UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2024
For the fiscal year ended December 31, 2025
or


☐			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~~8115 Preston Road, Suite ~~510A~~700

Dallas, Texas 75225

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (~~512~~214) ~~473~~545-~~2662~~0440

Securities registered pursuant to Section 12(b) of the Act:

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.


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~~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~~2025, the last business day of the registrant’s most recently completed second fiscal quarter was $1.79 billion. This calculation does not reflect a determination that such persons are affiliates for any other purpose.

As of February 612, ~~2025~~2026, there were ~~117~~144,~~528~~972,~~971~~358 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

Table of Contents

PART I			1
	Item 1.	Business	1
	Item 1A.	Risk Factors	10
	Item 1B.	Unresolved Staff Comments	33
	Item 1C.	Cybersecurity	33
	Item 2.	Properties	3534
	Item 3.	Legal Proceedings	3534
	Item 4.	Mine Safety Disclosures	3534
PART II			3635
	Item 5.	Market For Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	3635
	Item 6.	[Reserved]	3735
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3735
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	5150
	Item 8.	Financial Statements and Supplementary Data	5251
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	5251
	Item 9A.	Controls and Procedures	5251
	Item 9B.	Other Information	5554
	Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	5554
PART III			5655
	Item 10.	Directors, Executive Officers, and Corporate Governance	5655
	Item 11.	Executive Compensation	6160
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	8683
	Item 13.	Certain Relationships and Related Transactions and Director Independence	8985
	Item 14.	Principal Accountant Fees and Services	9188
PART IV			9289
	Item 15.	Exhibits and Financial Statement Schedules	9289

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Glossary

The abbreviations, acronyms, and industry terminology used in this Annual Report are defined as follows:

Credit Agreement						~~Seventh~~Eighth Amended and Restated Credit Agreement, dated as of ~~December~~August 827, ~~2021~~2025, 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
Partnership Agreement						Second Amended and Restated Agreement of Limited Partnership of USA Compression Partners, LP
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
Senior Notes 2033						$750.0 million aggregate principal amount of senior notes due on October 1, 2033
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, trade tensions or tariff impacts;

•changes in the long-term supply of and demand for crude oil and natural gas;

•our ability to realize the anticipated benefits of the J-W Power Acquisition (as defined below) and to integrate the acquired assets with our existing fleet and operations;

•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;

•our ability to realize the anticipated benefits of the shared services integration with Energy Transfer;

•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.

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Overview

We believe that we are one of the largest independent providers of natural gas compression services in the U.S. in terms of total compression fleet horsepower. We have been providing compression services since 1998 and completed our initial public offering in January 2013. As of December 31, 2025, we had 3.9 million horsepower in our fleet. On ~~April~~January 212, ~~2018~~2026, we acquired all of the equity interests in ~~CDM~~J-W ~~Resource~~Energy ~~Management~~Company ~~LLC~~(“J-W Energy”) and ~~CDM~~its ~~Environmental~~subsidiary, &J-W ~~Technical~~Power ~~Services~~Company ~~LLC~~ (“J-W Power”), which acquisition we refer to as the ~~“CDM~~J-W Power Acquisition. An additional 1.0 million horsepower was added to our fleet through the J-W Power Acquisition. Please see “Recent Developments”) below for additional information on the J-W Power 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, and following the J-W Power Acquisition, the Bakken. 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 1213 years as of December 31, 2025 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, as of December 31, 2025, 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.

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Weof ~~also~~our ~~own~~geographic ~~and~~areas ~~operate~~of aoperation ~~fleet~~in ofthe ~~equipment~~U.S. ~~used~~based toupon ~~provide~~the ~~natural~~level ~~gas~~of ~~treating~~customer ~~services~~demand. Our modern, ~~such~~flexible asfleet ~~carbon~~of ~~dioxide~~compression ~~and~~units, ~~hydrogen~~which ~~sulfide~~have ~~removal~~been ~~and~~designed ~~natural~~to ~~gas~~be ~~cooling~~rapidly deployed and ~~dehydration~~redeployed throughout the country, provides us with opportunities to ~~natural~~expand ~~gas~~into ~~producers~~other areas with both new and ~~midstream~~existing ~~companies~~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. Additionally, as a result of the J-W Power Acquisition, we also own and operate specialized manufacturing facilities for the manufacture of compression units.

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.

Recent Developments

On January 12, 2026, the Partnership and USA Compression Partners, LLC, a wholly owned subsidiary of the Partnership, completed the J-W Power Acquisition, pursuant to which USA Compression Partners, LLC purchased all of the issued and outstanding capital stock of J-W Energy from Westerman, Ltd. for aggregate consideration of approximately $860.0 million, subject to customary purchase price adjustments, consisting of (i) 18,175,323 common units representing limited partner interests in the Partnership and (ii) approximately $430.0 million in cash. Upon consummation of the J-W Power Acquisition, J-W Power and J-W Energy became wholly owned indirect subsidiaries of the Partnership.

The J-W Power Acquisition added approximately 0.8 million active horsepower and 1.0 million total horsepower to our fleet across key regions including the Northeast, Mid-Con, Rockies, Gulf Coast, Bakken and Permian Basin. J-W Power also owns and operates specialized manufacturing facilities that support its internal compression requirements and those of third-party customers.

Our Relationship with Energy Transfer LP

InWe ~~late~~share ~~2024,~~certain ~~we began implementing a shared~~ services ~~model~~ with the owner of our General Partner, Energy Transfer. Under this shared service model, we ~~will~~ share personnel and resources in certain departments, including information technology, accounting, and human resources~~. We~~, ~~believe~~which ~~this~~increases ~~will increase~~ efficiencies and support across our organization~~, while simultaneously reducing administrative costs~~.

As of February 612, ~~2025~~2026, Energy Transfer owned 100% of the membership interest in our General Partner and 46,056,228 of our common units, which constituted a 3932% 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~~certain circumstances, ~~and for established customers,~~ we ~~will agree to~~ service third-party owned equipment. WeAs doa ~~not~~result of the J-W Power Acquisition, we also own ~~any~~two 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~~2025, the average age of our compression units was approximately 1213 years. Our modern, standardized compression unit fleet as of December 31, 2025 is powered primarily by the Caterpillar 3400, 3500, and 3600 engine classes, which range from 400 to 5,000 horsepower per unit. These larger-horsepower units, which we define as 400 horsepower per unit or greater, represented 87.26% 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.

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of December 31, 2025. The ~~following~~remainder ~~table~~of ~~provides~~our afleet ~~summary~~as of ~~our~~December 31, ~~compression~~2025 consists of smaller-horsepower units byranging from 40 horsepower to 399 horsepower that are used primarily in gas lift applications. The unit fleet we acquired as a result of ~~December 31~~the J-W Power Acquisition consists of primarily of Caterpillar 3300, ~~2024:~~3400 and 3500 engine classes. We believe the average age and overall composition of our compressor fleet result in fewer mechanical failures, lower fuel usage, and reduced environmental emissions.

Unit Horsepower	FleetHorsepower	Number ofUnits	Horsepoweron Order (1)	Number of Units on Order (1)	TotalHorsepower	Number ofUnits	Percent ofTotalHorsepower		Percent ofUnits
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	%

The following table provides a summary of our compression units by horsepower as of December 31, 2025:


Unit Horsepower	Fleet Horsepower (1)	Number of Units	Horsepower on Order	Number of Units on Order	Total Horsepower (1)	Number of Units	Percent of Total Horsepower		Percent of Units
Small horsepower
<400	488,813	2,878	—	—	488,813	2,878	12.4	%	53.4	%
Large horsepower
≥400 and <1,000	422,920	722	—	—	422,920	722	10.6	%	13.4	%
≥1,000	2,982,599	1,764	63,250	28	3,045,849	1,792	77.0	%	33.2	%
Total large horsepower	3,405,519	2,486	63,250	28	3,468,769	2,514	87.6	%	46.6	%
Total horsepower	3,894,332	5,364	63,250	28	3,957,582	5,392	100.0	%	100.0	%

________________________

(1)As ofa ~~December~~result ~~31,~~of ~~2024,~~the weJ-W ~~had~~Power noAcquisition, ~~horsepower~~in ~~units~~January on2026 ~~order. Subsequent to December 31, 2024,~~ we ~~ordered~~added 4approximately ~~large-horsepower~~0.8 million ~~units,~~active ~~consisting of 10,000~~ horsepower, ~~for~~and ~~expected~~1.0 million ~~delivery~~total ~~during 2025~~horsepower.

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~~2026 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~~As of December 31, 2025, our customers ~~consist~~consisted of approximately ~~275~~260 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 4146%, 3941%, and 3839% of our total revenues for the years ended December 31, ~~2024~~2025, ~~2023~~2024, and ~~2022~~2023, respectively.

Suppliers and Service Providers

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~~products,~~Suppliers and ~~Arrow~~Service 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”.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 on several vendors, including Standard Equipment Company, a subsidiary of Energy Transfer, to package and assemble our compression units. Additionally, J-W Power owns specialized manufacturing facilities that support its internal compression requirements and those of third-party customers. 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, 2025, lead-times for such engines and frames have extended beyond one year, and in some cases with certain engine classes, are in excess of two years. 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.

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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

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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~~imposed a methane emissions charge on certain oil and gas facilities, including onshore petroleum and natural gas production facilities, that emit 25,000 metric tons or more of carbon dioxide equivalent gas per year and exceed certain emissions thresholds. InThe ~~November~~One ~~2024~~Big Beautiful Bill Act, ~~the~~signed ~~EPA~~by ~~issued~~President aTrump ~~final~~on ~~rule~~July to4, ~~impose~~2025, ~~and~~delays ~~collect~~the imposition of the methane emissions charge ~~authorized~~until ~~under~~calendar ~~the~~year ~~IRA 2022~~2034. We do not believe that this methane fee will have a material adverse effect on our business, financial position, results of operations, or cash flows. 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 (the “Endangerment Finding”), 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. On August 1, 2025, the EPA proposed rescinding the Endangerment Finding. It remains uncertain how EPA’s rescindment of the Endangerment Finding, once final, will impact future regulation of GHG emissions.

In addition, from time to time, there have been various proposals to regulate hydraulic fracturing at the federal level. 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.

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Finally, some scientists have concluded that increasing concentrations of GHG in Earth’s atmosphere may produce climate changes that have significant weather-related effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. 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 as a product offering 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

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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~~2025, USAC Management had ~~854~~885 full-time employees. An additional 594 employees were added as a result of the J-W Power Acquisition. In addition, under our shared services model with Energy Transfer, ~~in late 2024~~ we ~~began~~utilize ~~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.

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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.

•AnA ~~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.

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•Our ability to fund purchases of additional compression units and expansion capital expenditures in the future is dependent on our ability to access external capital, and if we are unable to access this external capital, we may be limited in our ability to grow our operations or maintain or increase our distributions.

•Integration of assets acquired in past acquisitions or future acquisitions with our existing business can be complex, time-consuming, and costly, particularly in the case of material acquisitions such as the J-W Power Acquisition, which increased our size and expanded the geographic areas in which we operate. 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.

•Changes in U.S. trade policy and the impact of tariffs, including any resulting market volatility or trade tensions, may have a material adverse effect on our business and results of operations.

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.

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•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~~and ~~sell~~Westerman, ~~and~~Ltd. ~~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.

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•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.

•We may have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.

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 $6176.71 million per quarter, or $~~246~~304.84 million per year, based on the number of common units outstanding as of February 612, ~~2025~~2026.

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, including the J-W Power Acquisition;

•the level of competition from other companies; and

•prevailing global and regional economic and regulatory conditions, and their impact on us and our customers.

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~~2029 and Senior Notes ~~2029~~2033 (collectively, the “Senior Notes”);

•the cost of acquisitions;

•fluctuations in interest rates;

•the financial condition of our customers;

•our ability to borrow funds and access the capital markets; and

•the amount of cash reserves established by the General Partner.

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AnA ~~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 has in the past and in the future could result in a reduction in our revenues and our cash available for distribution. Additionally, as a result of the J-W Power Acquisition, we own and operate specialized manufacturing facilities for the manufacture of compression units. The demand for these products is similarly affected by the production levels of natural gas and crude oil, and may be negatively affected even by a short-term decline in production. Our customers could seek to preserve capital or reduce expenses by using lower-cost providers of compression services, not renewing month-to-month contracts, determining not to enter into any new compression service contracts, seeking lower contract prices for our services, or delaying or eliminating orders for the manufacture of compression units.

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 4146%, 3941%, and 3839% of our total revenues for the years ended December 31, ~~2024~~2025, ~~2023~~2024, and ~~2022~~2023, 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~~Our ~~the~~customers ~~shared~~may ~~services~~choose ~~model~~to ~~with~~vertically ~~Energy~~integrate ~~Transfer~~their ~~will~~operations beby apurchasing ~~complex~~ and ~~time-consuming~~operating ~~process.~~their ~~Disruptions~~own tocompression ~~our~~fleet, ~~systems~~increasing the number of compression units they currently own, or ~~operations~~using ~~caused~~alternative bytechnologies ~~the~~for ~~implementation~~enhancing ~~may~~crude ~~have~~oil production, which could result in a ~~material~~decrease ~~adverse~~in ~~impact~~our onrevenues usand cash available for distribution to unitholders.

WeOur customers that are ~~currently~~significant ~~implementing~~producers, aprocessors, ~~shared~~gatherers, ~~services~~and ~~model~~transporters ~~with~~of ~~Energy~~natural ~~Transfer~~gas ~~whereby~~and wecrude ~~intend~~oil may choose to ~~share~~vertically ~~personnel~~integrate their operations by purchasing and ~~resources~~operating ~~with~~their ~~Energy~~own ~~Transfer~~compression fleets in ~~certain~~lieu ~~departments,~~of ~~including~~using ~~information~~our ~~technology,~~compression ~~accounting,~~services. The historical availability of attractive financing terms from financial institutions and ~~human~~equipment ~~resources.~~manufacturers ~~Integrating~~facilitates ~~these~~this ~~functions~~possibility ~~with~~by ~~Energy~~making ~~Transfer~~the ~~will~~purchase ~~require~~of ~~substantial~~individual ~~time,~~compression ~~resources,~~units ~~and~~more ~~coordination~~affordable to our customers. ~~This~~In ~~could~~addition, ~~result~~there inare ~~significant~~many ~~disruptions~~technologies oravailable ~~require~~for athe ~~disproportionate~~artificial ~~amount~~enhancement of ~~our~~crude ~~management’s~~oil ~~attention~~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 ~~unforeseen~~decreased demand for our

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~~operational~~compression ~~or administrative difficulties or costs. We may encounter significant delays to this integration~~services, which ~~would further exacerbate these effects. We~~ may ~~also~~have ~~encounter~~a ~~difficulties~~material inadverse ~~integrating~~effect on our ~~personnel~~business, ~~with~~results ~~Energy~~of ~~Transfer’s~~operations, ~~teams~~financial condition, and ~~may~~reduce ~~lose~~our ~~key~~cash ~~employees.~~available for distribution.

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~~2025, approximately 1419% 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~~2025, 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 up to $1.675 billion (subject to availability under our borrowing base), with a further potential increase of up to an additional $300 million. The Credit Agreement matures on August 27, 2030, except that if more than $50.0 million of the Senior Notes 2029 are outstanding on December 814, ~~2026~~2028, the Credit Agreement will mature on December 14, 2028. As of December 31, ~~2024~~2025, we had outstanding borrowings under the Credit Agreement of $~~772~~795.10 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $~~827~~954.12 million of remaining unused availability, all of which, ~~due~~was available to be drawn, inclusive of restrictions related to compliance with ~~the~~ applicable financial covenants. As of February 12, 2026, we had outstanding borrowings under the Credit Agreement of $~~782~~1.53 ~~million~~billion ~~was~~and ~~available~~outstanding toletters beof ~~drawn~~credit of $2.0 million.

As of December 31, ~~2024~~2025, we had $~~750~~1.0 ~~million~~billion and $1750.0 million ~~billion~~ aggregate principal amount outstanding on our Senior Notes ~~2027~~2029 and Senior Notes ~~2029~~2033, respectively. The Senior Notes ~~2027~~2029 and Senior Notes ~~2029~~2033 accrue interest at the rate of 67.~~875~~125% and 76.~~125~~250% 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~~2025, our leverage ratio under the Credit Agreement was 4.~~02x~~00x. Financial covenants in the Credit Agreement require us to maintain a leverage ratio of not greater than 5.50 to 1.00 or less than 0.00 to 1.00; 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.

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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~~lowered ~~lowering~~ interest rates recently, macroeconomic circumstances may change, resulting in delays or reversal of such actions, which may result in a prolonged high-interest rate environment. Any substantial increase in the interest rates applicable to our variable-rate indebtedness outstanding could have a material negative impact on our cash available for distribution. Based on our December 31, ~~2024~~2025, 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.

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outstanding, a one percent increase in the effective interest rate would result in an annual increase in our interest expense of approximately $8.0 million. 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~~a limited number of vendors, Aincluding GStandard Equipment Company, ~~Alegacy~~a ~~Equipment,~~subsidiary ~~LLC.,~~of ~~and~~Energy ~~Standard Equipment Company~~Transfer, 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;

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•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.15

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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. 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.

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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~~Integration ~~deterioration~~of assets acquired in past acquisitions or future acquisitions with our existing business can be complex, time-consuming, and costly, particularly in the case of material acquisitions such as the J-W Power Acquisition, which increased our size and expanded the geographic areas in which we operate. 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 ~~our~~operations, ~~customers~~or ~~could~~cash ~~adversely~~available ~~affect~~for distribution to our ~~business~~unitholders.

~~During~~The ~~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~~integrating ~~services,~~past 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~~future ~~oil~~acquisitions ~~production~~with ~~activities. Reduced demand for~~ our ~~services could adversely affect our~~ business, ~~results of operations~~include, ~~financial~~among ~~condition,~~other ~~and cash flows.~~things:

•operating a larger combined organization in new geographic areas and new lines of business;

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•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.

We may not be successful in integrating acquisitions, including the J-W Power Acquisition, 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 J-W Power Acquisition could expose us to additional unknown and contingent liabilities.

The J-W Power Acquisition could expose us to additional unknown and contingent liabilities. We performed due diligence in connection with the J-W Power Acquisition and attempted to verify the representations made by J-W Power, J-W Energy, and Westerman, Ltd. in connection therewith, but there may be unknown and contingent liabilities of which we are currently unaware. Westerman, Ltd. has agreed to indemnify us for losses or claims relating to the operation of the business or otherwise only to a limited extent and for a limited period of time. There is a risk that we could ultimately be liable for obligations relating to the J-W Power Acquisition for which indemnification is not available, which could materially adversely affect our business, results of operations and cash flow.

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, such as the J-W Power Acquisition, 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.

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

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~~common~~or ~~unitholders~~to ~~will~~enforce ~~not~~the beperformance ~~entitled~~of obligations owed to ~~receive~~us ~~distributions~~under ~~covering~~contractual arrangements. In the event that any ~~prior~~of ~~periods~~our ifcustomers was to enter into bankruptcy, we ~~later~~could ~~recommence~~lose ~~paying~~all ~~distributions~~or ona portion of the amounts owed to us by such customer, and we may be forced to cancel all or a portion of our ~~common~~service ~~units~~contracts with such customer at significant expense to us. For example, as of December 31, 2025 and 2024, one customer accounted for 12% and 11% of our trade accounts receivable, net balance, respectively. If this customer were to enter bankruptcy or failed to pay us, it could adversely affect our business, results of operations, financial condition, and cash flows.

~~The~~In ~~Preferred~~addition, ~~Units~~nonperformance ~~are convertible into common units in accordance with the terms of the Partnership Agreement~~ by ~~the~~suppliers ~~holders of the Preferred Units~~ or byvendors uswho inhave ~~certain~~committed ~~circumstances. In 2024, holders of our Preferred Units converted an aggregate of 320,000 Preferred Units. Our obligation~~ to ~~pay~~provide ~~distributions~~us onwith ~~the~~critical ~~Preferred~~products ~~Units,~~ or onservices ~~the common units issued following the conversion of the Preferred Units,~~ could ~~impact~~raise our ~~liquidity~~costs ~~and~~or ~~reduce~~interfere ~~the~~with 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~~successfully ~~additional~~conduct ~~financing or increase~~ our ~~borrowing costs, which could have an adverse effect on our financial condition~~business. ~~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~~186.39 million of identifiable intangible assets, net, as of December 31, ~~2024~~2025. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business. These events could cause us to record impairments of identifiable intangible assets. ~~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~~2025, ~~2023~~2024, and ~~2022~~2023, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 228, 422, and 1542 compression and treating units, respectively, representing approximately 119,~~260~~005, 371,~~700~~260, and 337,~~200~~700 of aggregate horsepower, respectively, that previously were used to provide compression and treating services in our business. As a result, we recorded impairments of compression and treating equipment of $07.38 million, $120.3 million, and $112.53 million for the years ended December 31, ~~2024~~2025, ~~2023~~2024, and ~~2022~~2023, respectively.

~~Additionally,~~Changes ~~for~~in U.S. trade policy and the ~~year~~impact ~~ended~~of ~~December 31~~tariffs, ~~2024,~~including weany ~~recognized~~resulting amarket ~~$0.6~~volatility ~~million~~or ~~impairment~~trade oftensions, ~~assets~~may ~~related~~have toa ~~capitalized~~material ~~software~~adverse ~~costs~~effect ~~that~~on ~~are~~our nobusiness ~~longer~~and ~~expected~~results toof ~~provide benefit~~operations.

