Item 7. Management’s Discussion and Analysis
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements, the notes thereto, and the other financial information appearing elsewhere in this report. The following discussion includes forward-looking statements that involve certain risks and uncertainties. See Part I “Disclosure Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors”.
Discussion and analysis of our operating highlights and financial results of operations for the year ended December 31, 2024, compared to the year ended December 31, 2023, is included under the headings in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Highlights, Financial Results of Operations, Liquidity and Capital Resources, and Critical Accounting Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 11, 2025.
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Overview
We have focused our compression services in unconventional resource plays throughout the U.S., including the Utica, Marcellus, Permian, Denver-Julesburg, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, and Haynesville, and following the J-W Power Acquisition, the Bakken. According to studies promulgated by the EIA, the production and transportation volumes in these unconventional plays, namely tight oil and gas shale plays, are expected to collectively increase over the long term. Furthermore, changes in production volumes and pressures of shale plays over time require a wider range of compression service levels than in conventional basins. We believe we are well-positioned to meet these changing operating conditions due to the operational design flexibility inherit within our compression-unit fleets.
Our business includes compression services serving infrastructure applications, including centralized natural gas gathering systems and processing facilities, which utilize large-horsepower compression units and also gas lift applications on crude oil wells targeted by horizontal drilling techniques. Gas lift is a process by which natural gas is injected into the production tubing of an existing producing well to reduce hydrostatic pressure and allow the oil to flow at a higher rate. This process, and other artificial-lift technologies are critical to the enhancement of oil production from horizontal wells operating in tight shale plays.
J-W Power Acquisition
On January 12, 2026, the Partnership and USA Compression Partners, LLC, a wholly owned subsidiary of the Partnership, completed the J-W Power Acquisition, pursuant to which USA Compression Partners, LLC purchased all of the issued and outstanding capital stock of J-W Energy from Westerman, Ltd. for aggregate consideration of approximately $860.0 million, subject to customary purchase price adjustments, consisting of (i) 18,175,323 common units and (ii) approximately $430.0 million in cash. Upon consummation of the J-W Power Acquisition, J-W Power and J-W Energy became wholly owned subsidiaries of the Partnership.
The J-W Power Acquisition added approximately 0.8 million active horsepower and 1.0 million total horsepower to our fleet across key regions including the Northeast, Mid-Con, Rockies, Gulf Coast, Bakken and Permian Basin. J‑W Power also owns and operates specialized manufacturing facilities that support its internal compression requirements and those of third‑party customers.
General Trends and Outlook
A significant portion of our assets are utilized in natural gas infrastructure applications typically located in U.S. onshore shale plays, primarily at centralized gathering systems and processing facilities utilizing large-horsepower compression units. Given the infrastructure nature of these applications, the continued need for additional natural gas compression throughout the production cycle, and the long-term investment horizon of our customers, we generally have experienced stability in service rates and higher sustained fleet utilization rates relative to other businesses more directly tied to drilling activity and wellhead-specific economics. In addition to our natural gas infrastructure applications, a portion of our small- and large-horsepower fleet is used in connection with gas-lift applications for crude oil production targeted by horizontal drilling techniques.
We deliver natural gas compression services in connection with domestic natural gas production that primarily occurs in natural gas basins, such as the Marcellus, Utica, and Haynesville Shales, and in crude oil basins where “associated” natural gas is produced alongside crude oil, such as in the Permian and Denver-Julesburg Basins, Eagle Ford, Bakken and the Mid-Continent. Relative stability in commodity prices over much of the past decade encouraged investment in domestic exploration and production and midstream infrastructure across the energy industry, particularly in low-cost U.S. onshore shale basins that feature crude oil and associated gas production. The development of these basins has created additional incremental demand for natural gas compression as it is a critical method to transport associated gas volumes or enhance crude oil production through gas lift.
Although our business is focused on providing compression services that do not bear direct exposure to commodity prices, our business exhibits indirect exposure to commodity prices as overall levels of drilling activity and production are influenced by prevailing commodity prices. With average natural gas prices up year-over-year and average oil prices down, we experienced improvements to pricing and maintained fleet utilization for our compression services in 2025, largely tied to associated gas growth from oil plays.
Looking ahead, global consumption of petroleum and liquids fuels according to the EIA’s January 2026 Short Term Energy Outlook (“EIA Outlook”) increased in 2025 and is expected to increase over 1.1 million barrels per day (“bpd”) in 2026 and 0.3 million bpd in 2027. The EIA Outlook estimates that annual U.S. crude oil production set a record of 13.6 million bpd in 2025, due to production growth in the Permian. In 2026 and 2027, the EIA Outlook expects U.S. crude oil production to stay flat in 2026 and decline by 2% in 2027 tied to a slowdown in drilling activity linked to WTI prices forecasted in the low $50 mark. The U.S. crude oil production growth in 2025 came almost entirely from the Permian, which grew by 4% despite
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flattening over the last two quarters of the year. In contrast, associated, wet natural gas growth from the Permian grew by over 10% and sequentially each quarter, owing to increased gas-to-oil ratios. We expect that anticipated flat crude oil production will continue to yield an increase in associated natural gas production volumes throughout 2026, thereby increasing demand for our compression services.
Unlike crude oil, natural gas production and prices have been influenced by different factors, including the nonexistence of an OPEC+ equivalent for the global natural gas market, which makes natural gas price discovery dependent on market supply and demand dynamics rather than by a centralized market coordinator. Over the past several years, increased natural gas production in the U.S., driven by large volumes of associated gas produced from shale sources, has been a major driver in natural gas prices. The EIA Outlook expects dry natural gas production to increase by 1.4 billion cubic feet per day (“bcf/d”) in 2026 and by 0.9 bcf/d in 2027, resulting in record dry natural gas production each year.
