strive to hire and maintain a highly qualified and dedicated workforce, and create a safety culture with safety accountability as part of our daily operations. We promote employee empowerment, leadership, communication, and personal responsibility to comply with standard operating procedures and regulatory requirements, effective risk reduction processes, and personal wellness.
Available Information
Our website address is usacompression.com. We make available, free of charge at the “Investor Relations” section of our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC. The information contained on our website does not constitute part of this report.
The SEC maintains a website that contains these reports at sec.gov.
ITEM 1A. Risk Factors
As described in Part I “Disclosure Regarding Forward-Looking Statements,” this report contains forward-looking statements regarding us, our business, and our industry. The risk factors described below, among others, could cause our actual results to differ materially from the expectations reflected in the forward-looking statements. If any of the following risks were to materialize, our business, financial condition or results of operations could be materially and adversely affected. In that case, we might not be able to continue to pay our current quarterly distribution on our common units or increase the level of such distributions in the future, and the trading price of our common units could decline.
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. The loss of any of these customers would result in a decrease in our revenues and cash available for distribution.
•We face significant competition that may cause us to lose market share and reduce our cash available for distribution.
•Implementing the shared services model with Energy Transfer will be a complex and time-consuming process. Disruptions to our systems or operations caused by the implementation may have a material adverse impact on us.
•Our customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, increasing the number of compression units they currently own, or using alternative technologies for enhancing crude oil production, which could result in a decrease in our revenues and cash available for distribution to unitholders.
•A significant portion of our services are provided to customers on a month-to-month basis, and we cannot be sure that such customers will continue to utilize our services. 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.
Risks Related to Governmental Legislation and Regulation
•We and our customers are subject to substantial environmental regulation, and changes in these regulations could increase our and their costs or liabilities and result in decreased demand for our services.
•New regulations, proposed regulations, and proposed modifications to existing regulations under the Clean Air Act, if implemented, could result in increased compliance costs.
Risks Inherent in an Investment in Us
•Holders of our common units have limited voting rights and are not entitled to elect the General Partner or its directors.
•Energy Transfer owns and controls the General Partner, and the General Partner has sole responsibility for conducting our business and managing our operations. The General Partner and its affiliates, including Energy Transfer, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders.
•The Partnership Agreement limits the General Partner’s fiduciary duties to our unitholders.
•The Partnership Agreement restricts the remedies available to our unitholders for actions taken by the General Partner that otherwise might constitute breaches of fiduciary duty.
•The Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units.
•We may issue additional limited partner interests without the approval of unitholders, subject to certain Preferred Unit approval rights, which would dilute unitholders’ existing ownership interests and may increase the risk that we will not have sufficient available cash to maintain or increase our per-common-unit distribution level.
•Energy Transfer may sell, and the holders of the Preferred Units have sold and may continue to sell, our common units in the public or private markets, and such sales could have an adverse impact on the trading price of our common units.
•The General Partner has a call right that may require holders of our common units to sell their common units at an undesirable time or price.
•Unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.
•Unitholders may have liability to repay distributions that were wrongfully distributed to them.
•Our Partnership Agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our General Partner’s directors, officers, or other employees.
Tax Risks to Common Unitholders
•Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or if we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced.
•The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial, or administrative changes or differing interpretations, possibly applied on a retroactive basis.
•Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from them with respect to that income.
•If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
•Tax gain or loss on the disposition of our common units could be more or less than expected.
•Unitholders will be subject to limitation on their ability to deduct interest expense incurred by us.
•Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.
•We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
•We generally prorate our items of income, gain, loss, and deduction for federal income tax purposes between transferors and transferees of our units each month based on the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss, and deduction among our unitholders.
•We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss, and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.
•As a result of investing in our common units, you will likely become subject to state and local taxes and income tax return filing requirements in jurisdictions where we operate or own or acquire properties.
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.
To make cash distributions at our current distribution rate of $0.525 per common unit per quarter, or $2.10 per common unit per year, we will require available cash of $61.7 million per quarter, or $246.8 million per year, based on the number of common units outstanding as of February 6, 2025.
Furthermore, our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”) prohibits us from paying distributions on our common units unless we have first paid the quarterly distribution on the Preferred Units, including any previously accrued but unpaid distributions on the Preferred Units. The Preferred Unit distributions require $4.4 million quarterly, or $17.6 million annually, based on the number of Preferred Units outstanding as of February 6, 2025 and the distribution rate of $24.375 per Preferred Unit per quarter, or $97.50 per Preferred Unit per year.
Under our cash distribution policy, the amount of cash we can distribute to our unitholders principally depends on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
•the level of production of, demand for, and price of natural gas and crude oil, particularly the level of production in the regions where we provide compression services;
•the fees we charge, and the margins we realize, from our compression services;
•the cost of achieving organic growth in current and new markets;
•the ability to effectively integrate any assets or businesses we acquire;
•the level of competition from other companies; and
•prevailing global and regional economic and regulatory conditions, and their impact on us and our customers.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:
•the levels of our maintenance and expansion capital expenditures;
•the level of our operating costs and expenses;
•our debt service requirements and other liabilities;
•state sales and use taxes that may be levied on us by the states in which we operate;
•fluctuations in our working capital needs;
•restrictions contained in the Credit Agreement or the Indentures (the “Indentures”) governing the Senior Notes 2027 and Senior Notes 2029 (collectively, the “Senior Notes”);
•the cost of acquisitions;
•fluctuations in interest rates;
•the financial condition of our customers;
•our ability to borrow funds and access the capital markets; and
•the amount of cash reserves established by the General Partner.
An extended reduction in the demand for, or production of, natural gas or crude oil could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders.
The 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. Any extended reduction in the demand for natural gas or crude oil could depress the level of production activity and result in a decline in the demand for our compression services, which could result in a reduction in our revenues and our cash available for distribution.
In particular, lower natural gas or crude oil prices over the long term could result in a decline in the production of natural gas or crude oil, respectively, resulting in reduced demand for our compression services. For example, in 2020, the price of crude oil declined rapidly beginning in March of that year. 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. 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 addition, a portion of our fleet is used in gas lift applications in connection with crude oil production using horizontal drilling techniques. During periods of low crude oil prices, we typically experience pressure on service rates and utilization from our customers in gas lift applications, and we have experienced such effects in the past. Any future decreases in the rate at which crude oil and natural gas reserves are developed, whether due to increased governmental regulation, low commodity pricing environment, limitations on exploration and production activity, or other factors, could have a material adverse effect on our business.
Additionally, unconventional sources, such as shales, tight sands, and coalbeds, can be less economically feasible to produce in low commodity price environments, in part due to costs related to compression requirements, and a reduction in demand for natural gas or gas lift for crude oil may cause such sources of natural gas or crude oil to become uneconomic to drill and produce, which has negatively impacted, and may again in the future negatively impact, the demand for our services. 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. The loss of one of these key customers may have a greater effect on our financial results than for a company with a more diverse customer base. Our ten largest customers accounted for approximately 41%, 39%, and 38% of our total revenues for the years ended December 31, 2024, 2023, and 2022, respectively. The loss of all or even a portion of the compression services we provide to our key customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, financial condition, and cash available for distribution.
We face significant competition that may cause us to lose market share and reduce our cash available for distribution.
The natural gas compression business is highly competitive. Some of our competitors have greater financial and other resources than we do. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors and our customers. If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to compete effectively. Some of these competitors may expand or construct newer, more powerful, or more flexible compression fleets, which would create additional competition for us. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition, and cash available for distribution.
Implementing the shared services model with Energy Transfer will be a complex and time-consuming process. Disruptions to our systems or operations caused by the implementation may have a material adverse impact on us.
We are currently implementing a shared services model with Energy Transfer whereby we intend to share personnel and resources with Energy Transfer in certain departments, including information technology, accounting, and human resources. Integrating these functions with Energy Transfer will require substantial time, resources, and coordination. This could result in significant disruptions or require a disproportionate amount of our management’s attention, and may result in unforeseen
operational or administrative difficulties or costs. We may encounter significant delays to this integration, which would further exacerbate these effects. We may also encounter difficulties in integrating our personnel with Energy Transfer’s teams, and may lose key employees.
Additionally, as part of the shared services integration, many of our information systems will migrate to Energy Transfer’s enterprise resource planning (“ERP”) systems. This migration may result in significant disruptions to our accounting or other internal systems, including our ability maintain effective systems of internal control over financial reporting and disclosure controls.
If any of these risks or any other unanticipated complications were to materialize, we may not realize the desired benefits from the shared services integration, such as operational and administrative synergies and cost reductions, which could result in a negative impact on our cash flows. Additionally, disruptions to our internal systems, including our internal control over financial reporting, could negatively impact our business, results of operations and financial condition.
Our customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, increasing the number of compression units they currently own, or using alternative technologies for enhancing crude oil production, which could result in a decrease in our revenues and cash available for distribution to unitholders.
Our customers that are significant producers, processors, gatherers, and transporters of natural gas and crude oil may choose to vertically integrate their operations by purchasing and operating their own compression fleets in lieu of using our compression services. The historical availability of attractive financing terms from financial institutions and equipment manufacturers facilitates this possibility by making the purchase of individual compression units more affordable to our customers. In addition, there are many technologies available for the artificial enhancement of crude oil production, and our customers may elect to use these alternative technologies instead of the gas lift compression services we provide. 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.
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.
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. For the year ended December 31, 2024, approximately 14% of our compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize our services following expiration of the primary term of their contracts. These customers can generally terminate their month-to-month compression services contracts on 30 days’ written notice. If a significant number of these customers were to terminate their month-to-month services, or attempt to renegotiate their month-to-month contracts at substantially lower rates, it 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.
As of December 31, 2024, we had $2.5 billion of total debt, net of amortized deferred financing costs, outstanding under our Credit Agreement and Senior Notes.
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. As of December 31, 2024, we had outstanding borrowings under the Credit Agreement of $772.1 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $827.1 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $782.5 million was available to be drawn.
As of December 31, 2024, we had $750.0 million and $1.0 billion aggregate principal amount outstanding on our Senior Notes 2027 and Senior Notes 2029, respectively. The Senior Notes 2027 and Senior Notes 2029 accrue interest at the rate of 6.875% and 7.125% per year, respectively.
Our ability to incur additional debt also is subject to limitations in the Credit Agreement, including certain financial covenants. As of December 31, 2024, our leverage ratio under the Credit Agreement was 4.02x. 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. As of February 6, 2025, we had outstanding borrowings under the Credit Agreement of $801.5 million and outstanding letters of credit of $0.8 million.
Our level of debt could have important consequences to us, including the following:
•our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions, or other purposes may not be available, or such financing may not be available on favorable terms;
•we will need a portion of our cash flow to make payments on our indebtedness, reducing the funds that otherwise would be available for operating activities, future business opportunities, and distributions; and
•our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
Our ability to service our debt will depend on, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory, and other factors, some of which are beyond our control. In addition, our ability to service our debt under the Credit Agreement could be impacted by market interest rates, as all of our outstanding borrowings under the Credit Agreement are subject to variable interest rates that fluctuate with changes in market interest rates. While the U.S. Federal Reserve has begun lowering interest rates, macroeconomic circumstances may change, resulting in delays or reversal of such actions, which may result in a prolonged high-interest rate environment. Any substantial increase in the interest rates applicable to our variable-rate indebtedness outstanding could have a material negative impact on our cash available for distribution. Based on our December 31, 2024, variable-rate indebtedness outstanding, a one percent increase in the effective interest rate would result in an annual increase in our interest expense of approximately $7.7 million. 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. 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.
The substantial majority of the components for our natural gas compression equipment are supplied by Caterpillar Inc., Cummins Inc., INNIO Waukesha, and TECO-Westinghouse for engines; Air-X-Changers, Alfa Laval (US), AXH air-coolers, EADS Cooling Solutions, LLC, and R&R Engineering Co. for coolers; and Ariel Corporation, Cooper Machinery Services Gemini products, and Arrow Engine Company for compressor frames and cylinders. Our reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. In addition, supply chain disruptions (including those caused by geopolitical events) may harm our suppliers and further complicate existing supply chain constraints. We also rely primarily on three vendors, A G Equipment Company, Alegacy Equipment, LLC., and Standard Equipment Company, to package and assemble our compression units. We do not have long-term contracts with these suppliers or packagers, and a partial or complete loss of any of these sources could have a negative impact on our results of operations and could damage our customer relationships. Some of these suppliers manufacture the components we purchase in a single facility, and any damage to that facility or slowdown or closure of that facility for any reason, including labor shortages or labor disputes, could lead to significant delays in delivery of completed compression units to us.
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.
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. Our future growth will depend on several factors, some of which we cannot control. These factors include our ability to:
•develop new business and enter into service contracts with new customers;
•retain our existing customers and maintain or expand the services we provide them;
•maintain or increase the fees we charge, and the margins we realize, from our compression services;
•recruit and train qualified personnel and retain valued employees;
•expand our geographic presence;
•effectively manage our costs and expenses, including costs and expenses related to growth;
•complete accretive acquisitions;
•obtain required debt or equity financing on favorable terms for our existing and new operations; and
•meet customer-specific contract requirements or pre-qualifications.
If we do not achieve our expected growth, we may not be able to maintain or increase the level of distributions on our common units, likely causing the market price of our common units to decline.
Our 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.
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. We expect to fund expansion capital expenditures through borrowings under the Credit Agreement and the issuance of debt and equity securities. 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. In addition, because we distribute all of our available cash, excluding prudent operating reserves, we may not grow as quickly as businesses that are able to reinvest their available cash to expand ongoing operations.
There are no limitations in the Partnership Agreement on our ability to issue additional equity securities, including securities ranking senior to the common units, subject to certain restrictions in the Partnership Agreement limiting our ability to issue units senior to or pari passu with the Preferred Units. 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. Similarly, our incurrence of borrowings or other debt to finance our growth strategy would increase our interest expense, which in turn would decrease our cash available for distribution.
The terms of the Credit Agreement and the Indentures restrict our current and future operations, particularly our ability to respond to changes or to take certain actions, may limit our ability to pay distributions and may limit our ability to capitalize on acquisitions and other business opportunities.
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.
In addition, the Credit Agreement contains certain operating and financial covenants that require us to maintain specified financial ratios and satisfy other financial condition tests. Our ability to comply with those covenants and meet those financial ratios and tests can be affected by events beyond our control, including prevailing economic, financial, and industry conditions. If market or other conditions deteriorate, our ability to comply with these covenants may be impaired.
A breach of the covenants or restrictions under the Credit Agreement or the Indentures could result in an event of default, in which case a significant portion of our indebtedness may become immediately due and payable and any other debt to which a cross-acceleration or cross-default provision applies also may be accelerated, our lenders’ commitment to make further loans to us may terminate, and we may be prohibited from making distributions to our unitholders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. If we were unable to repay amounts due and payable under the Credit Agreement, those lenders could proceed against the collateral securing that indebtedness. We may not be able to replace the Credit Agreement, or if we are, any subsequent replacement of the Credit Agreement or any new indebtedness could be equally or more restrictive.
These restrictions may negatively affect our ability to grow in accordance with our strategy. In addition, our financial results, substantial indebtedness, and credit ratings could adversely affect the availability and terms of our financing. Please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Revolving Credit Facility and – Senior Notes”.
The deterioration of the financial condition of our customers could adversely affect our business.
During times when the natural gas or crude oil markets weaken our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. 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 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. 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.
Weak economic conditions and widespread financial distress, have in the past and could again reduce the liquidity of our customers, suppliers, or vendors, making it more difficult for them to meet their obligations to us. We therefore are subject to heightened risks of loss resulting from nonpayment or nonperformance by our customers, suppliers, and vendors. Severe financial problems encountered by our customers, suppliers, and vendors could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In the event that any of our customers was to enter into bankruptcy, we could lose all or a portion of the amounts owed to us by such customer, and we may be forced to cancel all or a portion of our service contracts with such customer at significant expense to us. For example, as of December 31, 2024, two customers accounted for 12% and 11% of our trade accounts receivable, net balance, respectively. If these customers were to enter bankruptcy or failed to pay us, it could adversely affect our business, results of operations, financial condition, and cash flows.
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.
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.
In addition, distributions on the Preferred Units accrue and are cumulative, at the rate of 9.75% per annum on the original issue price, which amounts to a quarterly distribution of $24.375 per Preferred Unit, or $97.50 per Preferred Unit per year. 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. Also, because distributions on our common units are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our
common unitholders will not be entitled to receive distributions covering any prior periods if we later recommence paying distributions on our common units.
The Preferred Units are convertible into common units in accordance with the terms of the Partnership Agreement by the holders of the Preferred Units or by us in certain circumstances. In 2024, holders of our Preferred Units converted an aggregate of 320,000 Preferred Units. Our obligation to pay distributions on the Preferred Units, or on the common units issued following the conversion of the Preferred Units, could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general Partnership purposes. Our obligations to the holders of the Preferred Units also could limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition. See Note 11 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
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.
The operating and financial restrictions and covenants in the Partnership Agreement related to the Preferred Units could restrict our ability to finance future operations or capital needs, or to expand or pursue our business activities. 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.
A prolonged or severe sudden downturn in the economic environment could cause an impairment of identifiable intangible assets and reduce our earnings.
We have recorded $216.3 million of identifiable intangible assets, net, as of December 31, 2024. 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. For example, for the year ended December 31, 2020, we recognized a $619.4 million impairment of goodwill as a result of an economic downturn that occurred that year.
If we determine that any of our identifiable intangible assets are impaired, we will be required to take an immediate charge to earnings with a corresponding reduction of partners’ capital resulting in an increase in balance sheet leverage as measured by debt to total capitalization.
Impairment to the carrying value of long-lived assets could reduce our earnings.
We have a significant number of long-lived assets on our Consolidated Balance Sheets. Under GAAP, we are required to review our long-lived assets for impairment when events or circumstances indicate that the carrying value of such assets may not be recoverable or such assets will no longer be utilized in the operating fleet. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If business conditions or other factors cause the expected undiscounted cash flows to decline, we may be required to record non-cash impairment charges. Events and conditions that could result in impairment in the value of our long-lived assets include changes in the industry in which we operate, competition, advances in technology, adverse changes in the regulatory environment, or other factors leading to a reduction in our expected long-term profitability. For example, for the years ended December 31, 2024, 2023, and 2022, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 2, 42, and 15 compression units, respectively, representing approximately 1,260, 37,700, and 3,200 of aggregate horsepower, respectively, that previously were used to provide compression services in our business. As a result, we recorded impairments of compression equipment of $0.3 million, $12.3 million, and $1.5 million for the years ended December 31, 2024, 2023, and 2022, respectively.
Additionally, for the year ended December 31, 2024, we recognized a $0.6 million impairment of assets related to capitalized software costs that are no longer expected to provide benefit.
Our ability to manage and grow our business effectively may be adversely affected if we lose key management or operational personnel.
We depend on the continuing efforts of our executive officers and the departure of any of our executive officers could have a significant negative effect on our business, operating results, financial condition, and on our ability to compete effectively in the marketplace.
Additionally, our ability to hire, train, and retain qualified personnel will continue to be important and could become more challenging as we grow and to the extent energy industry market conditions are competitive. When labor markets are tight, such as when general industry conditions are favorable, the competition for experienced operational and field technicians increases as other energy and manufacturing companies’ needs for the same personnel increases. Our ability to grow or even to continue our current level of service to our current customers could be adversely impacted if we are unable to successfully hire, train, and retain these important personnel.
We may be unable to grow successfully through acquisitions, which may negatively impact our operations and limit our ability to maintain or increase the level of distributions on our common units.
From time to time, we may choose to make business acquisitions to pursue market opportunities, increase our existing capabilities, and expand into new geographic areas of operations. While we have reviewed acquisition opportunities in the past and will continue to do so in the future, we may not be able to identify attractive acquisition opportunities or successfully acquire identified targets.
Any acquisitions we do complete may require us to issue a substantial amount of equity or incur a substantial amount of indebtedness. If we consummate any future material acquisitions, our capitalization may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial, and other relevant information that we will consider in connection with any future acquisition. Furthermore, competition for acquisition opportunities may escalate, increasing our costs of pursuing acquisitions or causing us to refrain from making acquisitions.
Also, our reviews of proposed business or asset acquisitions are inherently imperfect because generally it is not feasible to perform an in-depth review of each such proposal given time constraints imposed by sellers. Even if performed, a detailed review of assets and businesses may not reveal existing or potential problems, and may not provide sufficient familiarity with such business or assets to fully assess their deficiencies and potential. Inspections may not be performed on every asset, and environmental problems, such as groundwater contamination, may not be observable even when an inspection is undertaken.
Integration of assets acquired in future acquisitions with our existing business can be complex, time-consuming, and costly, particularly in the case of material acquisitions such as the CDM Acquisition, which significantly increased our size and expanded the geographic areas in which we operate. A failure to successfully integrate acquired assets with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations, or cash available for distribution to our unitholders.
The difficulties of integrating future acquisitions with our business include, among other things:
•operating a larger combined organization in new geographic areas and new lines of business;
•hiring, training, or retaining qualified personnel to manage and operate our growing business and assets;
•integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees;
•diversion of management’s attention from our existing business;
•assimilation of acquired assets and operations, including additional regulatory programs;
•loss of customers;
•loss of key employees;
•maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and
•integrating new technology systems for financial reporting.
If any of these risks or other unanticipated liabilities or costs were to materialize, we may not realize the desired benefits from past and future acquisitions, resulting in a negative impact on our results of operations. 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.
We may not be successful in integrating acquisitions into our existing operations within our anticipated time frame, which may result in unforeseen operational difficulties, diminished financial performance, or require a disproportionate amount of our management’s attention. In addition, acquired assets may perform at levels below the forecasts used to evaluate their acquisition value, due to factors beyond our control. If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted.
The CDM Acquisition could expose us to additional unknown and contingent liabilities, which liabilities could materially adversely affect our business, results of operations, and cash flow.
The CDM Acquisition could expose us to additional unknown and contingent liabilities. We performed due diligence in connection with the CDM Acquisition and attempted to verify the representations made by Energy Transfer in connection therewith, but there may be unknown and contingent liabilities of which we are currently unaware. Energy Transfer has agreed to indemnify us for losses or claims relating to the operation of the business or otherwise only to a limited extent and for a limited period of time, and certain of Energy Transfer’s indemnification obligations have lapsed. There is a risk that we could ultimately be liable for obligations relating to the CDM Acquisition for which indemnification is not available, which could materially adversely affect our business, results of operations, and cash flow.
From time to time, we are subject to various claims, tax audits, litigation, and other proceedings that could ultimately be resolved against us and require material future cash payments or charges, which could impair our financial condition or results of operations.
The size, nature, and complexity of our business make us susceptible to various claims, tax audits, litigation, and binding arbitration proceedings. We are currently, and may in the future become, subject to various claims, which, if not resolved within amounts we have accrued, if any, could have a material adverse effect on our financial position, results of operations, or cash flows, including our ability to pay distributions. Similarly, any claims, even if fully indemnified or insured, could negatively impact our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future. 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.
Risks Related to Governmental Legislation and Regulation
We and our customers are subject to substantial environmental regulation, and changes in these regulations could increase our and their costs or liabilities and result in decreased demand for our services.
We are subject to stringent and complex federal, state, and local laws and regulations, including laws and regulations regarding the discharge of materials into the environment, emissions controls, and other environmental protection and occupational health and safety concerns, as discussed in detail in Item 1 “Business – Our Operations – Governmental Regulations”. Environmental laws and regulations may, in certain circumstances, impose strict liability for environmental contamination, which may render us liable for remediation costs, natural resource damages, and other damages as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior owners or operators or other third parties. In addition, where contamination may be present, neighboring landowners and other third parties sometimes file claims for personal injury, property damage, and recovery of response costs. Remediation costs and other damages arising as a result of environmental laws and regulations, and costs associated with new information, changes in existing environmental laws and regulations, or the adoption of new environmental laws and regulations could be substantial and could negatively impact our financial condition or results of operations. Moreover, failure to comply with these environmental laws and regulations may result in the imposition of administrative, civil, and criminal penalties and the issuance of injunctions delaying or prohibiting operations.
We conduct operations in a wide variety of locations across the continental U.S. These operations require U.S. federal, state, or local environmental permits or other authorizations. 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. Additionally, the operation of compression units may require individual air permits or general authorizations to operate under various air regulatory programs established by rule or regulation. These permits and authorizations frequently contain numerous compliance requirements, including monitoring and reporting obligations and operational restrictions, such as emissions limits. 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.
Additionally, some states also have passed legislation or regulations regarding hydraulic fracturing. For example, in 2019, Colorado passed Senate Bill 19-181, which delegates authority to local governments to regulate oil and gas activities and requires the Colorado Oil and Gas Conservation Commission to minimize emissions of methane and other air contaminants. Some local communities have adopted additional restrictions for oil and gas activities, such as requiring greater setbacks, and some groups are petitioning local governments to ban hydraulic fracturing. If additional regulatory measures are adopted that ban or restrict production of natural gas through hydraulic fracturing, our customers could experience delays, limitations, or prohibitions on their activities. Such delays, limitations, or prohibitions could result in decreased demand for our services.
In our business, we routinely deal with natural gas, crude oil, and other petroleum products at our worksites. Hydrocarbons or other hazardous substances or wastes may have been disposed or released on, under, or from properties used by us to provide compression services or idle compression unit storage or on or under other locations where such substances or wastes have been taken for disposal. These properties may be subject to investigatory, remediation, and monitoring requirements under federal, state, and local environmental laws and regulations.
The modification or interpretation of existing environmental laws or regulations, the more vigorous enforcement of existing environmental laws or regulations, or the adoption of new environmental laws or regulations also may negatively impact crude oil and natural gas exploration and production, gathering, and pipeline companies, including our customers, which in turn could have a negative impact on us.
New regulations, proposed regulations, and proposed modifications to existing regulations under the Clean Air Act, if implemented, could result in increased compliance costs.
New regulations or proposed modifications to existing regulations under the Clean Air Act (“CAA”), as discussed in detail in Item 1 “Business – Our Operations – Governmental Regulations”, may lead to adverse impacts on our business, financial condition, results of operations, and cash available for distribution. For example, in 2015, the EPA finalized a rule strengthening the primary and secondary National Ambient Air Quality Standards (“NAAQS”) for ground level ozone, both of which are eight-hour concentration standards of 70 parts per billion (the “2015 NAAQS”). In December 2020, the EPA announced its decision to retain, without changes, the 2015 NAAQS. After the EPA revises a NAAQS standard, the states are expected to establish revised attainment/non-attainment regions. State implementation of the 2015 NAAQS could result in stricter permitting requirements, delay, or prohibit our customers’ ability to obtain such permits, and result in increased expenditures for pollution-control equipment, which could negatively impact our customers’ operations, increase the cost of additions to property and equipment, and negatively impact our business.
In 2012, the EPA finalized rules that establish new air emissions controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards (“NSPS”) to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emissions standards to address hazardous air pollutants frequently associated with crude oil and natural gas production and processing activities. The rules established specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks, and other production equipment, as well as the first federal air standards for natural gas wells that are hydraulically fractured. In June 2016, the EPA expanded these regulations when it published additional NSPS, known as Subpart OOOOa, that required certain new, modified, or reconstructed facilities in the oil and gas sector to reduce methane gas and VOC emissions. These Subpart OOOOa standards expanded the 2012 NSPS by mandating certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. 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.
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. 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. 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 November 2024, the EPA issued a final rule to impose and collect the methane emissions charge authorized under the IRA 2022. In addition, federal or state governmental agencies could seek to pursue legislative, regulatory, or executive initiatives that restrict GHG emissions. Other energy legislation and initiatives could include a carbon tax or cap-and-trade program. Independent of the U.S. Congress, and as discussed in detail in Item 1 “Business – Our Operations – Governmental Regulations”, the EPA has taken steps to adopt regulations controlling GHG emissions under its existing CAA authority. Further, although Congress has not passed such legislation, many 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.
Federal and possibly state governments may impose significant restrictions on fossil-fuel exploration, production, and use such as limitations or bans on hydraulic fracturing of oil and gas wells, bans or restrictions on new leases for production of minerals on federal properties, and impose restrictive requirements on new pipeline infrastructure or fossil-fuel export facilities. Litigation risks also are increasing, as a number of cities, local governments, and other plaintiffs have sued companies engaged in the exploration and production of fossil fuels in state and federal courts, alleging various legal theories to recover for the impacts of alleged global warming effects, such as rising sea levels. Many of these suits allege that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. Although a number of these lawsuits have been dismissed, others remain pending and the outcome of these cases remains difficult to predict.
Although it is not currently possible to predict with specificity how the IRA 2022 or any proposed or future GHG legislation, regulation, agreements, or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate, including a carbon tax or cap-and-trade program, could result in increased compliance or operating costs, additional operating restrictions, or reduced demand for our services, and could have a material adverse effect on our business, financial condition, and results of operations.
Climate change may increase the frequency and severity of weather events that could result in severe personal injury, property damage, and environmental damage, which could curtail our or our customers’ operations and otherwise materially adversely affect our cash flows.
Some scientists have concluded that increasing concentrations of GHG in Earth’s atmosphere may produce climate changes that have significant weather-related effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. If any of those effects were to occur, they could have an adverse effect on our assets and operations, including damages to our or our customers’ facilities and assets from powerful wind or rising waters. We may experience increased insurance costs, or difficulty obtaining adequate insurance coverage, for our assets in areas subject to more frequent severe weather. We may not be able to recoup these increased costs through the rates we charge our customers. Extreme weather events could cause damage to property or facilities that could exceed our insurance coverage and our business, financial condition, and results of operations could be adversely affected.
Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for NGLs and natural gas generally is impacted by periods of colder weather and warmer weather, so any changes in climate could affect the market for those fuels, and thus demand for our services. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our services could be affected by increased temperature volatility.
A climate-related decrease in demand for crude oil and natural gas could negatively affect our business.
Supply and demand for crude oil and natural gas is dependent on a variety of factors, many of which are beyond our control. These factors include, among others, the potential adoption of new government regulations, including those related to fuel conservation measures and climate change regulations, technological advances in fuel economy, and energy generation devices. For example, legislative, regulatory, or executive actions intended to reduce emissions of GHGs, such as the IRA 2022, could increase the cost of consuming crude oil and natural gas, or provide incentives to encourage alternative forms of energy, thereby potentially causing a reduction in the demand for crude oil and natural gas. A broader transition to alternative fuels or energy sources, whether resulting from potential new government regulation, carbon taxes, or consumer preferences, could result in decreased demand for crude oil, natural gas, and NGLs. Any decrease in demand for these products could consequently reduce demand for our services and could have a negative effect on our business.
Also, recent activism directed at shifting funding away from companies with energy-related assets could result in a reduction of funding for the energy sector overall, which could have an adverse effect on our ability to obtain external financing as well as negatively affect the cost of, and terms for, financing to fund capital expenditures or other aspects of our business.
Increased attention to ESG matters and conservation measures may adversely impact our business.
Increasing attention to, and societal expectations on companies to address, climate change and other environmental and social impacts, investor and societal expectations regarding voluntary environmental, social, and governance (“ESG”) disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for fossil fuels and consequently demand for our services, reduced profits, increased risk of investigations and litigation, and negative impacts on the value of our assets and access to capital. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for crude oil and natural gas products, and additional governmental investigations and private litigation against us or our customers. To the extent that societal pressures, political, or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.
Such ESG matters also may impact our customers or suppliers, which may adversely impact our business, financial condition, or results of operations.
Increased regulation of hydraulic fracturing could result in reductions of, or delays in, natural gas production by our customers, which could adversely impact our revenue.
A significant portion of our customers’ natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the production process. Hydraulic fracturing involves the injection of water, sand, and chemicals under pressure into the rock formation to stimulate gas production. Several states have adopted, or are considering adopting, regulations that could impose more stringent permitting, public disclosure, or waste restrictions that may restrict or prohibit hydraulic fracturing. In addition, from time to time, there have been various proposals to regulate hydraulic fracturing at the federal level. Any new laws or regulations regarding hydraulic fracturing could negatively impact our customers’ ability to produce natural gas, which could adversely impact our revenue.
State and federal regulatory agencies also have recently focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing also may contribute to seismic activity. When caused by human activity, such events are called induced seismicity. Developing research suggests that the link between seismic activity and wastewater disposal may vary by region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. In March 2016, the U.S. Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In light of these concerns, some state regulatory agencies have modified their regulations or issued orders to address induced seismicity. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigation concerning, oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal, which could indirectly impact our business, financial condition, and results of operations. In addition, these concerns may give rise to private tort suits against our customers from individuals who claim they are adversely impacted by seismic activity they allege was induced. Such claims or actions could result in liability to our customers for property damage, exposure to waste and other hazardous materials, nuisance, or personal injuries, and require our customers to expend additional resources or incur substantial costs or losses. This could in turn adversely affect the demand for our services.
We cannot predict the future of any such legislation or tort liability. If additional levels of regulation, restrictions, and permits were required through the adoption of new laws and regulations at the federal or state level or the development of new interpretations of those requirements by the agencies that issue the required permits, that could lead to operational delays, increased operating costs, and process prohibitions that could reduce demand for our compression services, which would materially adversely affect our revenue and results of operations.
Risks Inherent in an Investment in Us
Holders of our common units have limited voting rights and are not entitled to elect the General Partner or its directors.
Unlike the holders of common stock in a corporation, our common unitholders only have limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Common
unitholders have no right to elect the General Partner or the board of directors of the General Partner (the “Board”). Energy Transfer is the sole member of the General Partner and has the right to appoint the majority of the members of the Board, including all but one of its independent directors. Also, pursuant to that certain Board Representation Agreement entered into by us, the General Partner, Energy Transfer, and EIG Veteran Equity Aggregator, L.P. (along with its affiliated funds, “EIG”) in connection with our private placement of Preferred Units and warrants to EIG, EIG Management Company, LLC has the right to designate one of the members of the Board for so long as the holders of the Preferred Units hold more than 5% of the Partnership’s outstanding common units in the aggregate (taking into account the common units that would be issuable upon conversion of the Preferred Units).
If our common unitholders are dissatisfied with the General Partner’s performance, they have little ability to remove the General Partner. Common unitholders are currently unable to remove the General Partner because the General Partner and its affiliates own a sufficient number of our common units to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove the General Partner, and Energy Transfer currently owns over 33 1/3% of our outstanding common units. As a result of these limitations, the price of our common units may decline because of the absence or reduction of a takeover premium in the trading price.
Furthermore, the Partnership Agreement contains provisions limiting the ability of common unitholders to call meetings or to obtain information about our operations, as well as other provisions limiting our common unitholders’ ability to influence the manner or direction of management.
Energy Transfer owns and controls the General Partner, and the General Partner has sole responsibility for conducting our business and managing our operations. 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.
Energy Transfer owns and controls the General Partner and appoints all of the officers and a majority of the directors of the General Partner, some of whom also are officers and directors of Energy Transfer. Although the General Partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of the General Partner also have a fiduciary duty to manage the General Partner in a manner that is beneficial to its owner. Conflicts of interest will arise between the General Partner and its owner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, the General Partner may favor its own interests and the interests of its owner over our interests and the interests of our unitholders. These conflicts include the following situations, among others:
•neither the Partnership Agreement nor any other agreement requires Energy Transfer to pursue a business strategy that favors us;
•Energy Transfer and its affiliates are not prohibited from engaging in businesses or activities that are in direct competition with us or from offering business opportunities or selling assets to our competitors;
•the General Partner is allowed to take into account the interests of parties other than us, such as its owner, in resolving conflicts of interest;
•the Partnership Agreement limits the liability of and reduces the fiduciary duties owed by the General Partner, and also restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;
•except in limited circumstances, the General Partner has the power and authority to conduct our business without unitholder approval;
•the General Partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership interests, and the creation, reduction, or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;
•the General Partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders;
•the General Partner determines which costs it incurs are reimbursable by us;
•the General Partner may cause us to borrow funds in order to permit the payment of cash distributions;
•the Partnership Agreement permits us to classify up to $36.6 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings, or other sources that otherwise would constitute capital surplus;
•the Partnership Agreement does not restrict the General Partner from causing us to pay it or its affiliates for any services rendered to us, or entering into additional contractual arrangements with any of these entities on our behalf;
•the General Partner currently limits, and intends to continue limiting, its liability for our contractual and other obligations;
•the General Partner may exercise its right to call and purchase all of our common units not owned by it and its affiliates if together those entities at any time own more than 80% of our common units;
•the General Partner controls the enforcement of the obligations that it and its affiliates owe to us; and
•the General Partner decides whether to retain separate counsel, accountants, or others to perform services for us.
The General Partner’s liability for our obligations is limited.
The General Partner has included, and will continue to include, provisions in its and our contractual arrangements that limit its liability under such contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against the General Partner or its assets. The General Partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to it. The Partnership Agreement provides that any action taken by the General Partner to limit its liability is not a breach of the General Partner’s fiduciary duties, even if we could have obtained more favorable terms without such limitation on liability. In addition, we are obligated to reimburse or indemnify the General Partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce our amount of cash otherwise available for distribution.
The Partnership Agreement limits the General Partner’s fiduciary duties to our unitholders.
The Partnership Agreement contains provisions that modify and reduce the fiduciary standards to which the General Partner otherwise would be held by state fiduciary duty law. For example, the Partnership Agreement permits the General Partner to make a number of decisions in its individual capacity, as opposed to its capacity as the General Partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles the General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates, or our limited partners. Examples of decisions that the General Partner may make in its individual capacity include:
•how to allocate business opportunities among us and its affiliates;
•whether to exercise its limited call right;
•how to exercise its voting rights with respect to the common units it owns; and
•whether or not to consent to any merger or consolidation of the Partnership or amendment to the Partnership Agreement.
By purchasing a unit, a unitholder agrees to become bound by the provisions of the Partnership Agreement, including the provisions discussed above.
The Partnership Agreement restricts the remedies available to our unitholders for actions taken by the General Partner that otherwise might constitute breaches of fiduciary duty.
The Partnership Agreement contains provisions that restrict the remedies available to unitholders for actions taken by the General Partner that otherwise might constitute breaches of fiduciary duty under state fiduciary duty law. For example, the Partnership Agreement:
•provides that whenever the General Partner makes a determination or takes, or declines to take, any other action in its capacity as the General Partner, the General Partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by the Partnership Agreement, Delaware law, or any other law, rule, or regulation, or at equity;
•provides that the General Partner will not have any liability to us, or our unitholders, for decisions made in its capacity as general partner so long as such decisions are made in good faith, meaning that it believed that the decisions were in the best interest of the Partnership;
•provides that the General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
•provides that the General Partner will not be in breach of its obligations under the Partnership Agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:
•approved by the conflicts committee of the Board, although the General Partner is not obligated to seek such approval;
•approved by the vote of a majority of our outstanding common units, excluding any common units owned by the General Partner and its affiliates;
•on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
•fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
In a situation involving a transaction with an affiliate or a conflict of interest, any determination by the General Partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the Board determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the last two bullets above, then it will be conclusively deemed that, in making its decision, the Board acted in good faith.
The Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Common unitholders’ voting rights are further restricted by a provision of the Partnership Agreement providing that any units held by a person or group that owns 20% or more of such class of units then outstanding, other than, with respect to our common units, the General Partner, its affiliates, their direct transferees, and their indirect transferees approved by the General Partner (which approval may be granted in its sole discretion) and persons who acquired such common units with the prior approval of the General Partner, cannot vote on any matter.
The general partner interest or the control of the General Partner may be transferred to a third party without unitholder consent.
The General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the common unitholders. Furthermore, the Partnership Agreement does not restrict the ability of Energy Transfer to transfer all or a portion of its ownership interest in the General Partner to a third party. The new owner of the General Partner would then be in a position to replace the majority of the Board, and all of the officers, of the General Partner with its own designees and thereby exert significant control over the decisions made by the Board and the officers of the General Partner.
An increase in interest rates may cause the market price of our common units to decline.
The market price of master limited partnership units, like other yield-oriented securities, may be affected by, among other factors, implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, increases or decreases in interest rates may affect whether or not certain investors decide to invest in master limited partnership units, including ours, and a rising interest rate environment could have an adverse impact on our common unit price and impair our ability to issue additional equity or incur debt to fund growth or for other purposes, including distributions.
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 Partnership Agreement does not limit the number or timing of additional limited partner interests that we may issue, including limited partner interests that are convertible into or senior to our common units, without the approval of our common unitholders as long as the newly issued limited partner interests are not senior to, or pari passu with, the Preferred Units. With the consent of a majority of the Preferred Units, we may issue an unlimited number of limited partner interests that are senior to our common units and pari passu with the Preferred Units.