Our business and results of operations may be adversely affected by uncertainty and changes in U.S. trade policies, including tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments. For example, on March 12, 2025, the U.S. government imposed a 25% tariff on steel imports, which was increased to 50% on June 4, 2025, and on April 2, 2025, the U.S. government announced a 10% tariff on product imports from almost all foreign countries and individualized higher tariffs on certain other countries. Several tariff announcements have been followed by announcements of limited exemptions and temporary pauses. These actions have caused uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods. Steel is a necessary component to build our compression units, and we require various other materials and equipment to operate and maintain our compression units. Any imposition of or increase in tariffs on imports of steel or other materials or equipment utilized in our business, as well as corresponding price increases for such materials available domestically, could increase the costs to purchase new compression units, manufacture compression units, and to maintain our operations. Additionally, any escalation of trade tensions, retaliatory measures by foreign governments, or shifts in U.S. or international trade policies could adversely impact our supply chain and increase costs. We may not be able to fully pass along the cost increases to our customers, which could materially and adversely affect our business and results of operations.

Additionally, our customers may be also affected by tariffs and the resulting volatility in pricing and demand, which could in turn affect demand for our services. Similarly, declines in consumer confidence and/or consumer spending, changes in unemployment, significant inflationary or deflationary changes or disruptive regulatory or geopolitical events could contribute to increased volatility and diminished expectations for the economy, including the market for our services, and lead to demand or cost pressures that could negatively and adversely impact our business. Volatility in the capital markets could also limit our ability to access capital on favorable terms, which could have an adverse impact on our ability to grow our business.

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The nature of these types of risks, which are often unpredictable, makes them difficult to plan for, or otherwise mitigate, and they are generally uninsurable, which compounds their potential impact on our business and results of operations.

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.

WeImplementing ~~may~~the beshared ~~unable~~services tomodel ~~grow~~with ~~successfully~~Energy ~~through~~Transfer ~~acquisitions,~~has ~~which~~been ~~may~~and ~~negatively~~will ~~impact~~continue ~~our~~to ~~operations~~be a complex and ~~limit~~time-consuming ~~our~~process. ~~ability~~Disruptions to ~~maintain~~our systems or ~~increase~~operations caused by the ~~level~~implementation ofmay ~~distributions~~have ona ~~our~~material ~~common~~adverse ~~units~~impact on us.

~~From~~We ~~time~~continue to ~~time,~~implement wea ~~may~~shared ~~choose~~services tomodel ~~make~~with ~~business~~Energy ~~acquisitions~~Transfer towhereby ~~pursue~~we ~~market~~share ~~opportunities,~~personnel ~~increase~~and ~~our~~resources ~~existing~~with ~~capabilities,~~Energy ~~and~~Transfer ~~expand~~in ~~into~~certain ~~new~~departments, ~~geographic~~including ~~areas~~information oftechnology, ~~operations.~~accounting, ~~While~~and wehuman ~~have~~resources. ~~reviewed~~Integrating ~~acquisition~~these ~~opportunities~~functions inwith ~~the~~Energy ~~past~~Transfer has required, and will continue to dorequire, sosubstantial time, resources, and coordination. This could result in ~~the~~significant ~~future~~disruptions or require a disproportionate amount of our management’s attention, weand may ~~not~~result bein ~~able~~unforeseen tooperational ~~identify~~or ~~attractive~~administrative ~~acquisition~~difficulties ~~opportunities~~ or ~~successfully~~costs. ~~acquire~~We ~~identified~~may ~~targets~~encounter significant delays to this integration, which would further exacerbate these effects.

~~Any~~Additionally, ~~acquisitions~~as wepart ~~do complete may require us to issue a substantial amount~~ of ~~equity~~the orshared ~~incur~~services aintegration, ~~substantial~~many ~~amount~~ of ~~indebtedness. If we consummate any future material acquisitions,~~ our ~~capitalization~~information ~~may~~systems ~~change significantly, and unitholders will not~~ have ~~the~~migrated ~~opportunity~~ to ~~evaluate~~Energy ~~the~~Transfer’s ~~economic,~~enterprise ~~financial,~~resource ~~and~~planning ~~other~~(“ERP”) ~~relevant~~systems. ~~information~~This ~~that~~migration wemay ~~will~~result ~~consider~~ in ~~connection~~significant ~~with~~disruptions ~~any~~to ~~future~~our ~~acquisition.~~accounting ~~Furthermore,~~or ~~competition~~other ~~for~~internal ~~acquisition opportunities may escalate~~systems, ~~increasing~~including our ~~costs~~ability ofmaintain ~~pursuing~~effective ~~acquisitions~~systems orof ~~causing~~internal uscontrol toover ~~refrain~~financial ~~from~~reporting ~~making~~and ~~acquisitions~~disclosure controls.

~~Also,~~If ~~our~~any ~~reviews~~ of ~~proposed~~these ~~business~~risks or ~~asset~~any ~~acquisitions~~other ~~are~~unanticipated ~~inherently~~complications ~~imperfect~~were ~~because~~to ~~generally~~materialize, itwe ismay not ~~feasible~~realize tothe ~~perform~~desired anbenefits ~~in-depth~~from ~~review~~the ofshared ~~each~~services ~~such proposal given time constraints imposed by sellers. Even if performed~~integration, asuch ~~detailed~~as ~~review~~operational ~~of assets~~ and ~~businesses~~administrative ~~may~~synergies ~~not~~and ~~reveal~~cost ~~existing or potential problems~~reductions, ~~and~~which ~~may~~could ~~not~~result ~~provide~~in ~~sufficient~~a ~~familiarity~~negative ~~with~~impact ~~such~~on ~~business~~our orcash ~~assets to fully assess their deficiencies and potential~~flows. ~~Inspections~~Additionally, ~~may~~disruptions ~~not~~to beour ~~performed~~internal ~~on every asset~~systems, ~~and~~including ~~environmental~~our ~~problems,~~internal ~~such~~control asover ~~groundwater~~financial ~~contamination~~reporting, ~~may~~could ~~not~~negatively beimpact ~~observable~~our ~~even~~business, ~~when~~results anof ~~inspection~~operations isand ~~undertaken~~financial condition.

~~Integration~~We ofmay ~~assets acquired in future acquisitions with our existing business can~~ be ~~complex,~~subject ~~time-consuming,~~to ~~and~~product ~~costly,~~liability ~~particularly~~claims inif ~~the~~people ~~case~~or ofproperty ~~material~~are ~~acquisitions~~harmed ~~such~~by as the ~~CDM~~compression ~~Acquisition,~~units ~~which significantly increased our size and expanded the geographic areas in which~~ we ~~operate~~package. 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~~As ~~difficulties~~a result of ~~integrating~~the ~~future~~J-W ~~acquisitions~~Power ~~with~~Acquisition, we own and operate specialized manufacturing facilities for the manufacture of compression units that support our ~~business~~internal operations and those of third-party customers. We face an inherent risk of product liability exposure related to the sale of these compression units. We may be sued if any of these compression units allegedly causes injury. Any such product liability claims may include allegations of defects in manufacturing, ~~among~~defects ~~other~~in ~~things:~~design, a failure to warn of dangers inherent in the product, negligence, strict liability, and a breach of warranties. If we cannot successfully defend ourselves against claims that our product caused injuries, we may incur substantial liabilities. Regardless of merit or eventual outcome, liability claims may result in injury to our reputation, significant costs to defend the related litigation, distraction to our management team, substantial monetary awards to plaintiffs, and loss of revenue. We cannot be certain that our insurance coverage will be adequate for liabilities actually incurred or that insurance will continue to be available to us on commercially reasonable terms, or at all.

~~•operating~~As a ~~larger~~result ~~combined~~of ~~organization~~these infactors, ~~new~~a ~~geographic~~product ~~areas~~liability ~~and~~claim, ~~new~~even ~~lines~~if ofsuccessfully defended, could have a material adverse effect on our business; or results of operations.

~~•hiring~~From time to time, ~~training~~we are subject to various claims, ortax ~~retaining~~audits, ~~qualified~~litigation, ~~personnel~~and toother ~~manage~~proceedings that could ultimately be resolved against us and ~~operate~~require material future cash payments or charges, which could impair our ~~growing~~financial ~~business~~condition ~~and~~or ~~assets;~~results of operations.

~~•integrating~~The ~~management~~size, ~~teams~~nature, and ~~employees~~complexity ~~into~~of ~~existing~~our ~~operations~~business ~~and~~make ~~establishing~~us ~~effective~~susceptible ~~communication~~to various claims, tax audits, litigation, and ~~information~~binding ~~exchange~~arbitration ~~with~~proceedings. ~~such~~We ~~management~~are ~~teams~~currently, and ~~employees;~~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

•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

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~~unanticipated~~impact ~~costs~~our inreputation ~~2018~~among toour ~~utilize~~customers ~~third-party~~and ~~contractors~~the public, and make it more difficult for us to ~~service~~compete ~~our~~effectively ~~compression~~or ~~units~~obtain atadequate ainsurance ~~greater~~in ~~cost~~the ~~than~~future. weSee ~~would~~Part ~~have~~I, ~~incurred~~Item 3 “Legal Proceedings” and Note 17 to ~~compensate~~our ~~employees~~consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information regarding certain proceedings to ~~perform~~which ~~the~~we ~~same~~are ~~work~~a party.

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.

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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.

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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.

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~~imposed a methane emissions charge on certain oil and gas facilities, including onshore petroleum and natural gas production facilities, that emit 25,000 metric tons or more of carbon dioxide equivalent gas per year and exceed certain emissions thresholds. The One Big Beautiful Bill Act, signed by President Trump on July 4, 2025, delays the imposition of the methane emissions charge until calendar year 2034. 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 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.

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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.

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.

Focus on ESG matters and conservation measures may adversely impact our business.

Focus on companies to address, climate change and other environmental and social impacts, investor and societal expectations regarding environmental, social, and governance (“ESG”) disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for fossil fuels and consequently demand for our services, reduced profits, increased risk of investigations and litigation, and negative impacts on the value of our assets and access to capital. 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 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.

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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 all of the members of the Board, including all of its independent directors.

23If our common unitholders are dissatisfied with the General Partner’s performance, they have little ability to remove the General Partner. The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove the General Partner, and Energy Transfer currently owns approximately 32% of our outstanding common units, making any effort to remove the General Partner difficult. 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.

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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:

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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;

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•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:

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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

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•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.~~25

~~The~~Table ~~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.Contents

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.

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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~~and ~~sell~~Westerman, ~~and~~Ltd. ~~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 612, ~~2025~~2026, Energy Transfer beneficially owns an aggregate of 46,056,228 common units inand ~~us. As of February 6~~Westerman, ~~2025,~~Ltd. ~~the~~owns ~~holders~~an ofaggregate ~~our Preferred Units (the “Preferred Unitholders”) have converted a portion~~ of ~~their Preferred Units into 15~~18,~~990~~175,~~804~~323 ~~common~~of ~~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~~an obligation to file a registration statement with the SEC for the benefit of ~~the~~Westerman, ~~Preferred~~Ltd. ~~Unitholders~~ with respect to ~~any~~the common units they ~~may~~received ~~receive~~as ~~upon~~a ~~conversion~~result of the ~~Preferred~~J-W ~~Units~~Power ~~or exercise of the warrants~~Acquisition. Energy Transfer may, and ~~the~~Westerman, ~~Preferred~~Ltd. ~~Unitholders~~may, ~~have~~subject ~~and~~to ~~may~~certain ~~continue~~lock-up restrictions agreed to in the J-W Power Acquisition, 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~~2025, the General Partner and its affiliates (including Energy Transfer), beneficially own an aggregate of approximately 3936% 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.

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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.

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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”.~~

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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.

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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.

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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.

29If 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.

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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 byin ~~$105.5~~prior ~~million~~tax years, and ~~$95.1~~may ~~million~~be ~~for~~subject ~~tax~~to ~~years~~limitations ~~2023~~in ~~and~~the ~~2022, respectively~~future. As a result, our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us and allocated to them. 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.~~

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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%.

30Moreover, 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. For a transfer of an interest in a publicly traded partnership that is effected through a broker, 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.

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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 (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.~~

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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.

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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.

We may have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.

Even though we (as a partnership for federal income tax purposes) are not subject to federal income tax, following the J-W Power Acquisition, we will conduct some of our operations through subsidiaries that are organized as corporations for federal income tax purposes. The taxable income, if any, of subsidiaries that are treated as corporations for federal income tax purposes, is subject to corporate-level federal income taxes, which may reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that these corporations have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced.

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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, or those of our service providers, could compromise our information and operations and expose us to liability, which would cause our business and reputation to suffer.

We rely on our information technology infrastructure to process, transmit, and store electronic information critical to our business activities. In 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. We also engage third parties, such as service providers and vendors, who provide a broad array of software, technologies, tools, and other products, services and functions (e.g., human resources, finance, data transmission, communications, risk, compliance, among others) that enable us to conduct, monitor and/or protect our business, operations, systems and data assets. If these third parties fail to adequately safeguard our data or their systems, or if they experience security breaches, our operations and reputation may be adversely affected. 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.

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~~information~~of ~~systems~~terror. byChanges ~~state-sponsored and other criminal organizations, as well as data security incidents caused by human error, vulnerabilities~~ in ~~software~~the ~~and~~insurance ~~other~~markets ~~technologies,~~attributable orto ~~vendor~~terrorist ~~and~~attacks ~~supply~~may ~~chain~~make ~~incidents. As~~insurance aagainst ~~result,~~such ~~the~~attacks ~~risks~~more ~~associated~~difficult ~~with~~for ~~such~~us ~~an event continue~~ to ~~increase~~obtain, ~~and~~if we ~~frequently~~choose ~~detect, respond~~ to ~~and~~do ~~mitigate security incidents~~so. ~~A significant failure~~Moreover, ~~compromise,~~the ~~breach,~~insurance orthat ~~interruption~~may ofbe ~~our~~available ~~information~~to ~~systems~~us ormay ~~inadequacies~~be insignificantly ~~our~~more ~~incident~~expensive ~~response~~than ~~processes could result in loss of confidential information, a disruption of~~ our ~~operations,~~existing ~~customer~~insurance ~~dissatisfaction, damage to our reputation, a loss of customers or revenues, privacy or cybersecurity related litigation, and potential regulatory fines~~coverage. IfInstability ~~any such failure, interruption, or similar event results~~ in ~~improper~~the ~~disclosure~~financial ofmarkets ~~information~~resulting ~~maintained~~from interrorism ~~our information systems and networks~~ or ~~those~~war ~~of our customers, suppliers, or vendors, including personnel, customer, pricing, and other sensitive information, we~~ also could benegatively ~~subject~~affect ~~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 orability ~~our vendors’ information systems are breached or an employee causes our information systems~~ to ~~fail,~~raise ~~either as a result of inadvertent error or by deliberately tampering with or manipulating such systems~~capital.

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.

AsWe are part of ~~the shared services integration with~~ Energy Transfer,’s ~~we are transitioning to a~~ shared services cybersecurity program for assessing, identifying and managing material risks from cybersecurity threats. As weThis program includes processes that are inmodeled after the ~~midst~~National Institute of ~~that~~Standards ~~transition~~and Technology’s Cybersecurity Framework and focuses on using business drivers to guide cybersecurity activities. This program is managed by Energy Transfer’s Chief Information Officer, ~~currently~~who ~~certain~~is supported by a team of ~~our~~full-time employees tasked with conducting day-to-day information ~~systems~~technology ~~are~~(“IT”) ~~operating~~operations ~~under~~(collectively, the “IT team”). Furthermore, we consider cybersecurity risks as part of, and have incorporated the shared services cybersecurity program into, ~~while~~our ~~certain~~overall ~~other~~risk ~~information~~management ~~systems~~processes. ~~remain~~Through ~~under~~engagement ~~our~~with ~~internal~~the ~~USAC~~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. Weseeks ~~expect~~to ~~that~~follow ~~once~~industry ~~the~~cybersecurity standards and protect our infrastructure against cyber attacks from domestic and international threats. The shared services ~~implementation~~cybersecurity isprogram ~~complete~~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 ~~information~~assets secure and operational. Through this cybersecurity program, we use various processes as part of our efforts to maintain the confidentiality, integrity and availability of our systems, ~~will~~including ~~operate~~security ~~under~~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). In an effort to validate the ~~shared~~effectiveness ~~services~~of our cybersecurity program and assess such program’s compliance with legal and regulatory requirements, we and the IT team engage third-party service providers to perform audits, assessments, and penetration tests.

~~The~~Cybersecurity ~~shared~~awareness ~~services~~among ~~cybersecurity~~our ~~program~~employees is ~~managed~~promoted bywith aregular ~~team~~training ofand ~~full-time~~awareness ~~Energy~~programs. ~~Transfer~~All employees, ~~overseen~~who byhave ~~its~~access ~~Chief~~to ~~Information~~our ~~Officer,~~systems ~~that~~ are ~~tasked~~required ~~with conducting day-~~to~~-day~~ ~~information~~undergo ~~technology~~annual ~~(“IT”)~~cybersecurity ~~operations~~training ~~(collectively~~and, ~~the~~each ~~“Energy~~year, ~~Transfer~~our ITemployees ~~team”).~~must ~~This~~review ~~program includes processes that are modeled after the National Institute of Standards~~ and ~~Technology’s~~acknowledge ~~Cybersecurity~~our ~~Framework and focuses on using business drivers to guide~~ cybersecurity ~~activities~~policies. ~~In creating and implementing this cybersecurity program~~Further, the ~~Energy Transfer~~ IT team ~~engages~~is ~~with~~trained ~~the~~to ~~guidance~~understand ofhow ~~the~~to ~~Federal Bureau of Investigation (FBI)~~manage, ~~Cybersecurity~~use and ~~Infrastructure~~protect ~~Security~~personally ~~Agency~~identifiable ~~(CISA), Transportation Security Administration (TSA) and the U~~information.S. ~~Coast~~User ~~Guard~~access ~~(USCG).~~controls ~~The~~have ~~shared~~been ~~services~~implemented ~~cybersecurity program seeks~~ to ~~use~~limit aunauthorized ~~defense-in-depth~~access ~~approach for cybersecurity management, layers of technology, policies and training at all levels of the enterprise designed~~ to ~~keep~~sensitive ~~our~~information ~~assets secure~~ and ~~operational~~critical systems. ItEmployees ~~uses~~are ~~various~~required ~~processes as part of its efforts~~ to ~~maintain~~use ~~the~~multifactor ~~confidentiality,~~authentication ~~integrity~~ and ~~availability~~keep oftheir ~~our~~passwords ~~systems~~confidential, ~~including~~among ~~security~~other 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)measures.

~~Our~~We ~~internal~~recognize ~~cybersecurity~~that ~~program~~third-party isservice ~~led~~providers bymay ~~USAC’s~~introduce ITcybersecurity ~~department~~risks. ~~USAC’s~~In ~~internal~~an ~~cybersecurity~~effort ~~program~~to ismitigate ~~designed~~these torisks, ~~align~~before contracting with ~~the~~certain ~~National~~technology ~~Institute~~service ofproviders, ~~Standards~~when ~~and~~possible, ~~Technology’s~~we ~~Cybersecurity~~conduct ~~Framework~~due diligence to evaluate their cybersecurity capabilities. ~~USAC’s~~Additionally, the IT ~~department~~team ~~stays~~endeavors ~~informed~~to ofinclude ~~current~~cybersecurity ~~developments~~requirements in ~~cybersecurity~~contracts ~~threats~~with technology service providers under the shared services model and endeavors to require them to adhere to security standards and protocols. Further, ~~including~~the ~~incidents~~IT orteam ~~issues~~also ~~that~~endeavors ~~may~~to ~~arise~~engage ~~involving~~with ~~our~~any third-party service providers under the shared services model with access to personally identifiable employee information to evaluate their security controls. Finally, Energy Transfer maintains cybersecurity insurance coverage, which coverage extends to us.

Impact of Risks from Cybersecurity Threats

The energy industry’s increasing dependence on information technology and operational technology to support critical functions has heightened its vulnerability to cybersecurity incidents. Consequently, the global surge in cybersecurity incidents, whether caused by intentional attacks or accidental events, presents a significant challenge to our sector. As cybersecurity threats grow in complexity and scale, preventing, detecting, mitigating and remediating these incidents remains a continuous and increasingly demanding task for the industry. Compliance with evolving cybersecurity reporting requirements presents significant challenges. These regulations necessitate timely and detailed reporting of cyber incidents, demanding substantial resources and robust internal processes to ensure adherence. Failure to comply could result in legal penalties, increased regulatory scrutiny and reputational damage. Moreover, the dynamic nature of these requirements may lead to overlapping or

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~~service~~inconsistent ~~providers~~obligations, ~~and~~further ~~preventative~~complicating ~~measures~~compliance ~~and continuously updates our cybersecurity program based on this knowledge~~efforts. ItMonitoring ~~utilizes~~these ~~industry-leading~~developments ~~security tools~~ and ~~regularly~~integrating ~~performs~~them ~~security~~into ~~risk~~our ~~assessments~~cybersecurity and ~~tool~~compliance ~~reviews~~frameworks ~~with~~is ~~independent~~essential ~~third parties~~ to ~~evaluate~~mitigate ~~program~~potential ~~effectiveness, and regularly updates our security roadmap~~risks. ~~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.~~

InAs anof ~~effort~~the todate ~~validate~~of this Annual Report on Form 10-K, though the ~~effectiveness~~Partnership ofand our service providers have experienced certain cybersecurity ~~programs~~incidents, ~~and~~we ~~assess~~are ~~such~~not aware of any 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 ~~compliance~~business ~~with~~continuity ~~legal~~plans, which are designed to limit service interruptions and ~~regulatory~~provide ~~requirements~~for continued business operation in the event of disaster, wewhether ~~engage~~physical, ~~third-party~~environmental ~~service~~or ~~providers~~cyber toin ~~perform~~nature. ~~audits~~However, ~~assessments~~we recognize that cybersecurity threats are continually evolving, and ~~penetration~~there ~~tests~~remains a risk that a cybersecurity incident could potentially negatively impact the Partnership. ~~These~~Despite ~~partnerships~~the ~~enable~~implementation usof 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 ~~access~~our ~~specialized~~business, ~~knowledge~~including ~~and~~the ~~insights~~interruption ~~which~~of key services that our customers depend on. While we ~~leverage~~devote resources to ~~continuously~~our ~~improve~~security measures to protect our systems and ~~modernize~~information, these measures cannot provide absolute security. Additionally, we are in the process of integrating the assets and operations we acquired in the J-W Power Acquisition, and until these assets and operations are fully integrated into our information systems, they may have incomplete cybersecurity ~~programs~~controls applied. WeFor ~~have~~additional ~~integrated~~information on cybersecurity ~~risk~~risks, ~~management~~see ~~into~~Part I, Item 1A “Risk Factors – General Risk Factors –Cybersecurity breaches and other disruptions of our ~~overall~~information ~~risk~~systems, ~~management~~or ~~system~~those of our service providers, ~~ensuring~~could ~~that~~compromise ~~cybersecurity~~our ~~risks~~information ~~are~~and ~~taken~~operations ~~into~~and ~~consideration~~expose ~~when~~us ~~managing~~to ~~business~~liability, ~~objectives~~which would cause our business and ~~operational~~reputation ~~needs~~to suffer.”

