ProPetro Holding Corp.: Form 10-Q for the period ended Mar 31, 2025

The financial information, discussion and analysis that follow should be read in conjunction with our consolidated financial statements and the related notes included in our Form 10-K as well as the financial and other information included therein.

Unless otherwise indicated, references in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" to the "Company," "we," "our," "us" or like terms refer to ProPetro Holding Corp. and its subsidiaries.

Overview

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 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.

Our operating segments comprise hydraulic fracturing, wireline, cementing and power generation services. Our completion services include hydraulic fracturing, wireline and cementing operations. Our hydraulic fracturing operations account for approximately 74.9% of our total revenues and operations as of March 31, 2025. Our total available hydraulic horsepower ("HHP") as of March 31, 2025, was 1,312,000 HHP, which was comprised of 445,000 HHP of our Tier IV DGB dual-fuel equipment, 312,000 HHP of FORCE® electric-powered equipment and 555,000 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 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 for four FORCE® electric-powered hydraulic fracturing fleets with 60,000 HHP per fleet (the "Electric Fleet Leases") and in 2024, we entered into an additional three-year lease for a fifth FORCE® electric-powered hydraulic fracturing fleet with 72,000 HHP. As of March 31, 2025, we have received 312,000 HHP of FORCE® electric-powered equipment representing four fleets and a portion of the fifth fleet. We currently expect to receive the remaining equipment associated with the fifth fleet in the first half of 2025. We currently have 26 wireline units and 30 cementing units.

In the fourth quarter of fiscal year 2024, we formed a new subsidiary, ProPetro Energy Solutions, LLC, ("PROPWR") 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 subsidiary has ordered equipment, but it has not yet begun revenue-generating activities. In April 2025, we entered into a financing arrangement to purchase additional mobile natural gas-fueled power generation equipment. See Note 15. Subsequent Events.

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. The note receivable is secured by substantially all assets of the former employee’s business and the former employee’s ownership interests in and distributions from the business. The note receivable is to be paid to the Company in quarterly installments with interest of 10% per annum from March 31, 2025, to December 31, 2029. We recorded a gain on disposal of $8.2 million related to the sale of the business. The former employee was part of our cementing operations until November 1, 2024, and is no longer affiliated with the Company.

On May 31, 2024, we consummated the acquisition of all of the outstanding equity interests in Aqua Prop, LLC ("AquaProp"), which provides wet sand solutions for hydraulic fracturing sand requirements at oil well sites (the "AquaProp Acquisition"). The consideration for the AquaProp Acquisition includes $13.7 million of cash paid to the seller, $3.7 million of deferred cash consideration payable to the seller by May 31, 2025, the payoff of $7.2 million of the seller's outstanding debt, the payment of $0.3 million of certain transaction costs and estimated contingent consideration of $10.9 million. As a result of the AquaProp Acquisition, we expanded our business to include wet sand services.

Our competitors include many large and small energy service companies, including Halliburton Company, Liberty Energy Inc., Patterson-UTI Energy Inc., ProFrac Holding Corp., Solaris Energy Infrastructure, Inc., RPC, Inc., and a number of private and locally-oriented businesses. The markets in which we operate are highly competitive. To be successful, an energy services company must provide services that meet the specific needs of oil and natural gas E&P companies at competitive prices. Competitive factors impacting sales of our services are price, reputation, technical expertise, emissions profile, service and equipment design and quality, and health and safety standards. Although we believe our customers consider all of these factors, we believe price is a key factor in an E&P company's criteria in choosing a service provider. However, we have recently observed the energy industry and our customers shift to lower emissions equipment, which we believe will be an increasingly important factor in an E&P company's selection of a service provider. The transition to lower emissions equipment has been challenging for companies in the service industry because of the capital requirements, lack of large scale deployment of certain new technology such as electric-powered equipment, and the pricing for our services and expected return on invested capital. While we seek to price our services competitively, we believe many of our customers elect to work with us based on our operational efficiencies, productivity, equipment portfolio and quality, reliability, ability to manage multifaceted logistics challenges, commitment to safety and the ability of our people to handle the most complex Permian Basin well completions and power generation challenges.

