USAC 10-K & 10-Q changes, risk factors and insider trading
USA Compression Partners, LP · NYSE · Natural Gas Transmission · CIK 1522727 · All filings on SEC.gov
At a glance
What changed in the latest 10-K
Risk Factors
New heading “Changes in U.S. trade policy and the impact of tariffs, including any resulting market volatility or trade tensions, may have a material adverse effect on our business and results of operations.”
New heading “Implementing the shared services model with Energy Transfer has been and will continue to be a complex and time-consuming process. Disruptions to our systems or operations caused by the implementation may have a material adverse impact on us.”
New heading “We may be subject to product liability claims if people or property are harmed by the compression units we package.”
New heading “We may have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.”
Removed heading “Implementing the shared services model with Energy Transfer will be a complex and time-consuming process. Disruptions to our systems or operations caused by the implementation may have a material adverse impact on us.”
Removed heading “The deterioration of the financial condition of our customers could adversely affect our business.”
Removed heading “The Preferred Units have rights, preferences, and privileges that are not held by, and are preferential to the rights of, holders of our common units.”
Removed heading “Restrictions in the Partnership Agreement related to the Preferred Units may limit our ability to make distributions to our common unitholders and our ability to capitalize on acquisition and other business opportunities.”
Largest changes
“Weak economic conditions and widespread financial distress, have in the past and could again reduce the liquidity of our customers, suppliers, or vendors, making it more difficult for them to meet their obligations to us. We therefore are subject to heightened risks of loss resulting from nonpayment or nonperformance by our customers, suppliers, and vendors. Severe financial problems encountered by our customers, suppliers, and vendors could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. …”see in full comparison
“Weak economic conditions and widespread financial distress, have in the past and could again reduce the liquidity of our customers, suppliers, or vendors, making it more difficult for them to meet their obligations to us. We therefore are subject to heightened risks of loss resulting from nonpayment or nonperformance by our customers, suppliers, and vendors. Severe financial problems encountered by our customers, suppliers, and vendors could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. …”see in full comparison
“Changes in U.S. trade policy and the impact of tariffs, including any resulting market volatility or trade tensions, may have a material adverse effect on our business and results of operations.”see in full comparison
“As a result of the J-W Power Acquisition, we own and operate specialized manufacturing facilities for the manufacture of compression units that support our internal operations and those of third-party customers. We face an inherent risk of product liability exposure related to the sale of these compression units. We may be sued if any of these compression units allegedly causes injury. …”see in full comparison
“Our business and results of operations may be adversely affected by uncertainty and changes in U.S. trade policies, including tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments. For example, on March 12, 2025, the U.S. government imposed a 25% tariff on steel imports, which was increased to 50% on June 4, 2025, and on April 2, 2025, the U.S. government announced a 10% tariff on product imports from almost all foreign countries and individualized higher tariffs on certain other countries. …”see in full comparison
“We have a significant number of long-lived assets on our Consolidated Balance Sheets. Under GAAP, we are required to review our long-lived assets for impairment when events or circumstances indicate that the carrying value of such assets may not be recoverable or such assets will no longer be utilized in the operating fleet. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. …”see in full comparison
Full comparison: every changed paragraph (89)
•An extendedA reduction in the demand for, or production of, natural gas or crude oil could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders.
•Implementing the shared services model with Energy Transfer will be a complex and time-consuming process. Disruptions to our systems or operations caused by the implementation may have a material adverse impact on us.
•Integration of assets acquired in past acquisitions or future acquisitions with our existing business can be complex, time-consuming, and costly, particularly in the case of material acquisitions such as the J-W Power Acquisition, which increased our size and expanded the geographic areas in which we operate. A failure to successfully integrate acquired assets with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations, or cash available for distribution to our unitholders.
•Changes in U.S. trade policy and the impact of tariffs, including any resulting market volatility or trade tensions, may have a material adverse effect on our business and results of operations.
•We may issue additional limited partner interests without the approval of unitholders, subject to certain Preferred Unit approval rights,unitholders which would dilute unitholders’ existing ownership interests and may increase the risk that we will not have sufficient available cash to maintain or increase our per-common-unit distribution level.
•Energy Transfer may sell, and theWesterman, holders of the Preferred Units have sold andLtd. may continue to sell,sell our common units in the public or private markets, and such sales could have an adverse impact on the trading price of our common units.
•Unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.
•Unitholders may have liability to repay distributions that were wrongfully distributed to them.
•Our Partnership Agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our General Partner’s directors, officers, or other employees.
•The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial, or administrative changes or differing interpretations, possibly applied on a retroactive basis.
•If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017,returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
•Tax gain or loss on the disposition of our common units could be more or less than expected.
•Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.
•We may have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.
Furthermore, our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”) prohibits us from paying distributions on our common units unless we have first paid the quarterly distribution on the Preferred Units, including any previously accrued but unpaid distributions on the Preferred Units. The Preferred Unit distributions require $4.4 million quarterly, or $17.6 million annually, based on the number of Preferred Units outstanding as of February 6, 2025 and the distribution rate of $24.375 per Preferred Unit per quarter, or $97.50 per Preferred Unit per year.
•the ability to effectively integrate any assets or businesses we acquireacquire, including the J-W Power Acquisition;
An extendedA reduction in the demand for, or production of, natural gas or crude oil could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders.
The demand for our compression services depends on the continued demand for, and production of, natural gas and crude oil. Demand may be affected by, among other factors, natural gas prices, crude oil prices, weather, availability of alternative energy sources, governmental regulation, geopolitical events, global health pandemics, and the overall demand for energy. Any extended reduction in the demand for natural gas or crude oil could depress the level of production activity and result in a decline in the demand for our compression services, which has in the past and in the future could result in a reduction in our revenues and our cash available for distribution. Additionally, as a result of the J-W Power Acquisition, we own and operate specialized manufacturing facilities for the manufacture of compression units. The demand for these products is similarly affected by the production levels of natural gas and crude oil, and may be negatively affected even by a short-term decline in production. Our customers could seek to preserve capital or reduce expenses by using lower-cost providers of compression services, not renewing month-to-month contracts, determining not to enter into any new compression service contracts, seeking lower contract prices for our services, or delaying or eliminating orders for the manufacture of compression units.
In particular, lower natural gas or crude oil prices over the long term could result in a decline in the production of natural gas or crude oil, respectively, resulting in reduced demand for our compression services. For example, in 2020, the price of crude oil declined rapidly beginning in March of that year. During 2020, the North American rig count reached a low of 247 rigs in August of 2020, down from 790 rigs at the end of January of that year, the price of WTI crude oil briefly went negative in April 2020, down from $51.58 per barrel at the end of January of that year, and Henry Hub natural gas spot reached a low of $1.33 per MMBtu in September 2020, down from $1.91 per MMBtu at the end of January of that year. The decline in commodity prices and the demand for and production of crude oil and natural gas resulted in a decline in the demand for our compression services, which caused a reduction of our revenues and our cash available for distribution.
Implementing the shared services model with Energy Transfer will be a complex and time-consuming process. Disruptions to our systems or operations caused by the implementation may have a material adverse impact on us.
We are currently implementing a shared services model with Energy Transfer whereby we intend to share personnel and resources with Energy Transfer in certain departments, including information technology, accounting, and human resources. Integrating these functions with Energy Transfer will require substantial time, resources, and coordination. This could result in significant disruptions or require a disproportionate amount of our management’s attention, and may result in unforeseen operational or administrative difficulties or costs. We may encounter significant delays to this integration, which would further exacerbate these effects. We may also encounter difficulties in integrating our personnel with Energy Transfer’s teams, and may lose key employees.
Additionally, as part of the shared services integration, many of our information systems will migrate to Energy Transfer’s enterprise resource planning (“ERP”) systems. This migration may result in significant disruptions to our accounting or other internal systems, including our ability maintain effective systems of internal control over financial reporting and disclosure controls.
The Credit Agreement has an aggregate commitment of $1.6up to $1.75 billion (subject to availability under our borrowing base)., with a further potential increase of up to an additional $300 million. The Credit Agreement matures on August 27, 2030, except that if more than $50.0 million of the Senior Notes 2029 are outstanding on December 8,14, 2026.2028, the Credit Agreement will mature on December 14, 2028. As of December 31, 2024,2025, we had outstanding borrowings under the Credit Agreement of $772.1$795.0 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $827.1$954.2 million of remaining unused availabilityavailability, all of which,which duewas available to be drawn, inclusive of restrictions related to compliance with the applicable financial covenants,covenants. $782.5As millionof wasFebruary available12, to2026, bewe drawn.had outstanding borrowings under the Credit Agreement of $1.3 billion and outstanding letters of credit of $2.0 million.