Significant demand for natural gas is driven by domestic power generation which has benefited from a lower-price environment. These low prices, combined with a general shift away from coal-fired power plants due to emissions concerns, has resulted in power generation becoming, and remaining, the largest use of natural gas in the U.S., and has created a relatively resilient baseload demand for natural gas. Growth in power demands from the development of artificial intelligence is also expected to increase demand. Finally, the demand for domestic natural gas also continues to benefit from the construction of LNG export infrastructure, which enables industry participants to benefit from attractive global natural gas prices. According to the EIA Outlook, the U.S. witnessed record LNG exports of 15.0 bcf/d during 2025 and expects LNG exports to set new records of 16.4 bcf/d and 18.1 bcf/d in 2026 and 2027, respectively, as new LNG export capacity continues to ramp up creating incremental baseload global demand.
Overall, the EIA Outlook expects the increase in U.S. natural gas demand to trail production by 0.9 bcf/d in 2026, primarily reflecting the aforementioned increase in dry natural gas production compared to the expected demand from increased exports, both by LNG and pipeline, and stable baseload demand. Looking further ahead, the EIA Outlook expects U.S natural gas net demand to increase by 0.5 bcf/d in 2027, again driven primarily by LNG and pipeline exports, and stable baseload with slower rate of growth in natural gas. Natural gas prices averaged $3.53 per million British thermal units (“MMBtu”) in 2025 and the EIA Outlook expects natural gas prices to average $3.46/MMBtu and $4.59/MMBtu in 2026 and 2027, respectively, driven by the expectation that domestic natural gas inventories remain at or below previous five-year averages. We expect the baseload natural gas demand and increase in LNG and pipeline exports described above, along with growth in data center demand tied to the development of artificial intelligence which we believe is not fully considered in the EIA Outlook’s numbers, to continue to support long-term domestic natural gas production.
The longer-term outlook for commodity prices remains constructive and we are increasing our new, large-horsepower compression unit order in 2026 to meet our customer needs. We expect total capital to be between $290.0 million and $320.0 million in 2026 and are beginning to evaluate new, large-horsepower compression unit orders for 2027. As we look forward over the next year, active geopolitical situations like those in the Middle East and Ukraine, global trade policies, inflationary pressures and slowing global GDP growth, might temper our longer-term outlook.
Ultimately, the extent to which our business will be impacted by the factors described above, as well as future developments beyond our control, cannot be predicted with reasonable certainty. However, we continue to believe that overall, the long-term demand for our compression services will continue given the necessity of compression in facilitating the transportation and processing of natural gas as well as the production of crude oil.
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Operating Highlights
The following table summarizes certain horsepower and horsepower-utilization percentages for the periods presented and excludes certain gas-treating assets for which horsepower is not a relevant metric.
Year Ended December 31, Increase
2025 2024 (Decrease)
Fleet horsepower (at period end) (1) 3,894,332 3,862,102 0.8 %
Total available horsepower (at period end) (2) 3,901,932 3,862,942 1.0 %
Revenue-generating horsepower (at period end) (3) 3,585,452 3,567,842 0.5 %
Average revenue-generating horsepower (4) 3,559,300 3,528,172 0.9 %
Average revenue per revenue-generating horsepower per month (5) $ 21.38 $ 20.43 4.7 %
Revenue-generating compression units (at period end) 4,256 4,269 (0.3 %)
Average horsepower per revenue-generating compression unit (6) 847 829 2.2 %
Horsepower utilization (7):
At period end 94.7 % 94.6 % 0.1 %
Average for the period (8) 94.3 % 94.6 % (0.3 %)
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(1) Fleet horsepower is horsepower for compression units that have been delivered to us and excludes 14,985 and 20,310 of non-marketable horsepower as of December 31, 2025, and 2024, respectively. As of December 31, 2025, we had 63,250 horsepower on order. Additionally, as a result of the J-W Power Acquisition in January 2026, we added approximately 0.8 million in active horsepower and 1.0 million total horsepower.
(2) Total available horsepower is revenue-generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract but not yet generating revenue and that is expected to be delivered, and idle horsepower. Total available horsepower excludes new horsepower expected to be delivered for which we do not have an executed compression services contract.
(3) Revenue-generating horsepower is horsepower under contract for which we are billing a customer.
(4) Calculated as the average of the month-end revenue-generating horsepower for each of the months in the period.
(5) Calculated as the average of the result of dividing the contractual monthly rate, excluding standby or other temporary rates, for all units at the end of each month in the period by the sum of the revenue-generating horsepower at the end of each month in the period.
(6) Calculated as the average of the month-end revenue-generating horsepower per revenue-generating compression unit for each of the months in the period.
(7) Horsepower utilization is calculated as (i) the sum of (a) revenue-generating horsepower, (b) horsepower in our fleet that is under contract, but is not yet generating revenue, and (c) horsepower not yet in our fleet that is under contract but not yet generating revenue and that is expected to be delivered, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue-generating horsepower and fleet horsepower was 92.1% and 92.4% as of December 31, 2025, and 2024, respectively.
(8) Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period. Average horsepower utilization based on revenue-generating horsepower and fleet horsepower was 92.0% and 91.7% for the years ended December 31, 2025, and 2024, respectively.
The 0.8% increase in fleet horsepower as of December 31, 2025, compared to December 31, 2024, primarily was driven by new compression units added to our fleet to meet incremental demand from customers for our compression services.
The increases in revenue-generating horsepower, average horsepower per revenue-generating compression unit, and average horsepower utilization based on revenue-generating horsepower and fleet horsepower as of and for the year ended December 31, 2025, compared to December 31, 2024, primarily were driven by the addition and deployment of new, and redeployment of existing, large-horsepower compression units due to increased demand for our services consistent with an overall increase in crude oil and natural gas produced within the U.S.
The 4.7% increase in average revenue per revenue-generating horsepower per month for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit.
