PUMP 10-K & 10-Q changes, risk factors and insider trading

Demand for most of our services depends substantially on the level of capital expenditures in the Permian Basin by companies in the oil and natural gas industry.industry AsActivity alevels result,and spending by our operationscustomers areand, dependentcorrespondingly, on the levels of capital spending and activity in oil and gas exploration, development and production. Demanddemand for our servicesservices, is largely dependent on oil and natural gas prices, and our customers’ well completion budgets and rig count. Prolonged low oil and natural gas prices would generally depress the level of oil and natural gas exploration, development, production, and well completion activity and would result in a corresponding decline in the demand for the completion services that we provide. Historically, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. The average WTI oil price per barrel was approximately $76,$65, $78$76 and $94$78 for the years ended December 31, 2025, 2024, 2023, and 2022,2023, respectively. In 2023,2025, theprice volatility continued and overall decline incrude oil and natural gas prices causedgenerally adeclined, reductioncontributing to reductions in our customers’ spending and associated drilling and completion activities, which has had and may continue to have an adverse effect on our revenue and cash flows, if the WTI oil price remains highly volatile or declines further in the future. Such trends are expected to continue in 2026. In addition, such volatility and reduction in our customers’ spending and associated drilling and completion activities could also reduce the prices we receive for our services and impact the number of fleets that we are able to deploy, which would also have an adverse effect on our revenue and cash flows. See “The cyclical nature of the oil and natural gas industry may cause our operating results to fluctuate.”

•the level of prices, and expectations about future prices, of oil and natural gasgas, including a potential increase in Venezuelan oil supply and any related impact on global oil prices and domestic oil production;

•domestic and foreign governmental approvals and regulatory requirements and conditions, including tighter emissions standards in the energy industry and proposed or existing tariffs;

•political or civil unrest in the United States or elsewhere, including the Russia-Ukraine war and the conflict in the Israel-Gaza region and related instability in the Middle East, including from Houthi rebels in Yemen, and tensions with IranIran, and U.S. intervention in Venezuela;

•technical advances affecting energy consumptionconsumption, including resulting from artificial intelligence (“AI”);

We derive substantially all of our revenues from companies in the oil and natural gas E&P industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and natural gas prices. We have experienced, and may in the future experience, significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. For example, aduring 2025 and into early 2026, price volatility has continued and crude oil prices have generally declined. If such prices do not improve or decline in oil and gas prices, combined with adverse changes in the capital and credit markets, could cause manyfurther, E&P companies to significantlymay reduce their 2020 and 2021 capital budgets and drilling activity. This could result in a significant decline in demand for energy services and could adversely impact the prices energy service companieswe can charge for theirour services.services and impact the number of fleets that we are able to deploy. These factors have in the past materially and adversely affected our business, results of operations and financial condition.condition and may do so in the future. In addition, a majoritymaterial portion of the service revenue we earn is based upon a charge for a relatively short period of time (for example, a day, a week or a month) for the actual period of time theour service is provided to our customers. ByAcross contractingour businesses, we consider contracts with term length of twelve months or more to be long-term contracts. We occasionally obtain longer-term contractual arrangements for certain of our hydraulic fracturing services and our PROPWRSM business line typically contracts for services on a short‑termlong-term basis, we are exposed to the risks of a rapid reduction in market prices and utilization and resulting volatility in our revenues.basis.

Our operations are geographically concentrated in the Permian Basin. For the years ended December 31, 2024,2025, 20232024 and 2022,2023, approximately 98.5%,100.0%, 98.1%98.5% and 98.3%,98.1%, respectively, of our revenues were attributable to our operations in the Permian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from or drilling and completions activity with respect to wells in the Permian Basin caused by weather, significant governmental regulation, processing or transportation capacity constraints, market limitations, curtailment of production or interruption of the processing or transportation of oil and natural gas produced from the wells in these areas. For example, winter weather conditions in January 2026 across the Permian Basin have resulted in a multi-day suspension of substantially all of our operations, which may negatively impact our results of operations in the first quarter of 2026. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our operations, we could experience any of the same conditions at the same time, resulting in a relatively greater impact on our revenue than they might have on other companies that have more geographically diverse operations.

A prolonged economic slowdown or recession in the United States, adverse events relating to the energy industry or regional, national and global economic conditions and factors, particularly a further slowdown in the E&P industry, could negatively impact our operations and therefore adversely affect our results. The risks associated with our business are more acute during periods of economic slowdown or recession because such periods may be accompanied by decreased exploration and development spending by our customers, decreased demand for oil and natural gas and decreased prices for oil and natural gas. For example, decreases in prices of oil and natural gas and/or our customers’ spending and activity levels could reduce the prices we receive for our services and impact the number of fleets that we are able to deploy, which would have an adverse effect on our revenue, cash flows, profitability and growth.

The energy service industry is subject to the introduction of new drilling and completion techniques and services using new technologiestechnologies, including artificial intelligence,AI, some of which may be subject to patent or other intellectual property protections. As competitors and others use or develop new or comparable technologies in the future, we may lose market share or be placed at a competitive disadvantage. For example, many E&P companies, including our customers, are transitioning to a lower emissions operating environment and may require us to invest in equipment with lower emissions profiles. The transition to lower emissions equipment is capital intensive and could require us to convert all our conventional Tier II equipment to lower emissions equipment. If we are unable to quickly transition to lower emissions equipment, the demand for our services could be adversely impacted. For example, many E&P companies, including our customers, are transitioning to a lower emissions operating environment and may require us to invest in equipment with lower emissions profiles. Further, we may face competitive pressure to further develop, implement or acquire and deploy certain technology improvements at a substantial cost, such as ouradditional FORCE® electric-powered hydraulic fracturing fleetsfleets. deployed in 2023, or theThe cost of implementingdeploying or purchasing a technology likeadditional FORCE® fleets may be substantially higher than anticipated, and we may not be able to successfully implement the technologies we may purchase.technologies. In fiscal year 2024, we recorded a property and equipment impairment charge of $188.6 million on our conventional Tier II diesel-only hydraulic fracturing pumping unitspumps and associated conventional assets,assets (the "“Tier II Units"”) because we determined that the marketability of our Tier II Units had declined due to decreasing customer demand for and related pricing pressures on such equipment, among other factors. In 2022, we recorded a property and equipment impairment charge of $57.5 million on our DuraStim® electric-powered equipment because they did not meet our expectations. Some of our competitors have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and develop and implement new products on a timely basis or at an acceptable cost. We cannot be certain that we will be able to develop and implement new technologies or products on a timely basis or at an acceptable cost. Limits on our ability to develop, effectively use and implement new and emerging technologies could have a material adverse effect on our business, financial condition, prospects or results of operations.

Our operations require substantial capitalcapital, and we may be unable to obtain needed capital or financing on satisfactory terms, or at all, which could limit our ability to grow.