As of December 31, 2024,2025, we had $1.0 billion and $750.0 million and $1.0 billion aggregate principal amount outstanding on our Senior Notes 20272029 and Senior Notes 2029,2033, respectively. The Senior Notes 20272029 and Senior Notes 20292033 accrue interest at the rate of 6.875%7.125% and 7.125%6.250% per year, respectively.
Our ability to incur additional debt also is subject to limitations in the Credit Agreement, including certain financial covenants. As of December 31, 2024,2025, our leverage ratio under the Credit Agreement was 4.02x.4.00x. Financial covenants in the Credit Agreement permitrequire us to maintain a maximum leverage ratio of 5.25not togreater 1.00 (except that we may increase the applicable Total Leverage Ratio by 0.25 for any fiscal quarter during which a Specified Acquisition (as defined in the Credit Agreement) occurs and the following two fiscal quarters, but in no event shall the maximum Total Leverage Ratio exceedthan 5.50 to 1.00 foror anyless fiscalthan quarter0.00 asto a result of such increase)1.00; an Interest Coverage Ratio (as defined in the Credit Agreement) of not less than 2.50 to 1.00; and a Secured Leverage Ratio (as defined in the Credit Agreement) of not greater than 3.00 to 1.00 or less than 0.00 to 1.00. As of February 6, 2025, we had outstanding borrowings under the Credit Agreement of $801.5 million and outstanding letters of credit of $0.8 million.
Our ability to service our debt will depend on, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory, and other factors, some of which are beyond our control. In addition, our ability to service our debt under the Credit Agreement could be impacted by market interest rates, as all of our outstanding borrowings under the Credit Agreement are subject to variable interest rates that fluctuate with changes in market interest rates. While the U.S. Federal Reserve has begun loweringlowered interest rates,rates recently, macroeconomic circumstances may change, resulting in delays or reversal of such actions, which may result in a prolonged high-interest rate environment. Any substantial increase in the interest rates applicable to our variable-rate indebtedness outstanding could have a material negative impact on our cash available for distribution. Based on our December 31, 2024,2025, variable-rate indebtedness outstanding, a one percent increase in the effective interest rate would result in an annual increase in our interest expense of approximately $7.7$8.0 million. If our operating results are not sufficient to service our current or future indebtedness, we could be forced to take actions such as reducing the level of distributions on our common units, curtailing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may be unable to affect any of these actions on terms satisfactory to us or at all.
The substantial majority of the components for our natural gas compression equipment are supplied by Caterpillar Inc., Cummins Inc., INNIO Waukesha, and TECO-Westinghouse for engines; Air-X-Changers, Alfa Laval (US), AXH air-coolers, EADS Cooling Solutions, LLC, and R&R Engineering Co. for coolers; and Ariel Corporation, Cooper Machinery Services Gemini products, and Arrow Engine Company for compressor frames and cylinders. Our reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. In addition, supply chain disruptions (including those caused by geopolitical events) may harm our suppliers and further complicate existing supply chain constraints. We also rely primarily on threea limited number of vendors, A G Equipment Company, Alegacy Equipment, LLC., andincluding Standard Equipment Company, a subsidiary of Energy Transfer, to package and assemble our compression units. We do not have long-term contracts with these suppliers or packagers, and a partial or complete loss of any of these sources could have a negative impact on our results of operations and could damage our customer relationships. Some of these suppliers manufacture the components we purchase in a single facility, and any damage to that facility or slowdown or closure of that facility for any reason, including labor shortages or labor disputes, could lead to significant delays in delivery of completed compression units to us.
There are no limitations in the Partnership Agreement on our ability to issue additional equity securities, including securities ranking senior to the common units, subject to certain restrictions in the Partnership Agreement limiting our ability to issue units senior to or pari passu with the Preferred Units.units. To the extent we issue additional equity securities, including common units and preferred units, the payment of distributions on those additional securities may increase the risk that we will be unable to maintain or increase our per-common-unit distribution level. Similarly, our incurrence of borrowings or other debt to finance our growth strategy would increase our interest expense, which in turn would decrease our cash available for distribution.
The deterioration of the financial condition of our customers could adversely affect our business.
During times when the natural gas or crude oil markets weaken our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. For example, our customers could seek to preserve capital or reduce expenses by using lower-cost providers of compression services, not renewing month-to-month contracts, determining not to enter into any new compression service contracts, or seeking lower contract prices for our services. A significant decline in commodity prices may cause certain of our customers to reconsider their near-term capital budgets, which may impact large-scale natural gas infrastructure and crude oil production activities. Reduced demand for our services could adversely affect our business, results of operations, financial condition, and cash flows.
Weak economic conditions and widespread financial distress, have in the past and could again reduce the liquidity of our customers, suppliers, or vendors, making it more difficult for them to meet their obligations to us. We therefore are subject to heightened risks of loss resulting from nonpayment or nonperformance by our customers, suppliers, and vendors. Severe financial problems encountered by our customers, suppliers, and vendors could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In the event that any of our customers was to enter into bankruptcy, we could lose all or a portion of the amounts owed to us by such customer, and we may be forced to cancel all or a portion of our service contracts with such customer at significant expense to us. For example, as of December 31, 2024, two customers accounted for 12% and 11% of our trade accounts receivable, net balance, respectively. If these customers were to enter bankruptcy or failed to pay us, it could adversely affect our business, results of operations, financial condition, and cash flows.
The Preferred Units have rights, preferences, and privileges that are not held by, and are preferential to the rights of, holders of our common units.
The Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.
In addition, distributions on the Preferred Units accrue and are cumulative, at the rate of 9.75% per annum on the original issue price, which amounts to a quarterly distribution of $24.375 per Preferred Unit, or $97.50 per Preferred Unit per year. If we do not pay the required distributions on the Preferred Units, we will be unable to pay distributions on our common units. Additionally, because distributions on the Preferred Units are cumulative, we will have to pay all unpaid accumulated distributions on the Preferred Units before we can pay any distributions on our common units. Also, because distributions on our common units are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will not be entitled to receive distributions covering any prior periods if we later recommence paying distributions on our common units.
The Preferred Units are convertible into common units in accordance with the terms of the Partnership Agreement by the holders of the Preferred Units or by us in certain circumstances. In 2024, holders of our Preferred Units converted an aggregate of 320,000 Preferred Units. Our obligation to pay distributions on the Preferred Units, or on the common units issued following the conversion of the Preferred Units, could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general Partnership purposes. Our obligations to the holders of the Preferred Units also could limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition. See Note 11 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
Restrictions in the Partnership Agreement related to the Preferred Units may limit our ability to make distributions to our common unitholders and our ability to capitalize on acquisition and other business opportunities.
The operating and financial restrictions and covenants in the Partnership Agreement related to the Preferred Units could restrict our ability to finance future operations or capital needs, or to expand or pursue our business activities. The Partnership Agreement restricts or limits our ability (subject to certain exceptions) to:
•pay distributions on any junior securities, including our common units, prior to paying the quarterly distribution payable to the holders of the Preferred Units, including any previously accrued and unpaid distributions;
•issue any securities that rank senior to or pari passu with the Preferred Units; however, we will be able to issue an unlimited number of securities ranking junior to the Preferred Units, including junior preferred units and additional common units; and
•incur Indebtedness (as defined in the Credit Agreement) if, after giving pro forma effect to such incurrence, the Leverage Ratio (as defined in the Credit Agreement) determined as of the last day of the most recently ended fiscal quarter would exceed 6.5x, subject to certain exceptions.
We have recorded $216.3 million of identifiable intangible assets, net, as of December 31, 2024. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business. These events could cause us to record impairments of identifiable intangible assets. For example, for the year ended December 31, 2020, we recognized a $619.4 million impairment of goodwill as a result of an economic downturn that occurred that year.