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Financial Results of Operations
Year ended December 31, 2025, compared to the year ended December 31, 2024
The following table summarizes our results of operations for the periods presented (dollars in thousands):
Year Ended December 31, Increase
2025 2024 (Decrease)
Revenues:
Contract operations $ 911,955 $ 885,250 3.0 %
Parts and service 21,136 23,897 (11.6) %
Related party 65,008 41,302 57.4 %
Total revenues 998,099 950,449 5.0 %
Costs and expenses:
Cost of operations, exclusive of depreciation and amortization 328,804 312,726 5.1 %
Depreciation and amortization 284,816 264,756 7.6 %
Selling, general, and administrative 66,343 72,666 (8.7) %
Loss on disposition of assets 3,820 4,939 *
Impairment of assets 7,811 913 *
Total costs and expenses 691,594 656,000 5.4 %
Operating income 306,505 294,449 4.1 %
Other income (expense):
Interest expense, net (187,408) (193,471) (3.1) %
Loss on extinguishment of debt (3,006) (4,966) *
Gain on derivative instrument — 5,684 *
Other 97 110 (11.8) %
Total other expense (190,317) (192,643) (1.2) %
Income before income tax expense 116,188 101,806 14.1 %
Income tax expense 4,869 2,231 118.2 %
Net income $ 111,319 $ 99,575 11.8 %
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* Not meaningful.
Contract operations revenue . The $26.7 million increase in contract operations revenue for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) a 4.7% increase in average revenue per revenue-generating horsepower per month, as a result of higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit, (ii) a 0.9% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with an overall increase in crude oil and natural gas produced within the U.S., partially offset by (iii) a $7.8 million decrease in revenue attributable to natural gas treating services activity.
Average revenue per revenue-generating horsepower per month associated with our compression services provided on a month-to-month basis did not differ significantly from the average revenue per revenue-generating horsepower per month associated with our compression services provided under contracts in their primary term during the period.
Parts and service revenue . The $2.8 million decrease in parts and service revenue for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to a decrease in maintenance work performed on units outside the scope of our core maintenance activities, and in directly reimbursable freight and crane charges that are the financial responsibility of the customers. Demand for retail parts and services fluctuates from period to period based on varying customer needs.
Related-party revenue. Related-party revenue was earned through related-party transactions that occur in the ordinary course of business with various affiliated entities of Energy Transfer. The $23.7 million increase in related-party revenue for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to revenue recognized from
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existing customers acquired by Energy Transfer that are classified as related-party revenue for a full year, as opposed to a partial year in the previous period.
Cost of operations, exclusive of depreciation and amortization. The $16.1 million increase in cost of operations for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) a $12.3 million increase in direct labor costs due to increased headcount associated with increased revenue-generating horsepower and higher employee costs, (ii) a $7.9 million increase in direct expenses, primarily driven by increased spending on parts resulting from higher costs and increased usage associated with increased revenue-generating horsepower, (iii) a $1.4 million increase in other indirect expenses due to increased usage associated with increased revenue-generating horsepower, and (iv) a $2.0 million increase in retail parts and service expenses, partially offset by (v) a $5.8 million decrease in fluids expense driven by decreased pricing, (vi) a $1.1 million decrease in vehicle expense due to lower maintenance and repair during the current period, and (vii) a $0.4 million decrease in non-income taxes.
Depreciation and amortization expense . The $20.1 million increase in depreciation and amortization expense for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to overhauls and major improvements to compression units.
Selling, general, and administrative expense . The $6.3 million decrease in selling, general, and administrative expense for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) an $11.5 million decrease in unit-based compensation expense attributable to lower unit-based compensation expense resulting from the forfeiture and vesting of certain awards by certain former senior management and mark-to-market changes to our unit-based compensation liability that occurred as a result of changes to our per-unit trading price as of December 31, 2025, (ii) a $0.6 million decrease in provision for expected credit losses, (iii) a $0.5 million decrease in employee-related expenses due to decreased administrative headcount and lower employee costs, and (iv) a $0.4 million decrease to professional fees primarily related to an initiative to improve business performance, partially offset by (v) a $2.4 million increase in severance charges and other employee costs primarily related to the departure of certain senior management as well as retention and relocation payments related to the shared services integration during the current year, (vi) a $2.2 million increase in insurance and other administrative expenses, and (vii) a $1.9 million increase in transaction expenses related to the J-W Power Acquisition.
Impairment of assets . The $7.8 million and $0.9 million impairments of assets during the years ended December 31, 2025 and 2024, respectively, primarily resulted from our evaluation of the future deployment of our idle fleet assets under then-current market conditions. The primary circumstances supporting these impairments were: (i) unmarketability of certain compression units into the foreseeable future, (ii) excessive maintenance costs associated with certain fleet assets, and (iii) prohibitive retrofitting costs that likely would prevent certain compression units from securing customer acceptance. These compression and treating units were written down to their estimated salvage values, if any.
As a result of our evaluations during the years ended December 31, 2025 and 2024, we retired 28 and 2 compression units, respectively, with approximately 19,005 and 1,260 aggregate horsepower, respectively, that previously were used to provide compression services in our business.
Interest expense, net . The $6.1 million decrease in interest expense, net for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to lower aggregate weighted-average interest rates under the Credit Agreement and refinanced senior notes.
Loss on extinguishment of debt. The $3.0 million loss on extinguishment of debt for the year ended December 31, 2025 resulted from the redemption of our Senior Notes 2027.
The $5.0 million loss on extinguishment of debt for the year ended December 31, 2024 resulted from the satisfaction and discharge of the Senior Notes 2026, which constituted a legal defeasance under GAAP (the “Defeasance”). This loss consists of the write-off of deferred financing costs of $4.3 million and the difference between (i) the purchase price of U.S. government securities of $748.8 million, which were used for the Defeasance and (ii) the aggregate outstanding principal balance and accrued interest of the Senior Notes 2026 of $748.1 million at the time of Defeasance. For additional information regarding the Defeasance of the Senior Notes 2026, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
Gain on derivative instrument. The $5.7 million gain on derivative instrument for the year ended December 31, 2024 resulted from the change in fair value of an interest-rate swap due to changes in the interest-rate forward curve and cash received during the period. This interest-rate swap was terminated in August 2024; see Note 8 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information.
