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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, 2024, compared to the year ended December 31, 2023, is included under the headings in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Highlights, Financial Results of Operations, Liquidity and Capital Resources, and Critical Accounting Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 11, 2025.

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Overview

We have focused our compression services in unconventional resource plays throughout the U.S., including the Utica, Marcellus, Permian, Denver-Julesburg, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, and Haynesville, and following the J-W Power Acquisition, the Bakken. 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.

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 up year-over-year and average oil prices down, we experienced improvements to pricing and maintained fleet utilization for our compression services in 2025, largely tied to associated gas growth from oil plays.

Looking ahead, global consumption of petroleum and liquids fuels according to the EIA’s January 2026 Short Term Energy Outlook (“EIA Outlook”) increased in 2025 and is expected to increase over 1.1 million barrels per day (“bpd”) in 2026 and 0.3 million bpd in 2027. 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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flattening over the last two quarters of the year. In contrast, associated, wet natural gas growth from the Permian grew by over 10% and sequentially each quarter, owing to increased gas-to-oil ratios. We expect that anticipated flat crude oil production will continue to yield an increase in associated natural gas production volumes throughout 2026, thereby increasing demand for our compression services.

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 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 2026 and by 0.9 bcf/d in 2027, resulting in record dry natural gas production each year.

Significant demand for natural gas is driven by domestic power generation which has benefited from a lower-price environment. 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 15.0 bcf/d during 2025 and expects LNG exports to set new records of 16.4 bcf/d and 18.1 bcf/d in 2026 and 2027, respectively, as new LNG export capacity continues to ramp up creating incremental baseload global demand.

Overall, the EIA Outlook expects the increase in U.S. natural gas demand to trail production by 0.9 bcf/d in 2026, primarily reflecting the aforementioned increase in dry natural gas production compared to the expected demand from increased exports, both by LNG and pipeline, and stable baseload demand. Looking further ahead, the EIA Outlook expects U.S natural gas net demand to increase by 0.5 bcf/d in 2027, again driven primarily by LNG and pipeline exports, and stable baseload with slower rate of growth in natural gas. Natural gas prices averaged $3.53 per million British thermal units (“MMBtu”) in 2025 and the EIA Outlook expects natural gas prices to average $3.46/MMBtu and $4.59/MMBtu in 2026 and 2027, respectively, driven by the expectation that domestic natural gas inventories remain at or below previous five-year averages. 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 2026 to meet our customer needs. We expect total capital to be between $290.0 million and $320.0 million in 2026 and are beginning to evaluate new, large-horsepower compression unit orders for 2027. 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

Revenue-generating compression units (at period end) 4,256 4,269 (0.3 %)

Average horsepower per revenue-generating compression unit (6) 847 829 2.2 %

Horsepower utilization (7):

Average for the period (8) 94.3 % 94.6 % (0.3 %)

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(1)Fleet horsepower is horsepower for compression units that have been delivered to us and excludes 14,985 and 20,310 of non-marketable horsepower as of December 31, 2025, and 2024, respectively. As of December 31, 2025, we had 63,250 horsepower on order. Additionally, as a result of the J-W Power Acquisition in January 2026, we added approximately 0.8 million in active 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 92.1% and 92.4% as of December 31, 2025, and 2024, respectively.

(8)Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period. Average horsepower utilization based on revenue-generating horsepower and fleet horsepower was 92.0% and 91.7% for the years ended December 31, 2025, and 2024, respectively.

The 0.8% increase in fleet horsepower as of December 31, 2025, compared to December 31, 2024, primarily was driven by new compression units added to our fleet to meet incremental demand from customers for our compression services.

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

The 4.7% increase in average revenue per revenue-generating horsepower per month for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit.

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Financial Results of Operations

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

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

Year Ended December 31, Increase

Revenues:

Costs and expenses:

Loss on disposition of assets 3,820 4,939 *

Other income (expense):

Loss on extinguishment of debt (3,006) (4,966) *

Gain on derivative instrument — 5,684 *

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*Not meaningful.