We have a significant number of long-lived assets on our Consolidated Balance Sheets. Under GAAP, we are required to review our long-lived assets for impairment when events or circumstances indicate that the carrying value of such assets may not be recoverable or such assets will no longer be utilized in the operating fleet. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If business conditions or other factors cause the expected undiscounted cash flows to decline, we may be required to record non-cash impairment charges. Events and conditions that could result in impairment in the value of our long-lived assets include changes in the industry in which we operate, competition, advances in technology, adverse changes in the regulatory environment, or other factors leading to a reduction in our expected long-term profitability. For example, for the years ended December 31, 2024, 2023, and 2022, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 2, 42, and 15 compression units, respectively, representing approximately 1,260, 37,700, and 3,200 of aggregate horsepower, respectively, that previously were used to provide compression services in our business. As a result, we recorded impairments of compression equipment of $0.3 million, $12.3 million, and $1.5 million for the years ended December 31, 2024, 2023, and 2022, respectively.
Additionally, for the year ended December 31, 2024, we recognized a $0.6 million impairment of assets related to capitalized software costs that are no longer expected to provide benefit.
From time to time, we may choose to make business acquisitions to pursue market opportunities, increase our existing capabilities, and expand into new geographic areas of operations. While we have reviewed acquisition opportunities in the past and will continue to do so in the future, we may not be able to identify attractive acquisition opportunities or successfully acquire identified targets.
Integration of assets acquired in past acquisitions or future acquisitions with our existing business can be complex, time-consuming, and costly, particularly in the case of material acquisitions such as the CDMJ-W Power Acquisition, which significantly increased our size and expanded the geographic areas in which we operate. A failure to successfully integrate acquired assets with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations, or cash available for distribution to our unitholders.
The difficulties of integrating past and future acquisitions with our business include, among other things:
If any of these risks or other unanticipated liabilities or costs were to materialize, we may not realize the desired benefits from past and future acquisitions, resulting in a negative impact on our results of operations. For example, subsequent to the CDM Acquisition the attrition rate of specialized field technicians exceeded our projections and, as a result, we incurred unanticipated costs in 2018 to utilize third-party contractors to service our compression units at a greater cost than we would have incurred to compensate employees to perform the same work.
We may not be successful in integrating acquisitionsacquisitions, including the J-W Power Acquisition, into our existing operations within our anticipated time frame, which may result in unforeseen operational difficulties, diminished financial performance, or require a disproportionate amount of our management’s attention. In addition, acquired assets may perform at levels below the forecasts used to evaluate their acquisition value, due to factors beyond our control. If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted.
The CDMJ-W Power Acquisition could expose us to additional unknown and contingent liabilities, which liabilities could materially adversely affect our business, results of operations, and cash flow.liabilities.
The CDMJ-W Power Acquisition could expose us to additional unknown and contingent liabilities. We performed due diligence in connection with the CDMJ-W Power Acquisition and attempted to verify the representations made by EnergyJ-W TransferPower, J-W Energy, and Westerman, Ltd. in connection therewith, but there may be unknown and contingent liabilities of which we are currently unaware. EnergyWesterman, TransferLtd. has agreed to indemnify us for losses or claims relating to the operation of the business or otherwise only to a limited extent and for a limited period of time, and certain of Energy Transfer’s indemnification obligations have lapsed.time. There is a risk that we could ultimately be liable for obligations relating to the CDMJ-W Power Acquisition for which indemnification is not available, which could materially adversely affect our business, results of operations,operations and cash flow.
From time to time, we may choose to make business acquisitions, such as the J-W Power Acquisition, to pursue market opportunities, increase our existing capabilities, and expand into new geographic areas of operations. While we have reviewed acquisition opportunities in the past and will continue to do so in the future, we may not be able to identify attractive acquisition opportunities or successfully acquire identified targets.
Weak economic conditions and widespread financial distress, have in the past and could again reduce the liquidity of our customers, suppliers, or vendors, making it more difficult for them to meet their obligations to us. We therefore are subject to heightened risks of loss resulting from nonpayment or nonperformance by our customers, suppliers, and vendors. Severe financial problems encountered by our customers, suppliers, and vendors could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In the event that any of our customers was to enter into bankruptcy, we could lose all or a portion of the amounts owed to us by such customer, and we may be forced to cancel all or a portion of our service contracts with such customer at significant expense to us. For example, as of December 31, 2025 and 2024, one customer accounted for 12% and 11% of our trade accounts receivable, net balance, respectively. If this customer were to enter bankruptcy or failed to pay us, it could adversely affect our business, results of operations, financial condition, and cash flows.
We have recorded $186.9 million of identifiable intangible assets, net, as of December 31, 2025. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business. These events could cause us to record impairments of identifiable intangible assets.
We have a significant number of long-lived assets on our Consolidated Balance Sheets. Under GAAP, we are required to review our long-lived assets for impairment when events or circumstances indicate that the carrying value of such assets may not be recoverable or such assets will no longer be utilized in the operating fleet. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If business conditions or other factors cause the expected undiscounted cash flows to decline, we may be required to record non-cash impairment charges. Events and conditions that could result in impairment in the value of our long-lived assets include changes in the industry in which we operate, competition, advances in technology, adverse changes in the regulatory environment, or other factors leading to a reduction in our expected long-term profitability. For example, for the years ended December 31, 2025, 2024, and 2023, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 28, 2, and 42 compression and treating units, respectively, representing approximately 19,005, 1,260, and 37,700 of aggregate horsepower, respectively, that previously were used to provide compression and treating services in our business. As a result, we recorded impairments of compression and treating equipment of $7.8 million, $0.3 million, and $12.3 million for the years ended December 31, 2025, 2024, and 2023, respectively.
Changes in U.S. trade policy and the impact of tariffs, including any resulting market volatility or trade tensions, may have a material adverse effect on our business and results of operations.
Our business and results of operations may be adversely affected by uncertainty and changes in U.S. trade policies, including tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments. For example, on March 12, 2025, the U.S. government imposed a 25% tariff on steel imports, which was increased to 50% on June 4, 2025, and on April 2, 2025, the U.S. government announced a 10% tariff on product imports from almost all foreign countries and individualized higher tariffs on certain other countries. Several tariff announcements have been followed by announcements of limited exemptions and temporary pauses. These actions have caused uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods. Steel is a necessary component to build our compression units, and we require various other materials and equipment to operate and maintain our compression units. Any imposition of or increase in tariffs on imports of steel or other materials or equipment utilized in our business, as well as corresponding price increases for such materials available domestically, could increase the costs to purchase new compression units, manufacture compression units, and to maintain our operations. Additionally, any escalation of trade tensions, retaliatory measures by foreign governments, or shifts in U.S. or international trade policies could adversely impact our supply chain and increase costs. We may not be able to fully pass along the cost increases to our customers, which could materially and adversely affect our business and results of operations.
Additionally, our customers may be also affected by tariffs and the resulting volatility in pricing and demand, which could in turn affect demand for our services. Similarly, declines in consumer confidence and/or consumer spending, changes in unemployment, significant inflationary or deflationary changes or disruptive regulatory or geopolitical events could contribute to increased volatility and diminished expectations for the economy, including the market for our services, and lead to demand or cost pressures that could negatively and adversely impact our business. Volatility in the capital markets could also limit our ability to access capital on favorable terms, which could have an adverse impact on our ability to grow our business.
The nature of these types of risks, which are often unpredictable, makes them difficult to plan for, or otherwise mitigate, and they are generally uninsurable, which compounds their potential impact on our business and results of operations.
Implementing the shared services model with Energy Transfer has been and will continue to be a complex and time-consuming process. Disruptions to our systems or operations caused by the implementation may have a material adverse impact on us.
We continue to implement a shared services model with Energy Transfer whereby we share personnel and resources with Energy Transfer in certain departments, including information technology, accounting, and human resources. Integrating these functions with Energy Transfer has required, and will continue to require, substantial time, resources, and coordination. This could result in significant disruptions or require a disproportionate amount of our management’s attention, and may result in unforeseen operational or administrative difficulties or costs. We may encounter significant delays to this integration, which would further exacerbate these effects.
Management's Discussion & Analysis (MD&A)
New heading “J-W Power Acquisition”
Removed heading “Other Financial Data”
Removed heading “Derivative Instrument”
Largest changes
“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. …”see in full comparison
“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. …”see in full comparison
“•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.”see in full comparison
Full comparison: every changed paragraph (75)
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.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.
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.
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 downup year-over-year and average oil prices relatively flat,down, we experienced improvements to pricing and maintained fleet utilization for our compression services in 2024,2025, largely tied to associated gas growth from oil plays.