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Income tax expense. The $2.6 million increase in income tax expense for the year ended December 31, 2025, compared to the year ended December 31, 2024, is primarily related to a charge of $2.9 million related to an IRS audit of our 2019 and 2020 tax returns. We believe that this amount is a reasonable estimate of the potential loss from the aggregate final imputed underpayment for the years 2019 and 2020 with the IRS. For additional information regarding our IRS audit for the years 2019 and 2020, see Note 17 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
The following table summarizes other financial data for the periods presented (dollars in thousands):
Year Ended December 31, Increase
Other Financial Data: (1) 2025 2024 (Decrease)
Gross margin $ 384,479 $ 372,967 3.1 %
Adjusted gross margin $ 669,295 $ 637,723 5.0 %
Adjusted gross margin percentage (2) 67.1 % 67.1 % — %
Adjusted EBITDA $ 613,760 $ 584,282 5.0 %
Adjusted EBITDA percentage (2) 61.5 % 61.5 % — %
DCF $ 385,677 $ 355,317 8.5 %
DCF Coverage Ratio 1.45 x 1.44 x 0.7 %
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(1) Adjusted gross margin, Adjusted EBITDA, Distributable Cash Flow (“DCF”), and DCF Coverage Ratio are all non-GAAP financial measures. Definitions of each measure, as well as reconciliations of each measure to its most directly comparable financial measure(s) calculated and presented in accordance with GAAP, can be found below under the caption “Non-GAAP Financial Measures”.
(2) Adjusted gross margin percentage and Adjusted EBITDA percentage are calculated as a percentage of revenue.
Gross margin. The $11.5 million increase in gross margin for the year ended December 31, 2025, compared to the year ended December 31, 2024, was due to (i) a $47.7 million increase in revenues, offset by (ii) a $16.1 million increase in cost of operations, exclusive of depreciation and amortization and (iii) an $20.1 million increase in depreciation and amortization.
Adjusted gross margin. The $31.6 million increase in Adjusted gross margin for the year ended December 31, 2025, compared to the year ended December 31, 2024, was due to a $47.7 million increase in revenues, offset by a $16.1 million increase in cost of operations, exclusive of depreciation and amortization.
Adjusted EBITDA. The $29.5 million increase in Adjusted EBITDA for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to a $31.6 million increase in Adjusted gross margin, partially offset by a $1.1 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, transaction expenses, and severance charges and other employee costs.
DCF. The $30.4 million increase in DCF for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) a $31.6 million increase in Adjusted gross margin, (ii) a $9.3 million decrease in distributions on Preferred Units following the conversion of 180,000 Preferred Units into 8,994,826 common units, and (iii) a $5.9 million decrease in cash interest expense, net, partially offset by (iv) a $7.5 million increase in maintenance capital expenditures, (v) a $6.9 million decrease in cash received on derivative instrument, and (vi) $1.1 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, transaction expenses, severance charges and other employee costs.
For additional information regarding the conversion of the Preferred Units, see Note 11 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
DCF Coverage Ratio . The slight increase in DCF Coverage Ratio for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to the increase in DCF, offset by an increase in distributions from an increase in the number of common units, largely attributable to the conversion of 180,000 Preferred Units into 8,994,826 common units during 2025 and the issuance of 18,175,323 common units in January 2026 related to the J-W Acquisition.
Liquidity and Capital Resources
Overview
We operate in a capital-intensive industry, and our primary liquidity needs include financing the purchase of additional compression units, making other capital expenditures, servicing our debt, funding working capital, and paying cash
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distributions on our outstanding preferred and common equity. Our principal sources of liquidity include cash generated by operating activities, borrowings under the Credit Agreement, and issuances of debt and equity securities, including common units under the DRIP.
We believe cash generated by operating activities and, where necessary, borrowings under the Credit Agreement will be sufficient to service our debt, fund working capital, fund our estimated expansion capital expenditures, fund our maintenance capital expenditures, and pay distributions to our unitholders through 2026.
Because we distribute all of our available cash, which excludes prudent operating reserves, we expect to fund any future expansion capital expenditures or acquisitions primarily with capital from external financing sources, such as borrowings under the Credit Agreement and issuances of debt and equity securities, including under the DRIP.
We are not aware of any regulatory changes or environmental liabilities that we currently expect to have a material impact on our current or future operations. Please see “Capital Expenditures” below.
Capital Expenditures
The compression services business is capital intensive, requiring significant investment to maintain, expand, and upgrade existing operations. Our capital requirements primarily have consisted of, and we anticipate that our capital requirements will continue primarily to consist of, the following:
• maintenance capital expenditures, which are capital expenditures made to maintain the operating capacity of our assets and extend their useful lives, to replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining our existing business and related operating income; and
• expansion capital expenditures, which are capital expenditures made to expand the operating capacity or operating-income capacity of assets, including by acquisition of compression units or through modification of existing compression units to increase their capacity, or to replace certain partially or fully depreciated assets that at the time of replacement were not generating operating income.
We classify capital expenditures as maintenance or expansion on an individual-asset basis. Over the long term, we expect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleet increases. Our aggregate maintenance capital expenditures for the years ended December 31, 2025 and 2024, were $39.4 million and $31.9 million, respectively. We currently have budgeted between $60.0 million and $70.0 million in maintenance capital expenditures during 2026, including parts consumed from inventory. This includes a budgeted increase in maintenance capital expenditures as a result of the J-W Power Acquisition.
Without giving effect to any equipment that we may acquire pursuant to any future acquisitions, we currently have budgeted between $230.0 million and $250.0 million in expansion capital expenditures for 2026. This includes a budgeted increase in expansion capital expenditures as a result of the J-W Power Acquisition. Our expansion capital expenditures for the years ended December 31, 2025 and 2024, were $117.6 million and $243.5 million, respectively.