The energy service industry is capital intensive. In conducting our business and operations, we have made, and expect to continue to make, substantial capital expenditures.expenditures, including capital expenditures to maintain our fleet and costs related to purchase options under certain leases. Our total capital expenditures incurred were approximately $133.4$281.2 million, $310.0$133.4 million and $365.3$310.0 million during the years ended December 31, 2025, 2024, 2023, and 2022.2023. Moreover, our PROPWRSM business has required us to make substantial capital expenditures for new power generation units, and these expenditures are expected to increase as we order and deploy additional units, among other business related expenditures. During the year ended December 31, 2025, we incurred approximately $198.4 million of capital expenditures for our PROPWRSM business. We have historically financed capital expenditures primarily with funding from cash on hand, cash flow from operations, equipment and vendor financing and borrowings under our credit facility. Approximately $81.1 million of our PROPWRSM capital expenditures incurred in fiscal year 2025 were financed through vendor financing. We may be unable to generate sufficient cash from operations and other capital resources to maintain planned or future levels of capital expenditures which, among other things, may prevent us from acquiring new equipment (including power generation equipment or hydraulic fracturing equipment with a lower emissions profile) or properly maintaining our existing equipment. Any disruptions or volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. Our Borrowing Base (as defined below) was $164.1$167.7 million as of December 31, 2024.2025. If our customer activity levels decline in the future resulting in a decrease in our eligible accounts receivable, our Borrowing Base could decline. This could put us at a competitive disadvantage or interfere with our growth plans. Further, our actual capital expenditures incurred could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of liquidity we have available, we could be required to seek additional sources of capital, which may include debt financing, joint venture partnerships, sales of assets, offerings of debt or equity securities or other means. We may not be able to obtain any such alternative source of capital. We may be required to curtail or eliminate contemplated activities. If we can obtain alternative sources of capital, the terms of such alternative may not be favorable to us. In particular, the terms of any debt financing may include covenants that significantly restrict our operations. Our inability to grow as planned may reduce our chances of maintaining and improving profitability.

Concerns over global economic conditions, geopolitical issues (including the Russia-Ukraine war and conflicts in the Middle East, including tensions with Iran), public health crises, interest rates, inflation, the availability and cost of credit in the United States, foreign financial markets and potential changes in U.SU.S. trade policy, including the imposition of tariffs and the resulting consequencesconsequences, have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, could precipitate an economic slowdown. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. In addition, there is currently significant uncertainty about the future relationship between the United States and various other countries, including changes arising as a result of the current presidential administration, with respect to trade policies, treaties, tariffs, taxes, and other limitations on cross-border operations. The historically unpredictable nature of oil and natural gas prices, and particularly the volatility over the past two years have caused a reduction in our customers’ spending and associated drilling and completion activities, which had and may continue to have an adverse effect on our revenue and cash flows. For example, decreases in commodity prices and/or our customers’ spending and activity levels could reduce the prices we receive for our services and impact the number of fleets that we are able to deploy, which would have an adverse effect on our revenue, cash flows, profitability and growth. If the economic climate in the United States or abroad deteriorates or remains uncertain, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids can be sold, which could affect the ability of our customers to continue operations and adversely impact our results of operations, liquidity and financial condition.

Our business is capital intensive and our existing and future indebtedness, whether incurred into connectionfund withsuch capital expenditures or to fund acquisitions, operations or otherwise, may adversely affect our operations and limit our growth, and we may have difficulty making debt service payments on such indebtedness as payments become due. Our level of indebtedness may affect our operations in several ways, including the following:

• the covenants that are contained in the agreements governing our indebtedness could limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments;

• our debt covenants could also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

• any failure to comply with the financial or other debt covenants, including covenants that impose requirements to maintain certain financial ratios, could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable;

• our level of debt could impair our ability to obtain additional financing, or obtain additional financing on favorable terms in the future for working capital, capital expenditures, research and development efforts, potential strategic acquisitions or other general corporate purposes;

• our business may not generate sufficient cash flow from operations to enable us to meet our obligations under our indebtedness.

Furthermore, interest rates on future indebtedness could be higher than current levels, causing our financing costs to increase accordingly. Changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on the price of our shares,shares and our ability to issue equity or incur debt.

Restrictions in our ABL Credit FacilityFacility, our Caterpillar Equipment Loan Agreement, our Stonebriar Equipment Lease Facility, and any future financing agreements may limit our ability to finance future operations or capital needs or capitalize on potential acquisitions and other business opportunities.

The operating and financial restrictions and covenants in our credit facilityfacility, Caterpillar Equipment Loan Agreement, Stonebriar Equipment Lease Facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our ABL Credit Facility restricts or limits our ability to:

Furthermore, our ABL Credit Facility contains certain other operating and financial covenants. Our ability to comply with the covenants and restrictions contained in the ABL Credit Facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our ABL Credit Facility, a significant portion of our indebtedness may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. Further, our borrowing base, as redetermined monthly, has a borrowing base of the sum of 85.0%85% to 90.0%90% of eligible accounts receivable and 80% of eligible unbilled accounts (up to a maximum of 25% of the borrowing base), in each case, depending on the credit ratings of our accounts receivable counterparties,counterparties and subject to certain customer concentration limits, less customary reserves (the “Borrowing Base”). Changes to our operational activity levels or customer concentration levels have an impact on our total eligible accounts receivable, which could result in significant changes to our borrowing base and therefore our availability under our ABL Credit Facility. If our customer activity declines in the future, our borrowing base could decline. If our borrowing base is reduced below the amount of our outstanding borrowings, we will be required to repay the excess borrowings immediately on demand by the lenders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent replacement of our ABL Credit Facility or any new indebtedness could have similar or greater restrictions. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facility and Other Financing Arrangements.”

Changes in future market conditions and prolonged periods of low utilization, changes in technology or the sale of assets below their carrying value may cause us to experience losses in our results of operations. These events could result in the recognition of impairment charges or losses from asset sales that negatively impact our financial results. Significant impairment charges or losses from asset sales as a result of a decline in market conditions or otherwise could have a material adverse effect on our results of operations in future periods. For example, in fiscal year 2024, we recorded property and equipment impairment charges of $188.6 million in connection with our Tier II Units and $23.6 million in connection with the goodwill in our wirelineWireline operating segment. In 2022, we recorded property and equipment impairment charges of $57.5 million in connection with our DuraStim® electric powered hydraulic fracturing equipment. If oil and natural gas prices trade at depressed price levels, and our equipment remains idle or under-utilized, the estimated fair value of such equipment may decline, which will result in additional impairment expense in the future.

Our operations are subject to unforeseen interruptions and hazards inherent in the oil and natural gas industry,and mobile power generation industries, for which we may not be adequately insuredinsured, and which could cause us to lose customers and substantial revenue.

Our operations are exposed to the risks inherent to our industry, such as equipment defects, vehicle accidents, worksite injuries to our or third-party personnel, fires, explosions, blowouts, surface cratering, uncontrollable flows of gas or well fluids, pipe or pipeline failures, abnormally pressured formations and various environmental hazards, such as oil spills and releases of, and exposure to, hazardous substances. For example, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including hydrochloric acid and other chemical additives. In addition, our operations are exposed to potential natural disasters, including blizzards, tornadoes, storms, floods, other adverse weather conditions and earthquakes. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigations and penalties or other damage resulting in curtailment or suspension of our operations or the loss of customers. For example, in January 2025, we experienced an accident at a customer site that resulted in one fatality and injured two others, which temporarily halted operations and isresulted subjectin toour routinebeing investigationissued a citation by OSHA.the Occupational Safety and Health Administration. The cost of managing such risks may be significant. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our environmental or safety record as unacceptable, which could cause us to lose customers and substantial revenues.

