USA Compression Partners, LP
For the period ended Dec 31, 2025. Filed Feb 17, 2026.
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A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Feb 17, 2026
USAC$24.97+3.0%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-02-11.
0001522727-25-000010
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-02-17.
0001522727-26-000015
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 144 previous paragraphs and 151 current paragraphs.
77 unchanged; 57 reworded; 16 added; 10 removed; 0 previous and 1 current paragraphs rearranged.
Tables are not compared: 8 previous and 8 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (16)
Current report
J-W Power Acquisition
Current report
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.
Current report
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.
Current report
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.
Current report
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”.
Current report
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.
Current report
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.
Current report
The Credit Agreement also contains various financial covenants, including covenants requiring us to maintain:
Current report
•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;
Current report
•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
Current report
•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.
Current report
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.
Current report
(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.
Current report
(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.
Current report
(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.
Current report
(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.
Removed paragraphs (10)
Previous report
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.
Previous report
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.
Previous report
Other Financial Data
Previous report
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.
Previous report
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).
Previous report
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.
Previous report
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.
Previous report
Derivative Instrument
Previous report
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.
Previous report
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.
Reworded paragraphs (57)
Previous wording
We have focused our compression services in unconventional resource plays throughout the U.S., including the Utica, Marcellus, Permian, Denver-Julesburg, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, and Haynesville. According to studies promulgated by the EIA, the production and transportation volumes in these unconventional plays, namely tight oil and gas shale plays, are expected to collectively increase over the long term. Furthermore, changes in production volumes and pressures of shale plays over time require a wider range of compression service levels than in conventional basins. We believe we are well-positioned to meet these changing operating conditions due to the operational design flexibility inherit within our compression-unit fleets.
Current wording
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.
Previous wording
We deliver natural gas compression services in connection with domestic natural gas production that primarily occurs in natural gas basins, such as the Marcellus, Utica, and Haynesville Shales, and in crude oil basins where “associated” natural gas is produced alongside crude oil, such as in the Permian and Denver-Julesburg Basins, Eagle Ford, and the Mid-Continent. Relative stability in commodity prices over much of the past decade encouraged investment in domestic exploration and production and midstream infrastructure across the energy industry, particularly in low-cost U.S. onshore shale basins that feature crude oil and associated gas production. The development of these basins has created additional incremental demand for natural gas compression as it is a critical method to transport associated gas volumes or enhance crude oil production through gas lift.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
Looking ahead, global consumption of petroleum and liquids fuels according to the EIA’s January 2025 Short Term Energy Outlook (“EIA Outlook”) increased in 2024 and is expected to increase over 1.3 million barrels per day (“bpd”) in 2025 and 1.1 million bpd in 2026. The EIA Outlook estimates that annual U.S. crude oil production set a record of 13.2 million bpd in 2024, due to production growth in the Permian. In 2025 and 2026, the EIA Outlook expects U.S. crude oil production growth to continue, albeit at a lower crude oil price, estimating average production of 13.5 million bpd for 2025 and 13.6 million bpd in 2026, which would represent new records for annual average crude oil production. The U.S. crude oil production growth in 2025 and 2026 is expected to come almost entirely from the Permian, which is expected to account for over half of U.S. crude oil production by 2026. We expect that anticipated crude oil production increases likewise will increase associated natural gas production volumes throughout 2025, thereby increasing demand for our compression services.
Current wording
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 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.
Previous wording
Unlike crude oil, natural gas production and prices have been influenced by different factors, including the nonexistence of an OPEC+ equivalent for the global natural gas market, which makes natural gas price discovery dependent on market supply and demand dynamics rather than by a centralized market coordinator. Over the past several years, increased natural gas production in the U.S., driven by large volumes of associated gas produced from shale sources, has been a major driver of an overall decline in natural gas prices. The EIA Outlook expects dry natural gas production to increase by 1.4 billion cubic feet per day (“bcf/d”) in 2025 and by 2.7 bcf/d in 2026, resulting in record dry natural gas production each year.
Current wording
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.
