What changed in this filing

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Item 7. Management’s Discussion and Analysis

2026-02-17 compared with 2025-02-11 · 113 added, 108 removed, 324 unchanged (41% of the section changed)

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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.

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

According to studies promulgated by the EIA, the production and transportation volumes in these unconventional plays, namely tight oil and gas shale plays, are expected to collectively increase over the long term.

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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

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In addition to our natural gas infrastructure applications, a portion of our small- and large-horsepower fleet is used in connection with gas-lift applications for crude oil production targeted by horizontal drilling techniques.

We deliver natural gas compression services in connection with domestic natural gas production that primarily occurs in natural gas basins, such as the Marcellus, Utica, and Haynesville Shales, and in crude oil basins where “associated” natural gas is produced alongside crude oil, such as in the Permian and Denver-Julesburg Basins, Eagle Ford, and the Mid-Continent.

Relative stability in commodity prices over much of the past decade encouraged investment in domestic exploration and production and midstream infrastructure across the energy industry, particularly in low-cost U.S.

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Although our business is focused on providing compression services that do not bear direct exposure to commodity prices, our business exhibits indirect exposure to commodity prices as overall levels of drilling activity and production are influenced by prevailing commodity prices.

With average natural gas prices down year-over-year and average oil prices relatively flat, we experienced improvements to pricing and fleet utilization for our compression services in 2024, largely tied to associated gas growth from oil plays.

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.

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In 2026 and 2027, the EIA Outlook expects U.S.

crude oil production growth to continue, albeit at a lower crude oil price, estimating average production of 13.5 million bpd for 2025 and 13.6 million bpd in 2026, which would represent new records for annual average crude oil production.

crude oil production growth in 2025 and 2026 is expected to come almost entirely from the Permian, which is expected to account for over half of U.S.

crude oil production by 2026.

We expect that anticipated crude oil production increases likewise will increase associated natural gas production volumes throughout 2025, thereby increasing demand for our compression services.

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.

crude oil production growth in 2025 came almost entirely from the Permian, which grew by 4% despite

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 of an overall decline in natural gas prices.

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.

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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 U.S.

natural gas demand to outpace production and to increase by 3.2 bcf/d in 2025, primarily reflecting increased exports, both by LNG and pipeline, and stable baseload demand.

Further, the EIA Outlook expects U.S natural gas demand to increase another 2.6 bcf/d in 2026, again driven primarily by LNG and pipeline exports, and stable baseload.

Natural gas prices averaged $2.20 per million British thermal units (“MMBtu”) in 2024 and the EIA Outlook expects natural gas prices to increase on average to $3.10/MMBtu and $4.00/MMBtu in 2025 and 2026, respectively, driven by the expectation that domestic natural gas inventories remain at or below previous five-year averages.

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.

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The following table summarizes certain horsepower and horsepower-utilization percentages for the periods presented and excludes certain gas-treating assets for which horsepower is not a relevant metric.

Year Ended December 31,

2024 2023 Increase

Year Ended December 31, Increase

2025 2024 (Decrease)

Fleet horsepower (at period end) (1) 3,894,332 3,862,102 0.8 %

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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, 2024, we had no horsepower on order.

Subsequent to December 31, 2024, the Partnership ordered 10,000 large horsepower for expected delivery during 2025.

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.

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

The 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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Selling, general, and administrative 66,343 72,666 (8.7) %

Loss (gain) on disposition of assets 4,939 (1,667) *

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

Impairment of assets 7,811 913 *

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Total other expense (190,317) (192,643) (1.2) %

Net income before income tax expense 101,806 69,633 46.2 %

Income before income tax expense 116,188 101,806 14.1 %

Income tax expense 4,869 2,231 118.2 %

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Contract operations revenue .

The $82.7 million increase in contract operations revenue for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) an 8.3% increase in average revenue per revenue-generating horsepower per month, as a result of higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit, (ii) a 6.0% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with an overall increase in crude oil and natural gas produced within the U.S., partially offset by (iii) an $8.9 million decrease in revenue attributable to natural gas treating services.

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 $2.0 million increase in parts and service revenue for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to an increase in maintenance work performed on units at customer locations that are outside the scope of our core maintenance activities and that are offered as a convenience, and in directly reimbursable freight and crane charges that are the financial responsibility of the customers.

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.

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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

existing customers acquired by Energy Transfer since the previous period that are now classified as related-party revenue in the current period.

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 $28.0 million increase in cost of operations for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $17.2 million increase in direct labor costs due to increased headcount associated with increased revenue-generating horsepower and higher employee costs, (ii) a $12.3 million increase in direct expenses, primarily driven by increased spending on parts resulting from higher costs and increased usage associated with increased revenue-generating horsepower, (iii) a $2.2 million increase in other indirect expenses due to increased usage associated with increased revenue-generating horsepower, and (iv) a $1.4 million increase in retail parts and service expenses, for which a corresponding increase in parts and service revenue also occurred, partially offset by (v) a $3.6 million decrease in outside maintenance costs due to reduced use of third-party labor during the current period and (vi) a $1.4 million decrease in non-income taxes.