Our insurance may not be adequate to cover all losses or liabilities we may suffer. We are also self-insured up to $10 million per occurrence for certain losses arising from or attributable to fire and/or explosion at wellsites that do not have qualified fire suppression measures.losses. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In addition, sub‑limits have been imposed for certain risks. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we are not fully insured, it could have a material adverse effect on our business, results of operations and financial condition. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position.

Terrorist activities, anti‑terrorist efforts, other armed conflicts and political or civil unrest, including the Russia-Ukraine war and conflicts in the Middle East, could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors or disruptions of fuel supplies and markets if pipelines, production facilities, processing plants, refineries or transportation facilities are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas,gas and power generation, which, in turn, could also reduce the demand for our services. Terrorist activities, the threat of potential terrorist activities, political or civil unrest and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.

WeOutside of our mobile power business, we operate with most of our customers under master service agreements (“MSAs”). We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for, including control and removal of, pollution or contamination which originates above surface and originates from our equipment or services. In our power business, we typically operate under power purchase agreements or power-as-a-service agreements and these agreements typically have liability allocation provisions that are similar to our MSAs. Our customer assumes responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. We may have liability in such cases if we are negligent or commit willful acts. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer‑owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into an MSA with terms that vary from the above allocations of risk. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in us being named as a defendant in lawsuits asserting large claims. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation.

We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruptiondisruptions, reputational harm and/or financial loss.

The oilOur and naturalour gascustomers’ industrybusinesses hashave become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and process and record operational and accounting data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased.

The frequency and magnitude of cybersecurity attacks is increasing and attackers have become more sophisticated. Cybersecurity attacks are similarly evolving and includeinclude, without limitationlimitation, use of malicious software, surveillance, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligenceAI), attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidentialconfidential, personally identifiable or otherwise protected information and corruption of data. We may be unable to anticipate, detect or prevent future attacks, particularly as the methodologies used by attackers change frequently or are not identifiable until deployed. We may also be unable to investigate or remediate incidents as attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection, and to remove or obfuscate forensic evidence.

The U.S. government has issued public warnings indicating that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and confidential information, personalpersonally identifiable information and other data, or other disruption of our business operations. In addition, certain cyber incidents, such as unauthorized surveillance, may remain undetected for an extended period. Our systems and insurance coverage (if any) for protecting against cyber security risks, including cyberattacks, may not be sufficient and may not protect against or cover all of the losses (including potential reputational loss) we may experience as a result of the realization of such risks. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate the effects of cyber incidents.

We utilize technologies, controls and procedures, as well as internal staff and external service providersproviders, to protect our systems and data, to identify and remediate vulnerabilities and to monitor and respond to threats. However, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. No security measure is infallible. If we or the third parties with whom we interact were to experience a successful attack, the potential consequences to our business, workforce and the communities in which we operate could be significant, including financial losses, regulatory fines,fines or penalties, loss of business, an inability to settle transactions or maintain operations, litigation costs, compliance and remediation costs, disruptions related to investigation, and significant damage to our reputation.

We may growpursue through acquisitions and/oracquisitions, internal expansions,expansions or other strategic transactions, and our failure to properly plan and manage such growth may adversely affect our performance.

We have completed and may in the future pursue,pursue asset acquisitions oracquisitions, acquisitions of businesses.businesses or other strategic transactions. We have internally expanded and may in the future expand into new lines of business, such as our new PROPWRSM business. Any acquisition of assets or businesses, or expansion into new lines of business or other strategic transactions involves potential risks, including the failure to realize expected profitability, growth or accretion; environmental or regulatory compliance matters or liability; title or permit issues; the incurrence of significant charges, such as impairment of goodwill, property and equipment orequipment, intangible assets or restructuring charges; and the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate. The process of upgrading acquired assets to our specifications and integrating acquired assets or businesses may also involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a significant amount of time and resources and may divert management’s attention from existing operations or other priorities. For example, insince 2024,2023, we acquired the assets and operations of AquaProp,Par Five Energy Services LLC and weAqua areProp, inLLC, thewhich process ofrequired fully integrating all parts of the acquired business into our operations. In late 2024, we also started a new line of business to provide power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers. This new line of business has not begun any revenue-generating activities yet.

We must plan and manage any acquisitions andacquisitions, expansions or other strategic transactions effectively to achieve revenue growth and maintain profitability in our evolving market. Any failure to manage acquisitions andacquisitions, expansions or other strategic transactions effectively or integrate acquired assets or businesses into our existing operations successfully, or to realize the expected benefits from ansuch acquisitiontransactions or minimize any unforeseen operational difficulties, could have a material adverse effect on our business, financial condition, prospects or results of operations.

The U.S. inflation rate steadily increased in 2021 and 2022 before decreasing to a moderate level in 2023 through 2024.2025. Inflation in wages, materials, parts, equipment and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure, particularly if we are unable to achieve commensurate increases in the prices we charge our customers for our products and services. In addition, the existence of inflation in the economy has the potential to result in higher interest rates, which could result in higher borrowing costs, supply shortages, increased costs of labor, weakening exchange rates and other similar effects. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates in 2023 followed by decreases in 2024,2024 and 2025, and the U.S. Federal Reserve may maintain high benchmark interest rates intothroughout 20252026 in an effort to curb inflationary pressure on the costs of goods and services across the U.S., which could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt the financial and operating results of our business. To the extent elevated inflation remains, and as a result potential changes in U.SU.S. trade policy, including the imposition of tariffs and the resulting consequences, we may experience further cost increases for our operations, including labor costs and equipment. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to timely pass-through the cost increases to our customers, would negatively impact our business, financial condition and results of operations.

The majority of our revenue is generated from our hydraulic fracturing services. Due to the large percentage of our revenue historically derived from our hydraulic fracturing services with recurring customers and the limited availability of our fracturing units, we have had some degree of customer concentration. Our top ten customers represented approximately 75.3%,84.5%, 85.5%75.3% and 91.2%85.5% of our consolidated revenue for the years ended December 31, 2024,2025, 20232024 and 2022,2023, respectively. It is likely that we will depend on a relatively small number of customers for a significant portion of our revenue in the future. If awe major customer failscease to paydo us,work revenuefor woulda be impacted andcustomer, our operating results and financial condition couldwould be harmed.adversely Additionally,affected ifunless we weresuccessfully toredeploy losethe anyequipment. materialOur customer, we may not be ableinability to redeploy our equipment at similar utilization or pricing levels and such loss could have an adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels. Similarly, if a major customer fails to pay us, our revenue would be impacted and our operating results and financial condition could be harmed. ExxonMobil, Occidental Petroleum Corporation, EOG Resources, Inc. and Permian Resources Corporation accounted for 24.9%, 13.7%, 12.1%, and 11.2%, respectively, of our revenue for the year ended December 31, 2025. Two of our fleets that currently perform services for ExxonMobil’s subsidiary XTO are governed by an agreement that will expire in approximately late 2026. At this time, we do not expect such agreement to be renewed or extended and, if we are not able to procure additional work from XTO, we will be required to redeploy the equipment associated with the affected fleets with other customers, exposing us to the risks described below associated with a delay or inability to redeploy our equipment.

Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. The amount of equipment available may exceed demand, which could result in active price competition. In addition, somefrom E&Ptime companiesto havetime, commencedour completingcustomers theirand wellspotential usingcustomers acquire equipment and utilize their own hydraulicpersonnel fracturingto equipmentperform andservices personnel.similar or equivalent to the services we offer. Any increase in the development and utilization of in‑housesuch fracturingin-house capabilitiesservices by our customers or potential customers could decrease the demand for our services and have a material adverse impact on our business.