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 is responsible for assessing and managing our material risks from cybersecurity threats, including cybersecurity threat prevention, detection, mitigation and remediation, and oversees the functions of IT, cybersecurity, infrastructure and IT governance (including the IT team). Energy Transfer’s ITChief ~~team)~~Information ~~and~~Officer has more than 35 years of experience leading business technology functions. The ~~members~~IT ofteam supports the ~~Energy~~Chief ~~Transfer~~Information Officer in our efforts to comply with applicable cybersecurity standards, establish effective cybersecurity protocols and protect the integrity, confidentiality and availability of our IT infrastructure. The members of the IT team have over 50 years of combined experience in the field of IT, including 20 years dedicated to cybersecurity, and hold various certifications, including Global Industrial Cyber Security Professional (GICSP), Certified Information Systems Security Professional (CISSP) and Certified Ethical Hacker (CEH) certifications. 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, IT and, ITas ~~departments~~appropriate, ET’s corporate security department) is notified by the IT team whenever a discovered cybersecurity incident may potentially have a significant impact on ~~us or~~ our ~~customers~~business operations.

Our Audit Committee is ~~ultimately~~ responsible for ~~assessing and managing~~ the ~~Partnership’s~~oversight ~~material~~of ~~risks from~~ cybersecurity ~~threats~~risks. ~~Our~~The IT ~~leadership~~team provides periodic cybersecurity program updates to senior management and to the Audit Committee. Management also updates the Audit Committee as new risks are identified and regarding the steps taken to mitigate such risks. The Audit Committee reviews periodic reporting and updates regarding our cybersecurity risk management.

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Audit Committee. Management also updates the Audit Committee as new risks are identified and the steps taken to mitigate such risks.

ITEM 2. Properties

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

ITEM 3. Legal Proceedings

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.

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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 612, ~~2025~~2026, we had ~~117~~144,~~528~~972,~~971~~358 common units outstanding. Energy Transfer owns 100% of the membership interests in the General Partner and, as of February 612, ~~2025~~2026, beneficially owns approximately 3932% 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 612, ~~2025~~2026, based on information received from the transfer agent of the common units, we had 6765 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.

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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~~2024, compared to the year ended December 31, ~~2022~~2023, is included under the headings in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Highlights, Financial Results of Operations, Liquidity and Capital Resources, and Critical Accounting Estimates” in our Annual Report on Form 10-K for the year ended December 31, ~~2023~~2024, filed with the SEC on February 1311, ~~2024~~2025.

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Overview

J-W Power Acquisition

On January 12, 2026, the Partnership and USA Compression Partners, LLC, a wholly owned subsidiary of the Partnership, completed the J-W Power Acquisition, pursuant to which USA Compression Partners, LLC purchased all of the issued and outstanding capital stock of J-W Energy from Westerman, Ltd. for aggregate consideration of approximately $860.0 million, subject to customary purchase price adjustments, consisting of (i) 18,175,323 common units and (ii) approximately $430.0 million in cash. Upon consummation of the J-W Power Acquisition, J-W Power and J-W Energy became wholly owned subsidiaries of the Partnership.

The J-W Power Acquisition added approximately 0.8 million active horsepower and 1.0 million total horsepower to our fleet across key regions including the Northeast, Mid-Con, Rockies, Gulf Coast, Bakken and Permian Basin. J‑W Power also owns and operates specialized manufacturing facilities that support its internal compression requirements and those of third‑party customers.

General Trends and Outlook

A significant portion of our assets are utilized in natural gas infrastructure applications typically located in U.S. onshore shale plays, primarily at centralized gathering systems and processing facilities utilizing large-horsepower compression units. 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, Bakken 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~~up year-over-year and average oil prices ~~relatively flat~~down, we experienced improvements to pricing and maintained fleet utilization for our compression services in ~~2024~~2025, largely tied to associated gas growth from oil plays.

37Looking ahead, global consumption of petroleum and liquids fuels according to the EIA’s January 2026 Short Term Energy Outlook (“EIA Outlook”) increased in 2025 and is expected to increase over 1.1 million barrels per day (“bpd”) in 2026 and 0.3 million bpd in 2027. The EIA Outlook estimates that annual U.S. crude oil production set a record of 13.6 million bpd in 2025, due to production growth in the Permian. In 2026 and 2027, the EIA Outlook expects U.S. crude oil production to stay flat in 2026 and decline by 2% in 2027 tied to a slowdown in drilling activity linked to WTI prices forecasted in the low $50 mark. The U.S. crude oil production growth in 2025 came almost entirely from the Permian, which grew by 4% despite

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~~Looking~~flattening ~~ahead,~~over ~~global consumption of petroleum and liquids fuels according to~~ the ~~EIA’s~~last ~~January~~two ~~2025~~quarters 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~~year. In ~~2025 and 2026~~contrast, ~~the EIA Outlook expects U.S. crude oil production growth to continue~~associated, ~~albeit~~wet atnatural agas 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~~grew isby ~~expected~~over to10% ~~account~~and ~~for~~sequentially ~~over~~each ~~half~~quarter, ofowing ~~U.S.~~to ~~crude~~increased gas-to-oil ~~production by 2026~~ratios. We expect that anticipated flat crude oil production ~~increases~~will ~~likewise~~continue ~~will~~to yield an increase in associated natural gas production volumes throughout ~~2025~~2026, 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~~2026 and by 20.79 bcf/d in ~~2026~~2027, resulting in record dry natural gas production each year.

Significant demand for natural gas is driven by domestic power generation which has benefited from a lower-price environment. 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 1215.0 bcf/d during ~~2024~~2025 and expects LNG exports to set new records of 1416.14 bcf/d and 1618.21 bcf/d in ~~2025~~2026 and ~~2026~~2027, respectively, as new LNG export capacity continues to ramp up creating incremental baseload global demand.

Overall, the EIA Outlook expects the increase in U.S. natural gas demand to ~~outpace~~trail production ~~and to increase~~ by 30.29 bcf/d in ~~2025~~2026, primarily reflecting the aforementioned increase in dry natural gas production compared to the expected demand from increased exports, both by LNG and pipeline, and stable baseload demand. ~~Further~~Looking further ahead, the EIA Outlook expects U.S natural gas net demand to increase ~~another~~by 20.65 bcf/d in ~~2026~~2027, again driven primarily by LNG and pipeline exports, and stable baseload with slower rate of growth in natural gas. Natural gas prices averaged $23.2053 per million British thermal units (“MMBtu”) in ~~2024~~2025 and the EIA Outlook expects natural gas prices to ~~increase on~~ average to $3.1046/MMBtu and $4.0059/MMBtu in ~~2025~~2026 and ~~2026~~2027, 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~~2026 to meet our customer needs. We expect total capital to be between $~~158~~290.0 million and $~~182~~320.0 million in ~~2025~~2026 and are beginning to evaluate new, large-horsepower compression unit orders for ~~2026~~2027. 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.

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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,						Increase
	2024			2023			Increase
	2025			2024			(Decrease)
Fleet horsepower (at period end) (1)	3,~~862~~894,~~102~~332			3,~~775~~862,~~660~~102			20.38	%
Total available horsepower (at period end) (2)	3,~~862~~901,~~942~~932			3,~~831~~862,~~444~~942			01.80	%
Revenue-generating horsepower (at period end) (3)	3,~~567~~585,~~842~~452			3,~~433~~567,~~775~~842			30.95	%
Average revenue-generating horsepower (4)	3,~~528~~559,~~172~~300			3,~~328~~528,~~999~~172			6.0.9	%
Average revenue per revenue-generating horsepower per month (5)	$	2021.4338		$	1820.8643		84.37	%
Revenue-generating compression units (at period end)	4,~~269~~256			4,~~237~~269			(0.83	%)
Average horsepower per revenue-generating compression unit (6)	~~829~~847			~~792~~829			42.72	%
Horsepower utilization (7):
At period end	94.67		%	94.36		%	0.31	%
Average for the period (8)	94.63		%	9394.46		%	1(0.23	%)

________________________

(1)Fleet horsepower is horsepower for compression units that have been delivered to us and excludes 2014,~~310~~985 and 2120,~~690~~310 of non-marketable horsepower as of December 31, ~~2024~~2025, and ~~2023~~2024, respectively. As of December 31, ~~2024~~2025, we had no63,250 horsepower on order. ~~Subsequent~~Additionally, toas ~~December~~a ~~31,~~result ~~2024,~~of the ~~Partnership~~J-W ~~ordered~~Power 10Acquisition in January 2026,~~000~~ ~~large~~we ~~horsepower~~added ~~for~~approximately ~~expected~~0.8 million ~~delivery~~in ~~during~~active ~~2025~~horsepower and 1.0 million total horsepower.

(2)Total available horsepower is revenue-generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract but not yet generating revenue and that is expected to be delivered, and idle horsepower. 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 92.41% and 9092.94% as of December 31, ~~2024~~2025, and ~~2023~~2024, respectively.

(8)Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period. Average horsepower utilization based on revenue-generating horsepower and fleet horsepower was 9192.70% and 8991.27% for the years ended December 31, ~~2024~~2025, and ~~2023~~2024, respectively.

The 20.38% increase in fleet horsepower as of December 31, ~~2024~~2025, compared to December 31, ~~2023~~2024, 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 average horsepower utilization based on revenue-generating horsepower and fleet horsepower as of and for the year ended December 31, ~~2024~~2025, compared to December 31, ~~2023~~2024, primarily were driven by the addition and deployment of new, and redeployment of existing, large-horsepower compression units due to increased demand for our services consistent with an overall increase in crude oil and natural gas produced within the U.S.

The 84.37% increase in average revenue per revenue-generating horsepower per month for the year ended December 31, ~~2024~~2025, compared to the year ended December 31, ~~2023~~2024, primarily was due to higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit.

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Financial Results of Operations

Year ended December 31, ~~2024~~2025, compared to the year ended December 31, ~~2023~~2024

The following table summarizes our results of operations for the periods presented (dollars in thousands):

	Year Ended December 31,				Increase
	2024		2023		(Decrease)
	2025		2024		(Decrease)
Revenues:
Contract operations	$	~~885~~911,~~250~~955	$	~~802~~885,~~562~~250	~~10.~~3.0	%
Parts and service	2321,~~897~~136		2123,~~890~~897		9(11.26)	%
Related party	4165,~~302~~008		2141,~~726~~302		9057.14	%
Total revenues	~~950~~998,~~449~~099		~~846~~950,~~178~~449		125.30	%
Costs and expenses:
Cost of operations, exclusive of depreciation and amortization	~~312~~328,~~726~~804		~~284~~312,~~708~~726		95.81	%
Depreciation and amortization	~~264~~284,~~756~~816		~~246~~264,~~096~~756		7.6	%
Selling, general, and administrative	7266,~~666~~343		72,~~714~~666		(08.17)	%
Loss (gain) on disposition of assets	4,939		(1,667)		*
Loss on disposition of assets	3,820		4,939		*
Impairment of assets	~~913~~7,811		~~12,346~~913		*
Total costs and expenses	~~656~~691,~~000~~594		~~614~~656,~~197~~000		65.84	%
Operating income	~~294~~306,~~449~~505		~~231~~294,~~981~~449		264.91	%
Other income (expense):
Interest expense, net	(~~193~~187,~~471~~408)		(~~169~~193,~~924~~471)		13(3.91)	%
Loss on extinguishment of debt	(43,~~966~~006)		—(4,966)		*
Gain on derivative instrument	~~5,684~~—		75,~~449~~684		~~(23.7)~~*	%
Other	~~110~~97		~~127~~110		(1311.48)	%
Total other expense	(~~192~~190,~~643~~317)		(~~162~~192,~~348~~643)		18(1.72)	%
Net income before income tax expense	101,806		69,633		46.2	%
Income before income tax expense	116,188		101,806		14.1	%
Income tax expense	24,~~231~~869		12,~~365~~231		63118.42	%
Net income	$	99111,~~575~~319	$	6899,~~268~~575	4511.98	%

________________________

*Not meaningful.

Contract operations revenue. The $8226.7 million increase in contract operations revenue for the year ended December 31, ~~2024~~2025, compared to the year ended December 31, ~~2023~~2024, primarily was due to (i) ana 84.37% 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 6.0.9% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with an overall increase in crude oil and natural gas produced within the U.S., partially offset by (iii) ana $87.98 million decrease in revenue attributable to natural gas treating services activity.

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 $2.08 million ~~increase~~decrease in parts and service revenue for the year ended December 31, ~~2024~~2025, compared to the year ended December 31, ~~2023~~2024, primarily was due to ana ~~increase~~decrease 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 $1923.67 million increase in related-party revenue for the year ended December 31, ~~2024~~2025, compared to the year ended December 31, ~~2023~~2024, primarily was due to revenue recognized from

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existing customers acquired by Energy Transfer that are classified as related-party revenue for a full year, as opposed to a partial year in the previous period.

Cost of operations, exclusive of depreciation and amortization. The $16.1 million increase in cost of operations for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) a $12.3 million increase in direct labor costs due to increased headcount associated with increased revenue-generating horsepower and higher employee costs, (ii) a $7.9 million increase in direct expenses, primarily driven by increased spending on parts resulting from higher costs and increased usage associated with increased revenue-generating horsepower, (iii) a $1.4 million increase in other indirect expenses due to increased usage associated with increased revenue-generating horsepower, and (iv) a $2.0 million increase in retail parts and service expenses, partially offset by (v) a $5.8 million decrease in fluids expense driven by decreased pricing, (vi) a $1.1 million decrease in vehicle expense due to lower maintenance and repair during the current period, and (vii) a $0.4 million decrease in non-income taxes.

Depreciation and amortization expense. The $20.1 million increase in depreciation and amortization expense for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to overhauls and major improvements to compression units.

Selling, general, and administrative expense. The $6.3 million decrease in selling, general, and administrative expense for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) an $11.5 million decrease in unit-based compensation expense attributable to lower unit-based compensation expense resulting from the forfeiture and vesting of certain awards by certain former senior management and mark-to-market changes to our unit-based compensation liability that occurred as a result of changes to our per-unit trading price as of December 31, 2025, (ii) a $0.6 million decrease in provision for expected credit losses, (iii) a $0.5 million decrease in employee-related expenses due to decreased administrative headcount and lower employee costs, and (iv) a $0.4 million decrease to professional fees primarily related to an initiative to improve business performance, partially offset by (v) a $2.4 million increase in severance charges and other employee costs primarily related to the departure of certain senior management as well as retention and relocation payments related to the shared services integration during the current year, (vi) a $2.2 million increase in insurance and other administrative expenses, and (vii) a $1.9 million increase in transaction expenses related to the J-W Power Acquisition.

Impairment of assets. The $7.8 million and $0.9 million impairments of assets during the years ended December 31, 2025 and 2024, respectively, primarily resulted from our evaluation of the future deployment of our idle fleet assets under then-current market conditions. The primary circumstances supporting these impairments were: (i) unmarketability of certain compression units into the foreseeable future, (ii) excessive maintenance costs associated with certain fleet assets, and (iii) prohibitive retrofitting costs that likely would prevent certain compression units from securing customer acceptance. These compression and treating units were written down to their estimated salvage values, if any.

As a result of our evaluations during the years ended December 31, 2025 and 2024, we retired 28 and 2 compression units, respectively, with approximately 19,005 and 1,260 aggregate horsepower, respectively, that previously were used to provide compression services in our business.

Interest expense, net. The $6.1 million decrease in interest expense, net for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to lower aggregate weighted-average interest rates under the Credit Agreement and refinanced senior notes.

Loss on extinguishment of debt. The $3.0 million loss on extinguishment of debt for the year ended December 31, 2025 resulted from the redemption of our Senior Notes 2027.

The $5.0 million loss on extinguishment of debt for the year ended December 31, 2024 resulted from the satisfaction and discharge of the Senior Notes 2026, which constituted a legal defeasance under GAAP (the “Defeasance”). 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 gain on derivative instrument for the year ended December 31, 2024 resulted from the change in fair value of an interest-rate swap due to changes in the interest-rate forward curve and cash received during the period. This interest-rate swap was terminated in August 2024; see Note 8 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information.

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~~existing~~Income ~~customers~~tax ~~acquired~~expense. byThe ~~Energy~~$2.6 ~~Transfer~~million ~~since~~increase in income tax expense for the ~~previous~~year ~~period~~ended ~~that~~December 31, ~~are~~2025, ~~now~~compared ~~classified~~to asthe year ended December 31, 2024, is primarily related~~-party~~ ~~revenue~~to ina charge of $2.9 million related to an IRS audit of our 2019 and 2020 tax returns. We believe that this amount is a reasonable estimate of the ~~current~~potential ~~period~~loss from the aggregate final imputed underpayment for the years 2019 and 2020 with the IRS. For additional information regarding our IRS audit for the years 2019 and 2020, see Note 17 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

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.

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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~~2025			~~2023~~2024			(Decrease)
Gross margin	$	~~372~~384,~~967~~479		$	~~315~~372,~~374~~967		~~18.~~3.1	%
Adjusted gross margin	$	~~637~~669,~~723~~295		$	~~561~~637,~~470~~723		135.60	%
Adjusted gross margin percentage (2)	67.1		%	6667.41		%	~~0.7~~—	%
Adjusted EBITDA	$	~~584~~613,~~282~~760		$	~~511~~584,~~939~~282		145.10	%
Adjusted EBITDA percentage (2)	61.5		%	6061.5		%	~~1.0~~—	%
DCF	$	~~355~~385,~~317~~677		$	~~281~~355,~~113~~317		268.45	%
DCF Coverage Ratio	1.4445		x	1.3544		x	60.7	%

________________________

(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 $5711.65 million increase in gross margin for the year ended December 31, ~~2024~~2025, compared to the year ended December 31, ~~2023~~2024, was due to (i) a $~~104~~47.37 million increase in revenues, offset by (ii) a $2816.01 million increase in cost of operations, exclusive of depreciation and amortization, and (iii) an $1820.71 million increase in depreciation and amortization.

Adjusted gross margin. The $7631.36 million increase in Adjusted gross margin for the year ended December 31, ~~2024~~2025, compared to the year ended December 31, ~~2023~~2024, was due to a $~~104~~47.37 million increase in revenues, offset by a $2816.01 million increase in cost of operations, exclusive of depreciation and amortization.

Adjusted EBITDA. The $7229.35 million increase in Adjusted EBITDA for the year ended December 31, ~~2024~~2025, compared to the year ended December 31, ~~2023~~2024, primarily was due to a $7631.36 million increase in Adjusted gross margin, partially offset by a $41.21 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, transaction expenses, and severance charges, and ~~transaction~~other ~~expenses~~employee costs.

DCF. The $7430.24 million increase in DCF for the year ended December 31, ~~2024~~2025, compared to the year ended December 31, ~~2023~~2024, primarily was due to (i) a $7631.36 million increase in Adjusted gross margin, (ii) a $309.23 million decrease in distributions on Preferred Units following the conversion of ~~320~~180,000 Preferred Units into 158,~~990~~994,~~804~~826 common units, and (iii) a $05.6 9 million ~~increase~~decrease in cash ~~received~~interest onexpense, ~~derivative instrument~~net, partially offset by (iv) a $227.1 5 million increase in ~~cash~~maintenance ~~interest~~capital ~~expense~~expenditures, ~~net,~~ (v) a $6.7 9 million ~~increase~~decrease in ~~maintenance~~cash ~~capital~~received ~~expenditures~~on derivative instrument, and (vi) a $41.21 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, transaction expenses, severance charges, and ~~transaction~~other ~~expenses~~employee costs.

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 slight increase in DCF Coverage Ratio for the year ended December 31, ~~2024~~2025, compared to the year ended December 31, ~~2023~~2024, 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~~180,000 Preferred Units into 158,~~990~~994,~~804~~826 common units during ~~2024~~2025 and the ~~exercise~~issuance of ~~warrants for 2~~18,~~360~~175,~~488~~323 common units in ~~November~~January ~~2023~~2026 related to the J-W Acquisition.

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.

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Wedistributions ~~believe~~on ~~cash~~our ~~generated~~outstanding bypreferred ~~operating activities~~ and, ~~where~~common ~~necessary,~~equity. ~~borrowings~~Our ~~under~~principal ~~the~~sources ~~Credit~~of ~~Agreement~~liquidity ~~will~~include becash ~~sufficient~~generated toby ~~service~~operating ~~our debt~~activities, ~~fund~~borrowings ~~working~~under ~~capital,~~the ~~fund~~Credit ~~our estimated expansion capital expenditures~~Agreement, ~~fund~~and ~~our~~issuances ~~maintenance~~of ~~capital~~debt ~~expenditures,~~ and ~~pay~~equity ~~distributions~~securities, toincluding ~~our~~common ~~unitholders~~units ~~through~~under ~~2025~~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 2026.