Contract operations revenue. The $26.7 million increase in contract operations revenue for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) a 4.7% increase in average revenue per revenue-generating horsepower per month, as a result of higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit, (ii) a 0.9% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with an overall increase in crude oil and natural gas produced within the U.S., partially offset by (iii) a $7.8 million decrease in revenue attributable to natural gas treating services activity.

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 $2.8 million decrease in parts and service revenue for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to a decrease in maintenance work performed on units outside the scope of our core maintenance activities, and in directly reimbursable freight and crane charges that are the financial responsibility of the customers. 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 $23.7 million increase in related-party revenue for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to revenue recognized from

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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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Income tax expense. The$2.6 million increase in income tax expense for the year ended December 31, 2025, compared to the year ended December 31, 2024, is primarily related to a 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 potential 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”.

The following table summarizes other financial data for the periods presented (dollars in thousands):

Year Ended December 31, Increase

Other Financial Data: (1) 2025 2024 (Decrease)

Adjusted gross margin percentage (2) 67.1 % 67.1 % — %

Adjusted EBITDA percentage (2) 61.5 % 61.5 % — %

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(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 $11.5 million increase in gross margin for the year ended December 31, 2025, compared to the year ended December 31, 2024, was due to (i) a $47.7 million increase in revenues, offset by (ii) a $16.1 million increase in cost of operations, exclusive of depreciation and amortization and (iii) an $20.1 million increase in depreciation and amortization.

Adjusted gross margin. The $31.6 million increase in Adjusted gross margin for the year ended December 31, 2025, compared to the year ended December 31, 2024, was due to a $47.7 million increase in revenues, offset by a $16.1 million increase in cost of operations, exclusive of depreciation and amortization.

Adjusted EBITDA. The $29.5 million increase in Adjusted EBITDA for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to a $31.6 million increase in Adjusted gross margin, partially offset by a $1.1 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, transaction expenses, and severance charges and other employee costs.

DCF. The $30.4 million increase in DCF for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) a $31.6 million increase in Adjusted gross margin, (ii) a $9.3 million decrease in distributions on Preferred Units following the conversion of 180,000 Preferred Units into 8,994,826 common units, and (iii) a $5.9 million decrease in cash interest expense, net, partially offset by (iv) a $7.5 million increase in maintenance capital expenditures, (v) a $6.9 million decrease in cash received on derivative instrument, and (vi) $1.1 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, transaction expenses, severance charges and other employee costs.

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, 2025, compared to the year ended December 31, 2024, primarily was due to the increase in DCF, offset by an increase in distributions from an increase in the number of common units, largely attributable to the conversion of 180,000 Preferred Units into 8,994,826 common units during 2025 and the issuance of 18,175,323 common units in January 2026 related to the J-W Acquisition.

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

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distributions on our outstanding preferred and common equity. Our principal sources of liquidity include cash generated by operating activities, borrowings under the Credit Agreement, and issuances of debt and equity securities, including common units under the DRIP.

We believe cash generated by operating activities and, where necessary, borrowings under the Credit Agreement will be sufficient to service our debt, fund working capital, fund our estimated expansion capital expenditures, fund our maintenance capital expenditures, and pay distributions to our unitholders through 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, 2025 and 2024, were $39.4 million and $31.9 million, respectively. We currently have budgeted between $60.0 million and $70.0 million in maintenance capital expenditures during 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 $230.0 million and $250.0 million in expansion capital expenditures for 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, 2025 and 2024, were $117.6 million and $243.5 million, respectively.

As of December 31, 2025, we had binding commitments to purchase $78.4 million of additional compression units, all of which is expected to be delivered within the next twelve months. We have not ordered any compression units subsequent to December 31, 2025.

Other Commitments

As of December 31, 2025, other commitments include operating and finance lease payments totaling $18.4 million, of which we expect to make payments of $5.6 million to be settled in the next twelve months. For 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, 2025 and 2024, (in thousands):

Year Ended December 31,

Net cash provided by operating activities $ 394,262 $ 341,334

Net cash provided by operating activities. The $52.9 million increase in net cash provided by operating activities for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) a $60.8 million decrease in inventory purchases and (ii) a $21.3 million increase in net income excluding non-cash charges, partially offset by (iii) a $27.0 million increase in interest payments due to the timing of payments related to our refinance of our Senior Notes 2026 and (iv) a $2.1 million increase in other working capital.