Previous wording
Significant demand for natural gas is driven by domestic power generation which has benefited from a lower-price environment. These low prices, combined with a general shift away from coal-fired power plants due to emissions concerns, has resulted in power generation becoming, and remaining, the largest use of natural gas in the U.S., and has created a relatively resilient baseload demand for natural gas. Growth in power demands from the development of artificial intelligence is also expected to increase demand. Finally, the demand for domestic natural gas also continues to benefit from the construction of LNG export infrastructure, which enables industry participants to benefit from attractive global natural gas prices. According to the EIA Outlook, the U.S. witnessed record LNG exports of 12.0 bcf/d during 2024 and expects LNG exports to set new records of 14.1 bcf/d and 16.2 bcf/d in 2025 and 2026, respectively, as new LNG export capacity continues to ramp up creating incremental baseload global demand.
Current wording
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.
Previous wording
Overall, the EIA Outlook expects U.S. natural gas demand to outpace production and to increase by 3.2 bcf/d in 2025, primarily reflecting increased exports, both by LNG and pipeline, and stable baseload demand. Further, the EIA Outlook expects U.S natural gas demand to increase another 2.6 bcf/d in 2026, again driven primarily by LNG and pipeline exports, and stable baseload. Natural gas prices averaged $2.20 per million British thermal units (“MMBtu”) in 2024 and the EIA Outlook expects natural gas prices to increase on average to $3.10/MMBtu and $4.00/MMBtu in 2025 and 2026, respectively, driven by the expectation that domestic natural gas inventories remain at or below previous five-year averages. We expect the baseload natural gas demand and increase in LNG and pipeline exports described above, along with growth in data center demand tied to the development of artificial intelligence which we believe is not fully considered in the EIA Outlook’s numbers, to continue to support long-term domestic natural gas production.
Current wording
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.
Previous wording
The longer-term outlook for commodity prices remains constructive and we are increasing our new, large-horsepower compression unit order in 2025 to meet our customer needs. We expect total capital to be between $158.0 million and $182.0 million in 2025 and are beginning to evaluate new, large-horsepower compression unit orders for 2026. As we look forward over the next year, active geopolitical situations like those in the Middle East and Ukraine, global trade policies, inflationary pressures and slowing global GDP growth, might temper our longer-term outlook.
Current wording
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.
Previous wording
(1)Fleet horsepower is horsepower for compression units that have been delivered to us and excludes 20,310 and 21,690 of non-marketable horsepower as of December 31, 2024, and 2023, respectively. As of December 31, 2024, we had no horsepower on order. Subsequent to December 31, 2024, the Partnership ordered 10,000 large horsepower for expected delivery during 2025.
Current wording
(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.
Previous wording
(7)Horsepower utilization is calculated as (i) the sum of (a) revenue-generating horsepower, (b) horsepower in our fleet that is under contract, but is not yet generating revenue, and (c) horsepower not yet in our fleet that is under contract but not yet generating revenue and that is expected to be delivered, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue-generating horsepower and fleet horsepower was 92.4% and 90.9% as of December 31, 2024, and 2023, respectively.
Current wording
(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.
Previous wording
(8)Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period. Average horsepower utilization based on revenue-generating horsepower and fleet horsepower was 91.7% and 89.2% for the years ended December 31, 2024, and 2023, respectively.
Current wording
(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.
Previous wording
The 2.3% increase in fleet horsepower as of December 31, 2024, compared to December 31, 2023, primarily was driven by new compression units added to our fleet to meet incremental demand from customers for our compression services.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
The 8.3% increase in average revenue per revenue-generating horsepower per month for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
Parts and service revenue. The $2.0 million increase in parts and service revenue for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to an increase in maintenance work performed on units at customer locations that are outside the scope of our core maintenance activities and that are offered as a convenience, and in directly reimbursable freight and crane charges that are the financial responsibility of the customers. Demand for retail parts and services fluctuates from period to period based on varying customer needs.
Current wording
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.
Previous wording
Related-party revenue. Related-party revenue was earned through related-party transactions that occur in the ordinary course of business with various affiliated entities of Energy Transfer. The $19.6 million increase in related-party revenue for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to revenue recognized from existing customers acquired by Energy Transfer since the previous period that are now classified as related-party revenue in the current period.
Current wording
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 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.