If a substantial portion of the Preferred Units are converted into common units, common unitholders could experience significant dilution. Furthermore, if holders of such converted Preferred Units were to dispose of a substantial portion of these common units in the public market, whether in a single transaction or series of transactions, it could adversely affect the market price of our common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.
Our issuance of additional common units, including pursuant to our DRIP, or other equity securities of equal or senior rank, such as additional preferred units, will have the following effects:
•our existing common unitholders’ proportionate ownership interest in us will decrease;
•our amount of cash available for distribution to common unitholders may decrease;
•the relative voting strength of each previously outstanding common unit may be diminished; and
•the market price of our common units may decline.
Energy Transfer may sell, and the holders of the Preferred Units have sold and may continue to sell, our common units in the public or private markets, and such sales could have an adverse impact on the trading price of our common units.
As of February 6, 2025, Energy Transfer beneficially owns an aggregate of 46,056,228 common units in us. As of February 6, 2025, the holders of our Preferred Units (the “Preferred Unitholders”) have converted a portion of their Preferred Units into 15,990,804 common units, in accordance with the formula set forth in our Partnership Agreement. Additionally, the warrants held by the Preferred Unitholders have been exercised and net settled in full for 2,894,796 common units. 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. Energy Transfer may, and the Preferred Unitholders have and may continue to, sell our common units. Any sales of these common units in the public or private markets could have an adverse impact on the price of our common units.
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 at any time the General Partner and its affiliates own more than 80% of our outstanding common units, the General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of our common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of the Partnership Agreement. As a result, holders of our common units may be required to sell their common units at an undesirable time or price. These holders also may incur a tax liability on a sale of their common units. As of December 31, 2024, the General Partner and its affiliates (including Energy Transfer), beneficially own an aggregate of approximately 39% of our outstanding common units.
Unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.
Under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our General Partner or to take other action under the Partnership Agreement constituted participation in the “control” of our business. 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.
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. Unitholders could have unlimited liability for obligations of the Partnership if a court or government agency determined that (i) we were conducting business in a state, but had not complied with that particular state’s partnership statute; or (ii) a unitholder’s right to act with other unitholders to remove or replace the General Partner, to approve some amendments to the Partnership Agreement, or to take other actions under the Partnership Agreement constituted “control” of our business.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. The Delaware Act provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their interest in the Partnership and liabilities that are nonrecourse to the Partnership are not counted for purposes of determining whether a distribution is permissible.
Our Partnership Agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers, or other employees.
Our Partnership Agreement provides that, with certain limited exceptions, the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction) shall be the exclusive forum for any claims, suits, actions, or proceedings (i) arising out of, or relating in any way to the Partnership Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the Partnership Agreement), any partnership interest or the duties, obligations, or liabilities among limited partners or of limited partners, or the rights or powers of, or restrictions on, the limited partners or us, (ii) asserting a claim arising out of any other instrument, document, agreement, or certificate contemplated by any provision of the Delaware Act relating to the Partnership or the Partnership Agreement, (iii) asserting a claim against us arising pursuant to any provision of the Delaware Act, or (iv) arising out of the federal securities laws of the U.S. or securities or anti-fraud laws of any governmental authority.
The exclusive forum provision would not apply to suits brought to enforce any liability or duty created by the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act, or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based on federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder.
The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings, and it is possible that a court could find the choice of forum provisions contained in our Partnership Agreement to be inapplicable or unenforceable, including with respect to claims arising under the U.S. federal securities laws. This exclusive forum provision may limit the ability of a limited partner to commence litigation in a forum that the limited partner prefers, or may require a limited partner to incur additional costs in order to commence litigation in Delaware, each of which may discourage such lawsuits against us or our General Partner’s directors or officers. Alternatively, if a court were to find this exclusive forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings described above, we may incur additional costs associated with resolving such matters in other jurisdictions, which could negatively affect our business, results of operations, and financial condition.
The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
Our common units are listed on the NYSE. Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on the Board, or to establish a compensation committee, or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to investors in certain corporations that are subject to all of the NYSE corporate governance requirements. Please read Part III, Item 10 “Directors, Executive Officers, and Corporate Governance”.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the 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 anticipated after-tax economic benefit of an investment in our common units largely depends on us being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS on this or any other tax matter affecting us.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based on our current operations that we are or will be so treated, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, and likely would pay state and local income tax at varying rates. Distributions generally would be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because taxes would be levied on us as a corporation, our cash
available for distribution also would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, and other forms of taxation. For example, we are required to pay the Texas Margin Tax on our gross income apportioned to Texas. Imposition of any similar taxes by any other state may reduce the cash available for distribution substantially, and therefore, negatively impact the value of an investment in our common units.
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.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative, or judicial changes or differing interpretations at any time. Members of the U.S. Congress have proposed and considered substantive changes to the existing federal income tax laws that would affect publicly traded partnerships, including elimination of partnership tax treatment for certain publicly traded partnerships. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.
Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in our common units. Unitholders are urged to consult with their own tax advisor with respect to the status of regulatory or administrative developments and proposals, and their potential effect on their investment in our common units.
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. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from them with respect to that income.
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 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.
We may engage in transactions to de-lever the Partnership and manage our liquidity that may result in income and gain to our unitholders. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale. The ultimate effect of any such allocations will depend on the unitholder’s individual tax position with respect to its units. 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.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained.
It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.
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.
For tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. Our U.S. Federal income tax returns for years 2019 and 2020 are currently under examination by the IRS. To the extent possible under applicable rules, the General Partner may pay such taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, elect to issue Form 8986, effectively taking the place of a revised Schedule K-1, to each unitholder and former unitholder with respect to an audited and adjusted return. No assurances can be made that such election will be practical, permissible, or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units during the tax year under audit. 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.
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. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.
A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income to such unitholder due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital losses only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized on the sale of units.
Unitholders will be subject to limitation on their ability to deduct interest expense incurred by us.
Our ability to deduct interest paid or accrued on indebtedness properly allocable to a trade or business (“business interest”) may be limited in certain circumstances. Generally, our deduction for business interest is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income.
Our “business interest” has been subject to limitation under these rules by $105.5 million and $95.1 million for tax years 2023 and 2022, respectively. As a result, our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us and allocated to them. In certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction subject to this limitation in future taxable years. Unitholders should consult their tax advisors regarding the impact of this business interest deduction limitation on an investment in our units.
Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (“IRAs”) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our common units.
Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.
Non-U.S. unitholders generally are taxed and subject to income tax filing requirements by the U.S. on income effectively connected with a U.S. trade or business (“effectively connected income”). A unitholder’s share of our income, gain, loss, and deduction, and any gain from the sale of our units generally will be considered effectively connected income. As a result,
distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit also will be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit. In addition to the withholding tax imposed on distributions of effectively connected income, distributions to a non-U.S. unitholder also will be subject to a 10% withholding tax on the amount of any distribution in excess of our cumulative net income. 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%.
Moreover, upon the sale, exchange, or other disposition of a unit by a non-U.S. unitholder, the transferee generally is required to withhold 10% of the amount realized on such transfer if any portion of the gain on such transfer would be treated as effectively connected income. Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership generally will be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor. Treasury regulations and recent Treasury guidance further provide that for a transfer of an interest in a publicly traded partnership that is effected through a broker on or after January 1, 2023, the obligation to withhold is imposed on the transferor’s broker. Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our units.
We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of common units, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.
We generally prorate our items of income, gain, loss, and deduction for federal income tax purposes between transferors and transferees of our units each month based on the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss, and deduction among our unitholders.
We generally prorate our items of income, gain, loss, and deduction for federal income tax purposes between transferors and transferees of our units each month based on the ownership of our units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets, and (iii) in the discretion of the General Partner, any other extraordinary item of income, gain, loss, or deduction based on ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.
A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss on the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned common units. In that case, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss on such disposition. Moreover, during the period of the loan, any of our income, gain, loss, or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss, and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss, and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation
matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss, and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain recognized from our unitholders’ sale of common units, have a negative impact on the value of the common units, or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
As a result of investing in our common units, you likely will become subject to state and local taxes and income tax return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to federal income taxes, our unitholders likely will be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with state and local filing requirements.
We currently conduct business and control assets in several states, many of which currently impose a personal income tax on individuals. Many of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states or foreign jurisdictions that impose an income tax. It is our unitholders’ responsibility to file all foreign, federal, state, and local tax returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.
General Risk Factors
If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which likely would have a negative impact on the market price of our common units.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and to operate successfully as a publicly traded partnership. Although we continuously evaluate the effectiveness of, and improve our internal controls, our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”). For example, Section 404 requires us to, among other things, review and report annually on the effectiveness of our internal control over financial reporting. In addition, our independent registered public accountants are required to assess the effectiveness of our internal control over financial reporting.
Any failure to develop, implement, or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our independent registered public accounting firm’s conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and may result in a loss of confidence in our reported financial information, which could have an adverse effect on our business and likely would have a negative effect on the trading price of our common units.
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.
Our operations are subject to inherent risks such as equipment defects, malfunctions, and failures, and natural disasters that can result in uncontrollable flows of gas or well fluids, fires, and explosions. These risks could expose us to substantial liability for personal injury, death, property damage, pollution, and other environmental damages. Our insurance may be inadequate to cover our liabilities. Further, insurance covering the risks we face or in the amounts we desire may not be available in the future or, if available, the premiums may not be commercially justifiable. If we were to incur substantial liability and such damages were not covered by insurance or were in excess of policy limits, or if we were to incur liability at a time when we are not able to obtain liability insurance, our business, results of operations, and financial condition could be adversely affected.
Cybersecurity breaches and other disruptions of our information systems could compromise our information and operations and expose us to liability, which would cause our business and reputation to suffer.
We rely on our information technology infrastructure to process, transmit, and store electronic information critical to our business activities. 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. As a result, the risks associated with such an event continue to increase and we frequently detect, respond to and mitigate security incidents. 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. If any such failure, interruption, or similar event results in improper disclosure of information maintained in our information systems and networks or those of our customers, suppliers, or vendors, including personnel, customer, pricing, and other sensitive information, we also could be subject to liability under relevant contractual obligations and laws and regulations protecting personal data and privacy. 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.
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. Uncertainty surrounding sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil and natural gas supplies and markets for crude oil, natural gas, and NGLs, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make insurance against such attacks more difficult for us to obtain, if we choose to do so. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets resulting from terrorism or war also could negatively affect our ability to raise capital.
ITEM 1B. Unresolved Staff Comments
None.
ITEM 1C. Cybersecurity
Description of Processes for Assessing, Identifying and Managing Cybersecurity Risks
The information and operational technology infrastructure we use is important to the operation of our business and to our ability to perform day-to-day operations. In the normal course of business, we may collect and store certain sensitive information of the Partnership, including proprietary and confidential business information, trade secrets, intellectual property, sensitive third-party and employee information, and certain personally identifiable information.
As part of the shared services integration with Energy Transfer, we are transitioning to a shared services cybersecurity program for assessing, identifying and managing material risks from cybersecurity threats. As we are in the midst of that transition, currently certain of our information systems are operating under the shared services cybersecurity program, while certain other information systems remain under our internal USAC cybersecurity program. We expect that once the shared services implementation is complete, all of our information systems will operate under the shared services cybersecurity program.
The shared services cybersecurity program is managed by a team of full-time Energy Transfer employees, overseen by its Chief Information Officer, that are tasked with conducting day-to-day information technology (“IT”) operations (collectively, the “Energy Transfer IT team”). This program includes processes that are modeled after the National Institute of Standards and Technology’s Cybersecurity Framework and focuses on using business drivers to guide cybersecurity activities. In creating and implementing this cybersecurity program, the Energy Transfer IT team engages with the guidance of the Federal Bureau of Investigation (FBI), Cybersecurity and Infrastructure Security Agency (CISA), Transportation Security Administration (TSA) and the U.S. Coast Guard (USCG). The shared services cybersecurity program seeks to use a defense-in-depth approach for cybersecurity management, layers of technology, policies and training at all levels of the enterprise designed to keep our assets secure and operational. It uses various processes as part of its efforts to maintain the confidentiality, integrity and availability of our systems, including security threat intelligence, incident response, identity and access management, supply-chain security assessments, endpoint extended detection and response protection, network segmentation, data encryption, event monitoring and a Security Operations Center (SOC).
Our internal cybersecurity program is led by USAC’s IT department. USAC’s internal cybersecurity program is designed to align with the National Institute of Standards and Technology’s Cybersecurity Framework. USAC’s IT department stays informed of current developments in cybersecurity threats, including incidents or issues that may arise involving our third-party
service providers, and preventative measures and continuously updates our cybersecurity program based on this knowledge. It utilizes industry-leading security tools and regularly performs security risk assessments and tool reviews with independent third parties to evaluate program effectiveness, and regularly updates our security roadmap. USAC’s IT department monitors industry news and updates to stay aware of the cybersecurity landscape, including incidents or issues that may arise involving USAC’s third-party service providers.
In an effort to validate the effectiveness of our cybersecurity programs and assess such program’s compliance with legal and regulatory requirements, we engage third-party service providers to perform audits, assessments, and penetration tests. These partnerships enable us to access specialized knowledge and insights which we leverage to continuously improve and modernize our cybersecurity programs. We have integrated cybersecurity risk management into our overall risk management system, ensuring that cybersecurity risks are taken into consideration when managing business objectives and operational needs.
Cybersecurity awareness among our employees is promoted with regular training and awareness programs. All employees who have access to our systems are required to undergo cybersecurity training at least annually and, under the shared services cybersecurity program, our employees will be required to review and acknowledge our cybersecurity policies each year. User access controls have been implemented to limit unauthorized access to sensitive information and critical systems. Employees are required to use multifactor authentication and keep their passwords confidential, among other measures.
We recognize that third-party service providers may introduce cybersecurity risks. In an effort to mitigate these risks, before contracting with certain technology services providers, when possible, we conduct due diligence to evaluate their cybersecurity capabilities. Additionally, we endeavor to require these providers to adhere to our security standards and protocols.
Impact of Risks from Cybersecurity Threats
As of the date of this Annual Report on Form 10-K, though the Partnership and our service providers have experienced certain cybersecurity incidents, we are not aware of any previous cybersecurity threats that have materially affected, or are reasonably likely to materially affect, the Partnership, either financially or operationally. Cybersecurity incident response is a component of both the Partnership’s cybersecurity program and the Partnership’s business continuity plans, which are designed to limit service interruptions and provide for continued business operation in the event of disaster, whether physical, environmental or cyber in nature. However, we recognize that cybersecurity threats are continually evolving, and there remains a risk that a cybersecurity incident could potentially negatively impact the Partnership. Despite the implementation of our cybersecurity processes, we cannot guarantee that a significant cybersecurity attack will not occur. A successful attack on our information system or operational technology system could have significant consequences to the business, including the interruption of key services that our customers depend on. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. For additional information on cybersecurity risks, see Part I, Item 1A “Risk Factors – General Risk Factors –Cybersecurity breaches and other disruptions of our information systems could compromise our information and operations and expose us to liability, which would cause our business and reputation to suffer.”
Board of Directors’ Oversight and Management’s Role
Under the shared services cybersecurity program, Energy Transfer’s Chief Information Officer oversees the functions of IT, cybersecurity, infrastructure and IT governance (including the Energy Transfer IT team) and has more than 35 years of experience leading business technology functions. The members of the Energy Transfer IT team have over 50 years of combined experience in the field of IT, including 20 years dedicated to cybersecurity, and hold various certifications, including Global Industrial Cyber Security Professional (GICSP), Certified Information Systems Security Professional (CISSP) and Certified Ethical Hacker (CEH) certifications. Our internal cybersecurity program is led by USAC’s IT department. The members of our IT leadership team have an average of over 25 years of experience in IT operations and over 10 years of experience in IT security, including cybersecurity risk identification and mitigation.
Our cyber incident response plan requires IT team members who detect suspicious activity in our IT environment to escalate that activity to a supervisor who then evaluates the threat. If necessary, the suspicious activity is reported to Energy Transfer’s Chief Information Officer, if applicable. Management (including representatives from the legal, human resources and IT departments) is notified by the IT team whenever a discovered cybersecurity incident may potentially have a significant impact on us or our customers.
Our Audit Committee is ultimately responsible for assessing and managing the Partnership’s material risks from cybersecurity threats. Our IT leadership provides periodic cybersecurity program updates to senior management and to the
Audit Committee. Management also updates the Audit Committee as new risks are identified and the steps taken to mitigate such risks.
ITEM 2. Properties
We do not currently own or lease any material facilities or properties for storage or maintenance of our compression units. As of December 31, 2024, our headquarters consisted of leased office space located at 8117 Preston Road, Dallas, Texas 75225.
ITEM 3. Legal Proceedings
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.
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.
PART II
ITEM 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our Partnership Interests
As of February 6, 2025, we had 117,528,971 common units outstanding. Energy Transfer owns 100% of the membership interests in the General Partner and, as of February 6, 2025, beneficially owns approximately 39% of our outstanding common units.
As of February 6, 2025, we had 180,000 Preferred Units outstanding representing limited partner interests in the Partnership, all of which were held by EIG Veteran Equity Aggregator LP and FSSL Finance BB AssetCo LLC (collectively, the “Preferred Unitholders”). The Preferred Units rank senior to our common units with respect to distributions and liquidation rights. The holders of the Preferred Units are entitled to receive cumulative quarterly cash distributions equal to $24.375 per Preferred Unit.
The Preferred Units are convertible, at the option of the holder, into common units in accordance with the terms of our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”). We have the option to redeem all or any portion of the Preferred Units outstanding, subject to certain minimum redemption threshold amounts, for a redemption price set forth in the Partnership Agreement. On or after April 2, 2028, each holder of the Preferred Units will have the right to require us to redeem all or a portion of their Preferred Units, subject to certain minimum redemption threshold amounts, for a redemption price set forth in the Partnership Agreement, which we may elect to pay up to 50% in common units, subject to certain additional limits.
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. Please read Part II, Item 8 “Financial Statements and Supplementary Data – Note 11 – Preferred Units and – Note 12 – Partners’ Deficit”.
Holders
At the close of business on February 6, 2025, based on information received from the transfer agent of the common units, we had 67 holders of record of our common units. 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.
Available Cash
The Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date, first to the holders of the Preferred Units and then to the common unitholders. The Partnership Agreement generally defines available cash, for each quarter, as cash on hand at the end of a quarter plus cash on hand resulting from working capital borrowings made after the end of the quarter less the amount of reserves established by the General Partner to provide for the proper conduct of our business, comply with applicable law, the Credit Agreement or other agreements; and provide funds for distributions to our unitholders for any one or more of the next four quarters. Working capital borrowings are borrowings made under a credit facility, commercial paper facility, or other similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners, and with the intent of the borrower to repay such borrowings within twelve months from sources other than working capital borrowings.
Issuer Purchases of Equity Securities
None.
Sales of Unregistered Securities; Use of Proceeds from Sale of Securities
None.
Equity Compensation Plan
For disclosures regarding securities authorized for issuance under equity compensation plans, see Part III, Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters”.
ITEM 6. [RESERVED]
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements, the notes thereto, and the other financial information appearing elsewhere in this report. The following discussion includes forward-looking statements that involve certain risks and uncertainties. See Part I “Disclosure Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors”.
Discussion and analysis of our operating highlights and financial results of operations for the year ended December 31, 2023, compared to the year ended December 31, 2022, is included under the headings in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Highlights, Financial Results of Operations, Liquidity and Capital Resources, and Critical Accounting Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 13, 2024.
Overview
We have focused our compression services in unconventional resource plays throughout the U.S., including the Utica, Marcellus, Permian, Denver-Julesburg, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, and Haynesville. According to studies promulgated by the EIA, the production and transportation volumes in these unconventional plays, namely tight oil and gas shale plays, are expected to collectively increase over the long term. Furthermore, changes in production volumes and pressures of shale plays over time require a wider range of compression service levels than in conventional basins. We believe we are well-positioned to meet these changing operating conditions due to the operational design flexibility inherit within our compression-unit fleets.
Our business includes compression services serving infrastructure applications, including centralized natural gas gathering systems and processing facilities, which utilize large-horsepower compression units and also gas lift applications on crude oil wells targeted by horizontal drilling techniques. Gas lift is a process by which natural gas is injected into the production tubing of an existing producing well to reduce hydrostatic pressure and allow the oil to flow at a higher rate. This process, and other artificial-lift technologies are critical to the enhancement of oil production from horizontal wells operating in tight shale plays.
General Trends and Outlook
A significant portion of our assets are utilized in natural gas infrastructure applications typically located in U.S. onshore shale plays, primarily at centralized gathering systems and processing facilities utilizing large-horsepower compression units. Given the infrastructure nature of these applications, the continued need for additional natural gas compression throughout the production cycle, and the long-term investment horizon of our customers, we generally have experienced stability in service rates and higher sustained fleet utilization rates relative to other businesses more directly tied to drilling activity and wellhead-specific economics. In addition to our natural gas infrastructure applications, a portion of our small- and large-horsepower fleet is used in connection with gas-lift applications for crude oil production targeted by horizontal drilling techniques.
We deliver natural gas compression services in connection with domestic natural gas production that primarily occurs in natural gas basins, such as the Marcellus, Utica, and Haynesville Shales, and in crude oil basins where “associated” natural gas is produced alongside crude oil, such as in the Permian and Denver-Julesburg Basins, Eagle Ford, and the Mid-Continent. Relative stability in commodity prices over much of the past decade encouraged investment in domestic exploration and production and midstream infrastructure across the energy industry, particularly in low-cost U.S. onshore shale basins that feature crude oil and associated gas production. The development of these basins has created additional incremental demand for natural gas compression as it is a critical method to transport associated gas volumes or enhance crude oil production through gas lift.
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. With average natural gas prices down year-over-year and average oil prices relatively flat, we experienced improvements to pricing and fleet utilization for our compression services in 2024, largely tied to associated gas growth from oil plays.
Looking ahead, global consumption of petroleum and liquids fuels according to the EIA’s January 2025 Short Term Energy Outlook (“EIA Outlook”) increased in 2024 and is expected to increase over 1.3 million barrels per day (“bpd”) in 2025 and 1.1 million bpd in 2026. The EIA Outlook estimates that annual U.S. crude oil production set a record of 13.2 million bpd in 2024, due to production growth in the Permian. In 2025 and 2026, the EIA Outlook expects U.S. crude oil production growth to continue, albeit at a lower crude oil price, estimating average production of 13.5 million bpd for 2025 and 13.6 million bpd in 2026, which would represent new records for annual average crude oil production. The U.S. crude oil production growth in 2025 and 2026 is expected to come almost entirely from the Permian, which is expected to account for over half of U.S. crude oil production by 2026. We expect that anticipated crude oil production increases likewise will increase associated natural gas production volumes throughout 2025, thereby increasing demand for our compression services.
Unlike crude oil, natural gas production and prices have been influenced by different factors, including the nonexistence of an OPEC+ equivalent for the global natural gas market, which makes natural gas price discovery dependent on market supply and demand dynamics rather than by a centralized market coordinator. Over the past several years, increased natural gas production in the U.S., driven by large volumes of associated gas produced from shale sources, has been a major driver of an overall decline in natural gas prices. The EIA Outlook expects dry natural gas production to increase by 1.4 billion cubic feet per day (“bcf/d”) in 2025 and by 2.7 bcf/d in 2026, resulting in record dry natural gas production each year.
Significant demand for natural gas is driven by domestic power generation which has benefited from a lower-price environment. These low prices, combined with a general shift away from coal-fired power plants due to emissions concerns, has resulted in power generation becoming, and remaining, the largest use of natural gas in the U.S., and has created a relatively resilient baseload demand for natural gas. Growth in power demands from the development of artificial intelligence is also expected to increase demand. Finally, the demand for domestic natural gas also continues to benefit from the construction of LNG export infrastructure, which enables industry participants to benefit from attractive global natural gas prices. According to the EIA Outlook, the U.S. witnessed record LNG exports of 12.0 bcf/d during 2024 and expects LNG exports to set new records of 14.1 bcf/d and 16.2 bcf/d in 2025 and 2026, respectively, as new LNG export capacity continues to ramp up creating incremental baseload global demand.
Overall, the EIA Outlook expects U.S. natural gas demand to outpace production and to increase by 3.2 bcf/d in 2025, primarily reflecting increased exports, both by LNG and pipeline, and stable baseload demand. Further, the EIA Outlook expects U.S natural gas demand to increase another 2.6 bcf/d in 2026, again driven primarily by LNG and pipeline exports, and stable baseload. Natural gas prices averaged $2.20 per million British thermal units (“MMBtu”) in 2024 and the EIA Outlook expects natural gas prices to increase on average to $3.10/MMBtu and $4.00/MMBtu in 2025 and 2026, respectively, driven by the expectation that domestic natural gas inventories remain at or below previous five-year averages. We expect the baseload natural gas demand and increase in LNG and pipeline exports described above, along with growth in data center demand tied to the development of artificial intelligence which we believe is not fully considered in the EIA Outlook’s numbers, to continue to support long-term domestic natural gas production.
The longer-term outlook for commodity prices remains constructive and we are increasing our new, large-horsepower compression unit order in 2025 to meet our customer needs. We expect total capital to be between $158.0 million and $182.0 million in 2025 and are beginning to evaluate new, large-horsepower compression unit orders for 2026. As we look forward over the next year, active geopolitical situations like those in the Middle East and Ukraine, global trade policies, inflationary pressures and slowing global GDP growth, might temper our longer-term outlook.
Ultimately, the extent to which our business will be impacted by the factors described above, as well as future developments beyond our control, cannot be predicted with reasonable certainty. However, we continue to believe that overall, the long-term demand for our compression services will continue given the necessity of compression in facilitating the transportation and processing of natural gas as well as the production of crude oil.
Operating Highlights
The following table summarizes certain horsepower and horsepower-utilization percentages for the periods presented and excludes certain gas-treating assets for which horsepower is not a relevant metric.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | |
| 2024 | | 2023 | | Increase |
| Fleet horsepower (at period end) (1) | 3,862,102 | | | 3,775,660 | | | 2.3 | % |
| Total available horsepower (at period end) (2) | 3,862,942 | | | 3,831,444 | | | 0.8 | % |
| Revenue-generating horsepower (at period end) (3) | 3,567,842 | | | 3,433,775 | | | 3.9 | % |
| Average revenue-generating horsepower (4) | 3,528,172 | | | 3,328,999 | | | 6.0 | % |
| Average revenue per revenue-generating horsepower per month (5) | $ | 20.43 | | | $ | 18.86 | | | 8.3 | % |
| Revenue-generating compression units (at period end) | 4,269 | | | 4,237 | | | 0.8 | % |
| Average horsepower per revenue-generating compression unit (6) | 829 | | | 792 | | | 4.7 | % |
| Horsepower utilization (7): | | | | | |
| At period end | 94.6 | % | | 94.3 | % | | 0.3 | % |
| Average for the period (8) | 94.6 | % | | 93.4 | % | | 1.2 | % |
________________________(1)Fleet horsepower is horsepower for compression units that have been delivered to us and excludes 20,310 and 21,690 of non-marketable horsepower as of December 31, 2024, and 2023, respectively. As of December 31, 2024, we had no horsepower on order. Subsequent to December 31, 2024, the Partnership ordered 10,000 large horsepower for expected delivery during 2025.
(2)Total available horsepower is revenue-generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract but not yet generating revenue and that is expected to be delivered, and idle horsepower. Total available horsepower excludes new horsepower expected to be delivered for which we do not have an executed compression services contract.
(3)Revenue-generating horsepower is horsepower under contract for which we are billing a customer.
(4)Calculated as the average of the month-end revenue-generating horsepower for each of the months in the period.
(5)Calculated as the average of the result of dividing the contractual monthly rate, excluding standby or other temporary rates, for all units at the end of each month in the period by the sum of the revenue-generating horsepower at the end of each month in the period.
(6)Calculated as the average of the month-end revenue-generating horsepower per revenue-generating compression unit for each of the months in the period.
(7)Horsepower utilization is calculated as (i) the sum of (a) revenue-generating horsepower, (b) horsepower in our fleet that is under contract, but is not yet generating revenue, and (c) horsepower not yet in our fleet that is under contract but not yet generating revenue and that is expected to be delivered, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue-generating horsepower and fleet horsepower was 92.4% and 90.9% as of December 31, 2024, and 2023, respectively.
(8)Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period. Average horsepower utilization based on revenue-generating horsepower and fleet horsepower was 91.7% and 89.2% for the years ended December 31, 2024, and 2023, respectively.
The 2.3% increase in fleet horsepower as of December 31, 2024, compared to December 31, 2023, primarily was driven by new compression units added to our fleet to meet incremental demand from customers for our compression services.
The increases in revenue-generating horsepower, average horsepower per revenue-generating compression unit, horsepower utilization, and horsepower utilization based on revenue-generating horsepower and fleet horsepower as of and for the year ended December 31, 2024, compared to December 31, 2023, primarily were driven by the addition and deployment of new, and redeployment of existing, large-horsepower compression units due to increased demand for our services consistent with an overall increase in crude oil and natural gas produced within the U.S.
The 8.3% increase in average revenue per revenue-generating horsepower per month for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit.
Financial Results of Operations
Year ended December 31, 2024, compared to the year ended December 31, 2023
The following table summarizes our results of operations for the periods presented (dollars in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Increase |
| 2024 | | 2023 | | (Decrease) |
| Revenues: | | | | | |
| Contract operations | $ | 885,250 | | | $ | 802,562 | | | 10.3 | % |
| Parts and service | 23,897 | | | 21,890 | | | 9.2 | % |
| Related party | 41,302 | | | 21,726 | | | 90.1 | % |
| Total revenues | 950,449 | | | 846,178 | | | 12.3 | % |
| Costs and expenses: | | | | | |
| Cost of operations, exclusive of depreciation and amortization | 312,726 | | | 284,708 | | | 9.8 | % |
| Depreciation and amortization | 264,756 | | | 246,096 | | | 7.6 | % |
| Selling, general, and administrative | 72,666 | | | 72,714 | | | (0.1) | % |
| Loss (gain) on disposition of assets | 4,939 | | | (1,667) | | | * |
| Impairment of assets | 913 | | | 12,346 | | | * |
| Total costs and expenses | 656,000 | | | 614,197 | | | 6.8 | % |
| Operating income | 294,449 | | | 231,981 | | | 26.9 | % |
| Other income (expense): | | | | | |
| Interest expense, net | (193,471) | | | (169,924) | | | 13.9 | % |
| Loss on extinguishment of debt | (4,966) | | | — | | | * |
| Gain on derivative instrument | 5,684 | | | 7,449 | | | (23.7) | % |
| Other | 110 | | | 127 | | | (13.4) | % |
| Total other expense | (192,643) | | | (162,348) | | | 18.7 | % |
| Net income before income tax expense | 101,806 | | | 69,633 | | | 46.2 | % |
| Income tax expense | 2,231 | | | 1,365 | | | 63.4 | % |
| Net income | $ | 99,575 | | | $ | 68,268 | | | 45.9 | % |
________________________*Not meaningful.
Contract operations revenue. The $82.7 million increase in contract operations revenue for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) an 8.3% increase in average revenue per revenue-generating horsepower per month, as a result of higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit, (ii) a 6.0% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with an overall increase in crude oil and natural gas produced within the U.S., partially offset by (iii) an $8.9 million decrease in revenue attributable to natural gas treating services.
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. The $2.0 million increase in parts and service revenue for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to an increase in maintenance work performed on units at customer locations that are outside the scope of our core maintenance activities and that are offered as a convenience, and in directly reimbursable freight and crane charges that are the financial responsibility of the customers. Demand for retail parts and services fluctuates from period to period based on varying customer needs.
Related-party revenue. Related-party revenue was earned through related-party transactions that occur in the ordinary course of business with various affiliated entities of Energy Transfer. The $19.6 million increase in related-party revenue for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to revenue recognized from
existing customers acquired by Energy Transfer since the previous period that are now classified as related-party revenue in the current period.
Cost of operations, exclusive of depreciation and amortization. The $28.0 million increase in cost of operations for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $17.2 million increase in direct labor costs due to increased headcount associated with increased revenue-generating horsepower and higher employee costs, (ii) a $12.3 million increase in direct expenses, primarily driven by increased spending on parts resulting from higher costs and increased usage associated with increased revenue-generating horsepower, (iii) a $2.2 million increase in other indirect expenses due to increased usage associated with increased revenue-generating horsepower, and (iv) a $1.4 million increase in retail parts and service expenses, for which a corresponding increase in parts and service revenue also occurred, partially offset by (v) a $3.6 million decrease in outside maintenance costs due to reduced use of third-party labor during the current period and (vi) a $1.4 million decrease in non-income taxes.
Depreciation and amortization expense. The $18.7 million increase in depreciation and amortization expense for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) overhauls and major improvements to compression units and (ii) new trucks added to our vehicle fleet.
Selling, general, and administrative expense. The change in selling, general, and administrative expense for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $5.6 million decrease in unit-based compensation expense, primarily attributable to mark-to-market changes to our unit-based compensation liability that occurred as a result of changes to our per-unit trading price as of December 31, 2024, partially offset by (ii) a $3.2 million increase to professional fees primarily related to an initiative to improve business performance, (iii) a $1.3 million increase in severance charges related to the departure of executives during the current period, and (iv) a $0.6 million increase in employee-related expenses driven by increased headcount.
Loss (gain) on disposition of assets. The $4.9 million loss on disposition of assets for the year ended December 31, 2024, and the $1.7 million gain on disposition of assets for the year ended December 31, 2023, were related to various asset transactions.
Impairment of assets. The $0.9 million and $12.3 million impairments of assets during the years ended December 31, 2024 and 2023, respectively, primarily resulted from our evaluation of the future deployment of our idle fleet assets under then-current market conditions. 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.
As a result of our evaluations during the years ended December 31, 2024 and 2023, we retired 2 and 42 compression units, respectively, with approximately 1,260 and 37,700 aggregate horsepower, respectively, that previously were used to provide compression services in our business.
Additionally, for the year ended December 31, 2024, we recognized a $0.6 million impairment of assets related to capitalized software costs that are no longer expected to provide benefit.
Interest expense, net. The $23.5 million increase in interest expense, net for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to increased aggregate borrowings and higher aggregate weighted-average interest rates under the Credit Agreement and refinanced senior notes.
Loss on extinguishment of debt. The $5.0 million loss on extinguishment of debt for the year ended December 31, 2024 resulted from the satisfaction and discharge of the Senior Notes 2026, which constituted a legal defeasance under GAAP (the “Defeasance”). This loss consists of the write-off of deferred financing costs of $4.3 million and the difference between (i) the purchase price of U.S. government securities of $748.8 million, which were used for the Defeasance, and (ii) the aggregate outstanding principal balance and accrued interest of the Senior Notes 2026 of $748.1 million at the time of Defeasance. For additional information regarding the Defeasance of the Senior Notes 2026, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
Gain on derivative instrument. The $5.7 million and $7.4 million gains on derivative instrument for the years ended December 31, 2024 and 2023, respectively, resulted from the change in fair value of the interest-rate swap due to changes in the interest-rate forward curve and cash received during the respective periods.
Income tax expense. The $0.9 million increase in income tax expense for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was related to deferred income taxes associated with the Texas Margin Tax.
Other Financial Data
The following table summarizes other financial data for the periods presented (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Increase |
| Other Financial Data: (1) | | 2024 | | 2023 | | (Decrease) |
| Gross margin | | $ | 372,967 | | | $ | 315,374 | | | 18.3 | % |
| Adjusted gross margin | | $ | 637,723 | | | $ | 561,470 | | | 13.6 | % |
| Adjusted gross margin percentage (2) | | 67.1 | % | | 66.4 | % | | 0.7 | % |
| Adjusted EBITDA | | $ | 584,282 | | | $ | 511,939 | | | 14.1 | % |
| Adjusted EBITDA percentage (2) | | 61.5 | % | | 60.5 | % | | 1.0 | % |
| DCF | | $ | 355,317 | | | $ | 281,113 | | | 26.4 | % |
| DCF Coverage Ratio | | 1.44 | x | | 1.35 | x | | 6.7 | % |
________________________(1)Adjusted gross margin, Adjusted EBITDA, Distributable Cash Flow (“DCF”), and DCF Coverage Ratio are all non-GAAP financial measures. Definitions of each measure, as well as reconciliations of each measure to its most directly comparable financial measure(s) calculated and presented in accordance with GAAP, can be found below under the caption “Non-GAAP Financial Measures”.
(2)Adjusted gross margin percentage and Adjusted EBITDA percentage are calculated as a percentage of revenue.
Gross margin. The $57.6 million increase in gross margin for the year ended December 31, 2024, compared to the year ended December 31, 2023, was due to (i) a $104.3 million increase in revenues, offset by (ii) a $28.0 million increase in cost of operations, exclusive of depreciation and amortization, and (iii) an $18.7 million increase in depreciation and amortization.
Adjusted gross margin. The $76.3 million increase in Adjusted gross margin for the year ended December 31, 2024, compared to the year ended December 31, 2023, was due to a $104.3 million increase in revenues, offset by a $28.0 million increase in cost of operations, exclusive of depreciation and amortization.
Adjusted EBITDA. The $72.3 million increase in Adjusted EBITDA for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to a $76.3 million increase in Adjusted gross margin, partially offset by a $4.2 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses.
DCF. The $74.2 million increase in DCF for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $76.3 million increase in Adjusted gross margin, (ii) a $30.2 million decrease in distributions on Preferred Units following the conversion of 320,000 Preferred Units into 15,990,804 common units, and (iii) a $0.6 million increase in cash received on derivative instrument, partially offset by (iv) a $22.1 million increase in cash interest expense, net, (v) a $6.7 million increase in maintenance capital expenditures, and (vi) a $4.2 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses.
For additional information regarding the conversion of the Preferred Units, see Note 11 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
DCF Coverage Ratio. The increase in DCF Coverage Ratio for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to the increase in DCF, partially offset by an increase in distributions from an increase in the number of common units, largely attributable to the conversion of 320,000 Preferred Units into 15,990,804 common units during 2024 and the exercise of warrants for 2,360,488 common units in November 2023.
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. Our principal sources of liquidity include cash generated by operating activities, borrowings under the Credit Agreement, and issuances of debt and equity securities, including common units under the DRIP.
We believe cash generated by operating activities and, where necessary, borrowings under the Credit Agreement will be sufficient to service our debt, fund working capital, fund our estimated expansion capital expenditures, fund our maintenance capital expenditures, and pay distributions to our unitholders through 2025.
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 are not aware of any regulatory changes or environmental liabilities that we currently expect to have a material impact on our current or future operations. Please see “Capital Expenditures” below.
Capital Expenditures
The compression services business is capital intensive, requiring significant investment to maintain, expand, and upgrade existing operations. Our capital requirements primarily have consisted of, and we anticipate that our capital requirements will continue primarily to consist of, the following:
•maintenance capital expenditures, which are capital expenditures made to maintain the operating capacity of our assets and extend their useful lives, to replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining our existing business and related operating income; and
•expansion capital expenditures, which are capital expenditures made to expand the operating capacity or operating-income capacity of assets, including by acquisition of compression units or through modification of existing compression units to increase their capacity, or to replace certain partially or fully depreciated assets that at the time of replacement were not generating operating income.
We classify capital expenditures as maintenance or expansion on an individual-asset basis. Over the long term, we expect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleet increases. Our aggregate maintenance capital expenditures for the years ended December 31, 2024 and 2023, were $31.9 million and $25.2 million, respectively. We currently have budgeted between $38.0 million and $42.0 million in maintenance capital expenditures during 2025, including parts consumed from inventory.
Without giving effect to any equipment that we may acquire pursuant to any future acquisitions, we currently have budgeted between $120.0 million and $140.0 million in expansion capital expenditures for 2025. Our expansion capital expenditures for the years ended December 31, 2024 and 2023, were $243.5 million and $275.4 million, respectively.
As of December 31, 2024, we did not have any binding commitments to purchase additional compression units and serialized parts. Subsequent to December 31, 2024, we ordered 10,000 horsepower for expected delivery during 2025 which will cost $10.8 million, which is expected to be settled within the next twelve months.
Other Commitments
As of December 31, 2024, other commitments include operating and finance lease payments totaling $19.3 million, of which we expect to make payments of $5.2 million to be settled in the next twelve months. 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”.