Looking ahead, global consumption of petroleum and liquids fuels according to the EIA’s January 20252026 Short Term Energy Outlook (“EIA Outlook”) increased in 20242025 and is expected to increase over 1.31.1 million barrels per day (“bpd”) in 20252026 and 1.10.3 million bpd in 2026.2027. The EIA Outlook estimates that annual U.S. crude oil production set a record of 13.213.6 million bpd in 2024,2025, due to production growth in the Permian. In 20252026 and 2026,2027, the EIA Outlook expects U.S. crude oil production growthto stay flat in 2026 and decline by 2% in 2027 tied to continue, albeit at a lower crude oil price, estimating average production of 13.5 million bpd for 2025 and 13.6 million bpdslowdown in 2026,drilling whichactivity wouldlinked representto newWTI recordsprices forforecasted annualin averagethe crudelow oil$50 production.mark. The U.S. crude oil production growth in 2025 and 2026 is expected to comecame almost entirely from the Permian, which isgrew expectedby 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 accountincreased forgas-to-oil over half of U.S. crude oil production by 2026.ratios. We expect that anticipated flat crude oil production increases likewise will continue to yield an increase in associated natural gas production volumes throughout 2025,2026, thereby increasing demand for our compression services.
Unlike crude oil, natural gas production and prices have been influenced by different factors, including the nonexistence of an OPEC+ equivalent for the global natural gas market, which makes natural gas price discovery dependent on market supply and demand dynamics rather than by a centralized market coordinator. Over the past several years, increased natural gas production in the U.S., driven by large volumes of associated gas produced from shale sources, has been a major driver of an overall decline in natural gas prices. The EIA Outlook expects dry natural gas production to increase by 1.4 billion cubic feet per day (“bcf/d”) in 20252026 and by 2.70.9 bcf/d in 2026,2027, resulting in record dry natural gas production each year.
Overall, the EIA Outlook expects the increase in U.S. natural gas demand to outpacetrail production and to increase by 3.20.9 bcf/d in 2025,2026, primarily reflecting the aforementioned increase in dry natural gas production compared to the expected demand from increased exports, both by LNG and pipeline, and stable baseload demand. Further,Looking further ahead, the EIA Outlook expects U.S natural gas net demand to increase anotherby 2.60.5 bcf/d in 2026,2027, again driven primarily by LNG and pipeline exports, and stable baseload.baseload with slower rate of growth in natural gas. Natural gas prices averaged $2.20$3.53 per million British thermal units (“MMBtu”) in 20242025 and the EIA Outlook expects natural gas prices to increase on average to $3.10$3.46/MMBtu and $4.00$4.59/MMBtu in 20252026 and 2026,2027, respectively, driven by the expectation that domestic natural gas inventories remain at or below previous five-year averages. We expect the baseload natural gas demand and increase in LNG and pipeline exports described above, along with growth in data center demand tied to the development of artificial intelligence which we believe is not fully considered in the EIA Outlook’s numbers, to continue to support long-term domestic natural gas production.
(1)Fleet horsepower is horsepower for compression units that have been delivered to us and excludes 20,31014,985 and 21,69020,310 of non-marketable horsepower as of December 31, 2024,2025, and 2023,2024, respectively. As of December 31, 2024,2025, we had no63,250 horsepower on order. SubsequentAdditionally, toas Decembera 31,result 2024,of the PartnershipJ-W orderedPower 10,000Acquisition largein January 2026, we added approximately 0.8 million in active horsepower forand expected1.0 deliverymillion duringtotal 2025.horsepower.
The increases in revenue-generating horsepower, average horsepower per revenue-generating compression unit, horsepowerand utilization, andaverage horsepower utilization based on revenue-generating horsepower and fleet horsepower as of and for the year ended December 31, 2024,2025, compared to December 31, 2023,2024, primarily were driven by the addition and deployment of new, and redeployment of existing, large-horsepower compression units due to increased demand for our services consistent with an overall increase in crude oil and natural gas produced within the U.S.
Contract operations revenue. The $82.7$26.7 million increase in contract operations revenue for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, primarily was due to (i) ana 8.3%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 6.0%0.9% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with an overall increase in crude oil and natural gas produced within the U.S., partially offset by (iii) ana $8.9$7.8 million decrease in revenue attributable to natural gas treating services.services activity.
Parts and service revenue. The $2.0$2.8 million increasedecrease in parts and service revenue for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, primarily was due to ana increasedecrease 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,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 $19.6$23.7 million increase in related-party revenue for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, primarily was due to revenue recognized from existing customers acquired by Energy Transfer since the previous period that are now classified as related-party revenue for a full year, as opposed to a partial year in the currentprevious period.
Cost of operations, exclusive of depreciation and amortization. The $28.0$16.1 million increase in cost of operations for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, primarily was due to (i) a $17.2$12.3 million increase in direct labor costs due to increased headcount associated with increased revenue-generating horsepower and higher employee costs, (ii) a $12.3$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 $2.2$1.4 million increase in other indirect expenses due to increased usage associated with increased revenue-generating horsepower, and (iv) a $1.4$2.0 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$5.8 million decrease in outsidefluids maintenanceexpense costsdriven by decreased pricing, (vi) a $1.1 million decrease in vehicle expense due to reducedlower usemaintenance ofand third-party laborrepair during the current periodperiod, and (vivii) a $1.4$0.4 million decrease in non-income taxes.
Depreciation and amortization expense. The $18.7$20.1 million increase in depreciation and amortization expense for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, primarily was due to (i) overhauls and major improvements to compression units and (ii) new trucks added to our vehicle fleet.units.
Selling, general, and administrative expense. The change$6.3 million decrease in selling, general, and administrative expense for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, primarily was due to (i) aan $5.6$11.5 million decrease in unit-based compensation expense, primarilyexpense 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, 2024, partially offset by2025, (ii) a $3.2$0.6 million increasedecrease 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 (iiiv) a $1.3$2.4 million increase in severance charges and other employee costs primarily related to the departure of executivescertain senior management as well as retention and relocation payments related to the shared services integration during the current period, andyear, (ivvi) a $0.6$2.2 million increase in employee-relatedinsurance and other administrative expenses, and (vii) a $1.9 million increase in transaction expenses drivenrelated byto increasedthe headcount.J-W Power Acquisition.
Loss (gain) on disposition of assets. The $4.9 million loss on disposition of assets for the year ended December 31, 2024, and the $1.7 million gain on disposition of assets for the year ended December 31, 2023, were related to various asset transactions.
Impairment of assets. The $0.9$7.8 million and $12.3$0.9 million impairments of assets during the years ended December 31, 20242025 and 2023,2024, 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.
Additionally, for the year ended December 31, 2024, we recognized a $0.6 million impairment of assets related to capitalized software costs that are no longer expected to provide benefit.
Interest expense, net. The $23.5$6.1 million increasedecrease in interest expense, net for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, primarily was due to increased aggregate borrowings and higherlower 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.
Loss on extinguishment of debt. The $5.0 million loss on extinguishment of debt for the year ended December 31, 2024 resulted from the satisfaction and discharge of the Senior Notes 2026, which constituted a legal defeasance under GAAP (the “Defeasance”). This loss consists of the write-off of deferred financing costs of $4.3 million and the difference between (i) the purchase price of U.S. government securities of $748.8 million, which were used for the Defeasance,Defeasance and (ii) the aggregate outstanding principal balance and accrued interest of the Senior Notes 2026 of $748.1 million at the time of Defeasance. For additional information regarding the Defeasance of the Senior Notes 2026, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
Gain on derivative instrument. The $5.7 million and $7.4 million gainsgain on derivative instrument for the yearsyear ended December 31, 2024 and 2023, respectively, resulted from the change in fair value of thean interest-rate swap due to changes in the interest-rate forward curve and cash received during the respectiveperiod. periods.This interest-rate swap was terminated in August 2024; see Note 8 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information.
Income tax expense. The $0.9$2.6 million increase in income tax expense for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, is primarily was related to deferreda incomecharge taxesof associated$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 TexasIRS. MarginFor Tax.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”.
Other Financial Data
Gross margin. The $57.6$11.5 million increase in gross margin for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, was due to (i) a $104.3$47.7 million increase in revenues, offset by (ii) a $28.0$16.1 million increase in cost of operations, exclusive of depreciation and amortization,amortization and (iii) an $18.7$20.1 million increase in depreciation and amortization.