As of December 31, 2025, we had binding commitments to purchase $78.4 million of additional compression units, all of which is expected to be delivered within the next twelve months. We have not ordered any compression units subsequent to December 31, 2025.
Other Commitments
As of December 31, 2025, other commitments include operating and finance lease payments totaling $18.4 million, of which we expect to make payments of $5.6 million to be settled in the next twelve months. For a more detailed description of our lease obligations, please refer to Note 7 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. Additionally, as of December 31, 2025, we had entered into a definitive agreement with respect to the J-W Power Acquisition, which closed on January 12, 2026. See “See Part I, Item 1 “Recent Developments” for additional information regarding the J-W Power Acquisition.
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Cash Flows
The following table summarizes our sources and uses of cash for the years ended December 31, 2025 and 2024, (in thousands):
Year Ended December 31,
2025 2024
Net cash provided by operating activities $ 394,262 $ 341,334
Net cash used in investing activities (114,957) (202,014)
Net cash used in financing activities (270,755) (139,317)
Net cash provided by operating activities . The $52.9 million increase in net cash provided by operating activities for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) a $60.8 million decrease in inventory purchases and (ii) a $21.3 million increase in net income excluding non-cash charges, partially offset by (iii) a $27.0 million increase in interest payments due to the timing of payments related to our refinance of our Senior Notes 2026 and (iv) a $2.1 million increase in other working capital.
Net cash used in investing activities . The $87.1 million decrease in net cash used in investing activities for the year ended December 31, 2025, compared to the year ended December 31, 2024, was due to (i) an $87.6 million decrease in capital expenditures, for purchases of new compression units, overhauls and major improvements, and purchases of other equipment, and (ii) a $0.9 million increase in proceeds from disposition of property and equipment, partially offset by (iii) a $1.4 million decrease in proceeds from insurance recovery.
Net cash used in financing activities . The $131.4 million increase in net cash used in financing activities for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily was due to (i) an increase of $750 million in payments on senior notes, (ii) a $250 million decrease in proceeds from issuance of senior notes, (iii) a $13.4 million increase in common unit distributions, and (iv) a $3.2 million increase in payments related to net settlement of unit-based awards, partially offset by (v) a $748.8 million decrease in investments in government securities purchased in connection with the Defeasance of the Senior Notes 2026, (vi) a $122.7 million increase in net borrowings under the Credit Agreement, and (vii) $11.7 million decrease in Preferred Unit distributions.
Revolving Credit Facility
As of December 31, 2025, we had outstanding borrowings under the Credit Agreement of $795.0 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $954.2 million of remaining unused availability all of which was available to be drawn, inclusive of restrictions related to compliance with applicable financial covenants. As of December 31, 2025, we were in compliance with all of our covenants under the Credit Agreement.
As of February 12, 2026, we had outstanding borrowings under the Credit Agreement of $1.3 billion and outstanding letters of credit of $2.0 million, which includes borrowings used to pay the cash consideration of the J-W Power Acquisition.
On August 27, 2025, the Partnership amended and restated its existing credit agreement by entering into the Credit Agreement. The Credit Agreement matures on August 27, 2030, except that if more than $50.0 million of the Senior Notes 2029 are outstanding on December 14, 2028, the Credit Agreement will mature on December 14, 2028.
The Credit Agreement provides for an asset-based revolving credit facility to be made available for the Partnership in an aggregate amount of up to $1.75 billion (subject to availability under our borrowing base), with a further potential increase of up to an additional $300 million.
Borrowings under the Credit Agreement bear interest at a per-annum interest rate equal to, at the Partnership’s option, either the Alternate Base Rate, one-month SOFR (which shall only be available for swingline loans made under the Credit Agreement), Daily Simple SOFR, or SOFR plus, in each case, the applicable margin. “Alternate Base Rate” means the greatest of (i) the prime rate, (ii) the federal funds effective rate plus 0.50%, and (iii) one-month SOFR rate plus 1.00%. The applicable margin for borrowings varies (a) in the case of Daily Simple SOFR and SOFR loans, from 1.75% to 2.50% per annum, and (b) in the case of Alternate Base Rate loans and one-month SOFR loans, from 0.75% to 1.50% per annum, and will be determined based on a total leverage ratio pricing grid. In addition, the Partnership is required to pay commitment fees based on the daily unused amount under the facility in an amount per annum equal to 0.25%. Amounts borrowed and repaid under the Credit Agreement may be re-borrowed, subject to borrowing base availability.
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The Credit Agreement also contains various financial covenants, including covenants requiring us to maintain:
• a minimum EBITDA to interest coverage ratio of 2.50 to 1.00, determined as of the last day of each fiscal quarter, with EBITDA and interest expense annualized for the most-recent fiscal quarter;
• a ratio of total secured indebtedness to EBITDA not greater than 3.00 to 1.00 or less than 0.00 to 1.00, determined as of the last day of each fiscal quarter, with EBITDA annualized for the most-recent fiscal quarter; and
• a funded debt-to-EBITDA ratio, defined in the Credit Agreement as the Total Leverage Ratio, determined as of the last day of each fiscal quarter with EBITDA annualized for the most-recent fiscal quarter, of not greater than 5.50 to 1.00 or less than 0.00 to 1.00.
We expect to remain in compliance with our covenants under the Credit Agreement throughout 2026. If our current cash flow projections prove to be inaccurate, we expect to be able to remain in compliance with such financial covenants by taking one or more of the following actions: issue equity in a public or private offering; request a modification of our covenants from our bank group; reduce distributions from our current distribution rate or suspend distributions altogether; delay discretionary capital spending and reduce operating expenses; or obtain an equity infusion pursuant to the terms of the Credit Agreement.
For a more detailed description of the Credit Agreement, including the covenants and restrictions contained therein, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
Senior Notes
As of December 31, 2025, we had $1.0 billion and $750.0 million aggregate principal amount outstanding on our Senior Notes 2029 and Senior Notes 2033, respectively.