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~~2025 and ~~2023~~2024, were $3139.94 million and $2531.29 million, respectively. We currently have budgeted between $3860.0 million and $4270.0 million in maintenance capital expenditures during ~~2025~~2026, including parts consumed from inventory. This includes a budgeted increase in maintenance capital expenditures as a result of the J-W Power Acquisition.

Without giving effect to any equipment that we may acquire pursuant to any future acquisitions, we currently have budgeted between $~~120~~230.0 million and $~~140~~250.0 million in expansion capital expenditures for ~~2025~~2026. This includes a budgeted increase in expansion capital expenditures as a result of the J-W Power Acquisition. Our expansion capital expenditures for the years ended December 31, ~~2024~~2025 and ~~2023~~2024, were $~~243~~117.56 million and $~~275~~243.45 million, respectively.

As of December 31, ~~2024~~2025, we ~~did~~had ~~not have any~~ binding commitments to purchase ~~additional compression units and serialized parts~~$78.4 ~~Subsequent~~million toof ~~December~~additional ~~31,~~compression ~~2024~~units, weall ~~ordered~~of ~~10,000~~which ~~horsepower~~is ~~for~~ expected ~~delivery~~to ~~during~~be ~~2025~~delivered ~~which~~within ~~will~~the ~~cost~~next ~~$10~~twelve months.8 ~~million,~~We ~~which~~have isnot ~~expected~~ordered toany becompression ~~settled~~units ~~within~~subsequent ~~the~~to ~~next~~December ~~twelve~~31, ~~months~~2025.

Other Commitments

As of December 31, ~~2024~~2025, other commitments include operating and finance lease payments totaling $1918.34 million, of which we expect to make payments of $5.26 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”. Additionally, as of December 31, 2025, we had entered into a definitive agreement with respect to the J-W Power Acquisition, which closed on January 12, 2026. See “See Part I, Item 1 “Recent Developments” for additional information regarding the J-W Power Acquisition.

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Cash Flows

The following table summarizes our sources and uses of cash for the years ended December 31, ~~2024~~2025 and ~~2023~~2024, (in thousands):

Year Ended December 31,

2024

2023

2025

2024

Net cash provided by operating activities

~~341~~394,~~334~~262

~~271~~341,~~885~~334

Net cash used in investing activities

(~~202~~114,~~014~~957)

(~~232~~202,~~653~~014)

Net cash used in financing activities

(~~139~~270,~~317~~755)

(39139,~~256~~317)

Net cash provided by operating activities. The $6952.49 million increase in net cash provided by operating activities for the year ended December 31, ~~2024~~2025, compared to the year ended December 31, ~~2023~~2024, primarily was due to (i) ana ~~increase~~$60.8 million decrease in ~~cash~~inventory ~~inflows~~purchases ~~from~~and (ii) a $7621.3 million increase in ~~Adjusted~~net ~~gross~~income ~~margin~~excluding ~~and~~non-cash charges, partially offset by (iiiii) a $927.30 million ~~decrease~~increase in ~~cash~~interest ~~paid~~payments ~~for~~due ~~interest~~to the timing of payments related to our refinance of our Senior Notes 2026 and (iv) a $2.1 million increase in other working capital.

Net cash used in investing activities. The $87.1 million decrease in net cash used in investing activities for the year ended December 31, 2025, compared to the year ended December 31, 2024, was due to (i) an $87.6 million decrease in capital expenditures, for purchases of new compression units, overhauls and major improvements, and purchases of other equipment, and (ii) a $0.9 million increase in proceeds from disposition of property and equipment, partially offset by (iii) a $1.4 million decrease in proceeds from insurance recovery.

Net cash used in financing activities. The $131.4 million increase in net cash used in financing activities for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) an increase of $750 million in payments on senior notes, (ii) a $250 million decrease in proceeds from issuance of senior notes, (iii) a $13.4 million increase in common unit distributions, and (iv) a $3.2 million increase in payments related to net settlement of unit-based awards, partially offset by (v) a $748.8 million decrease in investments in government securities purchased in connection with the Defeasance of the Senior Notes 2026, (vi) a $122.7 million increase in net borrowings under the Credit Agreement, and (vii) $11.7 million decrease in Preferred Unit distributions.

Revolving Credit Facility

As of December 31, 2025, we had outstanding borrowings under the Credit Agreement of $795.0 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $954.2 million of remaining unused availability all of which was available to be drawn, inclusive of restrictions related to compliance with applicable financial covenants. As of December 31, 2025, we were in compliance with all of our covenants under the Credit Agreement.

As of February 12, 2026, we had outstanding borrowings under the Credit Agreement of $1.3 billion and outstanding letters of credit of $2.0 million, which includes borrowings used to pay the cash consideration of the J-W Power Acquisition.

On August 27, 2025, the Partnership amended and restated its existing credit agreement by entering into the Credit Agreement. The Credit Agreement matures on August 27, 2030, except that if more than $50.0 million of the Senior Notes 2029 are outstanding on December 14, 2028, the Credit Agreement will mature on December 14, 2028.

The Credit Agreement provides for an asset-based revolving credit facility to be made available for the Partnership in an aggregate amount of up to $1.75 billion (subject to availability under our borrowing base), with a further potential increase of up to an additional $300 million.

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, one-month SOFR (which shall only be available for swingline loans made under the Credit Agreement), Daily Simple SOFR, or SOFR plus, in each case, the applicable margin. “Alternate Base Rate” means the greatest of (i) the prime rate, (ii) the federal funds effective rate plus 0.50%, and (iii) one-month SOFR rate plus 1.00%. The applicable margin for borrowings varies (a) in the case of Daily Simple SOFR and SOFR loans, from 1.75% to 2.50% per annum, and (b) in the case of Alternate Base Rate loans and one-month SOFR loans, from 0.75% to 1.50% per annum, and will be determined based on a total leverage ratio pricing grid. In addition, the Partnership is required to pay commitment fees based on the daily unused amount under the facility in an amount per annum equal to 0.25%. Amounts borrowed and repaid under the Credit Agreement may be re-borrowed, subject to borrowing base availability.

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~~expense,~~The ~~net~~Credit ofAgreement ~~capitalized~~also ~~amounts,~~contains ~~driven~~various byfinancial ~~the Defeasance of the Senior Notes 2026~~covenants, ~~partially~~including ~~offset~~covenants byrequiring ~~(iii)~~us ato ~~$25.1 million increase in inventory purchases.~~maintain:

~~Net~~•a ~~cash~~minimum ~~used~~EBITDA ~~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~~interest ~~year~~coverage ~~ended~~ratio ~~December 31,~~of ~~2023,~~2.50 ~~was due~~ to ~~(i) a $33~~1.~~7 million decrease in capital expenditures~~00, ~~for~~determined ~~purchases~~as of ~~new~~the ~~compression~~last ~~units,~~day ~~overhauls~~of ~~and~~each ~~major~~fiscal ~~improvements~~quarter, ~~and~~with ~~purchases~~EBITDA ~~of other equipment,~~ and ~~(ii)~~interest aexpense ~~$1.0 million~~annualized ~~increase~~for inthe ~~proceeds~~most-recent ~~from~~fiscal ~~insurance~~quarter; ~~recovery, partially offset by (iii) a $4.0 million decrease in proceeds from disposition of property and equipment.~~

~~Net~~•a ~~cash~~ratio ~~used~~of intotal ~~financing~~secured ~~activities.~~indebtedness ~~The $100.1 million increase in net cash used in financing activities for the year ended December 31, 2024, compared~~ to ~~the~~EBITDA ~~year~~not ~~ended~~greater ~~December 31,~~than ~~2023,~~3.00 ~~primarily was due~~ to ~~(i) a $748~~1.~~8 million~~00 ~~increase~~or inless ~~investments~~than ~~in government securities purchased in connection with the Defeasance of the Senior Notes 2026, (ii) a $325~~0.~~6 million~~00 ~~decrease~~to ~~in net borrowings under the Credit Agreement~~1.00, ~~(iii)~~determined anas ~~$18.2 million increase in deferred financing costs driven by the issuance~~ of the ~~Senior~~last ~~Notes~~day ~~2029,~~of ~~and~~each ~~(iv)~~fiscal ~~a $31.8 million increase in common unit distributions~~quarter, ~~partially~~with ~~offset~~EBITDA byannualized ~~(v)~~for ~~a 1.0 billion increase in proceeds from issuance of~~ the ~~Senior~~most-recent ~~Notes~~fiscal ~~2029,~~quarter; ~~(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~~•a funded debt-to-EBITDA ratio, defined in the Credit ~~Facility~~Agreement as the Total Leverage Ratio, determined as of the last day of each fiscal quarter with EBITDA annualized for the most-recent fiscal quarter, of not greater than 5.50 to 1.00 or less than 0.00 to 1.00.

AsWe ofexpect ~~December 31,~~to ~~2024,~~remain wein ~~had~~compliance ~~outstanding~~with ~~borrowings~~our covenants under the Credit Agreement ofthroughout ~~$772~~2026.~~1 million~~ ~~and~~If our current cash flow projections prove to be inaccurate, ~~after~~we ~~accounting~~expect ~~for~~to ~~outstanding~~be ~~letters~~able ofto ~~credit~~remain in ~~the~~compliance ~~amount~~with ofsuch ~~$0.8 million,~~financial ~~$827.1 million~~covenants ofby ~~remaining~~taking ~~unused~~one ~~availability~~or more of ~~which,~~the ~~due~~following toactions: ~~restrictions~~issue ~~related~~equity toin ~~compliance~~a ~~with~~public ~~the~~or ~~applicable~~private ~~financial~~offering; request a modification of our covenants, ~~$782.5 million~~from ~~was~~our ~~available~~bank togroup; bereduce ~~drawn.~~distributions Asfrom ofour ~~December~~current ~~31,~~distribution ~~2024,~~rate weor ~~were~~suspend indistributions ~~compliance~~altogether; ~~with~~delay ~~all~~discretionary ofcapital ~~our~~spending ~~covenants~~and ~~under~~reduce operating expenses; or obtain an equity infusion pursuant to the terms of 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

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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~~2025, we had $~~750~~1.0 ~~million~~billion and $1750.0 ~~billion~~million aggregate principal amount outstanding on our Senior Notes ~~2027~~2029 and Senior Notes ~~2029~~2033, respectively.

OnThe ~~March~~Senior 5,Notes ~~2024,~~2027 wewere ~~provided~~due ~~notice~~on toSeptember ~~the~~1, ~~holders of our Senior Notes 2026 that~~2027, ~~contingent~~and onaccrued ~~receipt~~interest ofat the ~~proceeds~~rate ~~from~~of ~~the~~6.875% ~~Senior~~per ~~Notes~~year. ~~2029,~~Interest on the Senior Notes ~~2026~~2027 ~~would~~was bepayable ~~redeemed~~semi-annually atin ~~par~~arrears on ~~April~~each 4,of ~~2024~~March 1 and September 1. On ~~March~~October 1815, ~~2024,~~2025 ~~utilizing a portion of~~ the ~~proceeds from the~~ Senior Notes ~~2029,~~2027 wewere ~~deposited~~redeemed ~~government~~in ~~securities~~full ~~with~~at ~~the~~par, ~~trustee~~plus toaccrued ~~satisfy~~ and ~~discharge~~unpaid ~~the~~interest, ~~Senior~~with ~~Notes 2026 under~~ the ~~Indenture~~net ~~governing~~proceeds from the ~~notes. This~~issuance ~~satisfaction~~ and ~~discharge~~sale ~~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~~2033, ~~were~~together ~~redeemed~~with inborrowings ~~full~~under atour ~~par~~Credit ~~on April 4, 2024~~Agreement.

The Senior Notes ~~2027~~2029 are due on ~~September 1~~March 15, ~~2027~~2029, and accrue interest at the rate of 67.~~875~~125% per year. Interest on the Senior Notes ~~2027~~2029 is payable semi-annually in arrears on each of March 1 15 and September 1 15.

The Senior Notes ~~2029~~2033 are due on ~~March 15~~October 1, ~~2029~~2033, and accrue interest at the rate of 76.~~125~~250% per year. Interest on the Senior Notes ~~2029~~2033 is payable semi-annually in arrears on each of ~~March~~April 151 and ~~September~~October 151, ~~which~~commencing ~~commenced~~ on ~~September~~April 151, ~~2024~~2026. ~~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, Senior Notes ~~2027~~2029, and Senior Notes ~~2029~~2033, 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~~2025 and ~~2023~~2024, distributions of $10.62 million and $1.96 million, respectively, were reinvested under the DRIP resulting in the issuance of 657,~~352~~832 and 8765,~~808~~352 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.

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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

2025

2024

Total revenues

~~950~~998,~~449~~099

~~846~~950,~~178~~449

Cost of operations, exclusive of depreciation and amortization

(~~312~~328,~~726~~804)

(~~284~~312,~~708~~726)

Depreciation and amortization

(~~264~~284,~~756~~816)

(~~246~~264,~~096~~756)

Gross margin

~~372~~384,~~967~~479

~~315~~372,~~374~~967

Depreciation and amortization

~~264~~284,~~756~~816

~~246~~264,~~096~~756

Adjusted gross margin

~~637~~669,~~723~~295

~~561~~637,~~470~~723

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 and other employee costs, certain transaction expenses, loss (gain) on disposition of assets, loss on extinguishment of debt, loss (gain) on derivative instrument, and other. 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.

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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

2025

2024

Net income

99111,~~575~~319

6899,~~268~~575

Interest expense, net

~~193~~187,~~471~~408

~~169~~193,~~924~~471

Depreciation and amortization

~~264~~284,~~756~~816

~~246~~264,~~096~~756

Income tax expense

24,~~231~~869

12,~~365~~231

EBITDA

~~560~~588,~~033~~412

~~485~~560,~~653~~033

Unit-based compensation expense (1)

164,~~552~~342

2216,~~169~~552

Transaction expenses (2)

~~133~~1,914

46133

Severance charges

2,430

841

Severance charges and other employee costs (3)

4,455

2,430

Loss (gain) on disposition of assets

4,939

(1,667)

Loss on disposition of assets

3,820

4,939

Loss on extinguishment of debt (3)

4,966

—

Loss on extinguishment of debt (4)

3,006

4,966

Gain on derivative instrument

~~(5,684)~~—

(75,~~449~~684)

Impairment of assets (4)

913

12,346

Impairment of assets (5)

7,811

913

Adjusted EBITDA

~~584~~613,~~282~~760

~~511~~584,~~939~~282

Interest expense, net

(~~193~~187,~~471~~408)

(~~169~~193,~~924~~471)

Non-cash interest expense

8,~~748~~554

78,~~279~~748

Income tax expense

(24,~~231~~869)

(12,~~365~~231)

Transaction expenses

(~~133~~1,914)

(46133)

Severance charges

(2,430)

(841)

Severance charges and other employee costs

(4,455)

(2,430)

Cash received on derivative instrument

~~6,888~~—

6,~~245~~888

Other

~~1,204~~466

1,~~448~~204

Changes in operating assets and liabilities

(6129,~~523~~872)

(8261,~~850~~523)

Net cash provided by operating activities

~~341~~394,~~334~~262

~~271~~341,~~885~~334

________________________

(1)For the years ended December 31, ~~2024~~2025 and ~~2023~~2024, unit-based compensation expense included $32.90 million and $43.49 million, respectively, of cash payments related to quarterly payments of DERs on outstanding ~~phantom~~ unit awards. Additionally, for the years ended December 31, 2025 and 2024, we paid $07.27 million and $05.34 million, respectively, ~~related~~for to the cash portion of the settlement of phantom unit awards upon vesting, a portion of which is included in the unit-based compensation expense for these periods. 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~~Severance ~~loss~~charges onand ~~extinguishment~~other ofemployee ~~debt~~costs isincludes a(i) ~~result~~severance payments to former employees of the ~~Defeasance~~Partnership, (ii) retention payments to employees of the ~~Senior~~Partnership ~~Notes~~that ~~2026.~~have ~~This~~executed ~~amount~~agreements ~~represents~~to maintain operations during the ~~write-off~~shared ofservices ~~deferred~~integration ~~financing~~but ~~costs~~do ofnot ~~$4.3 million~~intend ~~and~~to remain employed with the ~~difference~~Partnership ~~between~~after their retention period, and (iiii) ~~the~~relocation ~~purchase~~payments ~~price~~to employees of ~~U.S.~~the ~~government~~Partnership ~~securities~~for ofrelocation ~~$748.8 million~~resulting from the shared services integration and ~~(ii)~~the relocation of the ~~aggregate~~Partnership’s ~~outstanding~~headquarters ~~principal~~to ~~balance~~Dallas, ~~and~~Texas. ~~accrued~~These ~~interest~~retention ofpayments are incremental to the ~~Senior~~affected ~~Notes~~employees’ ~~2026~~base ofpay. For the year ended December 31, 2025, severance charges and other employee costs included $~~748~~0.16 million atrelated ~~the~~to ~~time~~each of ~~Defeasance~~retention payments and relocation payments.

(4)~~Represents~~For ~~non-cash~~the ~~charges~~year ~~incurred~~ended toDecember ~~decrease~~31, 2025, the ~~carrying~~loss ~~value~~on extinguishment of ~~long-lived~~debt ~~assets~~of ~~with~~$3.0 million ~~recorded~~is ~~values~~a ~~that~~result ~~are~~of ~~not~~the ~~expected~~redemption toof beour ~~recovered~~Senior ~~through~~Notes ~~future cash flows~~2027.

47For the year ended December 31, 2024, the 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.

(5)Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows.

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Distributable Cash Flow

We define DCF as net income (loss) plus non-cash interest expense, non-cash income tax expense (benefit), depreciation and amortization expense, unit-based compensation expense (benefit), impairment of assets, impairment of goodwill, certain transaction expenses, severance charges and other employee costs, loss (gain) on disposition of assets, loss on extinguishment of debt, change in fair value of derivative instrument, proceeds from insurance recovery, and other, less distributions on Preferred Units and maintenance capital expenditures.

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.

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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
	2025		2024
Net income	$	99111,~~575~~319	$	6899,~~268~~575
Non-cash interest expense	8,~~748~~554		78,~~279~~748
Depreciation and amortization	~~264~~284,~~756~~816		~~246~~264,~~096~~756
Non-cash income tax expense (benefit)	574		(52)
Non-cash income tax expense	466		574
Unit-based compensation expense (1)	164,~~552~~342		2216,~~169~~552
Transaction expenses (2)	~~133~~1,914		46133
Severance charges	2,430		841
Severance charges and other employee costs (3)	4,455		2,430
Loss (gain) on disposition of assets	4,939		(1,667)
Other	2,876		—
Loss on extinguishment of debt (3)	4,966		—
Loss on disposition of assets	3,820		4,939
Change in fair value of derivative instrument	1,204		(1,204)
Loss on extinguishment of debt (4)	3,006		4,966
Impairment of assets (4)	913		12,346
Change in fair value of derivative instrument	—		1,204
Distributions on Preferred Units	(17,550)		(47,775)
Impairment of assets (5)	7,811		913
Maintenance capital expenditures (5)	(31,923)		(25,234)
Distributions on Preferred Units	(8,288)		(17,550)
DCF	$	355,317	$	281,113
Maintenance capital expenditures (6)	(39,414)		(31,923)
Maintenance capital expenditures	31,923		25,234
DCF	$	385,677	$	355,317
Transaction expenses	(133)		(46)
Maintenance capital expenditures	39,414		31,923
Severance charges	(2,430)		(841)
Transaction expenses	(1,914)		(133)
Distributions on Preferred Units	17,550		47,775
Severance charges and other employee costs	(4,455)		(2,430)
Other	630		1,500
Distributions on Preferred Units	8,288		17,550
Changes in operating assets and liabilities	(61,523)		(82,850)
Other	(2,876)		630
Net cash provided by operating activities	$	341,334	$	271,885
Changes in operating assets and liabilities	(29,872)		(61,523)
Net cash provided by operating activities	$	394,262	$	341,334

________________________

(2)Represents certain expenses related to potential and completed transactions and other items. We believe it is useful to investors to exclude these expenses.

~~(5)Reflects~~For ~~actual~~the ~~maintenance~~year ~~capital~~ended ~~expenditures~~December ~~for~~31, 2024, the ~~period~~loss ~~presented.~~on ~~Maintenance~~extinguishment ~~capital~~of ~~expenditures~~debt ~~are~~is ~~capital~~a ~~expenditures~~result ~~made~~of tothe ~~maintain~~Defeasance of the ~~operating~~Senior ~~capacity~~Notes 2026. This amount represents the write-off of ~~our~~deferred ~~assets~~financing ~~and~~costs ~~extend~~of ~~their~~$4.3 million ~~useful~~and ~~lives,~~the ~~replace~~difference ~~partially~~between or(i) ~~fully~~the ~~depreciated~~purchase ~~assets,~~price orof ~~other~~U.S. ~~capital~~government ~~expenditures~~securities ~~that~~of ~~are~~$748.8 million ~~incurred~~and in(ii) ~~maintaining~~the ~~our~~aggregate ~~existing~~outstanding ~~business~~principal balance and ~~related~~accrued ~~cash~~interest ~~flow~~of the Senior Notes 2026 of $748.1 million at the time of Defeasance.

(5)Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows.

(6)Reflects actual maintenance capital expenditures for the period presented. 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.

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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.

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The following table summarizes our DCF Coverage Ratio for the periods presented (dollars in thousands):

	Year Ended December 31,
	2024			2023
	2025			2024
DCF	$	~~355~~385,~~317~~677		$	~~281~~355,~~113~~317
Distributions for DCF Coverage Ratio (1)	$	~~245~~266,~~990~~659		$	~~208~~245,~~856~~990
DCF Coverage Ratio	1.4445		x	1.3544		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~~2025 and ~~2023~~2024, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 228 and 422 compression and treating units, respectively, representing approximately 119,~~260~~005 and 371,~~700~~260 of aggregate horsepower, respectively, that previously were used to provide compression and treating services in our business. As a result, we recorded impairments of compression and treating equipment of $07.38 million and $120.3 million for the years ended December 31, ~~2024~~2025, and ~~2023~~2024, 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.~~49

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fleet assets, and (iii) prohibitive retrofitting costs that likely would prevent certain compression units from securing customer acceptance. These compression and treating units were written down to their estimated salvage values, if any.

