ProPetro Holding Corp. 10-K

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. You should read the following discussion and analysis of our financial condition and results of operations together with our audited consolidated financial statements and the related notes included in this Annual Report. Some of the information contained in this discussion and analysis or set forth elsewhere in this Annual Report, including information with respect to our plans and strategy for our business and related financing, includes forward‑looking statements that involve risks and uncertainties. You should read the " Risk Factors " section of this Annual Report for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward‑looking statements contained in the following discussion and analysis. Basis of Presentation This discussion of our results omits our results of operations and cash flows for the year ended December 31, 2022, and the comparison of our results of operations for the years ended December 31, 2023, and 2022, which may be found in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on March 13, 2024. Unless otherwise indicated, references in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” to “ProPetro Holding Corp.,” “the Company,” “we,” “our,” “us” or like terms refer to ProPetro Holding Corp. and its subsidiaries. Overview Our Business 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 completion services includes our operating segments comprised of hydraulic fracturing, wireline and cementing operations. Our hydraulic fracturing operations account for approximately 75.6% of our total revenues and operations. Our total available hydraulic horsepower (“HHP”) at December 31, 2024, w as 1,556,500 HHP, which was comprised of 450,000 HHP of our Tier IV Dynamic Gas Blending (“DGB”) dual-fuel equipment, 294,000 HHP of FORCE ® electric-powered equipment and 812,500 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, we committed to additional conversions of our Tier II 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 for four FORCE ® electric-powered hydraulic fracturing fleets with 60,000 HHP per fleet and in June 2024, we entered into an additional three-year lease for a fifth FORCE ® electric-powered hydraulic fracturing fleet with 72,000 HHP. As of December 31, 2024, we have re ceived 294,000 HHP of FORC E ® 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. In the fourth quarter of 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. 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 37 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 cash consideration for the AquaProp Acquisition includes $13.7 million paid to the seller, $7.2 million paid to settle the seller’s outstanding debt, and $0.3 million paid for the seller’s transaction expenses . As a result of the AquaProp Acquisition, we expanded our operations into the wet sand service business unit. On December 1, 2023, we consummated the purchase of the assets and operations of Par Five Energy Services LLC (“Par Five”), which provides cementing services in the Delaware Basin, in exchange for $25.4 million of cash, including deferred cash consideration of $3.1 million which is payable to Par Five or its beneficiary on June 1, 2025, with interest of 4.0% per annum (the “Par Five Acquisition”) . The Par Five Acquisition complemented our existing cementing business and enabled us to serve both the Midland and Delaware sub-basins of the Permian Basin. On November 1, 2022, we consummated the acquisition of all of the outstanding limited liability company interests of Silvertip Completion Services Operating, LLC (the “Silvertip Acquisition”), which provides wireline perforation and ancillary services in the Permian Basin in exchange for 10.1 million shares of our common stock valued at $106.7 million, $30.0 million of cash, the payoff of $7.2 million of assumed debt, and the payment of certain other closing and transaction costs. At December 31, 2024, we had 26 wireline units available to provide wireline perforation and ancillary services. Collectively, the AquaProp Acquisition, the Par Five Acquisition and the Silvertip Acquisition have positioned the Company as a more integrated and diversified completions-focused energy service provider. See Note 4. Business Acquisitions in the financial statements for additional disclosures. We believe that our substantial market presence in the Permian Basin positions us well to capitalize on drilling and completion activity in the region. Primarily, 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. We have historically conducted our business through four operating segments: hydraulic fracturing, wireline, cementing and coiled tubing. Prior to the fourth quarter of fiscal year 2023, our operating segments met the aggregation criteria and were aggregated into the “Completion Services” reportable segment and our coiled tubing operations (which were divested in September 2022) were shown in the “All Other” category. Effective in the the fourth quarter of fiscal year 2023, we revised our segment reporting as we determined that our three operating segments no longer met the criteria to be aggregated. In the fourth quarter of fiscal year 2024, we formed 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 new subsidiary has ordered equipment, but it has not yet begun revenue-generating activities. Our hydraulic fracturing, wireline and cementing operating segments 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.” 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, LLC in 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 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. 