The Senior Notes 2027 were due on September 1, 2027, and accrued interest at the rate of 6.875% per year. Interest on the Senior Notes 2027 was payable semi-annually in arrears on each of March 1 and September 1. On October 15, 2025 the Senior Notes 2027 were redeemed in full at par, plus accrued and unpaid interest, with the net proceeds from the issuance and sale of the Senior Notes 2033, together with borrowings under our Credit Agreement.
The Senior Notes 2029 are due on March 15, 2029, and accrue interest at the rate of 7.125% per year. Interest on the Senior Notes 2029 is payable semi-annually in arrears on each of March 15 and September 15.
The Senior Notes 2033 are due on October 1, 2033, and accrue interest at the rate of 6.250% per year. Interest on the Senior Notes 2033 is payable semi-annually in arrears on each of April 1 and October 1, commencing on April 1, 2026.
For more detailed descriptions of the Senior Notes 2027, Senior Notes 2029, and Senior Notes 2033, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
DRIP
During the years ended December 31, 2025 and 2024, distributions of $0.2 million and $1.6 million, respectively, were reinvested under the DRIP resulting in the issuance of 7,832 and 65,352 common units, respectively.
Such distributions are treated as non-cash transactions in the accompanying Consolidated Statements of Cash Flows included in Part II, Item 8 “Financial Statements and Supplementary Data” of this report.
See Note 12 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for more information regarding the DRIP.
Non-GAAP Financial Measures
Adjusted Gross Margin
Adjusted gross margin is a non-GAAP financial measure. We define Adjusted gross margin as revenue less cost of operations, exclusive of depreciation and amortization expense. We believe Adjusted gross margin is useful to investors as a supplemental measure of our operating profitability. Management uses adjusted gross margin to assess operating performance as compared to historical results, budget and forecast amounts, expected return on capital investment, and our competitors. Adjusted gross margin primarily is impacted by the pricing trends for service operations and cost of operations, including labor rates for service technicians, volume, and per-unit costs for lubricant oils, quantity and pricing of routine preventative maintenance on compression units, and property tax rates on compression units. Adjusted gross margin should not be considered an alternative to, or more meaningful than, gross margin or any other measure presented in accordance with GAAP. Moreover, our Adjusted gross margin, as presented, may not be comparable to similarly titled measures of other companies.
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Because we capitalize assets, depreciation and amortization of equipment is a necessary element of our cost structure. To compensate for the limitations of Adjusted gross margin as a measure of our performance, we believe it is important to consider gross margin determined under GAAP, as well as Adjusted gross margin, to evaluate our operating profitability.
The following table reconciles Adjusted gross margin to gross margin, its most directly comparable GAAP financial measure, for each of the periods presented (in thousands):
Year Ended December 31,
2025 2024
Total revenues $ 998,099 $ 950,449
Cost of operations, exclusive of depreciation and amortization (328,804) (312,726)
Depreciation and amortization (284,816) (264,756)
Gross margin $ 384,479 $ 372,967
Depreciation and amortization 284,816 264,756
Adjusted gross margin $ 669,295 $ 637,723
Adjusted EBITDA
We define EBITDA as net income (loss) before net interest expense, depreciation and amortization expense, and income tax expense (benefit). We define Adjusted EBITDA as EBITDA plus impairment of assets, impairment of goodwill, interest income on capital leases, unit-based compensation expense (benefit), severance charges and other employee costs, certain transaction expenses, loss (gain) on disposition of assets, loss on extinguishment of debt, loss (gain) on derivative instrument, and other. We view Adjusted EBITDA as one of management’s primary tools for evaluating our results of operations, and we track this item on a monthly basis as an absolute amount and as a percentage of revenue compared to the prior month, year-to-date, prior year, and budget. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financial statements, such as investors and commercial banks, to assess:
• the financial performance of our assets without regard to the impact of financing methods, capital structure, or the historical cost basis of our assets;
• the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;
• the ability of our assets to generate cash sufficient to make debt payments and pay distributions; and
• our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital structure.
We believe Adjusted EBITDA provides useful information to investors because, when viewed in conjunction with our GAAP results and the accompanying reconciliations, it may provide a more complete assessment of our performance as compared to considering solely GAAP results. We also believe that external users of our financial statements benefit from having access to the same financial measures that management uses to evaluate the results of our business.
Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), cash flows from operating activities, or any other measure presented in accordance with GAAP. Moreover, our Adjusted EBITDA, as presented, may not be comparable to similarly titled measures of other companies.
Because we use capital assets, depreciation, impairment of assets, loss (gain) on disposition of assets, and the interest cost of acquiring compression equipment also are necessary elements of our aggregate costs. Unit-based compensation expense related to equity awards granted to employees also is a meaningful business expense. Therefore, measures that exclude these cost elements have material limitations. To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating activities as determined under GAAP, as well as Adjusted EBITDA, to evaluate our financial performance and liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these excluded items may vary among companies. Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing comparable GAAP measures, understanding the differences between the measures, and incorporating this knowledge into their decision making.