The $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 $18.7 million increase in depreciation and amortization expense for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) overhauls and major improvements to compression units and (ii) new trucks added to our vehicle fleet.

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 change in selling, general, and administrative expense for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $5.6 million decrease in unit-based compensation expense, primarily attributable to mark-to-market changes to our unit-based compensation liability that occurred as a result of changes to our per-unit trading price as of December 31, 2024, partially offset by (ii) a $3.2 million increase to professional fees primarily related to an initiative to improve business performance, (iii) a $1.3 million increase in severance charges related to the departure of executives during the current period, and (iv) a $0.6 million increase in employee-related expenses driven by increased headcount.

Loss (gain) on disposition of assets.

The $4.9 million loss on disposition of assets for the year ended December 31, 2024, and the $1.7 million gain on disposition of assets for the year ended December 31, 2023, were related to various asset transactions.

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 .

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(i) unmarketability of certain compression units into the foreseeable future, (ii) excessive maintenance costs associated with certain fleet assets, and (iii) prohibitive retrofitting costs that likely would prevent certain compression units from securing customer acceptance.

These compression units were written down to their estimated salvage values, if any.

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.

Additionally, for the year ended December 31, 2024, we recognized a $0.6 million impairment of assets related to capitalized software costs that are no longer expected to provide benefit.

Interest expense, net .

The $23.5 million increase in interest expense, net for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to increased aggregate borrowings and higher aggregate weighted-average interest rates under the Credit Agreement and refinanced senior notes.

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”).

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Gain on derivative instrument.

The $5.7 million and $7.4 million gains on derivative instrument for the years ended December 31, 2024 and 2023, respectively, resulted from the change in fair value of the interest-rate swap due to changes in the interest-rate forward curve and cash received during the respective periods.

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.

Income tax expense.

The $0.9 million increase in income tax expense for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was related to deferred income taxes associated with the Texas Margin Tax.

Other Financial Data

The $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):

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Adjusted gross margin $ 669,295 $ 637,723 5.0 %

$ 637,723 $ 561,470 13.6 %

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

67.1 % 66.4 % 0.7 %

Adjusted EBITDA $ 613,760 $ 584,282 5.0 %

$ 584,282 $ 511,939 14.1 %

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

61.5 % 60.5 % 1.0 %

$ 355,317 $ 281,113 26.4 %

DCF Coverage Ratio

1.44 x 1.35 x 6.7 %

DCF $ 385,677 $ 355,317 8.5 %

DCF Coverage Ratio 1.45 x 1.44 x 0.7 %

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Adjusted EBITDA.

The $72.3 million increase in Adjusted EBITDA for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to a $76.3 million increase in Adjusted gross margin, partially offset by a $4.2 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses.

The $74.2 million increase in DCF for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $76.3 million increase in Adjusted gross margin, (ii) a $30.2 million decrease in distributions on Preferred Units following the conversion of 320,000 Preferred Units into 15,990,804 common units, and (iii) a $0.6 million increase in cash received on derivative instrument, partially offset by (iv) a $22.1 million increase in cash interest expense, net, (v) a $6.7 million increase in maintenance capital expenditures, and (vi) a $4.2 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses.

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.

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 increase in DCF Coverage Ratio for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to the increase in DCF, partially offset by an increase in distributions from an increase in the number of common units, largely attributable to the conversion of 320,000 Preferred Units into 15,990,804 common units during 2024 and the exercise of warrants for 2,360,488 common units in November 2023.

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

We operate in a capital-intensive industry, and our primary liquidity needs include financing the purchase of additional compression units, making other capital expenditures, servicing our debt, funding working capital, and paying cash distributions on our outstanding preferred and common equity.

distributions on our outstanding preferred and common equity.

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

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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, 2024, we did not have any binding commitments to purchase additional compression units and serialized parts.

Subsequent to December 31, 2024, we ordered 10,000 horsepower for expected delivery during 2025 which will cost $10.8 million, which is expected to be settled within the next twelve months.

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

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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.

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

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Net cash provided by operating activities .

The $69.4 million increase in net cash provided by operating activities for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) an increase in cash inflows from a $76.3 million increase in Adjusted gross margin and (ii) a $9.3 million decrease in cash paid for interest

expense, net of capitalized amounts, driven by the Defeasance of the Senior Notes 2026, partially offset by (iii) a $25.1 million increase in inventory purchases.