Cash Flows
The following table summarizes our sources and uses of cash for the years ended December 31, 2024 and 2023, (in thousands):
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | |
| Net cash provided by operating activities | $ | 341,334 | | | $ | 271,885 | | | |
| Net cash used in investing activities | (202,014) | | | (232,653) | | | |
| Net cash used in financing activities | (139,317) | | | (39,256) | | | |
Net cash provided by operating activities. The $69.4 million increase in net cash provided by operating activities for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) an increase in cash inflows from a $76.3 million increase in Adjusted gross margin and (ii) a $9.3 million decrease in cash paid for interest
expense, net of capitalized amounts, driven by the Defeasance of the Senior Notes 2026, partially offset by (iii) a $25.1 million increase in inventory purchases.
Net cash used in investing activities. The $30.6 million decrease in net cash used in investing activities for the year ended December 31, 2024, compared to the year ended December 31, 2023, was due to (i) a $33.7 million decrease in capital expenditures, for purchases of new compression units, overhauls and major improvements, and purchases of other equipment, and (ii) a $1.0 million increase in proceeds from insurance recovery, partially offset by (iii) a $4.0 million decrease in proceeds from disposition of property and equipment.
Net cash used in financing activities. The $100.1 million increase in net cash used in financing activities for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $748.8 million increase in investments in government securities purchased in connection with the Defeasance of the Senior Notes 2026, (ii) a $325.6 million decrease in net borrowings under the Credit Agreement, (iii) an $18.2 million increase in deferred financing costs driven by the issuance of the Senior Notes 2029, and (iv) a $31.8 million increase in common unit distributions, partially offset by (v) a 1.0 billion increase in proceeds from issuance of the Senior Notes 2029, (vi) a $24.4 million decrease in Preferred Unit distributions, and (vii) a $1.1 million decrease in cash paid related to net settlement of unit-based awards.
Revolving Credit Facility
As of December 31, 2024, we had outstanding borrowings under the Credit Agreement of $772.1 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $827.1 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $782.5 million was available to be drawn. As of December 31, 2024, we were in compliance with all of our covenants under the Credit Agreement.
As of February 6, 2025, we had outstanding borrowings under the Credit Agreement of $801.5 million and outstanding letters of credit of $0.8 million.
The Credit Agreement matures on December 8, 2026.
The Credit Agreement provides for an asset-based revolving credit facility to be made available to the Partnership in an aggregate amount of $1.6 billion. The Partnership’s obligations under the Credit Agreement are guaranteed by the guarantors party to the Credit Agreement, which currently consists of all of the Partnership’s subsidiaries. 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).
Borrowings under the Credit Agreement bear interest at a per-annum interest rate equal to, at the Partnership’s option, either the Alternate Base Rate or SOFR plus the applicable margin. “Alternate Base Rate” means the greatest of (i) the prime rate, (ii) the applicable federal funds effective rate plus 0.50%, and (iii) one-month SOFR rate plus 1.00%. The applicable margin for borrowings varies (a) in the case of SOFR loans, from 2.00% to 2.75% per annum, and (b) in the case of Alternate Base Rate loans, from 1.00% to 1.75% per annum, and are determined based on a total-leverage-ratio pricing grid. In addition, the Borrower is required to pay commitment fees based on the daily unused amount of the Credit Agreement in an amount equal to 0.375% per annum. Amounts borrowed and repaid under the Credit Agreement may be re-borrowed, subject to borrowing base availability.
The Credit Agreement contains various covenants with which the Partnership and its restricted subsidiaries must comply, including, but not limited to, limitations on the incurrence of indebtedness, investments, liens on assets, repurchasing equity and making distributions, transactions with affiliates, mergers, consolidations, dispositions of assets, and other provisions customary in similar types of agreements. 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 Credit Agreement also contains various customary representations and warranties, affirmative covenants, and events of default.
We expect to remain in compliance with our covenants under the Credit Agreement throughout 2025. If our current cash flow projections prove to be inaccurate, we expect to be able to remain in compliance with such financial covenants by taking one or more of the following actions: issue equity in a public or private offering; request a modification of our covenants from
our bank group; reduce distributions from our current distribution rate or suspend distributions altogether; delay discretionary capital spending and reduce operating expenses; or obtain an equity infusion pursuant to the terms of the Credit Agreement.
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”.
Senior Notes
As of December 31, 2024, we had $750.0 million and $1.0 billion aggregate principal amount outstanding on our Senior Notes 2027 and Senior Notes 2029, respectively.
On March 5, 2024, we provided notice to the holders of our Senior Notes 2026 that, contingent on receipt of the proceeds from the Senior Notes 2029, the Senior Notes 2026 would be redeemed at par on April 4, 2024. On March 18, 2024, utilizing a portion of the proceeds from the Senior Notes 2029, we deposited government securities with the trustee to satisfy and discharge the Senior Notes 2026 under the Indenture governing the notes. This satisfaction and discharge constituted a legal defeasance, or the Defeasance, under GAAP as of March 18, 2024 of the full outstanding principal balance of $725.0 million. The Senior Notes 2026 were redeemed in full at par on April 4, 2024.
The Senior Notes 2027 are due on September 1, 2027, and accrue interest at the rate of 6.875% per year. Interest on the Senior Notes 2027 is payable semi-annually in arrears on each of March 1 and September 1.
The Senior Notes 2029 are due on March 15, 2029, and accrue interest at the rate of 7.125% per year. Interest on the Senior Notes 2029 is payable semi-annually in arrears on each of March 15 and September 15, which commenced on September 15, 2024. Net proceeds from the Senior Notes 2029 were used for the Defeasance, with the remainder used to reduce outstanding borrowings under our Credit Agreement.
For more detailed descriptions of the Defeasance, Senior Notes 2027, and Senior Notes 2029, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
Derivative Instrument
During the year ended December 31, 2024, we elected to terminate the interest-rate swap we previously used to manage interest-rate risk associated with the floating-rate Credit Agreement, see Note 8 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for more information regarding the interest-rate swap.
DRIP
During the years ended December 31, 2024 and 2023, distributions of $1.6 million and $1.9 million, respectively, were reinvested under the DRIP resulting in the issuance of 65,352 and 87,808 common units, respectively.
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.
Non-GAAP Financial Measures
Adjusted Gross Margin
Adjusted gross margin is a non-GAAP financial measure. We define Adjusted gross margin as revenue less cost of operations, exclusive of depreciation and amortization expense. We believe Adjusted gross margin is useful to investors as a supplemental measure of our operating profitability. Management uses adjusted gross margin to assess operating performance as compared to historical results, budget and forecast amounts, expected return on capital investment, and our competitors. Adjusted gross margin primarily is impacted by the pricing trends for service operations and cost of operations, including labor rates for service technicians, volume, and per-unit costs for lubricant oils, quantity and pricing of routine preventative maintenance on compression units, and property tax rates on compression units. Adjusted gross margin should not be considered an alternative to, or more meaningful than, gross margin or any other measure presented in accordance with GAAP. Moreover, our Adjusted gross margin, as presented, may not be comparable to similarly titled measures of other companies. Because we capitalize assets, depreciation and amortization of equipment is a necessary element of our cost structure. 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.
The following table reconciles Adjusted gross margin to gross margin, its most directly comparable GAAP financial measure, for each of the periods presented (in thousands):
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | |
| Total revenues | $ | 950,449 | | | $ | 846,178 | | | |
| Cost of operations, exclusive of depreciation and amortization | (312,726) | | | (284,708) | | | |
| Depreciation and amortization | (264,756) | | | (246,096) | | | |
| Gross margin | $ | 372,967 | | | $ | 315,374 | | | |
| Depreciation and amortization | 264,756 | | | 246,096 | | | |
| Adjusted gross margin | $ | 637,723 | | | $ | 561,470 | | | |
Adjusted EBITDA
We define EBITDA as net income (loss) before net interest expense, depreciation and amortization expense, and income tax expense (benefit). We define Adjusted EBITDA as EBITDA plus impairment of assets, impairment of goodwill, interest income on capital leases, unit-based compensation expense (benefit), severance charges, certain transaction expenses, loss (gain) on disposition of assets, loss on extinguishment of debt, loss (gain) on derivative instrument, and other. We view Adjusted EBITDA as one of management’s primary tools for evaluating our results of operations, and we track this item on a monthly basis as an absolute amount and as a percentage of revenue compared to the prior month, year-to-date, prior year, and budget. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financial statements, such as investors and commercial banks, to assess:
•the financial performance of our assets without regard to the impact of financing methods, capital structure, or the historical cost basis of our assets;
•the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;
•the ability of our assets to generate cash sufficient to make debt payments and pay distributions; and
•our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital structure.
We believe Adjusted EBITDA provides useful information to investors because, when viewed in conjunction with our GAAP results and the accompanying reconciliations, it may provide a more complete assessment of our performance as compared to considering solely GAAP results. We also believe that external users of our financial statements benefit from having access to the same financial measures that management uses to evaluate the results of our business.
Adjusted EBITDA 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 Adjusted EBITDA, as presented, may not be comparable to similarly titled measures of other companies.
Because we use capital assets, depreciation, impairment of assets, loss (gain) on disposition of assets, and the interest cost of acquiring compression equipment also are necessary elements of our aggregate costs. Unit-based compensation expense related to equity awards granted to employees also is a meaningful business expense. Therefore, measures that exclude these cost elements have material limitations. 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 Adjusted EBITDA, to evaluate our financial performance and liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these excluded items may vary among companies. Management compensates for the limitations of 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.
The following table reconciles Adjusted EBITDA to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands):
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | |
| Net income | $ | 99,575 | | | $ | 68,268 | | | |
| Interest expense, net | 193,471 | | | 169,924 | | | |
| Depreciation and amortization | 264,756 | | | 246,096 | | | |
| Income tax expense | 2,231 | | | 1,365 | | | |
| EBITDA | $ | 560,033 | | | $ | 485,653 | | | |
| | | | | |
| Unit-based compensation expense (1) | 16,552 | | | 22,169 | | | |
| Transaction expenses (2) | 133 | | | 46 | | | |
| Severance charges | 2,430 | | | 841 | | | |
| Loss (gain) on disposition of assets | 4,939 | | | (1,667) | | | |
| Loss on extinguishment of debt (3) | 4,966 | | | — | | | |
| Gain on derivative instrument | (5,684) | | | (7,449) | | | |
| Impairment of assets (4) | 913 | | | 12,346 | | | |
| | | | | |
| Adjusted EBITDA | $ | 584,282 | | | $ | 511,939 | | | |
| Interest expense, net | (193,471) | | | (169,924) | | | |
| Non-cash interest expense | 8,748 | | | 7,279 | | | |
| Income tax expense | (2,231) | | | (1,365) | | | |
| | | | | |
| Transaction expenses | (133) | | | (46) | | | |
| Severance charges | (2,430) | | | (841) | | | |
| Cash received on derivative instrument | 6,888 | | | 6,245 | | | |
| Other | 1,204 | | | 1,448 | | | |
| Changes in operating assets and liabilities | (61,523) | | | (82,850) | | | |
| Net cash provided by operating activities | $ | 341,334 | | | $ | 271,885 | | | |
________________________
(1)For the years ended December 31, 2024 and 2023, unit-based compensation expense included $3.9 million and $4.4 million, respectively, of cash payments related to quarterly payments of DERs on outstanding phantom unit awards and $0.2 million and $0.3 million, respectively, related to the cash portion of the settlement of phantom unit awards upon vesting. 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.
(3)This loss on extinguishment of debt is a result of the Defeasance of the Senior Notes 2026. This amount represents the write-off of deferred financing costs of $4.3 million and the difference between (i) the purchase price of U.S. government securities of $748.8 million and (ii) the aggregate outstanding principal balance and accrued interest of the Senior Notes 2026 of $748.1 million at the time of Defeasance.
(4)Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows.
Distributable Cash Flow
We define DCF as net income (loss) plus non-cash interest expense, non-cash income tax expense (benefit), depreciation and amortization expense, unit-based compensation expense (benefit), impairment of assets, impairment of goodwill, certain transaction expenses, severance charges, loss (gain) on disposition of assets, loss on extinguishment of debt, change in fair value of derivative instrument, proceeds from insurance recovery, and other, less distributions on Preferred Units and maintenance capital expenditures.
We believe DCF is an important measure of operating performance because it allows management, investors, and others to compare the cash flows that we generate (after distributions on the Preferred Units but prior to any retained cash reserves established by the General Partner and the effect of the DRIP) to the cash distributions that we expect to pay our common unitholders.
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.
Because we use capital assets, depreciation, impairment of assets, loss (gain) on disposition of assets, the interest cost of acquiring compression equipment, and maintenance capital expenditures are necessary components of our aggregate costs. Unit-based compensation expense related to equity awards granted to employees also is a meaningful business expense. Therefore, measures that exclude these cost elements have material limitations. 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 DCF excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these excluded items may vary among companies. Management compensates for the limitations of DCF as an analytical tool by reviewing comparable GAAP measures, understanding the differences between the measures, and incorporating this knowledge into their decision making.
The following table reconciles DCF to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands):
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | |
| Net income | $ | 99,575 | | | $ | 68,268 | | | |
| Non-cash interest expense | 8,748 | | | 7,279 | | | |
| Depreciation and amortization | 264,756 | | | 246,096 | | | |
| Non-cash income tax expense (benefit) | 574 | | | (52) | | | |
| Unit-based compensation expense (1) | 16,552 | | | 22,169 | | | |
| Transaction expenses (2) | 133 | | | 46 | | | |
| Severance charges | 2,430 | | | 841 | | | |
| Loss (gain) on disposition of assets | 4,939 | | | (1,667) | | | |
| Loss on extinguishment of debt (3) | 4,966 | | | — | | | |
| Change in fair value of derivative instrument | 1,204 | | | (1,204) | | | |
| Impairment of assets (4) | 913 | | | 12,346 | | | |
| | | | | |
| Distributions on Preferred Units | (17,550) | | | (47,775) | | | |
| | | | | |
| Maintenance capital expenditures (5) | (31,923) | | | (25,234) | | | |
| DCF | $ | 355,317 | | | $ | 281,113 | | | |
| Maintenance capital expenditures | 31,923 | | | 25,234 | | | |
| Transaction expenses | (133) | | | (46) | | | |
| Severance charges | (2,430) | | | (841) | | | |
| Distributions on Preferred Units | 17,550 | | | 47,775 | | | |
| Other | 630 | | | 1,500 | | | |
| Changes in operating assets and liabilities | (61,523) | | | (82,850) | | | |
| Net cash provided by operating activities | $ | 341,334 | | | $ | 271,885 | | | |
________________________
(1)For the years ended December 31, 2024 and 2023, unit-based compensation expense included $3.9 million and $4.4 million, respectively, of cash payments related to quarterly payments of DERs on outstanding phantom unit awards and $0.2 million and $0.3 million, respectively, related to the cash portion of the settlement of phantom unit awards upon vesting. 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.
(3)This loss on extinguishment of debt is a result of the Defeasance of the Senior Notes 2026. This amount represents the write-off of deferred financing costs of $4.3 million and the difference between (i) the purchase price of U.S. government securities of $748.8 million and (ii) the aggregate outstanding principal balance and accrued interest of the Senior Notes 2026 of $748.1 million at the time of Defeasance.
(4)Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows.
(5)Reflects actual maintenance capital expenditures for the period presented. Maintenance capital expenditures are capital expenditures made to maintain the operating capacity of our assets and extend their useful lives, replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining our existing business and related cash flow.
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. We believe DCF Coverage Ratio is an important measure of operating performance because it permits management, investors, and others to assess our ability to pay distributions to common unitholders out of the cash flows that we generate. Our DCF Coverage Ratio, as presented, may not be comparable to similarly titled measures of other companies.
The following table summarizes our DCF Coverage Ratio for the periods presented (dollars in thousands):
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | |
| DCF | $ | 355,317 | | | $ | 281,113 | | | |
| | | | | |
| Distributions for DCF Coverage Ratio (1) | $ | 245,990 | | | $ | 208,856 | | | |
| | | | | |
| DCF Coverage Ratio | 1.44 | x | | 1.35 | x | | |
________________________
(1)Represents distributions to the holders of our common units as of the record date.
Critical Accounting Estimates
The discussion and analysis of our financial condition and results of operations is based on our financial statements. These financial statements were prepared in conformity with GAAP. As such, we are required to make certain estimates, judgments, and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. We base our estimates on historical experience, available information, and other assumptions we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates; however, actual results may differ from these estimates under different assumptions or conditions. The accounting estimates that we believe require management’s most difficult, subjective, or complex judgments, and that are the most critical to its reporting of results of operations and financial position are as follows:
Long-Lived Assets
Long-lived assets, which include property and equipment, and intangible assets, comprise a significant amount of our total assets. Long-lived assets to be held and used by us are reviewed to determine whether any events or changes in circumstances indicate the carrying amount of the asset may not be recoverable. For long-lived assets to be held and used, we base our evaluation on impairment indicators such as the nature of the assets, the future economic benefit of the assets, the consistency of performance characteristics of compression units in our idle fleet with the performance characteristics of our revenue-generating horsepower, any historical or future profitability measurements, and other external market conditions or factors that may be present. If such impairment indicators are present or other factors exist that indicate the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through the use of an undiscounted cash flows analysis. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the estimated fair value of the asset. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, is based on an estimate of discounted cash flows, the expected net sale proceeds compared to other similarly configured fleet units we recently sold, a review of other units recently offered for sale by third parties, or the estimated component value of similar equipment we plan to continue to use.
Potential events or circumstances that reasonably could be expected to negatively affect the key assumptions we used in estimating whether or not the carrying value of our long-lived assets are recoverable include the consolidation or failure of crude oil and natural gas producers, which may result in a smaller market for our services and may cause us to lose key customers, and cost-cutting efforts by crude oil and natural gas producers, which may cause us to lose current or potential customers or achieve less revenue per customer. If our projections of cash flows associated with our units decline, we may have to record an impairment of assets in future periods.
For the years ended December 31, 2024 and 2023, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 2 and 42 compression units, respectively, representing approximately 1,260 and 37,700 of aggregate horsepower, respectively, that previously were used to provide compression services in our business. As a result, we recorded impairments of compression equipment of $0.3 million and $12.3 million for the years ended December 31, 2024, and 2023, respectively. 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.
Additionally, for the year ended December 31, 2024, we recognized a $0.6 million impairment of assets related to capitalized software costs that are no longer expected to provide benefit.
Estimated Useful Lives of Property and Equipment
Property and equipment is carried at cost. Depreciation is computed on a straight-line basis using useful lives that are estimated based on assumptions and judgments that reflect both historical experience and expectations regarding future use of our assets. The use of different assumptions and judgments in the calculation of depreciation, especially those involving useful lives, likely would result in significantly different net book values of our assets and results of operations.
Commitments and Contingencies
From time to time, we and our subsidiaries may be involved in various claims and litigation arising in the ordinary course of business. Additionally, our compliance with federal, state, and local tax regulations is subject to audit by various taxing authorities. Certain taxing authorities have either claimed or issued an assessment that specific operational processes, which we and others in our industry regularly conduct, result in transactions that are subject to taxes. We and others in our industry have disputed these claims and assessments based on either existing tax statutes or published guidance by the taxing authorities.
We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments, or settlements. While we are unable to predict the ultimate outcome of these actions, the accounting standard for contingencies requires management to make judgments about future events that are inherently uncertain. We are required to record a loss during any period in which we believe a contingency is probable and can be reasonably estimated. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised, as required, as better information becomes available to us.
We currently are protesting certain sales tax assessments made by the Oklahoma Tax Commission (“OTC”). In August 2024, the administrative law judge (“ALJ”) assigned by the OTC accepted our position that the transactions are not taxable. The OTC subsequently requested a motion for reconsideration, which was denied by the ALJ. The OTC then requested an “en banc” hearing from the OTC Commissioners, which the OTC Commissioners denied and adopted the conclusions of the ALJ, thereby effectively closing the matter.
Our U.S. federal income tax returns for the 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. Under the Bipartisan Budget Act of 2015, there are several procedural steps, including an appeals process, to complete before a final imputed underpayment, if any, is determined. Based on discussions with the IRS, we estimate a potential range of loss from a final imputed underpayment of $0 to approximately $28.3 million, including interest, for potential adjustments resulting from the IRS examinations. Once a final partnership imputed underpayment, if any, is determined, our General Partner may elect to either pay the imputed underpayment (including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised information statement to each unitholder, and former unitholder, with respect to an audited and adjusted return.
Recent Accounting Pronouncements
See Part II, Item 8 “Financial Statements and Supplementary Data”, Note 19 for recent accounting pronouncements affecting us.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. We do not take title to any natural gas or crude oil in connection with our rendered services, and accordingly, we do not bear direct exposure to fluctuating commodity prices. However, 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. We do not intend to hedge our indirect exposure to fluctuating commodity prices. A one percent decrease in average revenue-generating horsepower during the year ended December 31, 2024 would result in an annual decrease of approximately $8.6 million and $5.8 million in our revenue and Adjusted gross margin, respectively. Adjusted gross margin is a non-GAAP financial measure. For a reconciliation of Adjusted gross margin to gross margin, its most directly comparable financial measure, calculated and presented in accordance with GAAP, please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Measures”. Please also read Part I, Item 1A “Risk Factors – Risks Related to Our Business – An extended reduction in the demand for, or production of, natural gas or crude oil could adversely
affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders.”
Interest Rate Risk
We are exposed to market risk due to variable interest rates under the Credit Agreement.
As of December 31, 2024, we had $772.1 million of variable-rate indebtedness outstanding at a weighted-average interest rate of 6.98%. Based on our December 31, 2024 variable-rate indebtedness outstanding, a one percent increase or decrease, respectively, in the effective interest rate would result in an annual increase or decrease in our interest expense of approximately $7.7 million.
For further information regarding our exposure to interest rate fluctuations on our debt obligations, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
In August 2024, we elected to terminate the interest-rate swap we previously used to manage interest-rate risk associated with the floating-rate Credit Agreement. For further information regarding our interest-rate swap and the termination, see Note 8 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
Credit Risk
Our credit exposure generally relates to receivables for services provided. 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. “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. 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.
ITEM 9A. Controls and Procedures
Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based on the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2024, at the reasonable assurance level.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting for us. Our internal control system was designed to provide reasonable assurance regarding the preparation and fair presentation of our published financial statements.
There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part on assumptions and judgments made by management about the likelihood of future events, and
there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal control over financial reporting can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.
Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria set forth by the 2013 Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework. Based on this assessment, our management believes that, as of December 31, 2024, our internal control over financial reporting was effective. Grant Thornton LLP, an independent registered public accounting firm that audited our consolidated financial statements included herein, also has audited the effectiveness of our internal control over financial reporting as of December 31, 2024, as stated in their report, which is included herein.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors of USA Compression GP, LLC and
Unitholders of USA Compression Partners, LP
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of USA Compression Partners, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2024, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2024, and our report dated February 11, 2025 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Houston, Texas
February 11, 2025
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. Other Information
In connection with recent changes to the business, the Partnership and Eric A. Scheller, our Vice President and Chief Operating Officer, engaged in discussions regarding Mr. Scheller’s role and mutually came to an agreement that it would be in the best interests of Mr. Scheller and the Partnership for Mr. Scheller to terminate his employment with the Partnership. Our Compensation Committee approved a separation package for Mr. Scheller on February 10, 2025, and Mr. Scheller’s last day at the Partnership is expected to be April 4, 2025. The Partnership expresses its appreciation to Mr. Scheller for his dedicated service and significant contributions to the Partnership and wishes him well in his future endeavors.
In connection with Mr. Scheller’s departure, Mr. Scheller and the General Partner intend to enter into a Restrictive Covenant and Separation Agreement and Full Release of Claims (the “Scheller Separation Agreement”). The Scheller Separation Agreement will become effective after execution and the expiration of a seven (7) day revocation period. The Scheller Separation Agreement will provide for the following: (i) a separation payment of $432,600, less all required governmental payroll deductions and withholdings; (ii) accelerated vesting of 81,286 phantom units to be settled up to 50% in cash, less all required governmental payroll deductions and withholdings, and (iii) a lump-sum payment equal to the full cost of the premium for eight (8) months of health insurance coverage under the Partnership’s health insurance plan.
The Scheller Separation Agreement will include, among other things, (i) a standard release of claims in favor of our General Partner, its parent entities, specifically including Energy Transfer, and their respective past and present subsidiaries, affiliates, partners, directors, officers, owners, shareholders, employees, benefit plans, benefit plan fiduciaries, predecessors, joint employers, successor employers and agents; (ii) a twenty-four (24) month restrictive covenant provision whereby Mr. Scheller acknowledges obligations with respect to competition and solicitation of customers and employees; (iii) a mutual non-disparagement clause (applicable to officers and directors of the General Partner); (iv) a confirmation and acknowledgement by Mr. Scheller of his obligations with respect to proprietary and confidential information; and (v) a twenty-four (24) month cooperation clause.
On February 10, 2025, G. Tracy Owens, our Vice President of Finance and Chief Accounting Officer informed the Partnership of his intention to retire effective March 3, 2025. The Partnership thanks Mr. Owens for his many years of service and important contributions to the Partnership, and wishes him well in the future.
In connection with Mr. Owens’s retirement, Mr. Owens and the General Partner intend to enter into a Restrictive Covenant and Separation Agreement and Full Release of Claims (the “Owens Retirement Agreement”). The Owens Retirement Agreement will become effective after execution and the expiration of a seven (7) day revocation period. The Owens Retirement Agreement will provide for the following: (i) a payment of $115,875, less all required governmental payroll deductions and withholdings; (ii) accelerated vesting of 12,765 phantom units to be settled up to 50% in cash, less all required governmental payroll deductions and withholdings, and (iii) a lump-sum payment equal to the full cost of the premium for nine (9) months of health insurance coverage under the Partnership’s health insurance plan.
The Owens Retirement Agreement will include, among other things, (i) a standard release of claims in favor of our General Partner, its parent entities, specifically including Energy Transfer, and their respective past and present subsidiaries, affiliates, partners, directors, officers, owners, shareholders, employees, benefit plans, benefit plan fiduciaries, predecessors, joint employers, successor employers and agents; (ii) a twelve (12) month restrictive covenant provision whereby Mr. Owens acknowledges obligations with respect to competition and solicitation of customers and employees; (iii) a mutual non-disparagement clause (applicable to officers and directors of the General Partner); (iv) a confirmation and acknowledgement by Mr. Owens of his obligations with respect to proprietary and confidential information; and (v) a twenty-four (24) month cooperation clause.
Rule 10b5-1 Trading Plans
During the three months ended December 31, 2024, none of the Company’s directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) informed the Company of the adoption, modification or termination of a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as defined in Item 408 of Regulation S-K.
ITEM 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
PART III
ITEM 10. Directors, Executive Officers, and Corporate Governance
Board of Directors
Our general partner, USA Compression GP, LLC (the “General Partner”), manages our operations and activities. The General Partner is wholly owned by Energy Transfer LP (“Energy Transfer”). The General Partner has a board of directors (the “Board”) that manages our business, and the Board has appointed executive officers of the General Partner. References to “our officers” and “our directors” in this section refers to the officers and directors of the General Partner. The Board is not elected by our unitholders and is not subject to re-election on a regular basis in the future. As the sole member of the General Partner, Energy Transfer is entitled under the limited liability company agreement of the General Partner (the “GP LLC Agreement”) to appoint all directors of the General Partner, subject to rights and restrictions contained in other agreements. The GP LLC Agreement provides that the Board shall consist of between two and eleven persons.
The Board is comprised of nine members, all of whom were designated by Energy Transfer. Pursuant to a Board Representation Agreement (the “Board Representation Agreement”) among us, the General Partner, Energy Transfer, EIG Veteran Equity Aggregator, L.P. (along with its affiliated funds, “EIG”), and EIG Management Company, LLC (“EIG Management”), entered into on April 2, 2018 (the “Transactions Date”) in connection with our private placement to EIG and FS Specialty Lending Fund (formerly known as FS Energy and Power Fund) (“FSSL”) of Preferred Units and warrants to purchase common units of the Partnership (the “Warrants”), EIG Management has the right to designate one member of the Board for so long as EIG and FSSL own, in the aggregate, more than 5% of the Partnership’s outstanding common units (taking into account the common units issuable upon conversion of the Preferred Units and exercise of the Warrants). EIG Management has not designated a board member following the resignation of its previous designee, Matthew S. Hartman, on November 20, 2023. Three members of the Board are independent as defined under the independence standards established by the NYSE and the SEC. Although the NYSE does not require a publicly traded limited partnership like us to have a majority of independent directors on the Board or to establish a compensation committee or a nominating committee, the Board has elected to have a standing compensation committee (the “Compensation Committee”). We do not have a nominating committee in light of the fact that Energy Transfer and EIG currently collectively have the right to appoint all of the members of the Board.
The non-management members of the Board meet in executive session without any members of management present at least twice a year. Mr. William S. Waldheim presides at such meetings. Interested parties can communicate directly with non-management members of the Board by mail in care of the General Counsel and Secretary at USA Compression Partners, LP, 8117 Preston Road, Suite 510A, Dallas, Texas 75225. Such communications should specify the intended recipient or recipients. Commercial solicitations or similar communications will not be forwarded to the Board.
As a limited partnership, NYSE rules do not require us to seek unitholder approval for the election of any of our directors. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees. We believe, however, that the individuals appointed as directors have experience, skills, and qualifications relevant to our business and have a history of service in the industry or senior leadership positions with the qualities and attributes required to provide effective oversight of the Partnership.
Independent Directors. The Board has determined that each of Glenn E. Joyce, William S. Waldheim, and John L. Wortham are an independent director under the standards established by the NYSE and the Exchange Act. The Board considered all relevant facts and circumstances and applied the independence guidelines of the NYSE and the Exchange Act in determining that none of these directors has any material relationship with us, our management, the General Partner or its affiliates, or our subsidiaries.
The Board’s Role in Risk Oversight
The Board administers its risk oversight function as a whole and through its committees. It does so in part through discussion and review of our business, financial reporting, and corporate governance policies, procedures, and practices, with opportunity to make specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of the Partnership’s operational and financial performance, which often prompts questions and feedback from the Board. The audit committee of the Board (the “Audit Committee”) provides additional risk oversight through its quarterly meetings, where it discusses policies with respect to risk assessment and risk management, reviews contingent liabilities and risks that may be material to the Partnership, and assesses major legislative and regulatory developments that could materially impact the Partnership’s contingent liabilities and risks. The Audit Committee also is required to discuss any material violations of our policies brought to its attention on an ad-hoc basis. Additionally, the Compensation Committee reviews our overall compensation program and its effectiveness at both linking executive pay to performance and aligning the interests of our executives and our unitholders.
Committees of the Board of Directors
Audit Committee. The Board appoints the Audit Committee, which is comprised solely of directors who meet the independence and experience standards established by the NYSE and the Exchange Act. The Audit Committee consists of Messrs. Joyce, Waldheim, and Wortham. Mr. Waldheim serves as chairman of the Audit Committee. The Board determined that Mr. Waldheim is an “audit committee financial expert” as defined in Item 407(d)(5)(ii) of SEC Regulation S-K, and that each of Messrs. Joyce, Waldheim, and Wortham is “independent” within the meaning of the applicable NYSE and Exchange Act rules governing audit committee independence. The Audit Committee assists the Board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements as well as the effectiveness of our corporate policies and internal controls. The Audit Committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee also is responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the Audit Committee.
The charter of the Audit Committee (the “Audit Committee Charter”) is available under the Investor Relations tab on our website at usacompression.com. We will provide a copy of the Audit Committee Charter to any of our unitholders without charge upon written request to Investor Relations, 8117 Preston Road, Suite 510A, Dallas, Texas 75225.
Compensation Committee. The NYSE does not require a listed limited partnership like us to have a compensation committee. However, the Board established the Compensation Committee to, among other things, oversee our compensation program described below in Part III, Item 11 “Executive Compensation.” The Compensation Committee consists of Messrs. Joyce, Waldheim, and Wortham and is chaired by Mr. Joyce. The Compensation Committee establishes and reviews general policies related to our compensation and benefits, and is responsible for making recommendations to the Board with respect to the compensation and benefits of the Board. In addition, the Compensation Committee administers the USA Compression Partners, LP 2013 Long-Term Incentive Plan, as amended and as may be further amended or replaced from time to time (the “LTIP”) and the USA Compression Partners, LP Long-Term Cash Restricted Unit Plan, as may be amended or replaced from time to time (the “CRU Plan”).
Under the charter of the Compensation Committee (the “Compensation Committee Charter”), a director serving as a member of the Compensation Committee may not be an officer of, or employed by, the General Partner, us, or our subsidiaries. During 2024, none of Mr. Joyce, Mr. Waldheim, or Mr. Wortham was an officer or employee of Energy Transfer or any of its affiliates, or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors.
The Compensation Committee Charter is available under the Investor Relations tab on our website at usacompression.com. We will provide a copy of the Compensation Committee Charter to any of our unitholders without charge upon written request to Investor Relations, 8117 Preston Road, Suite 510A, Dallas, Texas 75225.
Conflicts Committee. As set forth in the GP LLC Agreement, the General Partner may, from time to time, establish a conflicts committee to which the Board will appoint independent directors and which may be asked to review specific matters that the Board believes may involve conflicts of interest between us, our limited partners, and Energy Transfer. Such conflicts committee will determine the resolution of the conflict of interest in any matter referred to it in good faith. The members of the conflicts committee may not be officers or employees of the General Partner or directors, officers, or employees of its affiliates, including Energy Transfer, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on the Audit Committee, and certain other requirements. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by the General Partner of any duties it may owe us or our unitholders.
Corporate Governance Guidelines and Code of Ethics
The Board has adopted Corporate Governance Guidelines (the “Guidelines”) that outline important policies and practices regarding our governance and provide a framework for the function of the Board and its committees. The Board also has adopted a Code of Business Conduct and Ethics (the “Code”) that applies to the General Partner and its subsidiaries and affiliates, including us, and to all of its and their directors, employees, and officers, including its principal executive officer, principal financial officer, and principal accounting officer. We intend to post any amendments to the Code, or waivers of its provisions applicable to our directors or executive officers, including our principal executive officer and principal financial officer, on our website. The Guidelines and the Code are available under the Investor Relations tab on our website at usacompression.com. We will provide copies of the Guidelines and the Code to any of our unitholders without charge upon written request to Investor Relations, 8117 Preston Road, Suite 510A, Dallas, Texas 75225.
Note that the preceding internet addresses are for informational purposes only and are not intended to be hyperlinked. Accordingly, no information found on or provided at those internet addresses or on our website in general is intended or deemed to be incorporated by reference herein.
Insider Trading Policy
The Board has adopted insider trading policies and procedures governing the purchase, sale, and disposition of our securities that we believe are reasonably designed to promote compliance with insider trading laws, rules, and regulations, and the listing standards of the NYSE. Our insider trading policy is applicable to all employees, officers and directors and, among other things, (i) prohibits our employees, officers, directors, and certain related persons and entities from trading in securities of USA Compression Partners, LP and certain other companies while in possession of material, non-public information, (ii) contains confidentiality provisions designed to protect our material, non-public information, and (iii) requires that certain individuals who are designated as “Insiders” only transact in Partnership securities during an open trading window period, subject to limited exceptions. A copy of our insider trading policy is filed as Exhibit 19.1 to this Form 10-K.
Directors and Executive Officers
The following table shows information as of February 6, 2025 regarding the current directors and executive officers of USA Compression GP, LLC.
| | | | | | | | | | | | | | |
| Name | | Age | | Position with USA Compression GP, LLC |
| M. Clint Green | | 47 | | President and Chief Executive Officer |
| Christopher M. Paulsen | | 47 | | Vice President, Chief Financial Officer and Treasurer |
| Eric A. Scheller | | 61 | | Vice President and Chief Operating Officer |
| Christopher W. Porter | | 41 | | Vice President, General Counsel and Secretary |
| Dylan A. Bramhall | | 48 | | Director |
| Clifford A. Harris | | 76 | | Director |
| Glenn E. Joyce | | 67 | | Director |
| Thomas E. Long | | 68 | | Director |
| Thomas P. Mason | | 68 | | Director |
| William S. Waldheim | | 68 | | Director |
| Bradford D. Whitehurst | | 50 | | Director |
| John L. Wortham | | 73 | | Director |
| James M. Wright, Jr. | | 56 | | Director |
The directors of the General Partner hold office until the earlier of their death, resignation, removal, or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the Board. There are no family relationships among any of the directors or executive officers of the General Partner.
M. Clint Green has served as our President and CEO since October 2024. Prior to this position, Mr. Green served as Group Senior Vice President, Construction and Project Execution for Energy Transfer beginning in August 2024, Senior Vice President, Construction and Project Execution for Energy Transfer from April 2022 to August 2024, and as Vice President of Operations for Energy Transfer’s Western Division from August 2018 to April 2022. Mr. Green has more than 25 years of industry experience, having served in leadership positions at Energy Transfer since 2015, when he joined as a Senior Director through its merger with Regency Energy Partners. Prior to Energy Transfer, he held positions at Regency Energy Partners, Hanover Compression, CDM Compression and SEC Energy.
Christopher M. Paulsen has served as our Vice President, Chief Financial Officer and Treasurer since November 2024. Prior to this position, Mr. Paulsen was the Senior Vice President of Business Development and Strategy for Pioneer Natural Resources Company (“Pioneer”), a large independent oil and gas exploration and production company, from March 2023 through Pioneer’s merger with ExxonMobil in May 2024. Prior to that, he was the Vice President of Business Development and Strategy at Pioneer beginning in January 2013. Mr. Paulsen joined Pioneer in 2002 and served in various areas including investor relations, mergers and acquisitions, and operations and subsurface. In 2011, Mr. Paulsen took over leadership of the business development team responsible for shale technology, divestitures, and mergers and acquisitions. Transactions generally concentrated on upstream, midstream, oilfield service, and renewable sectors in the Permian Basin, Mid-Continent, Gulf Coast, Alaska, and Rockies. Additionally, his team was responsible for corporate strategy, scenario planning, and energy transition investments transactions. Prior to joining Pioneer, Mr. Paulsen worked for SBC Communications in planning as well as
treasury. Mr. Paulsen received his BBA from Baylor University and his MBA from the McCombs School of Business at the University of Texas. Mr. Paulsen is a board member of Ralph Lowe Energy Institute at Texas Christian University. He also serves as a board member of the Maguire Energy Institute at Southern Methodist University, focusing his efforts with the student-directed Spindletop Energy Investment Fund.
Eric A. Scheller has served as our Vice President, Chief Operating Officer since June 2020. Prior to that, Mr. Scheller served as our Vice President – Fleet Operations since April 2018, and prior to that was our Vice President, Operations & Performance Management beginning in August 2015. Prior to joining us, Mr. Scheller was a Director at Sapient Global Markets since August 2013. Before Sapient, Mr. Scheller was a consultant in private practice advising midstream and chemicals firms from January 2012 to July 2013. Prior to that, he held several positions with Enterprise Products Partners LP from November 2004 to December 2011, most recently as Regional Director, Pipeline & Storage Services. Mr. Scheller holds a B.S. in Chemical Engineering (Math minor), a Masters of Chemical Engineering, and an M.B.A., all from the University of Houston. Mr. Scheller also is a CFA ® charterholder.
Christopher W. Porter has served as our Vice President, General Counsel and Secretary since January 2017, and, prior to that, had served as our Associate General Counsel and Assistant Secretary since October 2015. From January 2010 through October 2015, Mr. Porter practiced corporate and securities law at Hunton Andrews Kurth LLP, representing public and private companies, including master limited partnerships, in capital markets offerings, mergers and acquisitions, and corporate governance. Mr. Porter holds a B.B.A. degree in accounting from Texas A&M University, a M.S. degree in finance from Texas A&M University, and a J.D. degree from The George Washington University.
Dylan A. Bramhall has served on the Board since April 2024. Mr. Bramhall has served as Executive Vice President and Group Chief Financial Officer of the general partner of Energy Transfer since November 2022 and currently is also Chief Financial Officer of Sunoco LP’s general partner. Mr. Bramhall joined Energy Transfer in 2015 as a result of its merger with Regency Energy Partners and is responsible for oversight of Energy Transfer’s Financial Planning and Analysis, Credit and Commodity Risk Management, Insurance, Cash Management, Capital Markets, Accounting, Financial Reporting and Investor Relations groups. He also serves as a member of Energy Transfer’s Risk Oversight Committee. While at Regency, Mr. Bramhall held management positions in the finance, risk, commercial and operations groups. Mr. Bramhall holds a Bachelor of Business Administration in finance and Master of Business Administration in finance and operations management, both from the University of Iowa.