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The following table reconciles Adjusted EBITDA to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands):
Year Ended December 31,
2025 2024
Net income $ 111,319 $ 99,575
Interest expense, net 187,408 193,471
Depreciation and amortization 284,816 264,756
Income tax expense 4,869 2,231
EBITDA $ 588,412 $ 560,033
Unit-based compensation expense (1) 4,342 16,552
Transaction expenses (2) 1,914 133
Severance charges and other employee costs (3) 4,455 2,430
Loss on disposition of assets 3,820 4,939
Loss on extinguishment of debt (4) 3,006 4,966
Gain on derivative instrument — (5,684)
Impairment of assets (5) 7,811 913
Adjusted EBITDA $ 613,760 $ 584,282
Interest expense, net (187,408) (193,471)
Non-cash interest expense 8,554 8,748
Income tax expense (4,869) (2,231)
Transaction expenses (1,914) (133)
Severance charges and other employee costs (4,455) (2,430)
Cash received on derivative instrument — 6,888
Other 466 1,204
Changes in operating assets and liabilities (29,872) (61,523)
Net cash provided by operating activities $ 394,262 $ 341,334
________________________
(1) For the years ended December 31, 2025 and 2024, unit-based compensation expense included $2.0 million and $3.9 million, respectively, of cash payments related to quarterly payments of DERs on outstanding unit awards. Additionally, for the years ended December 31, 2025 and 2024, we paid $7.7 million and $5.4 million, respectively, for the cash portion of the settlement of phantom unit awards upon vesting, a portion of which is included in the unit-based compensation expense for these periods. The remainder of unit-based compensation expense for all periods was related to non-cash adjustments to the unit-based compensation liability.
(2) Represents certain expenses related to potential and completed transactions and other items. We believe it is useful to investors to exclude these expenses.
(3) Severance charges and other employee costs includes (i) severance payments to former employees of the Partnership, (ii) retention payments to employees of the Partnership that have executed agreements to maintain operations during the shared services integration but do not intend to remain employed with the Partnership after their retention period, and (iii) relocation payments to employees of the Partnership for relocation resulting from the shared services integration and the relocation of the Partnership’s headquarters to Dallas, Texas. These retention payments are incremental to the affected employees’ base pay. For the year ended December 31, 2025, severance charges and other employee costs included $0.6 million related to each of retention payments and relocation payments.
(4) For the year ended December 31, 2025, the loss on extinguishment of debt of $3.0 million is a result of the redemption of our Senior Notes 2027.
For the year ended December 31, 2024, the loss on extinguishment of debt is a result of the Defeasance of the Senior Notes 2026. This amount represents the write-off of deferred financing costs of $4.3 million and the difference between (i) the purchase price of U.S. government securities of $748.8 million and (ii) the aggregate outstanding principal balance and accrued interest of the Senior Notes 2026 of $748.1 million at the time of Defeasance.
(5) Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows.
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Distributable Cash Flow
We define DCF as net income (loss) plus non-cash interest expense, non-cash income tax expense (benefit), depreciation and amortization expense, unit-based compensation expense (benefit), impairment of assets, impairment of goodwill, certain transaction expenses, severance charges and other employee costs, loss (gain) on disposition of assets, loss on extinguishment of debt, change in fair value of derivative instrument, proceeds from insurance recovery, and other, less distributions on Preferred Units and maintenance capital expenditures.
We believe DCF is an important measure of operating performance because it allows management, investors, and others to compare the cash flows that we generate (after distributions on the Preferred Units but prior to any retained cash reserves established by the General Partner and the effect of the DRIP) to the cash distributions that we expect to pay our common unitholders.
DCF should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), cash flows from operating activities, or any other measure presented in accordance with GAAP. Moreover, our DCF, as presented, may not be comparable to similarly titled measures of other companies.
Because we use capital assets, depreciation, impairment of assets, loss (gain) on disposition of assets, the interest cost of acquiring compression equipment, and maintenance capital expenditures are necessary components of our aggregate costs. Unit-based compensation expense related to equity awards granted to employees also is a meaningful business expense. Therefore, measures that exclude these cost elements have material limitations. To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating activities as determined under GAAP, as well as DCF, to evaluate our financial performance and liquidity. Our DCF excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these excluded items may vary among companies. Management compensates for the limitations of DCF as an analytical tool by reviewing comparable GAAP measures, understanding the differences between the measures, and incorporating this knowledge into their decision making.
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The following table reconciles DCF to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands):
Year Ended December 31,
2025 2024
Net income $ 111,319 $ 99,575
Non-cash interest expense 8,554 8,748
Depreciation and amortization 284,816 264,756
Non-cash income tax expense 466 574
Unit-based compensation expense (1) 4,342 16,552
Transaction expenses (2) 1,914 133
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
Change in fair value of derivative instrument — 1,204
Impairment of assets (5) 7,811 913
Distributions on Preferred Units (8,288) (17,550)
Maintenance capital expenditures (6) (39,414) (31,923)
DCF $ 385,677 $ 355,317
Maintenance capital expenditures 39,414 31,923
Transaction expenses (1,914) (133)
Severance charges and other employee costs (4,455) (2,430)
Distributions on Preferred Units 8,288 17,550
Other (2,876) 630
Changes in operating assets and liabilities (29,872) (61,523)
Net cash provided by operating activities $ 394,262 $ 341,334
________________________
(1) For the years ended December 31, 2025 and 2024, unit-based compensation expense included $2.0 million and $3.9 million, respectively, of cash payments related to quarterly payments of DERs on outstanding unit awards. Additionally, for the years ended December 31, 2025 and 2024, we paid $7.7 million and $5.4 million, respectively, for the cash portion of the settlement of phantom unit awards upon vesting, a portion of which is included in the unit-based compensation expense for these periods. The remainder of unit-based compensation expense for all periods was related to non-cash adjustments to the unit-based compensation liability.
(2) Represents certain expenses related to potential and completed transactions and other items. We believe it is useful to investors to exclude these expenses.
(3) Severance charges and other employee costs includes (i) severance payments to former employees of the Partnership, (ii) retention payments to employees of the Partnership that have executed agreements to maintain operations during the shared services integration but do not intend to remain employed with the Partnership after their retention period, and (iii) relocation payments to employees of the Partnership for relocation resulting from the shared services integration and the relocation of the Partnership’s headquarters to Dallas, Texas. These retention payments are incremental to the affected employees’ base pay. For the year ended December 31, 2025, severance charges and other employee costs included $0.6 million related to each of retention payments and relocation payments.
(4) For the year ended December 31, 2025, the loss on extinguishment of debt of $3.0 million is a result of the redemption of our Senior Notes 2027.