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.

WeOur ~~currently~~U.S. ~~are~~federal ~~protesting~~income ~~certain~~tax ~~sales~~returns ~~tax~~for ~~assessments~~the ~~made~~years 2019 and 2020 currently are under examination by the ~~Oklahoma~~IRS. ~~Tax~~The ~~Commission~~IRS ~~(“OTC”).~~has Inissued ~~August~~preliminary ~~2024~~partnership examination changes, ~~the~~resulted ~~administrative~~in ~~law~~imputed ~~judge~~underpayment ~~(“ALJ”)~~computations ~~assigned~~of byapproximately $30.3 million, including interest, for the ~~OTC~~2019 ~~accepted~~and ~~our~~2020 ~~position~~tax ~~that~~years. Under the ~~transactions~~Bipartisan Budget Act of 2015, there are ~~not~~several ~~taxable.~~procedural ~~The~~steps ~~OTC~~to ~~subsequently~~complete ~~requested~~before a ~~motion~~final ~~for~~imputed ~~reconsideration~~underpayment, ~~which~~if ~~was~~any, ~~denied~~is bydetermined. Based on discussions with the ~~ALJ~~IRS, we have accrued $2.9 ~~The~~million, ~~OTC~~which ~~then~~we ~~requested~~believe anis ~~“en~~a ~~banc”~~reasonable ~~hearing~~estimate ~~from~~of the ~~OTC~~potential ~~Commissioners,~~loss ~~which~~from the ~~OTC~~aggregate ~~Commissioners~~final ~~denied~~imputed underpayment for the years 2019 and ~~adopted~~2020. However, the ~~conclusions~~final ofpartnership imputed underpayment, if any, has not been determined. Once determined, our General Partner may elect to either pay the ~~ALJ~~imputed underpayment, ~~thereby~~if ~~effectively~~any, ~~closing~~(including any applicable penalties and interest) directly to the ~~matter~~IRS or, if eligible, issue a revised information statement to each unitholder, or former unitholder as applicable, with respect to an audited and adjusted return.

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~~2025 would result in an annual decrease of approximately $89.61 million and $56.81 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 – AnA ~~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.”

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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~~2025, we had $~~772~~795.10 million of variable-rate indebtedness outstanding at a weighted-average interest rate of 65.9874%. Based on our December 31, ~~2024~~2025 variable-rate indebtedness outstanding, a one percent increase or decrease, respectively, in the effective interest rate would result in an annual increase or decrease in our interest expense of approximately $78.70 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~~2025, 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, 2025. 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

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of December 31, 2025, 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, 2025, as stated in their report, which is included herein.

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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.

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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~~2025, 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~~2025, 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~~2025, and our report dated February 1117, ~~2025~~2026 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 1117, ~~2025~~2026

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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~~February ~~with recent changes to the business~~2026, the ~~Partnership~~Compensation ~~and~~Committee ~~Eric~~approved A.a ~~Scheller,~~one-time ~~our~~special ~~Vice~~incentive ~~President~~retention ~~and~~bonus ~~Chief~~for ~~Operating~~Christopher ~~Officer, engaged in discussions regarding Mr~~J. ~~Scheller’s~~Wauson ~~role and mutually came to an agreement that it would be~~ in the ~~best~~amount ~~interests~~ of ~~Mr.~~$500,000 ~~Scheller and~~ (the ~~Partnership~~“Special ~~for Mr~~Bonus”). ~~Scheller~~The toSpecial ~~terminate~~Bonus ~~his~~was ~~employment~~approved ~~with~~by the ~~Partnership. Our~~ Compensation Committee ~~approved~~based aon ~~separation~~the ~~package~~recommendation ~~for~~of ~~Mr.~~senior ~~Scheller~~management onin ~~February~~recognition 10of, ~~2025~~among other things, ~~and~~(i) Mr. ~~Scheller~~Wauson’s ~~last~~recent ~~day~~appointment atas the ~~Partnership~~Senior isVice ~~expected~~President toand beChief ~~April~~Operating 4,Officer ~~2025. The~~of ~~Partnership~~the ~~expresses~~Company ~~its~~and ~~appreciation~~prompt relocation to ~~Mr.~~Dallas ~~Scheller~~to ~~for~~assume the role; (ii) his ~~dedicated~~2025 ~~service~~calendar ~~and~~year ~~significant~~performance; ~~contributions~~and to(iii) the ~~Partnership~~anticipation ~~and~~of ~~wishes~~his ~~him~~role ~~well~~ in ~~his~~several key current and future ~~endeavors~~initiatives.

InThe ~~connection~~approval ~~with~~of ~~Mr.~~the ~~Scheller’s~~Special ~~departure,~~Bonus ~~Mr.~~by ~~Scheller~~the ~~and~~Compensation ~~the~~Committee ~~General~~was ~~Partner~~conditioned ~~intend~~upon toentry ~~enter~~by Mr. Wauson into a ~~Restrictive~~Special ~~Covenant~~Bonus ~~and~~Retention ~~Separation~~ Agreement ~~and~~with ~~Full~~the ~~Release~~General ofPartner ~~Claims~~ (the “~~Scheller~~Retention ~~Separation~~ Agreement”). ~~The~~which ~~Scheller~~provides ~~Separation~~(i) ~~Agreement~~if, ~~will~~prior ~~become~~to ~~effective~~the ~~after~~second ~~execution~~(2nd) ~~and~~anniversary of the ~~expiration~~effective date of athe ~~seven~~Retention Agreement, Mr. Wauson’s employment with the Partnership terminates (7)other ~~day~~than ~~revocation~~as ~~period.~~a ~~The~~result ~~Scheller~~of ~~Separation~~(x) ~~Agreement~~a ~~will~~termination ~~provide~~without ~~for~~cause by the ~~following:~~Partnership; (iy) ahis ~~separation~~death; ~~payment~~or of(z) ~~$432~~his permanent disability as determined by the Partnership),~~600,~~ ~~less~~he ~~all~~will ~~required~~be ~~governmental~~obligated ~~payroll~~to ~~deductions~~remit and ~~withholdings;~~repay one-hundred percent (ii100%) ~~accelerated~~of ~~vesting~~the ofSpecial 81Bonus to the Partnership; and (ii) if,~~286~~ ~~phantom~~after ~~units~~the tosecond be(2nd) ~~settled~~anniversary upbut prior to ~~50%~~March in1, ~~cash~~2029, ~~less~~Mr. ~~all~~Wauson’s ~~required~~employment ~~governmental~~with ~~payroll~~the ~~deductions~~Partnership ~~and~~terminates ~~withholdings,~~(other ~~and~~than as a result of (~~iii~~x) a ~~lump-sum~~termination ~~payment~~without ~~equal~~cause toby the ~~full~~Partnership; ~~cost~~(y) ofhis death; or (z) his permanent disability as determined by the ~~premium~~Partnership), ~~for~~he ~~eight~~will be obligated to remit and repay fifty percent (850%) ~~months~~ of ~~health~~the ~~insurance~~Special ~~coverage~~Bonus ~~under~~to the Partnership’s. ~~health~~Mr. ~~insurance~~Wauson ~~plan~~and the General Partner entered into the Retention Agreement on February 12, 2026.

The ~~Scheller~~foregoing ~~Separation~~summary ~~Agreement will include, among other things, (i) a standard release~~ of ~~claims~~the inRetention ~~favor~~Agreement ofdoes ~~our~~not ~~General~~purport 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~~be ~~and~~complete ~~solicitation of customers~~ and ~~employees;~~is ~~(iii)~~qualified ain ~~mutual~~its ~~non-disparagement~~entirety ~~clause~~by ~~(applicable~~reference to ~~officers~~the ~~and~~full ~~directors~~text of the ~~General~~Retention ~~Partner);~~Agreement, ~~(iv)~~which ais ~~confirmation~~filed ~~and~~as ~~acknowledgement~~Exhibit ~~by Mr~~10.22 ~~Scheller~~hereto, ~~of his obligations with respect to proprietary~~ and ~~confidential~~is ~~information;~~incorporated ~~and~~herein ~~(v)~~by ~~a twenty-four (24) month cooperation clause~~reference.

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~~2025, 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.

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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 any rights and restrictions that may be 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~~has ~~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~~8115 Preston Road, Suite ~~510A~~700, 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.

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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 75225.55

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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.

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~~2025, 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~~8115 Preston Road, Suite ~~510A~~700, 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, or our principal accounting 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~~8115 Preston Road, Suite ~~510A~~700, Dallas, Texas 75225.

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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.

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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 612, ~~2025~~2026 regarding the current directors and executive officers of USA Compression GP, LLC.

Name

Age

Position with USA Compression GP, LLC

M. Clint Green

4748

President and Chief Executive Officer

Christopher M. Paulsen

4748

Senior Vice President, Chief Financial Officer and Treasurer

Eric A. Scheller

Vice President and Chief Operating Officer

Christopher J. Wauson

Senior Vice President and Chief Operating Officer

Christopher W. Porter

4142

Senior Vice President, General Counsel and Secretary

Dylan A. Bramhall

4849

Director

Clifford A. Harris

7677

Director

Glenn E. Joyce

6768

Director

Thomas E. Long

6869

Director

Thomas P. Mason

6869

Director

William S. Waldheim

6869

Director

Bradford D. Whitehurst

5051

Director

John L. Wortham

7374

Director

James M. Wright, Jr.

5657

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~~Chief Executive Officer 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 Senior Vice President, Chief Financial Officer and Treasurer since January 2026 and prior to that was our Vice President, Chief Financial Officer and Treasurer since November 2024. Prior to ~~this~~joining ~~position~~us, 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

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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~~Christopher AJ. ~~Scheller~~Wauson has served as our Senior Vice President, and Chief Operating Officer since ~~June~~January ~~2020.~~2026 ~~Prior~~and prior to that, ~~Mr.~~was ~~Scheller served as~~ our Vice President –and ~~Fleet~~Chief ~~Operations~~Operating Officer since April ~~2018,~~2025. ~~and~~Prior ~~prior~~ to that ~~was our Vice President~~, ~~Operations~~he &served ~~Performance~~as ~~Management~~the ~~beginning~~company’s inRegional ~~August~~Vice ~~2015.~~President ~~Prior~~of ~~to joining us~~Operations, ~~Mr.~~a ~~Scheller~~position ~~was~~he aheld ~~Director~~since atUSA ~~Sapient~~Compression ~~Global~~acquired ~~Markets~~CDM ~~since~~Resource ~~August~~Management ~~2013~~in 2018. ~~Before~~From ~~Sapient~~2011 to 2018, Mr. ~~Scheller~~Wauson ~~was~~held aroles ~~consultant~~of inincreasing ~~private~~responsibility ~~practice~~at ~~advising~~CDM ~~midstream~~Resource ~~and~~Management, ~~chemicals~~where ~~firms~~he ~~from~~advanced ~~January~~to ~~2012~~Senior toVice ~~July~~President ~~2013~~of Operations. Prior to ~~that~~CDM Resource Management, heMr. Wauson held ~~several~~various positions ~~with~~in ~~Enterprise~~the ~~Products~~energy ~~Partners~~and LPnatural ~~from~~gas ~~November~~compression ~~2004~~industries tobeginning ~~December~~in ~~2011,~~1999 ~~most~~at ~~recently~~companies asincluding ~~Regional Director~~Hanover, ~~Pipeline~~Alcoa &and ~~Storage~~Valerus ~~Services~~Compression. Mr. ~~Scheller~~Wauson holds aan ~~B.S.~~associate’s degree in ~~Chemical~~Instrumentation/ ~~Engineering~~Electrical ~~(Math~~Technology ~~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 Senior Vice President, General Counsel and Secretary since January ~~2017,~~2026 and, prior to that was our Vice President, ~~had~~General ~~served~~Counsel and Secretary since January 2017. Mr. Porter joined us in October 2015 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~~the 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 has also ~~serves~~served 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., and was appointed to the board of directors of TXSE Group Inc., the parent company of the Texas Stock Exchange, in July 2024. 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

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~~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~~infrastructure ~~aimed at continuing to reduce Energy Transfer’s environmental footprint throughout its operations~~projects. 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.

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Mr. Wortham was selected to serve on the Board based on his 40 years of business experience in the energy and natural gas industry.

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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~~2025.

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~~2025, the NEOs were:

•M. Clint Green, President and CEO;*

•~~Eric~~Christopher DM. ~~Long~~Paulsen, ~~Former~~Vice President, Chief Financial Officer and ~~CEO~~Treasurer;*

•Christopher MJ. ~~Paulsen~~Wauson, Vice President, and Chief ~~Financial~~Operating Officer ~~and Treasurer~~;**

•G. Tracy Owens, Vice President of Finance and Chief Accounting Officer;**

•Eric A. Scheller, Vice President and Chief Operating Officer;

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•Christopher W. Porter, Vice President, General Counsel and Secretary; and

•~~Sean~~Eric TA. ~~Kimble~~Scheller, Former Vice President, ~~Human~~and ~~Resources.~~Chief Operating Officer***

*Mr. ~~Long~~Scheller resigned from his position as Vice President and ~~CEO~~Chief Operating Officer effective ~~October~~April 24, ~~2024~~2025. Effective ~~October~~April 35, ~~2024~~2025, Mr. ~~Green~~Wauson was appointed by the Board as the Vice President and ~~CEO~~Chief ofOperating ~~the Partnership~~Officer.

**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.60

***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.

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Each of Messrs. Paulsen, Wauson and Porter began serving in a Senior Vice President position with the Partnership beginning in January 2026 (i.e. as Senior Vice President, Chief Financial Officer and Treasurer; Senior Vice President and Chief Operating Officer, and Senior Vice President, General Counsel and Secretary, respectively).

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 seeks a total compensation program for the NEOs that provides for a slightly below the median market annual base compensation (i.e., approximately the 30th to 40th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both short- and long-term performance that are both targeted to pay out at approximately the top-quartile of market. 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 and (ii) the annual grant of time-based phantom unit, restricted unit, or cash restricted unit awards under our equity incentive plan(s). 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.

Historically, we have granted phantom unit awards (“Phantom Units”) that vested, 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. Since December 2024, however, we have granted time-based awards through a combination of restricted unit awards (“RSUs”) and cash restricted units (“CRSUs”), with 75% awarded as RSUs and the remaining 25% awarded as CRSUs. The RSUs 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 and the CRSUs vest, based generally upon continued employment, at a rate of 1/3 annually over a three-year period.

While we utilize time-based forms of equity-based awards, beginning with the awards approved in December 2025 consistent with the practices used by the Energy Transfer Group (as that term is defined below), the grant date valuation was set using a modified total unitholder return (“TUR”) performance metric as measured against the average return of Alerian MLP index (AMZ) over defined periods of time. The modified TUR is designed to create a recognition of a performance adjustment to the equity-based awards based on the prior periods measured to add an element of performance impact in setting grant date value even though the RSUs and CRSUs themselves are time-vested vehicles.

The following charts illustrate the level of at-risk incentive compensation we awarded in 2025 to our CEO and, on an averaged basis, the other NEOs who were serving as executive officers as of December 31, 2025. “Variable/at-risk” compensation is comprised of time-based incentive awards, including RSUs and CRSUs, and annual discretionary cash bonuses, and “fixed” compensation is comprised of base salary.

Our compensation program is structured to achieve the following:

•~~compensate~~reward executive officers with an industry-competitive total compensation package of competitive base salaries and significant incentive opportunities yielding a total compensation package inapproaching ~~a competitive range at or near~~ the ~~50th~~top-quartile ~~percentile~~ of the market;

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•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~~relevant ~~trends~~data inavailable ~~compensation~~to it to assess our competitive position with respect to base salary, ~~including~~annual ~~the~~short-term ~~practices~~incentives ofand ~~identified~~long-term ~~competitors~~incentive compensation, 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-based 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~~affiliates (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~~takes into account guidance and input, as appropriate, from our CEO, Energy Transfer’s Co-CEO, and ~~executives from~~ Energy Transfer’s Group Senior Vice President of 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~~Energy ~~CEO~~Transfer’s ~~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~~ Co-CEO ~~are then reviewed by the Compensation Committee~~, ~~which~~and ~~may~~Energy ~~accept the recommendations or make adjustments to the recommended compensation based on the Compensation Committee~~Transfer’s ~~assessment~~Group ofSenior ~~the~~Vice ~~individual’s~~President ~~performance,~~of ~~contributions~~Human ~~to the Partnership, and internal compensation levels within the Energy Transfer Group~~Resources. 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~~Periodically, ~~Compensation~~we ~~Committee~~engage ~~periodically~~a ~~compares~~third-party ~~results~~consultant ~~for~~to provide the ~~annual~~Compensation ~~base~~Committee ~~salary,~~with ~~annual~~market ~~cash~~information ~~bonus,~~regarding ~~and~~compensation ~~long-term~~levels ~~equity~~at ~~incentive~~peer ~~awards~~companies ofto ~~the~~assist ~~NEOs~~in ~~against~~evaluating ~~data for~~ compensation levels for ~~specific~~our ~~executive~~executives, ~~positions~~including ~~reported~~the inNEOs. ~~published~~In ~~executive~~2025, ~~compensation~~we ~~surveys~~engaged ~~within~~Meridian ~~each~~Compensation ofPartners, ~~the~~LLC (i“Meridian”), ~~energy~~the ~~industry~~independent ~~and~~compensation ~~(ii)~~advisor ~~overall~~to ~~market.~~Energy ~~The~~Transfer, ~~Compensation~~to ~~Committee~~conduct ~~also~~a ~~reviews~~report ~~publicly~~on ~~filed~~market ~~peer~~information ~~group~~and ~~executive~~ compensation ~~disclosures~~levels ~~pertaining~~of toour ~~certain~~peer ~~executive~~companies ~~roles~~(the “2025 Meridian Report”), ~~utilizing~~which ~~this~~report ~~data~~updated asand anreplaced ~~important~~the ~~reference~~most ~~point.~~recent report prepared by Meridian in 2023 (the “2023 Meridian Report”).

~~Periodically,~~In weconducting ~~engage~~its areview, ~~third-party~~Meridian ~~consultant~~assisted toin ~~provide~~ the ~~Compensation~~development ~~Committee~~of ~~with~~the ~~market~~final ~~information~~“peer ~~regarding~~group” ~~compensation~~of ~~levels at peer~~ companies ~~to assist~~ in ~~evaluating~~the ~~compensation~~oil ~~levels~~and ~~for~~gas ~~our~~space ~~executives,~~that ~~including~~most ~~the~~closely ~~NEOs. In~~reflect ~~2023,~~our weprofile ~~engaged~~after ~~Meridian~~considering ~~Compensation~~factors ~~Partners~~like revenue, ~~LLC~~total ~~(“Meridian”)~~assets, ~~the~~enterprise ~~independent~~value ~~compensation~~and ~~advisor~~market tocap. ~~Energy~~The ~~Transfer,~~final to“peer ~~conduct~~group” arepresented ~~report~~an onexpanded ~~market~~reference ~~information~~of ~~and~~companies ~~compensation~~composed ~~levels~~ of ~~our~~a ~~peer~~broader ~~companies~~group ~~(the~~of ~~“2023~~oil ~~Meridian~~and ~~Report”). The~~gas ~~Compensation~~companies, ~~Committee~~including ~~utilized~~a ~~the~~large ~~2023~~focus ~~Meridian~~on ~~Report~~equipment ~~when~~and ~~setting~~services ~~NEO~~companies ~~compensation~~but ~~for~~also ~~the~~including ~~2024~~certain ~~year.~~marketing ~~During 2024~~companies, ittransportation ~~relied~~and onstorage ~~the~~and ~~results~~upstream ofcomparators ~~the~~whose ~~2023~~data ~~Meridian~~provided ~~Report~~additional ~~for~~market ~~information~~context. onFor ~~base salary~~2025, ~~bonus,~~the ~~and~~core ~~general~~group of peer

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companies was updated from the 2023 Meridian Report to reflect changes assessed by Meridian from the prior market review. The core identified companies were:


Company						Ticker
1. Antero Midstream Corporation						AM
2. Archrock, Inc.						AROC
3. Atlas Energy Solutions Inc.						AESI
4. Cactus, Inc.						WHD
5. DT Midstream, Inc						DTM
6. Enerflex Ltd.						EFX.TO
7. Expro Group Holdings N.V.						XPRO
8. Genesis Energy, L.P.						GEL
9. Helmerich & Payne, Inc.						HP
10. Kodiak Gas Services, Inc						KGS
11. Kinetic Holdings, Inc.						KNTK
12. Oil States International, Inc						OIS
13. Patterson-UTI Energy						PTEN
14. Pro Petro Holding Corp.						PUMP
15. RPC, Inc.						RES
16. Select Water Solutions, Inc.						WTTR
17. Summit Midstream Partners, LP						SMLP
18. 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 (RSUs and in previous years, 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 (CRSUs)						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 2025

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. Generally, base salary increases are determined on an annual basis based on the job responsibilities, demonstrated proficiency and performance of the NEO, and market conditions. Initial base salaries for 2025 for Messrs. Green, Paulsen, and Wauson were determined when they were appointed in October 2024, November 2024,

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~~compensation~~and ~~items~~April ~~for~~2025, ~~2024~~respectively. ~~for~~In ~~the~~connection ~~NEOs~~with determining initial base salaries for Messrs. ~~The~~Porter and Scheller for 2025, the Compensation Committee ~~also~~and ~~utilized~~CEO ~~the~~considered ~~2023~~cost ~~Meridian~~of ~~Report~~living ~~when~~increases, ~~determining~~internal compensation levels within the ~~value~~Energy ofTransfer ~~equity~~Group, ~~awards~~and ~~that~~comparable ~~should~~salaries befor ~~granted~~certain toexecutive roles within our ~~NEOs~~peer group contained in ~~December~~the ~~2024~~2023 Meridian Report, and determined to provide an increase to base salary for Messrs. Porter and Scheller for 2025.