Mr. Bramhall was selected to serve on the Board because of his financial acumen and his experience as an executive officer in the energy sector.
Clifford A. Harris has served on our Board since February 2024. Until February 2024, Mr. Harris held the position of Director- Sales with the general partner of Energy Transfer. Prior to that, Mr. Harris was Director- Sales of Dual Drive Technologies, Ltd., a company that developed technology which enables a gas compressor to switch from a natural gas engine to an electric driver, which was acquired by Energy Transfer in 2017. Mr. Harris held various positions with Dual Drive Technologies, Ltd. and its predecessors beginning in 1995. Before entering the energy industry, Mr. Harris played professional football with the Dallas Cowboys, and was inducted into the Pro Football Hall of Fame in 2020. Mr. Harris also serves on the board of the Juvenile Diabetes Research Foundation, and holds a bachelor’s degree in mathematics and a minor in physics from Ouachita Baptist University.
Mr. Harris was selected to serve on the Board due to the valuable experience and insight he brings from over 25 years in the energy industry, as well as his experience with gas compression.
Glenn E. Joyce has served on the Board since April 2018. Mr. Joyce was with Apex International Energy (“Apex”) for over six years, most recently as their Chief Administrative Officer from January 2017 through April 2022. Prior to joining Apex, he spent over 17 years with Apache Corporation where his last position was Director of Global Human Resources in which he managed the HR functions of the international regions of Apache (Australia, Argentina, UK, Egypt). Previously, he worked for Amoco and was involved in international operations in many different countries. Mr. Joyce received his bachelor’s degree in accounting from Texas A&M University.
Mr. Joyce was selected to serve on the Board due to his extensive experience in senior human resources leadership positions in the energy industry.
Thomas E. Long has served on the Board since April 2018. Mr. Long was appointed as Co-Chief Executive Officer of the general partner of Energy Transfer effective January 2021. Since May 2022, Mr. Long also has served as a director of Texas Capital Bancshares, Inc. Mr. Long previously served as the Chief Financial Officer of the general partner of Energy Transfer from February 2016 until January 2021. Mr. Long also has served as a director of the general partner of Energy Transfer since April 2019. Mr. Long served as Co-Chief Executive Officer of ETO’s general partner from January 2021 until its merger into
Energy Transfer in April 2021 and was previously its Chief Financial Officer. He also served on the board of directors of the general partner of Sunoco LP from May 2016 until May 2021. Mr. Long also served as the Chief Financial Officer and as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Long also served as Executive Vice President and Chief Financial Officer of Regency GP LLC from November 2010 to April 2015.
Mr. Long was selected to serve on the Board because of his understanding of energy-related corporate finance gained through his extensive experience in the energy industry.
Thomas P. Mason has served on the Board since April 2018. Since December 2022, Mr. Mason has served as the Executive Vice President and President – LNG of the general partner of Energy Transfer. Mr. Mason became the Executive Vice President and General Counsel of the general partner of Energy Transfer in December 2015, and served as the Executive Vice President, General Counsel and President – LNG from October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. until December 2022 when he resigned from his role as General Counsel. In February 2021, Mr. Mason assumed leadership responsibility over Energy Transfer’s newly created Alternative Energy Group, which focuses on the development of alternative energy projects aimed at continuing to reduce Energy Transfer’s environmental footprint throughout its operations. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETO’s general partner from April 2012 to December 2015, as Vice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February 2007. Prior to joining ETO, he was a partner in the Houston office of Vinson & Elkins L.L.P. Mr. Mason also previously served on the Board of Directors of the general partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017 and also served on the Board of Directors of the general partner of PennTex Midstream Partners, LP from November 2016 to July 2017.
Mr. Mason was selected to serve on the Board because of his decades of legal experience in securities, mergers and acquisitions, and corporate governance in the energy sector.
William S. Waldheim has served on the Board since April 2018. Mr. Waldheim also served on the board of directors of Southcross Energy Partners GP, LLC from February 2020 through April 2022. Mr. Waldheim served as a director and a member of the Audit, Finance & Risk Committee of Enbridge Energy Company, Inc. and Enbridge Energy Management, L.L.C. from February 2016 through December 2018. He previously served as President of DCP Midstream LP where he had overall responsibility for DCP Midstream’s affairs including commercial, trading, and business development until his retirement in 2015. Prior to this, Mr. Waldheim was President of Midstream Marketing and Logistics for DCP Midstream and managed natural gas, crude oil, and natural gas liquids marketing and logistics. From 2005 to 2008, he was Group Vice President of Commercial for DCP Midstream, managing its upstream and downstream commercial business. Mr. Waldheim started his professional career in 1978 with Champlin Petroleum as an auditor and financial analyst and served in roles involving NGL and crude oil distribution and marketing. He served as Vice President of NGL and Crude Oil Marketing for Union Pacific Fuels from 1987 until 1998 at which time it was acquired by DCP Midstream.
Mr. Waldheim was selected to serve on the Board because of his broad and extensive experience in senior leadership roles in the energy industry and his financial and accounting expertise.
Bradford D. Whitehurst has served on the Board since April 2019. Since November 2022, Mr. Whitehurst has served as the Executive Vice President of Tax and Corporate Initiatives of the general partner of Energy Transfer. From January 2021 through November 2022, Mr. Whitehurst was the Chief Financial Officer of the general partner of Energy Transfer. Prior to that, Mr. Whitehurst served as their Executive Vice President – Head of Tax since August 2014. Mr. Whitehurst also served as the Chief Financial Officer of the general partner of ETO from January 2021 until its merger into Energy Transfer in April 2021, and prior to that was their Executive Vice President – Head of Tax since August 2014. Prior to joining Energy Transfer, Mr. Whitehurst was a partner in the Washington, DC office of Bingham McCutchen LLP and an attorney in the Washington, DC offices of both McKee Nelson LLP and Hogan & Hartson. Mr. Whitehurst has specialized in partnership taxation and has advised Energy Transfer LP in his role as outside counsel since 2006.
Mr. Whitehurst was selected to serve on the Board because of his strong background in the energy sector and specialized knowledge of the taxation structure and issues unique to partnerships.
John L. Wortham has served on the Board since March 2024. Mr. Wortham has over 40 years of experience in the energy industry. Mr. Wortham worked at Energy Transfer from 2002 until his retirement in October 2020, most recently as a Senior Director of Business Development and before that as a Senior Director of Gas Supply- Long Term Gas Contracts. Prior to that, Mr. Wortham worked for the energy company Aquila, Inc. (“Aquila”), as a Director of Business Management from 1993 until 2002, when Energy Transfer acquired certain of Aquila’s assets. Mr. Wortham has also worked in various other roles in the energy industry since 1980. Mr. Wortham graduated from Texas Christian University in 1973 with a business management degree.
Mr. Wortham was selected to serve on the Board based on his 40 years of business experience in the energy and natural gas industry.
James M. Wright, Jr. has served on the Board since April 2024. Mr. Wright was appointed as Executive Vice President, General Counsel and Chief Compliance Officer of the general partner of Energy Transfer in December 2022. He became Executive Vice President - Legal and Chief Compliance Officer of Energy Transfer’s general partner in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Mr. Wright has been a part of the Energy Transfer legal team with increasing levels of responsibility since July 2005 and has held various senior-level positions in the legal department including General Counsel of the general partner of Energy Transfer Partners, L.P. from December 2015 to October 2018 and Deputy General Counsel from May 2008 to December 2015. Prior to joining Energy Transfer, Mr. Wright gained significant experience at Enterprise Products Partners, L.P., El Paso Corp., Sonat Exploration Company and KPMG Peat Marwick LLP. Mr. Wright earned a Bachelor of Business Administration degree in Accounting and Finance from Texas A&M University and a JD from South Texas College of Law.
Mr. Wright was selected to serve on the Board because of his decades of legal experience and corporate governance in the energy sector.
Delinquent Section 16(a) Reports
Section 16(a) of the Exchange Act requires that the members of the Board, our executive officers, and persons who own more than 10 percent of a registered class of our equity securities file initial reports of ownership and reports of changes in ownership of our common units and other equity securities with the SEC and any exchange or other system on which such securities are traded or quoted. To our knowledge and based solely on a review of Section 16(a) forms filed electronically with the SEC, we believe that all reporting obligations of the members of the Board, our executive officers and greater than 10 percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2024.
Common Unit Ownership by Directors and Executive Officers
We encourage our directors and executive officers to invest in and retain ownership of our common units, but we do not require such individuals to establish and maintain a particular level of ownership.
Reimbursement of Expenses of the General Partner
The General Partner does not receive any management fee or other compensation for its management of us, but we reimburse the General Partner and its affiliates for all expenses incurred on our behalf, including the compensation of employees of the General Partner or its affiliates that perform services on our behalf. These expenses include all expenditures necessary or appropriate to the conduct of our business and that are allocable to us. The Partnership Agreement provides that the General Partner will determine in good faith the expenses that are allocable to us. There is no cap on the amount that may be paid or reimbursed to the General Partner or its affiliates for compensation or expenses incurred on our behalf.
ITEM 11. Executive Compensation
As is commonly the case with publicly traded limited partnerships, we have no officers, directors, or employees. Under the terms of the Partnership Agreement, we are ultimately managed by the General Partner, which is controlled by Energy Transfer. All of our employees, including our executive officers, are employees of USA Compression Management Services, LLC (“USAC Management”), a wholly owned subsidiary of the General Partner. References to “our officers” and “our directors” refer to the officers and directors of the General Partner.
Compensation Discussion & Analysis
Named Executive Officers
The following disclosure describes the executive compensation program for the named executive officers identified below (the “NEOs”). For the year ended December 31, 2024, the NEOs were:
•M. Clint Green, President and CEO;*
•Eric D. Long, Former President and CEO;*
•Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer;**
•G. Tracy Owens, Vice President of Finance and Chief Accounting Officer;**
•Eric A. Scheller, Vice President and Chief Operating Officer;
•Christopher W. Porter, Vice President, General Counsel and Secretary; and
•Sean T. Kimble, Former Vice President, Human Resources.***
*Mr. Long resigned from his position as President and CEO effective October 2, 2024. Effective October 3, 2024, Mr. Green was appointed by the Board as the President and CEO of the Partnership.
**Mr. Paulsen was appointed as Vice President, Chief Financial Officer and Treasurer and designated as the Partnership’s principal financial officer, effective November 18, 2024. Prior to Mr. Paulsen’s appointment, Mr. Owens was designated as the Partnership’s principal financial officer.
***Mr. Kimble left the Partnership on December 6, 2024.
Compensation Philosophy and Objectives
We have consistently based our compensation philosophy and objectives on the premise that a significant portion of each NEO’s total compensation should be incentive-based or “at-risk” compensation. We share Energy Transfer’s philosophy that the NEOs’ total compensation levels should be competitive in the marketplace for executive talent and abilities. The Compensation Committee generally targets a competitive range at or near the 50th percentile of the market for aggregate compensation consisting of the three main components of our compensation program: base salary, annual discretionary cash bonus, and long-term equity incentive awards, including cash restricted unit awards. The Compensation Committee believes that a desirable balance of incentive-based compensation is achieved by: (i) the payment of annual discretionary cash bonuses that consider (a) the achievement of the financial and operational performance objectives for a fiscal year set towards the beginning of such fiscal year and (b) the individual contributions of each NEO to our level of success in achieving the annual financial and operational performance objectives, (ii) the annual grant of time-based restricted phantom unit awards or restricted units under the LTIP, and (iii) the annual grant of time-based cash restricted unit awards under our CRU Plan. These time-based awards are intended to incentivize and retain our key employees for the long-term and motivate them to focus their efforts on increasing the market price of our common units and the level of cash distributions we pay to our common unitholders. The Partnership in 2024 continued its practice of granting restricted unit awards that vest, based generally upon continued employment, at a rate of 60% after the third year of service and the remaining 40% after the fifth year of service. Beginning in December 2024, the Partnership began granting cash restricted unit awards that vest annually in substantially three equal installments over a three-year period, together with restricted unit awards that vest at a rate of 60% after the third year of service and 40% after the fifth year of service, in each case based generally upon continued employment. For 2024, the long-term equity incentive awards to employees were split based on 75% restricted units and 25% cash restricted units.
The following charts illustrate the level of at-risk incentive compensation we awarded in 2024 to Mr. Green, our current CEO and, on an averaged basis, the other NEOs that were serving as executive officers as of December 31, 2024. Compensation has been annualized for our CEO and other NEOs that served for only a portion of 2024. “Variable/at-risk” compensation is comprised of long-term equity incentive awards, including cash restricted unit awards, and annual discretionary cash bonuses, and “fixed” compensation is comprised of base salary and bonuses not contingent on the Partnership’s performance.
Our compensation program is structured to achieve the following:
•compensate executive officers with an industry-competitive total compensation package of competitive base salaries and significant incentive opportunities yielding a total compensation package in a competitive range at or near the 50th percentile of the market;
•attract, retain, and reward talented executive officers and key members of management by providing a total compensation package competitive with those of their counterparts at similarly situated companies;
•motivate executive officers and key employees to achieve strong financial and operational performance;
•ensure that a significant portion of each executive officer’s compensation is performance-based or “at risk” compensation; and
•reward individual performance.
Methodology to Setting Compensation Packages
Our executive compensation program is administered by the Compensation Committee. The Compensation Committee considers market trends in compensation, including the practices of identified competitors, and the alignment of the compensation program with the Partnership’s compensation philosophy described above. Specifically, for the NEOs, the Compensation Committee:
•establishes and approves target compensation levels for each NEO;
•approves Partnership performance measures and goals;
•determines the mix between cash and equity compensation, short-term, and long-term incentives and benefits;
•verifies the achievement of previously established performance goals; and
•approves the resulting cash or equity awards to the NEOs.
The Compensation Committee also considers other factors such as the role, contribution, skills, experience, and performance of an individual relative to his or her peers at the Partnership, and internal compensation levels within Energy Transfer and its subsidiaries (the “Energy Transfer Group”). The Compensation Committee does not assign a specific weight to these factors, but rather makes a subjective judgment taking all of these factors into account. The Compensation Committee consults with and receives guidance and input, as appropriate, from our CEO, Energy Transfer’s Co-CEO, and executives from Energy Transfer’s Human Resources team to ensure compensation decisions are undertaken consistent with the relevant compensation philosophy and objectives of the Energy Transfer Group.
The Compensation Committee reviews and approves all compensation for the NEOs. In determining the compensation for the NEOs, the Compensation Committee takes into account input and recommendations from the CEO with respect to the compensation of the other NEOs. In this context, the CEO considers comparative compensation data and evaluates the individual performance of each of the other NEOs and their respective contributions to the Partnership. The recommendations from the CEO are then reviewed by the Compensation Committee, which may accept the recommendations or make adjustments to the recommended compensation based on the Compensation Committee’s assessment of the individual’s performance, contributions to the Partnership, and internal compensation levels within the Energy Transfer Group. The CEO’s compensation is reviewed and approved by the Compensation Committee based on comparative compensation data, including within the Energy Transfer Group, and the Compensation Committee’s independent evaluation of the CEO’s actual or expected contributions to the Partnership’s performance.
The Compensation Committee periodically compares results for the annual base salary, annual cash bonus, and long-term equity incentive awards of the NEOs against data for compensation levels for specific executive positions reported in published executive compensation surveys within each of the (i) energy industry and (ii) overall market. The Compensation Committee also reviews publicly filed peer group executive compensation disclosures pertaining to certain executive roles, utilizing this data as an important reference point.
Periodically, we engage a third-party consultant to provide the Compensation Committee with market information regarding compensation levels at peer companies to assist in evaluating compensation levels for our executives, including the NEOs. In 2023, we engaged Meridian Compensation Partners, LLC (“Meridian”), the independent compensation advisor to Energy Transfer, to conduct a report on market information and compensation levels of our peer companies (the “2023 Meridian Report”). The Compensation Committee utilized the 2023 Meridian Report when setting NEO compensation for the 2024 year. During 2024, it relied on the results of the 2023 Meridian Report for information on base salary, bonus, and general
compensation items for 2024 for the NEOs. The Compensation Committee also utilized the 2023 Meridian Report when determining the value of equity awards that should be granted to our NEOs in December 2024.
In connection with the engagement of Meridian for the 2023 Meridian Report, based on the information presented to it, the Compensation Committee assessed the independence of Meridian under applicable SEC and NYSE rules and concluded that Meridian’s work for the Compensation Committee did not raise any conflicts of interest.
For purposes of the 2023 Meridian Report, our peer group included the following companies:
| | | | | | | | |
| Company | | Ticker |
| 1. Antero Midstream Corporation | | AM |
| 2. Archrock, Inc. | | AROC |
| 3. Cactus, Inc. | | WHD |
| 4. Enerflex Ltd. | | EFX.TO |
| 5. EnLink Midstream, LLC | | ENLC |
| 6. Expro Group Holdings N.V. | | XPRO |
| 7. Genesis Energy, L.P. | | GEL |
| 8. Helmerich & Payne, Inc. | | HP |
| 9. Kodiak Gas Services, Inc. | | KGS |
| 10. NuStar Energy L.P. | | NS |
| 11. Oil States International, Inc. | | OIS |
| 12. Pro Petro Holding Corp. | | PUMP |
| 13. RPC, Inc. | | RES |
| 14. Select Water Solutions, Inc. | | WTTR |
| 15. Summit Midstream Partners, LP | | SMLP |
| 16. Sunoco LP | | SUN |
| 17. TETRA Technologies, Inc. | | TTI |
Elements of the Compensation Program
Compensation for the NEOs primarily consists of the following elements and corresponding objectives:
| | | | | | | | |
| Compensation Element | | Primary Objective |
| Base salary | | To recognize performance of job responsibilities and to attract and retain individuals with superior talent. |
| | |
| Annual incentive compensation | | To promote near-term performance objectives and reward individual contributions to the achievement of those objectives. |
| | |
| Long-term equity incentive awards (Restricted Units and Phantom Units) | | To emphasize long-term performance objectives, encourage the maximization of unitholder value, and retain key executives by providing an opportunity to participate in the ownership of the Partnership. |
| | |
| Long-term equity incentive awards (Cash Restricted Units) | | To emphasize long-term performance objectives, encourage the maximization of unitholder value, and retain key executives by providing an opportunity to benefit from strong unitholder value. |
| | |
| Retirement savings (401(k)) plan | | To provide an opportunity for tax-efficient savings. |
| | |
| Other elements of compensation and perquisites | | To attract and retain talented executives in a cost-efficient manner by providing benefits comparable to those offered by similarly situated companies. |
Base Salary for 2024
Base salaries for the NEOs generally have been set at a level deemed appropriate by the Compensation Committee to attract and retain individuals with superior talent. On an annual basis, base salary increases are determined based on the job responsibilities, demonstrated proficiency and performance of the NEO, and market conditions. The Compensation Committee provided each NEO with an increase to his base salary for the 2024 year, other than Mr. Owens, whose compensation had, at the time of determination of 2024 base salaries, been recently adjusted in connection with being designated the principal financial officer of the Partnership.
The 2024 base salaries and 2023 base salaries for the NEOs, including our current and former CEO, are set forth in the following table:
| | | | | | | | | | | | | | | | | |
| Name and Principal Position | | 2024 Base Salary ($) | | 2023 Base Salary ($) | |
| M. Clint Green, President and Chief Executive Officer | | 500,000 | | (1) | — | | |
| Eric D. Long, Former President and Chief Executive Officer | | 739,783 | | (2) | 711,330 | | |
| Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer | | 425,000 | | (3) | — | | |
| G. Tracy Owens, Vice President of Finance and Chief Accounting Officer | | 325,000 | | | 325,000 | | (4) |
| Eric A. Scheller, Vice President and Chief Operating Officer | | 420,000 | | | 385,000 | | |
| Christopher W. Porter, Vice President, General Counsel and Secretary | | 410,000 | | | 374,400 | | |
| Sean T. Kimble, Former Vice President, Human Resources | | 351,520 | | (5) | 338,000 | | |
________________________(1)Mr. Green joined the Partnership effective October 3, 2024. The amount above reflects his annualized base salary for 2024. Mr. Green received $124,923 in base salary in 2024.
(2)Mr. Long resigned from his positions as President and Chief Executive Officer of the Partnership effective October 2, 2024. Mr. Long remained an employee of the Partnership until his retirement on December 31, 2024.
(3)Mr. Paulsen joined the Partnership effective November 18, 2024. The amount above reflects his annualized base salary for 2024. Mr. Paulsen received $49,038 in base salary in 2024.
(4)Mr. Owens’s base salary was increased to $325,000 effective October 9, 2023 in connection with his designation as principal financial officer of the Partnership. The amount above reflects his annualized base salary for 2023 after this increase. Mr. Owens received $300,102 in base salary in 2023.
(5)Mr. Kimble left the Partnership effective December 6, 2024. The amount above reflects his annualized base salary for 2024. Mr. Kimble received $331,240 in base salary in 2024.
Annual Cash Incentive Compensation for 2024
Each of the NEOs is entitled to participate in the USA Compression Partners, LP Amended and Restated Annual Cash Incentive Plan (the “Bonus Plan”) and their potential bonus is governed by the Bonus Plan and, for Messrs. Porter and Kimble, also governed by their respective employment agreements. The Compensation Committee acts as the administrator of the Bonus Plan under the supervision of the full Board, and has the discretion to amend, modify, or terminate the Bonus Plan at any time.
In February 2025, the Compensation Committee made the determination to pay annual cash bonus awards to executives, including certain NEOs, under the Bonus Plan attributable to the year ended December 31, 2024. Although the funding of the Bonus Plan generally is based on our satisfaction of certain performance measures that were previously established for the 2024 year, the Compensation Committee retains the authority to use its business judgement to make decisions or adjustments to the Bonus Plan’s funding pool or the individual bonus awards resulting from the guidelines set forth below. The Bonus Plan contains four payout factors and corresponding percentages that comprise the total annual target bonus for all eligible employees, including the NEOs (the “Annual Target Bonus Pool”), as shown in the following chart.
| | | | | | | | |
| Bonus Plan Payout Factors |
| Payout Factor | | % of Total Annual Target Bonus |
| Adjusted EBITDA Budget Target Payout Factor | | 30% |
| Distributable Cash Flow Budget Target Payout Factor | | 30% |
| Leverage Ratio Budget Target Payout Factor | | 30% |
| Safety Budget Target Payout Factor | | 10% |
Each of the Adjusted EBITDA Budget Target Payout Factor (the “Adjusted EBITDA Factor”) and the Distributable Cash Flow, or DCF, Budget Target Payout Factor (the “DCF Factor”) assign payout factors from 0% to 120% based on the percentage of the Partnership’s budgeted Adjusted EBITDA and DCF, respectively, achieved for the year, as shown in the following chart. See Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Measures” for definitions of these non-GAAP measures as well as reconciliations of each measure to its most directly comparable financial measure(s) calculated and presented in accordance with GAAP.
| | | | | | | | |
| Adjusted EBITDA and DCF Factors |
| % of Budget Target | | Bonus Pool Payout Factor |
| Greater than or equal to 110% | | 1.20x |
| 109.9% – 105.0% | | 1.10x |
| 104.9% – 95.0% | | 1.00x |
| 94.9% – 90.0% | | 0.90x |
| 89.9% – 80.0% | | 0.75x |
| Less than 80.0% | | 0.00x |
For the 2024 year, the Compensation Committee set the Adjusted EBITDA Budget Target at $567.3 million and the DCF Budget Target at $351.0 million.
The Leverage Ratio Budget Target Payout Factor (the “Leverage Ratio Factor”) assigns payout factors based on the Partnership’s achievement of its budgeted Leverage Ratio (as defined in the Partnership’s Credit Agreement, provided that, for
purposes of calculating the Leverage Ratio for the Bonus Plan, EBITDA attributable to the full plan year is used in lieu of any other time period) for the year, as shown in the following chart.
| | | | | | | | |
| Leverage Ratio Factor |
| Range within Budget Target | | Bonus Pool Payout Factor |
| More than 0.250 below budget target | | 1.20x |
| 0.250 – 0.125 below | | 1.10x |
| 0.124 below – 0.125 above | | 1.00x |
| 0.126 – 0.375 above | | 0.70x |
| 0.376 – 0.500 above | | 0.50x |
| Greater than 0.500 above | | 0.00x |
For the 2024 year, the Compensation Committee set the Leverage Ratio Budget Target at 4.10x.
The Safety Budget Target Payout Factor (the “Safety Factor”) assigns payout factors based on the Partnership’s Total Recordable Incident Rate, or TRIR (as calculated by the U.S. Occupational Safety and Health Administration), against the Partnership’s TRIR target, as shown in the following chart.
| | | | | | | | |
| Safety Factor |
| % of Target | | Bonus Pool Payout Factor |
| Less than 100% | | 1.00x |
| 100% – 105% | | 0.90x |
| 105.1% – 110% | | 0.80x |
| 110.1% – 115% | | 0.70x |
| 115.1% – 125% | | 0.60x |
| Greater than 125% | | 0.00x |
For the 2024 year, the Compensation Committee set the Safety Target (as defined in the Bonus Plan) at 1.0.
The establishment and amount of the bonus pool is 100% discretionary and subject to approval and/or adjustment by the Compensation Committee. In determining bonuses for the NEOs, the Compensation Committee takes into account whether the Partnership achieved or exceeded its targeted performance objectives. In the case of the NEOs, their bonus pool targets for the 2024 year range from 50% to 130% of their respective annual base salary.
For the 2024 year, the Compensation Committee set a target bonus amount (the “Target Bonus”) for Messrs. Long, Owens, Scheller, Porter and Kimble prior to the first quarter of the 2024 year, which was set as a percentage of the NEO’s base salary. The Target Bonus for Mr. Green was set by the Compensation Committee in connection with his appointment in October 2024. For the bonus applicable to the 2024 year, the Target Bonus, as a percentage of base salary and as a dollar amount, is reflected in the table below.
| | | | | | | | | | | | | | | | | |
| Name | | Percentage of Base Salary | | Target
Amount ($) | |
| M. Clint Green, President and Chief Executive Officer | | 130 | % | | 650,000 | | (1) |
| Eric D. Long, Former President and Chief Executive Officer | | 130 | % | | 961,718 | | |
| Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer | | — | | | — | | (2) |
| G. Tracy Owens, Vice President of Finance and Chief Accounting Officer | | 50 | % | | 162,500 | | |
| Eric A. Scheller, Vice President and Chief Operating Officer | | 100 | % | | 420,000 | | |
| Christopher W. Porter, Vice President, General Counsel and Secretary | | 100 | % | | 410,000 | | |
| Sean T. Kimble, Former Vice President, Human Resources | | 90 | % | | 316,368 | | |
________________________
(1)Final bonus payout for Mr. Green was prorated based on the amount of time the NEO was employed with the Partnership during the year ended December 31, 2024.
(2)Mr. Paulsen did not have a Target Bonus allocation for 2024. Instead, his offer letter provided for payment of a sign-on bonus in the amount of $125,000 to be payable at the same time annual bonus awards were paid to our NEOs.
The annual cash bonus pool targets for 2024 were based on the determination of the Compensation Committee and in the case of Messrs. Long, Owens, Scheller, Porter, and Kimble in accordance with Meridian review, and in consideration of the available compensation data and the role, contribution, skills, experience, and performance of an individual relative to his or her peers at the Partnership.
Target Bonuses, if any, are paid within one week following delivery by our independent auditor of the audit of our financial statements for the year to which the Target Bonus relates, but in any case, no later than March 15 of the year following the year to which the Target Bonus relates. For the year ended December 31, 2024, we achieved (i) Adjusted EBITDA of $584,282,000 resulting in an Adjusted EBITDA Bonus Pool Payout Factor of 1.00; (ii) DCF of $355,317,000, resulting in a DCF Bonus Pool Payout Factor of 1.00; (iii) Leverage Ratio, as calculated for the purposes of the Bonus Plan, of 4.211x, resulting in a Leverage Ratio Bonus Pool Payout Factor of 1.00; and (iv) a TRIR of 0.81 resulting in a Safety Bonus Pool Payout Factor of 1.00. Based on these payout factors, the awards made pursuant to the Bonus Plan with respect to the year ended December 31, 2024 equal 100% of each NEO’s Target Bonus and were as follows:
| | | | | | | | | | | |
| Name (1) | | Bonus ($) | |
| M. Clint Green, President and Chief Executive Officer | | 162,500 | | (2) |
| Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer | | — | | (3) |
| G. Tracy Owens, Vice President of Finance and Chief Accounting Officer | | 162,500 | | |
| Eric A. Scheller, Vice President and Chief Operating Officer | | 420,000 | | |
| Christopher W. Porter, Vice President, General Counsel and Secretary | | 410,000 | | |
________________________
(1)Messrs. Long and Kimble left the Partnership prior to the payout of the Target Bonuses for the year ended December 31, 2024. Accordingly, no bonus payment was made to them for 2024.
(2)Mr. Green’s Target Bonus payout was prorated based on the amount of time he was employed with the Partnership during the year ended December 31, 2024.
(3)Mr. Paulsen did not have a Target Bonus allocation for 2024. Instead, his offer letter provided for payment of a sign-on bonus in the amount of $125,000 to be payable at the same time annual bonus awards were paid to our NEOs.
Amounts received on or after October 2, 2023 by the NEOs pursuant to the Bonus Plan are subject to certain clawback policies, and may be subject to repayment in part or in full if the Partnership is required to prepare an accounting restatement.
Long-Term Equity Incentive Awards
As noted above, while the Partnership has historically granted awards of phantom units (“Phantom Units”), beginning in December 2024, the Partnership began granting awards of cash restricted units (“CRSUs”) together with awards of restricted units (“RSUs”). The vesting terms of these awards and the target award levels for the 2024 RSUs and CRSUs are described below.
Long-Term Restricted Unit Awards
The LTIP is designed to promote our interests, as well as the interests of our unitholders, by rewarding our officers, directors, and certain of our employees for delivering desired performance results, as well as by strengthening our ability to attract, retain, and motivate qualified individuals to serve as officers, directors, and employees. The LTIP provides for the grant, from time to time at the discretion of the Compensation Committee, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, DERs, and other common unit-based awards, although since our initial public offering in 2013, the Compensation Committee has only granted awards of Phantom Units and RSUs with DERs under the LTIP. The Compensation Committee acts as the administrator of the LTIP. Each Phantom Unit and RSU represents the right to receive a common unit or, in the case of Phantom Units, an amount of cash equal to the fair market value of a common unit (or a combination thereof), upon the vesting of such Phantom Unit or RSU pursuant to the LTIP, the applicable award agreement thereunder (“Phantom Unit Agreement” or “Restricted Unit Agreement”, respectively), and as determined by the Compensation Committee in its discretion. The outstanding, unvested Phantom Units and RSUs granted under the LTIP and held by the NEOs are reflected below in “– Outstanding Equity Awards as of December 31, 2024.”
Each of our current Phantom Unit Agreement and Restricted Unit Agreement provides for (i) incremental vesting over five years in two tranches ((a) 60% on the third December 5 following the grant and (b) 40% on the fifth December 5 following the grant) and (ii) vesting of 100% of the outstanding, unvested Phantom Units or RSUs in the event of (a) a Change in Control (as defined under the LTIP and set forth below under “Potential Payments upon Termination or Change in Control”) or (b) the NEO’s death or Disability (as defined under the LTIP and set forth below under “Potential Payments upon Termination or Change in Control”). Additionally, the Phantom Unit Agreement provides for (i) vesting of 40% of the outstanding, unvested
Phantom Units if the NEO voluntarily retires between the ages of 65–68 and has been employed by us, the General Partner, or our affiliates for at least 10 years (with the remaining 60% being forfeited), and (ii) vesting of 50% of the outstanding, unvested Phantom Units if the NEO voluntarily retires at or over the age 68 and has been employed by us, the General Partner, or our affiliates for at least 10 years (with the remaining 50% being forfeited). The Restricted Unit Agreement similarly provides for (i) vesting of 40% of the outstanding, unvested RSUs if the NEO voluntarily retires between the ages of 65–68, has been employed by us, the General Partner, or our affiliates for at least five years, and has held the award for at least a year (with the remaining 60% being forfeited), and (ii) vesting of 50% of the outstanding, unvested RSUs if the NEO voluntarily retires at or over the age 68, has been employed by us, the General Partner, or our affiliates for at least five years, and has held the award for at least a year (with the remaining 50% being forfeited). The vesting of the Phantom Units and RSUs are subject, in each case described above, to the NEO’s continued employment with us, the General Partner, or our affiliates until the relevant vesting date.
Cash Restricted Unit Awards
The CRU Plan was adopted by our Compensation Committee and became effective December 1, 2024. Under the CRU Plan, our Compensation Committee, in its discretion, may grant awards of CRSUs, upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the CRU Plan. Each CRSU entitles the award recipient to receive cash equal to the market value of one common unit upon vesting, pursuant to the applicable award agreement thereunder (“Cash Restricted Unit Agreement”). The CRSUs do not include rights to DER cash payments. Awards from the CRU Plan are used to incentivize and reward eligible employees over a long-term basis.
Our Cash Restricted Unit Agreement provides for (i) incremental vesting over a three-year period, with 1/3 of the CRSUs subject to the award vesting on December 5 of each year, (ii) vesting of 100% of the outstanding, unvested CRSUs in the event of (a) a Change in Control (as defined under the CRU Plan and set forth below under “Potential Payments upon Termination or Change in Control”) or (b) the NEO’s death or Disability (as defined under the CRU Plan and set forth below under “Potential Payments upon Termination or Change in Control”), (iii) vesting of 40% of the outstanding, unvested CRSUs if the NEO voluntarily retires between the ages of 65–68, has been employed by us, the General Partner, or our affiliates for at least five years, and has held the award for at least one year (with the remaining 60% being forfeited), and (iv) vesting of 50% of the outstanding, unvested CRSUs if the NEO voluntarily retires at or over the age 68, has been employed by us, the General Partner, or our affiliates for at least five years, and has held the award for at least one year (with the remaining 50% being forfeited). The vesting of the CRSUs are subject, in each case, to the NEO’s continued employment with us until the relevant vesting date.
The target level of annual long-term incentive awards granted in 2024 for each of the NEOs is expressed below as a percentage of the NEO’s base salary. As described above, these awards were split in 2024 based on 75% RSUs and 25% CRSUs. In determining the level of the 2024 grants of long-term incentive awards to the NEOs, the Compensation Committee, taking into account the role, contribution, skills, experience, and performance of an NEO relative to his or her peers at the Partnership, award levels within the Energy Transfer Group, and market and other relevant data, determined each of the NEO’s long-term incentive targets. The base salaries used for these calculations were the base salaries for the 2024 calendar year. The Compensation Committee set a long-term incentive award target amount for Mr. Paulsen, which were based on the factors described above, in connection with his appointment to his position in November 2024. The long-term incentive targets are used as the basis to determine the target number of units to be awarded to the eligible participant, including the NEOs. For 2024, the Partnership utilized a 60 trading-day trailing weighted average price of the Partnership’s common units prior to November 1, 2024 to determine the target number of units to be awarded. The Compensation Committee set long-term incentive award target amounts for Messrs. Green, Scheller and Porter in December 2024, which are shown in the following table:
| | | | | | | | | | | | | | |
| Long-Term Incentive Target Amounts Awarded December 5, 2024 |
| Name (1)(2) | | Percentage of
Base Salary | | Grant Date Amount ($) |
| M. Clint Green, President and Chief Executive Officer | | 500 | % | | 2,500,000 | |
| Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer (3) | | 250 | % | | 1,668,803 | |
| Eric A. Scheller, Vice President and Chief Operating Officer | | 200 | % | | 840,000 | |
| Christopher W. Porter, Vice President, General Counsel and Secretary | | 200 | % | | 820,000 | |
________________________
(1)Mr. Kimble left the Partnership, and Mr. Long resigned from his executive offices, prior to the grant of the long-term incentive target awards for 2024. Accordingly, no such awards were granted to Messrs. Long or Kimble for 2024.
(2)Mr. Owens did not receive a long-term incentive target award in December 2024.
(3)Mr. Paulsen’s long-term incentive target amount was set at 250% of his base salary, or $1,062,500, however he also received a one-time sign-on bonus of additional long-term incentive awards, bringing the grant date value of his total award to $1,668,803.
Under the LTIP, the Compensation Committee has the discretion to determine whether any portion of awards should be settled in cash upon vesting. The Restricted Unit Agreements do not allow for cash settlement of the RSUs. The Phantom Unit Agreements do allow for cash settlement of the Phantom Units at the discretion of the Compensation Committee. On December 5, 2024, the Compensation Committee approved the current default settlement method for Phantom Units of 50% in cash (valued based on the 10 day volume weighted average closing price on the NYSE of the Partnership’s common units in advance of the vesting date) and 50% in common units for all vesting of Phantom Units occurring during 2025. However, the Compensation Committee has also specified that employees may elect to decrease the percentage of this cash settlement. If an employee affirmatively requests in writing that the percentage of cash settlement be set at a specific amount that is less than 50% (and such employee agrees to pay out of his or her own funds the amount of any required federal withholding to the extent that the cash portion is insufficient for the Partnership to withhold and pay such amounts on the employee’s behalf), the Compensation Committee approves in advance such lesser cash settlement percentage.
Each award of RSUs and Phantom Units granted to an employee, including the NEOs, is granted in tandem with a corresponding award of DERs, which entitles the recipient to receive an amount in cash on a quarterly basis equal to the product of (a) the number of RSUs and Phantom Units granted under such award to the grantee that remain outstanding and unvested as of the record date for the distribution on the Partnership’s common units for such quarter and (b) the quarterly distribution with respect to the Partnership’s common units. The CRSUs are not granted with a corresponding DER.
The Phantom Units are granted pursuant to the LTIP are subject to certain clawback features, and the award may not vest or settle if we determine that the recipient committed certain acts of misconduct, as more particularly described in the LTIP.
Benefit Plans and Perquisites
We provide the NEOs with certain other benefits and perquisites, which we do not consider to be a significant component of our overall executive compensation program, but which we recognize as an important factor in attracting and retaining talented executives. The NEOs are eligible under the same plans as all other employees with respect to (i) medical, dental, vision, disability, and life insurance benefits and (ii) a defined contribution plan that is tax-qualified under Section 401(k) of the Internal Revenue Code (the “401(k) Plan”). In addition, we have provided one or more NEOs with an annual automobile allowance and club memberships. The Compensation Committee has determined it is appropriate to offer these perquisites in order to provide compensation opportunities competitive with those offered by similarly situated public companies. In determining the compensation payable to the NEOs, the Compensation Committee considers perquisites in the context of the total compensation the NEOs are eligible to receive. However, given the fact that perquisites represent a relatively small portion of the NEOs’ total compensation, the availability of these perquisites does not materially influence the Compensation Committee’s decision making with respect to other elements of the NEOs’ total compensation. The value of personal benefits and perquisites we provided to each of the NEOs in 2024 is set forth below in “– Summary Compensation Table.”
Sign-On Bonus
The Compensation Committee granted Mr. Paulsen a one-time signing bonus consisting of (i) $125,000, to be paid in cash at the same time as other awards under the Bonus Plan and (ii) a one-time special sign on award of 75,000 units (split 75% RSUs and 25% CRSUs).
Energy Transfer LP Non-Qualified Deferred Compensation Plan (the “Energy Transfer NQDC Plan”)
As part of our shared services integration with Energy Transfer, beginning in 2025 our NEOs, along with certain other highly compensated employees, are eligible to participate in Energy Transfer’s deferred compensation plan, which permits eligible highly compensated employees to defer a portion of their salary, bonus, and/or quarterly non-vested phantom or restricted unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Each year under the Energy Transfer NQDC Plan, eligible employees are permitted to make an irrevocable election to defer up to 50% of their annual base salary, 50% of their quarterly non-vested phantom or restricted unit distribution income, and/or 50% of their discretionary performance bonus compensation during the following year. Pursuant to the Energy Transfer NQDC Plan, Energy Transfer may make annual discretionary matching contributions to participants’ accounts; however, Energy Transfer has not made any discretionary contributions to participants’ accounts and currently has no plans to make any discretionary contributions to participants’ accounts. All amounts credited under the Energy Transfer NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed earnings or losses based on hypothetical investment fund choices made by the participants among available funds.