38 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 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 the adverse impacts of the COVID-19 pandemic have resulted in volatility in supply and demand dynamics for crude oil and associated volatility in crude oil pricing. As the global response to the COVID-19 pandemic began to wane, the demand and prices for crude oil increased from the lows experienced in 2020, with the WTI average crude oil price reaching approximately $94 per barrel in 2022, the highest average price in the prior ten years. However, the WTI average crude oil price declined to approximately $78 per barrel in 2023 and approximately $76 per barrel in 2024. We believe that the volatility of crude oil prices in recent years has been partly driven by declines in crude oil supplies, concerns over sanctions resulting from Russia's invasion of Ukraine, concerns over a potential disruption of Middle Eastern oil supplies resulting from the conflict in the Middle East, slower crude oil production growth due to the lack of reinvestment in the oil and gas industry in the last three years, the extension of OPEC+ production cuts of approximately 3.9 million barrels per day originally announced in 2023, and concerns of a potential global recession resulting from high inflation and interest rates. With the significant increase in global crude oil prices from 2021, including the WTI crude oil price, there was a significant increase in the Permian Basin rig count from approximately 179 at the beginning of 2021 to approximately 353 at the end of 2022, according to the Baker Hughes. Following the increase in rig count and the WTI crude oil price, the energy service industry has experienced increased demand for its completion services, and improved pricing. However, the Permian Basin rig count experienced a 13% decrease in 2023 to 309 at the end of 2023 and further decreased to 304 at the end of 2024 which resulted in a reduction in the demand for completion services and pressure on pricing of our services. 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 change 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. 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 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 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 39 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 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. 2024 Operational Highlights Over the course of the year ended December 31, 2024: • we deployed two FORCE ® electric-powered hydraulic fracturing fleets with a total capacity of 120,000 HHP. Four FORCE ® electric-powered hydraulic fracturing fleets are now operating under contract with leading customers; • our available equipment portfolio is expected to be comprised of approximately 75% lower emissions (FORCE ® electric and Tier IV DGB dual-fuel), and 25% conventional diesel equipment by the end of 2025; • despite market volatility, our average active hydraulic fracturing fleet count was approximately 14 fleets, a decrease from 15 active fleets in 2023; • we published our second annual sustainability report, which describes our commitment to building a sustainable business that supports the safe, reliable production of the energy the world needs by offering competitive, value-driving services to customers, while benefitting our shareholders, communities, and other stakeholders; • we consummated the purchase of all of the outstanding equity interests in AquaProp on May 31, 2024, which provides wet sand solutions for hydraulic fracturing sand requirements at oil well sites; and • we formed PROPWR in the fourth quarter of 2024, 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 has not yet begun revenue-generating activities. 2024 Financial Highlights Financial highlights for the year ended December 31, 2024: • net loss was $137.9 million, compared to net income of $85.6 million for the year ended December 31, 2023. Diluted net loss per common share was $1.31, compared to diluted net income of $0.76 for the year ended December 31, 2023. Net loss for 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 and goodwill impairment expense of $23.6 million related to the goodwill in our wireline operating segment. Adjusted EBITDA of approximately $283.2 million decreased 29.9%, compared to $404.0 million for the year ended December 31, 2023 (see reconciliation of Adjusted EBITDA to net income in the subsequent section “How We Evaluate Our Operations”); • capital expenditures were reduced to $133.4 million or 57% as compared to 2023; • net cash provided by operating activities less net cash used in investing activities improved by $106.6 million compared to 2023; • our accounts receivable to accounts payable ratio increased to 2.1 from 1.5. Working capital (current assets less current liabilities) increased to $70.0 million from $39.7 million; • our total liquidity was $160.9 million as of December 31, 2024. consisting of cash and cash equivalents of $50.4 million and remaining availability of $110.5 million under our ABL Credit Facility; we had $45.0 million of borrowings as of December 31, 2024, under our ABL Credit Facility; and • the Company repurchased and retired 7.2 million shares of common stock for an aggregate of $59.1 million, an average price per share of $8.21 including commissions, under the share repurchase program. As of December 31, 2024, $89.2 million remained authorized for future repurchases of common stock under the share repurchase program. 40 Our Assets and Operations Completion services includes our hydraulic fracturing, wireline and cementing operations. We primarily provide these services to E&P comp anies in the Permian Basin. During the year ended December 31, 2024, our hydraulic fracturing, wireline and cementing operations accounted fo r 75.6%, 14.1%, and 10.3% of our total revenue, respectively. Our equipment has been designed to handle Permian Basin specific operating conditions a nd 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. We plan to continually reinvest in our equipment to ensure optimal performance and reliability. How We Generate Revenue We generate revenue 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. We also provide personnel and services that are tailored to meet each of our customers’ needs. Hydraulic fracturing operations account for a significant portion of our total revenue. We charge our customers on a per‑job basis, in which we set pricing terms after receiving full specifications for the requested job, including the lateral length of the customer’s wellbore, the number of frac stages per well, the amount of proppant and chemicals to be used and other parameters of the job. In addition to hydraulic fracturing services, we generate revenue through other completion services that we provide to our customers, including wireline, cementing and other related services. These completion services are complementary to each other and are undertaken in unison with hydraulic fracturing services. They are provided through various contractual arrangements, including on a turnkey contract basis, in which we set a price to perform a particular job, or a daywork contract basis, in which we are paid a set price per day for our services. We are also sometimes paid by the hour for these complementary services. Demand for our 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 $76 , $78, and $94 for the years ended December 31, 2024, 2023, and 2022, respectively. In January 2025, the WTI oil price was approximately $74 p er barrel. If the WTI oil price declines in the future or remains highly volatile, demand for our services may be negat ively 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. The historical weekly average Permian Basin rig count based on Baker Hughes rig count information was as follows: Year Ended December 31, Drilling Rig Type (Permian Basin) 2024 2023 2022 Directional 3 3 3 Horizontal 296 323 318 Vertical 10 9 14 Total 309 335 335 Average Permian Basin rig count to U.S. rig count 51.6 % 48.7 % 46.3 % Costs of Conducting our Business The principal direct costs involved in operating our business are direct labor, expendables and other direct costs. 