InThe ~~connection~~initial ~~with~~2025 ~~the~~base ~~engagement of Meridian for the 2023 Meridian Report~~salaries, ~~based~~and on2024 ~~the~~base ~~information~~salaries ~~presented~~for tocertain itNEOs, ~~the~~are ~~Compensation~~set ~~Committee~~forth ~~assessed~~in the ~~independence~~following ~~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.~~table:

For purposes of the 2023 Meridian Report, our peer group included the following companies:


Name and Principal Position	2025 Base Salary ($)(1)		2024 Base Salary ($)
M. Clint Green, President and Chief Executive Officer	500,000		500,000	(2)
Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer	425,000		425,000	(2)
Christopher J. Wauson, Vice President and Chief Operating Officer	375,000		—
Christopher W. Porter, Vice President, General Counsel and Secretary	422,300		410,000
Eric A. Scheller, Former Vice President and Chief Operating Officer*	432,600	(3)	420,000

________________________

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

(1)The 2025 base salaries reflected in the table are annualized amounts as of January 1, 2025, other than the amount for Mr. Wauson, which is his annualized base salary following his appointment on April 5, 2025. See “– Summary Compensation Table” below for the base salary actually paid to each NEO in 2025.

(2)The 2024 base salaries for Messrs. Green and Paulsen reflect such officer’s annualized base salary rate for 2024. Messrs. Green and Paulsen were actually paid $124,923 and $52,308 in base salary, respectively, in 2024, based on their time with Partnership during 2024.

(3)Mr. Scheller left the Partnership effective April 4, 2025.

In August 2025, after completion of the 2025 Meridian report and in order to align our compensation cycle with the Energy Transfer Group’s compensation cycle, the Compensation Committee performed a compensation merit review of the NEOs, other than Mr. Porter. Following this review, the Compensation Committee increased the base salaries for these NEOs. In July 2025, the Compensation Committee performed a compensation merit review of Mr. Porter in connection with the amendment to his Employment Agreement (as defined below), and increased Mr. Porter’s base salary. See “– Employment Agreement” below for more details on Mr. Porter’s Employment Agreement. The base salaries following these increases are set forth in the following table:


Name and Principal Position (2)						2025 Base Salary ($)(1)
M. Clint Green, President and Chief Executive Officer						525,000
Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer						450,000
Christopher J. Wauson, Vice President and Chief Operating Officer						425,000
Christopher W. Porter, Vice President, General Counsel and Secretary						435,000

________________________

(1)The 2025 base salaries reflected in the table are annualized amounts following the increases. These increases took effect for the payroll on August 22, 2025 for Messrs. Green, Paulsen and Wauson, and for the payroll on July 11, 2025 for Mr. Porter. See “– Summary Compensation Table” below for the base salary actually paid to each NEO in 2025.

(2)Mr. Scheller left the Partnership effective April 4, 2025, prior to the compensation increases.

Annual Cash Incentive Compensation for 2025

In March 2025, the Compensation Committee approved the USA Compression Partners, LP Second Amended and Restated Annual Cash Incentive Plan (the “Bonus Plan”), which was effective as of January 2025. Each NEO’s potential bonus is governed by the Bonus Plan and, for Mr. Porter, also governed by his Employment Agreement. 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 2026, the Compensation Committee made the determination to pay annual cash bonus awards to our NEOs, under the Bonus Plan attributable to the year ended December 31, 2025. Although the funding of the Bonus Plan generally is based on our satisfaction of certain performance measures that were previously established for the 2025 year, the Compensation Committee retains the authority to use its business judgment 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

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~~Elements~~corresponding ofpercentages that comprise the ~~Compensation~~total ~~Program~~annual target bonus for all eligible employees, including the NEOs (the “Annual Target Bonus Pool”), as shown in the following chart.

Compensation for the NEOs primarily consists of the following elements and corresponding objectives:


Bonus Plan Payout Factors
Payout Factor						% of Total Annual Target Bonus
Adjusted EBITDA Budget Target Payout Factor						50%
Distributable Cash Flow Budget Target Payout Factor						30%
Departmental Budget Target Payout Factor						10%
Safety Budget Target Payout Factor						10%

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.

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 135% 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.

Base Salary for 2024


Adjusted EBITDA and DCF Factors
% of Budget Target						Bonus Pool Payout Factor
Greater than 110						1.35x
107 – 110						1.30x
105 – 107						1.25x
103 – 105						1.20x
101 – 103						1.10x
95.0 – 101						1.00x
90.0 – 94.9						0.90x
85.0 – 89.9						0.85x
80 – 84.9						0.75x
< 80.0						0.0x

~~Base~~For ~~salaries for~~ the ~~NEOs~~2025 ~~generally~~year, ~~have been set at a level deemed appropriate by~~ the Compensation Committee toset ~~attract~~the ~~and~~Adjusted ~~retain~~EBITDA ~~individuals~~Budget ~~with~~Target ~~superior~~at ~~talent~~$600.0 Onmillion ~~an annual basis, base salary increases are determined based on the job responsibilities, demonstrated proficiency~~ and ~~performance of~~ the ~~NEO,~~DCF ~~and~~Budget ~~market~~Target ~~conditions.~~at ~~The Compensation Committee provided each NEO with an increase to his base salary for the 2024 year, other than Mr~~$360.0 ~~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~~million.

The ~~2024~~Departmental ~~base~~Budget ~~salaries~~Target ~~and~~Payout ~~2023~~Factor ~~base~~(the ~~salaries~~“Departmental ~~for~~Budget Factor”) assigns payout factors based on the ~~NEOs,~~specific ~~including~~dollar ~~our~~amount ~~current~~of general and ~~former~~administrative ~~CEO,~~expenses ~~are~~or operating and maintenance expenses set ~~forth~~for ineach department of the ~~following~~Partnership. ~~table:~~

Name and Principal Position	2024 Base Salary ($)		2023 Base Salary ($)
Departmental Budget Ratio Factor
M. Clint Green, President and Chief Executive Officer	500,000	(1)	—
% of Budget Target	Bonus Pool Payout Factor
Eric D. Long, Former President and Chief Executive Officer	739,783	(2)	711,330
0.0 – 100.9	1.00x
Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer	425,000	(3)	—
101.0 – 105.9	0.90x
G. Tracy Owens, Vice President of Finance and Chief Accounting Officer	325,000		325,000	(4)
106.0 – 110.9	0.70x
Eric A. Scheller, Vice President and Chief Operating Officer	420,000		385,000
111.0 – 114.9	0.50x
Christopher W. Porter, Vice President, General Counsel and Secretary	410,000		374,400
>115	0.0x
Sean T. Kimble, Former Vice President, Human Resources	351,520	(5)	338,000

~~(1)Mr.~~For ~~Green joined~~ the ~~Partnership~~2025 ~~effective October 3~~year, ~~2024.~~the ~~The~~Compensation ~~amount~~Committee ~~above~~set ~~reflects~~the ~~his~~Departmental ~~annualized~~Budget ~~base~~Target ~~salary~~(as ~~for~~defined ~~2024. Mr. Green received $124,923~~ in ~~base~~the ~~salary~~Bonus inPlan) ~~2024~~at $60.5 million.

(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.

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(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

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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
Less than 100						1.00x
100% – 105%						0.90x
100 – 105						0.90x
105.1% – 110%						0.80x
105.1 – 110						0.80x
110.1% – 115%						0.70x
110.1 – 115						0.70x
115.1% – 125%						0.60x
115.1 – 125						0.60x
Greater than 125%						0.00x
Greater than 125						0.00x

For the ~~2024~~2025 year, the Compensation Committee set the Safety Budget Target (as defined in the Bonus Plan) at 1.0.90.

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. Further, under the Bonus Plan no other targets are considered unless the Adjusted EBITDA Budget Target result is at least 80% of its Budget Target. In the case of the NEOs, their bonus pool targets for the ~~2024~~2025 year range from 5065% to ~~130~~135% of their respective annual base ~~salary~~salaries.

For the ~~2024~~2025 year, the Compensation Committee set a target bonus amount (the “Target Bonus”) for ~~Messrs~~each NEO as follows: (i) for Mr. ~~Long~~Wauson, ~~Owens,~~upon ~~Scheller,~~his ~~Porter~~appointment ~~and~~in ~~Kimble~~April ~~prior~~2025, towhich the ~~first~~Compensation ~~quarter~~Committee ofreaffirmed ~~the~~in ~~2024~~connection ~~year~~with its compensation merit review in August 2025, ~~which~~(ii) ~~was~~for ~~set~~Mr. asPorter, ain ~~percentage~~connection ofwith ~~the~~his ~~NEO’s~~compensation ~~base~~merit ~~salary.~~review ~~The~~in ~~Target~~July ~~Bonus~~2025, and (iii) for MrMessrs. Green ~~was~~and ~~set~~Paulsen, byin ~~the~~connection ~~Compensation~~with ~~Committee~~their compensation merit reviews in ~~connection~~August ~~with~~2025. ~~his~~These ~~appointment~~Target inBonuses ~~October~~were ~~2024~~set as a percentage of the NEO’s base salary. For the bonus applicable to the ~~2024~~2025 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 ($)
Name (1)	Percentage of Base Salary		Target Amount ($)
M. Clint Green, President and Chief Executive Officer	~~130~~135	%	~~650~~708,~~000~~750	~~(1)~~
Eric D. Long, Former President and Chief Executive Officer	130	%	961,718
Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer	105	%	472,500
Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer	—		—	(2)
Christopher J. Wauson, Vice President and Chief Operating Officer	105	%	446,250
G. Tracy Owens, Vice President of Finance and Chief Accounting Officer	50	%	162,500
Christopher W. Porter, Vice President, General Counsel and Secretary	105	%	456,750
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~~Scheller ~~was~~left ~~prorated~~the ~~based~~Partnership oneffective ~~the~~April ~~amount~~4, of2025 ~~time~~and, ~~the~~as ~~NEO~~such, was ~~employed~~ineligible ~~with~~to ~~the~~participate ~~Partnership~~in ~~during~~ the ~~year~~Bonus ~~ended~~Plan ~~December~~for ~~31, 2024~~2025.

~~(2)Mr.~~The ~~Paulsen~~annual ~~did~~cash ~~not~~bonus ~~have~~pool atargets ~~Target~~for ~~Bonus~~2025 ~~allocation~~were ~~for~~based ~~2024. Instead,~~on ~~his~~the ~~offer~~determination ~~letter~~of ~~provided~~the ~~for~~Compensation ~~payment~~Committee and in consideration of athe ~~sign-on~~available ~~bonus~~compensation indata and the ~~amount~~role, ofcontribution, ~~$125~~skills,~~000~~ toexperience, beand ~~payable~~performance atof ~~the~~an ~~same~~individual ~~time~~relative ~~annual~~to ~~bonus~~his ~~awards~~or ~~were~~her ~~paid~~peers toat ~~our~~the ~~NEOs~~Partnership.

67For the year ended December 31, 2025, we achieved (i) Adjusted EBITDA of $613.76 million or 102.3% of target resulting in an Adjusted EBITDA Bonus Pool Payout Factor of 1.10; (ii) DCF of $385.68 million or 104.4% of target, resulting in a DCF Bonus Pool Payout Factor of 1.20; (iii) Departmental Budget of $60.089 million or 99.3% of target, resulting in a Departmental Budget Bonus Pool Payout Factor of 1.00; and (iv) a TRIR of 0.39 or 55.7% of target resulting in a Safety Budget Bonus Pool Payout Factor of 1.00. Based on these achieved results, the Compensation Committee approved a total bonus pool of 111% of Bonus Plan target. The awards made to each of the NEOs pursuant to the Bonus Plan with respect to the year ended December 31, 2025 were as follows:

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Name (1)						Bonus ($)
M. Clint Green, President and Chief Executive Officer						765,000
Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer						507,000
Christopher J. Wauson, Vice President and Chief Operating Officer						450,500
Christopher W. Porter, Vice President, General Counsel and Secretary						507,000

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~~Mr. ~~Long~~Scheller ~~and Kimble~~ left the Partnership ~~prior~~effective toApril ~~the~~4, ~~payout~~2025, ofand ~~the~~as ~~Target Bonuses for the year ended December 31~~such, ~~2024.~~was ~~Accordingly,~~ineligible noto ~~bonus~~participate ~~payment~~in ~~was~~the ~~made~~Bonus toPlan ~~them~~ for ~~2024~~2025.

~~(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.~~ 66

~~(3)Mr.~~Table ~~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.~~Contents

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

AsWhile ~~noted above, while~~ the Partnership has historically granted Phantom Units awards ofunder ~~phantom~~its ~~units~~long-term ~~(“Phantom~~incentive ~~Units”)~~award program, beginning in December 2024, the Partnership began granting awards of ~~cash~~RSUs ~~restricted units (“CRSUs”)~~ together with awards of ~~restricted units (“RSUs”)~~CRSUs. The vesting terms of these awards and the target award levels for the ~~2024~~2025 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 Compensation Committee acts as the administrator of the LTIP, which 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. However, ~~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~~2025.”

~~Each~~Under of our ~~current~~ Phantom Unit Agreement and Restricted Unit Agreement ~~provides~~that ~~for~~are ~~(i)~~currently ~~incremental vesting over five years~~ in ~~two~~effect, ~~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 ofoccurs ~~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 follows:

•60% vesting on the third December 5 following the grant;

•40% vesting on the fifth December 5 following the grant;

•accelerated vesting of 100% of the outstanding unvested award(s) in the event of a Change in Control (as defined under the LTIP and set forth below under “Potential Payments upon Termination or Change in Control”); and

•accelerated vesting of 100% of the outstanding unvested award(s) in the event of 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, as discussed below under “Potential Payments Upon a Termination or Change of Control”, the Phantom Unit Agreements and Restricted Unit Agreements provide that outstanding unvested Phantom Units and RSUs would automatically accelerate upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the executive is terminated. In addition, the award agreements also include certain acceleration provisions upon retirement with the ability to accelerate 40% of outstanding unvested awards at age 65 and 50% at age 68. These acceleration provisions require that the participant have not less than (i) ten (10) years in respect of Phantom Unit awards or (ii) five (5) years in respect of RSU awards of employment service to the Partnership or an affiliate and are subject to the applicable provisions of IRC Section 409(A), which may include a six (6) month delay in the vesting after retirement. The retirement provision also requires that, in the case of RSUs, the award be held for at least one year after the grant date in order to be eligible for acceleration. The vesting of the Phantom Units and RSUs are subject, in each case described above, to the NEO’s continued employment with us or our affiliates until the relevant vesting date.

CRU Plan Awards

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 represents the right to receive an amount of cash equal to the fair market value of a common unit upon the vesting of such CRSU, 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.

Under our Cash Restricted Unit Agreements that are currently in effect, vesting occurs as follows:

•1/3 vesting of the award on each December 5 following the grant;

•accelerated vesting of 100% of the outstanding unvested award(s) in the event of a Change in Control (as defined under the CRU Plan and set forth below under “Potential Payments upon Termination or Change in Control”); and

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•accelerated vesting of 100% of the outstanding unvested award(s) in the event of 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”)

Additionally, as discussed below under “Potential Payments Upon a Termination or Change of Control”, the CRSU Agreements provide that outstanding unvested CRSUs would automatically accelerate upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the executive is terminated. In addition, the CRSU award agreements also include certain acceleration provisions upon retirement with the ability to accelerate 40% of outstanding unvested awards at age 65 and 50% at age 68. These acceleration provisions require that the participant have not less than five (5) years of employment service to the Partnership or an affiliate and are subject to the applicable provisions of IRC Section 409(A), which may include a six (6) month delay in the vesting after 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 vesting of the CRSUs are subject, in each case described above, to the NEO’s continued employment with us or our affiliates until the relevant vesting date.

The target level of annual long-term incentive awards granted in 2025 for each of the NEOs is expressed below as a percentage of the NEO’s base salary. As described above, these awards were split based on 75% RSUs and 25% CRSUs. In determining the level of the 2025 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 2025 calendar year following the mid-year increases described above. 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 2025, the Partnership utilized a 60 trading-day trailing weighted average price of the Partnership’s common units prior to November 1, 2025 to determine the target number of units to be awarded.

The annual long-term incentive targets are used as the basis to determine the target number of units to be awarded to the eligible participants, including the NEOs. A multiple of base salary is used to set the pool target, that number is then divided by a weighted average price determined by considering our modified TUR performance as measured against the average return of Alerian MLP index (AMZ) over defined time periods. The decision to use the AMZ for the TUR analysis was a recognition of the challenge of matching our business with an adequate set of peer companies for performance evaluation. It was determined that the AMZ would provide the most adequate basis for analysis. We will continue to evaluate the best and most adequate tool to appropriately measure an appropriate modified TUR analysis and will make changes as appropriate in future years. The modified TUR is designed to create a recognition of performance adjustment based on the prior periods measured to an element of performance impact in setting grant date value even though the RSUs and CRSUs themselves are a time-vested vehicle. For purposes of establishing an initial price, we utilized a 60 trading-day trailing weighted average price of our common units prior to November 1 of 2025. This average trading price is then subject to adjustment when our TUR is more than 10% greater or less than that of companies within the AMZ. If the TUR analysis yields a result that is within 10% of the AMZ, the Compensation Committee will simply use the 60 trading day trailing weighted average price divided by the applicable salary multiple to establish a target pool for each eligible participant, including the NEOs. If our TUR is outside of the 10% deviation, the 60 trading day trailing weighted average will be adjusted. For purposes of the adjustment to the trailing average we will consider deviations from 10% to 30% up or down, which number will then be divided by two to establish a maximum of 15% either way from the trailing weighted average price based on our performance as compared to the AMZ.

For 2025, our TUR performed within 10% of the AMZ for the applicable measurement period. As such, the 60 day trailing weighted average price was used to establish the total available pool without adjustment.


Long-Term Incentive Target Amounts Awarded December 5, 2025
Name (1)	Percentage of Base Salary			Grant Date Amount ($)
M. Clint Green, President and Chief Executive Officer	600	%		3,317,709
Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer	250	%		1,184,376
Christopher J. Wauson, Vice President and Chief Operating Officer	250	%	(2)	1,118,847
Christopher W. Porter, Vice President, General Counsel and Secretary	250	%		1,145,544

(1)Mr. Scheller left the Partnership effective April 4, 2025, prior to long-term incentives awarded.

(2)In addition to the grant awarded to Mr. Wauson in December 2025, the Compensation Committee awarded Mr. Wauson an LTIP award on August 12, 2025 for 20,000 RSUs, with 60% of the RSUs vesting on December 5, 2027, and the remaining 40% of the Phantom Units vesting on December 5, 2029.

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~~Phantom~~Under ~~Units if~~ the ~~NEO~~LTIP, ~~voluntarily retires between~~ the ~~ages~~Compensation ofCommittee ~~65–68 and~~ has ~~been~~the ~~employed~~discretion byto ~~us,~~determine ~~the~~whether ~~General~~any ~~Partner,~~portion orof ~~our~~awards ~~affiliates~~should ~~for~~be atsettled ~~least~~in 10cash ~~years~~upon ~~(with~~vesting. ~~the~~The ~~remaining~~Restricted ~~60%~~Unit ~~being~~Agreements ~~forfeited),~~do ~~and~~not ~~(ii)~~allow ~~vesting~~for ofcash ~~50%~~settlement of the ~~outstanding,~~RSUs. ~~unvested~~The Phantom ~~Units~~Unit ifAgreements ~~the~~do ~~NEO~~allow ~~voluntarily~~for ~~retires~~cash atsettlement orof ~~over~~ the ~~age~~Phantom 68Units ~~and~~at ~~has~~the ~~been~~discretion ~~employed~~of ~~by us,~~ the ~~General~~Compensation ~~Partner,~~Committee. orWith ~~our~~respect ~~affiliates~~to ~~for~~the atPhantom ~~least~~Units 10that ~~years~~vested ~~(with~~in 2025, the ~~remaining~~Compensation ~~50%~~Committee ~~being~~previously ~~forfeited).~~approved ~~The~~a ~~Restricted~~default ~~Unit~~settlement ~~Agreement~~method ~~similarly provides~~ for ~~(i)~~Phantom ~~vesting~~Units of 4050% ofin ~~the~~cash ~~outstanding,~~and ~~unvested~~50% ~~RSUs~~in ifcommon ~~the~~units. ~~NEO~~However, ~~voluntarily~~the ~~retires~~Compensation ~~between~~Committee ~~the~~has ~~ages~~also ofspecified ~~65–68,~~that ~~has~~employees ~~been~~may ~~employed~~elect byto ~~us,~~decrease the ~~General~~percentage ~~Partner,~~of orthis ~~our~~cash ~~affiliates~~settlement. ~~for~~If atan ~~least~~employee ~~five~~affirmatively ~~years,~~requests ~~and~~in ~~has~~writing ~~held~~that the ~~award~~percentage ~~for~~of atcash ~~least~~settlement abe ~~year~~set ~~(with~~at ~~the~~a ~~remaining~~specific ~~60%~~amount ~~being~~that ~~forfeited),~~is ~~and~~less ~~(ii)~~than ~~vesting of~~ 50% of(and ~~the~~such ~~outstanding,~~employee ~~unvested~~agrees ~~RSUs~~to ifpay ~~the~~out ~~NEO~~of ~~voluntarily~~his ~~retires at~~ or ~~over~~her ~~the~~own ~~age~~funds ~~68, has been employed by us,~~ the ~~General~~amount ~~Partner,~~of orany ~~our~~required ~~affiliates~~federal ~~for~~withholding atto ~~least five years, and has held~~ the ~~award~~extent ~~for~~that ~~at least a year (with~~ the ~~remaining~~cash ~~50%~~portion ~~being~~is ~~forfeited).~~insufficient ~~The~~for ~~vesting of~~ the ~~Phantom~~Partnership ~~Units~~to withhold and ~~RSUs~~pay ~~are~~such ~~subject,~~amounts inon ~~each case described above, to~~ the ~~NEO~~employee’s ~~continued employment with us~~behalf), the ~~General~~Compensation ~~Partner,~~Committee orapproves ~~our~~in ~~affiliates~~advance ~~until~~such ~~the~~lesser ~~relevant~~cash ~~vesting~~settlement ~~date~~percentage.