Participants may elect to have their account balances distributed in one lump sum payment or in annual installments over a period of three or five years upon retirement, and in a lump sum upon other termination events. Participants may also elect to take lump-sum in-service withdrawals five years or longer in the future, and such scheduled in-service withdrawals may be further deferred prior to the withdrawal date. Upon a change in control (as defined in the Energy Transfer NQDC Plan) of Energy Transfer, all Energy Transfer NQDC Plan accounts are immediately vested in full. However, distributions are not accelerated and, instead, are made in accordance with the Energy Transfer NQDC Plan’s normal distribution provisions unless a participant has elected to receive a change of control distribution pursuant to his deferral agreement.
Employment Agreements
Mr. Porter is, and prior to his departure Mr. Kimble was, party to an employment agreement with us (together, the “Employment Agreements”). Mr. Porter’s Employment Agreement has been extended on a year-to-year basis and will be automatically extended for successive twelve-month periods unless either party delivers written notice to the other at least 90 days prior to the end of the current employment term. Please see the description of the Employment Agreements under “Potential Payments upon Termination or Change in Control” for further details on the terms of the Employment Agreements.
Separation Agreements
Mr. Long retired from the Partnership effective December 31, 2024, and prior to that resigned from his position as President and CEO effective October 2, 2024. In recognition of his service and contributions to the Partnership, the Compensation Committee approved the following items to be paid or issued to Mr. Long (the “Long Separation Package”) pursuant to a Restrictive Covenant and Separation Agreement and Full Release of Claims (the “Long Separation Agreement”): (i) a lump-sum separation payment of $962,000, (ii) accelerated vesting of 509,974 Phantom Units of the Partnership, (iii) a lump-sum payment equal to 24 months of health-insurance coverage under the Partnership’s health insurance plan and (iv) a lump-sum payment of $25,000 upon execution of a supplemental release. The separation payment and health insurance premiums were paid after the effective date of the Long Separation Agreement. The supplemental release payment will be paid following execution of a supplemental release at the end of the term of Mr. Long’s Consulting Agreement (described below). A portion of the Phantom Units, consisting of 305,984 of the total 509,974 Phantom Units, vested after the effective date of the Long Separation Agreement, of which Mr. Long had the option to settle up to 50% in cash. The vesting of the remaining 203,990 Phantom Units, together with any accrued DERs on such Phantom Units, is delayed in accordance with Section 409A of the Internal Revenue Code (the “Code”), and will vest on July 1, 2025. The Long Separation Package was contingent upon Mr. Long’s execution of, and remains subject to his compliance with, the Long Separation Agreement, pursuant to which he released all claims against us, and which provides for certain non-disparagement, non-solicit, and confidentiality obligations.
In addition, our General Partner and Mr. Long have entered into a consulting agreement (the “Consulting Agreement”) for a period of one year commencing on January 1, 2025. Pursuant to the terms of the Consulting Agreement, in exchange for providing consulting and advisory services to the Partnership and complying with the terms of the Consulting Agreement, including certain non-competition and non-solicitation covenants incorporated by reference in the Long Separation Agreement, Mr. Long will receive a total of $740,000, paid monthly in arrears. As an independent contractor, Mr. Long will not be entitled to participate in or receive any benefit or right as a company employee under the employee benefit plans of the Partnership.
Mr. Kimble’s employment with the Partnership was terminated effective December 6, 2024. In recognition of his service and contributions to the Partnership, and generally consistent with the terms of Mr. Kimble’s Employment Agreement, the Compensation Committee approved the following amounts to be paid to Mr. Kimble: (i) a separation payment of $972,088, (ii) a lump-sum equal to his earned but unused paid time off, and (iii) a lump-sum equal to 24 months of health-insurance coverage under the Partnership’s health insurance plan (collectively, the “Kimble Separation Payment”). The Kimble Separation Payment was contingent upon Mr. Kimble’s execution of, and remains subject to his compliance with, a Restrictive Covenant and Separation Agreement and Full Release of Claims (the “Kimble Separation Agreement”) pursuant to which he released all claims against us, and which provides for certain non-disparagement, non-solicit, and confidentiality obligations. The Kimble Separation Payment will be paid in a lump sum six months after the effective date of the Kimble Separation Agreement, in accordance with Section 409A of the Code.
Risk Assessment Related to Our Compensation Structure
We believe our compensation program for all of our employees, including the NEOs, is appropriately structured and not reasonably likely to result in material risk to us because it is structured in a manner that does not promote excessive risk-taking that could damage our reputation, negatively impact our financial results, or reward poor judgment. We also have allocated our compensation among base salary and short- and long-term compensation in such a way as to not encourage excessive risk-taking. Furthermore, all business groups and employees receive similar compensation components of base pay and short-term incentives. We typically offer long-term equity incentives to employees at the director level or above, and we use RSUs, Phantom Units and CRSUs rather than unit options for these equity awards because these awards retain value even in a
depressed market, so employees are less likely to take unreasonable risks to get or keep options “in-the-money.” Finally, the time-based vesting pursuant to our RSU and Phantom Unit agreements over three to five years, and our time-based vesting pursuant to our CRSU agreement over three years, ensures that our employees’ interests align with those of our unitholders with respect to our long-term performance.
Accounting and Tax Considerations
We account for the equity compensation expense for equity awards granted under our LTIP in accordance with GAAP, which requires us to estimate and record an expense for each equity award over the vesting period of the award. For employees, Phantom Units with a cash settlement option and CRSUs are accounted for as a liability and are re-measured at fair value at the end of each reporting period using the market price of the Partnership’s common units. RSUs without a cash settlement option, as well as Phantom Units granted to outside directors without a cash settlement option, are accounted for as equity. During the requisite service period, compensation cost is recognized using the proportionate amount of the award’s fair value that has been earned through service to date.
Because we are a master limited partnership and the General Partner is a limited liability company, section 162(m) of the Code, which generally precludes public corporations (as defined pursuant to regulations issued under section 162(m)) from taking a tax deduction for individual compensation to certain of its executive officers in excess of $1 million, does not apply to the compensation paid to the NEOs and, accordingly, the Compensation Committee did not consider its impact in making the compensation recommendations discussed above.
Compensation Committee Interlocks and Insider Participation
We do not have any Compensation Committee interlocks. Messrs. Joyce, Waldheim and Wortham are the only members of the Compensation Committee as of February 6, 2024. Our former director, Mr. W. Brett Smith, also served on the Compensation Committee at the beginning of 2024. During 2024, none of Messrs. Joyce, Waldheim, Wortham, or Smith was an officer or employee of Energy Transfer or any of its affiliates, including us, or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors.
Compensation Committee Report
The Compensation Committee has reviewed and discussed the section of this report entitled “Compensation Discussion and Analysis” with management of the Partnership and approved its inclusion in this Annual Report on Form 10-K.
| | |
| Compensation Committee |
| Glenn E. Joyce (Chairman) |
| William S. Waldheim |
| John L. Wortham |
The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this Annual Report on Form 10-K into any filing under the Securities Act of 1933, as amended, or the Exchange Act, except to the extent that we specifically incorporate this information by reference, and otherwise shall not be deemed filed under those Acts.
Summary Compensation Table
The following table provides information concerning compensation of our NEOs for the fiscal years presented below, as applicable.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Name and Principal Position | | Year | | Salary ($) | | Bonus
($) | | Equity
Awards
($) (1) | | Non-Equity Incentive Plan Compensation ($) (2) | | All Other
Compensation
($) (3) | | Total ($) |
| M. Clint Green | | 2024 | | 124,923 | | | — | | | 2,607,876 | | | 162,500 | | | 4,154 | | (9) | 2,899,453 | |
| President and Chief Executive Officer | | | | | | | | | | | | | | |
| Eric D. Long | | 2024 | | 745,474 | | | — | | | 7,019,282 | | (5) | — | | | 2,531,169 | | (6) | 10,295,925 | |
| Former President and Chief Executive Officer | | 2023 | | 711,330 | | | — | | | 3,698,902 | | | 924,729 | | | 1,699,814 | | | 7,034,775 | |
| | 2022 | | 683,972 | | | — | | | 3,556,634 | | | 854,965 | | | 1,556,768 | | | 6,652,339 | |
| Christopher M. Paulsen | | 2024 | | 52,308 | | | 125,000 | | (4) | 1,740,750 | | | — | | | — | | | 1,918,058 | |
| Vice President, Chief Financial Officer and Treasurer | | | | | | | | | | | | | | |
| G. Tracy Owens | | 2024 | | 327,575 | | | — | | | — | | | 162,500 | | | 91,136 | | | 581,211 | |
| Vice President of Finance and Chief Accounting Officer | | 2023 | | 300,102 | | | — | | | 199,990 | | | 150,362 | | | 95,091 | | | 745,545 | |
| Eric A. Scheller | | 2024 | | 423,328 | | | — | | | 876,178 | | | 420,000 | | | 389,865 | | | 2,109,371 | |
| Vice President and Chief Operating Officer | | 2023 | | 385,000 | | | — | | | 1,224,995 | | | 385,000 | | | 377,573 | | | 2,372,568 | |
| | 2022 | | 360,500 | | | — | | | 769,997 | | | 324,450 | | | 298,387 | | | 1,753,334 | |
| Christopher W. Porter | | 2024 | | 413,248 | | | — | | | 855,289 | | | 410,000 | | | 346,074 | | | 2,024,611 | |
| Vice President, General Counsel and Secretary | | 2023 | | 374,400 | | | — | | | 819,978 | | | 336,960 | | | 354,327 | | | 1,885,665 | |
| | 2022 | | 360,000 | | | — | | | 748,798 | | | 324,000 | | | 307,310 | | | 1,740,108 | |
| Sean T. Kimble | | 2024 | | 331,240 | | | — | | | — | | | — | | | 1,345,813 | | (7) | 1,677,053 | |
| Former Vice President, Human Resources | | 2023 | | 338,000 | | | — | | | 615,159 | | | 304,200 | | | 324,521 | | | 1,581,880 | |
| | 2022 | | 325,000 | | | 9,750 | | (8) | 591,496 | | | 292,500 | | | 298,908 | | | 1,517,654 | |
________________________(1)Equity award amounts reflect the aggregate grant date fair value of the awards calculated in accordance with the Financial Accounting Standards Board’s (“FASB”) Accounting Standard Codification (“ASC”) Topic 718, disregarding the estimated likelihood of forfeitures. For a discussion of the assumptions utilized in determining the fair value of these awards, please see Note 15 in Part II, Item 8 “Financial Statements and Supplementary Data”. Although the CRSU awards may only be settled in cash, they are based upon the value of USAC common units and are accounted for as equity awards within these compensation tables.
(2)Represents the awards earned under the Bonus Plan for each of the NEOs. Amounts earned for the 2024 year will be paid after the Partnership’s audited financials are finalized.
(3)See the chart below for a detailed breakdown of amounts reported in this column for 2024:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Name | | DERs | | Automobile Allowance | | Employer 401(k) Contributions | | Club Membership Dues | | Parking | | |
| Mr. Green | | $ | — | | — | | $ | 4,154 | | — | | $ | 0 | | |
| Mr. Long | | $ | 1,476,781 | | $ | 18,001 | | $ | 17,250 | | $ | 18,013 | | $ | 9,186 | | |
| Mr. Paulsen | | $ | — | | — | | $ | — | | — | | $ | 0 | | |
| Mr. Owens | | $ | 74,168 | | — | | $ | 15,500 | | — | | $ | 1,468 | | |
| Mr. Scheller | | $ | 371,641 | | — | | $ | 17,250 | | — | | $ | 974 | | |
| Mr. Porter | | $ | 325,750 | | — | | $ | 16,558 | | — | | $ | 3,766 | | |
| Mr. Kimble | | $ | 270,268 | | — | | $ | 16,562 | | — | | $ | 3,263 | | |
We have included distribution payments in connection with distribution equivalent rights on unvested Phantom Unit awards. See notes (6) and (7) below for additional amounts included for Messrs. Long and Kimble, respectively. See note (9) below regarding certain benefits provided to Mr. Green during 2024.
(4)In 2024, Mr. Paulsen received a one-time cash signing bonus of $125,000, which will be paid at the same time as the bonus amounts under the Bonus Plan.
(5)Mr. Long retired from the Partnership on December 31, 2024. Pursuant to the Long Separation Agreement and subject to certain covenants contained therein, 100% of his unvested Phantom Units vested or will vest in connection with his retirement. Under the terms of Mr. Long’s award agreements for these Phantom Units, which were granted in previous years, 40% of these Phantom Units would vest upon his retirement. The value reported reflects the incremental value associated with modifications to his outstanding Phantom Unit awards in connection with his retirement and with respect to the accelerated vesting of the remaining 60% of these Phantom Units. See Note 15 in Part II, Item 8 “Financial Statements and Supplementary Data” for a discussion of the relevant assumptions used in calculating these amounts pursuant to FASB ASC Topic 718.
(6)In connection with Mr. Long’s retirement, he received a separation payment of $991,938 under the terms of the Long Separation Agreement. The incremental value of his accelerated Phantom Units is reported in the “Equity Awards” column and is not included in this amount. Additionally, the value of the vested Phantom Units Mr. Long was entitled to upon his retirement is not reported in this Summary Compensation Table, as this value was reflected as compensation in the summary compensation tables for the years in which each such award was granted.
(7)Mr. Kimble left the Partnership on December 6, 2024. In connection with his departure, he will receive a separation payment of $1,055,720 under the terms of the Kimble Separation Agreement.
(8)In 2022, Mr. Kimble was granted a one-time lump sum payment of $9,750 by the Compensation Committee.
(9)For administrative reasons, in 2024 Mr. Green remained on Energy Transfer’s employee plans with respect to (i) medical, dental, vision, disability, and life insurance benefits and (ii) a defined contribution plan that is tax-qualified under Section 401(k) of the Code. As part of the shared services model, all USAC employees moved to these Energy Transfer employee plans beginning in 2025. As these benefits were offered to all employees of Energy Transfer during 2024 and to all employees of USAC beginning in 2025, we do not classify these benefits as perquisites.
Grants of Plan-Based Awards during the Year Ended December 31, 2024
The below reflects awards granted to our NEOs under the LTIP and our Bonus Plan during 2024.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Name | | Grant Date | | Approval Date of Equity-Based
Awards | | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) | | All Other Unit Awards: Number of Units
(#) | | Grant Date Fair Value of Unit Awards
($) (6) |
| | | Target ($) | | Maximum ($) | | |
| M. Clint Green | | 10/2/2024 | | | | 650,000 | | | 767,000 | | | | | |
| President and Chief Executive Officer | | 12/5/2024 | | 12/5/2024 | | | | | | 84,270 | | (2) | 1,955,907 | |
| | 12/5/2024 | | 12/5/2024 | | | | | | 28,090 | | (3) | 651,969 | |
| Eric D. Long | | 2/9/2024 | | | | 961,718 | | | 1,134,827 | | | | | |
| Former President and Chief Executive Officer | | 10/2/2024 | | 10/2/2024 | | | | | | 305,984 | | (4) | 7,019,282 | |
| Christopher M. Paulsen (5) | | 12/5/2024 | | 12/5/2024 | | | | | | 56,250 | | (2) | 1,305,563 | |
| Vice President, Chief Financial Officer and Treasurer | | 12/5/2024 | | 12/5/2024 | | | | | | 18,750 | | (3) | 435,188 | |
| G. Tracy Owens | | 2/9/2024 | | | | 162,500 | | | 191,750 | | | | | |
| Vice President of Finance and Chief Accounting Officer | | | | | | | | | | | | |
| Eric A. Scheller | | 2/9/2024 | | | | 420,000 | | | 495,600 | | | | | |
| Vice President and Chief Operating Officer | | 12/5/2024 | | 12/5/2024 | | | | | | 28,310 | | (2) | 657,075 | |
| | 12/5/2024 | | 12/5/2024 | | | | | | 9,440 | | (3) | 219,102 | |
| Christopher W. Porter | | 2/9/2024 | | | | 410,000 | | | 483,800 | | | | | |
| Vice President, General Counsel and Secretary | | 12/5/2024 | | 12/5/2024 | | | | | | 27,640 | | (2) | 641,524 | |
| | 12/5/2024 | | 12/5/2024 | | | | | | 9,210 | | (3) | 213,764 | |
| Sean T. Kimble | | 2/9/2024 | | | | 316,368 | | | 373,314 | | | | | |
| Former Vice President, Human Resources | | | | | | | | | | | | |
________________________
(1)These awards were granted in 2024 pursuant to our Bonus Plan. The potential payout pursuant to these awards could be zero, thus we have not reflected a threshold amount in the table above. Actual amounts earned for 2024 have been reflected within the Summary Compensation Table above, which was prorated for Mr. Green based on the amount of time he was employed with the Partnership during 2024.
(2)The RSUs granted to our NEOs on December 5, 2024 were granted pursuant to our LTIP and will vest incrementally, with 60% of the RSUs vesting on December 5, 2027, and the remaining 40% of the RSUs vesting on December 5, 2029. All these RSUs will also vest in full upon a Change in Control (as defined in the LTIP) or the death or Disability (as defined in the LTIP) of the NEO. If the NEO retires after attaining the age of 65 and has been employed by us, the General Partner, or our affiliates for at least five years, 60% of his then-unvested RSUs granted in 2024 will be forfeited, and the remainder will vest, at the time of retirement. If the NEO is at or over age 68 at the time of retirement and has been employed by us, the General Partner, or our affiliates for at least five years, 50% of his then-unvested RSUs granted in 2024 will be forfeited, and the remainder will vest, at the time of retirement. The retirement provision also requires that the award be held for at least one year after the grant date in order to be eligible for acceleration. The RSUs granted to our NEOs on December 5, 2024 were granted in tandem with a corresponding DER.
(3)The CRSUs granted to our NEOs on December 5, 2024 were granted pursuant to our CRU Plan and will vest over a three-year period with 1/3 of the CRSUs vesting annually beginning on December 5, 2025. All these CRSUs will also vest in full upon a Change in Control (as defined in the CRU Plan) or the death or Disability (as defined in the CRU Plan) of the NEO. If the NEO retires after attaining the age of 65 and has been employed by us, the General Partner, or our affiliates for at least five years, 60% of his then-unvested CRSUs granted in 2024 will be forfeited, and the remainder will vest, at the time of retirement. If the NEO is at or over age 68 at the time of retirement and has been employed by us, the General Partner, or our affiliates for at least five years, 50% of his then-
unvested CRSUs granted in 2024 will be forfeited, and the remainder will vest, at the time of retirement. The retirement provision also requires that the award be held for at least one year after the grant date in order to be eligible for acceleration.
(4)Mr. Long retired from the Partnership on December 31, 2024. Pursuant to the Long Separation Agreement and subject to certain covenants contained therein, 100% of his unvested Phantom Units vested or will vest in connection with his retirement. Under the terms of Mr. Long’s award agreements for these Phantom Units, which were granted in previous years, 40% of these Phantom Units would vest upon his retirement. The value reported reflects the incremental value associated with modifications to his outstanding Phantom Unit awards in connection with his retirement and with respect to the accelerated vesting of the remaining 60% of these Phantom Units.
(5)In lieu of an annual bonus award under our Bonus Plan, Mr. Paulsen received a one-time cash signing bonus of $125,000, which will be paid at the same time as the bonus amounts under the Bonus Plan. The Compensation Committee approved Mr. Paulsen’s long-term equity incentive award target in connection with his appointment in November 2024, however in December 2024 it granted Mr. Paulsen the option to elect a 75% RSU and 25% CRSU split, consistent with the other NEOs.
(6)The reported grant date fair value of unit awards was calculated by multiplying the closing price of the Partnership’s common units on the grant date by the number of units granted, as required by FASB ASC Topic 718. The closing price of the Partnership’s common units was $22.94 on October 2, 2024 and $23.21 on December 5, 2024.
Outstanding Equity Awards as of December 31, 2024
The following table provides information regarding Phantom Units and RSUs granted to the NEOs pursuant to the LTIP, and CRSUs granted pursuant to the CRU Plan, in each of the years ended December 31, 2020, 2021, 2022, 2023 and 2024 that were outstanding as of December 31, 2024, as well as the scheduled vesting schedule for each outstanding award. Potential acceleration events or change in control treatment for these awards are described below in the section titled “Potential Payments upon Termination or Change in Control.” None of the NEOs held any outstanding option awards as of December 31, 2024.
| | | | | | | | | | | | | | | | | |
| Name (8) | | Number of Outstanding Unit Awards
(#) | | | Market Value of Outstanding Unit Awards
($) (10) |
| M. Clint Green, President and Chief Executive Officer | | | | | |
| 2024 RSU Grant | | 84,270 | | (6) | | 1,985,401 | |
| 2024 CRSU Grant | | 28,090 | | (7) | | 661,800 | |
| Eric D. Long, Former President and Chief Executive Officer (9) | | | | | |
| 2020 Grant | | 85,408 | | (1) | | 2,012,212 | |
| 2021 Grant | | 73,152 | | (2) | | 1,723,461 | |
| 2022 Grant | | 193,611 | | (3) | | 4,561,475 | |
| 2023 Grant | | 157,803 | | (4) | | 3,717,839 | |
| Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer | | | | | |
| 2024 RSU Grant | | 56,250 | | (6) | | 1,325,250 | |
| 2024 CRSU Grant | | 18,750 | | (7) | | 441,750 | |
| G. Tracy Owens, Vice President of Finance and Chief Accounting Officer | | | | | |
| 2020 Grant | | 4,822 | | (1) | | 113,606 | |
| 2021 Grant | | 4,010 | | (2) | | 94,476 | |
| 2022 Grant | | 8,165 | | (3) | | 192,367 | |
| 2023 Grant | | 8,532 | | (4) | | 201,014 | |
| Eric A. Scheller, Vice President and Chief Operating Officer | | | | | |
| 2020 Grant | | 19,694 | | (1) | | 463,991 | |
| 2021 Grant | | 19,278 | | (2) | | 454,190 | |
| 2022 Grant | | 41,916 | | (3) | | 987,541 | |
| 2023 February Grant | | 18,753 | | (5) | | 441,821 | |
| 2023 Grant | | 35,836 | | (4) | | 844,296 | |
| 2024 RSU Grant | | 28,310 | | (6) | | 666,984 | |
| 2024 CRSU Grant | | 9,440 | | (7) | | 222,406 | |
| Christopher W. Porter, Vice President, General Counsel and Secretary | | | | | |
| 2020 Grant | | 18,568 | | (1) | | 437,462 | |
| 2021 Grant | | 19,251 | | (2) | | 453,554 | |
| 2022 Grant | | 40,762 | | (3) | | 960,353 | |
| 2023 Grant | | 34,982 | | (4) | | 824,176 | |
| 2024 RSU Grant | | 27,640 | | (6) | | 651,198 | |
| 2024 CRSU Grant | | 9,210 | | (7) | | 216,988 | |
________________________
(1)Includes Phantom Units granted pursuant to the LTIP on December 5, 2020, to the following NEOs, of which the following remain unvested as of December 31, 2024: Mr. Long – 85,408; Mr. Owens – 4,822; Mr. Scheller – 19,694 and Mr. Porter – 18,568. These remaining unvested Phantom Units will vest on December 5, 2025, subject to the terms of the award agreement.
(2)Includes Phantom Units granted pursuant to the LTIP on December 5, 2021, to the following NEOs, of which the following remain unvested as of December 31, 2024: Mr. Long – 73,152; Mr. Owens – 4,010; Mr. Scheller – 19,278 and Mr. Porter – 19,251. These remaining unvested Phantom Units will vest on December 5, 2026, subject to the terms of the award agreement.
(3)Includes Phantom Units granted pursuant to the LTIP on December 5, 2022, to the NEOs as follows: Mr. Long – 193,611; Mr. Owens – 8,165; Mr. Scheller – 41,916 and Mr. Porter – 40,762. The Phantom Units granted on December 5, 2022, vest incrementally, with 60% of the Phantom Units vesting on December 5, 2025, and the remaining 40% of the Phantom Units vesting on December 5, 2027, subject to the terms of the award agreement.
(4)Includes Phantom Units granted pursuant to the LTIP on December 5, 2023, to the NEOs as follows: Mr. Long – 157,803; Mr. Owens – 8,532; Mr. Scheller – 35,836 and Mr. Porter – 34,982. The Phantom Units granted on December 5, 2023, vest incrementally, with 60% of the Phantom Units vesting on December 5, 2026, and the remaining 40% of the Phantom Units vesting on December 5, 2028, subject to the terms of the award agreement.
(5)Mr. Scheller was awarded an LTIP award on February 17, 2023 for 18,753 Phantom Units, with 60% of the Phantom Units vesting on December 5, 2025, and the remaining 40% of the Phantom Units vesting on December 5, 2027, subject to the terms of the award agreement.
(6)Includes RSUs granted pursuant to the LTIP on December 5, 2024, to the NEOs as follows: Mr. Green – 84,270; Mr. Paulsen – 56,250; Mr. Scheller – 28,310; and Mr. Porter – 27,640. The RSUs granted on December 5, 2024, vest incrementally, with 60% of the RSUs vesting on December 5, 2027, and the remaining 40% of the Phantom Units vesting on December 5, 2029, subject to the terms of the award agreement.
(7)Includes CRSUs granted pursuant to the CRU Plan on December 5, 2024, to the NEOs as follows: Mr. Green – 28,090; Mr. Paulsen –18,750; Mr. Scheller – 9,440; and Mr. Porter – 9,210 CRSUs. The CRSUs granted on December 5, 2024 vest 1/3 on each of December 5, 2025, 2026 and 2027, subject to the terms of the award agreement.
(8)Mr. Kimble left the Partnership effective December 6, 2024, at which time Mr. Kimble’s unvested equity awards were forfeited.
(9)Mr. Long retired from the Partnership on December 31, 2024. Pursuant to the Long Separation Agreement, following execution of such agreement and the expiration of a seven (7) day revocation period, 305,984 of Mr. Long’s Phantom Units vested. The remaining 203,990 Phantom Units, together with any accrued DERs on such unvested common units, are subject to delayed vesting in accordance with Section 409A of the Code, and will vest on July 1, 2025, subject to the terms of the Long Separation Agreement.
(10)The market value of the Phantom Units, RSUs and CRSUs are calculated by multiplying $23.56, the closing price of the Partnership’s common units on December 31, 2024 by the number of Phantom Units, RSUs or CRSUs outstanding.
Units Vested During the Year Ended December 31, 2024
The following table provides information regarding the vesting of Phantom Units held by the NEOs during 2024. No RSUs or CRSUs vested during 2024. There are no options outstanding on the Partnership’s common units.
| | | | | | | | | | | | | | | | | |
| Name (1) | | Number of Phantom Units Vested
(#) | | | Value Realized on Vesting
($) (6) |
| Eric D. Long, Former President and Chief Executive Officer | | 193,255 | | (1) | | 4,485,449 | |
| G. Tracy Owens, Vice President of Finance and Chief Accounting Officer | | 9,789 | | (2) | | 227,203 | |
| Eric A. Scheller, Vice President and Chief Operating Officer | | 41,495 | | (3) | | 963,099 | |
| Christopher W. Porter, Vice President, General Counsel and Secretary | | 41,556 | | (4) | | 964,515 | |
| Sean T. Kimble, Former Vice President, Human Resources | | 36,762 | | (5) | | 853,246 | |
________________________
(1)Mr. Long settled approximately 50% of his newly vested Phantom Units in cash in the amount of $2,242,736 (before taxes), which cash settlement was reported as a disposition of those Phantom Units. The remaining 96,627 vested Phantom Units were settled in our common units following such cash settlement. Additionally, pursuant to the Long Separation Agreement, following execution of such agreement and the expiration of a seven (7) day revocation period, which occurred after December 31, 2024, 305,984 of Mr. Long’s Phantom Units vested, which Mr. Long settled approximately 30% in cash in the amount of $2,142,794 (before taxes). The remaining 214,188 vested Phantom Units were settled in our common units following such cash settlement. The vesting of the remaining 203,990 Phantom Units, together with any accrued DERs on such unvested common units, is delayed in accordance with Section 409A of the Code, and will vest on July 1, 2025, subject to the terms of the Long Separation Agreement.
(2)Mr. Owens settled approximately 50% of his newly vested Phantom Units in cash in the amount of $113,613 (before taxes), which cash settlement was reported as a disposition of those Phantom Units. The remaining 4,894 vested Phantom Units were settled in our common units following such cash settlement.
(3)Mr. Scheller settled approximately 50% of his newly vested Phantom Units in cash in the amount of $481,561 (before taxes), which cash settlement was reported as a disposition of those Phantom Units. The remaining 20,747 vested Phantom Units were settled in our common units following such cash settlement.
(4)Mr. Porter settled approximately 40% of his newly vested Phantom Units in cash in the amount of $385,820 (before taxes), which cash settlement was reported as a disposition of those Phantom Units. The remaining 24,933 vested Phantom Units were settled in our common units following such cash settlement.
(5)Mr. Kimble settled approximately 50% of his newly vested Phantom Units in cash in the amount of $426,646 (before taxes), which cash settlement was reported as a disposition of those Phantom Units. The remaining 18,380 vested Phantom Units were settled in our common units following such cash settlement.
(6)The value realized on the vesting of Phantom Units was calculated by multiplying $23.21, the closing price of the Partnership’s common units on the date of vesting (December 5, 2024) by the number of Phantom Units vesting on such date.
Potential Payments upon Termination or Change in Control
The NEOs are entitled to severance payments and/or other benefits upon certain terminations of employment and, in certain cases, in connection with a Change in Control (as defined in the LTIP and the CRU Plan and as described below) of the General Partner. All capitalized terms used in the following description but not defined therein will have the definitions set forth in the referenced document.
Employment Agreements
As previously noted, each of Messrs. Porter and Kimble is or was party to an Employment Agreement providing for certain payments and benefits upon certain terminations of employment. For the purposes of the following description, the “Company” means USAC Management with respect to Messrs. Porter and Kimble. All capitalized terms used in the following description but not defined therein will have the definitions set forth in the referenced document.
The Employment Agreements provide for the following in the event of a termination of the NEO without Cause or by the NEO with Good Reason (each as defined in the Employment Agreements and set forth below): (i) semi-monthly severance payments for the one-year period following the NEO’s Separation from Service (the “Severance Period”) in an amount totaling the higher of the NEO’s Base Salary for (a) the current year and (b) any previous year during the term of the Employment Agreement (the “Severance Payment”); (ii) the entire amount of any earned Annual Bonus for the year preceding the year in which the NEO is terminated by the Company for “convenience” (as defined in the Employment Agreements and set forth below) or resigns for Good Reason; (iii) a pro rata portion (based on the number of days the NEO was employed during the year) of any earned Annual Bonus for the year in which the NEO is terminated without Cause or resigns for Good Reason; (iv) continued health insurance benefits for the NEO and his eligible dependents for a period of 24 months following his Separation from Service (the “Coverage Period”), as follows: (a) for the first 12 months of the Coverage Period, the Company will provide such health insurance coverage at its own expense (other than the NEO’s monthly cost-sharing contribution under the Company’s group health plan, as in effect at the time of the NEO’s Separation from Service); (b) for the following six months of the Coverage Period, such health insurance coverage will be at the NEO’s sole expense; and (c) for the final six months of the Coverage Period, the Company will be responsible for the proportion of the cost of such health insurance coverage that the NEO covered in the first 12 months of the Coverage Period; and the NEO will be responsible for the proportion that the Company covered during the first 12 months of the Coverage Period; and (v) within 30 days of the NEO’s Separation from Service, all earned but unpaid base salary and paid time off. The NEO’s right to the Severance Payment and continued health insurance benefits described in (i) and (iv) of the preceding sentence are subject to (1) the NEO’s execution of a release of claims against the Company within 45 days of such NEO’s Separation from Service and (2) the NEO’s compliance with the continuing obligations under his Employment Agreement, including confidentiality, non-compete and non-solicit obligations.
In the event of the termination of Mr. Porter’s or Mr. Kimble’s employment by the Company without Cause or by the NEO with Good Reason within two years of a “change in control event” within the meaning of Treasury Regulation 1.409A-3(i)(5), the Severance Payment will be paid in a lump sum on the Company’s first regular payroll date that occurs on or after 30 days after the date of the NEO’s Separation from Service.
In the event of a termination of Mr. Porter’s or Mr. Kimble’s employment due to death or Disability (as defined in the Employment Agreements), the Company shall pay the following to the NEO or the NEO’s estate: (i) the entire amount of any earned Annual Bonus for the year preceding the year in which the NEO dies or becomes Disabled; (ii) a pro rata portion (based on the number of days employed during the year) of any earned Annual Bonus for the year in which the NEO dies or becomes Disabled; and (iii) all earned but unpaid base salary and paid time off. In the event of the NEO’s death during the Severance Period, the Severance Payment will be paid in a lump sum within 30 days of his death.
As used in the Employment Agreements, a termination for “convenience” generally means an involuntary termination for any reason, including, under certain circumstances, a failure to renew the employment agreement at the end of an initial term or any renewal term, other than a termination for “Cause.” “Cause” is defined in the Employment Agreements to mean (i) any material breach of the Employment Agreement, including the material breach of any representation, warranty or covenant made under the Employment Agreement by the NEO, (ii) the NEO’s breach of any applicable duties of loyalty to the Company or any of its affiliates, gross negligence or material misconduct, or a significant act or acts of personal dishonesty or deceit, taken by the NEO, in the performance of the duties and services required of the NEO that is demonstrably and significantly injurious to the Company or any of its affiliates, (iii) conviction of a felony or crime involving moral turpitude, (iv) the NEO’s willful and continued failure or refusal to perform substantially the NEO’s material obligations pursuant to the Employment Agreement or follow any lawful and reasonable directive from the CEO or the Board, as applicable, other than as a result of the NEO’s incapacity, or (v) a violation of federal, state or local law or regulation applicable to the business of the Company that is demonstrably and significantly injurious to the Company.
“Good Reason” is defined in the Employment Agreements to mean (i) a material breach by the Company of the Employment Agreement or any other material agreement with the NEO, (ii) a material reduction in the NEO’s base salary, other than a reduction that is generally applicable to all similarly situated employees of the Company, (iii) a material reduction in the NEO’s duties, authority, responsibilities, job title or reporting relationships, (iv) a material reduction by the Company in the facilities or perquisites available to the NEO, other than a reduction that is generally applicable to all similarly situated employees, or (v) the relocation of the geographic location of the NEO’s current principal place of employment by more than 50 miles from the location of the NEO’s principal place of employment as of the effective date of the Employment Agreement.
“Disability” is defined in the Employment Agreements as the NEO being unable to perform essential functions of his position, with reasonable accommodation, due to an illness or physical or mental impairment or other incapacity which continues for a period in excess of 20 consecutive weeks. The determination of Disability will be made by a physician selected by the NEO and acceptable to the Company or its insurers.
Vesting and Change in Control Benefits – LTIP
On November 1, 2018, the Compensation Committee adopted the Phantom Unit Agreement, and on December 5, 2024 the Compensation Committee adopted the Restricted Unit Agreement (the “LTIP Agreements”). The LTIP Agreements (i) provide for incremental vesting of Phantom Units and RSUs over five years (60% on the third December 5 following the grant and 40% on the fifth December 5 following the grant) and (ii) provides for vesting of 100% of the outstanding, unvested Phantom Units and RSUs in the event of (a) a Change in Control (as defined under the LTIP and set forth below) or (b) the death or Disability of the NEO. Additionally, the Phantom Unit Agreement provides for (i) vesting of 40% of the outstanding, unvested Phantom Units if the NEO voluntarily retires between the ages of 65–68 and has been employed by us, the Company, or our affiliates for at least 10 years (with the remaining 60% being forfeited), and (ii) vesting of 50% of the outstanding, unvested Phantom Units if the NEO voluntarily retires at or over the age 68 and has been employed by us, the Company or our affiliates for at least 10 years (with the remaining 50% being forfeited). The Restricted Unit Agreement similarly provides for (i) vesting of 40% of the outstanding, unvested RSUs if the NEO voluntarily retires between the ages of 65–68, has been employed by us, the Company, or our affiliates for at least five years, and has held the award for at least a year (with the remaining 60% being forfeited), and (ii) vesting of 50% of the outstanding, unvested RSUs if the NEO voluntarily retires at or over the age 68, has been employed by us, the Company, or our affiliates for at least five years, and has held the award for at least a year (with the remaining 50% being forfeited). The vesting of the Phantom Units and RSUs are subject, in each case described above, to the NEO’s continued employment with us, the Company, or our affiliates until the relevant vesting date. For purposes of this description, the “Company” means USA Compression GP, LLC.
A “Change in Control” as defined under the LTIP means the occurrence of any of the following events: (i) any “person” or “group” within the meaning of Sections 13(d) and 14(d)(2) of the Exchange Act, other than the Company, Energy Transfer, an Affiliate of the Company (as determined immediately prior to such event), or an Affiliate of, or successor to, Energy Transfer, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Company or the Partnership; (ii) the limited partners of the Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership; (iii) the sale or other disposition by either the Company or the Partnership of all or substantially all of its assets in one or more transactions to any Person other than the Company, the Partnership, Energy Transfer, an Affiliate of the Company (as determined immediately prior to such event), the Partnership, or an Affiliate of, or successor to, Energy Transfer; or (iv) a transaction resulting in a Person other than the Company, Energy Transfer, an Affiliate of the Company (as determined immediately prior to such event), or an Affiliate of, or successor to, Energy Transfer being the sole general partner of the Partnership.
However, if an LTIP award is subject to section 409A of the Code, a “Change in Control” will be defined in accordance with section 409A of the Code and the regulations promulgated thereunder.
“Disability” as defined under the LTIP means, as determined by the Compensation Committee in its discretion exercised in good faith, a physical or mental condition of the NEO that would entitle him or her to payment of disability income payments under the Company’s or the Partnership’s or one of its subsidiaries’ long-term disability insurance policy or plan for employees as then in effect; or in the event that an NEO is not covered, for whatever reason, under the Company’s or the Partnership’s or one of its subsidiaries’ long-term disability insurance policy or plan for employees or the Company or the Partnership or one of its subsidiaries does not maintain such a long-term disability insurance policy, “Disability” means a total and permanent disability within the meaning of Section 22(e)(3) of the Code; provided, however, that if a Disability constitutes a payment event with respect to any award which provides for the deferral of compensation and is subject to section 409A of the Code, then, to the extent required to comply with section 409A of the Code, the NEO must also be considered “disabled” within the meaning of section 409A(a)(2)(C) of the Code. A determination of Disability may be made by a physician selected or approved by the Compensation Committee and, in this respect, NEOs shall submit to an examination by such physician upon request by the Compensation Committee.
Vesting and Change in Control Benefits – CRU Plan
On December 5, 2024, the Compensation Committee adopted the Time-Vested Cash Restricted Unit Agreement (the “CRU Agreement”), which (i) provides for incremental vesting of CRSUs over three years (1/3 on the first December 5 following the grant, 1/3 on the second December 5 following the grant, and the remaining 1/3 on the third December 5 following the grant) and (ii) provides for vesting of 100% of the outstanding, unvested CRSUs in the event of (a) a Change in Control (as defined under the CRU Plan and set forth below) or (b) the death or Disability of the NEO. Also, under the CRU Agreement, if the NEO has been employed by the Partnership, the Company, a subsidiary or an affiliate of the Partnership, the Company or a subsidiary for at least five years and is at least 65 at the time of his voluntary retirement, 60% of his then-unvested CRSUs will be forfeited, and the remainder will vest, at the time of retirement. If the NEO has been employed by the Partnership, the Company, a subsidiary or an affiliate of the Partnership, the Company or a subsidiary for at least five years and is at or over age 68 at the time of his voluntary retirement, 50% of his then-unvested CRSUs will be forfeited, and the remainder will vest, at the time of retirement. The retirement provision also requires that the award be held for at least one year after the grant date in order to be eligible for acceleration. For purposes of this description, the “Company” means USA Compression GP, LLC.
A “Change in Control” as defined under the CRU Plan means the occurrence of any of the following events: (i) any “person” or “group” within the meaning of Sections 13(d) and 14(d)(2) of the Exchange Act, other than the Company, Energy Transfer, an affiliate of the Company (as determined immediately prior to such event), or an affiliate of, or successor to, Energy Transfer, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Company or the Partnership; (ii) the limited partners of the Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership; (iii) the sale or other disposition by either the Company or the Partnership of all or substantially all of its assets in one or more transactions to any Person other than the Company, the Partnership, Energy Transfer, an affiliate of the Company (as determined immediately prior to such event), the Partnership, or an affiliate of, or successor to, Energy Transfer; or (iv) a transaction resulting in a Person other than the Company, Energy Transfer, an affiliate of the Company (as determined immediately prior to such event), or an Affiliate of, or successor to, Energy Transfer being the general partner of the Partnership.