We believe that our substantial market presence in the Permian Basin positions us well to capitalize on drilling and completion activity and power demand in the region. Our operational focus has been in the Permian Basin's Midland sub-basin, where our customers have operated. However, we have increased our operations in the Delaware sub-basin and are well-positioned to support further increases to our activity in this area in response to demand from our customers. Over time, we expect the Permian Basin's Midland and Delaware sub-basins to continue to command a disproportionate share of future North American E&P spending.

Additionally, we believe the significant natural gas production in the Permian Basin will become a natural market for power-intensive businesses including data centers and other industrial businesses seeking alternative solutions for reliable and available electricity requirements which are not dependent on grid or public utility limitations.

Our Hydraulic Fracturing, Wireline and Cementing operating segments meet the criteria of a reportable segment. Prior to the fourth quarter of 2024, our cementing segment did not meet the quantitative thresholds for a reportable segment and was shown in the "All Other" category. Effective as of the fourth quarter of 2024, cementing is shown as a reportable segment since it meets the criteria of a reportable segment. Our power generation services segment does not meet the reportable segment criteria and is included within the “All Other” category. Additionally, our corporate administrative activities do not involve business activities from which we may earn revenues and its results are not regularly reviewed by the Company’s CODM when making key operating and resource decisions. As a result, corporate administrative expenses and intersegment revenue have been included under "Reconciling Items." Prior period segment information has been revised to conform to our current presentation. For additional financial information on our reportable segments presentation, see "Note 7 - Reportable Segment Information."

Pioneer Pressure Pumping Acquisition

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 (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. 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, where we will provide hydraulic fracturing, wireline and pumpdown services with two committed FORCE® electric-powered hydraulic fracturing fleets with the option to add a third FORCE® fleet (also with wireline and pumpdown services) for a period of three years or for contracted hours, whichever occurs last with respect to each fleet, subject to certain termination and release rights.

Commodity Price and Other Economic Conditions

The oil and gas industry has traditionally been volatile and is characterized by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, and capital investments of E&P companies toward their development and production of oil and gas reserves. The oil and gas industry is also impacted by general domestic and international economic conditions such as supply chain disruptions and inflation, war and political instability in oil producing countries, government regulations (both in the United States and internationally), levels of consumer demand, adverse weather conditions, and other factors that are beyond our control.

The geopolitical and macroeconomic consequences of military action in the Middle East, the Russian invasion of Ukraine, including the associated sanctions, 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. More recently, the West Texas Intermediate ("WTI") average crude oil price declined to approximately $76 per barrel in 2024 and approximately $68 per barrel in March 2025 before further declining in April 2025 in response to tariff policies implemented by the U.S. government, an anticipated increase in global supply of crude oil and concerns of a potential global recession resulting from high inflation, interest rates, impacts of tariff policies on supply chains and increased costs as whole. Additionally, we have recently experienced a decrease in the rig count to 304 at the end of 2024 and a further decrease to 297 at the end of March 2025, which resulted in a reduction in the demand for completion services and pressure on pricing of our services.

Sustained levels of high inflation have 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 changes in U.S trade policy, including the imposition of tariffs and the resulting consequences, would negatively impact our business, financial condition and results of operations.

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 to 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 plan to replace our conventional Tier II diesel-only equipment with lower emissions equipment. We have transitioned our hydraulic fracturing equipment portfolio from approximately 60% lower emissions equipment in 2023, 70% in 2024, and expect to increase to approximately 75% by the end of the end 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 to quickly transition 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 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 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.

How We Evaluate Our Operations

Our management uses Adjusted EBITDA or Adjusted EBITDA margin to evaluate and analyze the performance of our various operating segments.

Adjusted EBITDA and Adjusted EBITDA Margin

We view Adjusted EBITDA and Adjusted EBITDA margin as important indicators of performance. We define EBITDA as our earnings, before (i) interest expense, (ii) income taxes and (iii) depreciation and amortization. We define Adjusted EBITDA as EBITDA, plus (i) loss/(gain) on disposal of assets, (ii) stock-based compensation, (iii) other expense/(income), (iv) other unusual or nonrecurring (income)/expenses such as impairment expenses, costs related to asset acquisitions, insurance recoveries, one-time professional fees and legal settlements and (v) retention bonuses and severance. Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of our revenues.