Adjusted EBITDA. The $72.3$29.5 million increase in Adjusted EBITDA for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, primarily was due to a $76.3$31.6 million increase in Adjusted gross margin, partially offset by a $4.2$1.1 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severancetransaction charges,expenses, and transactionseverance expenses.charges and other employee costs.
DCF. The $74.2$30.4 million increase in DCF for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, primarily was due to (i) a $76.3$31.6 million increase in Adjusted gross margin, (ii) a $30.2$9.3 million decrease in distributions on Preferred Units following the conversion of 320,000180,000 Preferred Units into 15,990,8048,994,826 common units, and (iii) a $0.6$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, 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$1.1 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, transaction expenses, severance charges,charges and transactionother expenses.employee costs.
DCF Coverage Ratio. The slight increase in DCF Coverage Ratio for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, primarily was due to the increase in DCF, partially offset by an increase in distributions from an increase in the number of common units, largely attributable to the conversion of 320,000180,000 Preferred Units into 15,990,8048,994,826 common units during 20242025 and the exerciseissuance of warrants for 2,360,48818,175,323 common units in NovemberJanuary 2023.2026 related to the J-W Acquisition.
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, 20242025 and 2023,2024, were $31.9$39.4 million and $25.2$31.9 million, respectively. We currently have budgeted between $38.0$60.0 million and $42.0$70.0 million in maintenance capital expenditures during 2025,2026, including parts consumed from inventory. This includes a budgeted increase in maintenance capital expenditures as a result of the J-W Power Acquisition.
Without giving effect to any equipment that we may acquire pursuant to any future acquisitions, we currently have budgeted between $120.0$230.0 million and $140.0$250.0 million in expansion capital expenditures for 2025.2026. This includes a budgeted increase in expansion capital expenditures as a result of the J-W Power Acquisition. Our expansion capital expenditures for the years ended December 31, 20242025 and 2023,2024, were $243.5$117.6 million and $275.4$243.5 million, respectively.
As of December 31, 2024,2025, we did not have anyhad binding commitments to purchase $78.4 million of additional compression unitsunits, andall serialized parts. Subsequent to December 31, 2024, we ordered 10,000 horsepower for expected delivery during 2025 which will cost $10.8 million,of which is expected to be settleddelivered within the next twelve months. We have not ordered any compression units subsequent to December 31, 2025.
As of December 31, 2024,2025, other commitments include operating and finance lease payments totaling $19.3$18.4 million, of which we expect to make payments of $5.2$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.
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.
Net cash usedprovided inby investingoperating activities. The $30.6$52.9 million decreaseincrease in net cash usedprovided inby investingoperating activities for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, primarily was due to (i) a $33.7$60.8 million decrease in capital expenditures, forinventory purchases of new compression units, overhauls and major improvements, and purchases of other equipment, and (ii) a $1.0$21.3 million increase in proceedsnet fromincome insuranceexcluding recovery,non-cash charges, partially offset by (iii) a $4.0$27.0 million decreaseincrease in proceedsinterest frompayments dispositiondue to the timing of propertypayments related to our refinance of our Senior Notes 2026 and equipment.(iv) a $2.1 million increase in other working capital.
Net cash used in financinginvesting activities. The $100.1$87.1 million increasedecrease in net cash used in financinginvesting activities for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023, primarily2024, was due to (i) aan $748.8$87.6 million increasedecrease in investmentscapital inexpenditures, governmentfor securities purchased in connection with the Defeasancepurchases of thenew Seniorcompression Notesunits, 2026,overhauls and major improvements, and purchases of other equipment, and (ii) a $325.6$0.9 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 issuancedisposition of theproperty Seniorand Notesequipment, 2029,partially offset by (viiii) a $24.4$1.4 million decrease in Preferredproceeds Unitfrom distributions,insurance and (vii) a $1.1 million decrease in cash paid related to net settlement of unit-based awards.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.
As of December 31, 2024,2025, we had outstanding borrowings under the Credit Agreement of $772.1$795.0 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $827.1$954.2 million of remaining unused availability all of which,which duewas available to be drawn, inclusive of restrictions related to compliance with the applicable financial covenants, $782.5 million was available to be drawn.covenants. As of December 31, 2024,2025, we were in compliance with all of our covenants under the Credit Agreement.
As of February 6,12, 2025,2026, we had outstanding borrowings under the Credit Agreement of $801.5$1.3 millionbillion and outstanding letters of credit of $0.8$2.0 million.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.
The Credit Agreement matures on December 8, 2026.
The Credit Agreement provides for an asset-based revolving credit facility to be made available to the Partnership in an aggregate amount of $1.6 billion. The Partnership’s obligations under the Credit Agreement are guaranteed by the guarantors party to the Credit Agreement, which currently consists of all of the Partnership’s subsidiaries. In addition, under the Credit Agreement the Partnership’s Secured Obligations (as defined therein) are secured by: (i) substantially all of the Partnership’s assets and substantially all of the assets of the guarantors party to the Credit Agreement, excluding real property and other customary exclusions; and (ii) all of the equity interests of the Partnership’s U.S. restricted subsidiaries (subject to customary exceptions).
Borrowings under the Credit Agreement bear interest at a per-annum interest rate equal to, at the Partnership’s option, either the Alternate Base RateRate, one-month SOFR (which shall only be available for swingline loans made under the Credit Agreement), Daily Simple SOFR, or SOFR plusplus, in each case, 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 Daily Simple SOFR and SOFR loans, from 2.00%1.75% to 2.75%2.50% per annum, and (b) in the case of Alternate Base Rate loans and one-month SOFR loans, from 1.00%0.75% to 1.75%1.50% per annum, and arewill be determined based on a total-leverage-ratiototal leverage ratio pricing grid. In addition, the BorrowerPartnership is required to pay commitment fees based on the daily unused amount ofunder the Credit Agreementfacility in an amount per annum equal to 0.375% per annum.0.25%. Amounts borrowed and repaid under the Credit Agreement may be re-borrowed, subject to borrowing base availability.
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.
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.
As of December 31, 2024,2025, we had $1.0 billion and $750.0 million and $1.0 billion aggregate principal amount outstanding on our Senior Notes 20272029 and Senior Notes 2029,2033, respectively.
On March 5, 2024, we provided notice to the holders of our Senior Notes 2026 that, contingent on receipt of the proceeds from the Senior Notes 2029, the Senior Notes 2026 would be redeemed at par on April 4, 2024. On March 18, 2024, utilizing a portion of the proceeds from the Senior Notes 2029, we deposited government securities with the trustee to satisfy and discharge the Senior Notes 2026 under the Indenture governing the notes. This satisfaction and discharge constituted a legal defeasance, or the Defeasance, under GAAP as of March 18, 2024 of the full outstanding principal balance of $725.0 million. The Senior Notes 2026 were redeemed in full at par on April 4, 2024.
The Senior Notes 2027 are due on September 1, 2027, and accrue interest at the rate of 6.875% per year. Interest on the Senior Notes 2027 is payable semi-annually in arrears on each of March 1 and September 1.
The Senior Notes 20292027 arewere due on MarchSeptember 15,1, 2029,2027, and accrueaccrued interest at the rate of 7.125%6.875% per year. Interest on the Senior Notes 20292027 iswas payable semi-annually in arrears on each of March 151 and September 15,1. whichOn commenced on SeptemberOctober 15, 2024.2025 Netthe 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 20292033, were used for the Defeasance,together with the remainder used to reduce outstanding 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 Defeasance,Senior Notes 2027, Senior Notes 2027,2029, and Senior Notes 2029,2033, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
Derivative Instrument
During the year ended December 31, 2024, we elected to terminate the interest-rate swap we previously used to manage interest-rate risk associated with the floating-rate Credit Agreement, see Note 8 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for more information regarding the interest-rate swap.
Adjusted gross margin is a non-GAAP financial measure. We define Adjusted gross margin as revenue less cost of operations, exclusive of depreciation and amortization expense. We believe Adjusted gross margin is useful to investors as a supplemental measure of our operating profitability. Management uses adjusted gross margin to assess operating performance as compared to historical results, budget and forecast amounts, expected return on capital investment, and our competitors. Adjusted gross margin primarily is impacted by the pricing trends for service operations and cost of operations, including labor rates for service technicians, volume, and per-unit costs for lubricant oils, quantity and pricing of routine preventative maintenance on compression units, and property tax rates on compression units. Adjusted gross margin should not be considered an alternative to, or more meaningful than, gross margin or any other measure presented in accordance with GAAP. Moreover, our Adjusted gross margin, as presented, may not be comparable to similarly titled measures of other companies. Because we capitalize assets, depreciation and amortization of equipment is a necessary element of our cost structure. To compensate for the limitations of Adjusted gross margin as a measure of our performance, we believe it is important to consider gross margin determined under GAAP, as well as Adjusted gross margin, to evaluate our operating profitability.
What changed in the latest 10-Q
Risk Factors
Security holders and potential investors in our securities should carefully consider the risk factors set forth in Part I, Item 1A “Risk Factors” of our 2025 Annual Report, as updated by Exhibit 99.1 to our current report on Form 8-K12B filed on July 6, 2026, and in subsequent filings we make with the SEC. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.
Largest changes
Security holders and potential investors in our securities should carefully consider the risk factors set forth in Part I, Item 1A “Risk Factors” of our 2025 Annual Report, as updated by Exhibit 99.1 to our current report on Form 8-K12B filed on July 6, 2026, and in subsequent filings we make with the SEC. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.see in full comparison
Full comparison: every changed paragraph (1)
Security holders and potential investors in our securities should carefully consider the risk factors set forth in Part I, Item 1A “Risk Factors” of our 2025 Annual Report, as updated by Exhibit 99.1 to our current report on Form 8-K12B filed on July 6, 2026, and in subsequent filings we make with the SEC. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.
Management's Discussion & Analysis (MD&A)
New heading “Six months ended June 30, 2026, compared to the six months ended June 30, 2025”
New heading “*Not meaningful”
Largest changes
“Six months ended June 30, 2026, compared to the six months ended June 30, 2025”see in full comparison
“Impairment of assets. The $4.0 thousand and $6.9 million impairments of assets for the six months ended June 30, 2026 and 2025, respectively, primarily resulted from our evaluation of the future deployment of idle fleet under 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. …”see in full comparison
“Cost of operations, exclusive of depreciation and amortization. The $74.6 million increase in cost of operations, exclusive of depreciation and amortization, for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily was due to (i) an $80.5 million increase attributable to the J-W Power Acquisition and (ii) a $8.3 million increase in direct labor costs due to increased operating headcount associated with increased average revenue-generating horsepower and higher employee costs, partially offset by (iii) a $4.2 million decrease in fluids expense, (iv) a …”see in full comparison
Cost of operations, exclusive of depreciation and amortization. Thesee in full comparison$36.3$38.3 million increase in cost of operations, exclusive of depreciation and amortization, for the three months endedMarchJune31,30, 2026, compared to the three months endedMarchJune31,30, 2025, primarily was due to (i) a$40.1$39.5 million increase attributable to the J-W PowerAcquisition,Acquisition and (ii) a $4.0 million increase in direct labor costs due to increased operating headcount associated with increased average revenue-generating horsepower and higher employee costs, partially offset by (iiiii) a$1.4$2.5 million decrease in fluidsexpense andexpense, (iiiiv) a$2.4$1.6 million decrease in partconsumption.consumption, and (v) a $1.6 million decrease in retail parts and service expense that corresponds to a decrease in retail parts and service revenue attributable to our operations outside of the J-W Power Acquisition.
“Interest expense, net. The $3.2 million increase in interest expense, net for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily was due to higher aggregate borrowings, partially offset by lower weighted-average interest rates under the Credit Agreement and our senior notes.”see in full comparison
Full comparison: every changed paragraph (73)
Known material factors that could cause our actual results to differ from those represented within these forward-looking statements are described in Part I, Item 1A “Risk Factors” of our annual report on Form 10-K for the year ended December 31, 2025, filed on February 17, 2026 (our “2025 Annual Report”), as updated by Exhibit 99.1 to our current report on Form 8-K12B filed on July 6, 2026, as well as our subsequent filings with the SEC. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things:
USA Compression Partners, LP (the “Partnership”) is a Delaware limited partnership that operates as one of the nation’s largest independent providers of natural gas compression services in terms of total compression fleet horsepower. The Partnership converted from a Delaware limited partnership to a Texas limited partnership on July 6, 2026. We are managed by our general partner, USA Compression GP, LLC (the “General Partner”), which is wholly owned by Energy Transfer. All references in this section to the Partnership, as well as the terms “our,” “we,” “us,” and “its” refer to USA Compression Partners, LP, together with its consolidated subsidiaries, unless the context otherwise requires or where otherwise indicated.
On January 12, 2026 (the “J-W Acquisition Date”), the Partnership and USA Compression Partners, LLC, a wholly owned subsidiary of the Partnership, completed the acquisition of J-W Energy Company (“J-W Energy”) and its subsidiary, J-W Power Company (“J-W Power”), pursuant to which USA Compression Partners, LLC purchased all of the issued and outstanding capital stock of J-W Energy from Westerman, Ltd. (the “J-W Power Acquisition”). The J-W Power Acquisition had an initial purchase price of $860$860.0 million, which after accounting for our common unit price and certain purchase price adjustments, resulted in an aggregate payment of approximately $911.6 million, consisting of (i) approximately $455.0 million in cash and (ii) 18,175,323 common units inof the Partnership, which had a fair value of approximately $456.6 million on the J-W Acquisition Date, subject to customary post-closing price adjustments. Upon consummation of the J-W Power Acquisition, J-W Power and J-W Energy became consolidated subsidiaries of the Partnership.
The results of operations of J-W Power and J-W Energy subsequent to the J-W Acquisition Date are reflected in our financial results of operations for the three and six months ended MarchJune 31,30, 2026.
(1)Fleet horsepower is horsepower for compression units that have been delivered to us and excludes 14,985 and 13,210 of non-marketable horsepower asfor ofeach Marchperiod 31, 2026 and 2025, respectively.presented. As of MarchJune 31,30, 2026, we had 61,35097,650 large horsepower on order for delivery, all of which 53,650 is expected to be delivered within the next 12 months.
(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 as of MarchJune 31,30, 2026 and 2025, was 90.0% and 92.2%,91.7%, 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 for the three months ended MarchJune 31,30, 2026 and 2025,2025 was 90.2%90.0% and 91.9%, respectively. Average horsepower utilization based on revenue-generating horsepower and fleet horsepower for the six months ended June 30, 2026 and 2025 was 90.1% and 91.9%, respectively.
The 7.9%7.2% increaseand 7.6% increases in average revenue per revenue-generating horsepower per month for the three and six months ended MarchJune 31,30, 2026, respectively, compared to the three and six months ended MarchJune 31,30, 2025, primarily was due to (i) a 4.8% increase in each period resulting from the addition of higher revenue per-revenue generating horsepower acquired in the J-W Power Acquisition,Acquisition whichand contributed(ii) 4.7%increases of the2.4% increase.and An2.8%, additional 3.2% increase isrespectively, attributable 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.
The 52.6%55.3% increase in revenue-generating compression units, 24.8% increase in average revenue-generating horsepower,units and 24.7%the 25.9% increase in revenue-generating horsepower forat theJune three30, months ended March 31, 2026,2026 compared to theJune three30, months ended March 31, 2025,2025 primarily waswere due to the acquisition of approximately 2,070 revenue-generating compression units in the J-W Power Acquisition, with an additional increase due to the deployment of new and redeployment of previously idle compression units. These same factors were also primarily responsible for the 25.2% and 25.0% increases in average revenue-generating horsepower for the three and six months ended June 30, 2026 compared to the three and six months ended June 30, 2025.
The 27.7%28.3% increase in fleet horsepower and 29.0%the 29.3% increase in total available horsepower for the three and six months ended MarchJune 31,30, 2026,2026 compared to the three and six months endedJune March 31,30, 2025, primarily waswere due to the acquisition of approximately 1.0 million total horsepower in the J-W Power Acquisition.
The 17.5%18.7% decreaseand 18.1% decreases in average horsepower per revenue-generating compression unit for the three and six months ended MarchJune 31,30, 2026, compared to the three and six months ended MarchJune 31,30, 2025, primarily waswere due to the inclusion of a higher proportion of mid-size horsepower compression units from the J-W Power Acquisition.