“Disability” as defined under the CRU Plan means, unless provided otherwise in CRU Agreement, an illness or injury that lasts at least six continuous months, is expected to be permanent and renders the participant unable to carry out his or her duties to the Company, the Partnership or an affiliate of the Company or the Partnership.
However, if a CRU award is subject to section 409A of the Code, a “Change in Control” or “Disability” will be defined in accordance with section 409A of the Code and the regulations promulgated thereunder.
Potential Payments upon Termination or Change in Control
Except as otherwise noted, the values in the table below assume that a Change in Control occurred on December 31, 2024, and/or that the NEO’s employment terminated on that date, as applicable. The amounts actually payable to any NEO can only be calculated with certainty upon actual termination or a Change in Control. Except as otherwise noted, the value of the acceleration of the LTIP and CRU awards was calculated using the value of $23.56, which was the closing price of the Partnership’s common units on December 31, 2024.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Executive Benefits and
Payments | | Change in Control followed by termination without “Cause” or for
“Good Reason”
($) | | Termination of Employment without “Cause” or for
“Good Reason”
($) | | Termination of Employment because of Death
or Disability
($) | | Termination by the Executive Other Than for
“Good Reason”
($) (9) | | Continued
Employment Following Change of Control
($) (10) |
| M. Clint Green | | | | | | | | | | |
| President and Chief Executive Officer | | | | | | | | | | |
| Salary (1) | | 33,966 | | | 33,966 | | | 33,966 | | | 33,966 | | | — | |
| Bonus | | — | | | — | | | — | | | — | | | — | |
| Accelerated Vesting of RSUs (2) | | 1,985,401 | | | — | | | 1,985,401 | | | — | | | 1,985,401 | |
| Accelerated Vesting of CRSUs (3) | | 661,800 | | | — | | | 661,800 | | | — | | | 661,800 | |
| Totals | | 2,681,167 | | | 33,966 | | | 2,681,167 | | | 33,966 | | | 2,647,201 | |
| Eric D. Long (4) | | | | | | | | | | |
| Former President and Chief Executive Officer | | | | | | | | | | |
| Salary | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Bonus | | — | | | — | | | — | | | — | | | — | |
| Accelerated Vesting of Phantom Units | | — | | | — | | | — | | | — | | | — | |
| Totals | | — | | | — | | | — | | | — | | | — | |
| Christopher M. Paulsen | | | | | | | | | | |
| Vice President, Chief Financial Officer and Treasurer | | | | | | | | | | |
| Salary (1) | | 3,269 | | | 3,269 | | | 3,269 | | | 3,269 | | | — | |
| Bonus | | — | | | — | | | — | | | — | | | — | |
| Accelerated Vesting of RSUs (2) | | 1,325,250 | | | — | | | 1,325,250 | | | — | | | 1,325,250 | |
| Accelerated Vesting of CRSUs (3) | | 441,750 | | | — | | | 441,750 | | | — | | | 441,750 | |
| Totals | | 1,770,269 | | | 3,269 | | | 1,770,269 | | | 3,269 | | | 1,767,000 | |
| G. Tracy Owens | | | | | | | | | | |
| Vice President of Finance and Chief Accounting Officer | | | | | | | | | | |
| Salary (1) | | 2,575 | | | 2,575 | | | 2,575 | | | 2,575 | | | — | |
| Bonus | | — | | | — | | | — | | | — | | | — | |
| Accelerated Vesting of Phantom Units (2) | | 601,463 | | | — | | | 601,463 | | | — | | | 601,463 | |
| Totals | | 604,038 | | | 2,575 | | | 604,038 | | | 2,575 | | | 601,463 | |
| Eric A. Scheller | | | | | | | | | | |
| Vice President and Chief Operating Officer | | | | | | | | | | |
| Salary (1) | | 3,328 | | | 3,328 | | | 3,328 | | | 3,328 | | | — | |
| Bonus | | — | | | — | | | — | | | — | | | — | |
| Accelerated Vesting of RSUs and Phantom Units (2) | | 3,858,822 | | | — | | | 3,858,822 | | | — | | | 3,858,822 | |
| Accelerated Vesting of CRSUs (3) | | 222,406 | | | — | | | 222,406 | | | — | | | 222,406 | |
| Totals | | 4,084,556 | | | 3,328 | | | 4,084,556 | | | 3,328 | | | 4,081,228 | |
| Christopher W. Porter | | | | | | | | | | |
| Vice President, General Counsel and Secretary | | | | | | | | | | |
| Salary (5)(8) | | 445,376 | | | 445,376 | | | 35,376 | | | 35,376 | | | — | |
| Bonus (6)(9) | | 746,960 | | | 746,960 | | | 746,960 | | | — | | | — | |
| Accelerated Vesting of RSUs and Phantom Units (2) | | 3,326,743 | | | — | | | 3,326,743 | | | — | | | 3,326,743 | |
| Accelerated Vesting of CRSUs (3) | | 216,988 | | | — | | | 216,988 | | | — | | | 216,988 | |
| Health and Welfare Plan Benefits (7) | | 33,915 | | | 33,915 | | | — | | | — | | | — | |
| Totals | | 4,769,982 | | | 1,226,251 | | | 4,326,067 | | | 35,376 | | | 3,543,731 | |
| Sean T. Kimble (11) | | | | | | | | | | |
| Former Vice President, Human Resources | | | | | | | | | | |
| Salary | | — | | | — | | | — | | | — | | | — | |
| Bonus | | — | | | — | | | — | | | — | | | — | |
| Accelerated Vesting of Phantom Units | | — | | | — | | | — | | | — | | | — | |
| Health and Welfare Plan Benefits | | — | | | — | | | — | | | — | | | — | |
| Totals | | — | | | — | | | — | | | — | | | — | |
________________________
(1)Includes accrued and unpaid salary and, with respect to Mr. Green, accrued and unused paid time off.
(2)In the event of the NEO’s cessation of service for any reason, other than as set forth below, 100% of the NEO’s Phantom Units and RSUs that have not vested prior to or in connection with such cessation of service shall be automatically forfeited. With respect to the Phantom Units, if the NEO retires after attaining the age of 65 and has been employed by us, our General Partner, or our affiliates for at least 10 years, 60% of his then-unvested Phantom Units will be forfeited, and the remainder will vest, at the time of retirement and, if the NEO is at or over age 68 at the time of retirement and has been employed by us, our General Partner, or our affiliates for at least 10 years, 50% of his then-unvested Phantom Units will be forfeited, and the remainder will vest, at the time of retirement. With respect to the RSUs, if the NEO retires after attaining the age of 65 and has been employed by us, our General Partner, or our affiliates for at least five years, 60% of his then-unvested RSUs will be forfeited, and the remainder will vest, at the time of retirement and, if the NEO is at or
over age 68 at the time of retirement and has been employed by us, our General Partner, or our affiliates for at least five years, 50% of his then-unvested RSUs will be forfeited, and the remainder will vest, at the time of retirement; provided that, for the retirement vesting of RSUs, the NEO must have held the award for at least a year. In the event of the death or Disability (as defined under the LTIP) of the NEO, 100% of the then-unvested Phantom Units and RSUs shall vest in full immediately prior to such NEO’s cessation of service due to death or Disability. In the event of a Change in Control (as defined under the LTIP), 100% of the NEO’s outstanding, unvested Phantom Units and RSUs would vest.
(3)In the event of the NEO’s cessation of service for any reason, other than as set forth below, 100% of the NEO’s CRSUs that have not vested prior to or in connection with such cessation of service shall be automatically forfeited. If the NEO retires after attaining the age of 65 and has been employed by us, our General Partner, or our affiliates for at least five years, 60% of his then-unvested CRSUs will be forfeited, and the remainder will vest, at the time of retirement and, if the NEO is at or over age 68 at the time of retirement and has been employed by us, our General Partner, or our affiliates for at least five years, 50% of his then-unvested CRSUs will be forfeited, and the remainder will vest, at the time of retirement; provided that, for the retirement vesting of CRSUs, the NEO must have held the award for at least a year. In the event of the death or Disability (as defined under the CRU Plan) of the NEO, 100% of the then-unvested CRSUs shall vest in full immediately prior to such NEO’s cessation of service due to death or Disability. In the event of a Change in Control (as defined under the CRU Plan), 100% of the NEO’s outstanding, unvested CRSUs would vest.
(4)Mr. Long retired from the Partnership on December 31, 2024. In exchange for Mr. Long’s execution of the Long Separation Agreement, and as approved by our Compensation Committee, we paid Mr. Long a separation payment of $962,400, and an additional $29,538, representing 24 months of health-insurance coverage under the Partnership’s health insurance plan (collectively, the “Long Separation Payment”). Additionally, under the terms of the Long Separation Agreement, Mr. Long’s 509,974 unvested Phantom Units vested or will vest in full, which, based on the December 31, 2024 closing price of our units, are valued at $12,014,987. The Long Separation Payment was paid in a lump sum. Under the terms of the Long Separation Agreement, Mr. Long released all claims against us, and agreed to certain non-disparagement, non-solicit, and confidentiality obligations. Mr. Long also received $5,691 in accrued, unpaid salary. The total aggregate value of the accrued, unpaid salary, the Long Separation Payment, and the unit vesting received by Mr. Long pursuant to the Long Separation Agreement is $13,012,616.
(5)The listed salary for Mr. Porter represents his accrued but unused paid time off and accrued and unpaid salary as of December 31, 2024 plus, with respect to the first two columns, his base salary as of December 31, 2024. Any accrued but unused paid time off owed to Mr. Porter would be paid within 30 days of the date of his termination of employment, and the base salary would be paid out as set forth in footnote 8 below.
(6)The listed bonus amount for Mr. Porter is his pro rata bonus awarded with respect to the year ended December 31, 2024, and his bonus awarded with respect to the year ended December 31, 2023.
(7)In the event of Mr. Porter’s termination by the Partnership without Cause or by the NEO with Good Reason, he and his eligible dependents will be entitled to continued health insurance benefits for the Coverage Period, as follows: (a) for the first 12 months of the Coverage Period, the Partnership will provide such health insurance coverage at its own expense (other than the NEO’s monthly cost-sharing contribution under the Partnership’s group health plan, as in effect at the time of the NEO’s Separation from Service); (b) for the following six months of the Coverage Period, such health insurance coverage will be at the NEO’s sole expense; and (c) for the final six months of the Coverage Period, the Partnership will be responsible for the proportion of the cost of such health insurance coverage that the NEO covered in the first 12 months of the Coverage Period; and the NEO will be responsible for the proportion that the Partnership covered during the first 12 months of the Coverage Period.
(8)The Employment Agreement for Mr. Porter provides that upon termination by the Partnership without Cause or by the NEO for Good Reason, the NEO is entitled to receive one times his base salary, payable in equal semi-monthly installments over the course of one year provided, that any such installment payments that would otherwise be paid prior to the Partnership’s first regular payroll date that occurs on or after the 60th day following the date of Employee’s Separation from Service (the “First Pay Date”) shall be paid on the First Pay Date. Upon the death of Mr. Porter during this one-year period, his salary payment will be accelerated and all remaining Severance Payments (as defined in the Employment Agreement) would be paid in a lump sum within 30 days of his death. If such termination occurs within two years after a “change in control event” within the meaning of Treasury Regulation 1.409A-3(i)(5), the Severance Payment will be made in a lump sum on the first regular payroll date that occurs on or after 30 days of the NEO’s termination date.
(9)Upon the death or Disability (as defined in the Employment Agreement) of Mr. Porter, he (or his estate) will be entitled to his pro rata bonus awarded with respect to the year ended December 31, 2024, and his bonus awarded with respect to the year ended December 31, 2023.
(10)The NEOs are not entitled to a certain level of compensation in the event of continued employment following a Change in Control, but for purposes of this table it is assumed that the NEO would continue to receive a level of base salary, bonus, benefits, and other compensation in the event of continued employment following a Change in Control that is the same as, or similar to, the amounts shown in the Summary Compensation Table. Accordingly, no additional amounts are shown for salary, bonus, or health and welfare plan benefits because those amounts would remain as in effect at the time of the Change in Control, and only the acceleration values of outstanding equity at the time of a Change of Control have been reflected.
(11)Mr. Kimble left the Partnership on December 6, 2024. In exchange for Mr. Kimble’s execution of the Kimble Separation Agreement, and as approved by our Compensation Committee, Mr. Kimble became entitled to receive (i) a separation payment of $972,088, which amount primarily consists of amounts owed to Mr. Kimble pursuant to Mr. Kimble’s Employment Agreement; (ii) earned but unused paid time off as of December 6, 2024 in the amount of $24,556; and (iii) a lump-sum payment of $59,077 representing the full cost of the premium for twenty-four (24) months of health insurance coverage under the Partnership’s health insurance plan. These amounts will be
paid in a lump sum following a deferral period in compliance with Section 409A of the Code. Under the terms of the Kimble Separation Agreement, Mr. Kimble released all claims against us, and agreed to certain non-disparagement, non-solicit, and confidentiality obligations. The total amount payable to Mr. Kimble pursuant to the Kimble Separation Agreement is $1,055,720.
CEO Pay Ratio
Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, require us to provide certain information about the relationship of the annual total compensation of our employees and the annual total compensation of our Chief Executive Officer as of December 31, 2024, M. Clint Green (our “CEO”). The total compensation reported below for Mr. Green is based on annualized amounts for those compensation components that were prorated for 2024. These annualized components of Mr. Green’s compensation are base salary, bonus and 401(k) contributions. The employees providing services to us are directly employed by USAC Management, therefore we do not have employees for purposes of the pay ratio rules. Rather than providing a pay ratio disclosure that contemplates no employees, we have determined that the disclosure that would be most aligned with the spirit of the pay ratio rules and that would provide our unitholders with more meaningful information would be to provide a ratio using the median employee from the USAC Management employee population. All references to “our” employees within this section shall refer to the applicable USAC Management employees. In accordance with Item 402(u), we are basing the following pay-ratio information on the same median employee that we selected in 2023. There has been no change in our employee population or employee compensation arrangements that we believe would result in a significant change to our pay ratio disclosure for 2024.
For 2024, our last completed fiscal year:
•The median of the annual total compensation of all employees (other than the CEO) was $114,565.
•The annual total compensation of our CEO, reported in the Summary Compensation Table included elsewhere within this Form 10-K, plus an additional amount that reflects the annualizing of his base salary, bonus and 401(k) contributions was $3,774,222.
•Based on this information, for 2024 the ratio of the annual total compensation of Mr. Green to the median of the annual total compensation of all employees was reasonably estimated to be 32.9 to 1.
To identify the median of the annual total compensation of all our employees, as well as to determine the annual total compensation of our median employee and our CEO, we took the following steps:
•We determined that, as of December 31, 2023, our employee population consisted of approximately 822 individuals with all of these individuals located in the U.S. This population consisted of our full-time employees, as we did not have any part-time employees, temporary employees or seasonal workers as of December 31, 2023.
•We selected December 31, 2023, as our identification date for determining our median employee because it enabled us to make such identification in a reasonably efficient and economic manner.
•We used a consistently applied compensation measure to identify our median employee of comparing the amount of salary or wages, bonuses, compensation received from equity award vesting, and any other compensation items reported to the Internal Revenue Service on Form W-2 for 2023.
•We identified our median employee by consistently applying this compensation measure to all of our employees included in our analysis. Since all of our employees, including our CEO, are located in the U.S., we did not make any cost-of-living adjustments in identifying the median employee.
•After we identified our median employee, we combined all of the elements of such employee’s compensation for the 2024 year in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $114,565.
•With respect to the annual total compensation of our CEO, we used the amount reported in the “Total” column of our 2024 Summary Compensation Table included in this Form 10-K plus an additional amount that reflects the annualizing of his base salary, bonus and 401(k) contributions.
Director Compensation
For the year ended December 31, 2024, Mr. Eric Long was the only NEO who also served as a director, and he did not receive additional compensation for his service on the Board. Mr. Long’s compensation as an NEO is reflected in the Summary Compensation Table above (Mr. Long resigned from his position as a member of the Board and as President and Chief Executive officer of the Partnership effective October 2, 2024). Officers, employees, paid consultants, or advisors of us or the General Partner or its affiliates who also serve as directors do not receive additional compensation for their service as directors. Our directors who are not officers, employees, paid consultants, or advisors of us or the General Partner or its affiliates receive
cash and equity-based compensation for their services as directors. Our director compensation program is subject to revision by the Board from time to time.
The following table shows the total fees earned and other compensation paid in cash to each outside director during 2024.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Name | | Fees
Paid in Cash
($) | | Unit Awards
($) (1) | | All Other
Compensation
($) (2) | | Total
($) |
| Glenn E. Joyce | | 130,000 | | | 99,980 | | | 43,014 | | | 272,994 | |
| William S. Waldheim | | 132,500 | | | 99,980 | | | 43,014 | | | 275,494 | |
| John L. Wortham | | 122,500 | | | 68,475 | | | 3,938 | | | 194,913 | |
| Clifford A. Harris | | 100,000 | | | 61,000 | | | 3,938 | | | 164,938 | |
| W. Brett Smith | | — | | | 99,980 | | | 34,104 | | | 134,084 | |
________________________
(1)Represents the grant date fair value of our Phantom Units, calculated in accordance with ASC Topic 718. For a detailed discussion of the assumptions utilized in coming to these values, please see Note 15 in Part II, Item 8 “Financial Statements and Supplementary Data”. As of December 31, 2024, the outside members of the Board who receive equity awards held the following number of outstanding equity awards under the LTIP: Mr. Joyce: 14,727 Phantom Units; Mr. Waldheim: 14,727 Phantom Units; Mr. Wortham: 2,500 Phantom Units; and Mr. Harris 2,500 Phantom Units. Mr. Smith resigned from our Board in March 2024, but as of December 31, 2024 held 12,709 unvested Phantom Units. The Phantom Units granted in 2024 to Messrs. Joyce, Waldheim, Wortham, Harris and Smith vest incrementally, with 60% of the Phantom Units vesting on December 5, 2026, and the remaining 40% of the Phantom Units vesting on December 5, 2028. In the event of the director’s cessation of service due to death, Disability, or a Change in Control, 100% of his outstanding, unvested Phantom Units will vest immediately prior to such event.
(2)Amounts in this column reflect the value of DERs received by the directors with respect to their outstanding Phantom Unit awards.
On July 30, 2018, the Board adopted the Amended and Restated Outside Director Compensation Policy (the “Director Compensation Policy”), which provides for: (i) an annual cash retainer of $100,000; (ii) an annual cash retainer for acting as the Chairman of the Audit Committee and for acting as Chairman of the Compensation Committee; (iii) an annual cash retainer for membership on the Audit Committee and for membership on the Compensation Committee; (iv) an undetermined fixed sum for membership on a special or conflicts committee; (v) an annual equity grant with a value of $100,000; and (vi) a one-time director onboarding equity award of 2,500 Phantom Units. All Phantom Units granted pursuant to the Director Compensation Policy vest incrementally over five years and all outstanding, unvested Phantom Units vest in full in the event of the director’s death, Disability, or upon a Change in Control (each as defined in the LTIP). The Director Compensation Policy does not provide for per meeting attendance fees.
The following chart summarizes the Director Compensation Policy.
| | | | | | | | |
| Compensation Element | | Director Compensation Detail |
| Annual Cash Retainer | | $100,000 |
| | |
| Committee Chair Cash Retainer | | Audit Committee: $25,000
Compensation Committee: $15,000 |
| | |
| Committee Membership Retainer (if not Committee Chair) | | Audit Committee: $15,000
Compensation Committee: $7,500 |
| | |
| Initial Phantom Unit Award | | 2,500 Phantom Units |
| | |
| Annual Phantom Unit Award | | $100,000 value |
| | |
| DERs on Unvested Phantom Units | | Yes (paid on a current basis) |
| | |
| Phantom Unit Vesting Schedule | | 60% vest on third December 5 following grant
40% vest on fifth December 5 following grant |
| | |
| Change-in-Control | | Unvested Phantom Units vest in full |
| | |
| Cessation of Service due to Death or Disability | | Unvested Phantom Units vest in full |
| | |
| Attendance Fee Per Meeting | | None |
| | |
| Reimbursement of Out-of-Pocket Expenses | | Yes |
| | |
| Indemnification | | Yes, to fullest extent permitted under Delaware law |
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
Pursuant to the terms of an Equity Restructuring Agreement the Partnership entered into on January 15, 2018, with the General Partner and Energy Transfer Equity, L.P. (the “Equity Restructuring Agreement”), at any time after the first anniversary of the Transactions Date, Energy Transfer has the right to contribute (or cause any of its subsidiaries to contribute) to the Partnership all of the outstanding equity interests in any of its subsidiaries that owns the General Partner Interest (as defined in the Equity Restructuring Agreement) in exchange for $10,000,000 (the “GP Contribution”); provided that the GP Contribution will occur automatically if at any time following the Transactions Date (i) Energy Transfer or one of its affiliates owns, directly or indirectly, the General Partner Interest and (ii) Energy Transfer and its affiliates collectively own less than 12,500,000 of the Partnership’s common units.
Security Ownership of Certain Beneficial Owners and Management
The following table sets forth the beneficial ownership of the Partnership’s common units and Preferred Units as of February 6, 2025, held by:
•each person who beneficially owns 5% or more of the Partnership’s outstanding common units;
•all of the directors of the General Partner;
•each NEO of the General Partner; and
•all directors and current executive officers of the General Partner as a group.
As of February 6, 2025, there were 117,528,971 common units outstanding. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all common units shown as beneficially owned by them and their address is 8117 Preston Road, Suite 510A, Dallas, Texas 75225. Any fractional common units are rounded down to the nearest whole number.
The table also presents information with respect to Energy Transfer’s common units beneficially owned as of February 6, 2025, by each current director and named executive officer of the General Partner and by all directors and executive officers of the General Partner as a group. As of February 6, 2025, Energy Transfer had 3,431,214,964 common units outstanding. Any fractional common units are rounded down to the nearest whole number.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | USA Compression Partners, LP | | Energy Transfer LP |
| Name of Beneficial Owner | | Common Units
Beneficially Owned | | Percentage of
Common Units | | Common Units
Beneficially Owned | | Percentage of
Common Units |
| Energy Transfer LP (1) (2) | | 46,056,228 | | | 39.19 | % | | N/A | | N/A |
| EIG Veteran Equity Aggregator, L.P. (3) | | 7,567,601 | | | 6.05 | % | | N/A | | N/A |
| Invesco Ltd. (4) | | 12,167,393 | | | 10.35 | % | | N/A | | N/A |
| ALPS Advisors, Inc. (5) | | 12,534,262 | | | 10.66 | % | | N/A | | N/A |
| M. Clint Green | | — | | | — | | | 34,274 | | | * |
| Eric D. Long (6) | | 668,615 | | | * | | 10,144 | | | * |
| Christopher M. Paulsen | | — | | | — | | | — | | | — | |
| G. Tracy Owens | | 29,803 | | | * | | — | | | — | |
| Eric A. Scheller | | 104,529 | | | * | | — | | | — | |
| Christopher W. Porter | | 63,448 | | | * | | 3,400 | | | * |
| Sean T. Kimble | | 68,380 | | | * | | — | | | — | |
| Dylan A. Bramhall | | — | | | — | | | 177,591 | | | * |
| Clifford A. Harris | | — | | | * | | 1,380,896 | | | * |
| Glenn E. Joyce | | 29,894 | | | * | | — | | | — | |
| Thomas E. Long | | — | | | — | | | 1,555,831 | | | * |
| Thomas P. Mason | | — | | | — | | | 1,052,674 | | | * |
| William S. Waldheim | | 29,894 | | | * | | — | | | — | |
| Bradford D. Whitehurst (7) | | 13,616 | | | * | | 849,189 | | | * |
| John L. Wortham | | — | | | — | | | 21,150 | | | * |
| James M. Wright, Jr. | | — | | | — | | | 346,566 | | | * |
| All directors and officers as a group (14 persons) (8) | | 271,184 | | | * | | 5,421,571 | | | * |
________________________
*Less than 1%.
(1)Energy Transfer LP has shared voting and dispositive power over 46,056,228 common units based on a Schedule 13D/A filed on August 5, 2019 with the SEC. The Schedule 13D/A was filed jointly by Energy Transfer LP, LE GP, LLC, Kelcy L. Warren, USA Compression GP, LLC, Energy Transfer Partners, L.L.C., Energy Transfer Partners GP, L.P., and Energy Transfer Operating, L.P. (collectively, the “Energy Transfer Reporting Companies”). The principal business address of each of the Energy Transfer Reporting Companies, other than USA Compression GP, LLC, is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225. The principal business address of USA Compression GP, LLC is 8117 Preston Road, Suite 510A, Dallas, Texas 75225.
(2)Includes 8,000,000 common units held by USA Compression GP, LLC.
(3)EIG owns approximately 151,439 Preferred Units, which are convertible into 7,567,601 common units at the election of the holder. Upon conversion of all 151,439 Preferred Units, EIG would have sole voting and dispositive power over 7,567,601 common units of the Partnership based on the Schedule 13D/A filed on June 26, 2024, with the SEC and our records. The principal business address of EIG Veteran Equity Aggregator, L.P. is 600 New Hampshire Ave NW, STE. 1200, Washington, DC 20037.
(4)Invesco Ltd. has the sole power to dispose or to direct the disposition of and sole power to vote or to direct the vote of 12,167,393 common units based on a Schedule 13G/A filed on November 11, 2024, with the SEC. Invesco Ltd., in its capacity as a parent holding company to its investment advisers, may be deemed to beneficially own these 12,167,393 common units which are held of record by clients of Invesco Ltd. Invesco Advisers, Inc. is a subsidiary of Invesco Ltd. and it advises the Invesco SteelPath MLP Income Fund which owns 7.71% of the security reported herein. However, no one individual has greater than 5% economic ownership. The
shareholders of the Fund have the right to receive or the power to direct the receipt of dividends and proceeds from the sales of these securities. The principal business address of Invesco Ltd. is 1331 Spring Street NW, Suite 2500, Atlanta GA 30309.
(5)The Schedule 13G/A was filed jointly by ALPS Advisors, Inc., an investment adviser registered under Section 203 of the Investment Advisors Act of 1940 (“AAI”) and Alerian MLP ETF, an investment company registered under the Investment Company Act of 1940 (“Alerian”). AAI and Alerian have the shared power to dispose or to direct the disposition of and shared power to vote or to direct the vote of 12,534,262 common units based on a Schedule 13G filed on November 13, 2024, with the SEC. AAI furnishes investment advice to certain investment companies (collectively, the “Funds”). In its role as an investment advisor, AAI has voting and/or investment power over the common units owned by the Funds, and may be deemed to be the beneficial ownership of the common units held by the Funds. All 12,534,262 common units are owned by the Funds and AAI disclaims beneficial ownership. Alerian MLP ETF, one of the Funds to which AAI provides investment advice, has an interest of 12,534,262 common units, or 10.66% in us. The principal business address of AAI and Alerian is 1290 Broadway, Suite 1000, Denver, CO 80203.
(6)Includes 617,841 of our common units held directly by Mr. Long, 17,592 of our common units held by Aladdin Partners, L.P., a limited partnership affiliated with Mr. Long, and 33,182 of our common units held in a trust of which Mr. Long is the trustee. The Energy Transfer LP common units reported as owned by Mr. Long include 4,000 common units held by Aladdin Partners, L.P., and 6,144 common units held by certain trusts of which Mr. Long is the trustee. This amount does not include 203,990 phantom units which, pursuant to the terms of the Long Separation Agreement, are subject to delayed vesting in accordance with Section 409A of the Code.
(7)Mr. Whitehurst holds 387,983 of Energy Transfer LP’s common units and 10,000 of USAC’s common units in a margin account.
(8)Includes our directors and current executive officers.
Securities Authorized for Issuance Under Equity Compensation Plans
The Board adopted the LTIP in January 2013. On November 1, 2018, the Board approved and adopted the First Amendment to the LTIP (the “First Amendment”) with immediate effectiveness. The First Amendment (i) increased the number of common units available to be awarded under the LTIP by 8,590,000 common units (which brought the total number of common units available to be awarded under the LTIP to 10,000,000 common units); (ii) provided that common units withheld to satisfy the exercise price or tax withholding obligations with respect to an award will not be considered to be common units that have been delivered under the LTIP; (iii) for awards granted on or after April 3, 2018, modifies the definition of “Change in Control” under the LTIP to refer to Energy Transfer and its Affiliates (as defined under the LTIP) and successors; (iv) updated the tax withholding provision of the LTIP; and (v) extended the term of the LTIP until November 1, 2028.
The following table provides certain information with respect to the LTIP as of December 31, 2024:
| | | | | | | | | | | | | | | | | | | | | | | |
| Plan Category | | Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights | | Weighted-average
exercise price of
outstanding options,
warrants and rights | | Number of securities
remaining available for
future issuance under
equity compensation
plan (excluding securities
reflected in the first
column) | |
| Equity compensation plans approved by security holders | | — | | | N/A | | — | | |
| Equity compensation plans not approved by security holders | | 1,643,708 | | | N/A | | 5,750,578 | | (1) |
________________________
(1)As of December 31, 2024, we had 7,394,286 common units available under the LTIP before giving effect to the outstanding awards of 1,643,708 Phantom Units and RSUs. Pursuant to the terms of the LTIP, other than director Phantom Unit awards, awards of Phantom Units may be settled in cash or common units at the discretion of the Board or a committee thereof. Any Phantom Unit settled in cash will not result in the actual delivery of a common unit. Additionally, Phantom Units or RSUs withheld to satisfy the exercise price or tax withholdings of an award and Phantom Units and RSUs that are forfeited, cancelled, or otherwise terminate or expire without the actual delivery of common units will be available for delivery pursuant to other awards.
For more information about the LTIP, please see Note 15 in Part II, Item 8 “Financial Statements and Supplementary Data”.
ITEM 13. Certain Relationships and Related Party Transactions, and Director Independence
Certain Relationships and Related Party Transactions
Services Agreement
We entered into that certain Services Agreement with USAC Management, a wholly owned subsidiary of the General Partner, effective on January 1, 2013 (the “Services Agreement”), pursuant to which USAC Management provides to us and the General Partner certain management, administrative and operating services, and certain personnel to manage and operate our business. We or one of our subsidiaries pays USAC Management for the allocable expenses it incurs in its performance under the Services Agreement. These expenses include, among other things, salary, bonus, cash incentive compensation, and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by USAC Management to us. USAC Management has substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us.
On October 28, 2022, the Services Agreement was amended to extend its term to December 31, 2027. The Services Agreement may be terminated at any time by (i) the Board upon 120 days’ written notice for any reason in its sole discretion or (ii) USAC Management upon 120 days’ written notice if: (a) we or the General Partner experience a Change of Control (as defined in the Services Agreement); (b) we or the General Partner breach the terms of the Services Agreement in any material respect following 30 days’ written notice detailing the breach (which breach remains uncured after such period); (c) a receiver is appointed for all or substantially all of our or the General Partner’s property or an order is made to wind up our or the General Partner’s business; (d) a final judgment, order or decree that materially and adversely affects the ability of us or the General Partner to perform under the Services Agreement is obtained or entered against us or the General Partner, and such judgment, order or decree is not vacated, discharged or stayed; or (e) certain events of bankruptcy, insolvency or reorganization of us or the General Partner occur. USAC Management will not be liable to us for their performance of, or failure to perform, services under the Services Agreement unless its acts or omissions constitute gross negligence or willful misconduct.
Transactions with Energy Transfer
We provide compression and related services to, and from time to time enter into other commercial transactions with, entities affiliated with Energy Transfer, which became a related party of ours on April 2, 2018. As of December 31, 2024, Energy Transfer has ownership and control of the General Partner and ownership of approximately 39% of our limited partner interests (including the 8,000,000 common units owned by the General Partner). Beginning in 2024, we also begin reimbursing Energy Transfer for certain employee and overhead costs allocated to us in connection with the shared services model. We may provide compression and related services to, or enter into other commercial transactions with entities affiliated with Energy Transfer in the future, and any significant transactions will be disclosed.
The following table summarizes payments and revenues between us and Energy Transfer during 2024.
| | | | | | | | | | | | | | |
| Transaction | | Explanation | | Amount/Value |
| 2024 quarterly distributions on limited partner interests | | Represents the aggregate amount of distributions made to Energy Transfer in respect of the Partnership’s common units during 2024. | | $ | 96.7 million |
| Revenue for compression and related services | | Represents the aggregate amount of revenue recognized for providing compression services to entities affiliated with Energy Transfer for the full year 2024. | | $ | 41.3 million |
| Reimbursement to Energy Transfer for certain allocated overhead and other expenses | | Represents the aggregate amount of transactions for reimbursement of overhead and other expenses, including employee compensation costs related to employees supporting our operations, to Energy Transfer during 2024. | | $ | 0.2 million |
| Amount of purchases from entities affiliated with Energy Transfer | | Represents the aggregate amount of purchases made from affiliates of Energy Transfer for certain other commercial purposes during 2024. | | $ | 2.2 million |
| | | | |
| | | | |
| | | | |
Consulting Agreement
Eric Long, our former CEO, entered into a consulting agreement (the “Consulting Agreement”) with us for a period of one (1) year commencing on January 1, 2025. The Consulting Agreement provides that Mr. E. Long shall provide consulting and advisory duties to the Partnership as requested by the Co-CEO of Energy Transfer. Pursuant to the terms of the Consulting Agreement, in exchange for providing consulting and advisory services to the Partnership and complying with the terms of the
Consulting Agreement, including certain non-competition and non-solicitation covenants incorporated by reference in the Long Separation Agreement, Mr. E. Long will receive a total of $740,000, paid monthly in arrears.
Employee Arrangement
Mr. Eric Scheller’s son is a salaried employee of USAC, and received compensation of approximately $122,000 during the year ended December 31, 2024. He was also eligible to participate in the same benefit programs as all of our other employees.
Conflicts of Interest
Conflicts of interest exist, and may arise in the future, as a result of the relationships between the General Partner and its affiliates, including Energy Transfer, on the one hand, and the Partnership and its limited partners, on the other hand. The directors and officers of the General Partner have fiduciary duties to manage the General Partner in a manner beneficial to its owners. At the same time, the General Partner has a fiduciary duty to manage the Partnership in a manner beneficial to us and our unitholders.
Whenever a conflict arises between the General Partner or its affiliates, on the one hand, and the Partnership and its limited partners, on the other hand, the General Partner will resolve that conflict. The Partnership Agreement contains provisions that modify and limit the General Partner’s fiduciary duties to the Partnership’s unitholders. The Partnership Agreement also restricts the remedies available to the Partnership’s unitholders for actions taken by the General Partner that, without those limitations, might constitute breaches of its fiduciary duty.
The Partnership Agreement provides that the General Partner will not be in breach of its obligations under the Partnership Agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is (a) approved by the conflicts committee of the Board, although the General Partner is not obligated to seek such approval; (b) approved by the vote of a majority of our outstanding common units, excluding any common units owned by the General Partner and its affiliates; (c) on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or (d) fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
The General Partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the Board. In connection with a situation involving a conflict of interest, any determination by the General Partner must be made in good faith, provided that, if the General Partner does not seek approval from the conflicts committee and the Board determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in subclauses (c) or (d) above, then it will conclusively be deemed that, in making its decision, the Board acted in good faith. Unless the resolution of a conflict is specifically provided for in the Partnership Agreement, the General Partner or the conflicts committee may consider any factors that it determines in good faith to be appropriate when resolving a conflict. When the Partnership Agreement provides that someone act in good faith, it requires that person to reasonably believe he is acting in the best interests of the Partnership. Please read Part I, Item 1A “Risk Factors – Risks Inherent in an Investment in Us”.
Procedures for Review, Approval, and Ratification of Related Person Transactions
The Audit Committee reviews and considers related party transactions with affiliates of Energy Transfer. The Audit Committee has authorized the General Partner’s management to enter into transactions with entities affiliated with Energy Transfer on arms-length terms taking into account then-current market conditions applicable to the services to be provided, and any such transaction shall be deemed approved by the Audit Committee. If other conflicts or potential conflicts of interest arises between the General Partner and its affiliates, including Energy Transfer, on the one hand and the Partnership and its limited partners, on the other hand, the resolution of any such conflict or potential conflict is addressed as described under “Conflicts of Interest.”
Pursuant to the Partnership’s Code of Business Conduct and Ethics and Corporate Governance Guidelines, directors, officers, and employees are required to disclose any situations that reasonably would be expected to give rise to a conflict of interest and report it to their supervisor, the Partnership’s general counsel, or the Board, as appropriate.
Director Independence
Please see Part III, Item 10 “Directors, Executive Officers and Corporate Governance – Board of Directors” for a discussion of director independence matters.
ITEM 14. Principal Accountant Fees and Services
The following table sets forth fees paid for professional services rendered by Grant Thornton LLP (“Grant Thornton”) during the years ended December 31, 2024 and 2023 (in millions):
| | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 |
| |
| Audit fees (1) | $ | 1.2 | | | $ | 1.0 | |
| Audit-related fees | — | | | — | |
| Tax fees | — | | | — | |
| All other fees | — | | | — | |
| Total | $ | 1.2 | | | $ | 1.0 | |
________________________
(1)Expenditures classified as “Audit fees” above were billed to the Partnership and include the audits of our annual financial statements and internal control over financial reporting, reviews of our quarterly financial statements, and fees associated with comfort letters and consents related to securities offerings and registration statements.
The Audit Committee has adopted the Audit Committee Charter, which is available on our website and which requires the Audit Committee to pre-approve all audit and non-audit services to be provided by our independent registered public accounting firm. The Audit Committee does not delegate its pre-approval responsibilities to management or to an individual member of the Audit Committee. The Audit Committee approved 100% of the services described above.
PART IV
ITEM 15. Exhibits and Financial Statement Schedules
(a)Documents filed as a part of this report.
1.Financial Statements. See “Index to Consolidated Financial Statements” set forth on Page F-1. 2.Financial Statement Schedule
All other schedules have been omitted because they are not required under the relevant instructions.
3.Exhibits
The following documents are filed as exhibits to this report:
| | | | | | | | |
| Exhibit Number | | Description |
| 2.1 | | Contribution Agreement dated as of January 15, 2018, by and among USA Compression Partners, LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETC Compression, LLC and, solely for certain purposes therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on January 16, 2018) |
| | |
| 2.2 | | |
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| 3.1 | | |
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| 3.2 | | |
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| 4.1 | | |
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| 4.2 | | |
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| 4.3 | | |
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| 4.4 | | |
| | |
| 4.5 | | Registration Rights Agreement, dated as of April 2, 2018, by and among USA Compression Partners, LP, Energy Transfer Equity, L.P., Energy Transfer Partners, L.P. and USA Compression Holdings, LLC (incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on April 6, 2018) |
| | |
| 4.6 | | |
| | |
| 4.7 | | |
| | |
| 4.8 | | |
| | | | | | | | |
| | |
| 10.1 | | Seventh Amended and Restated Credit Agreement, dated as of December 8, 2021, among USA Compression Partners, LP, as borrower, the guarantors party thereto from time to time, the lenders party thereto from time to time and JPMorgan Chase Bank, N.A., as administrative agent and issuing bank (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on December 8, 2021) |
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| 10.2† | | |
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| 10.3† | | |
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| 10.4† | | |
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| 10.5† | | |
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| 10.6†* | | |
| 10.7†* | | |
| 10.8†* | | |
| 10.9 | | |
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| 10.10 | | |
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| 10.11 | | |
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| 10.12† | | |
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| 10.13† | | |
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| 10.14† | | |
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| 10.15† | | |
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| 10.16† | | |
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| 10.17† | | |
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| 10.18† | | |
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| 10.19† | | |
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| 10.20†* | | |
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| 10.21† | | |
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| 10.22† | | |
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| 10.23†* | | |
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| 10.24†* | | |
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| 10.25 | | |
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| 19.1* | | |
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| 21.1* | | |
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| 22.1* | | |
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| 23.1* | | |
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| 31.1* | | |
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| 31.2* | | |
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| 32.1# | | |
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| 32.2# | | |
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| 97.1 | | |
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| 101* | | Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2024 and 2023; (ii) our Consolidated Statements of Operations for the years ended December 31, 2024, 2023, and 2022; (iii) our Consolidated Statements of Changes in Partners’ Capital (Deficit) for the years ended December 31, 2024, 2023, and 2022; (iv) our Consolidated Statements of Cash Flows for the years ended December 31, 2024, 2023, and 2022; and (v) the notes to our Consolidated Financial Statements |
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| 104 | | Cover Page Interactive Data File (embedded within the Inline XBRL document) |
* Filed Herewith.