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 lab or costs amounted to 30.2% and 28.7% of total costs of service for the years ended December 31, 2024, and 2023, respectively. The increase in our direct labor costs percentage is driven by wage adjustments and higher headcount resulting from business acquisitions. 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% and 32.9% of total costs of service for the years ended 41 December 31, 2024, and 2023, respectively. The percentage decrease in our expendables was primarily attributable to certain customers electing to directly source sand and the associated logistics. 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% and 38.4% of total costs of service for the years ended December 31, 2024, and 2023, respectively. The percentage increase in our other direct costs was primarily attributable to lease costs on our FORCE ® fleets. 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 and businesses, (ii) stock-based compensation, (iii) business acquisition contingent consideration adjustments, (iv) other expense/(income), (v) 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 (vi) retention bonuses and severance expense. 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 and 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): 42 Hydraulic Fracturing Wireline Cementing All Other Reconciling Items Total Year ended December 31, 2024 Service revenue $ 1,092,000 $ 203,182 $ 149,411 $ — $ (307) $ 1,444,286 Adjusted EBITDA $ 270,505 $ 43,857 $ 26,539 $ (370) $ (57,288) $ 283,243 Depreciation and amortization $ 182,188 $ 20,633 $ 8,812 $ — $ 100 $ 211,733 Property and equipment impairment expense (1) $ 188,601 $ — $ — $ — $ — $ 188,601 Goodwill impairment expense (2) $ — $ 23,624 $ — $ — $ — $ 23,624 Operating lease expense on FORCE ® fleets (3) $ 47,141 $ — $ — $ — $ — $ 47,141 Capital expenditures $ 116,257 $ 7,713 $ 9,376 $ — $ 42 $ 133,388 Goodwill $ 920 $ — $ — $ — $ — $ 920 Total assets $ 961,485 $ 156,349 $ 73,935 $ — $ 31,876 $ 1,223,645 Hydraulic Fracturing Wireline Cementing All Other Reconciling Items Total Year ended December 31, 2023 Service revenue $ 1,280,523 $ 229,599 $ 120,277 $ — $ — $ 1,630,399 Adjusted EBITDA $ 366,809 $ 61,930 $ 24,665 $ — $ (49,444) $ 403,960 Depreciation and amortization $ 156,057 $ 18,762 $ 5,845 $ — $ 222 $ 180,886 Operating lease expense on FORCE ® fleets (3) $ 5,087 $ — $ — $ — $ — $ 5,087 Capital expenditures $ 294,377 $ 12,203 $ 3,440 $ — $ — $ 310,020 Goodwill $ — $ 23,624 $ — $ — $ — $ 23,624 Total assets $ 1,189,526 $ 198,957 $ 78,475 $ — $ 13,354 $ 1,480,312 Hydraulic Fracturing Wireline Cementing All Other Reconciling Items Total Year ended December 31, 2022 Service revenue $ 1,143,216 $ 31,188 $ 91,857 $ 13,440 $ — $ 1,279,701 Adjusted EBITDA $ 339,186 $ 7,926 $ 14,897 $ (1,463) $ (43,956) $ 316,590 Depreciation and amortization $ 117,753 $ 2,619 $ 5,089 $ 2,240 $ 407 $ 128,108 Property and equipment impairment expense (1) $ 57,454 $ — $ — $ — $ — $ 57,454 Capital expenditures $ 347,757 $ 2,265 $ 7,769 $ 1,876 $ 5,649 $ 365,316 Goodwill $ — $ 23,624 $ — $ — $ — $ 23,624 Total assets $ 1,092,658 $ 173,489 $ 46,944 $ — $ 22,695 $ 1,335,786 ____________________ (1) Represents noncash property and equipment impairment expense on our conventional Tier II diesel-only hydraulic fracturing pumps and associated conventional assets (“Tier II Units”) for the year ended December 31, 2024, and noncash impairment expense on our DuraStim ® electric-powered hydraulic fracturing equipment for the year ended December 31, 2022. There was no property and equipment impairment expense for the year ended December 31, 2023. (2) Represents noncash impairment of goodwill in our wireline operating segment. (3) 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. 43 A reconciliation of net (loss) income to Adjusted EBITDA is provided in the table below (in thousands): Year Ended December 31, 2024 2023 2022 Net (loss) income $ (137,859) $ 85,634 $ 2,030 Depreciation and amortization 211,733 180,886 128,108 Property and equipment impairment expense (1) 188,601 — 57,454 Goodwill impairment expense (2) 23,624 — — Interest expense 7,815 5,308 1,605 Income tax (benefit) expense (31,385) 29,868 5,356 Loss on disposal of assets and businesses, net 7,451 73,015 102,150 Stock‑based compensation 17,288 14,450 21,881 Business acquisition contingent consideration adjustments (2,600) — — Other (income) expense, net (3) (5,531) 9,533 (11,582) Other general and administrative expense, net (4) 1,782 2,969 8,460 Retention bonus and severance expense 2,324 2,297 1,128 Adjusted EBITDA $ 283,243 $ 403,960 $ 316,590 ____________________ (1) Represents noncash property and equipment impairment expense on our Tier II Units for the year ended December 31, 2024, and noncash impairment expense on our DuraStim ® electric-powered hydraulic fracturing equipment for the year ended December 31, 2022. These impairment expenses are included in our Hydraulic Fracturing reportable segment. (2) Represents noncash impairment of goodwill in our wireline operating segment. (3) 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. (4) 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. 