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 (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").

Note Regarding Non-GAAP Financial Measures

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 provide 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.

The following tables set forth certain financial information with respect to the Company’s reportable segments; intersegment revenues are shown under "Reconciling Items" (in thousands):

(1) 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 condensed consolidated statements of operations.

(2) The write-offs of remaining book value of prematurely failed power ends and other components are recorded as depreciation in 2025. In order to conform to current period presentation, we have reclassified the corresponding amount of $6.5 million from loss on disposal of assets to depreciation for the three months ended March 31, 2024.

A reconciliation of net income to Adjusted EBITDA is provided in the table below (in thousands):

(1) The write-offs of remaining book value of prematurely failed power ends and other components are recorded as depreciation in 2025. In order to conform to current period presentation, we have reclassified the corresponding amount of $6.5 million from loss on disposal of assets to depreciation for the three months ended March 31, 2024.

(2) Other income for the three months ended March 31, 2025 is primarily comprised of true-up of 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 million, a $0.2 million unrealized gain on short-term investment and $1.0 million of other income. Other income for the three months ended March 31, 2024 is primarily comprised of insurance reimbursements of $2.0 million, partially offset by a $0.6 million unrealized loss on short-term investment.

Results of Operations

As of March 31, 2025, we conducted our business through four operating segments: hydraulic fracturing, wireline, cementing, and power generation services (started in the fourth quarter of fiscal year 2024 and has not begun any revenue-generating activities yet). Our power generation services operating segment is shown in the “All Other” category for segment reporting purposes.

On May 31, 2024, we completed the acquisition of all of the outstanding equity interests in AquaProp in exchange for $13.7 million of cash, $3.7 million of deferred cash consideration payable to AquaProp's seller by May 31, 2025, the payoff of $7.2 million of assumed debt, the payment of $0.3 million of certain transaction costs, and estimated contingent consideration of $10.9 million. As a result of the acquisition, we expanded our operations into the wet sand service business unit. The Company's 2025 results include the impact of AquaProp's operations which was not included in our 2024 results herein because we acquired AquaProp in May 2024. Accordingly, the full impact of the results of AquaProp may affect the comparability of our 2025 results when compared to prior period. AquaProp's operations, which are included for the entire period, resulted in $21.4 million in revenues and $20.4 million in cost of services for the three months ended March 31, 2025, which are included in the Hydraulic Fracturing reportable segment.

The following table sets forth the results of operations for the periods presented:

(in thousands, except for percentages)

(1) Represents our power generation services business.

(2) Exclusive of depreciation and amortization.

(3) Inclusive of stock-based compensation.

(4) The write-offs of remaining book value of prematurely failed power ends and other components are recorded as depreciation in 2025. In order to conform to current period presentation, we have reclassified the corresponding amount of $6.5 million from loss on disposal of assets to depreciation for the three months ended March 31, 2024

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

(6) The non-GAAP financial measure of Adjusted EBITDA margin for the Hydraulic Fracturing segment is calculated by taking Adjusted EBITDA for the Hydraulic Fracturing segment as a percentage of our revenue for the Hydraulic Fracturing segment.

Three Months Ended March 31, 2025 Compared to the Three Months Ended March 31, 2024

Revenues. Revenues decreased 11.4%, or $46.4 million, to $359.4 million during the three months ended March 31, 2025, as compared to $405.8 million during the three months ended March 31, 2024. Revenue by reportable segment was as follows:

Hydraulic Fracturing. Our hydraulic fracturing segment revenues decreased 12.9%, or $39.9 million, for the three months ended March 31, 2025, as compared to the three months ended March 31, 2024. The decrease was primarily attributable to decreased customer pricing, partially offset by increased efficiency and the addition of AquaProp's operations in May 2024, which contributed $21.4 million in revenues during the three months ended March 31, 2025. Our average active hydraulic fracturing fleet count was approximately 15 fleets for the three months ended March 31, 2025, an increase from approximately 14 fleets for the three months ended March 31, 2024. Intersegment revenues, consisting of revenues derived from our wireline segment, totaled $0.1 million and $0 for the three months ended March 31, 2025 and 2024, respectively.

Wireline. Our wireline segment revenues decreased 12.1% or $7.4 million for the three months ended March 31, 2025, as compared to the three months ended March 31, 2024. The decrease was primarily attributable to decreased customer activity and customer pricing.

Cementing. Our cementing segment revenue increased 2.5%, or $0.9 million for the three months ended March 31, 2025, as compared to the three months ended March 31, 2024. The increase was primarily attributable to synergies gained with customers after the acquisition of Par Five Energy Services LLC ("Par Five"), partially offset by the sale of our cementing business located in Vernal, Utah in November 2024.

Cost of Services. Cost of services decreased 8.6%, or $24.8 million, to $263.9 million for the three months ended March 31, 2025, as compared to $288.6 million during the three months ended March 31, 2024. Cost of services by reportable segment was as follows:

Hydraulic Fracturing. Cost of services in our hydraulic fracturing segment decreased $21.8 million for the three months ended March 31, 2025, as compared to the three months ended March 31, 2024. As a percentage of hydraulic fracturing segment revenues, hydraulic fracturing cost of services was 72.8% for the three months ended March 31, 2025, as compared to 70.5% for the three months ended March 31, 2024 driven by customer price decreases and the impact of general cost inflation. The decrease in cost of services was partially offset by the addition of AquaProp's operations in May 2024, which added $20.4 million in cost of services during the three months ended March 31, 2025.

Wireline. Our wireline segment cost of services decreased $0.9 million for the three months ended March 31, 2025, as compared to the three months ended March 31, 2024 due to decrease in activity. Intersegment cost of services, consisting of cost of services incurred to our hydraulic fracturing segment, totaled $0.1 million and $0 for the three months ended March 31, 2025 and 2024, respectively.

Cementing. Our cementing cost of services decreased 7.1%, or $2.1 million for the three months ended March 31, 2025, as compared to the three months ended March 31, 2024. The decrease was primarily attributable to the sale of our cementing business located in Vernal, Utah in November 2024.

General and Administrative Expenses. General and administrative expenses decreased 2.1%, or $0.6 million, to $27.6 million for the three months ended March 31, 2025, as compared to $28.2 million for the three months ended March 31, 2024.

Excluding nonrecurring and non-cash items (i.e., stock-based compensation of $3.3 million, retention bonuses and severance expenses of $1.7 million, partially offset by business acquisition contingent consideration adjustments of $0.3 million), general and administrative expenses were $22.9 million during the three months ended March 31, 2025, as compared to $23.8 million during the three months ended March 31, 2024.

Depreciation and Amortization. Depreciation and amortization decreased 17.0%, or $10.0 million, to $48.7 million for the three months ended March 31, 2025, as compared to $58.7 million for the three months ended March 31, 2024. The decrease was primarily attributable to assets fully depreciating and a reduction in the cost basis of Tier II diesel-only hydraulic fracturing pumping units and associated conventional assets impaired in the third quarter of 2024, partially offset by the addition of AquaProp's operations in May 2024 which included $1.5 million of depreciation and amortization.

Loss on Disposal of Assets. Loss on disposal of assets increased by $9.7 million, to $9.7 million for the three months ended March 31, 2025, as compared to $4 thousand for the three months ended March 31, 2024. The increase was primarily attributable to losses incurred during the three months ended March 31, 2025 from the sale of certain Tier II hydraulic fracturing equipment.

Interest Expense. Interest expense decreased to $1.7 million for the three months ended March 31, 2025, as compared to $2.0 million for the three months ended March 31, 2024. The decrease was primarily attributable to lower interest rates on outstanding borrowings under our revolving credit facility (the revolving credit facility, as amended and restated in April 2022, as amended in June 2023, as amended in June 2024, and as may be amended further, "ABL Credit Facility") during the three months ended March 31, 2025 and a reduction in our finance lease obligation as a result of a payments.

Other Income. Other income was approximately $2.9 million for the three months ended March 31, 2025, compared to other income of $1.4 million for the three months ended March 31, 2024. Other income for the three months ended March 31, 2025 is primarily comprised of true-up of 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 million, a $0.2 million unrealized gain on short-term investment and $1.0 million of other income. Other income for the three months ended March 31, 2024 is primarily comprised of insurance reimbursements of $2.0 million, partially offset by a $0.6 million unrealized loss on short-term investment.

Income Taxes. Total income tax expense was $1.1 million resulting in an effective tax rate of 10.4% for the three months ended March 31, 2025, as compared to income tax expense of $9.8 million or an effective tax rate of 32.9% for the three months ended March 31, 2024. The change in effective tax rate for the three months ended March 31, 2025, compared to the three months ended March 31, 2024, is primarily attributable to the difference in the impact of nondeductible expenses, state taxes and valuation allowances on the pre-tax loss for 2025, as compared to 2024.

Liquidity and Capital Resources

Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our ABL Credit Facility (as defined below). In addition, on April 2, 2025, we entered into a financing arrangement (the "PROPWR Loan Agreement") to support the purchase of certain mobile natural gas-fueled power generation equipment, including turbine generator sets along with auxiliary equipment, for our PROPWR business line. See "Credit Facility and Other Financing Arrangements" below. Our cash is primarily used to fund our operations, support growth opportunities, fund share repurchases under our share repurchase program and satisfy future debt payments. Our Borrowing Base (as defined below), under our ABL Credit Facility,as redetermined monthly, is tied to the sum of 85% to 90% of monthly 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, 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 a customer for our services, and the amount outstanding in connection with the advance payments as of March 31, 2025 was $9.3 million, which does not include any restricted cash.

As of March 31, 2025, our borrowings under our ABL Credit Facility were $45.0 million and our total liquidity was approximately $197.4 million, consisting of cash and cash equivalents of $63.4 million and $134.0 million of availability under our ABL Credit Facility.

On April 24, 2024, the Company's board of directors (the "Board") approved an increase and extension to the share repurchase program previously authorized on May 17, 2023. The program permits the repurchase of up to an additional $100 million of the Company's common stock for a total of $200 million and extends the expiration date by one year to May 31, 2025. 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 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 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 May 2025. During the three months ended March 31, 2025, the Company made no share repurchases under the share repurchase program. As of March 31, 2025, $89.2 million remained authorized for future repurchases of common stock under the share repurchase program.

There can be no assurance that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures and to continue with our share repurchases under our share repurchase program or fund future business acquisitions. Future cash flows are subject to a number of variables, and are highly dependent on the drilling, completion, and production activity by our customers, which in turn is highly dependent on oil and natural gas prices. Depending upon market conditions and other factors, we may issue equity and debt securities or take other actions necessary to fund our business, strategy or meet our future long-term liquidity requirements.

Capital Requirements, Future Sources and Use of Cash and Contractual Obligations

Capital expenditures incurred were $38.7 million during the three months ended March 31, 2025, as compared to $39.8 million during the three months ended March 31, 2024 for our reportable segments. The significant portion of our total capital expenditures incurred during the three months ended March 31, 2025 were maintenance capital expenditures and down payments on mobile natural gas-fueled power generation equipment for our PROPWR business line.

Our future material use of cash will be to fund our capital expenditures. We may also use material amounts of cash to repurchase shares under our share repurchase program. Capital expenditures for 2025 are projected to be primarily related to capital expenditures to extend the useful life of our existing completion services assets, costs to convert some existing equipment to lower emissions equipment, purchase power generation equipment, strategic purchases and other ancillary equipment purchases, subject to market conditions and customer demand. Our future capital expenditures depend on our projected operational activity, emission requirements and planned conversions to lower emissions equipment, among other factors, which could vary significantly throughout the year. Based on our current plan and projected activity levels for 2025, we expect our capital expenditures to range between approximately $295 million to $345 million which includes approximately $125 million to $175 million for our completion services business and approximately $170 million for our PROPWR business. We entered into a contractual arrangement with an equipment manufacturer to purchase mobile natural gas-fueled power generation equipment, including turbine generator sets along with auxiliary equipment, for our PROPWR business line, with a total cost of $122.0 million, of which approximately $103.7 million, representing progress payments beyond the initial down payment on this equipment, will be financed. We currently expect to receive this equipment beginning at the end of the second quarter of 2025 through early 2026. We entered into contractual arrangements with other equipment manufacturers to purchase additional natural gas-fueled power generation equipment for our PROPWR business line, with a total cost of $102.0 million. We currently expect to receive this equipment beginning in the second quarter of 2025 through the second quarter of 2026. We could incur significant additional capital expenditures if our projected activity levels increase during the course of the year, inflation and supply chain tightness continue to adversely impact our operations or we invest in new or different lower emissions equipment. The Company will continue to evaluate the emissions profile of its equipment over the coming years and may, depending on market conditions, convert or retire additional conventional Tier II equipment in favor of lower emissions equipment. The Company’s decisions regarding the retirement or conversion of equipment or the addition of lower emissions equipment will be subject to a number of factors, including (among other factors) the availability of equipment, including parts and major components, supply chain disruptions, prevailing and expected commodity prices, customer demand and requirements and the Company’s evaluation of projected returns on conversion or other capital expenditures. Depending on the impacts of these factors, the Company may decide to retain conventional equipment for a longer period of time or accelerate the retirement, replacement or conversion of that equipment.

We anticipate our capital expenditures will be funded by existing cash, cash flows from operations, and if needed, borrowings under our ABL Credit Facility. We expect to finance the purchase of our PROPWR mobile natural gas-fueled power generation equipment using the PROPWR Loan Agreement Our cash flows from operations will be generated from services we provide to our customers.

We entered into a sand purchase agreement with a supplier that will expire on December 31, 2025 with a remaining take-or-pay commitment of approximately $0.4 million. We also entered into three-year electric fleet leases for five FORCE® electric-powered hydraulic fracturing fleets (the "Electric Fleet Leases"), which contain options to extend the leases or purchase the equipment at the end of each lease or at the end of each subsequent renewal period. As of March 31, 2025, all five of the Electric Fleet Leases commenced when the Company took possession of all equipment associated with its first four FORCE® electric-powered hydraulic fracturing fleets and some of the equipment associated with its fifth fleet under these leases. We currently expect to receive the remaining equipment associated with the fifth fleet in the first half of 2025. The total estimated contractual commitment in connection with the Electric Fleet Leases excluding the cost associated with the option to purchase the equipment at the end of each lease is approximately $112.8 million. We also entered into a three year lease (the "Power Equipment Lease") for certain power generation equipment. The total estimated contractual commitment in connection with the Power Equipment Lease is approximately $29.1 million.

In the normal course of business, we enter into various contractual obligations and incur expenses in connection with routine growth, conversion and maintenance capital expenditures that impact our future liquidity. There were no other known future material contractual obligations as of March 31, 2025.

Cash and Cash Flows

The following table sets forth the historical cash flows for the three months ended March 31, 2025, and 2024:

(in thousands)

Operating Activities

Net cash provided by operating activities was $54.7 million for the three months ended March 31, 2025, compared to $74.8 million for the three months ended March 31, 2024. The net decrease of approximately $20.1 million was primarily due to lower net income adjusted for noncash expenses and the timing of our receivable collections from our customers and payments to our vendors.

Investing Activities

Net cash used in investing activities decreased to $32.8 million for the three months ended March 31, 2025, from $33.8 million for the three months ended March 31, 2024. The decrease was primarily attributable to a $7.0 million increase proceeds from the sale of assets, partially offset by a $6.3 million increase in capital expenditures which includes $18.3 million for mobile natural gas-fueled power generation equipment for our PROPWR business line.

The following table summarizes our capital expenditures incurred by reportable segment for the periods indicated:

(in thousands)

(1) Represents our power generation services business.

Cash Flows From Financing Activities

Net cash used in financing activities decreased to $8.9 million for the three months ended March 31, 2025, from $27.9 million for the three months ended March 31, 2024. The net decrease was primarily driven by a $22.5 million decrease in share repurchases, partially offset by a $1.5 million increase in tax withholdings paid for net settlement of equity awards, a $1.5 million increase in repayments of insurance financing and a $0.6 million increase in payments of finance lease obligation.