# Furnished herewith; not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.
† Management contract or compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | | | | | | | | | |
| | USA COMPRESSION PARTNERS, LP |
| | | |
| | By: | USA Compression GP, LLC, |
| | | its General Partner |
| | | |
| Date: | February 11, 2025 | By: | /s/ M. Clint Green |
| | | M. Clint Green |
| | | President and Chief Executive Officer |
| | | (Principal Executive Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 11, 2025.
| | | | | | | | |
| Name | | Title |
| | |
| /s/ M. Clint Green | | President and Chief Executive Officer |
| M. Clint Green | | (Principal Executive Officer) |
| | |
| /s/ Christopher M. Paulsen | | Vice President, Chief Financial Officer and Treasurer |
| Christopher M. Paulsen | | (Principal Financial Officer) |
| | |
| /s/ G. Tracy Owens | | Vice President of Finance and Chief Accounting Officer |
| G. Tracy Owens | | (Principal Accounting Officer) |
| | |
| /s/ Dylan A. Bramhall | | Director |
| Dylan A. Bramhall | |
| | |
| /s/ Clifford A. Harris | | Director |
| Clifford A. Harris | |
| | |
| /s/ Glenn E. Joyce | | Director |
| Glenn E. Joyce | |
| | |
| /s/ Thomas E. Long | | Director |
| Thomas E. Long | |
| | |
| /s/ Thomas P. Mason | | Director |
| Thomas P. Mason | |
| | |
| /s/ William S. Waldheim | | Director |
| William S. Waldheim | |
| | |
| /s/ Bradford D. Whitehurst | | Director |
| Bradford D. Whitehurst | |
| | |
| /s/ John L. Wortham | | Director |
| John L. Wortham | |
| | |
| /s/ James M. Wright, Jr. | | Director |
| James M. Wright, Jr. | |
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors of USA Compression GP, LLC and
Unitholders of USA Compression Partners, LP
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of USA Compression Partners, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2024 and 2023, the related consolidated statements of operations, changes in partners’ capital (deficit), and cash flows for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2024, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 11, 2025 expressed an unqualified opinion.
Basis for opinion
These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical audit matters
Critical audit matters are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that there are no critical audit matters.
/s/ GRANT THORNTON LLP
We have served as the Partnership’s auditor since 2017.
Houston, Texas
February 11, 2025
USA COMPRESSION PARTNERS, LP
Consolidated Balance Sheets
(in thousands, except unit amounts)
| | | | | | | | | | | |
| December 31, |
| 2024 | | 2023 |
| Assets |
| Current assets: | | | |
| Cash and cash equivalents | $ | 14 | | | $ | 11 | |
| | | |
| Accounts receivable, net of allowances for credit losses of $1,474 and $2,260, respectively | 88,478 | | | 95,421 | |
| | | |
| Related-party receivables | 636 | | | — | |
| Inventories | 133,901 | | | 114,728 | |
| Derivative instrument | — | | | 5,670 | |
| Prepaid expenses and other assets | 11,967 | | | 10,617 | |
| Total current assets | 234,996 | | | 226,447 | |
| Property and equipment, net | 2,273,376 | | | 2,237,625 | |
| Lease right-of-use assets | 14,336 | | | 17,290 | |
| | | |
| Identifiable intangible assets, net | 216,273 | | | 245,652 | |
| | | |
| Other assets | 6,620 | | | 9,746 | |
| Total assets | $ | 2,745,601 | | | $ | 2,736,760 | |
| Liabilities, Preferred Units, and Partners’ Deficit |
| Current liabilities: | | | |
| Accounts payable | $ | 27,245 | | | $ | 39,781 | |
| Related-party payables | 105 | | | — | |
| Accrued liabilities | 99,428 | | | 85,132 | |
| Deferred revenue | 63,900 | | | 62,589 | |
| Total current liabilities | 190,678 | | | 187,502 | |
| Long-term debt, net | 2,502,557 | | | 2,336,088 | |
| Operating lease liabilities | 11,678 | | | 14,731 | |
| Derivative instrument, long term | — | | | 4,466 | |
| Other liabilities | 12,930 | | | 10,924 | |
| Total liabilities | 2,717,843 | | | 2,553,711 | |
| Commitments and contingencies | | | |
| Preferred Units | 168,809 | | | 476,334 | |
| Partners’ deficit: | | | |
| Common units, 117,314,783 and 100,986,011 units issued and outstanding, respectively | (141,051) | | | (293,285) | |
| | | |
| | | |
| Total liabilities, Preferred Units, and partners’ deficit | $ | 2,745,601 | | | $ | 2,736,760 | |
See accompanying notes to consolidated financial statements.
USA COMPRESSION PARTNERS, LP
Consolidated Statements of Operations
(in thousands, except per unit amounts)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | 2022 |
| Revenues: | | | | | |
| Contract operations | $ | 885,250 | | | $ | 802,562 | | | $ | 673,214 | |
| Parts and service | 23,897 | | | 21,890 | | | 15,729 | |
| Related party | 41,302 | | | 21,726 | | | 15,655 | |
| Total revenues | 950,449 | | | 846,178 | | | 704,598 | |
| Costs and expenses: | | | | | |
| Cost of operations, exclusive of depreciation and amortization | 312,726 | | | 284,708 | | | 234,336 | |
| Depreciation and amortization | 264,756 | | | 246,096 | | | 236,677 | |
| Selling, general, and administrative | 72,666 | | | 72,714 | | | 61,278 | |
| Loss (gain) on disposition of assets | 4,939 | | | (1,667) | | | 1,527 | |
| Impairment of assets | 913 | | | 12,346 | | | 1,487 | |
| | | | | |
| Total costs and expenses | 656,000 | | | 614,197 | | | 535,305 | |
| Operating income | 294,449 | | | 231,981 | | | 169,293 | |
| Other income (expense): | | | | | |
| Interest expense, net | (193,471) | | | (169,924) | | | (138,050) | |
| Loss on extinguishment of debt | (4,966) | | | — | | | — | |
| Gain on derivative instrument | 5,684 | | | 7,449 | | | — | |
| Other | 110 | | | 127 | | | 91 | |
| Total other expense | (192,643) | | | (162,348) | | | (137,959) | |
| Net income before income tax expense | 101,806 | | | 69,633 | | | 31,334 | |
| Income tax expense | 2,231 | | | 1,365 | | | 1,016 | |
| Net income | 99,575 | | | 68,268 | | | 30,318 | |
| Less: distributions on Preferred Units | (17,550) | | | (47,775) | | | (48,750) | |
| Net income (loss) attributable to common unitholders’ interests | $ | 82,025 | | | $ | 20,493 | | | $ | (18,432) | |
| | | | | |
| Weighted-average common units outstanding – basic | 113,389 | | | 98,634 | | | 97,780 | |
| | | | | |
| Weighted-average common units outstanding – diluted | 114,501 | | | 100,675 | | | 97,780 | |
| | | | | |
| Basic net income (loss) per common unit | $ | 0.72 | | | $ | 0.21 | | | $ | (0.19) | |
| | | | | |
| Diluted net income (loss) per common unit | $ | 0.72 | | | $ | 0.20 | | | $ | (0.19) | |
| | | | | |
| Distributions declared per common unit for respective periods | $ | 2.10 | | | $ | 2.10 | | | $ | 2.10 | |
See accompanying notes to consolidated financial statements.
USA COMPRESSION PARTNERS, LP
Consolidated Statements of Changes in Partners’ Capital (Deficit)
(in thousands)
| | | | | | | | | | | | | | | | | |
| Common Units | | Warrants | | Total |
| Partners’ capital ending balance, December 31, 2021 | $ | 87,129 | | | $ | 13,979 | | | $ | 101,108 | |
| Vesting of phantom units | 3,860 | | | — | | | 3,860 | |
| Distributions and DERs, $2.10 per unit | (205,219) | | | — | | | (205,219) | |
| Issuance of common units under the DRIP | 2,132 | | | — | | | 2,132 | |
| Unit-based compensation for equity-classified awards | 252 | | | — | | | 252 | |
| Exercise and conversion of warrants into common units | 5,167 | | | (5,167) | | | — | |
| Net loss attributable to common unitholders’ interests | (18,432) | | | — | | | (18,432) | |
| Partners’ capital (deficit) ending balance, December 31, 2022 | (125,111) | | | 8,812 | | | (116,299) | |
| Vesting of phantom units | 6,878 | | | — | | | 6,878 | |
| Distributions and DERs, $2.10 per unit | (206,488) | | | — | | | (206,488) | |
| Issuance of common units under the DRIP | 1,860 | | | — | | | 1,860 | |
| Unit-based compensation for equity-classified awards | 271 | | | — | | | 271 | |
| Exercise and conversion of warrants into common units | 8,812 | | | (8,812) | | | — | |
| Net income attributable to common unitholders’ interests | 20,493 | | | — | | | 20,493 | |
| Partners’ deficit ending balance, December 31, 2023 | (293,285) | | | — | | | (293,285) | |
| Vesting of phantom units | 5,975 | | | — | | | 5,975 | |
| Distributions and DERs, $2.10 per unit | (238,483) | | | — | | | (238,483) | |
| Issuance of common units under the DRIP | 1,552 | | | — | | | 1,552 | |
| Unit-based compensation for equity-classified awards | 465 | | | — | | | 465 | |
| Exercise and conversion of Preferred Units into common units | 300,700 | | | — | | | 300,700 | |
| Net income attributable to common unitholders’ interests | 82,025 | | | — | | | 82,025 | |
| Partners’ deficit ending balance, December 31, 2024 | $ | (141,051) | | | $ | — | | | $ | (141,051) | |
See accompanying notes to consolidated financial statements.
USA COMPRESSION PARTNERS, LP
Consolidated Statements of Cash Flows
(in thousands) | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | 2022 |
| Cash flows from operating activities: | | | | | |
| Net income | $ | 99,575 | | | $ | 68,268 | | | $ | 30,318 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 264,756 | | | 246,096 | | | 236,677 | |
| Provision for expected credit losses | 630 | | | 1,500 | | | (700) | |
| Amortization of debt issuance costs | 8,748 | | | 7,279 | | | 7,265 | |
| Unit-based compensation expense | 16,552 | | | 22,169 | | | 15,894 | |
| Deferred income tax expense (benefit) | 574 | | | (52) | | | (151) | |
| Loss (gain) on disposition of assets | 4,939 | | | (1,667) | | | 1,527 | |
| Loss on extinguishment of debt | 4,966 | | | — | | | — | |
| Change in fair value of derivative instrument | 1,204 | | | (1,204) | | | — | |
| Impairment of assets | 913 | | | 12,346 | | | 1,487 | |
| | | | | |
| Changes in assets and liabilities: | | | | | |
| Accounts receivable and related-party receivables, net | 5,677 | | | (13,047) | | | 29,980 | |
| Inventories | (101,855) | | | (76,796) | | | (31,594) | |
| Prepaid expenses and other current assets | (1,350) | | | (1,833) | | | (2,767) | |
| Other assets | 3,876 | | | 4,197 | | | 3,465 | |
| Accounts payable | (3,891) | | | 523 | | | 7,547 | |
| Accrued liabilities and deferred revenue | 35,610 | | | 4,106 | | | (38,358) | |
| Other liabilities | 410 | | | — | | | — | |
| Net cash provided by operating activities | 341,334 | | | 271,885 | | | 260,590 | |
| Cash flows from investing activities: | | | | | |
| Capital expenditures, net | (204,852) | | | (238,522) | | | (134,224) | |
| Proceeds from disposition of property and equipment | 1,337 | | | 5,334 | | | 3,682 | |
| Proceeds from insurance recovery | 1,501 | | | 535 | | | 597 | |
| Net cash used in investing activities | (202,014) | | | (232,653) | | | (129,945) | |
| Cash flows from financing activities: | | | | | |
| Proceeds from revolving credit facility | 1,117,843 | | | 1,089,191 | | | 844,549 | |
| Proceeds from issuance of senior notes | 1,000,000 | | | — | | | — | |
| Payments on revolving credit facility | (1,217,564) | | | (863,334) | | | (714,935) | |
| Investments in government securities in connection with legal defeasance of the Senior Notes 2026 | (748,764) | | | — | | | — | |
| Cash paid related to net settlement of unit-based awards | (5,354) | | | (6,446) | | | (2,961) | |
| Cash distributions on common units | (240,855) | | | (209,049) | | | (207,446) | |
| Cash distributions on Preferred Units | (24,375) | | | (48,750) | | | (48,750) | |
| Deferred financing costs | (18,603) | | | (379) | | | (549) | |
| Other | (1,645) | | | (489) | | | (518) | |
| Net cash used in financing activities | (139,317) | | | (39,256) | | | (130,610) | |
| Increase (decrease) in cash and cash equivalents | 3 | | | (24) | | | 35 | |
| Cash and cash equivalents, beginning of year | 11 | | | 35 | | | — | |
| Cash and cash equivalents, end of year | $ | 14 | | | $ | 11 | | | $ | 35 | |
| | | | | |
| See accompanying notes to consolidated financial statements. |
| | | | | | | | | | | | | | | | | |
| USA COMPRESSION PARTNERS, LP |
| Consolidated Statements of Cash Flows (continued) |
| (in thousands) |
| Year Ended December 31, |
| 2024 | | 2023 | | 2022 |
| Supplemental cash flow information: | | | | | |
| Cash paid for interest, net of capitalized amounts | $ | 154,296 | | | $ | 163,589 | | | $ | 128,961 | |
| Cash paid for income taxes | 1,461 | | | 1,146 | | | 887 | |
| Supplemental non-cash transactions: | | | | | |
| Non-cash distributions to certain common unitholders (DRIP) | $ | 1,552 | | | $ | 1,860 | | | $ | 2,132 | |
| Transfers from inventories to property and equipment, net | 78,524 | | | 54,570 | | | 22,329 | |
| Changes in capital expenditures included in accounts payable and accrued liabilities | (9,031) | | | 3,644 | | | 6,507 | |
| Changes in financing costs included in accounts payable and accrued liabilities | 14 | | | 125 | | | (265) | |
| Exercise and conversion of warrants into common units | — | | | 8,812 | | | 5,167 | |
| Exercise and conversion of Preferred Units into common units | 300,700 | | | — | | | — | |
| Government securities transferred in connection with the legal defeasance of the Senior Notes 2026 | 748,764 | | | — | | | — | |
| Legal defeasance of Senior Notes 2026 | 725,000 | | | — | | | — | |
See accompanying notes to consolidated financial statements.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
(1)Organization and Description of Business
Unless otherwise indicated, the terms “our,” “we,” “us,” “the Partnership,” and similar language refer to USA Compression Partners, LP, collectively with its consolidated subsidiaries.
We are a Delaware limited partnership. Through our operating subsidiaries, we provide natural gas compression services to customers under fixed-term contracts in the natural gas and crude oil industries, using compression packages that we design, engineer, own, operate, and maintain. We also own and operate a fleet of equipment used to provide natural gas treating services, such as carbon dioxide and hydrogen sulfide removal, cooling, and dehydration. We provide compression services in unconventional resource plays throughout the U.S., including the Utica, Marcellus, Permian, Denver-Julesburg, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, and Haynesville.
USA Compression GP, LLC, a Delaware limited liability company, serves as our general partner and is referred to herein as the “General Partner.” The General Partner is wholly owned by Energy Transfer.
The Partnership is a borrower under a revolving credit facility and its subsidiaries are guarantors of that revolving credit facility (see Note 10). The accompanying consolidated financial statements include the accounts of the Partnership and its subsidiaries, all of which are wholly owned by us.
Net income (loss) attributable to partners is allocated to our common units and participating securities using the two-class income allocation method. All intercompany balances and transactions have been eliminated in consolidation. Our common units trade on the NYSE under the ticker symbol “USAC”.
USA Compression Management Services, LLC (“USAC Management”), a wholly owned subsidiary of the General Partner, performs certain management, administrative and operating services for us, and provides us with personnel to manage and operate our business. All of our employees, including our executive officers, are employees of USAC Management. As of December 31, 2024, USAC Management had 854 full-time employees. None of our employees are subject to collective bargaining agreements.
(2)Basis of Presentation and Significant Accounting Policies
Basis of Presentation
Our accompanying consolidated financial statements have been prepared in accordance with GAAP and pursuant to SEC rules and regulations.
Use of Estimates
Our consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions by management that affect the reported amounts in these consolidated financial statements and the accompanying results. Although these estimates were based on management’s available knowledge of current and expected future events, actual results could differ from these estimates.
Significant Accounting Policies
Cash and Cash Equivalents
Cash and cash equivalents consist of all cash balances. We consider investments in highly liquid financial instruments purchased with an original maturity of 90 days or less to be cash equivalents.
Trade Accounts Receivable
Trade accounts receivable are recorded at their invoiced amounts.
Allowance for Credit Losses
We evaluate allowance for credit losses with reference to our trade accounts receivable balances, which are measured at amortized cost. Due to the short-term nature of our trade accounts receivable, we consider the amortized cost of trade accounts receivable to equal the receivable’s carrying amounts, excluding the allowance for credit losses.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
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 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 other companies within their industry.
Inventories
Inventories consist of serialized and non-serialized parts primarily used on compression units. All inventories are stated at the lower of cost or net realizable value. Serialized parts inventories are determined using the specific-identification cost method, while non-serialized parts inventories are determined using the weighted-average cost method. Purchases of inventories are considered operating activities within the Consolidated Statements of Cash Flows.
Property and Equipment
Property and equipment are carried at cost except for (i) certain acquired assets which are recorded at fair value on their respective acquisition dates and (ii) impaired assets which are recorded at fair value as of the last impairment evaluation date for which an adjustment was required. Overhauls and major improvements that increase the value or extend the life of compression equipment are capitalized and depreciated over three to five years. Ordinary maintenance and repairs are charged to cost of operations, exclusive of depreciation and amortization.
When property and equipment is retired or sold, the associated carrying value and the related accumulated depreciation are removed from our accounts and any related gains or losses are recorded within our Consolidated Statements of Operations within the period of sale or disposition.
Capitalized interest is calculated by multiplying our monthly effective interest rate on outstanding variable-rate indebtedness by the amount of qualifying costs, which include upfront payments to acquire certain compression units. Capitalized interest was $0.2 million, $0.9 million, and $0.9 million for the years ended December 31, 2024, 2023, and 2022, respectively.
Impairment of Long-Lived Assets
The carrying value of long-lived assets that are not expected to be recovered from future cash flows are written down to estimated fair value. We test long-lived assets for impairment when events or circumstances indicate that a long-lived asset’s carrying value may not be recoverable or will no longer be utilized within the operating fleet. The most common circumstance requiring compression units to be evaluated for impairment involves idle units that do not meet the desired performance characteristics of our revenue-generating horsepower.
The carrying value of a long-lived asset is not recoverable if the asset’s carrying value exceeds the sum of the undiscounted cash flows expected to be generated from the use and eventual disposition of the asset. If the carrying value of the long-lived asset exceeds the sum of the undiscounted cash flows associated with the asset, an impairment loss equal to the amount of the carrying value exceeding the fair value of the asset is recognized. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, based on an estimate of discounted cash flows, the expected net sale proceeds compared to the other similarly configured fleet units that we recently sold, or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to continue using.
Refer to Note 5 for more detailed information about impairment charges during the years ended December 31, 2024, 2023, and 2022.
Identifiable Intangible Assets
Identifiable intangible assets are recorded at cost and amortized using the straight-line method over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to our future cash flows. The estimated useful lives of our intangible assets range from 15 to 25 years.
We assess identifiable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We did not record any impairment of identifiable intangible assets for the years ended December 31, 2024, 2023, or 2022.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
Revenue Recognition
Revenue is recognized when obligations under the terms of a contract with our customer are satisfied; generally, this occurs with the provision of services or the transfer of goods. Revenue is measured at the amount of consideration we expect to receive in exchange for providing services or transferring goods. Incidental items, if any, that are immaterial in the context of the contract are recognized as expenses. Refer to Note 13 for more detailed information about revenue recognition for the years ended December 31, 2024, 2023, and 2022.
Unit-Based Compensation
Our unit-based compensation awards include phantom units, restricted units, and cash restricted units. The fair values of phantom units granted to employees and cash restricted units are estimated at the end of each reporting period and are accounted for as liabilities. The fair value of phantom units granted to directors and restricted units are determined at grant date and amortized using the straight-line method over the vesting period. Refer to Note 15 for more detailed information about our unit-based compensation awards.
Income Taxes
USA Compression Partners, LP is organized as a partnership for U.S. federal and state income tax purposes. As a result, our partners are responsible for U.S. federal and state income taxes on their distributive share of our items of income, gain, loss, or deduction. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities.
Texas also imposes an entity-level income tax on partnerships that is based on Texas-sourced taxable margin (the “Texas Margin Tax”). Texas Margin Tax impacts are included within our consolidated financial statements. Our wholly owned finance subsidiary, USA Compression Finance Corp. (“Finance Corp”), is a corporation for U.S. federal and state income tax purposes and any resulting tax impacts attributable to Finance Corp are included within our consolidated financial statements. Refer to Note 9 for more detailed information about the Texas Margin Tax for the years ended December 31, 2024, 2023, and 2022.
Pass-Through Taxes
Sales taxes incurred on behalf of, and passed through to, customers are accounted for on a net basis.
Fair-Value Measurements
Accounting standards applicable to fair-value measurements establish a framework for measuring fair value and stipulate disclosures about fair-value measurements. The standards apply to recurring and non-recurring financial and non-financial assets and liabilities that require or permit fair-value measurements. Among the required disclosures is the fair-value hierarchy of inputs we use to value an asset or a liability. The three levels of the fair-value hierarchy are described as follows:
Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date.
Level 2 inputs are those other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.
Level 3 inputs are unobservable inputs for the asset or liability.
As of December 31, 2024 and 2023, our financial instruments primarily consisted of cash and cash equivalents, trade accounts receivable, trade accounts payable, and long-term debt. As of December 31, 2023, our financial instruments also consisted of a derivative instrument. The book values of cash and cash equivalents, trade accounts receivable, and trade accounts payable are representative of fair value due to their short-term maturities. Our revolving credit facility applies floating interest rates to amounts drawn under the facility; therefore, the carrying amount of our revolving credit facility approximates its fair value.
The fair value of our Senior Notes 2026, Senior Notes 2027, and Senior Notes 2029 were estimated using quoted prices in inactive markets and are considered Level 2 measurements.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
The following table summarizes the aggregate principal amount and fair value of our Senior Notes 2026, Senior Notes 2027, and Senior Notes 2029 (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2024 | | 2023 |
| Senior Notes 2026, aggregate principal | $ | — | | | $ | 725,000 | |
| Fair value of Senior Notes 2026 | — | | | 720,621 | |
| Senior Notes 2027, aggregate principal | 750,000 | | | 750,000 | |
| Fair value of Senior Notes 2027 | 750,938 | | | 737,963 | |
| Senior Notes 2029, aggregate principal | 1,000,000 | | | — | |
| Fair value of Senior Notes 2029 | 1,007,500 | | | — | |
The fair value of our derivative instrument, which was an interest-rate swap and is no longer outstanding as of December 31, 2024, was estimated based on inputs from actively quoted public markets, including interest-rate forward curves, and is considered a Level 2 measurement. We consider counterparty credit risk and our own credit risk in the determination of the estimated fair value. The following table summarizes the gross fair value of our interest-rate swap (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2024 | | 2023 |
| Interest-rate swap | $ | — | | | $ | 1,204 | |
Refer to Note 8 for additional information on the interest-rate swap.
Operating Segment
We operate in a single business segment, the compression services business. Refer to Note 18 for more detailed information about our compression services segment.
(3)Trade Accounts Receivable
The allowance for credit losses, which was $1.5 million and $2.3 million at December 31, 2024 and 2023, respectively, represents our best estimate of the amount of probable credit losses included within our existing accounts receivable balance.
The following summarizes activity within our trade accounts receivable allowance for credit losses balance (in thousands):
| | | | | |
| Allowance for Credit Losses |
| Balance as of December 31, 2022 | $ | 1,164 | |
| Current-period provision for expected credit losses | 1,500 | |
| Write-offs charged against the allowance | (487) | |
| Recoveries collected | 83 | |
| Balance as of December 31, 2023 | 2,260 | |
| Current-period provision for expected credit losses | 630 | |
| Write-offs charged against the allowance | (1,416) | |
| |
| Balance as of December 31, 2024 | $ | 1,474 | |
Unfavorable developments related to a customer was the primary factor supporting the recognized increase to the allowance for credit losses for the year ended December 31, 2024.
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.
During the year ended December 31, 2022, we recognized a reversal of $0.7 million to the current-period 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.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
(4)Inventories
Components of inventories are as follows (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2024 | | 2023 |
| Serialized parts | $ | 66,631 | | | $ | 59,901 | |
| Non-serialized parts | 67,270 | | | 54,827 | |
| Total inventories | $ | 133,901 | | | $ | 114,728 | |
| | | |
| | | |
(5) Property and Equipment, Identifiable Intangible Assets, and Other Assets
Property and Equipment
Property and equipment consisted of the following (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2024 | | 2023 |
| Compression and treating equipment | $ | 4,134,544 | | | $ | 3,902,115 | |
| Automobiles and vehicles | 53,301 | | | 46,395 | |
| Computer equipment | 38,614 | | | 33,456 | |
| Leasehold improvements | 9,807 | | | 9,414 | |
| Buildings | 3,935 | | | 3,464 | |
| Furniture and fixtures | 963 | | | 868 | |
| Land | 77 | | | 77 | |
| Total property and equipment, gross | 4,241,241 | | | 3,995,789 | |
| Less: accumulated depreciation and amortization | (1,967,865) | | | (1,758,164) | |
| Total property and equipment, net | $ | 2,273,376 | | | $ | 2,237,625 | |
Depreciation is calculated using the straight-line method over the estimated useful lives of the assets as follows:
| | | | | |
| Compression and treating equipment, acquired new | 25 years |
| Compression and treating equipment, acquired used | 5 - 25 years |
| Furniture and fixtures | 3 - 10 years |
| Vehicles and computer equipment | 1 - 10 years |
| Buildings | 5 years |
| Leasehold improvements | 5 years |
Depreciation expense on property and equipment and loss (gain) on disposition of assets were as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | 2022 |
| Depreciation expense | $ | 235,377 | | | $ | 216,716 | | | $ | 207,297 | |
| Loss (gain) on disposition of assets | 4,939 | | | (1,667) | | | 1,527 | |
For the years ended December 31, 2024, 2023, and 2022, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 2, 42, and 15 compression units, respectively, representing approximately 1,260, 37,700, and 3,200 of aggregate horsepower, respectively, that previously were used to provide compression services in our business. As a result, we recorded impairments of compression equipment of $0.3 million, $12.3 million, and $1.5 million for the years ended December 31, 2024, 2023, and 2022, respectively.
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
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
that likely would prevent certain compression units from securing customer acceptance. These compression units were written down to their estimated salvage values, if any.
Identifiable Intangible Assets
Identifiable intangible assets, net consisted of the following (in thousands):
| | | | | | | | | | | | | | | | | |
| Customer
Relationships | | Trade Names | | Total |
| Gross balance as of December 31, 2023 | $ | 485,162 | | | $ | 65,500 | | | $ | 550,662 | |
| | | | | |
| Accumulated amortization | (260,523) | | | (44,487) | | | (305,010) | |
| Net balance as of December 31, 2023 | $ | 224,639 | | | $ | 21,013 | | | $ | 245,652 | |
| | | | | |
| Gross balance as of December 31, 2024 | $ | 485,162 | | | $ | 65,500 | | | $ | 550,662 | |
| Accumulated amortization | (286,628) | | | (47,761) | | | (334,389) | |
| Net balance as of December 31, 2024 | $ | 198,534 | | | $ | 17,739 | | | $ | 216,273 | |
Amortization expense for the years ended December 31, 2024, 2023, and 2022, was $29.4 million, $29.4 million, and $29.4 million, respectively.
The expected amortization of the intangible assets for each of the five succeeding years is as follows:
| | | | | | | | |
| Year Ending December 31, | | |
| 2025 | | $ | 29,380 | |
| 2026 | | 29,380 | |
| 2027 | | 14,486 | |
| 2028 | | 12,135 | |
| 2029 | | 12,135 | |
Other Assets
For the year ended December 31, 2024, we recognized a $0.6 million impairment of assets related to capitalized software costs that are no longer expected to provide benefit.
(6) Current Liabilities
Components of current liabilities included the following (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2024 | | 2023 |
| Accrued interest expense | $ | 39,337 | | | $ | 31,960 | |
| Accrued unit-based compensation liability | 22,766 | | | 21,896 | |
| Accrued payroll and benefits | 10,656 | | | 7,055 | |
| Accrued capital expenditures | 4,641 | | | 13,672 | |
| | | |
(7) Lease Accounting
We maintain both finance leases and operating leases, primarily related to office space, warehouse facilities, and certain corporate equipment. Our leases have remaining lease terms of up to seven years, some of which include options that permit renewals for additional periods.
We determine if an arrangement is a lease at inception. Operating leases are included in lease right-of-use (“ROU”) assets, accrued liabilities, and operating lease liabilities within our Consolidated Balance Sheets. Finance leases are included in property and equipment, accrued liabilities, and other liabilities within our Consolidated Balance Sheets.
ROU lease assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. ROU lease assets and liabilities are recognized at the commencement
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
date based on the present value of lease payments over the lease term. As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available on the commencement date in determining the present value of lease payments. ROU lease assets also include any lease payments made and exclude lease incentives. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. Variable costs such as our proportionate share of actual costs for utilities, common area maintenance, property taxes, and insurance are not included in the lease liability and are recognized in the period in which they are incurred.
For short-term leases (leases that have terms of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded. For certain equipment leases, such as office equipment, we account for the lease and non-lease components as a single-lease component.
Supplemental balance sheet information related to leases consisted of the following (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2024 | | 2023 |
| Operating leases: | | | |
| Lease right-of-use assets | $ | 14,336 | | | $ | 17,290 | |
| Accrued liabilities | (4,013) | | | (4,066) | |
| Operating lease liabilities | (11,678) | | | (14,731) | |
| Finance leases: | | | |
| Property and equipment, gross | $ | 4,417 | | | $ | 3,661 | |
| Accumulated depreciation | (3,130) | | | (2,628) | |
| Property and equipment, net | 1,287 | | | 1,033 | |
| Accrued liabilities | (374) | | | (459) | |
| Other liabilities | (1,127) | | | (722) | |
Components of lease expense consisted of the following (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| Income Statement Line Item | | 2024 | | 2023 | | 2022 |
| Operating lease costs: | | | | | | | |
| Operating lease cost | Cost of operations, exclusive of depreciation and amortization | | $ | 3,856 | | | $ | 3,586 | | | $ | 3,349 | |
| Operating lease cost | Selling, general, and administrative | | 1,442 | | | 1,490 | | | 1,490 | |
| Total operating lease costs | | | 5,298 | | | 5,076 | | | 4,839 | |
| Finance lease costs: | | | | | | | |
| Amortization of lease assets | Depreciation and amortization | | 502 | | | 351 | | | 376 | |
| Short-term lease costs: | | | | | | | |
| Short-term lease cost | Cost of operations, exclusive of depreciation and amortization | | 76 | | | 135 | | | 165 | |
| Short-term lease cost | Selling, general, and administrative | | — | | | 39 | | | 10 | |
| Total short-term lease costs | | | 76 | | | 174 | | | 175 | |
| Variable lease costs: | | | | | | | |
| Variable lease cost | Cost of operations, exclusive of depreciation and amortization | | 65 | | | 10 | | | 129 | |
| Variable lease cost | Selling, general, and administrative | | 963 | | | 803 | | | 649 | |
| Total variable lease costs | | | 1,028 | | | 813 | | | 778 | |
| Total lease costs | | | $ | 6,904 | | | $ | 6,414 | | | $ | 6,168 | |
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
The weighted-average remaining lease terms and weighted-average discount rates were as follows:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | 2022 |
| Weighted-average remaining lease term: | | | | | |
| Operating leases | 4 years | | 5 years | | 6 years |
| Finance leases | 4 years | | 4 years | | 4 years |
| Weighted-average discount rate: | | | | | |
| Operating leases | 5.4 | % | | 5.1 | % | | 4.9 | % |
| Finance leases | 7.2 | % | | 6.3 | % | | 5.2 | % |
Supplemental cash flow information related to leases consisted of the following (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | 2022 |
| Cash paid for amounts included in the measurement of lease liabilities: | | | | | |
| Operating cash flows from operating leases | $ | (5,439) | | | $ | (5,034) | | | $ | (4,743) | |
| Operating cash flows from finance leases | (157) | | | (174) | | | (124) | |
| Financing cash flows from finance leases | (436) | | | (489) | | | (518) | |
| ROU assets obtained in exchange for lease obligations: | | | | | |
| Operating leases | $ | 1,432 | | | $ | 3,105 | | | $ | 1,720 | |
| Finance leases | 756 | | | — | | | 790 | |
Maturities of lease liabilities as of December 31, 2024, consisted of the following (in thousands):
| | | | | | | | | | | | | | | | | |
| Operating Leases | | Finance Leases | | Total |
| 2025 | $ | 4,718 | | | $ | 477 | | | $ | 5,195 | |
| 2026 | 3,851 | | | 481 | | | 4,332 | |
| 2027 | 3,075 | | | 484 | | | 3,559 | |
| 2028 | 3,039 | | | 154 | | | 3,193 | |
| 2029 | 2,593 | | | 54 | | | 2,647 | |
| Thereafter | 255 | | | 99 | | | 354 | |
| Total lease payments | 17,531 | | | 1,749 | | | 19,280 | |
| Less: present-value discount | (1,840) | | | (248) | | | (2,088) | |
| Present value of lease liabilities | $ | 15,691 | | | $ | 1,501 | | | $ | 17,192 | |
As of December 31, 2024, we have not entered into any additional leases that have not yet commenced that create significant rights and obligations.
(8) Derivative Instrument
In August 2024, we elected to terminate an interest-rate swap we previously used to manage interest-rate risk associated with the floating-rate Credit Agreement. The interest-rate swap was outstanding as of December 31, 2023. The interest-rate swap’s notional principal amount was $700 million and had a termination date of December 31, 2025. Under the interest-rate swap, we paid a fixed interest rate of 3.9725% and received floating interest-rate payments that were indexed to the one-month SOFR.
We did not apply hedge accounting to our previously outstanding derivative. Our derivative was carried on the Consolidated Balance Sheets at fair value and was classified as current or long-term depending on the expected timing of settlement, and gains and losses associated with the derivative instrument were recognized currently in gain on derivative instrument within the Consolidated Statements of Operations. Cash flows related to cash settlements for the periods presented were classified as operating activities within the Consolidated Statements of Cash Flows.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
The following table summarizes the location and fair value of our derivative instrument on our Consolidated Balance Sheets (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Assets | | Liabilities |
| | December 31, | | December 31, |
| Balance Sheet Classification | | 2024 | | 2023 | | 2024 | | 2023 |
| Derivative instrument | | $ | — | | | $ | 5,670 | | | $ | — | | | $ | — | |
| Derivative instrument, long term | | — | | | — | | | — | | | 4,466 | |
The following table summarizes the location and amounts recognized related to our derivative instrument within our Consolidated Statements of Operations (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | 2022 |
| Gain on derivative instrument | $ | 5,684 | | | $ | 7,449 | | | $ | — | |
(9) Income Tax Expense
We are subject to the Texas Margin Tax, which applies a tax to our gross margin. We do not conduct business in any other state where a similar tax is applied. The Texas Margin Tax requires certain forms of legal entities, including limited partnerships, to pay a tax of 0.75% on its “margin,” as defined in the law, based on annual results. The tax base to which the tax is applied is the least of (i) 70% of total revenues for federal income tax purposes, (ii) total revenue less cost of goods sold, (iii) total revenue less compensation for federal income tax purposes, or (iv) total revenue less $1 million.
Components of our income tax expense are as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | 2022 |
| Current tax expense | $ | 1,657 | | | $ | 1,417 | | | $ | 1,167 | |
| Deferred tax expense (benefit) | 574 | | | (52) | | | (151) | |
| Total income tax expense | $ | 2,231 | | | $ | 1,365 | | | $ | 1,016 | |
Deferred income tax balances are the direct effect of temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities at the enacted tax rates expected to be in effect when the taxes are actually paid or recovered.
The tax effects of temporary differences related to property and equipment, identifiable intangible assets, and goodwill that gives rise to deferred tax assets (liabilities), included net within other liabilities, are as follows (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2024 | | 2023 |
| Deferred tax assets: | | | |
| Goodwill | $ | 11 | | | $ | 12 | |
| Deferred tax liabilities: | | | |
| Property and equipment | (4,763) | | | (4,189) | |
| Identifiable intangible assets | (23) | | | (24) | |
| Total deferred tax liabilities | (4,786) | | | (4,213) | |
| Deferred tax liabilities, net | $ | (4,775) | | | $ | (4,201) | |
Accounting Standard Codification (“ASC”) Topic 740 Income Taxes (“Topic 740”) provides guidance on measurement and recognition in accounting for income tax uncertainties and provides related guidance on derecognition, classification, disclosure, interest, and penalties. As of December 31, 2024, we had no material unrecognized tax benefits (as defined in Topic 740). We do not expect to incur interest charges or penalties related to our tax positions, but if such charges or penalties are incurred, our policy is to account for interest charges and penalties as income tax expense within the Consolidated Statements of Operations. Our U.S. Federal income tax returns for years 2019 and 2020 currently are under examination by the Internal Revenue Service (“IRS”). Refer to Note 17 for more detailed information about our IRS examinations. Examinations of our
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
Texas Margin Tax returns for report years 2018 through 2021 were completed in 2023 by the Texas Comptroller of Public Accounts with no material adjustments. In general, USA Compression and its subsidiaries are no longer subject to examination by the IRS, and most state jurisdictions, for the 2018 and prior years.
The Bipartisan Budget Act of 2015 provides that any tax adjustments (including any applicable penalties and interest) resulting from partnership audits generally will be determined at the partnership level for tax years beginning after December 31, 2017. To the extent possible under these rules, our General Partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised information statement to each unitholder, and former unitholder, with respect to an audited and adjusted return. The Bipartisan Budget Act of 2015 allows a partnership to elect to apply these provisions to any return of the partnership filed for partnership taxable years beginning after the date of the enactment, November 2, 2015. We do not intend to elect to apply these provisions for any tax return filed for partnership taxable years beginning before January 1, 2018.
(10) Debt Obligations
Our debt obligations, of which there is no current portion, consisted of the following (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2024 | | 2023 |
| Senior Notes 2026, aggregate principal | $ | — | | | $ | 725,000 | |
| Senior Notes 2027, aggregate principal | 750,000 | | | 750,000 | |
| Senior Notes 2029, aggregate principal | 1,000,000 | | | — | |
| Less: deferred financing costs, net of amortization | (19,535) | | | (10,725) | |
| Total senior notes, net | 1,730,465 | | | 1,464,275 | |
| Revolving credit facility | 772,092 | | | 871,813 | |
| Total long-term debt, net | $ | 2,502,557 | | | $ | 2,336,088 | |
Revolving Credit Facility
The Credit Agreement matures on December 8, 2026. The Credit Agreement has an aggregate commitment of $1.6 billion (subject to availability under our borrowing base). The Partnership’s obligations under the Credit Agreement are guaranteed by the guarantors party to the Credit Agreement, which currently consists of all of the Partnership’s subsidiaries. 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).
Borrowings under the Credit Agreement bear interest at a per-annum interest rate equal to, at the Partnership’s option, either the Alternate Base Rate or SOFR plus the applicable margin. “Alternate Base Rate” means the greatest of (i) the prime rate, (ii) the applicable federal funds effective rate plus 0.50%, and (iii) one-month SOFR rate plus 1.00%. The applicable margin for borrowings varies (a) in the case of SOFR loans, from 2.00% to 2.75% per annum, and (b) in the case of Alternate Base Rate loans, from 1.00% to 1.75% per annum, and are determined based on a total-leverage-ratio pricing grid. In addition, the Borrower is required to pay commitment fees based on the daily unused amount of the Credit Agreement in an amount equal to 0.375% per annum. Amounts borrowed and repaid under the Credit Agreement may be re-borrowed, subject to borrowing base availability.