This discussion of our results omits our results of operations and cash flows for the year ended December 31, 2022,2023, and the comparison of our results of operations for the years ended December 31, 2023,2024, and 2022,2023, which may be found in our Annual Report on Form 10-K for the year ended December 31, 2023,2024, filed with the SEC on MarchFebruary 13,20, 2024.2025.

Our completion services includes our operating segments comprised of hydraulic fracturing, wireline and cementing operations. Our hydraulic fracturing operations account for approximately 75.6%73.2% of our total revenues and operations. Our total available hydraulic horsepower (“HHP”) at December 31, 2024,2025, was 1,556,5001,259,500 HHP, which was comprised of 450,000445,000 HHP of our Tier IV Dynamic Gas Blending (“DGB”) dual-fuel equipment, 294,000312,000 HHP of FORCE® electric-powered equipment and 812,500502,500 HHP of conventional Tier II equipment. Our hydraulic fracturing fleets range from approximately 50,000 to 80,000 HHP depending on the job design and customer demand at the wellsite. Our equipment has been designed to handle the operating conditions commonly encountered in the Permian Basin and the region’s increasingly high-intensity well completions (including simultaneous hydraulic fracturing ("Simul-Frac"), which involves fracturing multiple wellbores at the same time), which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well. With the industry transition to lower emissions equipment and Simul-Frac, in addition to several other changes to our customers' job designs, we believe that our available fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at wellsites. In addition, in 2021 and 2022,2021, we committedbegan to additional conversions oftransition our Tierfleet IIfrom traditional equipment to Tier IV DGB, and to purchase new Tier IV DGB dual-fuel equipment. As such, we entered into conversion and purchase agreements with our equipment manufacturers and have received all of the converted and new Tier IV DGB dual-fuel equipment by the end of 2023, representing 450,000 HHP of our Tier IV DGB dual-fuel equipment as of December 31, 2024. In 2022, we entered into three-year electric fleet leases which commenced in 2023 and 2024 for four FORCE® electric-powered hydraulic fracturing fleets worth of equipment with 60,000 HHP per fleet and in June 2024, we entered into an additional three-year lease for aone fifthmore FORCE® electric-powered hydraulic fracturing fleet worth of equipment with 72,000 HHP.HHP (collectively the “Electric Fleet Leases”). As of December 31, 2024,2025, we have received 294,000312,000 HHP of FORCE® electric-powered equipment representing fourfive fleets and a portionworth of the fifth fleet. We currently expect to receive the remaining equipment associated with the fifth fleet in the first half of 2025.equipment.

On November 1, 2024, we sold our cementing business located in Vernal, Utah, to a business owned by a former employee as part of a strategic repositioning. We received a promissory note for $13.0 million as consideration.consideration, and recorded a gain on disposal of $8.2 million related to the sale of the business. The note receivable iswas secured by substantially all assets of the formerdivested employee’s businessoperations and the former employee’s ownership interests in and distributions from the business. The note receivable iswas to be paid to the Company in quarterly installments with interest of 10% per annum from March 31, 2025, to December 31, 2029.2029, Webut recordedwas afully gainrepaid onwith disposalinterest ofin $8.2December million related to the sale of the business.2025. The former employee was part of our cementing operations until November 1, 2024, and is no longer affiliated with the Company.

WeAs haveof historicallyDecember 31, 2025, we conducted our business through four operating segments: hydraulicHydraulic fracturing,Fracturing, wireline,Wireline, cementingCementing and coiledPower tubing.Generation, all of which meet the criteria of a reportable segment. Prior to the third quarter of fiscal year 2025, our Power Generation segment did not meet the quantitative thresholds for a reportable segment and prior to the fourth quarter of fiscal year 2023,2024, our operatingCementing segmentssegment metdid not meet the aggregationquantitative criteriathresholds andfor were aggregated into the “Completion Services”a reportable segmentsegment. andAccordingly, our coiled tubing operations (which were divested in September 2022)they were shown in the “All Other” category. Effective inas of the the fourththird quarter of fiscal year 2023,2025 we revised our segment reporting as we determined that our three operating segments no longer met the criteria to be aggregated. Inand the fourth quarter of fiscal year 2024, wePower formed PROPWR to provide power generation services to oilGeneration and gasCementing, producersrespectively, andare non-oil and gas applications suchshown as general industrial projects and data centers. This new subsidiary has ordered equipment, but it has not yet begun revenue-generating activities. Our hydraulic fracturing, wireline and cementing operatingreportable segments since they meet the criteria of a reportable segment. Our divested coiled tubing and our newly formed power generation services segments do not meet the reportable segment criteria and are included within the “All Other” category. Additionally, our corporate administrative activities do not involve business activities from which it may earn revenues and its results are not regularly reviewed by the Company’s Chief Operating Decision Maker (the “CODM”) when making key operating and resource decisions. As a result, corporate administrative expenses have been included under “Reconciling Items.” For additional financial information on our reportable segments presentation, please see reportable segment information in Part II - Item 8, “Financial Statements and Supplementary Data.”

On April 22, 2024, we entered into a sub-agreement for hydraulic fracturing services with XTO, a wholly owned subsidiary of ExxonMobil, pursuant to which we will provide hydraulic fracturing, wireline and pumpdown services with two committed FORCE® electric-powered hydraulic fracturing fleets withand the option to add a third FORCE® fleet (also with wireline and pumpdown services) for a periodcertain number of three years or for contracted hours, whichever occurs lasthours with respect to each fleet, subject to certain termination and release rights. This agreement will expire in approximately late 2026. At this time, we do not expect such agreement to be renewed or extended and, if we are not able to procure additional work from XTO, we will be required to redeploy the equipment associated with the affected fleets with other customers.

Sustained levels of high inflation likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including interest rates, labor costs and equipment. We cannot predict any future trends in the rate of inflation and crude oil prices. A significant increase in or continued high levels of inflation, to the extent we are unable to timely pass-through the cost increases to our customers, further declines in crude oil prices, or potential changechanges in U.Sthe United States’ trade policy, including the imposition of tariffs and the resulting consequences, would negatively impact our business, financial condition and results of operations. See Part II, Item 1A. “Risk Factors—We may be adversely affected by the effects of inflation.”

Government regulations and investors are demanding the oil and gas industry transition to a lower emissions operating environment, including upstream and energy service companies. As a result, we are working with our customers and equipment manufacturers to transition our equipment tointo a lower emissions profile. Currently, a number of lower emission solutions for pumping equipment, including Tier IV DGB dual-fuel, FORCE® electric, direct drive gas turbine and other technologies have been developed, and we expect additional lower emission solutions will be developed in the future. We are continually evaluating these technologies and other investment and acquisition opportunities that would support our existing and new customer relationships. The transition to lower emissions equipment is quickly evolving and will be capital intensive. Over time, we may be required to convert substantially all of our conventional Tier II equipment to lower emissions equipment. We have transitioned our hydraulic fracturing available equipment portfolio from approximately 10% lower emissions equipment in 2021 to approximately 35% in 2022, 60% in 2023, 70% in 2024, and expect to increase to approximately 75% by the end of the first quarter of 2025. To the extent any of our customers have certain expectations or requirements with respect to emissions reductions from their contractors, if we are unable to continue quickly transitioning to lower emissions equipment, the demand for our services could be adversely impacted.