44 Results of Operations In 2024, 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 segments are shown in the “All Other” category for segment reporting purposes. Year Ended December 31, 2024 Compared to Year Ended December 31, 2023 (in thousands, except percentages) Year Ended December 31, Change 2024 2023 Variance % Revenue Hydraulic Fracturing $ 1,092,000 $ 1,280,523 $ (188,523) (14.7) % Wireline 203,182 229,599 (26,417) (11.5) % Cementing 149,411 120,277 29,134 24.2 % Elimination of intersegment service revenue (307) — (307) 100.0 % Total revenue 1,444,286 1,630,399 (186,113) (11.4) % Cost of services (1) Hydraulic Fracturing 800,202 886,157 (85,955) (9.7) % Wireline 148,125 155,357 (7,232) (4.7) % Cementing 117,490 90,287 27,203 30.1 % All Other (2) 4 — 4 100.0 % Elimination of intersegment cost of services (307) — (307) 100.0 % Total cost of services 1,065,514 1,131,801 (66,287) (5.9) % General and administrative expense (3) 114,323 114,354 (31) — % Depreciation and amortization 211,733 180,886 30,847 17.1 % Property and equipment impairment expense 188,601 — 188,601 100.0 % Goodwill impairment expense 23,624 — 23,624 100.0 % Loss on disposal of assets and business, net 7,451 73,015 (65,564) (89.8) % Interest expense 7,815 5,308 2,507 47.2 % Other (income) expense, net (5,531) 9,533 (15,064) (158.0) % Income tax (benefit) expense (31,385) 29,868 (61,253) (205.1) % Net (loss) income $ (137,859) $ 85,634 $ (223,493) (260.99) % Adjusted EBITDA (4) $ 283,243 $ 403,960 $ (120,717) (29.88) % Adjusted EBITDA Margin (4) 19.6 % 24.8 % (5.2) % (20.97) % Hydraulic Fracturing segment results of operations: Revenue $ 1,092,000 $ 1,280,523 $ (188,523) (14.7) % Cost of services $ 800,202 $ 886,157 $ (85,955) (9.7) % Adjusted EBITDA $ 270,505 $ 366,809 $ (96,304) (26.3) % Adjusted EBITDA Margin (5) 24.8 % 28.6 % (3.8) % (13.3) % ____________________ (1) Exclusive of depreciation and amortization. (2) Includes our newly formed power generation services business. (3) Inclusive of stock‑based compensation. 45 (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 measures calculated in accordance with GAAP, please read “How We Evaluate Our Operations.” (5) 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 revenues for the Hydraulic Fracturing segment. Revenue. Revenue decreased 11.4%, or $186.1 million, to $1,444.3 million for the year ended December 31, 2024, as compared to $1,630.4 million for the year ended December 31, 2023. Revenue by reportable segment was as follows: Hydraulic Fracturing. Our hydraulic fracturing segment revenues decreased 14.7%, or $188.5 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023. The decrease was primarily attributable to a decrease in our customers’ activity levels as a result of a decrease in drilling activity and decreased customer pricing, partially offset by the addition of AquaProp's operations in May 2024, which contributed $44.1 million in revenues during 2024. Our average active hydraulic fracturing fleet count was approximately 14 fleets for the year ended December 31, 2024, a decrease from 15 fleets for the year ended December 31, 2023. Intersegment revenues, consisting of revenues derived from our wireline segment, totaled $0.3 million and $0 for the years ended December 31, 2024 and 2023, respectively. Wireline. Our wireline segment revenue decreased 11.5%, or $26.4 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023. The decrease was primarily attributable to a decrease in our customers' activity levels as a result of a decrease in drilling activity and decreased customer pricing. Cementing. Our cementing segment revenue increased 24.2%, or $29.1 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023. The increase was primarily attributable to the addition of Par Five's operations in December 2023, which contributed to $35.3 million of the increase in revenues. Cost of Services. Cost of services decreased 5.9%, or $66.3 million, to $1,065.5 million for the year ended December 31, 2024, from $1,131.8 million during the year ended December 31, 2023. Cost of services by reportable segment was as follows: Hydraulic Fracturing. C ost of services for our hydraulic fracturing segment decreased $86.0 million during the year ended December 31, 2024, as compared to the year ended December 31, 2023. As a percentage of hydraulic fracturing segment revenues (including equipment reservation fees), hydraulic fracturing cost of services was 73.3% for the year ended December 31, 2024, as compared to 69.2% for the year ended December 31, 2023 driven by the decreased activity levels, customer price decreases and the impact of general cost inflation. The decrease in cost of services was partially offset by an increase of $7.6 million in insurance expense resulting from higher allocation of workers' compensation, general liability and automobile insurance costs to cost of services in 2024 compared to 2023 since these costs are primarily incurred for our operational workforce, and the addition of AquaProp's operations in May 2024, which added $42.5 million in cost of services during the year ended December 31, 2024. Wireline. Our wireline segment cost of services decreased 4.7%, or $7.2 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023 due to scaling back in response to decreased revenues. Intersegment cost of services, consisting of cost of services incurred to our hydraulic fracturing segment, totaled $0.3 million and $0 for the years ended December 31, 2024 and 2023, respectively. Cementing. Our cementing cost of services increased 30.1%, or $27.2 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023. The increase was primarily attributable to the addition of Par Five's operations in December 2023, which resulted in $27.9 million of the net increase in cost of services. General and Administrative Expenses. General and administrative expen ses remained flat at $114.3 million for the y ear ended December 31, 2024, as compared to $114.4 million for the year ended December 31, 2023. Excluding nonrecurring and noncash items ( i.e., stock-based compensation of $17.3 million, legal settlements (net of insurance reimbursements) of $0.2 million, transaction expenses of $1.6 million and retention bonuses and severance expenses of $2.3 million, partially offset by business acquisition contingent consideration adjustments of $2.6 million), general and administrative expenses were $95.5 million for the year ended December 31, 2024, as compared to $94.6 million for the year ended December 31, 2023. Depreciation and Amortization. Depreciation and amortization increased 17.1%, or $30.8 million, to $211.7 million for the yea r ended December 31, 2024, as compared to $180.9 million for the year ended December 31, 2023. The increase was 46 primarily attributable to (i) assets placed into service since December 31, 2023, (ii) the addition of a finance lease for certain power generation equipment in August 2023 which resulted in $19.0 million of amortization, (iii) the addition of Par Five's operations in December 2023 which resulted in a $3.5 million increase in depreciation and (iv) the addition of AquaProp's operations in May 2024 which included $3.5 million of depreciation and amortization. Property and Equipment Impairment Expense. During the year ended December 31, 2024, we recorded noncash property and equipment impairment expense of $188.6 million in connection with the impairment of our Tier II Units, which is included in our Hydraulic Fracturing reportable segment. No property and equipment impairment expense was recorded during the year ended December 31, 2023. Goodwill Impairment Expense. During the year ended December 31, 2024, we recorded goodwill impairment expense of $23.6 million in our Wireline reportable segment during the year ended December 31, 2024. No goodwill impairment expense was recorded during the year ended December 31, 2023. Loss on Disposal of Assets and Business. Loss on the disposal of assets and business decreased 89.8%, or $65.5 million, to $7.5 million for the year ended December 31, 2024, as compared to $73.0 million for the year ended December 31, 2023. The decrease was primarily attributable to an $8.2 million gain related to the sale of our cementing business located in Vernal, Utah, during 2024, losses incurred during 2023 from the decommissioning of certain hydraulic fracturing equipment, replacement of certain major components in connection with our conversion of certain Tier II hydraulic fracturing equipment to Tier IV DGB, and the write-off of certain hydraulic fracturing equipment as a result of an accidental fire at a wellsite in March 2023. Interest Expense. Interest expense increased to $7.8 million for the yea r ended December 31, 2024, as compared to $5.3 million for t he year ended December 31, 2023. The increase was primarily attributable to higher average outstanding borrowings under our ABL Credit Facility during the year ended December 31, 2024 and the addition of a finance lease for certain power generation equipment in August 2023. Other (Income) Expense. Other income was approximately $5.5 million for the year ended December 31, 2024, as compared to other expense of $9.5 million for the year ended December 31, 2023. Other income during the year ended December 31, 2024 is primarily comprised of tax refunds (net of advisory fees) totaling $5.0 million, insurance reimbursements of $2.0 million and a $2.6 million decrease in estimated fair value of the contingent consideration payable on our acquisition of AquaProp, 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 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. Income Taxes. Total income tax benefit was $31.4 million resulting in an effective tax rate of 18.5% for the year ended December 31, 2024, as compared to income tax expense of $29.9 million resulting in an effective tax rate of 25.9% for the year ended December 31, 2023. The change in income tax benefit recorded during the year ended December 31, 2024, compared to the change in income tax expense recorded during the year ended December 31, 2023, is primarily attributable to the difference in the impact of nondeductible expenses and state taxes on the pre-tax loss for 2024, as compared to pre-tax income for 2023. 47 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). 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), 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. 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 was $11.8 million and $19.2 million as of December 31, 2024 an d 2023, respectively. There were no amounts of restricted cash as of December 31, 2024 an d 2023. As of December 31, 2024, our borrowings under our ABL Credit Facility were $45.0 million and our total liquidity was $160.9 million, consisting of cash and cash equivalents of $50.4 million and $110.5 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 year ended December 31, 2024 , the Company repurchased and retired 7.2 million shares of common stock for an aggregate of $59.1 million, an average price per share of $8.21 including commissions, under the share repurchase program. As of December 31, 2024 , $89.2 million remained authorized for future repurchases of common stock under the share repurchase program. On May 31, 2024, the Company consummated the acquisition of all of the outstanding equity interests in AquaProp, which provides wet sand solutions for hydraulic fracturing sand requirements at oil well sites. The cash consideration for this acquisition includes $13.7 million paid to the seller, $7.2 million paid to settle the seller’s outstanding debt, and $0.3 million paid for the seller’s transaction expenses . 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. 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 and 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. Cash and Cash Flows The following table sets forth our net cash provided by (used in) operating, investing and financing activities during the years ended December 31, 2024 and 2023, respectively. Year Ended December 31, (in thousands) 2024 2023 Net cash provided by operating activities $ 252,295 $ 374,742 Net cash used in investing activities $ (155,099) $ (384,127) Net cash used in financing activities $ (80,107) $ (46,123) Operating Activities Net cash provided by operating activities was $252.3 million for the year ended December 31, 2024, as compared to $374.7 million for the year ended December 31, 2023. The net decrease of $122.4 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 $155.1 million for the year ended December 31, 2024, from $384.1 million for the year ended December 31, 2023. The decrease was primarily attributable to our capital light strategy and the completion of our planned investments in Tier IV DGB equipment. The following table summarizes our capital expenditures incurred by reportable segment for the periods indicated: Year Ended December 31, (in thousands) 2024 2023 Reportable Segments: Hydraulic Fracturing $ 116,257 $ 294,377 Wireline 7,713 12,203 Cementing 9,376 3,440 Reconciling Items (1) 42 — Total capital expenditures (2) $ 133,388 $ 310,020 _________________ (1) Reconciling Items include our corporate facilities. (2) See Note 3. Supplemental Cash Flows Information in the financial statements for noncash reconciling items. Financing Activities Net cash used in financing activities increased to $80.1 million for the year ended December 31, 2024, compared to $46.1 million for the year ended December 31, 2023. The net increase was primarily driven by net borrowings of $15.0 million under our ABL Credit Facility during the year ended December 31, 2023 , a $13.0 million increase in payments of finance lease obligation and a $7.4 million increase in share repurchases and repayments of insurance financing of $1.0 million during the year ended December 31, 2024 , partially offset by a $1.6 million decrease in tax withholdings paid for net settlement of equity awards and payment of debt issuance costs of $1.2 million during the year ended December 31, 2023 . 