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 ofBase 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.

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(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~~and RSUs 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~~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~~2025 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”)

AsOur ~~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.

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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~~69

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

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~~depressed~~Employment 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.Agreement

During 2025, Mr. Porter was party to an employment agreement with us (the “Employment Agreement”). Mr. Porter’s Employment Agreement terminated on January 1, 2026, which for clarity did not result in Mr. Porter's termination of employment. 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 Agreement

Mr. Scheller left the Partnership effective April 4, 2025. In connection with his departure, Mr. Scheller and the General Partner entered into a Restrictive Covenant and Separation Agreement and Full Release of Claims (the “Scheller Separation Agreement”). The Scheller Separation Agreement provided for: (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 includes, 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.

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 applicable 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 Internal Revenue 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~~were the only members of the Compensation Committee asduring ~~of February 6, 2024~~2025. ~~Our~~ ~~former director, Mr. W. Brett Smith, also served on the Compensation Committee at the beginning of 2024.~~ During ~~2024~~2025, none of Messrs. Joyce, Waldheim, ~~Wortham,~~ or ~~Smith~~Wortham 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.

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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.

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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 ($)		Bonus ($)		EquityAwards ($) (1)		Non-Equity Incentive Plan Compensation ($) (2)	All OtherCompensation($) (3)		Total ($)
M. Clint Green	~~2024~~2025	~~124~~511,~~923~~745		—		23,~~607~~317,~~876~~709		~~162~~765,~~500~~000	416,~~154~~942	~~(9)~~	24,~~899~~611,~~453~~396
President and Chief Executive Officer	2024	124,923				2,607,876		162,500	4,154	(4)	2,899,453
Eric D. Long	2024	745,474		—		7,019,282	(5)	—	2,531,169	(6)	10,295,925
Christopher M. Paulsen	2025	436,538				1,184,376		507,000	17,500		2,145,414
Former President and Chief Executive Officer	2023	711,330		—		3,698,902		924,729	1,699,814		7,034,775
Vice President, Chief Financial Officer and Treasurer	2024	52,308		125,000	(5)	1,740,750		—	—		1,918,058
	2022	683,972		—		3,556,634		854,965	1,556,768		6,652,339
Christopher J. Wauson	2025	390,141				1,606,047		450,500	149,719		2,596,407
Christopher M. Paulsen	2024	52,308		125,000	(4)	1,740,750		—	—		1,918,058
Vice President and Chief Operating Officer
Vice President, Chief Financial Officer and Treasurer
Christopher W. Porter	2025	429,706				1,145,544		507,000	259,861		2,342,111
G. Tracy Owens	2024	327,575		—		—		162,500	91,136		581,211
Vice President, General Counsel and Secretary	2024	413,248				855,289		410,000	346,074		2,024,611
Vice President of Finance and Chief Accounting Officer	2023	300,102		—		199,990		150,362	95,091		745,545
	2023	374,400				819,978		336,960	354,327		1,885,665
Eric A. Scheller	~~2024~~2025	~~423~~124,~~328~~135	(6)	—		~~876~~2,~~178~~376,803	(7)	~~420,000~~	~~389~~522,~~865~~497	(8)	23,~~109~~023,~~371~~435
Vice President and Chief Operating Officer	2023	385,000		—		1,224,995		385,000	377,573		2,372,568
Former Vice President and Chief Operating Officer	2024	423,328				876,178		420,000	389,865		2,109,371
	2022	360,500		—		769,997		324,450	298,387		1,753,334
	2023	385,000				1,224,995		385,000	377,573		2,372,568
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 1515in 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~~our 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~~2025 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:~~71

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

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~~We have included distribution payments in connection with distribution equivalent rights on unvested Phantom Unit awards. See notes~~ (63)See ~~and~~the ~~(7)~~chart below for ~~additional~~a ~~amounts~~detailed ~~included~~breakdown ~~for~~of ~~Messrs.~~amounts ~~Long~~reported ~~and~~in ~~Kimble,~~this ~~respectively. See~~column ~~note~~for ~~(9) below regarding certain benefits provided to Mr. Green during 2024.~~2025:

(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.


Name	DERs		Automobile Allowance		Employer 401(k) Contributions		Parking
Mr. Green	$	—	$	—	$	16,942	$	—
Mr. Paulsen	—		—		17,500		—
Mr. Wauson	116,955		15,264		17,500		—
Mr. Porter	238,482		—		17,500		3,879
Mr. Scheller	71,125		—		5,823		325

~~(5)Mr.~~The ~~Long~~amounts ~~retired~~reflected ~~from~~for ~~the~~all ~~Partnership~~periods oninclude ~~December~~distribution ~~31,~~payments ~~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~~DERs ~~retirement.~~on ~~Under~~unvested ~~the terms of Mr. Long’s award agreements for these~~ Phantom ~~Units,~~Unit ~~which were granted in previous years, 40% of these Phantom Units would vest upon his retirement~~awards. ~~The~~However ~~value reported reflects~~ the ~~incremental~~amounts ~~value~~exclude ~~associated~~distribution ~~with~~payments ~~modifications to his outstanding Phantom Unit awards~~ in connection with ~~his~~DERs ~~retirement~~on ~~and~~unvested ~~with~~RSU ~~respect~~awards tobecause the ~~accelerated~~dollar ~~vesting~~value of ~~the~~such ~~remaining~~distributions ~~60%~~are offactored ~~these~~into ~~Phantom~~the ~~Units.~~grant ~~See~~date ~~Note~~fair 15value reported in ~~Part~~the ~~II, Item 8~~ “~~Financial~~Equity ~~Statements~~Awards” ~~and~~column ~~Supplementary~~of ~~Data”~~the ~~for~~Summary aCompensation ~~discussion~~Table ofat the ~~relevant~~time ~~assumptions~~that ~~used~~the inRSU ~~calculating~~awards ~~these~~and ~~amounts~~related ~~pursuant~~DERs towere ~~FASB~~originally ~~ASC Topic 718~~granted.

See note (64)In ~~connection~~below ~~with~~regarding ~~Mr.~~certain ~~Long’s~~benefits ~~retirement,~~provided heto ~~received~~Mr. aGreen ~~separation~~during ~~payment of $991~~2024,~~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 isnote ~~not~~(8) ~~included~~below inwith ~~this~~respect ~~amount.~~to ~~Additionally,~~separation ~~the~~payments ~~value~~to ~~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 grantedScheller.

(74)For administrative reasons, in 2024 Mr. ~~Kimble~~Green ~~left~~remained ~~the~~on ~~Partnership~~Energy onTransfer’s ~~December~~employee 6,plans ~~2024.~~with Inrespect ~~connection~~to ~~with~~(i) ~~his~~medical, ~~departure~~dental, hevision, ~~will~~disability, ~~receive~~and life insurance benefits and (ii) a ~~separation~~defined ~~payment~~contribution ofplan ~~$1,055,720~~that is tax-qualified under section 401(k) of the ~~terms~~Internal Revenue Code. As part of the ~~Kimble~~shared ~~Separation~~services ~~Agreement~~model, all of our 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 of our employees beginning in 2025, we do not classify these benefits as perquisites.

(85)In ~~2022~~2024, Mr. ~~Kimble~~Paulsen ~~was~~received ~~granted~~ a one-time ~~lump~~cash ~~sum~~signing ~~payment~~bonus of $9125,~~750~~000, bywhich was paid at the ~~Compensation~~same ~~Committee~~time as the bonus amounts under the Bonus Plan.

(96)~~For administrative reasons, in 2024~~ Mr. ~~Green~~Scheller ~~remained~~left onthe ~~Energy~~Partnership ~~Transfer’s~~on ~~employee~~April ~~plans with respect to (i) medical~~4, ~~dental, vision, disability, and life insurance benefits and (ii) a defined contribution plan that is tax-qualified under Section 401(k) of the Code~~2025. AsThe ~~part~~amount ofreported ~~the~~in ~~shared~~this ~~services~~column ~~model,~~reflects ~~all~~his ~~USAC~~base ~~employees~~salary ~~moved~~paid ~~to these Energy Transfer employee plans beginning~~ in 2025~~. As~~, ~~these~~as ~~benefits~~well ~~were~~as ~~offered~~the tovalue ~~all employees~~ of ~~Energy~~his ~~Transfer~~accrued ~~during~~paid ~~2024~~time ~~and~~off tohe ~~all~~received ~~employees~~upon ofhis ~~USAC beginning in 2025, we do not classify these benefits as perquisites~~departure.

74(7)Pursuant to the Scheller Separation Agreement as approved on February 10, 2025 and entered into on April 4, 2025, and subject to certain covenants contained therein, 81,286 of Mr. Scheller’s unvested Phantom Units vested in connection with his departure. The value reported reflects the incremental value associated with the accelerated vesting of the 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.

(8)In connection with Mr. Scheller’s departure, he received a separation payment of $445,223 under the terms of the Scheller Separation Agreement. The incremental value of his accelerated Phantom Units is reported in the “Equity Awards” column and is not included in this amount.

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Grants of Plan-Based Awards during the Year Ended December 31, ~~2024~~2025

The below reflects awards granted to our NEOs under the LTIP, the CRU Plan, and our Bonus Plan during ~~2024~~2025.

Name	Grant Date	Approval Date of Equity-BasedAwards	Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)		All Other Unit Awards: Number of Units(#)		Grant Date Fair Value of Unit Awards($) (6)
Name (6)	Grant Date	Approval Date of Equity-BasedAwards	Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)		All Other Unit Awards: Number of Units(#)		Grant Date Fair Value of Unit Awards($) (5)
			Target ($)	Maximum ($)
M. Clint Green	~~10/2/2024~~		~~650~~708,~~000~~750	~~767~~907,~~000~~200
President and Chief Executive Officer	12/5/~~2024~~2025	12/5/~~2024~~2025			84102,~~270~~525	(2)	12,~~955~~488,~~907~~282
	12/5/2024	12/5/2024			28,090	(3)	651,969
	12/5/2025	12/5/2025			34,175	(3)	829,427
Eric D. Long	2/9/2024		961,718	1,134,827
Christopher M. Paulsen			472,500	604,800
Former President and Chief Executive Officer	10/2/2024	10/2/2024			305,984	(4)	7,019,282
Vice President, Chief Financial Officer and Treasurer	12/5/2025	12/5/2025			36,600	(2)	888,282
Christopher M. Paulsen (5)	12/5/2024	12/5/2024			56,250	(2)	1,305,563
	12/5/2025	12/5/2025			12,200	(3)	296,094
Vice President, Chief Financial Officer and Treasurer	12/5/2024	12/5/2024			18,750	(3)	435,188
Christopher J. Wauson			446,250	571,200
G. Tracy Owens	2/9/2024		162,500	191,750
Vice President and Chief Operating Officer	8/12/2025	8/12/2025			20,000	(4)	487,200
Vice President of Finance and Chief Accounting Officer
	12/5/2025	12/5/2025			34,575	(2)	839,135
Eric A. Scheller	2/9/2024		420,000	495,600
	12/5/2025	12/5/2025			11,525	(3)	279,712
Vice President and Chief Operating Officer	12/5/2024	12/5/2024			28,310	(2)	657,075
Christopher W. Porter			456,750	584,640
	12/5/2024	12/5/2024			9,440	(3)	219,102
Vice President, General Counsel and Secretary	12/5/2025	12/5/2025			35,400	(2)	859,158
Christopher W. Porter	2/9/2024		410,000	483,800
	12/5/2025	12/5/2025			11,800	(3)	286,386
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~~2025 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~~2025 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~~2025 were granted pursuant to our LTIP and will vest incrementally, with 60% of the RSUs vesting on December 5, ~~2027~~2028, and the remaining 40% of the RSUs vesting on December 5, ~~2029~~2030. 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 or her then-unvested RSUs granted in ~~2024~~2025 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 or her then-unvested RSUs granted in ~~2024~~2025 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~~2025 were granted in tandem with a corresponding DER.

(3)The CRSUs granted to our NEOs on December 5, ~~2024~~2025 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~~2026. 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 or her then-unvested CRSUs granted in ~~2024~~2025 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 or her then-unvested CRSUs granted in 2025 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.

75(4)The RSUs granted to Mr. Wauson on August 12, 2025 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 Mr. Wauson. The RSUs granted to Mr. Wauson on August 12, 2025 were granted in tandem with a corresponding DER.

(5)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 $24.36 on August 12, 2025 and $24.27 on December 5, 2025.

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~~unvested~~(6)Mr. ~~CRSUs~~Scheller ~~granted~~left inthe ~~2024~~Partnership ~~will~~effective beApril ~~forfeited~~4, 2025, prior to the grant of any plan-based awards for 2025. As noted above in “Summary Compensation Table” and the ~~remainder~~footnote ~~will~~discussion ~~vest~~thereunder, atpursuant to the ~~time~~Scheller ofSeparation ~~retirement.~~Agreement, ~~The~~as ~~retirement~~approved ~~provision~~on ~~also~~February ~~requires~~10, ~~that~~2025 ~~the~~and ~~award~~entered beinto ~~held~~on ~~for~~April at4, ~~least~~2025, ~~one~~and ~~year~~subject ~~after~~to ~~the~~certain ~~grant~~covenants ~~date~~contained therein, 81,286 of Mr. Scheller’s unvested Phantom Units vested in ~~order~~connection towith behis ~~eligible~~departure ~~for~~resulting ~~acceleration~~in $2,376,803 in incremental value associated with the accelerated vesting of such Phantom Units.

~~(4)Mr.~~Outstanding ~~Long~~Equity ~~retired~~Awards ~~from~~as ~~the~~of ~~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.2025

~~(5)In~~The ~~lieu~~following oftable anprovides ~~annual~~information ~~bonus~~regarding ~~award~~Phantom ~~under~~Units ~~our~~and ~~Bonus~~RSUs ~~Plan~~granted to the NEOs pursuant to the LTIP, ~~Mr.~~and ~~Paulsen~~CRSUs ~~received~~granted apursuant ~~one-time~~to ~~cash~~the ~~signing~~CRU ~~bonus~~Plan, in each of ~~$125~~the years ended December 31,~~000~~ 2021, ~~which~~2022, ~~will~~2023, be2024 ~~paid~~and at2025 ~~the~~that ~~same~~were ~~time~~outstanding as ~~the~~of ~~bonus~~December 31, ~~amounts~~2025, ~~under~~as well as the ~~Bonus~~scheduled ~~Plan. The~~vesting ~~Compensation~~schedule ~~Committee~~for ~~approved~~each Mroutstanding award. ~~Paulsen’s~~Potential ~~long-term~~acceleration ~~equity~~events ~~incentive~~or ~~award~~change ~~target~~ in ~~connection~~control ~~with~~treatment ~~his~~for ~~appointment~~these inawards ~~November~~are ~~2024,~~described ~~however~~below in ~~December~~the ~~2024~~section ittitled ~~granted~~“Potential ~~Mr.~~Payments ~~Paulsen~~upon ~~the~~Termination ~~option~~or toChange ~~elect~~in aControl.” ~~75%~~None ~~RSU~~of ~~and~~the ~~25%~~NEOs ~~CRSU~~held ~~split,~~any ~~consistent~~outstanding ~~with~~option ~~the~~awards ~~other~~as ~~NEOs~~of December 31, 2025.

(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.


Name (10)	Number of Outstanding Unit Awards (#)		Market Value of Outstanding Unit Awards ($) (9)
M. Clint Green, President and Chief Executive Officer
2024 RSU Grant	84,270	(4)	1,938,210
2024 CRSU Grant	18,727	(5)	430,721
2025 RSU Grant	102,525	(7)	2,358,075
2025 CRSU Grant	34,175	(8)	786,025
Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer
2024 RSU Grant	56,250	(4)	1,293,750
2024 CRSU Grant	12,500	(5)	287,500
2025 RSU Grant	36,600	(7)	841,800
2025 CRSU Grant	12,200	(8)	280,600
Christopher J. Wauson, Vice President and Chief Operating Officer
2021 Grant	6,684	(1)	153,732
2022 Grant	8,709	(2)	200,307
2023 Grant	19,197	(3)	441,531
2024 RSU Grant	15,170	(4)	348,910
2024 CRSU Grant	3,370	(5)	77,510
2025 August Grant -RSUs	20,000	(6)	460,000
2025 RSU Grant	34,575	(7)	795,225
2025 CRSU Grant	11,525	(8)	265,075
Christopher W. Porter, Vice President, General Counsel and Secretary
2021 Grant	19,251	(1)	442,773
2022 Grant	16,304	(2)	374,992
2023 Grant	34,982	(3)	804,586
2024 RSU Grant	27,640	(4)	635,720
2024 CRSU Grant	6,140	(5)	141,220
2025 RSU Grant	35,400	(7)	814,200
2025 CRSU Grant	11,800	(8)	271,400

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.

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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~~2021, to the following NEOs, of which the following remain unvested as of December 31, ~~2024~~2025: Mr. ~~Long~~Wauson – 856,~~408;~~684 ~~Mr. Owens – 4,822; Mr. Scheller – 19,694~~ and Mr. Porter – 1819,~~568~~251. These remaining unvested Phantom Units will vest on December 5, ~~2025~~2026, subject to the terms of the award agreement.

(2)Includes Phantom Units granted pursuant to the LTIP on December 5, ~~2021~~2022, to the following NEOs, of which the following remain unvested as of December 31, ~~2024~~2025: Mr. ~~Long~~Wauson – 738,~~152;~~709 ~~Mr. Owens – 4,010; Mr. Scheller – 19,278~~ and Mr. Porter – 1916,~~251~~304. These remaining unvested Phantom Units will vest on December 5, ~~2026~~2027, 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.74

(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.

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(53)~~Mr.~~Includes ~~Scheller~~Phantom ~~was~~Units ~~awarded~~granted anpursuant ~~LTIP~~to ~~award~~the LTIP on ~~February~~December 175, 2023, ~~for~~to 18the NEOs as follows: Mr. Wauson – 19,~~753~~197 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, ~~2025~~2026, and the remaining 40% of the Phantom Units vesting on December 5, ~~2027~~2028, subject to the terms of the award agreement.

(64)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~~Wauson – 2815,~~310~~170; 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.

(75)Includes CRSUs granted pursuant to the CRU Plan on December 5, 2024, to the following NEOs, of which the following remain unvested as ~~follows~~of December 31, 2025: Mr. Green – 2818,~~090~~727; Mr. Paulsen –18 12,~~750~~500; Mr. ~~Scheller~~Wauson – 93,~~440;~~370 and Mr. Porter – 96,~~210 CRSUs~~140. ~~The~~These remaining CRSUs ~~granted~~will ~~on December 5, 2024~~ vest 1/32 on each of December 5, ~~2025,~~ 2026 and 2027, subject to the terms of the award agreement.

(86)Mr. ~~Kimble~~Wauson ~~left~~was awarded 20,000 RSUs pursuant to the ~~Partnership~~LTIP ~~effective~~on August 12, 2025, with 60% of the RSUs vesting on December 65, ~~2024~~2027, atand ~~which~~the ~~time~~remaining ~~Mr.~~40% ~~Kimble’s~~of ~~unvested~~the ~~equity~~RSUs ~~awards~~vesting ~~were~~on ~~forfeited~~December 5, 2029, subject to the terms of the award agreement.

(97)~~Mr.~~Includes ~~Long~~RSUs ~~retired~~granted ~~from~~pursuant to the ~~Partnership~~LTIP on December 315, ~~2024.~~2025, ~~Pursuant~~ to the ~~Long~~NEOs ~~Separation~~as ~~Agreement,~~follows: ~~following~~Mr. ~~execution~~Green of– ~~such~~102,525; ~~agreement~~Mr. ~~and~~Paulsen ~~the~~– ~~expiration~~36,600; ofMr. aWauson ~~seven~~– ~~(7) day revocation period~~34,575 ~~305,984~~and of Mr. ~~Long’s~~Porter ~~Phantom~~– ~~Units vested~~35,400. The ~~remaining~~RSUs ~~203,990~~granted ~~Phantom~~on ~~Units~~December 5, ~~together~~2025, vest incrementally, with ~~any~~60% ~~accrued~~of ~~DERs~~the onRSUs ~~such~~vesting ~~unvested~~on ~~common~~December ~~units~~5, ~~are~~2028, ~~subject~~and tothe ~~delayed~~remaining ~~vesting~~40% ~~in accordance with Section 409A~~ of the ~~Code,~~RSUs ~~and~~vesting ~~will vest~~ on ~~July~~December 15, ~~2025~~2030, subject to the terms of the ~~Long~~award ~~Separation Agreement~~agreement.

(108)~~The~~Includes ~~market~~CRSUs ~~value~~granted ofpursuant to the ~~Phantom~~CRU ~~Units~~Plan on December 5, ~~RSUs~~2025, ~~and~~to ~~CRSUs~~the ~~are~~NEOs ~~calculated~~as byfollows: ~~multiplying~~Mr. ~~$23~~Green – 34,175; Mr.56 Paulsen – 12,200; ~~the~~Mr. ~~closing~~Wauson ~~price~~– of11,525 ~~the~~and ~~Partnership’s~~Mr. ~~common~~Porter ~~units~~– 11,800. The CRSUs granted on December 315, ~~2024~~2025 byvest ~~the~~1/3 ~~number~~on each of ~~Phantom~~December ~~Units~~5, ~~RSUs~~2026, or2027 ~~CRSUs~~and ~~outstanding.~~2028, subject to the terms of the award agreement..

(9)The market value of the Phantom Units, ~~Vested~~RSUs ~~During~~and CRSUs are calculated by multiplying $23.00, the ~~Year~~closing ~~Ended~~price of the Partnership’s common units on December 31, ~~2024~~2025 by the number of Phantom Units, RSUs or CRSUs outstanding.

~~The~~(10)Mr. ~~following~~Scheller ~~table~~left ~~provides information regarding~~ the ~~vesting~~Partnership ofeffective ~~Phantom~~April ~~Units~~4, ~~held~~2025, byat ~~the~~which ~~NEOs~~time ~~during~~any ~~2024.~~awards Nothat ~~RSUs~~did ornot ~~CRSUs~~vest ~~vested~~in ~~during~~connection ~~2024~~with Mr. ~~There are no options outstanding on the Partnership~~Scheller’s ~~common~~departure ~~units~~were forfeited.

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

Units Vested During the Year Ended December 31, 2025

The following table provides information regarding the vesting of Phantom Units and CRSUs held by the NEOs during 2025. No RSUs held by the NEOs vested during 2025. There are no options outstanding on the Partnership’s common units.


Name	Number of Units Vested (#)		Value Realized on Vesting ($) (4)
M. Clint Green, President and Chief Executive Officer
CRSUs	9,363		227,240
Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer
CRSUs	6,250		151,688
Christopher J. Wauson, Vice President and Chief Operating Officer
Phantom Units	21,103	(1)	512,170
CRSUs	1,685		40,895
Christopher W. Porter, Vice President, General Counsel and Secretary
Phantom Units	43,026	(2)	1,044,241
CRSUs	3,070		74,509
Eric A. Scheller, Former Vice President and Chief Operating Officer
Phantom Units	81,286	(3)	1,918,350

________________________

(1)Mr. ~~Long~~Wauson settled approximately 50% of his newly vested Phantom Units in cash in the amount of $2256,~~242,736~~097 (before taxes), which cash settlement was reported as a disposition of those Phantom Units. The remaining 9610,~~627~~551 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~~Porter settled approximately 50% of his newly vested Phantom Units in cash in the amount of $~~113~~522,~~613~~121 (before taxes), which cash settlement was reported as a disposition of those Phantom Units. The remaining 421,~~894~~513 vested Phantom Units were settled in our common units following such cash settlement.

(3)These units vested in connection with Mr. Scheller’s departure on April 4, 2025. Mr. Scheller settled approximately 50% of his newly vested Phantom Units in cash in the amount of $~~481~~962,~~561~~020 (before taxes), which cash settlement was reported as a disposition of those Phantom Units. The remaining 2040,~~747~~643 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.75

(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.

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(4)All of the units, other Mr. Scheller’s, vested on December 5, 2025. The value realized on the vesting of Phantom Units and CRSUs was calculated by multiplying the closing price of the Partnership’s common units on the date of vesting by the number of Phantom Units or CRSUs vesting on such date. The closing price of our units on April 4, 2025 was $23.60, and the closing price on December 5, 2025 was $24.27.

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~~Agreement

As previously noted, ~~each of Messrs~~Mr. Porter ~~and Kimble is or~~ was party to an Employment Agreement providing for certain payments and benefits upon certain ~~terminations~~termination of employment. For the purposes of the following description, the “Company” means USAC Management with respect to ~~Messrs~~Mr. 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 Agreement was amended (the “Employment Agreement Amendment”) on July 2, 2025 to (i) remove the right of Mr. Porter to terminate the Employment Agreement due to a relocation of his principal place of employment; and (ii) not renew the Employment Agreement at the end of its current term. Per the terms of the Employment Agreement Amendment, the Employment Agreement terminated on January 1, 2026, which for clarity did not result in Mr. Porter’s termination of employment.

The Employment ~~Agreements~~Agreement ~~provide~~provided for the following in the event of a termination of ~~the~~Mr. ~~NEO~~Porter without Cause or by ~~the~~Mr. ~~NEO~~Porter with Good Reason (each as defined in the Employment ~~Agreements~~Agreement and set forth below): (i) semi-monthly severance payments for the one-year period following ~~the~~Mr. ~~NEO~~Porter’s Separation from Service (the “Severance Period”) in an amount totaling the higher of ~~the~~Mr. ~~NEO~~Porter’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~~Mr. ~~NEO~~Porter is terminated by the Company for “convenience” (as defined in the Employment ~~Agreements~~Agreement and set forth below) or resigns for Good Reason; (iii) a pro rata portion (based on the number of days ~~the~~Mr. ~~NEO~~Porter was employed during the year) of any earned Annual Bonus for the year in which ~~the~~Mr. ~~NEO~~Porter is terminated without Cause or resigns for Good Reason; (iv) continued health insurance benefits for ~~the~~Mr. ~~NEO~~Porter 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~~Mr. ~~NEO~~Porter’s monthly cost-sharing contribution under the Company’s group health plan, as in effect at the time of ~~the~~Mr. ~~NEO~~Porter’s Separation from Service); (b) for the following six months of the Coverage Period, such health insurance coverage will be at ~~the~~Mr. ~~NEO~~Porter’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~~Mr. ~~NEO~~Porter covered in the first 12 months of the Coverage Period; and ~~the~~Mr. ~~NEO~~Porter 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~~Mr. ~~NEO~~Porter’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~~Mr. ~~NEO~~Porter’s execution of a release of claims against the Company within 45 days of ~~such~~Mr. ~~NEO~~Porter’s Separation from Service and (2) ~~the~~Mr. ~~NEO~~Porter’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~~Mr. ~~NEO~~Porter’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~~Agreement), the Company shall pay the following to ~~the~~Mr. ~~NEO~~Porter or ~~the~~Mr. ~~NEO~~Porter’s estate: (i) the entire amount of any earned Annual Bonus for the year preceding the year in which ~~the~~Mr. ~~NEO~~Porter 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~~Mr. ~~NEO~~Porter dies or becomes Disabled; and (iii) all earned but unpaid base salary and paid time off. In the event of ~~the~~Mr. ~~NEO~~Porter’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~~Agreement, 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~~Mr. ~~NEO~~Porter, (ii) ~~the~~Mr. ~~NEO~~Porter’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.

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~~“Good~~its ~~Reason”~~affiliates, isgross ~~defined~~negligence inor ~~the~~material ~~Employment~~misconduct, ~~Agreements~~or ~~to mean (i)~~ a ~~material~~significant ~~breach~~act byor ~~the~~acts ~~Company~~ of ~~the~~personal ~~Employment~~dishonesty ~~Agreement~~ or ~~any~~deceit, ~~other~~taken ~~material~~by ~~agreement~~Mr. ~~with the NEO~~Porter, ~~(ii)~~in athe ~~material~~performance ~~reduction~~of in the ~~NEO’s~~duties ~~base~~and ~~salary,~~services ~~other~~required ~~than~~of aMr. ~~reduction~~Porter that is ~~generally~~demonstrably ~~applicable~~and significantly injurious to ~~all~~the ~~similarly~~Company ~~situated~~or ~~employees~~any of ~~the~~its ~~Company~~affiliates, (iii) aconviction ~~material~~of ~~reduction~~a infelony ~~the~~or ~~NEO’s~~crime ~~duties,~~involving ~~authority,~~moral ~~responsibilities~~turpitude, ~~job~~(iv) ~~title~~Mr. orPorter’s ~~reporting~~willful ~~relationships,~~and ~~(iv)~~continued afailure ~~material~~or ~~reduction~~refusal byto ~~the~~perform ~~Company~~substantially inMr. ~~the~~Porter’s ~~facilities~~material orobligations ~~perquisites~~pursuant ~~available~~ to the ~~NEO,~~Employment ~~other~~Agreement ~~than~~or afollow ~~reduction~~any ~~that~~lawful isand ~~generally~~reasonable ~~applicable~~directive tofrom ~~all~~the ~~similarly~~CEO ~~situated~~or ~~employees~~the Board, oras ~~(v)~~applicable, ~~the~~other ~~relocation~~than ofas ~~the~~a ~~geographic~~result ~~location~~ of ~~the~~Mr. ~~NEO~~Porter’s ~~current~~incapacity, ~~principal~~or ~~place~~(v) a violation of ~~employment~~federal, bystate ~~more~~or ~~than~~local 50law ~~miles~~or ~~from~~regulation applicable to the ~~location~~business of the ~~NEO’s~~Company ~~principal~~that ~~place~~is ofdemonstrably ~~employment~~and assignificantly ofinjurious ~~the~~to ~~effective date of~~ the ~~Employment Agreement~~Company.

“~~Disability~~Good Reason” is defined in the Employment ~~Agreements~~Agreement asto ~~the~~mean ~~NEO~~(i) ~~being~~a ~~unable~~material tobreach ~~perform~~by ~~essential~~the ~~functions~~Company of ~~his~~the ~~position,~~Employment Agreement or any other material agreement with ~~reasonable~~Mr. ~~accommodation~~Porter, ~~due~~(ii) toa anmaterial ~~illness~~reduction orin ~~physical~~Mr. orPorter’s ~~mental~~base ~~impairment~~salary, or other ~~incapacity~~than ~~which~~a ~~continues~~reduction ~~for~~that ais ~~period~~generally inapplicable ~~excess~~to all similarly situated employees of 20the ~~consecutive~~Company, ~~weeks~~(iii) a material reduction in Mr. ~~The~~ ~~determination~~Porter’s ofduties, ~~Disability~~authority, ~~will~~responsibilities, bejob ~~made~~title byor reporting relationships, or (iv) a ~~physician~~material ~~selected~~reduction by the ~~NEO~~Company ~~and~~in ~~acceptable to~~ the ~~Company~~facilities or ~~its~~perquisites ~~insurers~~available to Mr. Porter, other than a reduction that is generally applicable to all similarly situated employees.

“Disability” is defined in the Employment Agreement as Mr. Porter 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 Mr. Porter 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~~and Restricted Unit Agreement provide for (i) vesting of 40% of the outstanding, unvested Phantom Units or RSUs 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~~in the ~~remaining~~case ~~60% being forfeited), and (ii) vesting~~ of ~~50% of~~ the ~~outstanding, unvested~~ Phantom ~~Units~~Unit ifAgreement ~~the~~and ~~NEO~~five ~~voluntarily~~years ~~retires~~(provided ~~at or over~~ the ~~age~~award ~~68 and~~ has been ~~employed~~held byfor ~~us,~~at ~~the~~least ~~Company~~one oryear) ~~our~~in ~~affiliates~~the ~~for~~case atof ~~least~~the 10Restricted ~~years~~Unit Agreement (with the remaining 5060% being forfeited)., ~~The~~and ~~Restricted Unit Agreement similarly provides for~~ (iii) vesting of 4050% of the outstanding, unvested Phantom Units or RSUs if the NEO voluntarily retires ~~between~~at ~~the~~or ~~ages~~over ofthe ~~65–~~age 68, and has been employed by us, the Company, or our affiliates for at least ~~five~~10 years, ~~and~~in ~~has held~~ the ~~award~~case ~~for~~of ~~at least a year (with~~ the ~~remaining~~Phantom ~~60%~~Unit ~~being~~Agreement ~~forfeited),~~ and ~~(ii)~~five ~~vesting~~years of(provided ~~50% of~~ the ~~outstanding,~~award ~~unvested RSUs if the NEO voluntarily retires at or over the age 68,~~ has been ~~employed~~held ~~by us, the Company, or our affiliates~~ for at least ~~five~~one ~~years,~~year) ~~and~~in ~~has held~~ the ~~award~~case ~~for~~of atthe ~~least~~Restricted aUnit ~~year~~Agreement (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.

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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~~Cash Restricted Unit Agreement” described above), 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~~Cash Restricted Unit 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~~Cash Restricted Unit 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~~2025, 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 $23.5600, which was the closing price of the Partnership’s common units on December 31, ~~2024~~2025.

Executive Benefits andPayments	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 Deathor Disability($)	Termination by the Executive Other Than for“Good Reason”($) (9)	ContinuedEmployment 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	—	—	—	—	—

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Executive Benefits andPayments	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 Deathor Disability($)	Termination by the Executive Other Than for“Good Reason”($) (9)	ContinuedEmployment Following Change of Control($) (10)
M. Clint Green
President and Chief Executive Officer
Salary (1)	42,115	42,115	42,115	42,115	—
Bonus	—	—	—	—	—
Accelerated Vesting of Phantom Units	—	—	—	—	—
Accelerated Vesting of RSUs (2)	4,296,285	—	4,296,285	—	4,296,285
Totals	—	—	—	—	—
Accelerated Vesting of CRSUs (3)	1,216,746	—	1,216,746	—	1,216,746
Totals	5,555,146	42,115	5,555,146	42,115	5,513,031
Christopher M. Paulsen
Vice President, Chief Financial Officer and Treasurer
Salary (1)	347,~~269~~678	347,~~269~~678	347,~~269~~678	347,~~269~~678	—
Bonus	—	—	—	—	—
Accelerated Vesting of RSUs (2)	12,~~325~~135,~~250~~550	—	12,~~325~~135,~~250~~550	—	12,~~325~~135,~~250~~550
Accelerated Vesting of CRSUs (3)	~~441~~568,~~750~~100	—	~~441~~568,~~750~~100	—	~~441~~568,~~750~~100
Totals	12,~~770~~751,~~269~~328	347,~~269~~678	12,~~770~~751,~~269~~328	347,~~269~~678	12,~~767~~703,~~000~~650
G. Tracy Owens
Christopher J. Wauson
Vice President of Finance and Chief Accounting Officer
Vice President of Finance and Chief Operating Officer
Salary (1)	265,~~575~~152	265,~~575~~152	265,~~575~~152	265,~~575~~152	—
Bonus	—	—	—	—	—
Accelerated Vesting of Phantom Units (2)	601,463	—	601,463	—	601,463
Accelerated Vesting of Phantom Units and RSUs (2)	2,399,705	—	2,399,705	—	2,399,705
Totals	604,038	2,575	604,038	2,575	601,463
Accelerated Vesting of CRSUs (3)	342,585	—	342,585	—	342,585
Eric A. Scheller
Totals	2,807,442	65,152	2,807,442	65,152	2,742,290
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	—
Salary (4)(7)	468,222	468,222	33,222	33,222	—
Bonus (6)(9)	746,960	746,960	746,960	—	—
Bonus (5)(8)	917,000	917,000	917,000	—	—
Accelerated Vesting of RSUs and Phantom Units (2)	3,~~326~~072,~~743~~271	—	3,~~326~~072,~~743~~271	—	3,~~326~~072,~~743~~271
Accelerated Vesting of CRSUs (3)	~~216~~412,~~988~~620	—	~~216~~412,~~988~~620	—	~~216~~412,~~988~~620
Health and Welfare Plan Benefits (7)	33,915	33,915	—	—	—
Health and Welfare Plan Benefits (6)	34,982	34,982	—	—	—
Totals	4,~~769~~905,~~982~~095	1,~~226~~420,~~251~~204	4,~~326~~435,~~067~~113	3533,~~376~~222	3,~~543~~484,~~731~~891
Sean T. Kimble (11)
Eric A. Scheller (11)
Former Vice President, Human Resources
Former Vice President and Chief Operating Officer
Salary	—	—	—	—	—
Bonus	—	—	—	—	—
Accelerated Vesting of Phantom Units	—	—	—	—	—
Accelerated Vesting of RSUs and Phantom Units	—	—	—	—	—
Health and Welfare Plan Benefits	—	—	—	—	—
Accelerated Vesting of CRSUs	—	—	—	—	—
Totals	—	—	—	—	—

________________________

~~(1)Includes accrued and unpaid salary and, with respect to Mr. Green, accrued and unused paid time off.~~79

(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

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~~over~~(1)Includes ~~age~~accrued 68and atunpaid ~~the~~salary ~~time of retirement~~ and ~~has~~accrued ~~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~~unused ~~remainder~~paid ~~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~~off. 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.

(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 and 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 10 years in the case of the Phantom Units and five years (provided the award has been held for at least one year) in the case of RSUs, 60% of his then-unvested Phantom Units or RSUs will be forfeited, and the remainder will vest, at the time of retirement and, if the NEO retires at or over age 68 and has been employed by us, our General Partner, or our affiliates for at least 10 years in the case of the Phantom Units and five years (provided the award has been held for at least a year) in the case of RSUs, 50% of his then-unvested Phantom Units or RSUs will be forfeited, and the remainder will vest, at the time of retirement. 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.~~The ~~Long~~listed ~~retired~~salary ~~from the Partnership on December 31, 2024. In exchange~~ for Mr. ~~Long’s~~Porter ~~execution~~represents ofhis ~~the~~accrued ~~Long~~but ~~Separation~~unused ~~Agreement, and as approved by our Compensation Committee, we~~ paid ~~Mr.~~time ~~Long~~off aand ~~separation~~accrued ~~payment of $962,400,~~ and anunpaid ~~additional~~salary ~~$29,538,~~as ~~representing 24 months~~ of ~~health-insurance~~December ~~coverage under the Partnership’s health insurance plan (collectively~~31, ~~the~~2025 ~~“Long Separation Payment”). Additionally~~plus, ~~under~~with ~~the~~respect ~~terms~~to of the ~~Long~~first ~~Separation~~two ~~Agreement~~columns, ~~Mr.~~his ~~Long’s~~base ~~509,974~~salary ~~unvested~~as ~~Phantom~~of ~~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~~2025. ~~The~~ ~~Long~~Any ~~Separation~~accrued ~~Payment~~but ~~was~~unused paid intime aoff ~~lump~~owed ~~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~~Porter ~~also~~would ~~received~~be ~~$5,691~~paid inwithin ~~accrued,~~30 ~~unpaid~~days ~~salary. The total aggregate value~~ of the ~~accrued,~~date ~~unpaid~~of ~~salary,~~his ~~the~~termination ~~Long~~of ~~Separation Payment~~employment, and the ~~unit~~base ~~vesting~~salary ~~received~~would bybe ~~Mr.~~paid ~~Long~~out ~~pursuant~~as toset ~~the~~forth ~~Long~~in ~~Separation~~footnote ~~Agreement~~7 ~~is $13,012,616~~below.

(5)The listed ~~salary~~bonus amount for Mr. Porter ~~represents~~is his ~~accrued~~pro ~~but~~rata ~~unused~~bonus ~~paid~~awarded ~~time off and accrued and unpaid salary as of December 31, 2024 plus,~~ with respect to the ~~first~~year ~~two~~ended ~~columns, his base salary as of~~ December 31, ~~2024.~~2025, ~~Any~~and ~~accrued~~his ~~but~~bonus ~~unused~~awarded ~~paid~~with ~~time~~respect ~~off owed~~ to ~~Mr. Porter would be paid within 30 days of~~ the ~~date~~year ofended ~~his~~December ~~termination of employment~~31, ~~and the base salary would be paid out as set forth in footnote 8 below~~2024.

(6)~~The~~In ~~listed~~the ~~bonus~~event ~~amount~~of ~~for~~ Mr. Porter’s istermination ~~his~~by ~~pro~~the ~~rata~~Partnership ~~bonus~~without ~~awarded~~Cause or by the NEO with ~~respect~~Good Reason, he and his eligible dependents will be entitled to continued health insurance benefits for the ~~year~~Coverage ~~ended~~Period, ~~December~~as 31follows: (a) for the first 12 months of the Coverage Period, ~~2024~~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, ~~and~~as ~~his~~in ~~bonus~~effect ~~awarded~~at ~~with~~the ~~respect~~time toof the ~~year~~NEO’s ~~ended~~Separation ~~December~~from 31Service); (b) for the following six months of the Coverage Period, ~~2023~~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.

(7)InThe ~~the~~Employment ~~event~~Agreement offor Mr. Porter’s provides that upon termination by the Partnership without Cause or by the NEO ~~with~~for Good Reason, hethe ~~and~~NEO ~~his~~is ~~eligible dependents will be~~ entitled to ~~continued~~receive ~~health~~one ~~insurance~~times ~~benefits~~his ~~for~~base ~~the~~salary, ~~Coverage~~payable ~~Period,~~in asequal ~~follows:~~semi-monthly ~~(a)~~installments ~~for~~over the ~~first~~course ~~12 months~~ of ~~the~~one ~~Coverage~~year ~~Period~~provided, ~~the~~that ~~Partnership~~any ~~will provide~~ such ~~health~~installment ~~insurance~~payments ~~coverage~~that atwould ~~its~~otherwise ~~own~~be ~~expense~~paid ~~(other~~prior ~~than~~to the ~~NEO~~Partnership’s ~~monthly~~first ~~cost-sharing~~regular ~~contribution~~payroll ~~under~~date ~~the~~that ~~Partnership’s~~occurs ~~group~~on ~~health~~or ~~plan,~~after asthe in60th ~~effect~~day atfollowing the ~~time~~date of ~~the NEO~~Employee’s Separation from Service); (bthe “First Pay Date”) ~~for~~shall be paid on the ~~following~~First ~~six~~Pay ~~months~~Date. ofUpon the ~~Coverage~~death ~~Period,~~of ~~such~~Mr. ~~health~~Porter ~~insurance~~during ~~coverage~~this ~~will~~one-year beperiod, athis ~~the~~salary ~~NEO’s~~payment ~~sole~~will ~~expense;~~be accelerated and ~~(c)~~all ~~for~~remaining ~~the~~Severance ~~final~~Payments ~~six~~(as ~~months~~defined ofin the ~~Coverage~~Employment ~~Period,~~Agreement) ~~the~~would ~~Partnership~~be ~~will~~paid

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