If the Permian Basin rig count and market conditions improve, including improved pricing for our services and labor availability, and we are able to meet our customers' lower emissions equipment demands, we believe our operational and financial results will also continue to improve. If the rig count or market conditions do not improve or decline in the future, and we are unable to increase our pricing or pass-through future cost increases to our customers, there could be a material adverse impact on our business, results of operations and cash flows.

Our results of operations have historically reflected seasonal tendencies, typically in the fourth quarter, relating to the holiday season, inclement winter weather and the exhaustion of our customers' annual budgets. As a result, we typically experience declines in our operating and financial results in November and December, even in a stable commodity price and operations environment.

•net lossincome was $137.9$0.8 million, compared to net incomeloss of $85.6$137.9 million for the year ended December 31, 2023.2024. Diluted net lossincome per common share was $1.31,$0.01, compared to diluted net incomeloss of $0.76$1.31 for the year ended December 31, 2023.2024. Net loss for the year ended December 31, 2024 included property and equipment impairment expense of $188.6 million related to our conventional Tier II diesel-only hydraulic fracturing pumping units and associated conventional assets (“Tier II Units”) and goodwill impairment expense of $23.6 million related to the goodwill in our wirelineWireline operating segment. Adjusted EBITDA of approximately $283.2$208.4 million decreased 29.9%,26.4%, compared to $404.0$283.2 million for the year ended December 31, 20232024 (see reconciliation of Adjusted EBITDA to net income in the subsequent section “How We Evaluate Our Operations”);

•net cash provided by operating activities less net cash used in investing activities improveddeclined by $106.6$15.4 million compared to 20232024; and

•our total liquidity was $160.9$205.4 million as of December 31, 2024.2025. consisting of cash and cash equivalents of $50.4$91.3 million and remaining availability of $110.5$114.1 million under our ABL Credit Facility; we had $45.0total millionoutstanding debt of borrowings$122.6 million as of December 31, 2024,2025, comprising of $45.0 million of borrowings under our ABL Credit Facility; and $77.6 million of equipment financing interim and term loans under the Caterpillar Equipment Loan Agreement (as defined below).

Completion services includesinclude our hydraulic fracturing, wireline and cementing operations. We primarily provide these services to E&P companies in the Permian Basin. We also provide turnkey power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers. During the year ended December 31, 2024,2025, our hydraulic fracturing, wirelinewireline, cementing and cementingpower generation operations accounted for 75.6%,approximately 14.1%,73.2%, 16.5%, 10.3%, and 10.3%0% of our total revenue, respectively. Our completion services equipment has been designed to handle Permian Basin specific operating conditions and the region’s increasingly high‑intensity well completions, which are characterized by longer horizontal wellbores, more frac stages per lateral and increasing amounts of proppant per well. Our power generation operations consist of mobile natural gas-fueled power generation equipment, including turbine generator sets, reciprocating engines, auxiliary equipment and battery energy storage solution equipment. We plan to continually reinvest in our equipment to ensure optimal performance and reliability.

We generate revenue predominantly through our completion services, and more specifically, by providing hydraulic fracturing services to our customers. We operate a fleet of mobile hydraulic fracturing, wireline and cementing units and other auxiliary equipment to perform completion services to E&P companies. Additionally, we generate revenue through our PROPWRSM power generation business by providing turnkey power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers using mobile power generation equipment installed at customers’ sites. These services are generally provided through contractual arrangements in which we set a price per unit of power generated or a price per period and a minimum quantity of power per period under our contracts. We also provide personnel and services that are tailored to meet each of our customers’ needs.

Demand for our completion services is largely dependent on oil and natural gas prices, and our customers’ well completion budgets and rig count. Our revenue, profitability and cash flows are highly dependent upon prevailing crude oil prices and expectations about future prices. For many years, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. The average WTI oil price per barrel was approximately $65, $76, $78, and $94$78 for the years ended December 31, 2025, 2024, 2023, and 2022,2023, respectively. In January 2025,2026, the WTI oil price was approximately $74$60 per barrel. If the WTI oil price declines in the future or remains highly volatile, demand for our services may be negatively impacted, which could result in a significant decrease in our future profitability and cash flows. We monitor oil and natural gas prices and the Permian Basin rig count to enable us to more effectively plan our business and forecast the demand for our services.

Direct Labor Costs. Payroll and benefit expenses related to our crews and other employees that are directly or indirectly attributable to the effective delivery of services are included in our operating costs. Direct labor costs amounted to 30.2%28.5% and 28.7%30.2% of total costs of service for the years ended December 31, 2024,2025, and 2023,2024, respectively. The increasedecrease in our direct labor costs percentage is driven by wagethe adjustmentsimplementation andof higherreactive headcountcost resultingreductions fromto businessalign acquisitions.our costs with the decrease in customer activity experienced in fiscal year 2025.

Expendables. Expendables include the product and freight costs associated with proppant, chemicals and other consumables used in our completion services and other operations. These costs comprise a substantial variable component of our service costs, particularly with respect to the quantity and quality of sand and chemicals demanded when providing hydraulic fracturing services. Expendable product costs comprised approximately 25.7%26.8% and 32.9%25.7% of total costs of service for the years ended December 31, 2024,2025, and 2023,2024, respectively. The percentage decreaseincrease in our expendables was primarily attributable to certain customers electing to directly source sand and the associatedimpact logistics.of general cost inflation.

Other Direct Costs. We incur other direct expenses related to our service offerings, including the costs of fuel, repairs and maintenance, general supplies, equipment rental, lease costs on our FORCE® electric-powered hydraulic fracturing fleets, and other miscellaneous operating expenses. Fuel is consumed both in the operation and movement of our equipment. Repairs and maintenance costs are expenses directly related to upkeep of equipment, which have been amplified by the demand for higher horsepower jobs. Capital expenditures to upgrade or extend the useful life of equipment are capitalized and are not included in other direct costs. Other direct costs were 44.1%44.7% and 38.4%44.1% of total costs of service for the years ended December 31, 2024,2025, and 2023,2024, respectively. The percentage increase in our other direct costsexpendables was primarily attributable to leasethe costsimpact onof ourgeneral FORCE®cost fleets.inflation.

Adjusted EBITDA and Adjusted EBITDA margin are supplemental measures utilized by our management and other users of our financial statements such as investors, commercial banks, and research analysts, to assess our financial performance because it allows us and other users to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization), nonrecurring expenses/(income) expenses and items outside the control of our management team (such as income taxes). Adjusted EBITDA and Adjusted EBITDA margin have limitations as analytical tools and should not be considered as an alternative to net income (loss), operating income (loss), cash flow from operating activities or any other measure of financial performance presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

(31)Represents amortization of right-of-use assets and interest expense on lease liabilities related to operating leases on our FORCE® electric-powered hydraulic fracturing fleets. This cost is recorded within cost of services in our consolidated statements of operations. We did not have this cost for the year ended December 31, 2022.

(2)Represents noncash impairment ofexpense goodwillon our Tier II Units. This impairment expense is included in our wirelineHydraulic Fracturing operating segment.