Previous wording
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.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
Impairment of assets. The $0.9 million and $12.3 million impairments of assets during the years ended December 31, 2024 and 2023, respectively, primarily resulted from our evaluation of the future deployment of our idle fleet assets under then-current market conditions. The primary circumstances supporting these impairments were: (i) unmarketability of certain compression units into the foreseeable future, (ii) excessive maintenance costs associated with certain fleet assets, and (iii) prohibitive retrofitting costs that likely would prevent certain compression units from securing customer acceptance. These compression units were written down to their estimated salvage values, if any.
Current wording
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.
Previous wording
As a result of our evaluations during the years ended December 31, 2024 and 2023, we retired 2 and 42 compression units, respectively, with approximately 1,260 and 37,700 aggregate horsepower, respectively, that previously were used to provide compression services in our business.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
Loss on extinguishment of debt. The$5.0 million loss on extinguishment of debtfor 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”.
Current wording
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”.
Previous wording
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.
Current wording
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.
Previous wording
Gross margin. The $57.6 million increase in gross margin for the year ended December 31, 2024, compared to the year ended December 31, 2023, was due to (i) a $104.3 million increase in revenues, offset by (ii) a $28.0 million increase in cost of operations, exclusive of depreciation and amortization, and (iii) an $18.7 million increase in depreciation and amortization.
Current wording
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.
Previous wording
Adjusted gross margin. The $76.3 million increase in Adjusted gross margin for the year ended December 31, 2024, compared to the year ended December 31, 2023, was due to a $104.3 million increase in revenues, offset by a $28.0 million increase in cost of operations, exclusive of depreciation and amortization.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
DCF. The $74.2 million increase in DCF for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $76.3 million increase in Adjusted gross margin, (ii) a $30.2 million decrease in distributions on Preferred Units following the conversion of 320,000 Preferred Units into 15,990,804 common units, and (iii) a $0.6 million increase in cash received on derivative instrument, partially offset by (iv) a $22.1 million increase in cash interest expense, net, (v) a $6.7 million increase in maintenance capital expenditures, and (vi) a $4.2 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
We classify capital expenditures as maintenance or expansion on an individual-asset basis. Over the long term, we expect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleet increases. Our aggregate maintenance capital expenditures for the years ended December 31, 2024 and 2023, were $31.9 million and $25.2 million, respectively. We currently have budgeted between $38.0 million and $42.0 million in maintenance capital expenditures during 2025, including parts consumed from inventory.
Current wording
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.
Previous wording
Without giving effect to any equipment that we may acquire pursuant to any future acquisitions, we currently have budgeted between $120.0 million and $140.0 million in expansion capital expenditures for 2025. Our expansion capital expenditures for the years ended December 31, 2024 and 2023, were $243.5 million and $275.4 million, respectively.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
As of December 31, 2024, other commitments include operating and finance lease payments totaling $19.3 million, of which we expect to make payments of $5.2 million to be settled in the next twelve months. For a more detailed description of our lease obligations, please refer to Note 7 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
As of December 31, 2024, we had outstanding borrowings under the Credit Agreement of $772.1 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $827.1 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $782.5 million was available to be drawn. As of December 31, 2024, we were in compliance with all of our covenants under the Credit Agreement.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
The Credit Agreement matures on December 8, 2026.
Current wording
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.
Previous wording
Borrowings under the Credit Agreement bear interest at a per-annum interest rate equal to, at the Partnership’s option, either the Alternate Base Rate or SOFR plus the applicable margin. “Alternate Base Rate” means the greatest of (i) the prime rate, (ii) the applicable federal funds effective rate plus 0.50%, and (iii) one-month SOFR rate plus 1.00%. The applicable margin for borrowings varies (a) in the case of SOFR loans, from 2.00% to 2.75% per annum, and (b) in the case of Alternate Base Rate loans, from 1.00% to 1.75% per annum, and are determined based on a total-leverage-ratio pricing grid. In addition, the Borrower is required to pay commitment fees based on the daily unused amount of the Credit Agreement in an amount equal to 0.375% per annum. Amounts borrowed and repaid under the Credit Agreement may be re-borrowed, subject to borrowing base availability.
Current wording
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.
Showing the first 40 of 57 pairs. Open the source sections for the rest.
Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
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.