For the year ended December 31, 2024, the loss on extinguishment of debt is a result of the Defeasance of the Senior Notes 2026. This amount represents the write-off of deferred financing costs of $4.3 million and the difference between (i) the purchase price of U.S. government securities of $748.8 million and (ii) the aggregate outstanding principal balance and accrued interest of the Senior Notes 2026 of $748.1 million at the time of Defeasance.
(5) Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows.
(6) Reflects actual maintenance capital expenditures for the period presented. Maintenance capital expenditures are capital expenditures made to maintain the operating capacity of our assets and extend their useful lives, replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining our existing business and related cash flow.
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DCF Coverage Ratio
DCF Coverage Ratio is defined as the period’s DCF divided by distributions declared to common unitholders in respect of such period. We believe DCF Coverage Ratio is an important measure of operating performance because it permits management, investors, and others to assess our ability to pay distributions to common unitholders out of the cash flows that we generate. Our DCF Coverage Ratio, as presented, may not be comparable to similarly titled measures of other companies.
The following table summarizes our DCF Coverage Ratio for the periods presented (dollars in thousands):
Year Ended December 31,
2025 2024
DCF $ 385,677 $ 355,317
Distributions for DCF Coverage Ratio (1) $ 266,659 $ 245,990
DCF Coverage Ratio 1.45 x 1.44 x
________________________
(1) Represents distributions to the holders of our common units as of the record date.
Critical Accounting Estimates
The discussion and analysis of our financial condition and results of operations is based on our financial statements. These financial statements were prepared in conformity with GAAP. As such, we are required to make certain estimates, judgments, and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. We base our estimates on historical experience, available information, and other assumptions we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates; however, actual results may differ from these estimates under different assumptions or conditions. The accounting estimates that we believe require management’s most difficult, subjective, or complex judgments, and that are the most critical to its reporting of results of operations and financial position are as follows:
Long-Lived Assets
Long-lived assets, which include property and equipment, and intangible assets, comprise a significant amount of our total assets. Long-lived assets to be held and used by us are reviewed to determine whether any events or changes in circumstances indicate the carrying amount of the asset may not be recoverable. For long-lived assets to be held and used, we base our evaluation on impairment indicators such as the nature of the assets, the future economic benefit of the assets, the consistency of performance characteristics of compression units in our idle fleet with the performance characteristics of our revenue-generating horsepower, any historical or future profitability measurements, and other external market conditions or factors that may be present. If such impairment indicators are present or other factors exist that indicate the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through the use of an undiscounted cash flows analysis. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the estimated fair value of the asset. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, is based on an estimate of discounted cash flows, the expected net sale proceeds compared to other similarly configured fleet units we recently sold, a review of other units recently offered for sale by third parties, or the estimated component value of similar equipment we plan to continue to use.
Potential events or circumstances that reasonably could be expected to negatively affect the key assumptions we used in estimating whether or not the carrying value of our long-lived assets are recoverable include the consolidation or failure of crude oil and natural gas producers, which may result in a smaller market for our services and may cause us to lose key customers, and cost-cutting efforts by crude oil and natural gas producers, which may cause us to lose current or potential customers or achieve less revenue per customer. If our projections of cash flows associated with our units decline, we may have to record an impairment of assets in future periods.
For the years ended December 31, 2025 and 2024, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 28 and 2 compression and treating units, respectively, representing approximately 19,005 and 1,260 of aggregate horsepower, respectively, that previously were used to provide compression and treating services in our business. As a result, we recorded impairments of compression and treating equipment of $7.8 million and $0.3 million for the years ended December 31, 2025, and 2024, respectively. The primary circumstances supporting these impairments were: (i) unmarketability of certain compression units into the foreseeable future, (ii) excessive maintenance costs associated with certain
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fleet assets, and (iii) prohibitive retrofitting costs that likely would prevent certain compression units from securing customer acceptance. These compression and treating units were written down to their estimated salvage values, if any.
Estimated Useful Lives of Property and Equipment
Property and equipment is carried at cost. Depreciation is computed on a straight-line basis using useful lives that are estimated based on assumptions and judgments that reflect both historical experience and expectations regarding future use of our assets. The use of different assumptions and judgments in the calculation of depreciation, especially those involving useful lives, likely would result in significantly different net book values of our assets and results of operations.
Commitments and Contingencies
From time to time, we and our subsidiaries may be involved in various claims and litigation arising in the ordinary course of business. Additionally, our compliance with federal, state, and local tax regulations is subject to audit by various taxing authorities. Certain taxing authorities have either claimed or issued an assessment that specific operational processes, which we and others in our industry regularly conduct, result in transactions that are subject to taxes. We and others in our industry have disputed these claims and assessments based on either existing tax statutes or published guidance by the taxing authorities.
We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments, or settlements. While we are unable to predict the ultimate outcome of these actions, the accounting standard for contingencies requires management to make judgments about future events that are inherently uncertain. We are required to record a loss during any period in which we believe a contingency is probable and can be reasonably estimated. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised, as required, as better information becomes available to us.
Our U.S. federal income tax returns for the years 2019 and 2020 currently are under examination by the IRS. The IRS has issued preliminary partnership examination changes, resulted in imputed underpayment computations of approximately $30.3 million, including interest, for the 2019 and 2020 tax years. Under the Bipartisan Budget Act of 2015, there are several procedural steps to complete before a final imputed underpayment, if any, is determined. Based on discussions with the IRS, we have accrued $2.9 million, which we believe is a reasonable estimate of the potential loss from the aggregate final imputed underpayment for the years 2019 and 2020. However, the final partnership imputed underpayment, if any, has not been determined. Once determined, our General Partner may elect to either pay the imputed underpayment, if any, (including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised information statement to each unitholder, or former unitholder as applicable, with respect to an audited and adjusted return.
Recent Accounting Pronouncements
See Part II, Item 8 “Financial Statements and Supplementary Data”, Note 19 for recent accounting pronouncements affecting us.