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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The Credit Agreement also contains various financial covenants, including covenants requiring us to maintain:

•a minimum EBITDA to interest coverage ratio of 2.50 to 1.00, determined as of the last day of each fiscal quarter, with EBITDA and interest expense annualized for the most-recent fiscal quarter;

•a ratio of total secured indebtedness to EBITDA not greater than 3.00 to 1.00 or less than 0.00 to 1.00, determined as of the last day of each fiscal quarter, with EBITDA annualized for the most-recent fiscal quarter; and

•a funded debt-to-EBITDA ratio, defined in the Credit Agreement as the Total Leverage Ratio, determined as of the last day of each fiscal quarter with EBITDA annualized for the most-recent fiscal quarter, of not greater than 5.50 to 1.00 or less than 0.00 to 1.00.

We expect to remain in compliance with our covenants under the Credit Agreement throughout 2026. If our current cash flow projections prove to be inaccurate, we expect to be able to remain in compliance with such financial covenants by taking one or more of the following actions: issue equity in a public or private offering; request a modification of our covenants from our bank group; reduce distributions from our current distribution rate or suspend distributions altogether; delay discretionary capital spending and reduce operating expenses; or obtain an equity infusion pursuant to the terms of the Credit Agreement.

For a more detailed description of the Credit Agreement, including the covenants and restrictions contained therein, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

Senior Notes

As of December 31, 2025, we had $1.0 billion and $750.0 million aggregate principal amount outstanding on our Senior Notes 2029 and Senior Notes 2033, respectively.

The Senior Notes 2027 were due on September 1, 2027, and accrued interest at the rate of 6.875% per year. Interest on the Senior Notes 2027 was payable semi-annually in arrears on each of March 1 and September 1. On October 15, 2025 the Senior Notes 2027 were redeemed in full at par, plus accrued and unpaid interest, with the net proceeds from the issuance and sale of the Senior Notes 2033, together with borrowings under our Credit Agreement.

The Senior Notes 2029 are due on March 15, 2029, and accrue interest at the rate of 7.125% per year. Interest on the Senior Notes 2029 is payable semi-annually in arrears on each of March 15 and September 15.

The Senior Notes 2033 are due on October 1, 2033, and accrue interest at the rate of 6.250% per year. Interest on the Senior Notes 2033 is payable semi-annually in arrears on each of April 1 and October 1, commencing on April 1, 2026.

For more detailed descriptions of the Senior Notes 2027, Senior Notes 2029, and Senior Notes 2033, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

DRIP

During the years ended December 31, 2025 and 2024, distributions of $0.2 million and $1.6 million, respectively, were reinvested under the DRIP resulting in the issuance of 7,832 and 65,352 common units, respectively.

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.

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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,

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,

Severance charges and other employee costs (3) 4,455 2,430

Loss on disposition of assets 3,820 4,939

Loss on extinguishment of debt (4) 3,006 4,966

Gain on derivative instrument — (5,684)

Severance charges and other employee costs (4,455) (2,430)

Cash received on derivative instrument — 6,888

Changes in operating assets and liabilities (29,872) (61,523)

Net cash provided by operating activities $ 394,262 $ 341,334

________________________

(1)For the years ended December 31, 2025 and 2024, unit-based compensation expense included $2.0 million and $3.9 million, respectively, of cash payments related to quarterly payments of DERs on outstanding unit awards. Additionally, for the years ended December 31, 2025 and 2024, we paid $7.7 million and $5.4 million, respectively, for 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)Severance charges and other employee costs includes (i) severance payments to former employees of the Partnership, (ii) retention payments to employees of the Partnership that have executed agreements to maintain operations during the shared services integration but do not intend to remain employed with the Partnership after their retention period, and (iii) relocation payments to employees of the Partnership for relocation resulting from the shared services integration and the relocation of the Partnership’s headquarters to Dallas, Texas. These retention payments are incremental to the affected employees’ base pay. For the year ended December 31, 2025, severance charges and other employee costs included $0.6 million related to each of retention payments and relocation payments.

(4)For the year ended December 31, 2025, the loss on extinguishment of debt of $3.0 million is a result of the redemption of our Senior Notes 2027.

For the year ended December 31, 2024, the loss on extinguishment of debt is a result of the Defeasance of the Senior Notes 2026. 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,

Non-cash income tax expense 466 574

Severance charges and other employee costs (3) 4,455 2,430

Loss on disposition of assets 3,820 4,939

Loss on extinguishment of debt (4) 3,006 4,966

Change in fair value of derivative instrument — 1,204

Distributions on Preferred Units (8,288) (17,550)

Severance charges and other employee costs (4,455) (2,430)

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.

(4)For the year ended December 31, 2025, the loss on extinguishment of debt of $3.0 million is a result of the redemption of our Senior Notes 2027.

(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.

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

Year Ended December 31,

DCF Coverage Ratio 1.45 x 1.44 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, 2025 and 2024, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 28 and 2 compression and treating units, respectively, representing approximately 19,005 and 1,260 of aggregate horsepower, respectively, that previously were used to provide compression and treating services in our business. As a result, we recorded impairments of compression and treating equipment of $7.8 million and $0.3 million for the years ended December 31, 2025, and 2024, respectively. The primary circumstances supporting these impairments were: (i) unmarketability of certain compression units into the foreseeable future, (ii) excessive maintenance costs associated with certain

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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.

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, resulted in imputed underpayment computations of approximately $30.3 million, including interest, for the 2019 and 2020 tax years. Under the Bipartisan Budget Act of 2015, there are several procedural steps to complete before a final imputed underpayment, if any, is determined. Based on discussions with the IRS, we have accrued $2.9 million, which we believe is a reasonable estimate of the potential loss from the aggregate final imputed underpayment for the years 2019 and 2020. However, the final partnership imputed underpayment, if any, has not been determined. Once determined, our General Partner may elect to either pay the imputed underpayment, if any, (including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised information statement to each unitholder, or former unitholder as applicable, with respect to an audited and adjusted return.

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, 2025 would result in an annual decrease of approximately $9.1 million and $6.1 million in our revenue and Adjusted gross margin, respectively. Adjusted gross margin is a non-GAAP financial measure. For 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 – A reduction in the demand for, or production of, natural gas or crude oil could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders.”

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Interest Rate Risk

We are exposed to market risk due to variable interest rates under the Credit Agreement.

As of December 31, 2025, we had $795.0 million of variable-rate indebtedness outstanding at a weighted-average interest rate of 5.74%. Based on our December 31, 2025 variable-rate indebtedness outstanding, a one percent increase or decrease, respectively, in the effective interest rate would result in an annual increase or decrease in our interest expense of approximately $8.0 million.

For further information regarding our exposure to interest rate fluctuations on our debt obligations, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

Credit Risk

Our credit exposure generally relates to receivables for services provided. 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, 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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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, 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, 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, 2025, and our report dated February 17, 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 17, 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 February 2026, the Compensation Committee approved a one-time special incentive retention bonus for Christopher J. Wauson in the amount of $500,000 (the “Special Bonus”). The Special Bonus was approved by the Compensation Committee based on the recommendation of senior management in recognition of, among other things, (i) Mr. Wauson’s recent appointment as the Senior Vice President and Chief Operating Officer of the Company and prompt relocation to Dallas to assume the role; (ii) his 2025 calendar year performance; and (iii) the anticipation of his role in several key current and future initiatives.

The approval of the Special Bonus by the Compensation Committee was conditioned upon entry by Mr. Wauson into a Special Bonus Retention Agreement with the General Partner (the “Retention Agreement”) which provides (i) if, prior to the second (2nd) anniversary of the effective date of the Retention Agreement, Mr. Wauson’s employment with the Partnership terminates (other than as a result of (x) a termination without cause by the Partnership; (y) his death; or (z) his permanent disability as determined by the Partnership), he will be obligated to remit and repay one-hundred percent (100%) of the Special Bonus to the Partnership; and (ii) if, after the second (2nd) anniversary but prior to March 1, 2029, Mr. Wauson’s employment with the Partnership terminates (other than as a result of (x) a termination without cause by the Partnership; (y) his death; or (z) his permanent disability as determined by the Partnership), he will be obligated to remit and repay fifty percent (50%) of the Special Bonus to the Partnership. Mr. Wauson and the General Partner entered into the Retention Agreement on February 12, 2026.

The foregoing summary of the Retention Agreement does not purport to be complete and is qualified in its entirety by reference to the full text of the Retention Agreement, which is filed as Exhibit 10.22 hereto, and is incorporated herein by reference.

Rule 10b5-1 Trading Plans

During the three months ended December 31, 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. 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 currently has 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, 8115 Preston Road, Suite 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.

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

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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.

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, 8115 Preston Road, Suite 700, Dallas, Texas 75225.

Compensation Committee. The NYSE does not require a listed limited partnership like us to have a compensation committee. However, the Board established the Compensation Committee to, among other things, oversee our compensation program described below in Part III, Item 11 “Executive Compensation.” The Compensation Committee consists of Messrs. Joyce, Waldheim, and Wortham and is chaired by Mr. Joyce. The Compensation Committee establishes and reviews general policies related to our compensation and benefits, and is responsible for making recommendations to the Board with respect to the compensation and benefits of the Board. In addition, the Compensation Committee administers the USA Compression Partners, LP 2013 Long-Term Incentive Plan, as amended and as may be further amended or replaced from time to time (the “LTIP”) and the USA Compression Partners, LP Long-Term Cash Restricted Unit Plan, as may be amended or replaced from time to time (the “CRU Plan”).

Under the charter of the Compensation Committee (the “Compensation Committee Charter”), a director serving as a member of the Compensation Committee may not be an officer of, or employed by, the General Partner, us, or our subsidiaries. During 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, 8115 Preston Road, Suite 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, 8115 Preston Road, Suite 700, Dallas, Texas 75225.

Note that the preceding internet addresses are for informational purposes only and are not intended to be hyperlinked. Accordingly, no information found on or provided at those internet addresses or on our website in general is intended or deemed to be incorporated by reference herein.

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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 12, 2026 regarding the current directors and executive officers of USA Compression GP, LLC.

Name Age Position with USA Compression GP, LLC

M. Clint Green 48 President and Chief Executive Officer

Christopher J. Wauson 45 Senior Vice President and Chief Operating Officer

Christopher W. Porter 42 Senior Vice President, General Counsel and Secretary

Dylan A. Bramhall 49 Director

Clifford A. Harris 77 Director

Glenn E. Joyce 68 Director

Thomas E. Long 69 Director

Thomas P. Mason 69 Director

William S. Waldheim 69 Director

Bradford D. Whitehurst 51 Director

John L. Wortham 74 Director

James M. Wright, Jr. 57 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 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 joining 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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Maguire Energy Institute at Southern Methodist University, focusing his efforts with the student-directed Spindletop Energy Investment Fund.

Christopher J. Wauson has served as our Senior Vice President and Chief Operating Officer since January 2026 and prior to that was our Vice President and Chief Operating Officer since April 2025. Prior to that, he served as the company’s Regional Vice President of Operations, a position he held since USA Compression acquired CDM Resource Management in 2018. From 2011 to 2018, Mr. Wauson held roles of increasing responsibility at CDM Resource Management, where he advanced to Senior Vice President of Operations. Prior to CDM Resource Management, Mr. Wauson held various positions in the energy and natural gas compression industries beginning in 1999 at companies including Hanover, Alcoa and Valerus Compression. Mr. Wauson holds an associate’s degree in Instrumentation/ Electrical Technology from the University of Houston.

Christopher W. Porter has served as our Senior Vice President, General Counsel and Secretary since January 2026 and prior to that was our Vice President, General Counsel and Secretary since January 2017. Mr. Porter joined us in October 2015 as our Associate General Counsel and Assistant Secretary. 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 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 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 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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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 infrastructure 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.