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 $30.6 million decrease in net cash used in investing activities for the year ended December 31, 2024, compared to the year ended December 31, 2023, was due to (i) a $33.7 million decrease in capital expenditures, for purchases of new compression units, overhauls and major improvements, and purchases of other equipment, and (ii) a $1.0 million increase in proceeds from insurance recovery, partially offset by (iii) a $4.0 million decrease in proceeds from disposition of property and equipment.

The $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 $100.1 million increase in net cash used in financing activities for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $748.8 million increase in investments in government securities purchased in connection with the Defeasance of the Senior Notes 2026, (ii) a $325.6 million decrease in net borrowings under the Credit Agreement, (iii) an $18.2 million increase in deferred financing costs driven by the issuance of the Senior Notes 2029, and (iv) a $31.8 million increase in common unit distributions, partially offset by (v) a 1.0 billion increase in proceeds from issuance of the Senior Notes 2029, (vi) a $24.4 million decrease in Preferred Unit distributions, and (vii) a $1.1 million decrease in cash paid related to net settlement of unit-based awards.

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, 2024, we had outstanding borrowings under the Credit Agreement of $772.1 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $827.1 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $782.5 million was available to be drawn.

As of December 31, 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 6, 2025, we had outstanding borrowings under the Credit Agreement of $801.5 million and outstanding letters of credit of $0.8 million.

The Credit Agreement matures on December 8, 2026.

The Credit Agreement provides for an asset-based revolving credit facility to be made available to the Partnership in an aggregate amount of $1.6 billion.

The Partnership’s obligations under the Credit Agreement are guaranteed by the guarantors party to the Credit Agreement, which currently consists of all of the Partnership’s subsidiaries.

In addition, under the Credit Agreement the Partnership’s Secured Obligations (as defined therein) are secured by:

(i) substantially all of the Partnership’s assets and substantially all of the assets of the guarantors party to the Credit Agreement, excluding real property and other customary exclusions;

and (ii) all of the equity interests of the Partnership’s U.S.

restricted subsidiaries (subject to customary exceptions).

Borrowings under the Credit Agreement bear interest at a per-annum interest rate equal to, at the Partnership’s option, either the Alternate Base Rate or SOFR plus the applicable margin.

“Alternate Base Rate” means the greatest of (i) the prime rate, (ii) the applicable federal funds effective rate plus 0.50%, and (iii) one-month SOFR rate plus 1.00%.

The applicable margin for borrowings varies (a) in the case of SOFR loans, from 2.00% to 2.75% per annum, and (b) in the case of Alternate Base Rate loans, from 1.00% to 1.75% per annum, and are determined based on a total-leverage-ratio pricing grid.

In addition, the Borrower is required to pay commitment fees based on the daily unused amount of the Credit Agreement in an amount equal to 0.375% per annum.

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.

The Credit Agreement contains various covenants with which the Partnership and its restricted subsidiaries must comply, including, but not limited to, limitations on the incurrence of indebtedness, investments, liens on assets, repurchasing equity and making distributions, transactions with affiliates, mergers, consolidations, dispositions of assets, and other provisions customary in similar types of agreements.

The Partnership also must maintain, on a consolidated basis, as of the last day of each fiscal quarter a Total Leverage Ratio (as defined in the Credit Agreement) of not greater than 5.25 to 1.00 (except that the Partnership may increase the applicable Total Leverage Ratio by 0.25 for any fiscal quarter during which a Specified Acquisition (as defined in the Credit Agreement) occurs and the following two fiscal quarters, but in no event shall the maximum Total Leverage Ratio exceed 5.50 to 1.00 for any fiscal quarter as a result of such increase);

an Interest Coverage Ratio (as defined in the Credit Agreement) of not less than 2.50 to 1.00;

and a Secured Leverage Ratio (as defined in the Credit Agreement) of not greater than 3.00 to 1.00 or less than 0.00 to 1.00.

The Credit Agreement also contains various customary representations and warranties, affirmative covenants, and events of default.

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;

• 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.

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issue equity in a public or private offering;

request a modification of our covenants from

our bank group;

request a modification of our covenants from our bank group;

reduce distributions from our current distribution rate or suspend distributions altogether;

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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”.

As of December 31, 2024, we had $750.0 million and $1.0 billion aggregate principal amount outstanding on our Senior Notes 2027 and Senior Notes 2029, respectively.

On March 5, 2024, we provided notice to the holders of our Senior Notes 2026 that, contingent on receipt of the proceeds from the Senior Notes 2029, the Senior Notes 2026 would be redeemed at par on April 4, 2024.

On March 18, 2024, utilizing a portion of the proceeds from the Senior Notes 2029, we deposited government securities with the trustee to satisfy and discharge the Senior Notes 2026 under the Indenture governing the notes.

This satisfaction and discharge constituted a legal defeasance, or the Defeasance, under GAAP as of March 18, 2024 of the full outstanding principal balance of $725.0 million.