Three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025
Contract operations revenue. The $68.5$77.6 million increase in contract operations revenue for the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, primarily was due to a $60.3$69.5 million increase due to the J-W Power Acquisition with the remaining increase attributable to our operations outside of the J-W Power Acquisition, including (i) ana 2.4% increase in average revenue per revenue-generating horsepower per month, which resulted from 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 and (ii) ana 1.1% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with an overall increase in natural gas produced within the U.S.
Parts and service revenue. The $16.8$15.6 million increase in parts and service revenue for the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, was due to the additional revenue generated by the J-W Power Acquisition, including $11.7$11.1 million attributable to parts and service revenue earned on maintenance work performed on customer-owned equipment and $8.1$6.9 million attributable to manufacturing sales.sales, offset by a decrease of $3.2 million in maintenance work generated by our operations outside of the J-W Power Acquisition, which is 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. Related-party revenue for the three months ended MarchJune 31,30, 2026 was generally consistent with the three months ended MarchJune 31,30, 2025.
Cost of operations, exclusive of depreciation and amortization. The $36.3$38.3 million increase in cost of operations, exclusive of depreciation and amortization, for the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, primarily was due to (i) a $40.1$39.5 million increase attributable to the J-W Power Acquisition,Acquisition and (ii) a $4.0 million increase in direct labor costs due to increased operating headcount associated with increased average revenue-generating horsepower and higher employee costs, partially offset by (iiiii) a $1.4$2.5 million decrease in fluids expense andexpense, (iiiiv) a $2.4$1.6 million decrease in part consumption.consumption, and (v) a $1.6 million decrease in retail parts and service expense that corresponds to a decrease in retail parts and service revenue attributable to our operations outside of the J-W Power Acquisition.
Depreciation and amortization expense. The $16.8$18.2 million increase in depreciation and amortization expense for the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, primarily was due to (i) a $13.5$16.0 million increase resulting from the J-W Power Acquisition, and (ii) overhauls and major improvements to compression units.
Selling, general, and administrative expense. The $16.5$16.0 million increase in selling, general, and administrative expense for the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, primarily was due to (i) a $10.4$8.5 million increase related to the J-W Power Acquisition, (ii) a $3.8$3.7 million increase in unit-based compensation, (iii) a $1.9 million increase in outside services and professional fees, (iv) a $0.8 million increase in administrative salaries and benefits, (v) a $0.8 million increase in transaction expenses related to the J-W Power Acquisition, and (iiivi) a $2.1$0.4 million increase in outsideother servicesindirect and professional fees.costs.
Impairment of assets. There was no impairment of assets for the three months ended June 30, 2026.
Impairment of assets. The $4 thousand and $3.6$3.2 million impairment of assets for the three months ended MarchJune 31,30, 2026 and 2025, respectively,2025 primarily resulted from our evaluation of the future deployment of our idle fleet under current market conditions. The primary circumstances supporting this impairment were: (i) unmarketability of certain compression units into the foreseeable future, (ii) excessive maintenance costs associated with certain fleet assets, and (iii) prohibitive retrofitting costs that likely would prevent certain compression units from securing customer acceptance. These compression units were written down to their estimated salvage values, if any.
As a result of our evaluation during the three months ended MarchJune 31,30, 2026 and 2025,2025 we retired one and 17four compression units, respectively,units with approximately 335 and 10,2005,900 of aggregate horsepower, respectively,horsepower that were previously used to provide compression services in our business.
Interest expense, net. The $2$1.6 million increase in interest expense, net for the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, primarily was due to higher aggregate borrowings, partially offset by lower weighted-average interest rates under the Credit Agreement and our senior notes.
Income tax expense. The $2.6$5.1 million increase in income tax expense for the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, primarily was related to additional taxes attributable to the J-W Power Acquisition. For additional information on income tax expense, see Note 7 to our unaudited condensed consolidated financial statements in Part I, Item 1 “Financial Statements” of this report for additional information.
Six months ended June 30, 2026, compared to the six months ended June 30, 2025
The following table summarizes our results of operations for the periods presented (dollars in thousands):
*Not meaningful
Contract operations revenue. The $146.1 million increase in contract operations revenue for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily was due to a $129.9 million increase due to the J-W Power Acquisition with the remaining increase attributable our operations outside of the J-W Power Acquisition, including (i) a 2.8% 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 and (ii) a 1.1% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with an overall increase in natural gas produced within the U.S.
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 $32.4 million increase in parts and service revenue for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily was due to the additional revenue generated by the J-W Power Acquisition, including $22.7 million attributable to parts and service revenue earned on maintenance work performed on customer-owned equipment and $15.0 million attributable to manufacturing sales, partially offset by a decrease of $6.7 million in maintenance work attributable to our operations outside of the J-W Power Acquisition, which is 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. Related-party revenue for the six months ended June 30, 2026 was consistent with the six months ended June 30, 2025.
Cost of operations, exclusive of depreciation and amortization. The $74.6 million increase in cost of operations, exclusive of depreciation and amortization, for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily was due to (i) an $80.5 million increase attributable to the J-W Power Acquisition and (ii) a $8.3 million increase in direct labor costs due to increased operating headcount associated with increased average revenue-generating horsepower and higher employee costs, partially offset by (iii) a $4.2 million decrease in fluids expense, (iv) a $4.0 million decrease in part consumption, (v) a $4.0 million decrease in retail parts and service expense that corresponds to a decrease in retail parts and service revenue attributable to our operations outside of the J-W Power Acquisition, and (vi) a $1.3 million decrease in outside maintenance expense for third party services.
Depreciation and amortization expense. The $35.0 million increase in depreciation and amortization expense for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily was due to (i) a $29.8 million increase resulting from the J-W Power Acquisition, and (ii) overhauls and major improvements to compression units.
Selling, general, and administrative expense. The $32.5 million increase in selling, general, and administrative expense for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily was due to (i) a $19.5 million increase related to the J-W Power Acquisition, (ii) a $4.5 million increase in transaction expenses related to the J-W Power Acquisition, (iii) a $3.9 million increase in outside services and professional fees, (iv) a $3.0 million increase in unit-based compensation, (v) a $1.0 million increase in administrative salaries and related benefits, and (vi) a $0.6 million increase in other indirect costs.
Impairment of assets. The $4.0 thousand and $6.9 million impairments of assets for the six months ended June 30, 2026 and 2025, respectively, primarily resulted from our evaluation of the future deployment of idle fleet under current market conditions. The primary circumstances supporting these impairments were: (i) unmarketability of certain compression units into the foreseeable future, (ii) excessive maintenance costs associated with certain fleet assets, and (iii) prohibitive retrofitting costs that likely would prevent certain compression units from securing customer acceptance. These compression units were written down to their estimated salvage values, if any.
As a result of our evaluations during the six months ended June 30, 2026 and 2025, we retired 1 and 21 compression units, respectively, with approximately 335 and 16,100 aggregate horsepower, respectively, that previously were used to provide compression services in our business.
Interest expense, net. The $3.2 million increase in interest expense, net for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily was due to higher aggregate borrowings, partially offset by lower weighted-average interest rates under the Credit Agreement and our senior notes.
Income tax expense. The $7.7 million increase in income tax expense for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily was related to additional taxes attributable to the J-W Power Acquisition. For additional information on income tax expense, see Note 7 to our unaudited condensed consolidated financial statements in Part I, Item 1 “Financial Statements” of this report for additional information.
Gross margin. The $33.0$35.5 million increase in gross margin for the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, was due to (i) ana $86.0$92.0 million increase in revenues, partially offset by (ii) a $36.3$38.3 million increase in cost of operations, exclusive of depreciation and amortization, and (iii) aan $16.8$18.2 million increase in depreciation and amortization.
Adjusted gross margin. The $49.8$68.5 million increase in Adjusted gross margin for the threesix months ended MarchJune 31,30, 2026, compared to the threesix months ended MarchJune 31,30, 2025, was due to an(i) $86.0a $178.1 million increase in revenuesrevenues, partially offset by (ii) a $36.3$74.6 million increase in cost of operations, exclusive of depreciation and amortization, and (iii) a $35.0 million increase in depreciation and amortization.
Adjusted EBITDA.gross margin. The $39.1$53.7 million increase in Adjusted EBITDAgross margin for the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, primarily was due to a $49.8$92.0 million increase in Adjusted gross margin,revenues offset by a $12.7$38.3 million increase in selling,cost general,of operations, exclusive of depreciation and administrative expenses, excluding unit-based compensation expense, transaction expenses, amortization of capitalized SaaS implementation costs, and severance charges and other employee costs.amortization.