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. Waldheimhas served on the Board since April 2018. Mr. Waldheim also served on the board of directors of Southcross Energy Partners GP, LLC from February 2020 through April 2022. Mr. Waldheim served as a director and a member of the Audit, Finance & Risk Committee of Enbridge Energy Company, Inc. and Enbridge Energy Management, L.L.C. from February 2016 through December 2018. He previously served as President of DCP Midstream LP where he had overall responsibility for DCP Midstream’s affairs including commercial, trading, and business development until his retirement in 2015. Prior to this, Mr. Waldheim was President of Midstream Marketing and Logistics for DCP Midstream and managed natural gas, crude oil, and natural gas liquids marketing and logistics. From 2005 to 2008, he was Group Vice President of Commercial for DCP Midstream, managing its upstream and downstream commercial business. Mr. Waldheim started his professional career in 1978 with Champlin Petroleum as an auditor and financial analyst and served in roles involving NGL and crude oil distribution and marketing. He served as Vice President of NGL and Crude Oil Marketing for Union Pacific Fuels from 1987 until 1998 at which time it was acquired by DCP Midstream.

Mr. Waldheim was selected to serve on the Board because of his broad and extensive experience in senior leadership roles in the energy industry and his financial and accounting expertise.

Bradford D. Whitehurst has served on the Board since April 2019. Since November 2022, Mr. Whitehurst has served as the Executive Vice President of Tax and Corporate Initiatives of the general partner of Energy Transfer. From January 2021 through November 2022, Mr. Whitehurst was the Chief Financial Officer of the general partner of Energy Transfer. Prior to that, Mr. Whitehurst served as their Executive Vice President – Head of Tax since August 2014. Mr. Whitehurst also served as the Chief Financial Officer of the general partner of ETO from January 2021 until its merger into Energy Transfer in April 2021, and prior to that was their Executive Vice President – Head of Tax since August 2014. Prior to joining Energy Transfer, Mr. Whitehurst was a partner in the Washington, DC office of Bingham McCutchen LLP and an attorney in the Washington, DC offices of both McKee Nelson LLP and Hogan & Hartson. Mr. Whitehurst has specialized in partnership taxation and has advised Energy Transfer LP in his role as outside counsel since 2006.

Mr. Whitehurst was selected to serve on the Board because of his strong background in the energy sector and specialized knowledge of the taxation structure and issues unique to partnerships.

John L. Wortham has served on the Board since March 2024. Mr. Wortham has over 40 years of experience in the energy industry. Mr. Wortham worked at Energy Transfer from 2002 until his retirement in October 2020, most recently as a Senior Director of Business Development and before that as a Senior Director of Gas Supply- Long Term Gas Contracts. Prior to that, Mr. Wortham worked for the energy company Aquila, Inc. (“Aquila”), as a Director of Business Management from 1993 until 2002, when Energy Transfer acquired certain of Aquila’s assets. Mr. Wortham has also worked in various other roles in the energy industry since 1980. Mr. Wortham graduated from Texas Christian University in 1973 with a business management degree.

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

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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, 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, 2025, the NEOs were:

•M. Clint Green, President and CEO;

•Christopher M. Paulsen, Vice President, Chief Financial Officer and Treasurer;

•Christopher J. Wauson, Vice President and Chief Operating Officer;*

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

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

*Mr. Scheller resigned from his position as Vice President and Chief Operating Officer effective April 4, 2025. Effective April 5, 2025, Mr. Wauson was appointed by the Board as the Vice President and Chief Operating Officer.

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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:

•reward executive officers with an industry-competitive total compensation package of competitive base salaries and significant incentive opportunities yielding a total compensation package approaching the top-quartile 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 relevant data available to it to assess our competitive position with respect to base salary, annual short-term incentives and long-term 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 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 takes into account guidance and input, as appropriate, from our CEO, Energy Transfer’s Co-CEO, and Energy Transfer’s Group Senior Vice President of Human Resources 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, Energy Transfer’s Co-CEO, and Energy Transfer’s Group Senior Vice President of Human 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.

Periodically, we engage a third-party consultant to provide the Compensation Committee with market information regarding compensation levels at peer companies to assist in evaluating compensation levels for our executives, including the NEOs. In 2025, we engaged Meridian Compensation Partners, LLC (“Meridian”), the independent compensation advisor to Energy Transfer, to conduct a report on market information and compensation levels of our peer companies (the “2025 Meridian Report”), which report updated and replaced the most recent report prepared by Meridian in 2023 (the “2023 Meridian Report”).

In conducting its review, Meridian assisted in the development of the final “peer group” of companies in the oil and gas space that most closely reflect our profile after considering factors like revenue, total assets, enterprise value and market cap. The final “peer group” represented an expanded reference of companies composed of a broader group of oil and gas companies, including a large focus on equipment and services companies but also including certain marketing companies, transportation and storage and upstream comparators whose data provided additional market context. For 2025, the core 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 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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and April 2025, respectively. In connection with determining initial base salaries for Messrs. Porter and Scheller for 2025, the Compensation Committee and CEO considered cost of living increases, internal compensation levels within the Energy Transfer Group, and comparable salaries for certain executive roles within our peer group contained in the 2023 Meridian Report, and determined to provide an increase to base salary for Messrs. Porter and Scheller for 2025.

The initial 2025 base salaries, and 2024 base salaries for certain NEOs, are set forth in the following table:

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 J. Wauson, Vice President and Chief Operating Officer 375,000 —

________________________

(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 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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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 50%

Distributable Cash Flow Budget Target Payout Factor 30%

Departmental Budget Target Payout Factor 10%

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 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.

Adjusted EBITDA and DCF Factors

% of Budget Target Bonus Pool Payout Factor

For the 2025 year, the Compensation Committee set the Adjusted EBITDA Budget Target at $600.0 million and the DCF Budget Target at $360.0 million.

The Departmental Budget Target Payout Factor (the “Departmental Budget Factor”) assigns payout factors based on the specific dollar amount of general and administrative expenses or operating and maintenance expenses set for each department of the Partnership.

Departmental Budget Ratio Factor

% of Budget Target Bonus Pool Payout Factor

For the 2025 year, the Compensation Committee set the Departmental Budget Target (as defined in the Bonus Plan) at $60.5 million.

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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

For the 2025 year, the Compensation Committee set the Safety Budget Target (as defined in the Bonus Plan) at 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 2025 year range from 65% to 135% of their respective annual base salaries.

For the 2025 year, the Compensation Committee set a target bonus amount (the “Target Bonus”) for each NEO as follows: (i) for Mr. Wauson, upon his appointment in April 2025, which the Compensation Committee reaffirmed in connection with its compensation merit review in August 2025, (ii) for Mr. Porter, in connection with his compensation merit review in July 2025, and (iii) for Messrs. Green and Paulsen, in connection with their compensation merit reviews in August 2025. These Target Bonuses were set as a percentage of the NEO’s base salary. For the bonus applicable to the 2025 year, the Target Bonus, as a percentage of base salary and as a dollar amount, is reflected in the table below.

Name (1) Percentage of Base Salary Target Amount ($)

M. Clint Green, President and Chief Executive Officer 135 % 708,750

Christopher J. Wauson, Vice President and Chief Operating Officer 105 % 446,250

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(1)Mr. Scheller left the Partnership effective April 4, 2025 and, as such, was ineligible to participate in the Bonus Plan for 2025.

The annual cash bonus pool targets for 2025 were based on the determination of the Compensation Committee 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.

For 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:

Name (1) Bonus ($)

M. Clint Green, President and Chief Executive Officer 765,000

Christopher J. Wauson, Vice President and Chief Operating Officer 450,500

Christopher W. Porter, Vice President, General Counsel and Secretary 507,000

________________________

(1)Mr. Scheller left the Partnership effective April 4, 2025, and as such, was ineligible to participate in the Bonus Plan for 2025.

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Amounts received 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

While the Partnership has historically granted Phantom Units awards under its long-term incentive award program, beginning in December 2024, the Partnership began granting awards of RSUs together with awards of CRSUs. The vesting terms of these awards and the target award levels for the 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, since our initial public offering in 2013, the Compensation Committee has only granted awards of Phantom Units and RSUs with DERs under 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, 2025.”