Credit Facility and Other Financing Arrangements

Our revolving credit facility, as amended and restated in April 2022, prior to giving effect to the amendment to the revolving credit facility in June 2023, had a total borrowing capacity of $150.0 million. The revolving credit facility had a borrowing base of 85% to 90%, depending on the credit ratings of our accounts receivable counterparties, of monthly eligible accounts receivable less customary reserves. The revolving credit facility included a springing fixed charge coverage ratio to apply when excess availability was less than the greater of (i) 10% of the lesser of the facility size or the borrowing base or (ii) $10.0 million. Under the revolving credit facility we were required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens, indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities.

Effective June 2, 2023, the Company entered into an amendment to the ABL Credit Facility. The amendment increased the borrowing capacity under the ABL Credit Facility to $225.0 million (subject to the Borrowing Base limit), and extended the maturity date to June 2, 2028.

Effective June 26, 2024, the Company entered into an amendment to the ABL Credit Facility. The amendment increased the amount of non-cash consideration that may be considered cash pursuant to certain permitted dispositions.

The Borrowing Base as of March 31, 2025, was approximately $187.5 million. The ABL Credit Facility includes a springing fixed charge coverage ratio to apply when excess availability is less than the greater of (i) 10% of the lesser of the facility size or the Borrowing Base or (ii) $15.0 million. Under the ABL Credit Facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens, indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company.

Borrowings under the ABL Credit Facility accrue interest based on a three-tier pricing grid tied to availability, and we may elect for loans to be based on either the Secured Overnight Financing Rate ("SOFR") or the base rate, plus the applicable margin, which ranges from 1.75% to 2.25% for SOFR loans and 0.75% to 1.25% for base rate loans.

Effective April 2, 2025, PROPWR entered into a contractual arrangement with an equipment manufacturer to purchase mobile natural gas-fueled power generation equipment for our PROPWR business line, with a total cost of $122.0 million, of which approximately $103.7 million, representing progress payments beyond the initial down payment on this equipment, will be financed. We currently expect to receive this equipment beginning at the end of the second quarter of 2025 through early 2026. We entered into contractual arrangements with other equipment manufacturers to purchase additional natural gas-fueled power generation equipment for our PROPWR business line, with a total cost of $102.0 million. We currently expect to receive this equipment beginning in the second quarter of 2025 through the second quarter of 2026. See "Note 15 – Subsequent Events" in the Notes to Condensed Consolidated Financial Statements for further information.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of March 31, 2025.

Critical Accounting Policies and Estimates

There have been no material changes during the three months ended March 31, 2025 to the methodology applied by our management for critical accounting policies previously disclosed in our Form 10-K. Please refer to Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" in our Form 10-K for a discussion of our critical accounting policies and estimates.

Recently Issued Accounting Standards

Disclosure concerning recently issued accounting standards is incorporated by reference to Note 2 of our Condensed Consolidated Financial Statements (Unaudited) contained in this Form 10-Q.

As of March 31, 2025, there have been no material changes in market risk from the information provided in "Management’s Discussion and Analysis of Financial Condition and Results of Operations" or "Quantitative and Qualitative Disclosures of Market Risk" in our Form 10-K.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that the information required to be disclosed by us in our reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2025.

Changes in Internal Control over Financial Reporting

There were no changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended March 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Except 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.

Changes in U.S. trade policy and the impact of tariffs 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 United States or other governments. For example, on March 12, 2025, the U.S. government imposed a 25% tariff on steel imports, and on April 2, 2025, the U.S. government announced a 10% tariff on product imports from almost all 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 are unprecedented, have caused substantial uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods.

Any imposition of or increase in tariffs on imports of steel or other materials, as well as corresponding price increases for such materials available domestically, could increase our material input costs and our costs to maintain our assets. To the extent that we are unable to pass all or any such cost increases on to our customers, such cost increases could adversely affect our returns on investment.

The imposition of further tariffs by the United States on a broader range of imports, or further retaliatory trade measures taken in response to additional tariffs, could increase costs in our supply chain or reduce demand of our customers’ products, either of which could adversely affect our results of operations. The ultimate impact of these trade measures on our business operations and financial results is uncertain and may be affected by various factors, including whether and when such trade measures are implemented, the timing when such measures may become effective, and the amount, scope, or nature of such trade measures, and our ability to execute strategies to mitigate the negative impacts.