DCF. The $42.1 million increase in DCF for the three months ended March 31, 2026, compared to the three months ended March 31, 2025, primarily was due to (i) a $39.1 million increase in Adjusted EBITDA, (ii) a $4.4 million decrease in distributions on Preferred Units due to the conversion of the remaining Preferred Units into common units, and (iii) a $1.6 million decrease in maintenance capital expenditures, offset by (iv) a $2.0 million increase in cash interest expense, net.
DCFThe Coverage$103.5 Ratio. Themillion increase in DCFAdjusted Coveragegross Ratiomargin for the threesix months ended MarchJune 31,30, 2026, compared to the threesix months ended MarchJune 31,30, 2025, was due to thea $178.1 million increase in DCFrevenues, for the periodpartially offset by increaseda common$74.6 unitholdermillion distributionsincrease primarilyin due to (i) the conversioncost of theoperations, remainingexclusive Preferredof Units into common unitsdepreciation and (ii) the issuance of 18,175,323 common units pursuant to the J-W Power Acquisition.amortization.
Adjusted EBITDA. The $43.8 million increase in Adjusted EBITDA for the three months ended June 30, 2026, compared to the three months ended June 30, 2025, primarily was due to a $53.7 million increase in Adjusted gross margin, partially offset by a $10.8 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, transaction expenses, amortization of capitalized SaaS implementation costs, and severance charges and other employee costs.
The $82.8 million increase in Adjusted EBITDA for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily was due to a $103.5 million increase in Adjusted gross margin, partially offset by a $23.4 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, transaction expenses, amortization of capitalized SaaS implementation costs, and severance charges and other employee costs.
DCF. The $35.4 million increase in DCF for the three months ended June 30, 2026, compared to the three months ended June 30, 2025, primarily was due to (i) a $43.8 million increase in Adjusted EBITDA and (ii) a $2.0 million decrease in distributions on Preferred Units due to the conversion of the remaining Preferred Units into common units, partially offset by (iii) a $5.2 million increase in maintenance capital expenditures, (iv) a $3.1 million increase in cash income tax expense, and (v) a $2.0 million increase in cash interest expense, net.
The $77.5 million increase in DCF for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily was due to (i) an $82.8 million increase in Adjusted EBITDA and (ii) a $6.3 million decrease in distributions on Preferred Units due to the conversion of the remaining Preferred Units into common units, partially offset by (iii) a $3.6 million increase in maintenance capital expenditures, (iv) a $3.1 million increase in cash income tax expense, and (v) a $4.0 million increase in cash interest expense, net.
DCF Coverage Ratio. The increase in DCF Coverage Ratio for the three and six months ended June 30, 2026, compared to the three and six months ended June 30, 2025, was due to the increase in DCF for the period offset by increased common unitholder distributions primarily due to (i) the conversion of the remaining Preferred Units into common units and (ii) the issuance of common units pursuant to the J-W Power Acquisition.
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 threesix months ended MarchJune 31,30, 2026 and 2025, were $9.2$26.2 million and $10.9$22.6 million, respectively. We currently plan to spend between $60.0 million and $70.0 million in maintenance capital expenditures for the year 2026, including parts consumed from inventory.
Without giving effect to any equipment that we may acquire pursuant to any future acquisitions, we currently plan to spend between $230.0 million and $250.0 million in expansion capital expenditures for the year 2026. Our expansion capital expenditures for the threesix months ended MarchJune 31,30, 2026 and 2025, were $26.4$73.2 million and $22.2$40.3 million, respectively.
As of MarchJune 31,30, 2026, we had binding commitments to purchase $76.0$123.3 million of additional compression units and $83.9$134.0 million of major components for manufacturing compression units, in total $159.9$257.3 million, of which $106.9$122.6 million is expected to be settled within the next 12 months.
As of MarchJune 31,30, 2026, other commitments include operating and finance lease payments totaling $27.4$25.8 million, of which we expect to make payments of $6.6$6.3 million in the next twelve months.
During the firstsix quartermonths ofended June 30, 2026, the Partnership reclassified $62.7 million of heavy equipment inventory, such as engines, compressor frames, coolers, and cylinders, from inventory to fixed assets. The intended use of the assets changed from sale to third parties to internal use for fixed assets.
The following table summarizes our sources and uses of cash for the threesix months ended MarchJune 31,30, 2026 and 2025 (in thousands):
Net cash provided by operating activities. The $31.5$52.9 million increase in net cash provided by operating activities for the threesix months ended MarchJune 31,30, 2026, compared to the threesix months ended MarchJune 31,30, 2025, primarily was due to (i) a $30.7$66.7 million increase in net income excluding non-cash charges and (ii) a $22.8$19.9 million decrease in interestworking payments,capital, partially offset by (iii) a $19.2$28.2 million increase in workinginventory capitalpurchases and (iv) a $3.2$6.2 million increase in inventoryinterest purchases.payments.
Net cash used in investing activities. The $449.9$462.5 million increase in net cash used in investing activities for the threesix months ended MarchJune 31,30, 2026, compared to the threesix months ended MarchJune 31,30, 2025, was primarily due to (i) $444.4 million in cash paid, net of cash acquired, in connection with the J-W Power Acquisition and (ii) a $5.9$20.1 million increase in capital expenditures for purchases of new compression units, overhauls and major improvements, and purchases of other equipment.equipment, partially offset by (iii) a $1.5 million increase in insurance recovery proceeds.
Net cash provided by (used in) financing activities. The $424.4$410.5 million increase in net cash provided by financing activities for the threesix months ended MarchJune 31,30, 2026, compared to the threesix months ended MarchJune 31,30, 2025, primarily was due to (i) a $422.7$417.6 million increase in net borrowings under the Credit Agreement, which was primarily used for the J-W Power Acquisition, (ii) aan $4.4$8.8 million decrease in Preferred Unit distributions, and (iii) a $2.2$3.2 million decrease in cash paid related to the net settlement of unit-based awards, partially offset by (iv) aan $4.5$18.7 million increase in common unit distributions, and (v) a $0.2 million increase in deferred financing costs.distributions.
As of MarchJune 31,30, 2026, we had outstanding borrowings under the Credit Agreement of $1.25$1.21 billion and, after accounting for outstanding letters of credit in the amount of $2.0 million, $497.8$536.9 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 MarchJune 31,30, 2026, we were in compliance with all of our covenants under the Credit Agreement.
As of MayJuly 1,31, 2026, we had outstanding borrowings under the Credit Agreement of $1.22$1.19 billion and outstanding letters of credit of $2.0 million.
As of MarchJune 31,30, 2026, we had $1.0 billion and $750.0 million aggregate principal amount outstanding on our Senior Notes 2029 and Senior Notes 2033, respectively.
During the threesix months ended MarchJune 31,30, 2026, distributions of $48$97 thousand were reinvested under the DRIP resulting in the issuance of 1,9003,694 common units. Such distributions are treated as non-cash transactions in the accompanying unaudited condensed consolidated statements of cash flows included under Part I, Item 1 “Financial Statements” of this report.
USAC insider buying and selling (Form 4)
Since 2026-04-11, insiders reported open-market purchases in 1 Form 4 filing (1 insider, 2 trade dates, 10,000 shares, about $262.2K) and open-market sales in 0 filings. Net open-market shares: 10,000 (purchases minus sales); net value about $262.2K.Totals add up every open-market (code P and S) line in those filings, using the prices reported in the filings. Awards, option exercises, tax withholding and gifts are listed below but not counted.
| Trade date | Insider | Transaction | Shares | Price | Value |
|---|---|---|---|---|---|
| 2026-08-21 | Whitehurst Bradford D. |
Open-market purchase | 6,000 | $26.10 | $156.6K |
| 2026-08-20 | Whitehurst Bradford D. |
Open-market purchase | 4,000 | $26.40 | $105.6K |
| 2026-06-23 | Porter Christopher W |
Grant/award | 20,000 | — | — |
| 2026-04-28 | Holotik Jim |
Grant/award | 2,500 | — | — |
Well-known investors holding USAC (13F)
| Investor | Quarter | Shares | Reported value | % of their 13F | Change vs prior quarter |
|---|---|---|---|---|---|
| Citadel Advisors (Ken Griffin) | 2026-06-30 | 348,839 | $9.2M | 0.01% | Added 185% |