The Credit Agreement permits us to make distributions of available cash to unitholders so long as (i) no default under the facility has occurred, is continuing, or would result from the distribution; (ii) immediately prior to and after giving effect to such distribution, we are in compliance with the facility’s financial covenants; and (iii) immediately prior to and after giving effect to such distribution, we have availability under the Credit Agreement of at least $100 million. In addition, the Credit Agreement contains various covenants that may limit, among other things, our ability to (subject to exceptions):
•grant liens;
•make certain loans or investments;
•incur additional indebtedness or guarantee other indebtedness;
•enter into transactions with affiliates;
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
•merge or consolidate;
•sell our assets; and
•make certain acquisitions.
The Credit Agreement also contains various financial covenants, including covenants requiring us to maintain:
•a minimum EBITDA to interest coverage ratio of 2.50 to 1.00, determined as of the last day of each fiscal quarter, with EBITDA and interest expense annualized for the most-recent fiscal quarter;
•a ratio of total secured indebtedness to EBITDA not greater than 3.00 to 1.00 or less than 0.00 to 1.00, determined as of the last day of each fiscal quarter, with EBITDA annualized for the most-recent fiscal quarter; and
•a maximum funded debt-to-EBITDA ratio, defined in the Credit Agreement as the Total Leverage Ratio, determined as of the last day of each fiscal quarter with EBITDA annualized for the most-recent fiscal quarter, of 5.25 to 1.00. In addition, the Partnership may increase the applicable ratio by 0.25 for any fiscal quarter during which a Specified Acquisition (as defined in the Credit Agreement) occurs and for the following two fiscal quarters, but in no event shall the maximum ratio exceed 5.50 to 1.00 for any fiscal quarter as a result of such increase.
For purposes of the above covenants, EBITDA is calculated as set forth in the Credit Agreement. If a default exists under the Credit Agreement, the lenders will be able to accelerate the maturity on the amount then outstanding and exercise other rights and remedies.
As of December 31, 2024, we were in compliance with all of our covenants under the Credit Agreement.
As of December 31, 2024, we had outstanding borrowings under the Credit Agreement of $772.1 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $827.1 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $782.5 million was available to be drawn. The borrowing base consists of eligible accounts receivable, inventory, and compression units. The largest component, representing 94% of the borrowing base as of December 31, 2024, was eligible compression units. Eligible compression units consist of compressor packages that are under service contracts, leased or rented, and carried in the financial statements as fixed assets.
Our weighted-average interest rate in effect for all borrowings under the Credit Agreement for the year ended December 31, 2024, was 7.81%, and our weighted-average interest rate under the Credit Agreement as of December 31, 2024, was 6.98%.
The Credit Agreement is a “revolving credit facility” that includes a lockbox arrangement, whereby remittances from customers are made to a bank account controlled by the administrative agent. While we are not required by the terms of the Credit Agreement to use these customer remittances to reduce borrowings under the facility unless certain events of default occur under the Credit Agreement or unused availability under the facility is reduced below $70 million, we have in the past routinely applied such remittances to reduce borrowings under the facility.
Issuance of Senior Notes 2029
On March 18, 2024, the Partnership and Finance Corp co-issued the Senior Notes 2029, a $1.0 billion aggregate principal amount of senior notes that will mature on March 15, 2029. The Senior Notes 2029 accrue interest from March 18, 2024 at the rate of 7.125% per year. Interest on the Senior Notes 2029 is payable semi-annually in arrears on each of March 15 and September 15, which commenced on September 15, 2024.
At any time prior to March 15, 2026, we may redeem up to 40% of the aggregate principal amount of the Senior Notes 2029 at a redemption price equal to 107.125% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in an amount not greater than the net cash proceeds from one or more equity offerings, provided that at least 60% of the aggregate principal amount of the Senior Notes 2029 remains outstanding immediately after the occurrence of such redemption (excluding Senior Notes 2029 held by us and our subsidiaries) and redemption occurs within 180 days of the date of the closing of such equity offering.
Prior to March 15, 2026, we may redeem all or a part of the Senior Notes 2029 at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date and accrued and unpaid interest, if any, to the redemption date.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
On or after March 15, 2026, we may redeem all or a part of the Senior Notes 2029 at redemption prices (expressed as percentages of the principal amount) set forth below, plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on March 15 of the years indicated below:
| | | | | |
| Year | Percentages |
| 2026 | 103.563 | % |
| 2027 | 101.781 | % |
| 2028 and thereafter | 100.000 | % |
If we experience a change of control followed by a ratings decline, which ratings decline is caused by the applicable change of control event, unless we have previously exercised, or concurrently exercise, our right to redeem the Senior Notes 2029 (as described above), we may be required to offer to repurchase the Senior Notes 2029 at a purchase price equal to 101% of the principal amount repurchased, plus accrued and unpaid interest, if any, to the repurchase date.
In connection with issuing the Senior Notes 2029, we incurred certain issuance costs in the amount of $18.2 million, which are amortized over the expected term of the Senior Notes 2029.
The indenture governing the Senior Notes 2029 (the “2029 Indenture”) contains certain financial covenants that we must comply with in order to make certain restricted payments as described in the 2029 Indenture. As of December 31, 2024, we were in compliance with such financial covenants under the 2029 Indenture.
The Senior Notes 2029 are fully and unconditionally guaranteed (the “2029 Guarantees”), jointly and severally, on a senior unsecured basis by all of our existing subsidiaries (other than Finance Corp), and will be fully and unconditionally guaranteed, jointly and severally, by each of our future restricted subsidiaries that either borrows under, or guarantees, the Credit Agreement or guarantees certain of our other indebtedness (collectively, the “Guarantors”). The Senior Notes 2029 and the 2029 Guarantees are general unsecured obligations and rank equally in right of payment with all of the Guarantors’, Finance Corp’s, and our existing and future senior indebtedness and senior to the Guarantors’, Finance Corp’s, and our future subordinated indebtedness, if any. The Senior Notes 2029 and the 2029 Guarantees effectively are subordinated in right of payment to all of the Guarantors’, Finance Corp’s, and our existing and future secured debt, including debt under the Credit Agreement and guarantees thereof, to the extent of the value of the assets securing such debt, and are structurally subordinate to all indebtedness of any of our subsidiaries that do not guarantee the Senior Notes 2029.
Redemption of Senior Notes 2026
On March 18, 2024, in connection with the issuance of the Senior Notes 2029, the Senior Notes 2026, which had a maturity date of April 1, 2026, and an aggregate outstanding principal balance of $725.0 million at such time, were satisfied and discharged under the Indenture governing the Senior Notes 2026, which constituted a legal defeasance under GAAP (the “Defeasance”).
The Defeasance required a cash outlay in the net amount of $748.8 million, which was used to purchase U.S. government securities. These securities generated sufficient cash upon maturity to fund interest payments on the Senior Notes 2026 occurring between the effective date of the Defeasance through April 4, 2024, when the Senior Notes 2026 were redeemed at par, as well as fund the redemption of the Senior Notes 2026 in full. As a result of the Defeasance, we recognized a loss on early extinguishment of debt of $5.0 million for the year ended December 31, 2024, which represents the write-off of deferred financing costs of $4.3 million and the difference between (i) the purchase price of U.S. government securities of $748.8 million and (ii) the aggregate outstanding principal balance and accrued interest of the Senior Notes 2026 of $748.1 million at the time of Defeasance.
Senior Notes 2027
On March 7, 2019, the Partnership and Finance Corp co-issued the Senior Notes 2027. The Senior Notes 2027 mature 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.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
We may redeem all or a part of the Senior Notes 2027 at redemption prices (expressed as percentages of the principal amount) set forth below, plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on September 1 of the years indicated below:
| | | | | |
| Year | Percentages |
| |
| 2024 | 101.719 | % |
| 2025 and thereafter | 100.000 | % |
If we experience a change of control followed by a ratings decline, unless we have previously exercised, or concurrently exercise, our right to redeem the Senior Notes 2027 (as described above), we may be required to offer to repurchase the Senior Notes 2027 at a purchase price equal to 101% of the principal amount repurchased, plus accrued and unpaid interest, if any, to the repurchase date.
The indenture governing the Senior Notes 2027 (the “2027 Indenture”) contains certain financial covenants that we must comply with in order to make certain restricted payments as described in the 2027 Indenture. As of December 31, 2024, we were in compliance with such financial covenants under the 2027 Indenture.
The Senior Notes 2027 are fully and unconditionally guaranteed (the “2027 Guarantees”), jointly and severally, on a senior unsecured basis by the Guarantors. The Senior Notes 2027 and the 2027 Guarantees are general unsecured obligations and rank equally in right of payment with all of the Guarantors’, Finance Corp’s, and our existing and future senior indebtedness and senior to the Guarantors’, Finance Corp’s, and our future subordinated indebtedness, if any. The Senior Notes 2027 and the 2027 Guarantees effectively are subordinated in right of payment to all of the Guarantors’, Finance Corp’s, and our existing and future secured debt, including debt under the Credit Agreement and guarantees thereof, to the extent of the value of the assets securing such debt, and are structurally subordinate to all indebtedness of any of our subsidiaries that do not guarantee the Senior Notes 2027.
We have no assets or operations independent of our subsidiaries, and there are no significant restrictions on our ability to obtain funds from our subsidiaries by dividend or loan. Each of the Guarantors is 100% owned by us. None of the assets of our subsidiaries represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended.
Subsidiary Guarantors
The Partnership may from time to time file a Registration Statement on Form S-3 with the SEC to register the issuance and sale of, among other securities, debt securities, which may be co-issued by Finance Corp (together with the Partnership, the “Issuers”) and fully and unconditionally guaranteed on a joint and several basis by the Partnership’s operating subsidiaries for the benefit of each holder and the trustee. Such guarantees are expected to be subject to release, subject to certain limitations, as follows (i) upon the sale, exchange or transfer, by way of a merger or otherwise, to any person that is not our affiliate, of all of our direct or indirect limited partnership or other equity interest in such subsidiary guarantor; or (ii) upon delivery by an Issuer of a written notice to the trustee of the release or discharge of all guarantees by such subsidiary guarantor of any debt of the Issuers other than obligations arising under the indenture governing such debt and any debt securities issued under such indenture, except a discharge or release by or as a result of payment under such guarantees.
Maturities of long-term debt for each of the five succeeding years are as follows (in thousands):
| | | | | | | | |
| Year Ending December 31, | | |
| 2025 | | $ | — | |
| 2026 | | 772,092 | |
| 2027 | | 750,000 | |
| 2028 | | — | |
| 2029 | | 1,000,000 | |
| | |
(11) Preferred Units
Preferred Unit and Warrant Private Placement
On April 2, 2018, we completed a private placement of $500 million in the aggregate of (i) newly authorized and established Preferred Units and (ii) two tranches of warrants to purchase common units with certain investment funds managed,
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
or advised, by EIG Global Energy Partners. We issued the holders of the Preferred Units an aggregate of 500,000 Preferred Units with a face value of $1,000 per Preferred Unit, a tranche of warrants with the right to purchase 10,000,000 common units with a strike price of $19.59 per common unit, and a tranche of warrants with the right to purchase 5,000,000 common units with a strike price of $17.03 per common unit. Refer to Note 12 for further information on these warrants.
On November 13, 2018, the Partnership filed a Registration Statement on Form S-3 to register 41,202,553 common units that are potentially issuable upon conversion of the Preferred Units and exercise of the warrants described above.
The Preferred Units rank senior to our common units with respect to distributions and liquidation rights. The holders of the Preferred Units are entitled to receive cumulative quarterly cash distributions equal to $24.375 per Preferred Unit.
The change in Preferred Units outstanding was as follows:
| | | | | |
| Preferred Units Outstanding |
| Number of Preferred Units outstanding, December 31, 2023 | 500,000 | |
| Exercise and conversion of Preferred Units into common units | (320,000) | |
| Number of Preferred Units outstanding, December 31, 2024 | 180,000 | |
We have declared and paid per-unit quarterly cash distributions to the holders of the Preferred Units of record as follows:
| | | | | | | | |
| Payment date | | Distribution per Preferred Unit |
| February 4, 2022 | | $ | 24.375 | |
| May 6, 2022 | | 24.375 | |
| August 5, 2022 | | 24.375 | |
| November 4, 2022 | | 24.375 | |
| Total 2022 distributions | | $ | 97.50 | |
| | |
| February 3, 2023 | | $ | 24.375 | |
| May 5, 2023 | | 24.375 | |
| August 4, 2023 | | 24.375 | |
| November 3, 2023 | | 24.375 | |
| Total 2023 distributions | | $ | 97.50 | |
| | |
| February 2, 2024 | | $ | 24.375 | |
| May 3, 2024 | | 24.375 | |
| August 2, 2024 | | 24.375 | |
| November 1, 2024 | | 24.375 | |
| Total 2024 distributions | | $ | 97.50 | |
Announced Quarterly Distribution
On January 16, 2025, we declared a cash distribution of $24.375 per unit on our Preferred Units. The distribution was paid on February 7, 2025, to the holders of the Preferred Units of record as of the close of business on January 27, 2025.
Redemption and Conversion Features
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”). The conversion rate for the Preferred Units is the quotient of (i) the sum of (a) $1,000, plus (b) any unpaid cash distributions on the applicable Preferred Unit, divided by (ii) $20.0115 for each Preferred Unit. As of December 31, 2024, the remaining Preferred Units outstanding are convertible into a maximum number of 8,994,827 common units, assuming there are no unpaid cash distributions on the Preferred Units.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
The holders of the Preferred Units are entitled to vote on an as-converted basis with the common unitholders and (as proportionately adjusted for unit splits, unit distributions, and similar transactions) will have certain other class voting rights with respect to any amendment to the Partnership Agreement that would adversely affect any rights, preferences, or privileges of the Preferred Units. In addition, upon certain events involving a change of control, the holders of the Preferred Units may elect, among other potential elections, to convert their Preferred Units to common units at the then change of control conversion rate.
We have the option to redeem all or any portion of the Preferred Units outstanding, subject to certain minimum redemption threshold amounts, for a redemption price set forth in the Partnership Agreement. On or after April 2, 2028, each holder of the Preferred Units will have the right to require us to redeem all or a portion of their Preferred Units, subject to certain minimum redemption threshold amounts, for a redemption price set forth in the Partnership Agreement, which we may elect to pay up to 50% in common units, subject to certain additional limits. The Preferred Units are presented as temporary equity within the mezzanine section of the Consolidated Balance Sheets because the redemption provisions on or after April 2, 2028 are outside the Partnership’s control.
The Preferred Units were recorded at their issuance date fair value, net of issuance cost. Net income allocations increase the carrying value and declared distributions decrease the carrying value of the Preferred Units. As the Preferred Units are not currently redeemable, and it is not probable that they will become redeemable, adjustment to the initial carrying value is not necessary and would only be required if it becomes probable that the Preferred Units would become redeemable.
January 2024 Conversion
On January 12, 2024, the holders of the Preferred Units elected to convert 40,000 Preferred Units into 1,998,850 common units. These Preferred Units were converted into common units and, for our fourth-quarter 2023 distribution, the holders received the common unit distribution of $0.525 on the 1,998,850 common units in lieu of the Preferred Unit distribution of $24.375 on the converted 40,000 Preferred Units.
April 2024 Conversion
On April 1, 2024, the holders of the Preferred Units elected to convert 280,000 Preferred Units into 13,991,954 common units. These Preferred Units were converted into common units and, for our first-quarter 2024 distribution, the holders received the common unit distribution of $0.525 on the 13,991,954 common units in lieu of the Preferred Unit distribution of $24.375 on the converted 280,000 Preferred Units.
Changes in the Preferred Units’ balance are as follows (in thousands):
| | | | | |
| Preferred Units |
| Balance as of December 31, 2021 | $ | 477,309 | |
| Net income allocated to Preferred Units | 48,750 | |
| Cash distributions on Preferred Units | (48,750) | |
| Balance as of December 31, 2022 | 477,309 | |
| Net income allocated to Preferred Units | 47,775 | |
| Cash distributions on Preferred Units | (48,750) | |
| Balance as of December 31, 2023 | 476,334 | |
| Net income allocated to Preferred Units | 17,550 | |
| Cash distributions on Preferred Units | (24,375) | |
| Exercise and conversion of Preferred Units into common units | (300,700) | |
| Balance as of December 31, 2024 | $ | 168,809 | |
Refer to Note 14 for information about the rights EIG Veteran Equity Aggregator, L.P. (along with its affiliated funds, “EIG”) has to designate one of the members of the board of directors of the General Partner (the “Board”).
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
(12) Partners’ Deficit
Common Units
The change in common units outstanding were as follows:
| | | | | |
| Common Units Outstanding |
| Number of common units outstanding, December 31, 2021 | 97,344,707 | |
| Vesting of phantom units | 224,386 | |
| Issuance of common units under the DRIP | 124,255 | |
| Exercise and conversion of warrants into common units | 534,308 | |
| Number of common units outstanding, December 31, 2022 | 98,227,656 | |
| Vesting of phantom units | 310,059 | |
| Issuance of common units under the DRIP | 87,808 | |
| Exercise and conversion of warrants into common units | 2,360,488 | |
| Number of common units outstanding, December 31, 2023 | 100,986,011 | |
| Vesting of phantom units | 272,616 | |
| Issuance of common units under the DRIP | 65,352 | |
| Exercise and conversion of Preferred Units into common units | 15,990,804 | |
| Number of common units outstanding, December 31, 2024 | 117,314,783 | |
As of December 31, 2024, Energy Transfer held 46,056,228 common units, including 8,000,000 common units held by the General Partner and controlled by Energy Transfer.
The limited partners holding our common units have the following rights, among others:
•right to receive distributions of our available cash within 45 days after the end of each quarter, so long as we have paid the required distributions on the Preferred Units for such quarter;
•right to transfer limited partner unit ownership to substitute limited partners;
•right to approve certain amendments of the Partnership Agreement;
•right to electronic access of an annual report, containing audited financial statements and a report on those financial statements by our independent public accountants, within 90 days after the close of the fiscal year end; and
•right to receive information reasonably required for tax reporting purposes within 90 days after the close of the calendar year.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
Cash Distributions
We have declared and paid per-unit quarterly distributions to our limited partner unitholders of record, including holders of our common and phantom units, as follows (dollars in millions, except distribution per unit):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Payment Date | | Distribution per
Limited Partner
Unit | | Amount Paid to
Common
Unitholders | | Amount Paid to
Phantom
Unitholders | | Total
Distribution |
| February 4, 2022 | | $ | 0.525 | | | $ | 51.1 | | | $ | 1.2 | | | $ | 52.3 | |
| May 6, 2022 | | 0.525 | | | 51.1 | | | 1.2 | | | 52.3 | |
| August 5, 2022 | | 0.525 | | | 51.4 | | | 1.1 | | | 52.5 | |
| November 4, 2022 | | 0.525 | | | 51.5 | | | 1.0 | | | 52.5 | |
| Total 2022 distributions | | $ | 2.10 | | | $ | 205.1 | | | $ | 4.5 | | | $ | 209.6 | |
| | | | | | | | |
| February 3, 2023 | | $ | 0.525 | | | $ | 51.6 | | | $ | 1.1 | | | $ | 52.7 | |
| May 5, 2023 | | 0.525 | | | 51.6 | | | 1.1 | | | 52.7 | |
| August 4, 2023 | | 0.525 | | | 51.6 | | | 1.2 | | | 52.8 | |
| November 3, 2023 | | 0.525 | | | 51.6 | | | 1.1 | | | 52.7 | |
| Total 2023 distributions | | $ | 2.10 | | | $ | 206.4 | | | $ | 4.5 | | | $ | 210.9 | |
| | | | | | | | |
| February 2, 2024 | | $ | 0.525 | | | $ | 54.1 | | | $ | 1.0 | | | $ | 55.1 | |
| May 3, 2024 | | 0.525 | | | 61.4 | | | 1.0 | | | 62.4 | |
| August 2, 2024 | | 0.525 | | | 61.4 | | | 1.0 | | | 62.4 | |
| November 1, 2024 | | 0.525 | | | 61.5 | | | 1.0 | | | 62.5 | |
| Total 2024 distributions | | $ | 2.10 | | | $ | 238.4 | | | $ | 4.0 | | | $ | 242.4 | |
Announced Quarterly Distribution
On January 16, 2025, we announced a cash distribution of $0.525 per unit on our common units. The distribution was paid on February 7, 2025, to common unitholders of record as of the close of business on January 27, 2025.
DRIP
During the years ended December 31, 2024, 2023, and 2022, distributions of $1.6 million, $1.9 million, and $2.1 million, respectively, were reinvested under the DRIP resulting in the issuance of 65,352, 87,808, and 124,255 common units, respectively.
On August 5, 2020, we filed a registration statement on Form S-3 for the issuance of up to 5,000,000 units under the DRIP.
Warrants
On April 27, 2022, the tranche of warrants with the right to purchase 5,000,000 common units with a strike price of $17.03 per common unit was exercised in full by the holders. The exercise of these warrants was net settled by the Partnership for 534,308 common units.
On October 27, 2023, the tranche of warrants with the right to purchase 10,000,000 common units with a strike price of $19.59 per common unit was exercised in full by the holders. The exercise of the warrants was net settled by the Partnership for 2,360,488 common units.
No warrants remained outstanding subsequent to the exercise on October 27, 2023.
Income (Loss) Per Unit
The computation of income (loss) per unit is based on the weighted average number of participating securities, which includes our common units and certain equity-based awards outstanding during the applicable period. Basic income (loss) per unit is determined by dividing net income (loss) allocated to participating securities after deducting the amount distributed on Preferred Units, by the weighted-average number of participating securities outstanding during the period. Income (loss) attributable to unitholders is allocated to participating securities based on their respective shares of the distributed and
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
undistributed earnings for the period. To the extent cash distributions exceed net income (loss) attributable to unitholders for the period, the excess distributions are allocated to all participating securities outstanding based on their respective ownership percentages.
Diluted income (loss) per unit is computed using the treasury stock method, which considers the potential issuance of limited partner units associated with our long-term incentive plan and warrants. Unvested phantom and restricted units, and unexercised warrants are not included in basic income (loss) per unit, as they are not considered to be participating securities, but are included in the calculation of diluted income (loss) per unit to the extent they are dilutive, and in the case of warrants to the extent they are considered “in the money.”
For the year ended December 31, 2024, approximately 1,112,000 incremental unvested phantom and restricted units represent the difference between our basic and diluted weighted-average common units outstanding.
For the year ended December 31, 2023, approximately 1,167,000 and 873,000 incremental unvested phantom units and “in the money” then-outstanding warrants, respectively, represent the difference between our basic and diluted weighted-average common units outstanding.
For the year ended December 31, 2022, approximately 980,000 and 42,000 incremental unvested phantom units and “in the money” then-outstanding warrants, respectively, were excluded from the calculation of diluted loss per unit because the impact was anti-dilutive.
(13) Revenue Recognition
Disaggregation of Revenue
The following table disaggregates our revenue by type of service (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | 2022 |
| Contract operations revenue | $ | 925,243 | | | $ | 823,661 | | | $ | 688,857 | |
| Retail parts and services revenue | 25,206 | | | 22,517 | | | 15,741 | |
| Total revenues | $ | 950,449 | | | $ | 846,178 | | | $ | 704,598 | |
The following table disaggregates our revenue by timing of provision of services or transfer of goods (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | 2022 |
| Services provided over time: | | | | | |
| Primary term | $ | 799,161 | | | $ | 643,284 | | | $ | 489,091 | |
| Month-to-month | 126,082 | | | 180,377 | | | 199,766 | |
| Total services provided over time | 925,243 | | | 823,661 | | | 688,857 | |
| Services provided or goods transferred at a point in time | 25,206 | | | 22,517 | | | 15,741 | |
| Total revenues | $ | 950,449 | | | $ | 846,178 | | | $ | 704,598 | |
Contract operations revenue
Revenue from contracted compression, natural gas treating, and maintenance services is recognized ratably as services are provided to our customers under our fixed-fee contracts over the term of the contract. Initial contract terms typically range from six months to five years. However, we usually continue to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. We primarily enter into fixed-fee contracts whereby our customers are required to pay our monthly fee even during periods of limited or disrupted throughput. Services generally are billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment generally is due 30 days after receipt of our invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration we receive and revenue we recognize is based on the fixed-fee rate stated in each service contract.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower.
Our contracts with customers may include multiple performance obligations. For such arrangements, we allocate revenues to each performance obligation based on its relative standalone service fee. We generally determine standalone service fees based on the service fees charged to customers or use expected cost plus margin.
The majority of our service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based on specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month-to-month and is promised consecutively over the service contract term. We measure progress and performance of the service consistently using a straight-line, time-based method as each month passes, because our performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by our service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. We have elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on our performance completed to date.
There are typically no material obligations for returns or refunds. Our standard contracts do not usually include material non-cash consideration.
Retail parts and services revenue
Retail parts and services revenue primarily is earned on directly reimbursable freight and crane charges that are the financial responsibility of the customers and maintenance work on units at customer locations that are outside the scope of core maintenance activities. Revenue from retail parts and services is recognized at the point-in-time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after we have performed our services. We bill upon completion of the service or transfer of the parts, and payment generally is due 30 days after receipt of our invoice. The amount of consideration we receive and revenue we recognize is based on the invoice amount. There are typically no material obligations for returns, refunds, or warranties. Our standard contracts do not usually include material variable or non-cash consideration.
Deferred Revenue
We record deferred revenue when cash payments are received or due in advance of our performance. Components of deferred revenue were as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| | | December 31, |
| Balance sheet location | | 2024 | | 2023 |
| Current (1) | Deferred revenue | | $ | 63,900 | | | $ | 62,589 | |
| Noncurrent | Other liabilities | | 6,616 | | | 6,000 | |
| Total | | $ | 70,516 | | | $ | 68,589 | |
________________________
(1)We recognized $61.9 million of revenue during the year ended December 31, 2024, related to our deferred revenue balance as of December 31, 2023.
Performance Obligations
As of December 31, 2024, the aggregate amount of transaction price allocated to unsatisfied performance obligations related to our contract operations revenue was $1.2 billion. We expect to recognize these remaining performance obligations as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2025 | | 2026 | | 2027 | | 2028 | | Thereafter | | Total |
| Remaining performance obligations | $ | 586,990 | | | $ | 338,327 | | | $ | 190,061 | | | $ | 74,600 | | | $ | 14,985 | | | $ | 1,204,963 | |
(14) Transactions with Related Parties
We provide natural gas compression and treating services to entities affiliated with Energy Transfer, which as of December 31, 2024, owned approximately 39% of our limited partner interests and 100% of the General Partner.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
Revenue recognized from those entities affiliated with Energy Transfer on our Consolidated Statement of Operations were as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2024 | | 2023 | | 2022 |
| Related-party revenues | $ | 41,302 | | | $ | 21,726 | | | $ | 15,655 | |
We also made purchases of equipment from an entity affiliated with Energy Transfer of $2.2 million during the year ended December 31, 2024.
We had $0.6 million and $0 within related-party receivables on our Consolidated Balance Sheets as of December 31, 2024 and 2023, respectively, from those entities affiliated with Energy Transfer. We had $0.1 million and $0 within related-party payables on our Consolidated Balance Sheets as of December 31, 2024 and 2023, respectively, due to those entities affiliated with Energy Transfer.
Pursuant to the Board Representation Agreement entered into by us, the General Partner, Energy Transfer, and EIG, in connection with our private placement of Preferred Units and warrants to EIG, EIG Management Company, LLC has the right to designate one of the members of the Board for so long as the holders of the Preferred Units hold more than 5% of the Partnership’s outstanding common units in the aggregate (taking into account the common units issuable upon conversion of the Preferred Units and exercise of the warrants).
(15) Unit-Based Compensation
Long-Term Incentive Plan
In January 2013, the Board adopted the USA Compression Partners, LP 2013 Long-Term Incentive Plan (as amended, the “LTIP”), which is available for certain employees, consultants, and directors of the General Partner and any of its affiliates who perform services for us. The LTIP provides for awards of unit options, unit appreciation rights, restricted units, phantom units, DERs, unit awards, profits interest units, and other unit-based awards. Under the LTIP, the maximum number of common units available for issuance is 10,000,000 and the term of the LTIP is until November 1, 2028. Awards that are forfeited, canceled, paid, or otherwise terminate or expire without the actual delivery of common units will be available for delivery pursuant to other awards. The LTIP is administered by the Board or a committee thereof.
(a)Phantom Units
Prior to December 2024, the General Partner’s executive officers, certain of its employees, and certain of its outside directors were granted phantom units to incentivize them to help drive our future success and to share in the economic benefits of that success. Our Compensation Committee has the ability to allow, and has historically granted, employees with phantom units the option to have a portion of their phantom unit settled in cash, above the statutory tax rate, with the remainder settled in common units upon vesting. ASC Topic 718 Compensation – Stock Compensation requires the entire amount of an award with such features to be accounted for as a liability. Under the liability method of accounting for unit-based compensation, we re-measure the fair value of the phantom unit award at each financial statement date until the award vests or is forfeited. The fair value is measured using the market price of the Partnership’s common units. During the requisite service period (the vesting period of the phantom unit awards), compensation cost is recognized using the proportionate amount of the award’s fair value that has been earned through service to date. Phantom unit awards granted to outside directors do not have a cash settlement option and as such, we account for these phantom unit awards as equity. Each phantom unit is granted in tandem with a corresponding DER, which entitles the recipient to receive an amount in cash on a quarterly basis equal to the product of (i) the number of the recipient’s outstanding, unvested phantom units on the record date for such quarter and (ii) the quarterly distribution declared by the Board for such quarter with respect to the Partnership’s common units.
During the years ended December 31, 2024, 2023, and 2022, an aggregate of 17,384, 476,959, and 603,365, respectively, phantom units (including the corresponding DERs) were granted under the LTIP to the General Partner’s executive officers, certain of its employees, and outside directors. The phantom units (including the corresponding DERs) awarded are subject to restrictions on transferability, customary forfeiture provisions, and time vesting provisions. These phantom unit awards vest incrementally, with 60% of the phantom units vesting on December 5 of the third year following the grant and the remaining 40% vesting on December 5 of the fifth year following the grant.
Phantom units vest in full upon a change in control. Phantom unit recipients do not have all the rights of a unitholder in the Partnership with respect to the phantom units until the units have vested.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
As of December 31, 2024 and 2023, our total unit-based compensation liability related to these phantom units was $22.7 million and $21.9 million, respectively. During the years ended December 31, 2024, 2023, and 2022, we recognized $16.4 million, $22.2 million, and $15.9 million of compensation expense associated with these phantom unit awards, respectively, recorded in selling, general, and administrative expense. During the years ended December 31, 2024, 2023, and 2022, amounts paid related to the cash settlement of vested phantom units under the LTIP were $5.4 million, $6.4 million, and $3.0 million, respectively.
The total fair value and intrinsic value of the phantom units vested under the LTIP was $6.3 million, $7.3 million, and $4.1 million for the years ended December 31, 2024, 2023, and 2022, respectively.
The following table summarizes information regarding phantom unit awards for the periods presented:
| | | | | | | | | | | |
| Number of Units | | Weighted-Average
Grant Date Fair
Value per Unit |
| Phantom units outstanding at December 31, 2021 | 2,229,768 | | | $ | 13.57 | |
| Granted | 603,365 | | | 18.31 | |
| Vested | (386,916) | | | 15.89 | |
| Forfeited | (292,202) | | | 14.10 | |
| Phantom units outstanding at December 31, 2022 | 2,154,015 | | | $ | 14.21 | |
| Granted | 476,959 | | | 23.13 | |
| Vested | (585,055) | | | 13.29 | |
| Forfeited | (122,887) | | | 17.50 | |
| Phantom units outstanding at December 31, 2023 | 1,923,032 | | | $ | 17.08 | |
| Granted | 17,384 | | | 24.70 | |
| Vested | (506,516) | | | 15.40 | |
| Forfeited | (113,584) | | | 18.09 | |
| Phantom units outstanding at December 31, 2024 | 1,320,316 | | | $ | 18.59 | |
The unrecognized compensation cost associated with phantom unit awards was an aggregate $7.8 million as of December 31, 2024. We expect to recognize the unrecognized compensation cost for these phantom unit awards on a weighted-average basis over a period of approximately 2.0 years.
(b)Restricted Units
Beginning December 2024, the General Partner’s executive officers, certain of its employees, and its outside directors were granted restricted units to incentivize them to help drive our future success and to share in the economic benefits of that success. Each restricted unit is granted in tandem with a corresponding DER, which entitles the recipient to receive an amount in cash on a quarterly basis equal to the product of (i) the number of the recipient’s outstanding, unvested restricted units on the record date for such quarter and (ii) the quarterly distribution declared by the Board for such quarter with respect to the Partnership’s common units.
These restricted units vest incrementally, with 60% of the restricted units vesting on December 5 of the third year following the grant and the remaining 40% vesting on December 5 of the fifth year following the grant. Upon vesting, one Partnership common unit is issued for each restricted unit.
Restricted units vest in full upon a change in control. Restricted unit recipients do not have all the rights of a unitholder in the Partnership with respect to the restricted units until the units have vested.
During the year ended December 31, 2024, we recognized $0.1 million of compensation expense associated with these restricted units recorded in selling, general, and administrative expense.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
The following table summarizes information regarding restricted units for the periods presented:
| | | | | | | | | | | |
| Number of Units | | Weighted-Average
Grant Date Fair
Value per Unit |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Restricted units outstanding at December 31, 2023 | — | | | $ | — | |
| Granted | 323,390 | | | 22.25 | |
| | | |
| | | |
| Restricted units outstanding at December 31, 2024 | 323,390 | | | $ | 22.25 | |
The unrecognized compensation cost associated with restricted units was an aggregate $7.1 million as of December 31, 2024. We expect to recognize the unrecognized compensation cost for these restricted units on a weighted-average basis over a period of approximately 3.7 years.
Long-Term Cash Restricted Unit Plan
In December 2024, the Compensation Committee adopted the USA Compression Partners, LP Long-Term Cash Restricted Unit Plan (the “CRU Plan”) which is available for certain employees and directors of the General Partner and any of its affiliates who perform services for us. The CRU Plan provides for awards of cash restricted units which vest one-third on December 5, each of the first, second, and third anniversaries following the grant. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one Partnership common unit upon vesting. ASC Topic 718 Compensation – Stock Compensation requires the entire amount of an award with such features to be accounted for as a liability. Under the liability method of accounting for unit-based compensation, we re-measure the fair value of the cash restricted unit at each financial statement date until the cash restricted unit vests or is forfeited. The fair value is measured using the market price of the Partnership’s common units. During the requisite service period (the vesting period of the cash restricted units), compensation cost is recognized using the proportionate amount of the cash restricted unit’s fair value that has been earned through service to date. Cash restricted units vest in full upon a change in control.
For the year ended December 31, 2024, the Partnership granted a total of 107,820 cash restricted units. As of December 31, 2024, a total of 107,820 cash restricted units were unvested. As of December 31, 2024, our total unit-based compensation liability related to these cash restricted units was $0.1 million.
(16) Employee Benefit Plans
A 401(k) plan is available to all of our employees. In 2024, the plan permitted employees to contribute up to 20% of their salary, up to the statutory limits, which was $23,000 for 2024. The plan provides for discretionary matching contributions by us on an annual basis. Aggregate matching contributions made to employees’ 401(k) plans were $4.4 million, $3.8 million, and $3.2 million for the years ended December 31, 2024, 2023, and 2022, respectively.
(17) Commitments and Contingencies
(a)Major Customers and Concentration of Credit Risk
One customer accounted for approximately 12% and 11% of total revenue for the years ended December 31, 2024 and 2023, respectively. No customer accounted for 10% or more of total revenues for the year ended December 31, 2022.
As of December 31, 2024, two customers accounted for 12% and 11% of our trade accounts receivable, net balance, respectively. As of December 31, 2023, one customer accounted for 17% of our trade accounts receivable, net balance.
Financial instruments that potentially subject us to concentrations of credit risk consist of cash and cash equivalents and trade accounts receivable. Our cash and cash equivalents have a zero-loss expectation because we maintain minimal balances in our cash and cash equivalents’ accounts and have no history of loss. Trade accounts receivable are due from companies of varying size engaged principally in oil and natural gas activities throughout the U.S.; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry. We perform periodic evaluations of our customers’ financial condition, including monitoring our customers’ payment history and current credit worthiness to manage this risk. We generally do not obtain collateral for trade receivables, but we may require payment in advance. Payment terms are on a short-term basis and in accordance with industry practice. We consider this credit risk to be limited due to these companies’ financial resources, the nature of the products and services we provide, and the terms of our customer agreements.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
(b)Litigation
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.
(c)Tax Contingencies
Our compliance with federal, state, and local tax regulations is subject to audit by various taxing authorities. Certain taxing authorities have either claimed or issued an assessment that specific operational processes, which we and others in our industry regularly conduct, result in transactions that are subject to taxes. We and others in our industry have disputed these claims and assessments based on either existing tax statutes or published guidance by the taxing authorities.
We currently are protesting certain sales tax assessments made by the Oklahoma Tax Commission (“OTC”). In August 2024, the administrative law judge (“ALJ”) assigned by the OTC accepted our position that the transactions are not taxable. The OTC subsequently requested a motion for reconsideration, which was denied by the ALJ. The OTC then requested an “en banc” hearing from the OTC Commissioners, which the OTC Commissioners denied and adopted the conclusions of the ALJ, thereby effectively closing the matter.
Our U.S. federal income tax returns for the 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. Under the Bipartisan Budget Act of 2015, there are several procedural steps, including an appeals process, to complete before a final imputed underpayment, if any, is determined. Based on discussions with the IRS, we estimate a potential range of loss from a final imputed underpayment of $0 to approximately $28.3 million, including interest, for potential adjustments resulting from the IRS examinations. Once a final partnership imputed underpayment, if any, is determined, our General Partner may elect to either pay the imputed underpayment (including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised information statement to each unitholder, and former unitholder, with respect to an audited and adjusted return.
(d)Environmental
Our operations are subject to federal, state, and local laws, rules, and regulations regarding water quality, hazardous and solid waste management, air quality control, and other environmental matters. These laws, rules, and regulations require that we conduct our operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections, and other approvals. Failure to comply with applicable environmental laws, rules, and regulations may expose us to significant fines, penalties, and/or interruptions in operations. Our environmental policies and procedures are designed to achieve compliance with such applicable laws, rules, and regulations. These evolving laws, rules, and regulations, and claims for damages to property, employees, other persons, and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future.
(18) Reportable Segments
We manage our business through one operating and reportable segment: compression services. The compression services segment provides natural gas compression and treating services to customers, using a fleet of equipment that we design, engineer, own, operate, and maintain. Our services are primarily provided under fixed-fee contracts, and all revenue is derived from within the U.S.
The accounting policies of the compression services segment are the same as those described in the summary of significant accounting policies. We do not have intra-entity sales or transfers.
Our chief operating decision maker (“CODM”) is the Chief Executive Officer.
The CODM assesses segment performance and allocates resources based on consolidated net income. All expense categories on the Consolidated Statements of Operations are significant and there are no other significant segment expenses that would require disclosure. The CODM uses consolidated net income to assess operating performance as compared to historical results, budget and forecast amounts, expected return on capital investment, and our competitors. The CODM uses this information to allocate future operating and capital expenditures. The measure of segment assets is reported on the balance sheet as total consolidated assets.
USA COMPRESSION PARTNERS, LP
Notes to Consolidated Financial Statements
(19) Recent Accounting Pronouncements
In November 2024, Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2024-03, Income Statement–Reporting Comprehensive Income–Expense Disaggregation Disclosures (Subtopic 220-40). ASU 2024-03 requires disclosure of specified information about certain costs and expenses in the notes to the consolidated financial statements. ASU 2024-03 is effective for annual periods beginning after December 15, 2026, and interim periods within annual periods beginning after December 15, 2027, with early adoption permitted. ASU 2024-03 is to be applied on a prospective basis, with retrospective application permitted. We are currently evaluating the impact, if any, of ASU 2024-03 on our consolidated financial statements and related disclosures.
In December 2023, FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. ASU 2023-09 improves and enhances income tax disclosure requirements, including new disclosures related to tax rate reconciliation and income taxes paid. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, and interim periods within annual periods beginning after December 15, 2025, with early adoption permitted. ASU 2023-09 is to be applied on a prospective basis, with retrospective application permitted. We are currently evaluating the impact, if any, of ASU 2023-09 on our consolidated financial statements and related disclosures.