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 its amended and restated revolving 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 its amended and restated 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, the “ABL Credit Facility”). The amendment increased the amount of noncash consideration that may be considered cash pursuant to certain permitted dispositions. The ABL Credit Facility has a borrowing base of 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”) as redetermined monthly. The Borrowing Base as of December 31, 2024, was approximately $164.1 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 or 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. The weighted average annual interest rate for our ABL Credit Facility for the year ended December 31, 2024, was 7.12% . The loan origination costs relating to the ABL Credit Facility are classified as an asset on our balance sheet. As of December 31, 2024, and 2023 , we had outstanding borrowings under our ABL Credit Facility of $45.0 million and $45.0 million, respectively. We 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 start receiving this equipment from the end of the second quarter of 2025 through early 2026. Off Balance Sheet Arrangements We had no material off balance sheet arrangements as of December 31, 2024. Capital Requirements, Future Sources and Use of Cash Capital expenditures incurred were $133.4 million during the year ended December 31, 2024, as compared to $310.0 million during the year ended December 31, 2023. The significant portion of our total capital expenditures incurred during the year ended December 31, 2024, were maintenance capital expenditures and conversion of our hydraulic fracturing equipment to lower emissions equipment. Our future material use of cash will be to fund our capital expenditures. 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 $300 million to $400 million which includes approximately $150 million to $200 million for our completion services business and approximately $150 million to $200 million for our PROPWR business. We 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 will be financed, representing progress payments beyond the initial down payment on this equipment. We currently expect receive this equipment beginning with the end of the second quarter of 2025 through early 2026. We entered into a contractual arrangement with another related equipment manufacturer to purchase additional natural gas-fueled power generation equipment for our PROPWR business line, with a total cost of $25.0 million. We currently expect to receive this equipment in the first half of 2025. We could incur significant additional capital expenditures if our projected activity levels increase during the course of the year, inflation and supply chain tightness continues 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 impact 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. Our cash flows from operations will be generated from services we provide to our customers. Contractual Obligations The following table presents our contractual obligations and other commitments as of December 31, 2024: (in thousands) Period Total 1 year or less More than 1 year ABL Credit Facility (1) $ 45,000 $ — $ 45,000 Operating leases (2)(3) 126,550 51,238 75,312 Finance lease (4) 34,377 20,915 13,462 Sand commitments (5) 1,500 1,500 — Equipment purchase commitments (6) 147,000 120,160 26,840 Par Five deferred cash consideration (7) 3,109 3,109 — AquaProp deferred cash consideration (8) 3,664 3,664 — Total $ 361,200 $ 200,586 $ 160,614 ____________________ (1) Exclusive of future commitment fees, amortization of deferred financing costs, interest expense or other fees on our ABL Credit Facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments of future interest rates to be changed. However, assuming a weighted average interest rate of 7.12% , and that our ABL Credit Facility debt balance remains the same, our estimated annual interest payment will be $3.2 million. (2) Operating leases exclude short-term leases and other commitments (see Note 17. Leases and Note 18. Commitments and Contingencies in the financial statements for additional disclosures). (3) Includes our leases for FORCE ® electric-powered hydraulic fracturing fleets (312,000 HHP). We expect to receive the remaining equipment under these leases in the first half of 2025. (4) Finance lease for certain power generation equipment (70 MW) to support electric-powered hydraulic fracturing equipment . (5) Relates to a take-or-pay sand commitment with one of our sand vendors. (6) Represents contractual commitments with two equipment manufacturers to purchase 140 megawatts of mobile natural gas-fueled power generation equipment for our PROPWR business line (see Note 18. Commitments and Contingencies in the financial statements for additional disclosures). (7) Represents the unpaid portion of the purchase consideration on our acquisition of Par Five to be used to cover (i) the amount by which the estimated purchase price exceeds the final purchase price, if any, and (ii) any indemnity obligations of the seller, if any. (8) Represents the unpaid portion of the purchase consideration on our acquisition of AquaProp to be used to cover (i) the amount by which the estimated purchase price exceeds the final purchase price, if any, and (ii) any indemnity obligations of the seller, if any. We enter into other purchase agreements with Sand Suppliers to secure the supply of sand in the normal course of our business. The agreements with the Sand Suppliers require that we purchase a minimum volume of sand, based primarily on a certain percentage of our sand requirements from our customers or in certain situations based on predetermined fixed minimum volumes, otherwise certain penalties (shortfall fees) may be charged. The shortfall fee represents liquidated damages and is either a fixed percentage of the purchase price for the mi nimum volumes or a fixed price per ton of unpurchased volumes. Our current agreements with Sand Suppliers expire at different times prior to December 31, 2025 . Our agreed upon sand requirements or minimum volumes are based on certain future events such as our customer demand, which cannot be reasonably