(34)Other income for the year ended December 31, 2025 is primarily comprised of direct payment tax refunds and well service tax refunds (net of advisory fees) totaling $3.3 million, a $2.4 million unrealized gain on short-term investment, interest income from note receivable from sale of business of $1.2 million, adjustments to workers' compensation and general liability insurance premiums of $1.0 million, insurance reimbursements of $0.8 million and $1.0 million of other income. Other income for the year ended December 31, 2024 is primarily comprised of tax refunds (net of advisory fees) totaling $5.0 million and insurance reimbursements of $2.0 million, partially offset by a $2.0 million loss to a customer related to an accidental cementing job failure. Other expense for the year ended December 31, 2023 is primarily comprised of settlement expenses resulting from routine audits and true-up health insurance costs totaling approximately $7.4 million and a $2.5 million unrealized loss on short-term investment. Other income for the year ended December 31, 2022 includes tax refunds (net of advisory fees) totaling $10.7 million, a $2.7 million noncash income from fixed asset inventory received as part of a settlement of warranty claims with an equipment manufacturer, and a $1.6 million unrealized loss on short-term investment.

(45)Other general and administrative expense for the years ended December 31, 2024 and 2023 primarily relates to nonrecurring professional fees paid to external consultants in connection with our business acquisitions and legal settlements, net of reimbursements from insurance carriers. Other general and administrative expense for the year ended December 31, 2022 primarily relates to nonrecurring professional fees paid to external consultants in connection with the Company's audit committee review, SEC investigation, shareholder litigation, legal settlements and other legal matters, net of reimbursements from insurance carriers.

In 2024, we conducted our business through four operating segments: hydraulicHydraulic fracturing,Fracturing, wireline,Wireline, cementing,Cementing, and powerPower generationGeneration servicesServices (started in the fourth quarter of fiscal year 2024 and has not begun any revenue-generating activities yet). Our powerPower generation servicesGeneration operating segmentssegment areis shown in the “All Other” category for segment reporting purposes.

(4) For definitions of the non‑GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA margin and reconciliation of Adjusted EBITDA and Adjusted EBITDA margin to our most directly comparable financial measuresmeasure calculated in accordance with GAAP, please read “How We Evaluate Our Operations.”

ThereExcept as set forth below, there have been no material changes to the risk factors disclosed in Part I, Item 1A. of our Form 10-K.

We are a leading integrated energy service company, located in Midland, Texas, focused on providing innovative hydraulic fracturing, wireline and other complementary energy and power generation services to leading upstream oil and gas companies engaged in the exploration and production ("E&P") of North American oil and natural gas resources. Our completions operations are primarily focused in the Permian Basin, where we have cultivated longstanding customer relationships with some of the region’s most active and well‑capitalized E&P companies. The Permian Basin is widely regarded as one of the most prolific oil‑producing areas in the United States, and we believe we are one of the leading providers of completion services in the region. Through our subsidiary, ProPetro Energy Solutions, LLC,LLC ("PROPWR"), we provide turnkey power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers using mobile power generation equipment installed at customers’ sites.

Our completion services include our operating segments comprised of hydraulic fracturing, wireline and cementing operations. Our hydraulic fracturing operations account for approximately 66.1%67.0% of our total revenuesrevenue andfor operationsall segments as of MarchJune 31,30, 2026. Our total available hydraulic horsepower ("HHP") as of MarchJune 31,30, 2026, was 1,254,5001,257,000 HHP, which was comprised of 447,500 HHP of our Tier IV DGB dual-fuel equipment, 312,000 HHP of FORCE® electric-powered equipment and 495,000497,500 HHP of conventional Tier II equipment. Our hydraulic fracturing fleets range from approximately 50,000 to 80,000 HHP depending on the job design and customer demand at the wellsite. Our completions equipment has been designed to handle the operating conditions commonly encountered in the Permian Basin and the region’s increasingly high-intensity well completions (including simultaneous hydraulic fracturing ("Simul-Frac"), which involves fracturing multiple wellbores at the same time), which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well. With the industry transition to lower emissions equipment and Simul-Frac, in addition to several other changes to our customers' job designs, we believe that our available fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at wellsites. In 2021, we began to transition our fleet from traditional equipment to Tier IV DGB dual-fuel equipment. In 2022, we entered into three-year electric fleet leases which commenced in 2023 and 2024 for four FORCE® electric-powered hydraulic fracturing fleets with 60,000 HHP per fleet and in 2024, we entered into an additional three-year lease for a fifth FORCE® electric-powered hydraulic fracturing fleet with 72,000 HHP (collectively the "Electric Fleet Leases"). The equipment under these leases representrepresents all of our FORCE® electric-powered equipment. We currently have 28 wireline units and 2930 cementing units.

In December 2024, we formed PROPWR to provide power generation services and represent our Power Generation operating segment. This subsidiary began revenue-generating activities during the third quarter of fiscal year 2025 and has entered into contractual arrangements with equipment manufacturers to purchase mobile natural gas-fueled power generation equipment, including turbine generator sets, reciprocating engines, auxiliary equipment and battery energy storage solution equipment. We have received certain units of this equipment and anticipate all remaining ordered units will be delivered by year-endlate 2027.fiscal year 2028. As of MarchJuly 31,30, 2026, we had total committed capacity of approximately 240350 megawatts and total delivered or on-order generation capacity of approximately 5501.1 megawatts,gigawatts excluding equipment not yet ordered under the global framework agreement with Caterpillar Inc. described in "Note 13 - Commitments and Contingencies." Our total delivered or on-order power generation equipment is split approximately 70%80% and 30%20% between high-efficiency reciprocating engine generators and low emissions modular turbines, respectively. We continue to actively negotiate additional contracts amid increasing demand for power solutions and to explore various financing alternatives for our power equipment.

On December 31, 2018, we consummated the purchase of certain pressure pumping assets and real property from Pioneer Natural Resources USA, Inc. ("Pioneer") and Pioneer Pumping Services, LLC (the "Pioneer Pressure Pumping Acquisition") in exchange for 16.6 million shares of our common stock and $110.0 million in cash. In May 2024, Pioneer merged with and into a wholly owned subsidiary of Exxon Mobil Corporation ("ExxonMobil") after which ExxonMobil became the owner of these shares.shares until ExxonMobil's sale of these shares in May 2026. The Company currently provides pressure pumping, wireline and other services to ExxonMobil and previously provided such services to Pioneer.

On April 22, 2024, we entered into a sub-agreement for Hydraulic Fracturing Services with XTO Energy Inc., a wholly owned subsidiary of ExxonMobil ("XTO"), pursuant to which we will provide hydraulic fracturing, wireline and pumpdown services with two committed FORCE® electric-powered hydraulic fracturing fleets and the option to add a third FORCE® fleet (also with wireline and pumpdown services) for a certain number of contracted hours with respect to each fleet, subject to certain termination and release rights. We expect this agreement will expire in late 2026. At this time, we do not expect such agreement to be renewed or extended and, if we are not able to procure additional work from XTO, we will be required to redeploy the equipment associated with the affected fleets with other customers. Our inability to redeploy our equipment at similar utilization or pricing levels and such loss could have an adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels. We continue to actively negotiate with other customers and potential customers to redeploy this equipment.

The geopolitical and macroeconomic consequences of the war between Israel, Iran and the United States hashave contributed to significant volatility in crude oil prices, with the spot price per barrel of the West Texas Intermediate ("WTI") average crude oil price increasing to approximately $91 per barrel on average in March 2026 before decreasing to approximately $84 per barrel on average in June 2026 compared to approximately $58 per barrel on average in December 2025 as a result of disruptions to crude oil production in the Middle East and global shipping constraints. In addition, the war between Russia and Ukraine, including the associated sanctions, events in Venezuela and actions by OPEC+ have contributed to volatility in supply and demand dynamics for crude oil and associated volatility in crude oil pricing in recent years. Additionally, we have recently experienced aan decreaseincrease in the Permian Basin rig count to 247261 at the end of 2025 and a further decrease to 242 at the end of MarchJune 2026, according to the Baker Hughes Company, after experiencing several months of rig count decreases from 2023 onwards, which resultedhas inincreased less predictablethe demand for completion services in the near term although demand remains less predictable and the pressure on pricing of our services.services continues to persist.

Sustained levels of high inflation likewise caused the U.S. Federal Reserve and other central banks to increasekeep previously raised interest rates,rates unchanged, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including interest rates, labor costs and equipment. We cannot predict any future trends in the rate of inflation and crude oil prices. A significant increase in or continued high levels of inflation, to the extent we are unable to timely pass-through the cost increases to our customers, further volatility in crude oil prices, or potential changes in the United States’ trade policy, including the imposition of tariffs and the resulting consequences, would negatively impact our business, financial condition and results of operations.

Adjusted EBITDA and Adjusted EBITDA margin are not financial measures presented in accordance with GAAP ("non-GAAP"), except when specifically required to be disclosed by GAAP in the financial statements. We believe that the presentation of Adjusted EBITDA and Adjusted EBITDA margin provideprovides useful information to investors in assessing our financial condition and results of operations because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure, asset base, nonrecurring expenses (income) and items outside the control of the Company. Net income (loss) is the GAAP measure most directly comparable to Adjusted EBITDA. Adjusted EBITDA and Adjusted EBITDA margin should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as analytical tools because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. You should not consider Adjusted EBITDA or Adjusted EBITDA margin in isolation or as a substitute for an analysis of our results as reported under GAAP. Because Adjusted EBITDA and Adjusted EBITDA margin may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

(1)Other income for the three months ended MarchJune 31,30, 2026 is primarily comprised of interest income of $1.1$3.8 million and legal settlement income of $0.3 million, partially offset by $0.1 million of other expense. Other income for the six months ended June 30, 2026 is primarily comprised of interest income of $4.9 million, tax refunds (net of advisory fees) totaling $0.2 million and $0.1legal millionsettlement income of other$0.3 income.million. Other income for the threesix months ended MarchJune 31,30, 2025 is primarily comprised of true-upadjustments to workers' compensation and general liability insurance premiums of $1.0 million, tax refunds (net of advisory fees) totaling $0.4 million, interest income from note receivable from sale of business of $0.3$0.6 million, $0.2a $0.3 million unrealized gain on short-term investment and $1.0$0.8 million of other income.

As of MarchJune 31,30, 2026, we conducted our business through four operating segments: Hydraulic Fracturing, Wireline, Cementing, and Power Generation.

ThreeSix Months Ended MarchJune 31,30, 2026 Compared to the ThreeSix Months Ended MarchJune 31,30, 2025

Revenues. Revenues decreased 24.7%,15.9%, or $88.7$109.1 million, to $270.7$576.5 million during the threesix months ended MarchJune 31,30, 2026, as compared to $359.4$685.6 million during the threesix months ended MarchJune 31,30, 2025. Revenue by reportable segment was as follows:

Hydraulic Fracturing. Our Hydraulic Fracturing segment revenues decreased 33.4%,25.0%, or $90.1$128.6 million, to $179.3$386.6 million for the threesix months ended MarchJune 31,30, 2026, as compared to $269.4$515.1 million for the threesix months ended MarchJune 31,30, 2025. The decrease was primarily attributable to decreased customer activity, reduced customer pricing, idling of fleetspricing and inclement weather-related operational disruptions during the threesix months ended MarchJune 31,30, 2026.2026 along with idling of fleets during fiscal year 2025. Intersegment revenues totaled $0.5$0.8 million and $0.1 million for the threesix months ended MarchJune 31,30, 2026 and 2025, respectively. Intersegment revenues were derived from our Wireline, Cementing and Power Generation segments for the threesix months ended MarchJune 31,30, 2026, and from our Wireline segment for the threesix months ended MarchJune 31,30, 2025.

Wireline. Our Wireline segment revenues increased 15.6%17.7% or $8.4$17.9 million, to $61.8$119.3 million for the threesix months ended MarchJune 31,30, 2026, as compared to $53.4$101.4 million for the threesix months ended MarchJune 31,30, 2025. The increase was primarily attributable to increased customer activity and utilization.

Cementing. Our Cementing segment revenue decreased 24.1%,13.4%, or $8.8$9.2 million, to $27.8$59.8 million for the threesix months ended MarchJune 31,30, 2026, as compared to $36.6$69.1 million for the threesix months ended MarchJune 31,30, 2025. The decrease was primarily attributable to decreased customer activity and inclement weather-related operational disruptions during the threesix months ended MarchJune 31,30, 2026.

Power Generation. Our Power Generation segment revenue was $2.2$11.5 million for the threesix months ended MarchJune 31,30, 2026. Our Power Generation segment began revenue generatingrevenue-generating activities during the third quarter of fiscal year 2025.

Cost of Services. Cost of services decreased 19.8%,13.8%, or $52.2$71.3 million, to $211.7$445.7 million for the threesix months ended MarchJune 31,30, 2026, as compared to $263.9$517.0 million during the threesix months ended MarchJune 31,30, 2025. Cost of services by reportable segment was as follows:

Hydraulic Fracturing. Our Hydraulic Fracturing segment cost of services decreased $57.922.8% or $88.0 million, to $138.4$297.1 million for the threesix months ended MarchJune 31,30, 2026, as compared to $196.3$385.0 million for the threesix months ended MarchJune 31,30, 2025. As a percentage of Hydraulic Fracturing segment revenues, Hydraulic Fracturing cost of services was 77.2%76.8% for the threesix months ended MarchJune 31,30, 2026, as compared to 72.8%74.7% for the threesix months ended MarchJune 31,30, 2025, driven by the absorption of fixed costs as a result of inclement weather-related operational disruptions anddisruptions, lower revenue during the threesix months ended MarchJune 31,30, 2026 and the impact of general cost inflation.

Wireline. Our Wireline segment cost of services increased 11.8%,13.7%, or $4.8$10.6 million to $45.1$88.3 million for the threesix months ended MarchJune 31,30, 2026, as compared to $40.3$77.7 million for the threesix months ended MarchJune 31,30, 2025, due to increased customer activity and the impact of general cost inflation. Intersegment cost of services, consisting of cost of services incurred to our Hydraulic Fracturing segment, totaled $0.3$0.5 million and $0.1 million for the threesix months ended MarchJune 31,30, 2026 and 2025, respectively.

Cementing. Our Cementing segment cost of services decreased 12.0%,9.0%, or $3.3$4.9 million, to $24.1$49.0 million for the threesix months ended MarchJune 31,30, 2026, as compared to $27.4$53.9 million for the threesix months ended MarchJune 31,30, 2025. The decrease was primarily attributable to decreased customer activity and inclement weather-related operational disruptions during the threesix months ended MarchJune 31,30, 2026. Intersegment cost of services, consisting of cost of services incurred to our Hydraulic Fracturing segment, totaled $0.1$0.2 million and $0 for the threesix months ended MarchJune 31,30, 2026 and 2025, respectively.

Power Generation. Our Power Generation segment cost of services was $4.7$12.1 million for the threesix months ended MarchJune 31,30, 2026.2026, as compared to $0.5 million for the six months ended June 30, 2025. Our Power Generation segment began revenue generatingrevenue-generating activities during the third quarter of fiscal year 2025. Intersegment cost of services, consisting of cost of services incurred to our Hydraulic Fracturing segment, totaled $0.04$0.1 million and $0 for the threesix months ended MarchJune 31,30, 2026 and 2025, respectively.

Excluding nonrecurring and non-cash items (i.e., stock-based compensation of $4.7$10.6 million and retention bonuses and severance expenses of $0.4$0.5 million, partially offset by business acquisition contingent consideration adjustments of $0.5 million), general and administrative expenses were $22.6$49.7 million during the threesix months ended MarchJune 31,30, 2026, as compared to $22.9$46.2 million during the threesix months ended MarchJune 31,30, 2025.

Depreciation and Amortization. Depreciation and amortization decreased 16.6%,8.6%, or $8.0$7.9 million, to $40.6$84.1 million for the threesix months ended MarchJune 31,30, 2026, as compared to $48.7$92.0 million for the threesix months ended MarchJune 31,30, 2025. The decrease was primarily attributable to assets fully depreciating and a reduction in the cost basis of conventional Tier II hydraulic fracturing equipment sold in 2025.

Gain (loss) on Disposal of Assets. Gain on disposal of assets decreasedincreased by 107.6%,116.5%, or $10.5$16.4 million, to $0.7$2.3 million for the threesix months ended MarchJune 31,30, 2026, as compared to loss on disposal of $9.7$14.1 million for the threesix months ended MarchJune 31,30, 2025 due to lower write-offs related to the sale of conventional Tier II hydraulic fracturing equipment.equipment during the six months ended June 30, 2026.

Interest Expense. Interest expense increased 54.0%60.2% or $1.0$2.2 million to $2.7$5.7 million for the threesix months ended MarchJune 31,30, 2026, as compared to $1.7$3.5 million for the threesix months ended MarchJune 31,30, 2025. The increase was primarily attributable to the addition of loans under the Caterpillar Equipment Loan Agreement (as defined below) to support the purchase of certain mobile natural gas-fueled power generation equipment.

Other Income. Other income was approximately $1.4$5.4 million for the threesix months ended MarchJune 31,30, 2026, compared to other income of $2.9$3.1 million for the threesix months ended MarchJune 31,30, 2025. Other income for the threesix months ended MarchJune 31,30, 2026 is primarily comprised of interest income of $1.1$4.9 million, tax refunds (net of advisory fees) totaling $0.2 million and $0.1legal millionsettlement income of other$0.3 income.million. Other income for the threesix months ended MarchJune 31,30, 2025 is primarily comprised of true-upadjustments to workers' compensation and general liability insurance premiums of $1.0 million, tax refunds (net of advisory fees) totaling $0.4 million, interest income from note receivable from sale of business of $0.3$0.6 million, $0.2a $0.3 million unrealized gain on short-term investment and $1.0$0.8 million of other income.

Income Taxes. Total income tax benefitexpense was $5.7$0.3 million on pre-tax loss resulting in an effective tax rate of 60.9%(2.3)% for the threesix months ended MarchJune 31,30, 2026, as compared to income tax benefitexpense of $1.1$3.5 million on pre-tax income or an effective tax rate of 10.4%58.7% for the threesix months ended MarchJune 31,30, 2025. The change in income tax benefitexpense recorded during the threesix months ended MarchJune 31,30, 2026, compared to the income tax expense recorded during the threesix months ended MarchJune 31,30, 2025, is primarily attributable to the difference in the impact of nondeductible expensesexpenses, state taxes, and statevaluation taxesallowances on the pre-tax loss for 2026, compared to pre-tax income forin 2025.

Our liquidity is currently provided by (i) existing cash balances, including net proceeds of approximately $163.4$163.1 million from the 2026 Common Stock Offering (as defined below) after deducting underwriting discounts and commissions and estimated offering expenses paid by the Company and net proceeds of approximately $668.5 million from the 2026issuance Commonof StockConvertible OfferingNotes (as defined below), after deducting initial purchasers’ discounts and commissions and offering expenses paid by the Company, (ii) operating cash flows, and (iii) borrowings under our Caterpillar Equipment Loan Agreement (as defined below).Agreement. See "Credit Facility and Other Financing Arrangements" below. Additionally, on December 29, 2025, we entered into the Stonebriar Equipment Lease Facility to support the lease of certain mobile power generation equipment, including turbine generator sets along with auxiliary equipment, for our PROPWRSMPROPWR® business line. Our cash is primarily used to fund our operations, support growth opportunities, fund share repurchases under our share repurchase program and satisfy future debt repayments and lease payments. Our Borrowing Base (as defined below), under our ABL Credit Facility (as defined below), as redetermined monthly, is tied to the sum of 85% to 90% of monthly eligible accounts receivable andreceivable, 80% of eligible unbilled accounts (up to a maximum of 25% of the Borrowing Base in the aggregate), in each case, depending on the credit ratings of our accounts receivable counterparties,counterparties and certain value of eligible power generation equipment (up to a maximum of 35% of the Borrowing Base), less customary reserves (the "Borrowing Base"). Changes to our operational activity levels and our customers' credit ratings have an impact on our total eligible accounts receivable, which could result in significant changes to our Borrowing Base and therefore, our availability under our ABL Credit Facility.

We received advance payments from customers for our services, and the amount outstanding in connection with the advance payments as of MarchJune 31,30, 2026 was $8.5$7.4 million, which does not include any restricted cash.

As of MarchJune 31,30, 2026, we had no outstanding borrowings under our ABL Credit Facility, our outstanding borrowings under our Caterpillar Equipment Loan Agreement were $112.0$129.6 million and our total liquidity was approximately $289.3$904.7 million, consisting of cash and cash equivalents of $156.6$784.0 million and $132.7$120.7 million of availability under our ABL Credit Facility.

In May 2025, the Company's board of directors (the "Board") approved a further extension of the share repurchase program initially authorized on May 17, 2023. As extended, the program permits the repurchase of up to $200 million of the Company's common stock through December 31, 2026. The shares may be repurchased from time to time in open market transactions, block trades, accelerated share repurchases, privately negotiated transactions, derivative transactions or otherwise, certain of which may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act, as amended, in compliance with applicable state and federal securities laws. The timing, as well as the number and value of shares repurchased under the share repurchase program, will be determined by the Company at its discretion and will depend on a variety of factors, including management's assessment of the intrinsic value of the Company's common stock, the market price of the Company's common stock, general market and economic conditions, available liquidity, compliance with the Company's debt and other agreements, applicable legal requirements, and other considerations. The Company is not obligated to purchase any shares under the share repurchase program, and the share repurchase program may be suspended, modified, or discontinued at any time without prior notice. The Company expects to fund the repurchases using cash on hand and expected free cash flow to be generated through December 2026. During the three and six months ended MarchJune 31,30, 2026, the Company made no share repurchases under the share repurchase program as it prioritized the scaling of its PROPWRSMPROPWR® business line. The Company intends to continue to prioritize investing in its PROPWRSMPROPWR® business line in the near future. As of MarchJune 31,30, 2026, $89.2 million remained authorized for future repurchases of common stock under the share repurchase program.