Under our Phantom Unit Agreement and Restricted Unit Agreement that are currently in effect, vesting occurs as 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 ofBase Salary Grant Date Amount ($)

M. Clint Green, President and Chief Executive Officer 600 % 3,317,709

(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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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. With respect to the Phantom Units that vested in 2025, the Compensation Committee previously approved a default settlement method for Phantom Units of 50% in cash and 50% in common units. 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 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 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. 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 2025 is set forth below in “– Summary Compensation Table.”

Energy Transfer LP Non-Qualified Deferred Compensation Plan (the “Energy Transfer NQDC Plan”)

Our NEOs, along with certain other highly compensated employees, are eligible to participate in Energy Transfer’s deferred compensation plan, which permits eligible highly compensated employees to defer a portion of their salary, bonus, and/or quarterly non-vested phantom or restricted unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Each year under the Energy Transfer NQDC Plan, eligible employees are permitted to make an irrevocable election to defer up to 50% of their annual base salary, 50% of their quarterly non-vested phantom or restricted unit distribution income, and/or 50% of their discretionary performance bonus compensation during the following year. Pursuant to the Energy Transfer NQDC Plan, Energy Transfer may make annual discretionary matching contributions to participants’ accounts; however, Energy Transfer has not made any discretionary contributions to participants’ accounts and currently has no plans to make any discretionary contributions to participants’ accounts. All amounts credited under the Energy Transfer NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed earnings or losses based on hypothetical investment fund choices made by the participants among available funds.

Participants may elect to have their account balances distributed in one lump sum payment or in annual installments over a period of three or five years upon retirement, and in a lump sum upon other termination events. Participants may also elect to take lump-sum in-service withdrawals five years or longer in the future, and such scheduled in-service withdrawals may be further deferred prior to the withdrawal date. Upon a change in control (as defined in the Energy Transfer NQDC Plan) of Energy Transfer, all Energy Transfer NQDC Plan accounts are immediately vested in full. However, distributions are not accelerated and, instead, are made in accordance with the Energy Transfer NQDC Plan’s normal distribution provisions unless a participant has elected to receive a change of control distribution pursuant to his deferral agreement.

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Employment 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 award over the applicable vesting period. 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 were the only members of the Compensation Committee during 2025. During 2025, none of Messrs. Joyce, Waldheim or 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.

Summary Compensation Table

The following table provides information concerning compensation of our NEOs for the fiscal years presented below, as applicable.

Vice President and Chief Operating Officer

________________________

(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 15in 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 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 2025 year will be paid after the Partnership’s audited financials are finalized.

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(3)See the chart below for a detailed breakdown of amounts reported in this column for 2025:

Name DERs Automobile Allowance Employer 401(k) Contributions Parking

Mr. Green $ — $ — $ 16,942 $ —

The amounts reflected for all periods include distribution payments in connection with DERs on unvested Phantom Unit awards. However the amounts exclude distribution payments in connection with DERs on unvested RSU awards because the dollar value of such distributions are factored into the grant date fair value reported in the “Equity Awards” column of the Summary Compensation Table at the time that the RSU awards and related DERs were originally granted.

See note (4) below regarding certain benefits provided to Mr. Green during 2024, and note (8) below with respect to separation payments to Mr. Scheller.

(4)For administrative reasons, in 2024 Mr. Green remained on Energy Transfer’s employee plans with respect to (i) medical, dental, vision, disability, and life insurance benefits and (ii) a defined contribution plan that is tax-qualified under section 401(k) of the Internal Revenue Code. As part of the shared services 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.

USAC US Equity

USAC · 10-K · period ended 2025-12-31

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk

ITEM 8. Financial Statements and Supplementary Data

ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

ITEM 9A. Controls and Procedures

ITEM 9B. Other Information

ITEM 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

ITEM 10. Directors, Executive Officers, and Corporate Governance

ITEM 11. Executive Compensation

USAC US Equity☆

USAC · 10-K · period ended 2025-12-31

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk

ITEM 8. Financial Statements and Supplementary Data

ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

ITEM 9A. Controls and Procedures

ITEM 9B. Other Information

ITEM 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

ITEM 10. Directors, Executive Officers, and Corporate Governance

ITEM 11. Executive Compensation

USAC US Equity