estimated. If the activity level of our customers declines and the future demand for our services is materially and adversely affected, we may be required to pay for more sand from one of our Sand Suppliers than we need in the performance of our services, regardless of whether we take physical delivery of such sand. In such an event, we may be required to pay shortfall fees or other penalties under the purchase agreement, which could have a material adverse effect on our business, financial condition, or results of operations. Recent Accounting Pronouncements Disclosure concerning recently issued accounting standards is incorporated by reference to " Note 2- Significant Accounting Policies " of our Consolidated Financial Statements contained in this Annual Report. Critical Accounting Policies and Estimates The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported revenues and expenses during the years. We evaluate these estimates and assumptions on an ongoing basis and base our estimates on historical experience, current conditions and various other assumptions that we believe to be reasonable under the circumstances. The results of these estimates form the basis for making judgments about the carrying values of assets and liabilities as well as identifying and assessing the accounting treatment with respect to commitments and contingencies. Our actual results may materially differ from these estimates. Listed below are the accounting policies that we believe are critical to our financial statements due to the degree of uncertainty regarding the estimates or assumptions involved, and that we believe are critical to the understanding of our operations. Business Combinations Business combinations are accounted for under the acquisition method of accounting. Under this method, the assets acquired and liabilities assumed are recognized at their respective fair values as of the date of acquisition. The excess, if any, of the acquisition price over the fair values of the assets acquired and liabilities assumed is recorded as goodwill if the definition of a business is met. For significant acquisitions, we utilize third-party appraisal firms to assist us in determining the fair values for certain assets acquired and liabilities assumed using discounted cash flows and other applicable valuation techniques. We record any acquisition related costs as expenses when incurred. Adjustments to the fair values of assets acquired and liabilities assumed are made until we obtain all relevant information regarding the facts and circumstances that existed as of the acquisition date (the “measurement period”), not to exceed one year from the date of the acquisition. We recognize measurement period adjustments in the period in which we determine the amounts, including the effect on earnings of any amounts we would have recorded in previous periods if the accounting had been completed at the acquisition date. The estimation of the fair values of assets and liabilities acquired in business combinations requires significant judgment. Our fair value estimates require us to use significant observable and unobservable inputs. The estimates of fair value are also subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. A significant change in the observable and unobservable inputs and determination of fair value of the assets and liabilities acquired could significantly impact our consolidated financial statements. Property and Equipment 48 Our property and equipment are recorded at cost, less accumulated depreciation. Upon sale or retirement of property and equipment, the cost and related accumulated depreciation are removed from the balance sheet and the net amount, less proceeds from disposal, is recognized as a gain or loss in earnings. We primarily retire certain components of equipment such as fluid ends and power ends, rather than the entire pieces of equipment. The associated loss is recorded in our statement of operations as part of net loss on disposal of assets and businesses, which was $7.5 million , $73.0 million, and $102.1 million for the years ended December 31, 2024, 2023, and 2022, respectively. The estimated useful lives and salvage values of property and equipment are subject to key assumptions such as maintenance, utilization and job variation. Unanticipated future changes in these assumptions could negatively or positively impact our net income (loss). A 10% change in the useful lives of our property and equipment would have resulted in approximately $18.5 million impact on pre-tax loss during the year ended December 31, 2024. Depreciation of property and equipment is provided on the straight‑line method over estimated useful lives as shown in the table below. Land Indefinite Buildings and property improvements 5 - 30 years Vehicles 1 ‑ 5 years Equipment 1 ‑ 22 years Leasehold improvements 5 ‑ 20 years Impairment of Long-Lived Assets In accordance with the Financial Accounting Standards Board Accounting Standards Codification (“ASC”) 360 regarding Accounting for the Impairment or Disposal of Long‑Lived Assets , we review the long‑lived assets including intangible assets to be held and used whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future undiscounted cash flows attributable to the assets is less than the carrying amount of such assets. In this circumstance, we recognize an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the asset. Our cash flow forecasts require us to make certain judgments regarding long‑term forecasts of future revenue and costs and cash flows related to the assets subject to review. The significant assumption in our cash flow forecasts is our estimated equipment utilization and profitability. The significant assumption is uncertain in that it is driven by future demand for our services and utilization, which could be impacted by crude oil market prices, future market conditions and technological advancements. Our fair value estimates for certain long‑lived assets require us to use significant other observable inputs, including assumptions related to market based on recent auction sales or selling prices of comparable equipment. The estimates of fair value are also subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. If the crude oil market declines or the demand for our services does n ot recover, and if our equipment remains idle or underutilized, the estimated fair value of such equipment may decline, which could result in future impairment charges. Though the impacts of variations in any of these factors can have compounding or offsetting impacts, a 10% decline in the estimated future cash flows of our existing asset groups will not indicate an impairment. During the year ended December 31, 2024 , we recorded property and equipment impairment expense of approximately $188.6 million in connection with our conventional Tier II diesel-only hydraulic fracturing pumping units and associated conventional assets. In 2022, we recorded property and equipment impairment expense of $57.5 million on our DuraStim ® electric-powered hydraulic fracturing equipment within the hydraulic fracturing operating segment . Intangible assets consist of trade mark/trade name, customer relationships and favorable contracts. Trademark/trade names are amortized on a straight‑line basis over useful l ives of ten and fifteen years. Customer relationships are amortized on a straight‑line basis over useful lives of six and ten years. Favorable contracts are amortized on a straight‑line basis over useful lives of thirty months and five years. Internally developed software will be amortized on a straight‑line basis over a useful life of twenty-nine months. Our estimated useful life could be sensitive to changes in market conditions and management’s judgment, and are likely to change in the future if certain events occur. Presently, there are no events or circumstances that will cause us to believe that our estimated useful life for our intangible assets are likely to change. 49 Goodwill Goodwill is the excess of the consideration transferred over the fair value of the tangible and identifiable intangible assets and liabilities recognized. Goodwill is not amortized. We perform an annual impairment test of goodwill and intangible assets as of December 31, or more frequently if circumstances indicate that impairment may exist. In connection with the AquaProp Acquisition, we added $0.9 million of goodwill in our hydraulic fracturing operating segment during the year ended December 31, 2024. We recorded goodwill impairment expense of $23.6 million in our wireline reporting unit during the year ended December 31, 2024. There were no additions to goodwill during the year ended December 31, 2023. The hydraulic fracturing operating segment was the only segment with goodwill at December 31, 2024. The wireline operating segment was the only segment with goodwill at December 31, 2023 . There were no goodwill impairment losses during the year ended December 31, 2023 . We performed our annual goodwill impairment test in accordance with ASC 350, Intangibles—Goodwill and Other , on December 31, 2024, at which time, we determined that the fair value of our wireline reporting unit was substantially in excess of its carrying value resulting in impairment. The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted equipment utilization, pricing and cost assumptions. Our discounted cash flow analysis includes significant assumptions regarding discount rates, utilization, expected profitability margin, forecasted maintenance capital expenditures, and the timing of expected cash flow. As such, our goodwill analysis incorporates inherent uncertainties that are difficult to predict in volatile economic environments and could result in impairment charges in future periods if actual results materially differ from the estimated assumptions utilized in our forecast. As of December 31, 2024, and 2023, our goodwill carrying value w as $0.9 million and $23.6 million, respectively. Leases In accordance with ASC Topic 842, the Company determines if a contract is a lease at inception and evaluates identified leases for operating and finance lease accounting. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. The Company uses a discount rate based on its estimated incremental borrowing rate on a collateralized basis with similar terms and economic considerations as its lease payments at the lease commencement in determining the present value of lease payments. Lease terms may include options to renew the lease or purchase the underlying assets, however, the Company typically cannot determine its intent to renew the lease or purchase the assets with reasonable certainty at inception. The Company elected the short-term lease recognition practical expedient provided by ASC 842 in which leases with a term of twelve months or less will not be recognized on the balance sheet, and the practical expedient to not separate lease and non-lease components for real estate class of assets. We elected to analogize to the measurement guidance of ASC 360 to capitalize costs incurred to place a leased asset into its intended use and to present such capitalized costs as part of the related lease right-of-use asset cost as initial direct costs. Income Taxes Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of differences between the consolidated financial statements and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. We recognize deferred tax assets to the extent that we believe these assets are more likely than not to be realized. In making such a determination, we consider all positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, and the results of recent operations. If we determine that we would not be able to fully realize our deferred tax assets in the future in excess of their net recorded amount, we would record a valuation allowance, which would increase our provision for income taxes. In determining our need for a valuation allowance as of December 31, 2024, we have considered and made judgments and estimates regarding estimated future taxable income. These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to record additional valuation allowances for our deferred tax assets and the ultimate realization of tax assets depends on the generation of sufficient taxable income. Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and estimates. Additionally, we forecast certain tax elements, such as future taxable income, as well as evaluate the feasibility of implementing tax planning strategies. Given the inherent uncertainty involved with the use of such variables, there can be significant variation between anticipated and actual results. Unforeseen events may significantly impact these variables, and changes to these variables could have a material impact on our income tax accounts. The final determination of our income tax 50 liabilities involves the interpretation of local tax laws and related authorities in each jurisdiction. Changes in the operating environments, including changes in tax law, could impact the determination of our income tax liabilities for a tax year. 51