The Senior Notes 2026 were redeemed in full at par on April 4, 2024.

The Senior Notes 2027 are due on September 1, 2027, and accrue interest at the rate of 6.875% per year.

Interest on the Senior Notes 2027 is payable semi-annually in arrears on each of March 1 and September 1.

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, which commenced on September 15, 2024.

Net proceeds from the Senior Notes 2029 were used for the Defeasance, with the remainder used to reduce outstanding borrowings under our Credit Agreement.

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

Derivative Instrument

During the year ended December 31, 2024, we elected to terminate the interest-rate swap we previously used to manage interest-rate risk associated with the floating-rate Credit Agreement, see Note 8 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for more information regarding the interest-rate swap.

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”.

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.

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We define EBITDA as net income (loss) before net interest expense, depreciation and amortization expense, and income tax expense (benefit).

We define Adjusted EBITDA as EBITDA plus impairment of assets, impairment of goodwill, interest income on capital leases, unit-based compensation expense (benefit), severance charges, certain transaction expenses, loss (gain) on disposition of assets, loss on extinguishment of debt, loss (gain) on derivative instrument, and other.

We 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.

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Transaction expenses (2) 1,914 133

Severance charges 2,430 841

Loss (gain) on disposition of assets 4,939 (1,667)

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

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Transaction expenses (1,914) (133)

Severance charges (2,430) (841)

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

Cash received on derivative instrument — 6,888

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________________________

(1) For the years ended December 31, 2024 and 2023, unit-based compensation expense included $3.9 million and $4.4 million, respectively, of cash payments related to quarterly payments of DERs on outstanding phantom unit awards and $0.2 million and $0.3 million, respectively, related to the cash portion of the settlement of phantom unit awards upon vesting.

(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.

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We believe it is useful to investors to exclude these expenses.

(3) This loss on extinguishment of debt is a result of the Defeasance of the Senior Notes 2026.

(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.

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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, 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 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.

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Depreciation and amortization 284,816 264,756

Non-cash income tax expense (benefit) 574 (52)

Non-cash income tax expense 466 574

Unit-based compensation expense (1) 4,342 16,552

Transaction expenses (2) 1,914 133

Severance charges 2,430 841

Loss (gain) on disposition of assets 4,939 (1,667)

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

Other 2,876 —

Loss on disposition of assets 3,820 4,939

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

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Transaction expenses (1,914) (133)

Severance charges (2,430) (841)

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

Distributions on Preferred Units 8,288 17,550

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________________________

The remainder of unit-based compensation expense for all periods was related to non-cash adjustments to the unit-based compensation liability.

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We believe it is useful to investors to exclude these expenses.

(3) This loss on extinguishment of debt is a result of the Defeasance of the Senior Notes 2026.

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.

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If our projections of cash flows associated with our units decline, we may have to record an impairment of assets in future periods.

For the years ended December 31, 2024 and 2023, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 2 and 42 compression units, respectively, representing approximately 1,260 and 37,700 of aggregate horsepower, respectively, that previously were used to provide compression services in our business.

As a result, we recorded impairments of compression equipment of $0.3 million and $12.3 million for the years ended December 31, 2024, and 2023, respectively.

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:

These compression units were written down to their estimated salvage values, if any.

Additionally, for the year ended December 31, 2024, we recognized a $0.6 million impairment of assets related to capitalized software costs that are no longer expected to provide benefit.

(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.

Estimated Useful Lives of Property and Equipment

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We expense legal costs as incurred, and all recorded legal liabilities are revised, as required, as better information becomes available to us.

We currently are protesting certain sales tax assessments made by the Oklahoma Tax Commission (“OTC”).

In August 2024, the administrative law judge (“ALJ”) assigned by the OTC accepted our position that the transactions are not taxable.

The OTC subsequently requested a motion for reconsideration, which was denied by the ALJ.

The OTC then requested an “en banc” hearing from the OTC Commissioners, which the OTC Commissioners denied and adopted the conclusions of the ALJ, thereby effectively closing the matter.

federal income tax returns for the years 2019 and 2020 currently are under examination by the IRS.

The IRS has issued preliminary partnership examination changes, along with imputed underpayment computations, for the 2019 and 2020 tax years.

Under the Bipartisan Budget Act of 2015, there are several procedural steps, including an appeals process, to complete before a final imputed underpayment, if any, is determined.

Based on discussions with the IRS, we estimate a potential range of loss from a final imputed underpayment of $0 to approximately $28.3 million, including interest, for potential adjustments resulting from the IRS examinations.

Once a final partnership imputed underpayment, if any, is determined, our General Partner may elect to either pay the imputed underpayment (including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised information statement to each unitholder, and former unitholder, with respect to an audited and adjusted return.

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

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis